F-10/A

As filed with the Securities and Exchange Commission on June 8, 2016

Registration No. 333-211741

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 1 TO

FORM F-10

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

EMERA INCORPORATED

(Exact Name of Registrant as Specified in Its Charter)

NOVA SCOTIA, CANADA

(Province or other jurisdiction of incorporation or organization)

4911

(Primary Standard Industrial Classification Code Number)

Not Applicable

(I.R.S. Employer Identification Number)

5151 Terminal Road

Halifax NS Canada

B3J 1A1

Telephone: (902) 428-6096

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

Emera US Finance LP

2711 Centerville Road, Suite 400,

Wilmington, Delaware 19808

Telephone: (302) 636-5400

(Name, address, and telephone number of agent for service in the United States)

Copies to:

Stephen Aftanas	Byron B. Rooney	John Macfarlane	Peter O’Brien	Joel E. Binder
5151 Terminal Road Halifax Nova Scotia Canada B3J 1A1 (902) 428-6096	Davis Polk & Wardwell LLP 450 Lexington Avenue New York, New York U.S.A., 10017 (212) 450-4000	Osler, Hoskin & Harcourt LLP Box 50, 1 First Canadian Place Toronto, Ontario, Canada M5X 1B8 (416) 362-2111	Hunton & Williams LLP 200 Park Avenue 52nd Floor New York, New York U.S.A. 10166 (212) 309-1000	Stikeman Elliott LLP 5300 Commerce Court West 199 Bay Street Toronto, Ontario, Canada M5L 1B9 (418) 689-5500

Approximate date of commencement of proposed sale of the securities to the public:

As soon as practicable after this Registration Statement is declared effective.

Province of Nova Scotia, Canada

(Principal jurisdiction regulating this offering).

It is proposed that this filing shall become effective (check appropriate box):

A.	¨	Upon filing with the Commission, pursuant to Rule 467(a) (if in connection with an offering being made contemporaneously in the United States and Canada).
B.	x	By at some future date (check appropriate box below):
		1.	¨	Pursuant to Rule 467(b) on (date) at (time) (designate a time not sooner than 7 calendar days after filing).
		2.	¨	Pursuant to Rule 467(b) on (date) at (time) (designate a time 7 calendar days or sooner after filing) because the securities regulatory authority in the review jurisdiction has issued a receipt or notification of clearance on (date).
		3.	x	Pursuant to Rule 467(b) as soon as practicable after notification of the Commission by the Registrant or the Canadian securities regulatory authority of the review jurisdiction that a receipt or notification of clearance has been issued with respect hereto.
		4.	¨	After the filing of the next amendment to this form (if preliminary material is being filed).

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to the home jurisdiction’s shelf prospectus offering procedures, check the following box:  x

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Offering Price Security	Proposed Maximum Aggregate Offering Price (1)	Amount of Registration Fee
Emera Incorporated:
Unsecured, Subordinated Notes (the “Notes”)	U.S.$1,250,000,000	100%	U.S.$1,250,000,000	U.S.$125,875.00(3)
First Preferred Shares (the “Preferred Shares”)	(2)	n/a	n/a	n/a

(1) Estimated solely for purposes of calculating the registration fee.

(2) There are hereby registered such indeterminate number of Preferred Shares as may be issued upon an automatic conversion of the Notes registered hereunder. Pursuant to Rule 457(i), no separate registration fee is payable where securities and securities into which conversion is offered are registered at the same time and no additional consideration is payable upon conversion.

(3) U.S.$80,560.00 was previously paid upon the initial filing of this Registration Statement. The additional fee of U.S.$45,315.00 is paid herewith.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registration Statement shall become effective as provided in Rule 467 under the Securities Act of 1933, as amended, or on such date as the Commission, acting pursuant to Section 8(a) of the Act, may determine.

PART I

INFORMATION REQUIRED TO BE

DELIVERED TO OFFEREES OR PURCHASERS

I-1

Short Form Base Shelf Prospectus

New Issue June 8, 2016

EMERA INCORPORATED

U.S.$1,250,000,000

Unsecured, Subordinated Notes

First Preferred Shares Issuable Upon Automatic Conversion

Emera Incorporated (“Emera” or the “Company”) may offer and sell from time to time up to U.S.$1,250,000,000 principal amount of unsecured, subordinated notes (the “Notes”), in one or more transactions during the 25 month period ending July 8, 2018 that this base shelf prospectus (this “Prospectus”), including any amendments hereto, remains valid. The Notes are convertible into First Preferred Shares of Emera in certain circumstances (see “Description of the Notes—Automatic Conversion” and “Description of Conversion Preferred Shares”). The Notes offered hereunder may be offered separately or together, in separate series, in amounts, at prices, with maturities, and on terms to be set forth in one or more shelf prospectus supplements (each, a “Prospectus Supplement”). A Prospectus Supplement may include other specific terms pertaining to the Notes that are not prohibited by the parameters set forth in this Prospectus. See “Description of the Notes”.

All shelf information permitted under applicable laws to be omitted from this Prospectus will be contained in one or more Prospectus Supplements that will be delivered to purchasers together with this Prospectus. Each Prospectus Supplement will be incorporated by reference into this Prospectus for the purposes of securities legislation as of the date of the Prospectus Supplement and only for the purposes of the Notes to which the Prospectus Supplement pertains.

Emera may sell the Notes to or through underwriters purchasing as principal and may also sell the Notes to one or more other purchasers directly or through agents. Any underwriting syndicate in respect of an offering of Notes will be led by J.P. Morgan Securities LLC. See “Plan of Distribution.” The Prospectus Supplement relating to a particular offering of Notes will identify each underwriter or agent, as the case may be, engaged by Emera in connection with the offering and sale of the Notes and will set forth the terms of the offering of such Notes, including the method of distribution of such Notes, the proceeds to Emera and any fees, discounts or other compensation payable to underwriters or agents, and any other material terms of the offering of such Notes.

In connection with any offering of Notes, the underwriters or agents may over-allot or effect transactions which stabilize or maintain the market price of the Notes offered at a level above that which might otherwise prevail in the open market. Such transactions, if commenced, may be discontinued at any time. See “Plan of Distribution.”

Investing in the Notes involves risk. See “Risk Factors.”

Emera is permitted, under the multi-jurisdictional disclosure system adopted by the United States (“U.S.”), to prepare this Prospectus in accordance with Canadian disclosure requirements. You should be aware that such requirements are different from those of the U.S.

Financial statements incorporated herein have been prepared in accordance with U.S. generally accepted accounting principles, which is referred to as “U.S. GAAP.”

Owning the Notes may subject you to tax consequences both in the United States and Canada. This Prospectus or any applicable Prospectus Supplement may not describe these tax consequences fully. You should read the tax discussion in any applicable Prospectus Supplement.

Your ability to enforce civil liabilities under U.S. federal securities laws may be affected adversely by the fact that Emera is organized under the laws of Nova Scotia, that some or all of the officers and directors of Emera may be residents of Canada, that some or all of the experts named herein may be residents of Canada and that all or a substantial portion of our assets and the assets of said persons are located outside of the U.S.

J. Wayne Leonard and Richard P. Sergel are directors of Emera who reside outside of Canada and each of these directors has appointed Emera Incorporated as agent for service of process at 5151 Terminal Road, Halifax, Nova Scotia B3J 1A1. Purchasers are advised that it may not be possible for investors to enforce judgements obtained in Canada against any person who resides outside of Canada, even if the party has appointed an agent for service of process.

The Notes have not been approved or disapproved by the United States Securities and Exchange Commission (the “SEC”) or any state securities commission nor has the SEC or any state securities commission passed upon the accuracy or adequacy of this Prospectus. Any representation to the contrary is a criminal offense.

Emera’s head office is located at 5151 Terminal Road, Halifax, Nova Scotia B3J 1A1.

Post-Acquisition Map of Combined Emera and TECO Energy Operations

TABLE OF CONTENTS

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	1
WHERE TO FIND MORE INFORMATION	3
DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT	3
DOCUMENTS INCORPORATED BY REFERENCE	3
PRESENTATION OF FINANCIAL INFORMATION	6
CAUTION REGARDING UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS	10
CURRENCY	11
THIRD PARTY SOURCES AND INDUSTRY DATA	12
SUMMARY	13
GLOSSARY	40
RISK FACTORS	54
USE OF PROCEEDS	74
CAPITALIZATION	75
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS	76
MANAGEMENT’S DISCUSSION AND ANALYSIS	90
BUSINESS	196
MANAGEMENT	250
THE ACQUISITION AGREEMENT	254
DESCRIPTION OF OTHER INDEBTEDNESS	255
DIVIDEND POLICY	259
DESCRIPTION OF THE NOTES	260
DESCRIPTION OF CONVERSION PREFERRED SHARES	269
CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS	272
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS	274
PLAN OF DISTRIBUTION	279
EARNINGS COVERAGE RATIOS	280
LEGAL MATTERS	280
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS	280
INTERESTS OF EXPERTS	280
TRANSFER AGENT, REGISTRAR, PAYING AGENT AND INDENTURE TRUSTEE	280
ENFORCEMENT OF CIVIL LIABILITIES	281

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Please refer to the “Glossary” beginning on page 40 of this Prospectus for a list of defined terms used herein.

This Prospectus, including the documents incorporated herein by reference, contains forward-looking information within the meaning of applicable securities laws which reflects current expectations of Emera’s management regarding: (i) the future growth, results of operations, performance, business prospects and opportunities of the Company; (ii) the timing and completion of the Acquisition Capital Markets Transactions (as defined herein) and the Acquisition (as defined herein); (iii) the benefits and the impact of the Acquisition, any offering hereunder, the other Acquisition Capital Markets Transactions and the Acquisition Credit Facilities (and the proposed refinancing thereof) on the financial position of the Company; and (iv) the future performance, business prospects and opportunities of TECO Energy and the integration of its electric and gas utility businesses with the existing operations of Emera. These expectations may not be appropriate for other purposes. Such statements are “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995. The words “anticipates,” “believes,” “budget,” “could,” “estimates,” “expects,” “forecasts,” “intends,” “may,” “might,” “plans,” “projects,” “schedule,” “should,” “targets,” “will,” “would,” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to the Company’s management.

The forward-looking information in this Prospectus, including the documents incorporated herein by reference, includes, but is not limited to, statements regarding: Emera’s consolidated net income and cash flow; the growth and diversification of Emera’s business and earnings base; future annual net income and dividend growth; expansion of Emera’s business in the United States and elsewhere; the completion of the Acquisition; the completion of the Acquisition Capital Markets Transactions; the expected compliance by Emera and its subsidiaries with the regulation of their operations; the expected timing of regulatory decisions; forecasted gross capital expenditures; the nature, timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; expectations related to annual operating cash flows; the expectation that Emera will continue to have reasonable access to capital in the near to medium terms; expected debt maturities and repayments; expectations about increases in interest expense and/or fees associated with debt securities and credit facilities; no material adverse credit rating actions being expected in the near term; the number of customers served in the future; the successful execution of relationships with third-parties, such as agreements relating to the Maritime Link Project, Muskrat Falls and the Assembly of Nova Scotia Mi’Kmaq Chiefs; the impact of currency fluctuations; expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within Northeastern United States.

The forward-looking information contained herein pertaining to the Acquisition and the financing thereof, the future performance, business prospects and opportunities of TECO Energy and the integration of its electric and gas utility businesses with the existing operations of Emera includes, but is not limited to, statements regarding: the expectation that the Acquisition will increase the Company’s consolidated rate base and total customers; the expectation that the Acquisition will be accretive to earnings per common share, assuming a stable currency environment; the impact of the Acquisition on the Company’s total assets, net income, long-term growth, access to equity and debt capital markets, credit profile, economies of scale and ability to deploy capital; expectations regarding the nature, timing and costs of capital spending of Emera, TECO Energy, New Mexico Gas Company (“NMGC”), Tampa Electric and Peoples Gas System (“PGS”); the expected future unemployment rates, housing starts and GDP growth rates in Florida and New Mexico; the expectations regarding rate base growth; the complementary management teams and corporate cultures of Emera and TECO Energy; the projected use of TECO Energy’s tax carry-forwards; the locations of the combined operations after completion of the Acquisition; the projected coal and petroleum coke consumption for Tampa Electric; the expectations with respect to the impact of costs and compliance as a result of new and existing laws, regulations and guidelines, including, but not limited, to environmental and climate change matters; the financial liability with respect to Superfund sites

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and former manufactured gas plant sites of Tampa Electric and PGS, as well as other potential contamination liabilities; the impact of legal proceedings; the financing of the Acquisition, including, but not limited to, the use of the net proceeds of any offering hereunder and the other Acquisition Capital Markets Transactions, the repayments under the Acquisition Credit Facilities and the terms and conditions of the Acquisition Credit Agreements; the impact of any offering hereunder, the other Acquisition Capital Markets Transactions, the Acquisition Credit Facilities, the timing and closing of the Acquisition, capital lease and finance obligations on the capital structure of the Company; the material attributes and characteristics of the Notes and any other securities issued in connection with the Acquisition Capital Markets Transactions; the plan of distribution; and the risk factors relating to the Acquisition, the post-Acquisition combined business and operations of the Company and TECO Energy and the Acquisition Capital Markets Transactions.

The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations include, but are not limited to: derivative financial instruments, including, but not limited to, hedging availability; commodity price and availability risk; foreign exchange risk; interest rate risk; commercial relationship risk; credit risk; rating agency risk; labour risk; weather risk; regulatory risk; environmental risk; capital market risk, including, but not limited to, economic conditions, cost of financing, capital resources and liquidity risk; construction and development risks; inability to complete an offering hereunder and the financing and the completion of the Acquisition; an increase in the cash purchase price of the Acquisition; uncertainty regarding the length of time required to complete the Acquisition; the anticipated benefits of the Acquisition not materializing or not occurring within the time periods anticipated by the Company; the impact of significant demands placed on the Company as a result of the Acquisition; failure by the Company to repay the Acquisition Credit Facilities; potential unavailability of the Acquisition Credit Facilities; alternate sources of funding, including the Acquisition Capital Markets Transactions, that would be used to replace the Acquisition Credit Facilities not being available when needed; lack of control by the Company of TECO Energy and its subsidiaries prior to the closing of the Acquisition; the impact of the Acquisition-Related Expenses; accuracy and completeness of TECO Energy’s publicly disclosed information; increased indebtedness of Emera after the closing of the Acquisition; that an offering hereunder could result in a downgrade of the Company’s credit ratings; historical and pro forma combined financial information not being representative of future performance; potential undisclosed liabilities of TECO Energy; ability to retain key personnel of TECO Energy following the Acquisition; operating and maintenance risks; risks relating to the financing of Emera; risks associated with changes in economic conditions; that developments in technology could reduce demand for electricity and gas; integration of NMGC and its impact on TECO Energy’s business and operations; changes in customer energy-usage patterns; risk of failure of information technology infrastructure and cybersecurity; disruption of fuel supply; natural disasters or other catastrophic events; impairment testing of certain long-lived assets could result in impairment charges; indebtedness of TECO Energy; risks relating to the Notes; unanticipated maintenance and other expenditures; risk associated with the continuation, renewal, replacement and/or regulatory approval of power supply and capacity purchase contracts; risks associated with pension plan performance and funding requirements; regulatory and government decisions including, but not limited to, changes to environmental, financial reporting and tax legislation and regulations; risk of loss of licences and permits; risk of loss of service area; market energy sales prices; maintenance of adequate insurance coverage; impact of Acquisition-Related Expenses; labor relations and management resources. For additional information with respect to the Company’s risk factors and risk factors relating to the post-Acquisition business of Emera, the operations of Emera and TECO Energy, the Acquisition and the Acquisition Capital Markets Transactions, reference should be made to the section of this Prospectus entitled “Risk Factors” and to the documents incorporated herein by reference and to the Company’s continuous disclosure materials filed from time to time with the CSA.

All forward-looking information in this Prospectus and in the documents incorporated herein by reference is qualified in its entirety by the above cautionary statements and, except as required by law, the Company undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

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WHERE TO FIND MORE INFORMATION

Emera has filed with the SEC, under the Securities Act, a registration statement on Form F-10 relating to the Notes and First Preferred Shares qualified by this Prospectus. This Prospectus, which constitutes a part of the registration statement, does not contain all of the information contained in the registration statement, certain items of which are contained in the exhibits to the registration statement as permitted by the rules and regulations of the SEC. Statements included or incorporated by reference in this Prospectus about the contents of any contract, agreement or other documents referred to are not necessarily complete, and in each instance, you should refer to the exhibits for a complete description of the matter involved. Emera files annual and quarterly financial information and material change reports, business acquisition reports and other material with the Nova Scotia Securities Commission and the securities regulatory authorities in each of the other Canadian provinces.

Under the multi-jurisdictional disclosure system adopted by the U.S., documents and other information that Emera files with the SEC may be prepared in accordance with the disclosure requirements of Canada, which are different from those of the U.S. You may read and download any public document that Emera has filed with the Nova Scotia Securities Commission and the securities regulatory authorities in each of the other Canadian provinces on SEDAR at www.sedar.com. You may read and copy any document that we have filed with the SEC at the SEC’s public reference room in Washington D.C., and may also obtain copies of those documents from the public reference room of the SEC at 100 F Street, N.E., Washington, D.C. 20549 by paying a fee. Additionally, you may read and download some of the documents that we have filed on EDGAR at www.sec.gov.

DOCUMENTS FILED AS PART OF THE REGISTRATION STATEMENT

The following documents are being filed with the SEC as part of the Registration Statement: (i) the documents referred to under the heading “Documents Incorporated by Reference”; (ii) the consent of PricewaterhouseCoopers LLP; (iii) the consent of Ernst & Young LLP; (iv) the consent of Osler, Hoskin & Harcourt LLP; (v) the consent of Davis Polk & Wardwell LLP; (vi) the powers of attorney from Emera’s directors and officers; (vii) the form of Indenture between Emera, American Stock Transfer & Trust Company, LLC and CST Trust Company; and (viii) the Statement of Eligibility under the Trust Indenture Act of 1939, of American Stock Transfer & Trust Company, LLC.

DOCUMENTS INCORPORATED BY REFERENCE

The disclosure documents of the Company listed below and filed with the appropriate securities commissions or similar regulatory authorities in each of the provinces of Canada are specifically incorporated by reference into and form an integral part of this Prospectus:

(i) the Annual Information Form of Emera dated March 30, 2016 for the year ended December 31, 2015;

(ii) the audited consolidated financial statements of Emera as at and for the years ended December 31, 2015 and December 31, 2014, together with the auditors’ report thereon;

(iii) Management’s Discussion and Analysis of Emera for the year ended December 31, 2015;

(iv) the unaudited condensed consolidated interim financial statements of Emera as at and for the three months ended March 31, 2016 and March 31, 2015;

(v) Management’s Discussion and Analysis of Emera for the three months ended March 31, 2016; and

(vi) the Management Information Circular of Emera distributed in connection with Emera’s annual meeting of shareholders held on May 17, 2016 (as refiled on March 24, 2016).

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In addition, the disclosure documents of TECO Energy listed below and filed by it with the SEC, and each also filed by the Company on SEDAR as “Documents incorporated by reference not previously filed” on June 1, 2016, are specifically incorporated by reference into and form an integral part of this Prospectus:

(i) the audited consolidated financial statements and schedule of TECO Energy as at and for the years ended December 31, 2015, 2014 and 2013 contained in TECO Energy’s Annual Report on Form 10-K filed with the SEC for the year ended December 31, 2015;

(ii) Management’s Report on Internal Control over Financial Reporting of TECO Energy contained in TECO Energy’s Annual Report on Form 10-K filed with the SEC for the year ended December 31, 2015; and

(iii) the unaudited consolidated condensed financial statements of TECO Energy as at and for the three months ended March 31, 2016 and 2015 contained in TECO Energy’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended March 31, 2016.

Any documents of the type referred to above (other than confidential material change reports), and any other documents required under applicable securities laws to be incorporated by reference into this Prospectus, if filed by Emera with the provincial securities commissions or similar authorities in Canada after the date of this Prospectus and prior to the termination of any offering of Notes, shall be deemed to be incorporated by reference into this Prospectus. To the extent that any document or information incorporated by reference into this Prospectus is included in a report that is filed with or furnished to the SEC, such document or information shall be deemed to be incorporated by reference as an exhibit to the Registration Statement. In addition, any other report filed with or furnished to the SEC by the Company shall be deemed to be incorporated by reference as an exhibit to the Registration Statement, if and to the extent that such report expressly so provides.

Upon a new annual information form, new management information circular, new annual consolidated financial statements and accompanying management’s discussions and analysis being filed by Emera with (and where required, accepted by) the applicable securities regulatory authorities during the currency of this Prospectus, the previous annual information form, the previous management information circular, the previous annual consolidated financial statements and accompanying management’s discussion and analysis, all consolidated interim financial statements and accompanying management’s discussion and analysis, and all material change reports filed prior to the commencement of the financial year of Emera in which the new annual information form is filed shall be deemed no longer to be incorporated into this Prospectus for the purposes of future offers and sales of Notes hereunder. Upon any interim financial statements and accompanying management’s discussion and analysis being filed by Emera with (and, where required, accepted by) the applicable securities regulatory authorities during the currency of this Prospectus, all interim financial statements and accompanying management’s discussion and analysis filed prior to the new interim financial statements shall be deemed no longer to be incorporated into this Prospectus for purposes of future offers and sales of Notes hereunder.

Any statement contained in a document incorporated or deemed to be incorporated by reference in this Prospectus shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained herein, or in any other subsequently filed document which also is incorporated or is deemed to be incorporated by reference herein, modifies or supersedes such statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement will not be deemed to be an admission for any purpose that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus.

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Copies of Emera’s documents incorporated herein by reference may be obtained on request without charge from the Corporate Secretary of Emera at 5151 Terminal Road, Halifax, Nova Scotia B3J 1A1 (telephone 902-428-6096). These documents are also available through the internet on the Company’s website at www.emera.com or on SEDAR which can be accessed at www.sedar.com. Copies of TECO Energy’s documents incorporated herein by reference may be obtained on request without charge from the Director of Investor Relations of TECO Energy at 702 North Franklin Street, Tampa, Florida 33602 (telephone 813-228-4111). These documents are also available through the internet on TECO Energy’s website at www.tecoenergy.com or on the SEC’s website which can be accessed at www.sec.gov. The information contained on, or accessible through, any of these websites is not incorporated by reference into this Prospectus and is not, and should not be considered to be, a part of this Prospectus, unless it is explicitly so incorporated.

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PRESENTATION OF FINANCIAL INFORMATION

All financial information of Emera (with the exception of the Emera Maine and Emera Caribbean sections of “Management’s Discussion and Analysis”) included in this Prospectus as at December 31, 2015, 2014 and 2013 is reported in Canadian dollars and has been derived from audited historical financial statements of Emera that were prepared in accordance with U.S. GAAP. All financial information of Emera (with the exception of the Emera Maine and Emera Caribbean sections of “Management’s Discussion and Analysis”) included in this Prospectus as at March 31, 2016 and 2015 is reported in Canadian dollars and has been derived from unaudited historical financial statements of Emera that were prepared in accordance with U.S. GAAP. All financial information of TECO Energy included in this Prospectus as at December 31, 2015, 2014 and 2013 is reported in U.S. dollars and has been derived from audited historical financial statements of TECO Energy that were prepared in accordance with U.S. GAAP. All financial information of TECO Energy included in this Prospectus as at March 31, 2016 and 2015 is reported in U.S. dollars and has been derived from unaudited historical financial statements of TECO Energy that were prepared in accordance with U.S. GAAP. The revenues and expenses of TECO Energy shown in the unaudited pro forma consolidated statements of earnings of the Company for the three month period ended March 31, 2016 and for the year ended December 31, 2015 are reported in Canadian dollars and reflect the average U.S. dollar-to-Canadian dollar exchange rates for such periods. The assets and liabilities of TECO Energy shown in the unaudited pro forma consolidated balance sheet of the Company as of March 31, 2016 are reported in Canadian dollars and reflect the U.S. dollar-to-Canadian dollar period-end closing exchange rate. Financial information in this Prospectus that has been derived from the unaudited pro forma consolidated financial statements has been translated to Canadian dollars on the same basis. Certain tables in this Prospectus may not sum to total due to rounding.

Non-U.S. GAAP Financial Measures

Emera uses financial measures that do not have standardized meaning under U.S. GAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-U.S. GAAP measures by adjusting certain U.S. GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period, as detailed below:

Non-U.S. GAAP measure	U.S. GAAP measure
Adjusted net income attributable to common shareholders or adjusted net income	Net income attributable to common shareholders
Adjusted earnings per common share – basic	Earnings per common share – basic
Adjusted contribution to consolidated net income	Contribution to consolidated net income
Adjusted income before provision for income taxes	Income before provision for income taxes
Adjusted contribution to consolidated earnings per common share – basic	Contribution to consolidated earnings per common share – basic
EBITDA	Net income
Adjusted EBITDA	Net income
Electric margin	Income from operations

Emera believes that these non-U.S. GAAP measures are useful to investors because they are frequently used by securities analysts, investors and other interested parties in the evaluation of companies and will provide investors with a useful tool for assessing the comparability between periods of its ability to generate cash from operations sufficient to pay taxes, to service debt and to undertake capital expenditures.

You are encouraged to evaluate each adjustment to the corresponding U.S. GAAP measure and the reasons management considers them appropriate for supplemental analysis. In evaluating these non-U.S. GAAP

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measures, you should be aware that in the future Emera may incur expenses similar to the adjustments in this Prospectus. This presentation should not be construed as an inference that Emera’s future results will be unaffected by such items.

The SEC has adopted rules to regulate the use in filings with the SEC and public disclosures and press releases of non-U.S. GAAP financial measures. The rules prohibit the following, among other things, in filings with the SEC:

• exclusion of charges or liabilities that require, or will require, cash settlement or would have required cash settlement, absent an ability to settle in another manner, from non-U.S. GAAP liquidity measures; and

• adjustment of a non-U.S. GAAP performance measure to eliminate or smooth items identified as non-recurring, infrequent or unusual, when the nature of the charge or gain is such that it has occurred in the past two years or is reasonably likely to recur within the next two years.

The non-U.S. GAAP financial information presented in this Prospectus may not comply with these rules.

The non-U.S. GAAP financial information presented in this Prospectus are measures of our performance that are not required by, or presented in accordance with, U.S. GAAP and should not be considered as an alternative to cash flows from operations, net income, net operating income or any other performance measure derived in accordance with U.S. GAAP or as an alternative measure of our liquidity.

For additional information regarding non-U.S. GAAP measures See “Management’s Discussion and Analysis.”

Adjusted Contribution to Consolidated Net Income, Adjusted Income Before Provision for Income Taxes and Adjusted Contribution to Consolidated Earnings per Common Share—Basic

Emera calculates these non-U.S. GAAP measures by excluding the effect of certain mark-to-market adjustments from their respective U.S. GAAP equivalents.

Mark-to-market adjustments are further discussed in the sections under “Management’s Discussion and Analysis”: “—Consolidated Financial Highlights,” “—Emera Energy—Review of 2015,” “—Pipelines—Review of 2015,” “—Corporate and Other—Review of 2015,” “—Emera Energy—Review of 2016,” “—Pipelines—Review of 2016 and Corporate and Other—Review of 2016.”

Adjusted Net Income and Adjusted Earnings per Common Share—Basic

Emera calculates comparable measures by excluding the effect of:

• the mark-to-market adjustments related to Emera’s held-for-trading derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered;

• the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp Power Company, LLC (“Bear Swamp”) and Northwest Wind Partners II, LLC (“NWP”), until NWP’s sale on January 29, 2015;

• the amortization of transportation capacity recognized as a result of certain trading and marketing transactions;

• the mark-to-market adjustments related to an interest rate swap in Emera Brunswick Pipeline Company Limited (“EBPC”); and

• the mark-to-market adjustments included in Emera’s other income related to the effect of USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the Convertible Debenture Offering in connection with the Acquisition.

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Management believes excluding from income the effect of these mark-to-market valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows.

Mark-to-market adjustments are further discussed in the sections under “Management’s Discussion and Analysis”: “—Consolidated Financial Highlights,” “—Emera Energy—Review of 2015,” “—Pipelines—Review of 2015,” “—Corporate and Other—Review of 2015,” “—Emera Energy—Review of 2016,” “—Pipelines—Review of 2016” and “Corporate and Other—Review of 2016.”

The following is a reconciliation of reported net income attributable to common shareholders to adjusted net income attributable to common shareholders, and reported earnings per common share—basic to adjusted earnings per common share—basic:

	Three months ended March 31						Year ended December 31
	2016			2015			2015		2014		2013
	millions of Canadian dollars (except per share amounts)
Net income attributable to common shareholders	$	44.3		$	160.1		$	397.2	$	406.7	$	217.5
After-tax mark-to-market gain (loss)		(75.9	)		(11.5	)		67.2		87.5		(41.9	)
Adjusted net income attributable to common shareholders		120.2			171.6			330.0		319.2		259.4
Earnings per common share – basic		0.30			1.10			2.72		2.84		1.64
Adjusted earnings per common share – basic		0.81			1.18			2.26		2.23		1.96

Emera EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is a non-U.S. GAAP financial measure used in this Prospectus in respect of Emera. EBITDA is used by numerous investors and lenders to better understand cash flows and credit quality.

“Adjusted EBITDA” is a non-U.S. GAAP financial measure used by Emera. Similar to Adjusted Net Income calculations, this measure represents EBITDA absent the income effect of Emera’s mark-to-market adjustments, as previously discussed.

The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies, but in Emera’s management’s view appropriately reflects Emera’s specific financial condition. These measures are not intended to replace “Net income” which, as determined in accordance with U.S. GAAP, is an indicator of operating performance. Emera’s EBITDA and Adjusted EBITDA are discussed further in the section entitled “Management’s Discussion and Analysis”.

The following is a reconciliation of reported net income to EBITDA and Adjusted EBITDA:

	Three months ended March 31						Year ended December 31
	2016			2015			2015		2014		2013
	millions of Canadian dollars
Net income	$	54.8		$	174.1		$	452.4	$	452.8	$	255.3
Interest expense, net		75.2			44.4			212.6		179.8		172.2
Income tax expense (recovery)		26.8			61.4			92.4		113.6		43.3
Depreciation and amortization		87.5			82.8			339.9		329.0		297.8
EBITDA		244.3			362.7			1,097.3		1,075.2		768.6
Mark-to-market gain (loss), excluding income tax and interest		(75.1	)		(21.5	)		66.1		128.7		(60.9	)
Adjusted EBITDA	$	319.4		$	384.2		$	1,031.2	$	946.5	$	829.5

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TECO Energy EBITDA

EBITDA is a non-U.S. GAAP financial measure used in this Prospectus in respect of TECO Energy. EBITDA is used by numerous investors and lenders to better understand cash flows and credit quality.

TECO Energy’s EBITDA may not be comparable to the EBITDA measures of other companies, but in TECO Energy’s management’s view appropriately reflects TECO Energy’s specific financial condition. These measures are not intended to replace “Net income” which, as determined in accordance with U.S. GAAP, is an indicator of operating performance. TECO Energy’s EBITDA is discussed further in the section entitled “Management’s Discussion and Analysis.”

The following is a reconciliation of reported net income from continuing operations to EBITDA:

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014		2013
	millions of U.S. dollars
Net income from continuing operations	$	73.7	$	63.8	$	241.2	$	206.4		$188.7
Interest expense, net		45.9		47.9		186.4		171.1		161.4
Income tax expense		35.7		39.9		155.3		138.9		112.6
Depreciation and amortization		89.8		85.5		349.0		315.3		291.8
EBITDA	$	245.1	$	237.1	$	931.9	$	831.7		$754.5

Electric Margin

“Electric margin” is a non-U.S. GAAP financial measure used to show the amounts that Nova Scotia Power Incorporated (“NSPI”), Barbados Light & Power Company Limited (“BLPC”), Grand Bahama Power Company Ltd. (“GBPC”) and Dominica Electricity Services Ltd. (“Domlec”) retain to recover non-fuel costs. Prudently incurred fuel costs are recovered from customers, except in Domlec, where substantially all fuel costs are passed to customers through the fuel pass-through mechanism. Management believes measuring electric margin shows the portion of the utilities’ revenues that directly contribute to Emera’s income as distinguished from the portion of revenues that are managed through fuel adjustment mechanisms, which have a minimal impact on income. Emera Energy also reports “Electric margin” because the sales price of electricity and the cost of natural gas used to generate it are highly correlated. However, their absolute values can vary materially over time. Emera Energy believes that “Electric margin,” as the net result, provides a meaningful measure of the business’ performance in addition to the absolute values of sales and fuel expenses, which are also reported. Electric margin, as calculated by Emera, may not be comparable to the electric margin measures of other companies, but in management’s view appropriately reflects Emera’s specific condition. This measure is not intended to replace “Income from operations” which, as determined in accordance with U.S. GAAP, is an indicator of operating performance. Electric margin is discussed further in the sections under “Management’s Discussion and Analysis” “—NSPI—Electric Margin,” “—the Emera Caribbean—Electric Margin” and “—Emera Energy—Adjusted EBITDA”.

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CAUTION REGARDING UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

This Prospectus contains the unaudited pro forma consolidated balance sheet as at March 31, 2016 and consolidated statements of earnings of the Company for the three month period ended March 31, 2016 and for the year ended December 31, 2015, giving effect to: (i) the Acquisition Capital Markets Transactions (as discussed under “Summary—Financing the Acquisition”), (ii) the issuance of common shares of Emera (“Common Shares”) upon conversion of the Convertible Debentures on the Final Instalment Date (assuming payment in full of the Final Instalment of the Convertible Debentures, as discussed under “Description of Other Indebtedness—Convertible Debentures”) and (iii) the consummation of the Acquisition. Any offering of Notes hereunder is not contingent upon the consummation of the Acquisition, the other Acquisition Capital Markets Transactions or payment in full of the Final Instalment of the Convertible Debentures. The unaudited pro forma financial statements included herein do not give effect to the sale by Emera of 50.1 million common shares of Algonquin Power & Utilities Corp. (“APUC”). See “Summary—Recent Developments.”

Emera intends to raise up to approximately Cdn$6.6 billion in aggregate principal amount in the Acquisition Capital Markets Transactions. The aggregate principal amounts raised in the Acquisition Capital Markets Transactions and the terms on which such securities are issued are dependent on market and other conditions and may vary. To the extent (i) Emera raises less than Cdn$6.6 billion in connection with the Acquisition Capital Markets Transactions, or (ii) Emera does not receive payment in full of the Final Instalment of the Convertible Debentures, Emera intends to pay any shortfall by drawing on the Acquisition Credit Facilities and/or using existing cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) or other sources available to Emera in order to consummate the Acquisition. See “Summary—Financing the Acquisition.”

The unaudited pro forma consolidated financial statements have been prepared using certain of the Company’s and TECO Energy’s respective financial statements as more particularly described in the notes to such unaudited pro forma consolidated financial statements. In preparing such unaudited pro forma consolidated financial statements, Emera has had limited access to the non-public books and records of TECO Energy and makes no representation or warranty as to the accuracy or completeness of such information provided by TECO Energy, including the financial statements of TECO Energy that were used to prepare the unaudited pro forma consolidated financial statements. The unaudited pro forma combined financial information included in this Prospectus has not been prepared in compliance with Regulation S-X.

Such unaudited pro forma consolidated financial statements are not intended to be indicative of the results that would actually have occurred, or the results expected in future periods, had the events reflected herein occurred on the dates indicated. Actual amounts recorded upon the finalization of the purchase price allocation under the Acquisition may differ from such unaudited pro forma consolidated financial statements. Since the unaudited pro forma consolidated financial statements have been developed to retroactively show the effect of transactions that are expected to occur at a later date (even though this was accomplished by following generally accepted practice using reasonable assumptions), there are limitations inherent in the very nature of pro forma data. The data contained in the unaudited pro forma consolidated financial statements represents only a simulation of the potential impact of the Acquisition. Undue reliance should not be placed on such unaudited pro forma consolidated financial statements. See “Special Note Regarding Forward-Looking Statements” and “Risk Factors.”

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CURRENCY

In this Prospectus, unless otherwise specified or the context otherwise requires, all dollar amounts are expressed in Canadian dollars. References to “Canadian dollars”, “$”, “CAD” or “Cdn$” are to lawful currency of Canada. References to “U.S. dollars”, “USD”, “US$” or “U.S.$” are to lawful currency of the United States of America.

The following table sets forth, for each of the periods indicated, the noon exchange rate, the average noon exchange rate and the high and low noon exchange rates of one U.S. dollar in exchange for Canadian dollars as reported by the Bank of Canada.

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014		2013
High		1.4589		1.2803		1.3990		1.1643		1.0697
Low		1.2962		1.1728		1.1728		1.0614		0.9839
Average		1.3732		1.2412		1.2787		1.1045		1.0299
Period End		1.2971		1.2683		1.3840		1.1601		1.0636

On June 7, 2016, the noon exchange rate as reported by the Bank of Canada was U.S.$1.00 = $1.2789.

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THIRD PARTY SOURCES AND INDUSTRY DATA

This Prospectus contains information from publicly available third party sources as well as industry data prepared by the Company’s management on the basis of its knowledge of the regulated electric and gas utility industry in which Emera operates (including management’s estimates and assumptions relating to the industry based on that knowledge). Emera’s management’s knowledge of the regulated utility industry has been developed through its experience and participation in the industry. Emera’s management believes that its industry data is accurate and that its estimates and assumptions are reasonable, but there can be no assurance as to the accuracy or completeness of this data. Third-party sources generally state that the information contained therein has been obtained from sources believed to be reliable, but there can be no assurance as to the accuracy or completeness of included information. Although Emera’s management believes it to be reliable, Emera has not independently verified any of the data from third-party sources referred to in this Prospectus or analyzed or verified the underlying studies or surveys relied upon or referred to by such sources, or ascertained the underlying economic assumptions relied upon or referred to by such sources.

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SUMMARY

The following information is a summary only and is to be read in conjunction with, and is qualified in its entirety by, the more detailed information and financial data and statements appearing elsewhere in this Prospectus and in the documents incorporated by reference herein.

Unless otherwise indicated by the context, the terms “Emera,” the “Company,” “we,” “our,” and “us” refer to Emera Incorporated, and, if the context requires, its subsidiaries.

Unless otherwise indicated by the context, the term “TECO Energy” refers to the holding company TECO Energy, Inc. and its subsidiaries, and references to individual subsidiaries of TECO Energy, Inc. refer to that company and its respective subsidiaries.

Unless otherwise indicated by the context, the term “Acquisition” refers to the acquisition by Emera of TECO Energy pursuant to the terms of the Acquisition Agreement.

In this Prospectus, unless otherwise specified or the context otherwise requires, all dollar amounts are expressed in Canadian dollars. References to “Canadian dollars,” “$,” “CAD” or “Cdn$” are to lawful currency of Canada. References to “U.S. dollars,” “USD”, “U.S.$” or “US$” are to lawful currency of the United States of America.

Please refer to the “Glossary” beginning on page 40 of this Prospectus for a list of defined terms used herein.

Company Overview

Emera

Emera is a geographically diverse energy and services company headquartered in Halifax, Nova Scotia with approximately Cdn$11.5 billion in assets as of March 31, 2016 and 2015 revenues of Cdn$2.79 billion. Emera invests in electricity generation, transmission and distribution, gas transmission and utility services. Emera currently provides regional energy solutions by connecting its assets, markets and partners in eastern Canada, northeastern United States and the Caribbean. Emera’s business continues to grow and evolve. Meeting customer demand for cleaner affordable energy remains central to Emera’s strategy.

Key Lines of Business

Utilities

Regulated utilities are the foundation of Emera’s business, providing the company with strong and consistent earnings. From its beginnings as NS Power Holdings Incorporated in 1998 following the privatization of Nova Scotia Power Corporation in 1992, Emera has grown by investing in its businesses, and through strategic acquisitions. Emera became an international business with the acquisition of Bangor Hydro in 2001, and expanded its investment in the State of Maine by adding Maine & Maritimes Corporation in 2010. In the Caribbean, Emera has built a business of scale, starting with its investment in St. Lucia’s electric utility in 2007, and now holding an indirect majority ownership interest in electric utilities in Grand Bahama and Dominica and a 100% indirect ownership interest in The Barbados Light & Power Company Limited.

At the core of Emera’s utilities strategy is identifying opportunities to invest in the transition from higher carbon methods of electricity generation to lower carbon alternatives. NSPI has invested in wind energy, biomass and hydroelectricity with the result that in 2015, 27% of NSPI’s generation mix was derived from renewable sources, and on track to meet a minimum 40% renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives, with an emphasis on affordability and fuel cost stability for its customers.

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Transmission

Emera is investing in electricity transmission to help get new renewable energy to market. Emera’s leadership in the Maritime Link Project is expected to transform the electricity market in the Atlantic Provinces, enabling growth in the availability of clean, renewable energy for the region. In addition, the Atlantic Provinces will be connected to the Northeastern United States, providing potential for excess renewable energy to be delivered throughout that region.

Non-regulated

Since its formation in 2003, Emera Energy has become an active participant in the Northeastern United States electricity and natural gas marketplace. It has built a strong marketing, trading and asset management business, based on comprehensive market knowledge, a focus on customer service and robust risk management. The integration and performance of the three New England Gas Generation Facilities purchased in 2013 has contributed significantly to the success of Emera Energy. Emera Energy has invested to improve the performance of its natural gas generation assets in New England, creating long-term value for its business.

As it has grown, Emera has held true to the core values that guide its business: building relationships by acting with integrity, focusing on operations and service excellence, investing in its people, and making safety and health its foremost priority. For more information on Emera’s business operations, see “Business”.

Emera’s Segments

Emera manages its reportable segments separately due to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contributions of revenues, net income attributable to common shareholders and total assets. As of March 31, 2016, Emera had the following six reportable segments: NSPI, Emera Maine, Emera Caribbean, Pipelines, Emera Energy and Corporate and Other.

Nova Scotia Power Inc.

NSPI was created in 1992 through the privatization of the Crown corporation, Nova Scotia Power Corporation. NSPI is a fully-integrated regulated electric utility and is the primary electricity supplier in Nova Scotia, Canada. As of March 31, 2016 NSPI has Cdn$4.6 billion of assets and provides electricity generation, transmission and distribution services to approximately 507,000 customers. NSPI owns 2,483 megawatts (“MW”) of generating capacity, of which approximately 50% is coal-fired; 28% of which is natural gas and/or oil; 19% of which is hydro and wind and 3% of which is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from independent power producers (“IPP”). These IPPs own and operate 496 MW of wind and biomass fueled generation capacity, which is expected to increase to 552 MW by the end of 2016. NSPI also owns approximately 5,000 kilometres of transmission facilities and 27,000 kilometres of distribution facilities. NSPI has a workforce of approximately 1,700 people. NSPI is a public utility as defined in the Public Utilities Act (Nova Scotia) (the “Public Utilities Act”) and is subject to regulation under the Public Utilities Act by the Nova Scotia Utility and Review Board (the “UARB”). The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings from time to time at its request or at the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates established to recover prudently incurred costs of providing electricity service to customers, and to provide an appropriate return to investors. NSPI has a fuel adjustment mechanism (“FAM”), approved by the UARB, allowing NSPI to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. Differences between prudently incurred fuel for generation

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and purchased power and certain fuel-related costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

Emera Maine

Emera Maine is a transmission and distribution (“T&D”) electric utility with assets of approximately Cdn$1.1 billion serving approximately 158,000 customers in the State of Maine (as of March 31, 2016). Effective January 1, 2014, Bangor Hydro Electric Company (“Bangor Hydro”) and Maine Public Service Company (“MPS”) merged, becoming Emera Maine.

Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through Emera Maine’s T&D networks. Emera Maine owns and operates approximately 1,700 kilometres of transmission facilities and 15,000 kilometres of distribution facilities. Emera Maine’s workforce is approximately 400 people.

Approximately 55% of Emera Maine’s electric revenue represents distribution operations, 31% is associated with local transmission operations and 14% relates to stranded cost recoveries. The rates for each element are established in distinct regulatory proceedings.

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC.

There are two transmission districts in Emera Maine: Bangor Hydro District and MPS District, each of which correspond to the service territories of the two pre-merger entities.

Local transmission rates for Bangor Hydro District (the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook) are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. The Bangor Hydro District’s bulk transmission assets are managed by ISO-NE as part of a region-wide pool of assets. ISO-NE manages the region’s bulk power generation and transmission systems and administers the open access transmission tariff. Currently, the Bangor Hydro District, along with all other participating transmission providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year.

Local transmission rates for MPS District (the franchise electric service territory associated with the former Maine Public Service Company in the Maine counties of Aroostook and a portion of Penobscot) are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers, based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted investments. The MPS District electric service territory is not connected to the New England bulk power system and it is not a member of ISO-NE.

Emera Caribbean

Emera Caribbean includes the following consolidated and non-consolidated investments:

• 100% (December 31, 2015 – 95.5%) investment in Emera (Caribbean) Incorporated (“ECI”) and its wholly owned subsidiary Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and the provider of electricity on the island of Barbados, serving approximately 126,000 customers and regulated by the Fair Trading Commission, Barbados. The government of Barbados has

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granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. BLPC owns 239 MW of oil-fired generation, 116 kilometres of transmission facilities and 2,800 kilometres of distribution facilities. BLPC has a workforce of 330 people. BLPC is regulated under a cost-of-service model with rates set to recover prudently incurred costs of providing electricity service to customers, and to provide an appropriate return to investors. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner.

• 50.0% direct and 30.4% indirect interest (through a 60.7% interest in ICD Utilities Ltd. (“ICDU”) in Grand Bahama Power Company Ltd. (“GBPC”), which is a vertically integrated utility and the sole provider of electricity on Grand Bahama Island. GBPC serves approximately 19,000 customers. GBPC owns 98 MW of oil-fired generation, 138 kilometres of transmission facilities and 850 kilometres of distribution facilities and has a workforce of 205 people. GBPC is regulated by Grand Bahama Port Authority (“GBPA”), which has granted GBPC a licensed, regulated and exclusive franchise to generate, transmit and distribute electricity on the island until 2054. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner.

• 51.9% (December 31, 2015 – 49.6%) indirect controlling interest, through ECI, in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica. Domlec serves approximately 36,000 customers and is regulated by the Independent Regulatory Commission, Dominica. Domlec owns 20 MW of oil-fired generation, 7 MW of hydro production, 452 kilometres of transmission facilities and 640 kilometres of distribution facilities. Domlec has a workforce of 238 people. On October 7, 2013, the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014, for a period of 25 years. Domlec’s approved allowable regulated return on rate base for 2016 is 15.0%. A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely manner.

• 19.1% indirect interest, through ECI, in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia, which is regulated by the Government of St. Lucia. The investment in Lucelec is accounted for on the equity basis.

Pipelines

Pipelines comprises Emera’s wholly owned Brunswick Pipeline and Emera’s 12.89% interest in M&NP.

• Brunswick Pipeline is a 145-kilometre pipeline delivering re-gasified natural gas from the Canaport™ liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick, to markets in the northeastern United States for Repsol Energy Canada under a 25-year firm service agreement which expires in 2034. The NEB, which regulates Brunswick Pipeline, has classified it as a Group II pipeline. The agreement is accounted for as a direct financing lease.

• M&NP is a 1,400-kilometre transmission pipeline built to transport natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. The investment in M&NP is accounted for on the equity basis.

Emera Energy

Emera Energy includes the following:

• Emera Energy Services (“EES”), a wholly owned physical energy marketing and trading business.

• Emera Energy Generation (“EEG”), consisting of a wholly owned portfolio of electricity generation facilities in New England and the Maritime provinces of Canada with 1,410 MW of total capacity.

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• Emera’s 50.0% joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

Corporate and Other

Corporate encompasses certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, internal audit, investor relations, risk management, insurance, acquisition-related costs and corporate human resource activities. It also includes interest revenue on intercompany financings, and costs associated with corporate activities that are not directly allocated to the operations of Emera’s consolidated subsidiaries and investments.

Other includes various consolidated and non-consolidated investments, including:

Consolidated Investments

• Emera Utility Services, which is a utility services contractor primarily operating in Atlantic Canada.

• Emera Reinsurance Limited, which is a captive insurance company providing insurance and reinsurance to Emera and its affiliates.

Non-consolidated Investments

• Emera’s 4.75% (March 31, 2016: 23.2% ) investment in APUC. APUC is a diversified generation, transmission and distribution utility traded on the Toronto Stock Exchange (“TSX”) under the symbol “AQN,” the distribution group operates in the United States and provides rate regulated water, electricity and natural gas utility services. The non-regulated generation group owns or has interests in a portfolio of North American based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission group invests in rate-regulated electric transmission and natural gas pipeline systems in the United States and Canada. For information regarding Emera’s recent sale of a portion of its ownership interest in APUC, see “Summary—Recent Developments.”

• Emera’s 100% investment in Emera Newfoundland and Labrador Holdings, Incorporated (“ENL”), which holds investments in the following:

• Emera’s 100% investment in NSP Maritime Link Incorporated (“NSPML”), a $1.56 billion transmission project, including two 170-kilometre subsea cables, between the island of Newfoundland and Nova Scotia. The investment in NSPML is accounted for on the equity basis with equity earnings equal to the return on equity component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017.

• Emera’s 59.0% (December 31, 2015 – 55.5%) investment in the partnership capital of Labrador Island Link Limited Partnership (“LIL”), a $3.1 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change based on the balance of capital investments required from Emera and Nalcor to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49% of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is expected to go into service in 2017. Emera’s total investment is expected to approximate Cdn$409.1 million.

• Other investments.

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Organizational Structure

The following chart provides a summary of Emera’s organizational structure as of December 31, 2015 on a pro forma basis after giving effect to the Acquisition. The chart depicts (i) Emera’s reportable segments (including consolidated and non-consolidated investments) and (ii) selected subsidiaries of Emera.

Simplified Pro Forma Organization Chart

Business Strategy

Emera’s business strategy consists of the following key components:

Focus on identifying reliable and affordable energy solutions, typically including the replacement of higher carbon electricity generation with generation from cleaner sources, and the related transmission and distribution infrastructure to deliver energy to that market

• Emera is investing Cdn$2.2 billion to build the Maritime Link and associated projects, which will bring clean hydro energy from Labrador to Nova Scotia, and create opportunities for surplus renewable energy to supply other markets.

• NSPI has invested in wind energy, biomass and hydroelectricity, which has driven substantial increases in the portion of its generation mix derived from renewable sources (reaching 27% in 2015 and on track to meet its 40% target by 2020).

• Numerous other investments and initiatives are underway, from a new utility grade solar facility in Barbados to the Maine Renewable Energy Interconnect (“MREI”) transmission proposal, designed to deliver new wind energy in northern Maine to markets in southern New England.

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Develop strong partnerships and relationships throughout the regions in which we operate and utilize a collaborative approach to strategic partnerships

• The foundation of Emera’s strategy is its collaborative approach to strategic partnerships and its ability to develop strong relationships throughout the regions in which it operates. Prime examples of Emera’s success in this areas include:

• The Maritime Link project, where Emera and its partner Nalcor, along with the Government of Canada and the Provinces of Nova Scotia and Newfoundland and Labrador, have entered into numerous agreements and partnerships to deliver and finance the Maritime Link, the Labrador Island Link and the related Muskrat Falls project.

• Emera’s Strategic Investment Agreement (“SIA”) with APUC establishes how Emera and APUC will work together to pursue specific strategic investments of mutual benefit. While Emera recently announced that it has reduced its direct investment in APUC, the SIA remains in place as both companies value the partnership. See “Summary—Recent Developments.”

• Emera has a number of other partnerships and collaborative agreements across its operating regions, including a joint dispatch project between NSPI and New Brunswick Power Corporation (“NB Power”), a partnership between Emera Maine and Central Maine Power Company to develop the MREI, and the Massachusetts Clean Electricity Partnership, an alliance including Brookfield Renewable Partners, Hydro-Québec, Nalcor, NB Power, SunEdison and TDI New England to promote clean energy investments in New England.

Establish a diverse investment and operations profile

• Emera is a geographically diverse company, operating in Canada, the United States, and the Caribbean.

• Its operations include:

• vertically integrated electric utilities in Nova Scotia, Barbados, Dominica and Grand Bahama;

• a transmission and distribution electric utility in Maine;

• a portfolio of generation facilities, including combined-cycle natural gas and pumped storage hydro in Atlantic Canada and the U.S. northeast;

• investments in two natural gas pipelines in Atlantic Canada and New England;

• natural gas marketing and trading;

• a utility services contractor in Atlantic Canada;

• a Cdn$2.2 billion project to bring clean hydro energy from Labrador to Nova Scotia; and

• minority interests in numerous energy projects and companies.

Employ operating and governance models that focus on operational excellence, constructive regulatory approaches, proactive stakeholder engagement and a customer focus through service reliability and rate stability

• Emera’s focus on maintaining the highest standards of governance practices is evident in a number of ways including, for example:

• The Maritime Link project’s on time and on budget record, notwithstanding the ambitious and ground-breaking nature of the project, the changing economic climate during the course of the project, and the challenge other similar projects have had with budget and schedule;

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• Emera’s consistently high ranking (2nd overall in 2015) in a survey of governance practices among Canada’s publicly traded companies, conducted each year by the Globe & Mail’s Report on Business; and

• The establishment of operating boards for Emera’s subsidiaries, and the inclusion of local business and community leaders on these boards as well as Emera executives. This practice has helped Emera develop constructive regulatory approaches, proactive stakeholder engagement and maintain a customer focus in its businesses in each of the markets it operates in.

Competitive Strengths

We believe we have the following key competitive strengths to enable us to carry out our business strategy.

Diverse, increasingly regulated profile

• The portion of Emera’s adjusted net income generated from rate regulated business has grown from 67% in 2014 to 72% in the 12 months ended March 31, 2016. On a pro forma basis, the Acquisition will bring Emera’s regulated earnings to greater than 80%.

• Emera targets achieving 75% to 85% of its adjusted net income from rate-regulated subsidiaries, which contribute strong, predictable income and cash flows, and which is reflective of Emera’s risk tolerance.

Supportive and stable regulatory environments

• Through its long history of operating regulated businesses, Emera has gained an appreciation for the importance of constructive, professional regulatory oversight. Emera’s experience in jurisdictions such as Nova Scotia and Maine, where it has built robust regulatory teams and practices, was a significant factor in making stable regulatory environments a key criteria in its assessment of growth opportunities, including the Acquisition.

Strong balance sheet, cash flow and liquidity position

• Over the last 10 years, Emera’s strong balance sheet, and its ability to raise the capital necessary to fund investments has been a strong enabler of its growth. This was demonstrated in Emera’s issue of the Convertible Debentures represented by instalment receipts in connection with the Acquisition.

• In addition to access to debt and equity capital markets, cash flow from operations has grown substantially, from Cdn$419 million for the year ended December 31, 2010 to approximately Cdn$674 million for the year ended December 31, 2015.

• Emera and its subsidiaries maintain strong credit metrics, and Emera has consistently maintained a strong, investment grade credit rating, which is an important component of Emera’s financing strategy.

Sizeable capital investment plan to drive growth

• Emera has a Cdn$4.2 billion capital investment plan over the next five years, a significant portion of which is related to the Maritime Link and Labrador Island Link projects.

• This capital plan increases to Cdn$8.3 billion, on a pro forma basis, when TECO Energy’s US$4.1 billion in planned capital investments are included.

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Disciplined investment criteria

• Emera’s focused growth strategy and disciplined investment criteria has served it well. Throughout the period of declining interest rates, its investment hurdle rate has remained unchanged, ensuring that any investment met long term criteria.

• Similarly, Emera’s strategic target of earning 75-85% of its adjusted net income from rate-regulated subsidiaries meant that the search for growth opportunities in 2014 and 2015 was focused on rate-regulated businesses.

The Acquisition

Acquisition Overview

On September 4, 2015, Emera announced a definitive agreement for Emera to acquire TECO Energy. TECO Energy shareholders will receive U.S.$27.55 per common share of TECO Energy, which represents an aggregate purchase price of approximately U.S.$10.6 billion and which includes the assumption of approximately U.S.$4.1 billion of debt. The closing of the Acquisition is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on December 3, 2015), (ii) approvals by the New Mexico Public Regulation Commission (the “NMPRC”), (iii) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Acquisition, (iv) the absence of any material adverse effect with respect to TECO Energy and (v) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Acquisition Agreement.

On April 11, 2016, Emera and TECO Energy filed with the NMPRC an unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the Acquisition. In the stipulation, the parties state that they believe the settlement is in the public interest and have recommended approval to the NMPRC. Amongst other elements, the stipulation includes Emera’s agreement to maintain the commitments made by TECO Energy in its 2014 case relating to its acquisition of New Mexico Gas Company (“NMGC”), invest in the expansion of the natural gas system to underserved communities and the Mexican border, and provide resources to support certain economic growth projects and programs. The stipulation is subject to review and approval by the NMPRC. On May 2, 2016 the hearing examiner held a hearing in connection with the joint application to the NMPRC of the change in control of NMGC affected by the Acquisition. A final order of the NMPRC is expected in mid-2016. The closing of the Acquisition is currently expected to occur in mid-2016, although there can be no assurance the Acquisition will occur within the expected timeframe, as contemplated, or at all.

To finance a portion of the Acquisition, Emera, through the Selling Debentureholder, on September 28, 2015, completed the sale of $1.9 billion of Convertible Debentures (the “Convertible Debenture Offering”). On October 2, 2015, in connection with the Convertible Debenture Offering, the underwriters fully exercised an over-allotment option and purchased an additional $285 million aggregate principal amount of Convertible Debentures at the Convertible Debenture offering price. The sale of the additional Convertible Debentures brought the aggregate proceeds of the Convertible Debenture Offering to $2.185 billion, assuming payment of the final instalment. See “Description of Other Indebtedness—Convertible Debenture Offering.” Additionally, on May 24, 2016, Emera sold a portion of its ownership interest in APUC. See “Management’s Discussion and Analysis—Recent Developments.”

TECO Energy is a utility holding company headquartered in Tampa, Florida engaged through its subsidiaries in the regulated vertically-integrated electric utility business in Florida and natural gas transmission and distribution business in Florida and New Mexico. TECO Energy’s operating revenue in fiscal 2015 totalled approximately

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U.S.$2.7 billion and for the three-month period ended March 31, 2016 totalled approximately U.S.$659.5 million. As at March 31, 2016, TECO Energy had total assets of approximately U.S.$9.0 billion. Virtually all of TECO Energy’s operating revenue is from regulated businesses.

The offering of any series of Notes hereunder is not contingent upon the completion of the Acquisition, which, if completed may occur subsequent to certain offerings hereunder.

Giving effect to the Acquisition as if it closed on March 31, 2016, the Company’s total assets would have increased from approximately Cdn$11 billion (U.S.$9 billion) to approximately Cdn$28 billion (U.S.$21 billion) and the percentage of its EBITDA that is regulated EBITDA would have increased from approximately 70% to over 90% (excluding Emera Corporate and Other (except for ENL) and TECO Energy discontinued operations, TECO Energy Corporate and Other). See “Unaudited Pro Forma Consolidated Financial Statements.” The Acquisition is expected to increase the Company’s consolidated rate base by approximately U.S.$6.5 billion and its total customers by approximately 1.6 million. Following the Acquisition, the regulated utility subsidiaries of Emera will serve approximately 2.5 million customers.

TECO Energy Overview

TECO Energy was incorporated in Florida in 1981 as part of a restructuring in which it became the parent corporation of Tampa Electric Company (“TEC”). TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiary, New Mexico Gas Intermediate, Inc. (“NMGI”), NMGC. TECO Energy and its subsidiaries had approximately 3,700 employees as of March 31, 2016.

TEC, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division provided retail electric service to approximately 725,000 customers on average in West Central Florida for the three months ended March 31, 2016, and has a net winter system generating capacity of 4,730 MW. PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. With approximately 365,000 customers on average for the three months ended March 31, 2016, PGS has operations in Florida’s major metropolitan areas and most populous counties including: Miami-Dade, Broward, Palm Beach, Hillsborough and Orange. Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) in 2015 was almost 1.8 billion therms.

NMGC, a Delaware corporation and wholly-owned subsidiary of NMGI, was acquired by TECO Energy on September 2, 2014. NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in New Mexico. With approximately 520,000 customers on average for the three months ended March 31, 2016, NMGC serves approximately 60% of the state’s population in 23 of New Mexico’s 33 counties. NMGC’s largest concentration of customers (approximately 360,000) is in the region known as the Central Rio Grande Corridor, which includes the communities of Albuquerque, Belen, Rio Rancho and Santa Fe.

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Sale of TECO Coal

On September 21, 2015, TECO Diversified, a wholly-owned subsidiary of TECO Energy, entered into a securities purchase agreement for the sale of TECO Coal to Cambrian Coal Corp. The securities purchase agreement did not provide for an up-front purchase payment, but provides for contingent payments of up to U.S.$60 million that may be paid in the years up to 2019 depending on specified coal benchmark prices. TECO Energy retains certain deferred tax assets and personnel related liabilities, but all other TECO Coal assets and liabilities were transferred in the transaction. The retained liabilities included pension liability, which was fully funded at September 30, 2015, and severance agreements, which were paid in 2015. In addition, TECO Energy retained obligations under letters of indemnity that guarantee payments on bonds posted for the reclamation of mines prior to the transfer of all permits to the purchaser by the Commonwealths of Kentucky and Virginia. TECO Energy is working with the purchaser and the respective permitting agencies to have all permits transferred to the purchaser by the end of 2016.

The securities purchase agreement called for a simultaneous signing and closing, which occurred on September 21, 2015. The closing of this sale essentially completed the process of TECO Energy’s exit from unregulated operations to focus on regulated utility businesses.

As a result of the authorization by TECO Energy’s Board of Directors authorizing it to enter into negotiations for the sale of TECO Coal, effective in the third quarter of 2014 it was classified as asset held for sale and its results for all periods presented are classified on TECO Energy’s financial statements as discontinued operations. TECO Energy recorded a non-cash valuation adjustment of approximately U.S.$76 million, after tax, to the carrying value of TECO Coal to reflect the sales price specified under a sales agreement entered into in October 2014, and an additional U.S.$51 million impairment charge, including a U.S.$7.7 million charge related to black lung liabilities was recorded in 2015.

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Acquisition Highlights

The Acquisition will propel Emera into a top 20 North American regulated utility as ranked by asset size, with geographic diversity and significant growth potential. TECO Energy represents an accretive opportunity for Emera to further diversify its regulated assets, net income and cash flows in growth markets and constructive regulatory environments, while furthering its strategic objective to supply customers with generation from cleaner sources. Features of the Acquisition and TECO Energy business include:

• Accretive to Earnings, Growth and Scale. Management expects the Acquisition to be accretive to Emera’s earnings per Common Share and to provide support for Emera’s dividend growth target through and beyond 2019 and to improve Emera’s long-term growth due to the favourable growth profile of the Florida and New Mexico economies and constructive regulatory environments. As a result of the Acquisition, Emera will become one of the top 20 largest regulated utility companies in North America as ranked by asset size, helping to ensure access to equity and debt capital markets and economies of scale.

• Acquisition of a Pure-Play Regulated Utility—Increase in Regulated Net Income. Following the closing of the acquisition of TECO Energy, a utility holding company with virtually all of its net income derived from regulated businesses, the percentage of Emera’s net income that is derived from regulated business is expected to increase from approximately 70% to over 80% (excluding Emera Corporate and Other (except for ENL) and TECO Energy discontinued operations, TECO Energy Corporate and Other).

• Increase in Diversification. The Acquisition will help Emera diversify net income across several regulatory jurisdictions, geographies and business lines. Emera anticipates that this increased diversification in net income derived from regulated businesses will enhance the stability of net income (partially due to complementary seasonality) and overall quality of cash flows, and should also assist in strengthening its credit profile.

• Constructive Regulatory Jurisdictions. The majority of TECO Energy’s earnings are derived from Florida, which is a constructive regulatory environment. The Florida Public Service Commission (the “FPSC”) regulates the operations of Tampa Electric and PGS in Florida. In addition, Tampa Electric has a fuel recovery clause and PGS has recovery clauses in place for purchased gas and cast iron and bare steel pipe replacement, as well as higher increased fixed monthly customer charges that reduce volume sensitivity. NMGC, TECO Energy’s gas operations located in New Mexico, is regulated by the NMPRC, which allows for the basic costs, excluding purchased gas, storage and interstate capacity, to be provided for through rates. NMGC has a purchased gas adjustment clause (“PGAC”) which allows it to recover the cost of purchased gas on a timely basis.

• Rate Base Growth Through Capital Investment. TECO Energy’s continued investment in its gas and electric businesses to support customer growth, system reliability and facilities is expected to drive rate base growth over the next several years. Over the long term, Emera believes there is an opportunity to participate in the shift in generation from high carbon sources to low carbon sources as Tampa Electric moves from coal-fired generation to a diversified portfolio of generation that includes gas-fired generating capacity and renewable energy sources.

• Favourable Florida Economic Indicators. Florida is the third most populous state in the United States and ranks as the fourth largest economy in the United States. According to the Florida Office of Economic & Demographic Research, job growth and improvements in the housing market are expected to contribute to the growth of Florida’s economy and GDP growth is forecast to continue through 2016, with an expected increase of 3.4%.

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• Favourable New Mexico Economic Indicators. New Mexico is the 36^th most populous state in the United States. Sustained job growth of approximately 10,000 jobs per year is forecast through 2017 and the current forecast of GDP growth in 2016 in New Mexico is 2.5% as forecasted by the University of New Mexico Bureau of Business & Economic Research.

• Experienced Management Team. TECO Energy’s management has a demonstrated track record of working productively with regulators and policy makers, employing a customer focus and regulatory management philosophy in its operating geographies that results in timely recovery of costs and returns on its capital employed. Emera believes that TECO Energy and Emera have complementary management teams and corporate cultures focused on safety and customer service that will facilitate the combination of Emera and TECO Energy following completion of the Acquisition.

• Community and Stakeholder Engagement. Emera’s approach to combining newly-acquired entities with existing operations is premised on creating value for customers, continuing to invest in the communities in which the acquisition entities operate and aligning Emera’s management team and employee base with those of the acquisition entities. Emera intends to continue to invest in local communities in Florida and New Mexico where TECO Energy operates, to preserve TECO Energy’s existing headquarter locations and local boards of directors in each state and to retain TECO Energy’s existing management team, allowing local managers to be responsive to employees, customers and regulators.

Financing the Acquisition

The cash purchase price of the Acquisition and the Acquisition-Related Expenses will be financed at the closing of the Acquisition with a combination of some or all of the following: (i) the proceeds from the Acquisition Capital Markets Transactions, including the offering of any Notes pursuant to one or more Prospectus Supplements, (ii) the receipt of payment in full on the Final Instalment Date of the Final Instalment due under the Convertible Debentures, (iii) amounts drawn under the Acquisition Credit Facilities, if any, and (iv) existing cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) and other sources available to the Company.

In connection with financing the Acquisition, in addition to the offering by Emera of any series of Notes pursuant to one or more Prospectus Supplements, Emera US Finance intends to issue Senior Guaranteed Notes. In addition, Emera intends to issue one or more series of Canadian dollar-denominated unsecured senior notes, and may also issue Canadian dollar-denominated unsecured subordinated notes, in each case, on a basis which is exempt from the prospectus requirements of applicable Canadian securities laws. These offerings are collectively referred to herein as the “Acquisition Capital Markets Transactions.” Emera intends to raise up to approximately Cdn$6.6 billion in aggregate principal amount in the Acquisition Capital Markets Transactions. The aggregate principal amounts raised in the Acquisition Capital Markets Transactions and the terms on which such securities are issued are dependent on market and other conditions and may vary. Nothing contained herein shall be deemed to constitute an offer to sell or a solicitation of an offer to buy any of the securities to be issued in the Acquisition Capital Markets Transactions other than any Notes offered hereunder.

The closing of any offering of any series of Notes hereunder is not contingent upon the consummation of the Acquisition, the other Acquisition Capital Markets Transactions or payment in full of the Final Instalment of the Convertible Debentures. To the extent (i) Emera raises less than Cdn$6.6 billion in connection with the Acquisition Capital Markets Transactions, or (ii) Emera does not receive payment in full of the Final Instalment of the Convertible Debentures, Emera intends to pay any shortfall by drawing on the Acquisition Credit Facilities and/or using existing cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) or other sources available to Emera in order to consummate the Acquisition.

The net proceeds of any offering of Notes will be used as set forth in the applicable Prospectus Supplement. Such uses may include financing directly or indirectly, part of the purchase price payable for the Acquisition

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(including Acquisition-Related Expenses) and to reduce amounts outstanding under the Acquisition Credit Facilities established in favour of Emera to fund the purchase price payable for the Acquisition, to the extent any amounts are drawn on such facilities in connection with the Acquisition.

See “Use of Proceeds” for information concerning the use of proceeds of offerings hereunder, “Description of Other Indebtedness” for information concerning the Subordinated Notes, the Acquisition Credit Facilities and the Revolving Facility, and “Risk Factors” for a discussion of certain risks relating to the financing of the Acquisition.

Recent Developments

On May 17, 2016, Emera announced that it had agreed to sell all of its 50.1 million common shares of APUC representing approximately 19.3% of the issued and outstanding common shares, to a syndicate of underwriters at Cdn$10.85 per common share, for an aggregate gross amount of approximately Cdn$544 million. The sale was completed on May 24, 2016. Emera intends to use the net proceeds from the sale in support of its general financing requirements, including the Acquisition. Emera continues to hold an equity interest in APUC equivalent to approximately 12.9 million common shares (in the form of subscription receipts and dividend equivalents), which upon conversion represent a continuing common equity interest of approximately 4.75%.

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The Notes

The specific terms of any offering of the Notes will be set forth in one or more Prospectus Supplements. You should read this Prospectus and any applicable Prospectus Supplement before you invest in any Notes.

Issuer: Emera Incorporated, a company formed under the Companies Act (Nova Scotia).

Offering: Unsecured, subordinated notes of Emera (the “Notes”).

Principal Amount of Notes: Up to U.S.$1,250,000,000 Notes.

Terms of the Notes: The Notes may be issued in one or more separate series. The Prospectus Supplement relating to the particular series of Notes being offered will specify the particular amounts, prices and terms of those Notes. These terms may include:

• the title of the Notes;

• any limit on the aggregate principal amount of the Notes of the series;

• the date on which the Notes will mature;

• the interest rate or rates, or the method of determining those rates;

• the date from which interest will accrue or the method for determining such date;

• the interest payment dates and the regular record dates;

• the places where payments will be made;

• any mandatory or optional redemption provisions;

• any additions to the events of default or covenants included in the Trust Indenture, as described in this Prospectus;

• if other than U.S. dollars, the currency or currencies, or units based on or related to currencies, in which payments on the Notes will be payable;

• whether the Notes will be issued in the form of a global security; and

• any other specific terms of the Notes

Specified Denominations: Minimum denominations of U.S.$2,000 and integral multiples of U.S.$1,000 in excess thereof.

Maturity Date: Each series of Notes will mature sixty (60) years from the date of issue (the “Maturity Date”).

Interest: During the initial ten (10) year period following the issuance of any series of Notes, Emera will pay interest on such Notes at the rate specified in the applicable Prospectus Supplement in equal semi-annual installments.

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Starting on the date which is ten (10) years from the date of issuance of any series of Notes, Emera will pay interest on such Notes on a quarterly basis in each year during which such Notes are outstanding thereafter until the Maturity Date (each such semi-annual or quarterly date, as applicable, an “Interest Payment Date”).

From the date of issuance of any series of Notes to, but excluding, the date which is ten (10) years from the date of issuance of such Notes, the interest rate on such Notes will be fixed at the rate specified in the applicable Prospectus Supplement, payable in arrears. Starting on the date which is ten (10) years from the date of issuance of any series of Notes and on every quarterly period thereafter until the Maturity Date (each such date, an “Interest Reset Date”), the interest rate on such Notes will be reset at an interest rate per annum equal to the three month LIBOR plus an additional basis points margin as specified in the applicable Prospectus Supplement. See “Description of the Notes—Interest.”

Deferral Right: So long as no event of default has occurred and is continuing, Emera may elect, at its sole option, at any date other than an Interest Payment Date (a “Deferral Date”) to defer the interest payable on any series of Notes on one or more occasions for up to five consecutive years (a “Deferral Period”). There is no limit on the number of Deferral Periods that may occur. Such deferral will not constitute an event of default or any other breach under the Trust Indenture and the Notes. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. A Deferral Period terminates on any interest payment date where Emera pays all accrued and unpaid interest on such date. No Deferral Period may extend beyond the maturity date of the series of Notes.

Dividend Stopper Undertaking: Unless Emera has paid all accrued and payable interest on any series of Notes, subject to certain exceptions, Emera will not (i) declare any dividends on the Dividend Restricted Shares or pay any interest on any Parity Notes, (ii) redeem, purchase or otherwise retire Dividend Restricted Shares or Parity Notes, or (iii) make any payment to holders of any of the Dividend Restricted Shares or any Parity Notes in respect of dividends not declared or paid on such Dividend Restricted Shares or interest not paid on such Parity Notes, respectively (the “Dividend Stopper Undertaking”).

“Dividend Restricted Shares” means, collectively, the preferred shares of Emera (including the Conversion Preferred Shares) and the common shares of Emera.

“Parity Notes” means any class or series of Emera indebtedness currently outstanding or hereafter created which ranks on a parity with the Notes (prior to any Automatic Conversion (as defined below)) as to distributions upon liquidation, dissolution or winding-up.

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It is in the interest of Emera to ensure that it timely pays interest on the Notes so as to avoid triggering the Dividend Stopper Undertaking. See “Description of the Notes—Dividend Stopper Undertaking” and “Risk Factors.”

Automatic Conversion: Each series of Notes, including accrued and unpaid interest thereon, will be converted automatically (“Automatic Conversion”), without the consent of the holders thereof, into shares of a newly issued series of First Preferred Shares of Emera (the “Conversion Preferred Shares”) upon the occurrence of: (i) the making by Emera of a general assignment for the benefit of its creditors or a proposal (or the filing of a notice of its intention to do so) under the Bankruptcy and Insolvency Act (Canada), (ii) any proceeding instituted by Emera seeking to adjudicate it a bankrupt or insolvent, or, where Emera is insolvent, seeking liquidation, winding up, dissolution, reorganization, arrangement, adjustment, protection, relief or composition of its debts under any law relating to bankruptcy or insolvency in Canada, or seeking the entry of an order for the appointment of a receiver, interim receiver, trustee or other similar official for Emera or any substantial part of its property and assets in circumstances where Emera is adjudged a bankrupt or insolvent, (iii) a receiver, interim receiver, trustee or other similar official is appointed over Emera or for any substantial part of its property and assets by a court of competent jurisdiction in circumstances where Emera is adjudged a bankrupt or insolvent under any law relating to bankruptcy or insolvency in Canada; or (iv) any proceeding is instituted against Emera seeking to adjudicate it a bankrupt or insolvent or, where Emera is insolvent, seeking liquidation, winding up, dissolution, reorganization, arrangement, adjustment, protection, relief or composition of its debts under any law relating to bankruptcy or insolvency in Canada, or seeking the entry of an order for the appointment of a receiver, interim receiver, trustee or other similar official for Emera or any substantial part of its property and assets in circumstances where Emera is adjudged a bankrupt or insolvent under any law relating to bankruptcy or insolvency in Canada, and either such proceeding has not been stayed or dismissed within sixty (60) days of the institution of any such proceeding or the actions sought in such proceedings occur, including the entry of an order for relief against Emera or the appointment of a receiver, interim receiver, trustee, or other similar official for it or for any substantial part of its property and assets (each, an “Automatic Conversion Event”).

The Automatic Conversion shall occur upon an Automatic Conversion Event (the “Conversion Time”). As of the Conversion Time, each series of Notes shall be automatically converted, without the consent of noteholders, into a newly issued series of fully-paid Conversion Preferred Shares. At such time, such series of Notes shall be deemed to be immediately and automatically surrendered and cancelled without need for further action by noteholders, who shall thereupon automatically cease to be holders thereof and all rights of

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any such holder as a debtholder of Emera shall automatically cease. At the Conversion Time, holders of each series of Notes will receive one Conversion Preferred Share for each U.S.$1,000 principal amount of Notes previously held together with the number of Conversion Preferred Shares (including fractional shares, if applicable) calculated by dividing the amount of accrued and unpaid interest, if any, on the Notes by U.S.$1,000.

Upon an Automatic Conversion of the Notes, Emera reserves the right not to issue some or all, as applicable, of the Conversion Preferred Shares to any person whose address is in, or whom Emera or its transfer agent has reason to believe is a resident of, any jurisdiction outside of Canada and the United States of America to the extent that: (i) the issuance or delivery by Emera to such person, upon an Automatic Conversion of Conversion Preferred Shares, would require Emera to take any action to comply with securities or analogous laws of such jurisdiction; or (ii) withholding tax would be applicable in connection with the delivery to such person of Conversion Preferred Shares upon an Automatic Conversion (“Ineligible Persons”). In such circumstances, Emera will hold all Conversion Preferred Shares that would otherwise be delivered to Ineligible Persons, as agent for Ineligible Persons, and will attempt to facilitate the sale of such shares through a registered dealer retained by Emera for the purpose of effecting the sale (to parties other than Emera, its affiliates or other Ineligible Persons) on behalf of such Ineligible Persons of such Conversion Preferred Shares.

As the events that give rise to an Automatic Conversion are bankruptcy and related events, it is in the interest of Emera to ensure that an Automatic Conversion does not occur, although the events that could give rise to an Automatic Conversion may be beyond Emera’s control. See “Description of the Notes—Automatic Conversion,” “Description of Conversion Preferred Shares” and “Risk Factors.”

Conversion Preferred Shares: The Conversion Preferred Shares will carry the right to receive cumulative preferential cash dividends, if, as and when declared by the Board of Directors, subject to the Companies Act (Nova Scotia) at the same rate as would have accrued on the related series of Notes (had such Notes remained outstanding) as described under “Descriptions of the Notes—Interest” (the “Perpetual Preferred Share Rate”), payable on each semi-annual or quarterly dividend payment date, as the case may be, subject to any applicable withholding tax. See “Description of Conversion Preferred Shares.”

Purchase for Cancellation: Subject to the Dividend Stopper Undertaking, each series of Notes may be purchased, in whole or in part, by Emera in the open market or by tender or private contract. Notes purchased by Emera shall be cancelled and shall not be reissued. The purchase price payable by Emera will be paid in cash.

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Redemption Right: Except as may otherwise be provided in a Prospectus Supplement, on or after the date that is ten (10) years from the date of issuance of any series of Notes, Emera may, at its option, on giving not more than 60 nor less than 30 days’ notice to the holders of such Notes, redeem the Notes, in whole at any time or in part from time to time on any Interest Payment Date. The redemption price per U.S.$1,000 principal amount of Notes redeemed on any Interest Payment Date will be 100% of the principal amount thereof, together with accrued and unpaid interest to, but excluding, the date fixed for redemption. Notes that are redeemed shall be cancelled and shall not be reissued. See “Description of the Notes—Redemption Right.”

Redemption on Tax or Rating Event: Except as may otherwise be provided in a Prospectus Supplement, prior to the initial Interest Reset Date and within 90 days of a Tax Event, Emera may, at its option, redeem all (but not less than all) of any series of Notes at a redemption price per U.S.$1,000 principal amount of such Notes equal to 100% of the principal amount thereof, together with accrued and unpaid interest to but excluding the date fixed for redemption. See “Description of the Notes—Redemption on Tax or Rating Event.”

Except as may otherwise be provided in a Prospectus Supplement, prior to the initial Interest Reset Date and within 90 days of a Rating Event, Emera may, at its option, redeem all (but not less than all) of any series of Notes at a redemption price per U.S.$1,000 principal amount of such Notes equal to 102% of the principal amount thereof, together with accrued and unpaid interest to but excluding the date fixed for redemption. See “Description of the Notes—Redemption on Tax or Rating Event.”

Additional Optional and Mandatory Redemption Events: The Prospectus Supplement relating to a particular series of Notes being offered may also include additional optional redemption rights or mandatory redemption events.

Additional Emera Covenants: In addition to the Dividend Stopper Undertaking, Emera will covenant for the benefit of the holders of each series of Notes that it will not create or issue any Emera Preferred Shares which, in the event of insolvency or winding-up of Emera, would rank in right of payment in priority to the Conversion Preferred Shares.

Subordination and Events of Default: The Notes will be direct unsecured subordinated obligations of Emera. The payment of principal and interest on the Notes will be subordinated in right of payment to the prior payment in full of all present and future Senior Indebtedness, and will be effectively subordinated to all indebtedness and obligations of Emera’s subsidiaries.

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“Senior Indebtedness” means obligations (other than non-recourse obligations, Notes issued under the Trust Indenture or any other obligations specifically designated as being subordinate in right of payment to Senior Indebtedness) of, or guaranteed or assumed by, Emera for borrowed money or evidenced by bonds, debentures or notes or obligations of Emera for or in respect of bankers’ acceptances (including the face amount thereof), letters of credit and letters of guarantee (including all reimbursement obligations in respect of each of the forgoing) or other similar instruments, and amendments, renewals, extensions, modifications and refunding of any such indebtedness or obligation. As of March 31, 2016, Emera’s Senior Indebtedness totaled approximately Cdn$751 million.

An event of default in respect of any series of Notes will occur only if Emera defaults on the payment of (i) principal or premium, if any, when due and payable, or (ii) interest when due and payable and such default continues for 30 days (subject to Emera’s right, at its sole option, to defer interest payments, as described under “Description of the Notes—Deferral Right”).

If an event of default has occurred and is continuing with respect to a series of Notes, and the Notes have not already been automatically converted into Conversion Preferred Shares, then Emera shall without notice from the Indenture Trustee be deemed to be in default under the Trust Indenture and the Notes and an Indenture Trustee may, in its discretion and shall upon the request of holders of not less than one-quarter of the principal amount of Notes of that series then outstanding under the Trust Indenture, demand payment of the principal or premium, if any, together with any accrued and unpaid interest up to (but excluding) such date, which shall immediately become due and payable in cash, and may institute legal proceedings for the collection of such aggregate amount where Emera fails to make payment thereof upon such demand.

Payment of Additional Amounts: All payments made by or on account of any obligation of Emera under or with respect to the Notes shall be made free and clear of and without withholding or deduction for, or on account of, any present, or future tax, duty, levy, impost, assessment or other governmental charge (including penalties, interest and other liabilities related thereto) imposed or levied by or on behalf of the Government of Canada or any province or territory thereof or by any authority or agency therein or thereof having power to tax (“Canadian Taxes”), unless Emera is required to withhold or deduct Canadian Taxes by law or by the interpretation or administration thereof by the relevant government authority or agency. If Emera is so required to withhold or deduct any amount for or on account of Canadian Taxes from any payment made under or with respect to the Notes, Emera shall pay as additional interest such additional amounts as may be necessary so that the net amount received by each holder of the Notes after such withholding or deduction shall not be less than the amount such

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holder would have received if such Canadian Taxes had not been withheld or deducted, subject to certain exceptions. See “Description of the Notes—Payment of Additional Amounts.”

Book-Entry Only Form: Each series of Notes will be issued under the book-entry only system operated by The Depository Trust Company or its nominees (the “Clearing Agency”) and must be purchased or transferred through participants (collectively, “Participants”) in the depository service of the Clearing Agency. Participants include securities brokers and dealers, banks and trust companies. Accordingly, physical certificates representing the Notes will not be available except in the limited circumstances described under “Description of the Notes—Book-Entry Only Form”.

Use of Proceeds: The net proceeds of any offering of Notes will be used as set forth in the applicable Prospectus Supplement. Such uses may include financing, directly or indirectly, part of the purchase price payable for the Acquisition (including Acquisition-Related Expenses) and to reduce any amounts outstanding under the Acquisition Credit Facilities to the extent any amounts are drawn on such facilities in connection with the Acquisition. See “Use of Proceeds”.

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Corporate Information

Emera was incorporated in the Province of Nova Scotia in 1998. Emera’s principal executive office is located at 5151 Terminal Road, P.O. Box 910, Halifax, Nova Scotia B3J 1A1 and Emera’s telephone number is (902) 450-0507. Emera’s website address is www.emera.com. Material contained on Emera’s website is not part of and is not incorporated by reference in this Prospectus.

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Summary Historical and Pro Forma Financial Data

Emera Summary Historical Financial Data

The following table shows summary historical financial of Emera for the periods and as of the dates indicated. The summary historical financial data presented as at December 31, 2015 and 2014 and for the year ended December 31, 2015 are derived from the audited financial statements of Emera, which are incorporated by reference in this Prospectus. The selected historical financial data presented as at December 31, 2013 and for the year ended December 31, 2013 are derived from the audited financial statements of Emera, which are not incorporated by reference in this Prospectus. The summary historical financial data presented as of March 31, 2016 and 2015 and for the three months ended March 31, 2016 and 2015 are derived from the unaudited financial statements of Emera, which are incorporated by reference in this Prospectus.

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The following summary historical and unaudited financial data should be read in conjunction with “Capitalization” and “Management’s Discussion and Analysis” contained herein and Emera’s financial statements and related notes incorporated by reference in this Prospectus.

	Emera historical
	Three months ended March 31					Year ended December 31
	2016			2015		2015		2014		2013
	millions of Canadian dollars
Statement of Operations Data:
Total operating revenues		877.0			888.5		2,789.3		2,938.6		2,230.2
Total operating expenses		607.0			656.4		2,281.6		2,271.3		1,823.1
Net income		54.8			174.1		452.4		452.8		255.3
Non-controlling interest in subsidiaries		3.5			6.3		24.9		19.9		18.5
Net income of Emera Incorporated		51.3			167.8		427.5		432.9		236.8
Preferred stock dividends		7.0			7.7		30.3		26.2		19.3
Net income attributable to common shareholders	$	44.3		$	160.1	$	397.2	$	406.7	$	217.5
Other comprehensive income (loss), net of tax(1):
Foreign currency translation adjustment		(161.5	)		189.4		434.6		165.2		108.6
Other comprehensive income (loss)		(137.5	)		183.4		512.1		90.0		354.0
Comprehensive income (loss)		(82.7	)		357.5		964.5		542.8		609.3
Comprehensive income (loss) attributable to non-controlling interest		(3.3	)		19.5		52.8		31.6		26.8
Comprehensive income of Emera Incorporated	$	(79.4	)	$	338.0	$	911.7	$	511.2	$	582.5
Adjusted EBITDA(2)	$	319.4		$	384.2	$	1,031.2	$	946.5	$	829.5
Balance Sheet Data (at period end):
Assets:
Current assets:
Cash and cash equivalents	$	999.5		$	305.3	$	1,073.4	$	221.1	$	100.8
Total current assets		2,289.4			1,646.5		2,595.6		1,410.8		1,161.3
Property, plant and equipment, net of accumulated depreciation		6,014.9			5,826.0		6,188.0		5,610.2		5,327.7
Total assets(3)	$	11,448.6			10,191.7	$	11,950.0	$	9,853.4	$	8,876.8
Short-term debt	$	10.2		$	5.7	$	15.9	$	257.6	$	438.0
Current portion of long-term debt		272.6			92.9		274.0		94.5		328.3
Long-term debt(3)		3,714.2			3,800.3		3,734.6		3,660.3		3,363.7
Total Emera Incorporated equity		4,091.7			3,691.9		4,200.1		3,398.8		2,608.2
Non-controlling interest in subsidiaries		105.2			321.8		134.0		306.6		289.0
Total equity		4,196.9			4,013.7		4,334.1		3,705.4		2,897.2
Total liabilities and equity(3)	$	11,448.6		$	10,191.7	$	11,950.0	$	9,853.4	$	8,876.8

(1) Certain of these items are net of tax expense or recovery, please refer to Emera’s audited consolidated financial statements as at and for the years ended December 31, 2015 and December 31, 2014, which are incorporated by reference herein and Emera’s unaudited condensed consolidated interim financial statements as at and for the three months ended March 31, 2016 for more details.

(2) Adjusted EBITDA is a non-U.S. GAAP measure. See “Presentation of Financial Information.”

(3) Year ended December 31, 2015 amounts have been adjusted to conform to the accounting presentation applied to amounts for the three months ended March 31, 2016.

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TECO Energy Summary Historical Financial Data

The following table shows the summary historical financial data of TECO Energy for the periods and as of the dates indicated. The summary historical financial data presented as of December 31, 2015, 2014 and 2013 and for the year ended December 31, 2015, 2014 and 2013 are derived from the audited financial statements of TECO Energy, which are incorporated by reference in this Prospectus. The summary historical financial data presented as of March 31, 2016 and 2015 and for the three months ended March 31, 2016 and 2015 are derived from the unaudited financial statements of TECO Energy, which are incorporated by reference in this Prospectus.

The following summary historical financial data should be read in conjunction with “Capitalization” contained herein and TECO Energy’s financial statements and related notes incorporated by reference in this Prospectus.

	TECO Energy historical
	Three months ended March 31					Year ended December 31
	2016		2015			2015			2014			2013
	millions of U.S. dollars
Statement of Operations Data:
Total revenues(1)		659.5		693.0			2,743.5			2,566.4			2,355.1
Total expenses		511.4		546.8			2,181.4			2,061.0			1,900.5
Net income from continuing operations(1)		73.7		63.8			241.2			206.4			188.7
Net income from discontinued operations(1)(2)		0.1		(5.8	)		(67.7	)		(76.0	)		9.0
Net income		73.8		58.0			173.5			130.4			197.7
EBITDA(3)		245.1		237.1			931.9			831.7			754.5
Balance Sheet Data (at period end):
Total current assets		547.2		728.7			570.3			755.6			857.7
Total property, plant and equipment, net		7,553.0		7,164.7			7,481.8			7,088.2			6,170.1
Total assets		8,981.1		8,777.5			8,933.5			8,726.2			7,448.0
Long-term debt, including current portion		3,573.0		3,627.7			3,822.5			3,628.5			2,921.1
Total capital		2,582.3		2,587.3			2,559.0			2,574.7			2,333.7
Total liabilities and capital		8,981.1		8,777.5			8,933.5			8,726.2			7,448.0

(1) Years ended December 31, 2015, December 31, 2014 and December 31, 2013 amounts shown include reclassifications to reflect discontinued operations discussed in Note 19 to the TECO Energy Consolidated Financial Statements for the fiscal year ended December 31, 2015.

(2) Three months ended March 31, 2015 amounts have been adjusted to reflect the results from operations to discontinued operations for TECO Coal and certain charges and gains at TECO Energy’s Other reportable segment that directly relate to TECO Coal and TECO Guatemala. See Note 15 to TECO Energy’s unaudited financial statements for the three months ended March 31, 2016, which are incorporated by reference in this Prospectus.

(3) EBITDA is a non-U.S. GAAP measure. See “Presentation of Financial Information.”

Pro Forma Financial Data

The summary unaudited pro forma financial data as of March 31, 2016 and for the fiscal year ended December 31, 2015 and the three months ended March 31, 2016 are derived from Emera’s unaudited pro forma consolidated financial statements. The unaudited pro forma consolidated statements of operations for the year

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ended December 31, 2015 and for the three months ended March 31, 2016 give effect to the Acquisition and related transactions described below as if they had occurred on January 1, 2015. The summary unaudited pro forma consolidated financial information is presented to illustrate the estimated effects of (i) the Acquisition Capital Markets Transactions, (ii) the issuance of Common Shares upon conversion of the Convertible Debentures on the Final Instalment Date (assuming payment in full of the Final Instalment of the Convertible Debentures) and (iii) the consummation of the Acquisition. The unaudited pro forma consolidated balance sheet information gives effect to the Acquisition Capital Markets Transactions, the issuance of the Common Shares (as described above) and the Acquisition as if they closed on March 31, 2016. The unaudited pro forma consolidated statements of earnings information for the year ended December 31, 2015 and the three months ended March 31, 2016 gives effect to the Acquisition and the Acquisition Capital Markets Transactions as if they had closed on January 1, 2015.

The following summary unaudited pro forma financial data should be read in conjunction with “Caution Regarding Unaudited Consolidated Pro Forma Consolidated Financial Statements,” “Capitalization,” “Management’s Discussion and Analysis,” and “Unaudited Pro Forma Consolidated Financial Statements” contained herein and Emera’s financial statements and related notes incorporated by reference in this Prospectus. Among other things, the unaudited pro forma financial statements under “Unaudited Pro Forma Consolidated Financial Statements” include more detailed information regarding the basis of presentation for the information in the following table.

	Emera Pro Forma
	Three months ended March 31		Year ended December 31
	2016		2015
	millions of Canadian dollars
Statement of Operations Data:
Total operating revenues		1,784		6,298
Total operating expenses		1,310		5,036
Net Income from continuing operations		243		538
Net income of Emera Incorporated		240		426
Preferred stock dividends		7		30
Net income attributable to common shareholders		233		396
Adjusted EBITDA(1)	$	657	$	2,258
Balance Sheet Data (at period end):
Current assets:
Cash and cash equivalents	$	323
Total current assets		2,263
Property, plant and equipment, net of accumulated depreciation		15,812
Total assets	$	27,558
Short-term debt	$	676
Current portion of long-term debt		381
Long-term debt		14,756
Total Emera Incorporated equity		6,068
Non-controlling interest in subsidiaries		105
Total equity		6,173
Total liabilities and equity	$	27,558

(1) Adjusted EBITDA is a non-U.S. GAAP measure. See “Presentation of Financial Information.”

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Pro Forma Non-U.S. GAAP financial measures

EBITDA and Adjusted EBITDA

The following table presents a reconciliation of EBITDA and Adjusted EBITDA to the most directly comparable U.S. GAAP financial measure, on a historical basis and a pro forma basis, for Emera and EBITDA to the most directly comparable U.S. GAAP financial measure, on a historical basis for TECO Energy, for each of the periods indicated. See “Presentation of Financial Information.” The Emera pro forma information for the three months ended March 31, 2016 and the year ended December 31, 2015 set forth below has been prepared using the U.S. dollar to Canadian dollar weighted average rates of 1.3748 (for the period January 1, 2016 to March 31, 2016) and 1.2788 (for the period January 1, 2015 to December 31, 2015), respectively.

	Emera Historical					TECO Energy Historical				Emera Pro Forma
	Three months ended March 31			Year ended December 31		Three months ended March 31		Year ended December 31		Three months ended March 31		Year ended December 31
	2016			2015		2016		2015		2016		2015
	millions of Canadian dollars					millions of U.S. dollars				millions of Canadian dollars
Net Income	$	54.8		$	452.4	$	73.7	$	241.2	$	243.3	$	537.5
Add:
Interest expense, net		75.2			212.6		45.9		186.4		192.1		684.1
Income tax expense (recovery)		26.8			92.4		35.7		155.3		74.7		197.2
Depreciation and amortization		87.5			339.9		89.8		349.0		211.0		786.2
EBITDA	$	244.3		$	1,097.3	$	245.1	$	931.9	$	721.0	$	2,205.1
Mark-to-market gain (loss), excluding income tax and interest		(75.1	)		66.1						64.4		(52.8	)
Adjusted EBITDA	$	319.4		$	1,031.2					$	656.6	$	2,257.9

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GLOSSARY

In this Prospectus, unless the context otherwise requires:

“Acquisition” means the proposed acquisition by Emera of TECO Energy pursuant to the terms of the Acquisition Agreement.

“Acquisition Agreement” means the agreement and plan of merger dated September 4, 2015 among Emera, Merger Sub and TECO Energy.

“Acquisition Capital Markets Transactions” has the meaning ascribed thereto under the heading “Summary—Financing the Acquisition.”

“Acquisition Credit Agreements” has the meaning ascribed thereto under the heading “Description of Other Indebtedness—Acquisition Credit Facilities.”

“Acquisition Credit Facilities” has the meaning ascribed thereto under the heading “Description of Other Indebtedness—Acquisition Credit Facilities.”

“Acquisition-Related Expenses” means the estimated non-recurring costs, including related income tax effects and any governmental and other imposed costs that may be incurred to consummate the Acquisition. Such costs, which will be fully expensed when incurred in accordance with U.S. GAAP, include but are not limited to fees associated with financial advisory, consulting, accounting, tax, legal and other professional services, bridge facility commitment fees, costs associated with change of control and integration, out-of-pocket costs and other costs of a non-recurring nature.

“Additional Amounts” has the meaning ascribed thereto under the heading “Description of the Notes—Payment of Additional Amounts.”

“Adjusted EBITDA” has the meaning ascribed thereto under the heading “Presentation of Financial Information—Emera EBITDA and Adjusted EBITDA.”

“Adjusted Net Income” means net income attributable to common shareholders, as defined by U.S. GAAP excluding the effect of after-tax mark-to-market adjustments related to certain derivative instruments, the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp and NWP until NWP’s sale on January 29, 2015, the mark-to-market adjustments related to an interest rate swap in EBPC, the mark-to-market adjustments related to the effect of USD-denominated currency and forward contracts put in place to economically hedge the then anticipated proceeds from the Convertible Debenture Offering for the Acquisition and the mark-to-market adjustments included in Emera Energy’s margin, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered and the amortization of transportation capacity recognized as a result of certain marketing and trading transactions. See “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures.”

“AFUDC” means allowance for funds used during construction and represents the cost of financing regulated construction projects and is capitalized to the cost of property, plant and equipment, where permitted by the regulator.

“Annual Information Form” means the annual information form of Emera for the year ended December 31, 2015 dated March 30, 2016.

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“Approval Conditions” means that (i) the Company has received all regulatory and governmental approvals required to finalize the Acquisition and (ii) the Company and TECO Energy have fulfilled or waived all other outstanding conditions precedent to closing the Acquisition, other than those which by their nature cannot be satisfied until the closing of the Acquisition, in each case as set out in the Acquisition Agreement.

“APUC” means Algonquin Power & Utilities Corp.

“ARO” means asset retirement obligation.

“ASU” means Accounting Standard Update.

“Atlantic Provinces” means the region of Canada consisting of the Provinces of New Brunswick, Newfoundland and Labrador, Nova Scotia and Prince Edward Island.

“Automatic Conversion” means the automatic conversion of the Notes for newly issued Conversion Preferred Shares upon the occurrence of an Automatic Conversion Event.

“Automatic Conversion Event” means an event giving rise to the Automatic Conversion, being the occurrence of any one of the following: (i) the making by Emera of a general assignment for the benefit of its creditors or a proposal (or the filing of a notice of its intention to do so) under the Bankruptcy and Insolvency Act (Canada); (ii) any proceeding instituted by Emera seeking to adjudicate it a bankrupt or insolvent or, where Emera is insolvent, seeking liquidation, winding up, dissolution, reorganization, arrangement, adjustment, protection, relief or composition of its debts under any law relating to bankruptcy or insolvency in Canada, or seeking the entry of an order for the appointment of a receiver, interim receiver, trustee or other similar official for Emera or for any substantial part of its property and assets in circumstances where Emera is adjudged a bankrupt or insolvent; (iii) a receiver, interim receiver, trustee or other similar official is appointed over Emera or for any substantial part of its property and assets by a court of competent jurisdiction in circumstances where Emera is adjudged a bankrupt or insolvent under any law relating to bankruptcy or insolvency in Canada; or (iv) any proceeding is instituted against Emera seeking to adjudicate it a bankrupt or insolvent, or where Emera is insolvent, seeking liquidation, winding up, dissolution, reorganization, arrangement, adjustment, protection, relief or composition of its debts under any law relating to bankruptcy or insolvency in Canada, or seeking the entry of an order for the appointment of a receiver, interim receiver, trustee or other similar official for Emera or any substantial part of its property and assets in circumstances where Emera is adjudged a bankrupt or insolvent under any law relating to bankruptcy or insolvency in Canada, and either such proceeding has not been stayed or dismissed within sixty (60) days of the institution of any such proceeding or the actions sought in such proceedings occur (including the entry of an order for relief against Emera or the appointment of a receiver, interim receiver, trustee, or other similar official for it or for any substantial part of its property and assets).

“BACT” means Best Available Control Technology.

“Bangor Hydro” means Bangor Hydro Electric Company, a transmission and distribution electric utility company incorporated under the laws of the State of Maine and a wholly owned, indirect subsidiary of Emera which merged on January 1, 2014 with MPS to form Emera Maine.

“Bangor Hydro District” means the franchise electric service territory associated with the former Bangor Hydro Electric Company in eastern and Down East Maine.

“Bayside Power” means Bayside Power Limited Partnership.

“Bayside Power Station” means the coal-fired Gannon Power Station to natural gas, which was renamed as the H. L. Culbreath Bayside Power Station.

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“BBD” means Barbadian dollar.

“Bear Swamp” means Bear Swamp Power Company, LLC, a 600 MW pumped storage hydroelectric company incorporated under the laws of the State of Delaware in which Emera indirectly holds a 50% interest.

“BLPC” means The Barbados Light & Power Company Limited.

“Board of Directors” means the board of directors of Emera.

“Brookfield Renewable Partners” means Brookfield Renewable Partners L.P.

“Brooklyn Energy” means Brooklyn Power Corporation.

“Brunswick Pipeline” means the pipeline delivering re-gasified natural gas from the Canaport^™ LNG gas terminal near Saint John, New Brunswick to markets in the Northeastern United States, which is owned directly by EBPC.

“Bull Hill” means Blue Sky East, LLC, a company incorporated under the laws of the State of Delaware which owns a 34.5 MW wind farm located south of Bangor, Maine, and in which Emera held an indirect interest of 49% through its joint venture with First Wind in NWP until January 29, 2015, when Emera sold its interest in NWP.

“CAD” means Canadian dollars.

“CAIR” means the U.S. Environmental Protection Agency’s Clean Air Interstate Rule, which was replaced by the CSAPR, as of January 1, 2015.

“Cambrian” means Cambrian Coal Corp.

“Canadian Dollar Subordinated Notes” means the Canadian dollar-denominated unsecured, subordinated notes that may be issued by Emera on a basis that is exempt from the prospectus requirements of applicable Canadian securities laws.

“Canaport LNG” means an LNG receiving and regasification terminal in Saint John, New Brunswick. Canaport LNG is a partnership between Repsol S.A. and Irving Oil Limited with Canaport LNG as the developer, owner and operator of the terminal.

“Cash Offer” means EBH2’s offer to purchase minority shareholders’ stakes in ECI for $23.26 ($33.30 Barbadian dollars) in cash per common share.

“CCRs” means coal combustion residuals.

“CFO” means Chief Financial Officer.

“Clean Air Act” means the Clean Air Act, a US federal law related to air pollution, codified at 42 U.S.C. 7401 et seq., as amended.

“Clean Power Plan” means the guidelines for existing fossil fuel-fired electric generating units proposed and established by the EPA under the authority of Clean Air Act section 111(d).

“Clean Water Act” means the Clean Water Act, a U.S. federal law related to water pollution, codified at 33 U.S.C. 1251 et seq., as amended.

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“Code” means the U.S. Internal Revenue Code of 1986, as amended.

“COMFIT” means the Community Feed-In Tariff, which NSPI is subject to.

“Common Shares” means the common shares in the capital of Emera.

“Companies Act Relief” has the meaning ascribed thereto under the heading “Business—General Development of the Business—Emera Maine—U.S. GAAP—Exemptive Relief and Companies Act Relief.”

“Conversion Preferred Shares” means the applicable series of first preferred shares of Emera, as authorized by the Board of Directors, to be issued by Emera upon an Automatic Conversion.

“Conversion Time” means the time at which an Automatic Conversion occurs, namely upon an Automatic Conversion Event.

“Convertible Debenture Make-Whole Payment” means an amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Convertible Debenture Offering had the Convertible Debentures remained outstanding and continued to accrue interest until and including such date.

“Convertible Debenture Offering” has the meaning ascribed thereto under the heading “Description of Other Indebtedness—Emera—Debentures Represented by Instalment Receipts.”

“Convertible Debentures” means the 4.0% convertible unsecured subordinated debentures of Emera that were issued on September 28 and October 2, 2015 in order to finance a portion of the Acquisition.

“CRA” means Canada Revenue Agency.

“CRMB” has the meaning ascribed thereto under the heading “Business—TECO Energy—Capital Expenditures.”

“CSA” means the various securities commissions or other securities regulatory authorities in the provinces of Canada.

“CSAPR” means the U.S. Environmental Protection Agency’s Cross-State Air Pollution Rule, a set of rules aimed at reducing power plant emissions that contribute to ozone and fine particle pollution.

“CT” means combustion turbine.

“cybersecurity threats” has the meaning ascribed thereto under the heading “Management’s Discussion and Analysis—Enterprise Risk and Risk Management—Cybersecurity Risk.”

“DC&P” means disclosure controls and procedures, as such term is defined in “Management’s Discussion and Analysis—Disclosure and Internal Controls.”

“Deferral Date” has the meaning ascribed to thereto under the heading “Description of the Notes—Deferral Right.”

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“Deferral Event” means the election by Emera, at its sole option, to defer the interest payable on the Notes.

“Deferral Period” has the meaning ascribed thereto under the heading “Description of the Notes—Deferral Right.”

“Determination of Need” means a formal process required under Florida law that is conducted by the FPSC. The FPSC reviews the need for the power generated by the proposed facility in relation to the needs of Florida.

“Dividend Restricted Shares” has the meaning ascribed thereto under the heading “Description of the Notes—Dividend Stopper Undertaking.”

“Dividend Stopper Undertaking” has the meaning ascribed thereto under the heading “Description of the Notes—Dividend Stopper Undertaking.”

“Domlec” means Dominica Electricity Services Limited.

“DR” means depositary receipt.

“DR Offer” means EBH2’s offer to purchase minority shareholders’ stakes in ECI for 2.1 DRs per common share.

“DSM” means demand side management.

“DSM Program Costs” means the requirement of NSPI to purchase electricity efficiency and conservation activities pursuant to legislation of the Government of Nova Scotia.

“EBITDA” means earnings before interest, income taxes, depreciation and amortization.

“EBH2” means Emera (Barbados) Holdings No. 2 Inc., an indirect wholly owned subsidiary of Emera.

“EBPC” means Emera Brunswick Pipeline Company Ltd.

“ECHL” means Emera Caribbean Holdings Limited.

“ECI” means Emera (Caribbean) Incorporated, effective November 24, 2014, which was formerly Light & Power Holdings Ltd.

“ECRC” means an environmental cost recovery clause, which allows for the recovery of costs associated with certain environmental investment and expenses.

“EE New England Gas Generation” means Emera Energy Generation II LLC, a company incorporated under the laws of the State of Delaware that holds the New England Gas Generation Facilities and a wholly owned, direct subsidiary of Emera.

“EES” means Emera Energy Services.

“Electricity Plan Act” means the Electricity Plan Implementation (2015) Act (Nova Scotia).

“ELGs” means the electric effluent limit guidelines of the EPA.

“Emera” means Emera Incorporated.

“Emera Caribbean” means BLPC and Domlec (and their parent company, ECI), GBPC, Emera Utility Services (Bahamas) and Lucelec.

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“Emera Common Shares” means the common shares of Emera.

“Emera Corporate and Other” means Emera’s consolidated investment in Emera Utility Services, Emera Reinsurance Limited and Emera’s non-consolidated investments in ENL, NSPML, LIL, APUC and OpenHydro. Corporate and Other also includes other investments and interest revenue on intercompany financings and costs allocated to corporate activities not directly associated with operations, including without limitation, the acquisition costs for the Acquisition and the mark-to-market adjustments related to the effect of USD-denominated currency and forward contracts to economically hedge the anticipated proceeds from the Convertible Debenture Offering for the Acquisition.

“Emera Energy” means Emera Energy Incorporated.

“Emera Energy Generation” means, collectively, EE New England Gas Generation, Bayside Power and Brooklyn Energy.

“Emera Energy Services” means Emera Energy Services, Inc., a natural gas and electricity marketing and trading company incorporated under the laws of the State of Delaware and a wholly owned, indirect subsidiary of Emera Energy.

“Emera Maine” means the company resulting from the merger of Bangor Hydro Electric Company and Maine Public Service Company under the laws of the state of Maine on January 1, 2014, and a wholly-owned indirect subsidiary of Emera.

“Emera Preferred Shares” means the preferred shares of Emera (including the Conversion Preferred Shares).

“Emera US Finance” means Emera US Finance LP

“Emera Utility Services” means Emera Utility Services Inc.

“ENL” means Emera Newfoundland and Labrador Holdings, Incorporated.

“EPA” means the United States Environmental Protection Agency.

“Equity Credit Methodology” means the methodology or criteria employed by Moody’s or S&P for purposes of assigning equity credit to securities such as the Notes that was effective on the date of the original issuance of a series of Notes.

“EUS Bahamas” means Emera Utility Services (Bahamas) Limited.

“EUSHI” means Emera US Holdings Inc., a wholly-owned (directly and indirectly) subsidiary of the Company.

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

“Exemptive Relief” has the meaning ascribed thereto under the heading “Business—General Development of the Business—Emera Maine—U.S. GAAP—Exemptive Relief and Companies Act Relief.”

“Extraordinary Resolution” means (i) the written consent of holders of not less than a majority of the aggregate principal amount of the Notes or an applicable series of Notes; or (ii) an extraordinary resolution proposed at a meeting of holders of the Notes where holders of not less than a majority of the aggregate principal amount of the Notes, or of each applicable series of Notes if a serial meeting, are represented in person or by proxy (or a lesser amount of holders if such meeting has been dissolved and reconvened due to failure to achieve quorum in the manner specified in the Trust Indenture) and passed by the favourable votes of holders of the Notes representing not less than 66 ²⁄₃% of the aggregate principal amount of the Notes represented at the meeting.

“FAM” means the fuel adjustment mechanism established by the UARB.

“FASB” means the Financial Accounting Standards Board.

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“FCA” means, with respect to Emera Energy Generation, forward capacity auction.

“FDEP” means Florida Department of Environmental Protection.

“FERC” means the United States Federal Energy Regulatory Commission.

“FGD” means flue gas desulfurization.

“Final Instalment” means the remaining Cdn$667 per Cdn$1,000 principal amount of Convertible Debentures that is payable on the Final Instalment Date.

“Final Instalment Date” has the meaning ascribed thereto under the heading “Management’s Discussion and Analysis—Developments—Emera—Convertible Debentures Represented By Instalment Receipts.”

“First Preferred Shares” means the first preferred shares in the capital of Emera.

“First Wind” means First Wind Holdings LLC, a company incorporated under the laws of the State of Delaware.

“FLG” has the meaning ascribed thereto under the heading “Business—General Development of the Business—Maritime Link Project and Strategic Partnership with Nalcor on Muskrat Falls Projects.”

“FLG Completion Guarantee” means a completion guarantee granted by Emera in favour of the Government of Canada under which Emera has guaranteed the performance of the obligations of NSPML to cause the completion of the Maritime Link Project in the circumstances and within the timelines provided for in the FLG Completion Guarantee. The FLG Payment Obligation Agreement (as defined below) and FLG Completion Guarantee collectively satisfy the requirement in the FLG term sheet to deliver the condition precedent in the FLG term sheet to deliver to the Government of Canada a guarantee of certain payment and performance obligations, which condition precedent was satisfied collectively by the FLG Completion Guarantee (as defined above) and the FLG Payment Obligation Agreement (as defined below).

“FLG Payment Obligation Agreement” means a payment obligation agreement between Emera, NSPML and the Government of Canada, which together with the FLG Completion Guarantee (as defined above) collectively satisfy the requirement in the FLG term sheet to deliver a guarantee agreement from Emera.

“FPSC” means the Florida Public Service Commission.

“Fuel Costs” means certain fuel-related costs as described in “Management’s Discussion and Analysis—NSPI—Overview.”

“Fuel Electric Revenues” means NSPI’s electric revenues related to the recovery of Fuel Costs.

“Gas Industry Standards Board” means the Gas Industry Standards Board, the precursor to the NAESB.

“GBPA” means The Grand Bahama Port Authority.

“GBPC” means The Grand Bahama Power Company Limited.

“GCBF” means gas cost billing factor.

“GDP” means gross domestic product.

“GHG” means greenhouse gas.

“GRA” means general rate application.

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“Guarantors” has the meaning ascribed thereto under the heading “Description of Other Indebtedness—Proposed Emera US Finance Senior Guaranteed Notes.”

“GWh” means the amount of electricity measured in gigawatt hours.

“HAPS” has the meaning ascribed thereto under the heading “Business—TECO Energy.”

“HFT” means held-for-trading.

“Hydro-Québec” means Hydro-Québec, the public utility.

“ICDU” means ICD Utilities Limited.

“ICFR” means internal controls over financial reporting.

“ICSID” means the International Centre for the Settlement of Investment Disputes.

“IFRS” means International Financial Reporting Standards.

“IGCC” means integrated gasification combined-cycle.

“Indenture Trustee” means CST Trust Company and American Stock Transfer & Trust Company, LLC, or such other successor trustee or trustees as may be appointed from time to time pursuant to the Trust Indenture.

“Ineligible Person” means any person whose address is in, or whom Emera or its transfer agent has reason to believe is a resident of, any jurisdiction outside of Canada and the U.S. to the extent that: (i) the issuance or delivery by Emera to such person, upon an Automatic Conversion of Conversion Preferred Shares, would require Emera to take any action to comply with securities or analogous laws of such jurisdiction; or (ii) withholding tax would be applicable in connection with the delivery to such person of Conversion Preferred Shares upon an Automatic Conversion.

“instalment receipts” means the instalment receipts representing beneficial ownership of the Convertible Debentures.

“IOU ” means Investor Owned Utility.

“IPP” means independent power producer.

“IRCD” means the Independent Regulatory Commission, Dominica.

“ISO-NE” means the independent, non-profit regional transmission organization that oversees the operation of New England’s bulk electric power system and transmission lines, generated and transmitted by its member utilities.

“km” means kilometre.

“Labrador-Island Transmission Link Project” means an electricity transmission project in Newfoundland and Labrador being developed by Nalcor, which will enable the transmission of the Muskrat Falls energy between Labrador and the island of Newfoundland.

“Labrador Transmission Assets” means an electricity transmission project in Labrador between Muskrat Falls and Churchill Falls.

“LIBOR” means, for any interest period in respect of a series of Notes, the rate for U.S. dollar borrowings appearing on page LIBOR01 of the Reuters Service (or on any successor or substitute page of such Service, or any successor to or substitute for such Service providing rate quotations comparable to those currently provided

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on such page of such Service, as determined by the Company from time to time for purposes of providing quotations of interest rates applicable to U.S. dollar deposits in the London interbank market) at approximately 11:00 a.m., London, time, two business days prior to the commencement of such interest period, as the rate for U.S. dollar deposits with a maturity comparable to such interest period. In the event that such rate is not available at such time for any reason, the “LIBOR” for such interest period shall be the rate at which U.S. dollar deposits of U.S.$5,000,000 and for a maturity comparable to such interest period are offered by the principal London offer of an agent selected by Emera in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such interest period.

“LIL” means Labrador Island Link Limited Partnership.

“LNG” means liquefied natural gas.

“LPH” means Light & Power Holdings Ltd., the former name of ECI.

“Lucelec” means St. Lucia Electricity Services Limited.

“M&NP” means the Maritimes & Northeast Pipeline Limited Partnership and Maritimes and Northeast Pipeline LLC.

“MACT” has the meaning ascribed thereto under the heading “Business—TECO Energy.”

“Maine & Maritimes Corporation” means Maine & Maritimes Corporation, a company incorporated under the laws of the State of Maine, the parent company of MPS, and a wholly owned, indirect subsidiary of Emera; Maine & Maritimes Corporation was dissolved when MPS and Bangor Hydro merged on January 1, 2014, forming Emera Maine..

“MAP 21” means the Moving Ahead for Progress in the 21^st Century Act.

“Maritime Link Act” means the Maritime Link Act (Nova Scotia).

“Maritime Link Joint Development Agreement” means the agreement dated July 31, 2014 between Nalcor and Emera relating to the development of the Maritime Link Project.

“Maritime Link Project” means the transmission project including two 170 km sub-sea cables between the island of Newfoundland and Nova Scotia, being developed by NSPML

“Maritime Provinces” means the region of Canada consisting of the Provinces of Nova Scotia, New Brunswick, and Prince Edward Island.

“MATS” means the U.S. Environmental Protection Agency’s Mercury Air Toxics Standards, a rule issued pursuant to section 112 of the Clean Air Act aimed at reducing mercury, acid gases and other toxic pollution from power plants.

“MD&A” means Emera’s Management’s Discussion and Analysis for the three months ended March 31, 2016 and the fiscal year ended December 31, 2015, incorporated herein by reference copies of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

“Merger Sub” means Emera US Inc., a direct wholly-owned subsidiary of EUSHI.

“MLFT” means Maritime Link Financing Trust, a special purpose funding vehicle formed by Emera.

“MMBTU” means one million British thermal units.

“Moody’s” means Moody’s Investor Service, Inc.

“MOU” has the meaning ascribed thereto under the heading “Risk Factors—Risk Factors Relating to the Acquisition.”

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“MPS” means Maine Public Service Company, which merged with Bangor Hydro Electric Company to become Emera Maine.

“MPS District” means the franchise electric service territory associated with the former Maine Public Service Company in northern Maine.

“MPUC” means the Maine Public Utilities Commission.

“MREI” means the Maine Renewable Energy Interconnect project proposed by Central Maine Power Company and Emera Maine.

“MTM” means mark-to-market.

“MTN” means medium-term notes.

“Muskrat Falls Generating Station” means a hydroelectric generating facility at Muskrat Falls being developed by Nalcor on the Lower Churchill River in Labrador.

“Muskrat Falls Hydroelectric Project” means, collectively, the Muskrat Falls Generating Station, the Labrador Transmission Assets, and the Labrador-Island Transmission Link Project.

“MW” means megawatts.

“MWh” means megawatt-hours.

“NAESB” means the North American Energy Standards Board.

“Nalcor” means Nalcor Energy, a Newfoundland and Labrador provincial Crown corporation.

“NB Power” means New Brunswick Power Corporation.

“NEB” means the Canadian National Energy Board.

“New England Gas Generation Facilities” means a three-facility, 1,090 MW combined-cycle gas-fired electricity -generating investment in the Northeastern United States, comprising Bridgeport Energy (560 MW) in Bridgeport, -Connecticut; Tiverton Power (265 MW) in Tiverton, Rhode Island; and Rumford Power (265 MW) in Rumford, Maine.

“NLPUB” means the Newfoundland and Labrador Board of Commissioners of Public Utilities.

“NMGC” means New Mexico Gas Company, Inc.

“NMGI” means New Mexico Gas Intermediate, Inc.

“NMPRC” means the New Mexico Public Regulation Commission.

“No.” means number.

“Non-Fuel Electric Revenues” means NSPI’s revenues related to the recovery of non-fuel costs.

“Non-Resident Holder” means a holder of Notes who acquires Notes and who, for purposes of the Tax Act and at all relevant times, is not, and is not deemed to be, resident in Canada, deals at arm’s length with and is not affiliated with Emera or any of its affiliates and holds Notes and any Conversion Preferred Shares as capital property.

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“NPNS” means normal purchases and normal sales.

“NSPC” means Nova Scotia Power Corporation.

“NSPFC” means Nova Scotia Power Finance Corporation.

“NSPI” means Nova Scotia Power Incorporated.

“NSPML” means NSP Maritime Link Incorporated.

“NWP” means Northeast Wind Partners II, LLC.

“NYSE” means the New York Stock Exchange.

“OATT” means open access transmission tariff.

“OM&G” means operating, maintenance and general, with respect to costs.

“Participants” means the participants in the depository service of the Clearing Agency.

“PBO” means the net actuarial gain or loss, which exceeds 10% of the greater of the projected benefit obligation/accumulated post-retirement benefit obligation, as defined in “Management’s Discussion and Analysis—Pension and Other Post-Retirement Employee Benefits.”

“Perpetual Preferred Share Rate” has the meaning ascribed thereto under the heading “Description of Conversion Preferred Shares—Dividends.”

“petcoke” means petroleum coke.

“PGA” means purchased gas adjustment.

“PGAC” means purchased gas adjustment clause.

“PGS” means Peoples Gas System, the gas division of Tampa Electric Company.

“PHMSA” has the meaning ascribed thereto under the heading “Risk Factors—Risk Factors Relating to the Acquisition.”

“Polk Power Station” means Tampa Electric’s integrated coal gasification combined-cycle power plant, located on State Road 37 in Polk County, Florida.

“PPA” means power purchase agreement.

“PPSA” means the Florida’s Power Plant Siting Act.

“PSC” means the Florida Public Service Commission.

“Prospectus” means this prospectus.

“Prospectus Supplement” has the meaning ascribed thereto on the cover page of this Prospectus.

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“PRP” means potentially responsible party.

“Public Utilities Act” means the Public Utilities Act (Nova Scotia).

A “Rating Event” means the amount of equity credit assigned to a series of Notes by Moody’s or S&P has been reduced due to an amendment to, clarification or change in, the Equity Credit Methodology.

“RECL” means Repsol Energy Canada Ltd.

“regulated net income” means net income from regulated subsidiaries.

“Revolving Facility” has the meaning ascribed thereto under the heading “Description of Other Indebtedness—Revolving Facility.”

“RFP” means request for proposal.

“ROE” means return on equity.

“S&P” means Standard & Poor’s Ratings Services.

“Sable Wind Project” means a 13.8 MW wind farm near Canso, Nova Scotia.

“SCR” means selective catalytic reduction.

“SEC” means the U.S. Securities and Exchange Commission.

“Securities Act” means the United States Securities Act of 1933, as amended.

“SEDAR” means the System for Electronic Document Analysis and Retrieval.

“Selling Debentureholder” means Emera Holdings NS Company, a direct wholly-owned subsidiary of Emera.

“Senior Guaranteed Note Indenture” has the meaning ascribed thereto under the heading “Description of the Indebtedness—Proposed Emera US Finance Senior Guaranteed Notes.”

“Senior Guaranteed Notes” has the meaning ascribed thereto under the heading “Summary—Financing the Acquisition.”

“Senior Indebtedness” means obligations (other than non-recourse obligations, Notes issued under the Trust Indenture or any other obligations specifically designated as being subordinate in right of payment to Senior Indebtedness) of, or guaranteed or assumed by, Emera for borrowed money or evidenced by bonds, debentures or notes or obligations of Emera for or in respect of bankers’ acceptances (including the face amount thereof), letters of credit and letters of guarantee (including all reimbursement obligations in respect of each of the forgoing) or other similar instruments, and amendments, renewals, extensions, modifications and refunding of any such indebtedness or obligation.

“Senior Notes” has the meaning ascribed thereto under the heading “Summary—Financing the Acquisition.”

“Series A First Preferred Shares” means the cumulative 5-year rate reset first preferred shares, Series A of Emera.

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“Series B First Preferred Shares” means the cumulative floating rate first preferred shares, Series B of Emera.

“Series C First Preferred Shares” means the cumulative rate reset first preferred shares, Series C of Emera.

“Series E First Preferred Shares” means the cumulative redeemable first preferred shares, Series E of Emera.

“Series F First Preferred Shares” means the cumulative redeemable rate reset first preferred shares, Series F of Emera.

“SIA” means the Strategic Investment Agreement dated April 29, 2011 between Emera and APUC.

“SO₂” means sulfur dioxide.

“South Canoe Wind Project” means a wind farm project approved by the Municipality of the District of Chester on March 14, 2013.

“Special Mandatory Redemption Date” means the 20th Business Day following the earlier of the Special Mandatory Redemption Triggering Date and the date on which the Acquisition Agreement is terminated.

“Special Mandatory Redemption Triggering Date” has the meaning ascribed thereto under the heading “Description of Other Indebtedness—Proposed Emera US Finance Senior Guaranteed Notes.”

“SunEdison” means SunEdison, Inc.

“Superfund” means a fund established to finance a long-term, permanent remedial project in connection with the U.S. federal government’s program to clean up the uncontrolled hazardous waste sites in the United States.

“Tampa Electric” means Tampa Electric, the electric division of TEC.

“Tax Act” means the Income Tax Act (Canada) and the regulations thereunder.

“Tax Event” means Emera has received an opinion of independent counsel of a nationally recognized law firm in Canada or the U.S. experienced in such matters (who may be counsel to Emera) to the effect that, as a result of, (i) any amendment to, clarification of, or change (including any announced prospective change) in, the laws, or any regulations thereunder, or any application or interpretation thereof, of Canada or the U.S. or any political subdivision or taxing authority thereof or therein, affecting taxation; (ii) any judicial decision, administrative pronouncement, published or private ruling, regulatory procedure, rule, notice, announcement, assessment or reassessment (including any notice or announcement of intent to adopt or issue such decision, pronouncement, ruling, procedure, rule, notice, announcement, assessment or reassessment) (collectively, an “administrative action”); or (iii) any amendment to, clarification of, or change in, the official position with respect to or the interpretation of any administrative action or any interpretation or pronouncement that provides for a position with respect to such administrative action that differs from the theretofore generally accepted position, in each of case (i), (ii) or (iii), by any legislative body, court, governmental authority or agency, regulatory body or taxing authority, irrespective of the manner in which such amendment, clarification, change, administrative action, interpretation or pronouncement is made known, which amendment, clarification, change or administrative action is effective or which interpretation, pronouncement or administrative action is announced on or after the date of issue of the Notes, there is more than an insubstantial risk (assuming any proposed or announced amendment, clarification, change, interpretation, pronouncement or administrative action is effective and applicable) that Emera is, or may be, subject to more than a de minimis amount of additional taxes, duties or other governmental charges or civil liabilities because the treatment of any of its items of income, taxable

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income, expense, taxable capital or taxable paid-up capital with respect to the Notes (including the treatment by Emera of interest on any series of Notes), as or as would be reflected in any tax return or form filed, to be filed, or otherwise could have been filed, will not be respected by a taxing authority.

“Tax Proposals” means all specific proposals to amend the Tax Act and the regulations thereunder publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date of this Prospectus.

“TDI New England” means Champlain VT, LLC doing business as “TDI New England.”

“TEC” means Tampa Electric Company, the principal subsidiary of TECO Energy, Inc.

“TECO Coal” means TECO Coal LLC, and its subsidiaries, a coal producing subsidiary of TECO Diversified.

“TECO Coal SPA” means the Securities Purchase Agreement for the sale of TECO Coal to Cambrian.

“TECO Diversified” means TECO Diversified, Inc., a subsidiary of TECO Energy, Inc. and parent of TECO Coal Corporation.

“TECO Energy” means the holding company, TECO Energy, Inc. and its subsidiaries, and references to individual subsidiaries of TECO Energy, Inc. refer to that company and its respective subsidiaries.

“TECO Finance” means TECO Finance, Inc., a financing subsidiary for the unregulated businesses of TECO Energy, Inc.

“TECO Guatemala” means TECO Guatemala, Inc., a subsidiary of TECO Energy, Inc., parent company of formerly owned generating and transmission assets in Guatemala.

“TGH” means TECO Guatemala Holdings, LLC.

“therm” equals 100,000 British thermal units, or 0.10 MMBTU.

“Trust Indenture” means the trust indenture to be entered into between Emera and American Stock Transfer & Trust Company, LLC and CST Trust Company, as Indenture Trustee, providing for the issuance of Notes by Emera, as amended, restated or supplemented from time to time.

“TSX” means the Toronto Stock Exchange.

“U.S.” means the United States of America.

“U.S. dollars” or “USD” or “U.S.$” means the lawful currency of the U.S.

“U.S. GAAP” means Generally Accepted Accounting Principles in the United States.

“U.S. person” has the meaning set out under the Securities Act.

“UARB” means the Nova Scotia Utility and Review Board.

“VaR” means value-at-risk.

“WOTUS” has the meaning ascribed thereto under the heading “Business—TECO Energy—EPA Waters of the U.S.”

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RISK FACTORS

An investment in the Notes involves certain risks. A prospective purchaser of the Notes should carefully consider the risk factors described under:

(a) the heading “Principal Risks and Uncertainties” in note 32 to Emera’s audited consolidated financial statements as at and for the years ended December 31, 2015 and 2014, as found on pages 165 to 166 of the Company’s 2015 Annual Report; and

(b) the heading “Principal Risks and Uncertainties” in note 24 to Emera’s unaudited interim financial statements as at and for the three months ended March 31, 2016, as found on pages 40 to 42 of such statements,

each of which is incorporated by reference herein. In addition, a prospective purchaser of the Notes should carefully consider the risk factors described in this section which relate to the Acquisition, the Notes and the post-Acquisition business and operations of the Company and TECO Energy, as well as the other information contained in this Prospectus (including the documents incorporated by reference herein).

Risk Factors Relating to the Acquisition

Failure to complete the Acquisition

The closing of the Acquisition is subject to the normal commercial risks that the Acquisition will not close on the terms negotiated or at all. The completion of the Acquisition is subject to satisfaction of the Approval Conditions, including obtaining the approval of NMPRC, which is pending, and the satisfaction or waiver of certain closing conditions contained in the Acquisition Agreement, including the absence of any law or judgement that prevents, makes illegal or prohibits the consummation of the Acquisition. The failure to obtain the required approvals or satisfy or waive the conditions contained in the Acquisition Agreement may result in the termination of the Acquisition Agreement. There is no assurance that such closing conditions will be satisfied or waived. Accordingly, there can be no assurance that Emera will complete the Acquisition in the timeframe or on the basis described herein, if at all. Furthermore, Emera or TECO Energy may terminate the Acquisition Agreement if (i) the closing of the Acquisition has not occurred by September 30, 2016 (subject to a six-month extension if required to obtain necessary regulatory approvals) or (ii) a law or judgement preventing or prohibiting the closing of the Acquisition has become final. The termination of the Acquisition Agreement may have a negative effect on the price of the Notes. If the closing of the Acquisition does not take place as contemplated, the Company could suffer adverse consequences, including the loss of investor confidence. See “The Acquisition Agreement.”

Length of time required to complete the Acquisition is unknown

As described above under “—Failure to complete the Acquisition,” the closing of the Acquisition remains subject to the receipt of NMPRC approval and the satisfaction or waiver of certain closing conditions contained in the Acquisition Agreement. There is no certainty, nor can Emera provide any assurance, as to when these conditions will be satisfied, if at all. A substantial delay in obtaining the NMPRC approval or the imposition of unfavourable terms and/or conditions could have a material adverse effect on the Company’s ability to complete the Acquisition and on the Company’s or TECO Energy’s business, financial condition or results of operations. In addition, in the event that regulatory agencies imposed unfavorable terms and/or conditions on Emera or any TECO Energy utility (including the requirement to sell or divest of certain assets or limitations on the future conduct of the combined entities), the Company would still be required to complete the transaction on the terms set forth in the Acquisition Agreement. Emera intends to complete the Acquisition within fifteen business days of obtaining the required regulatory approvals and satisfying the other required closing conditions. See “The Acquisition Agreement.”

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Emera may not realize all of the anticipated benefits of the Acquisition

Emera believes that the Acquisition will provide benefits to the Company, including that the Acquisition will be accretive to Emera’s earnings and will provide significant accretion to Emera’s cash position. However, there is a risk that some or all of the expected benefits of the Acquisition may fail to materialize, or may not occur within the time periods anticipated by the Company. The realization of such benefits may be affected by a number of factors, many of which are beyond the control of the Company. The challenge of combining previously independent businesses makes evaluating the Company’s business and future financial prospects difficult. The past financial performance of the Company may not be indicative of its future financial performance. In addition, regulatory approvals required in connection with the Acquisition may include terms which could have an adverse effect on the Company’s financial performance, including reduced revenues or investment recovery, increased competition or costs, or adverse alterations to the rate structure.

Failure to realize the anticipated benefits of the Acquisition may impact the financial performance of the Company. See “—Risk Factors Relating to the Post-Acquisition Business and Operations of Emera and TECO Energy.”

Foreign exchange risk

The cash consideration for the Acquisition is required to be paid in U.S. dollars, while a portion of the funds raised in certain of the Acquisition Capital Markets Transactions and the balance of the payments due upon the Final Instalment of the Convertible Debentures will be denominated in Canadian dollars. In addition, any cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) that Emera holds that will be used to fund the Acquisition may be held in Canadian dollars. See “Use of Proceeds.” As a result, increases in the value of the U.S. dollar versus the Canadian dollar will increase the purchase price translated in Canadian dollars, which could cause a failure to realize the anticipated benefits of the Acquisition.

Emera may enter into hedge arrangements for the remaining portion of Canadian dollar financing, if any. The failure to enter into hedging arrangements could result in adverse impacts greater than if hedging had been used.

The operations of TECO Energy are conducted in U.S. dollars. Following the Acquisition, the consolidated net income and cash flows of Emera will be impacted to a much greater extent by movements in the U.S. dollar relative to the Canadian dollar. In particular, decreases in the value of the U.S. dollar versus the Canadian dollar following the Acquisition, could negatively impact the Company’s net income as reported in Canadian dollars, which could cause a failure to realize the anticipated benefits of the Acquisition.

Significant demands will be placed on Emera as a result of the Acquisition

As a result of the pursuit and completion of the Acquisition, significant demands will be placed on the Company’s managerial, operational and financial personnel and systems. No assurance can be given that the Company’s systems, procedures and controls will be adequate to support the expansion of the Company’s operations resulting from the Acquisition. The Company’s future operating results will be affected by the ability of its officers and key employees to manage changing business conditions and to implement and improve its operational and financial controls and reporting systems.

Alternate sources of funding that would be used to fund the Acquisition or replace the Acquisition Credit Facilities may not be available

The cash purchase price of the Acquisition and the Acquisition-Related Expenses will be financed at the closing of the Acquisition with a combination of some or all of the following: (i) the proceeds from the Acquisition Capital Markets Transactions, (ii) the receipt of payment in full on the Final Instalment Date of the Final Instalment due under the Convertible Debentures, (iii) amounts drawn under the Acquisition Credit Facilities, if any, and (iv) existing cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) and other sources available to the Company.

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In connection with financing the Acquisition, in addition to the offering by Emera of any series of Notes pursuant to one or more Prospectus Supplements, Emera US Finance intends to issue Senior Guaranteed Notes. In addition, Emera intends to issue one or more series of Canadian dollar-denominated unsecured senior notes and may also issue Canadian dollar-denominated unsecured subordinated notes, in each case, on a basis which is exempt from the prospectus requirements of applicable Canadian securities laws.

Emera intends to raise up to approximately Cdn$6.6 billion in aggregate principal amount in the Acquisition Capital Markets Transactions. The aggregate principal amounts raised in the Acquisition Capital Markets Transactions and the terms on which such securities are issued are dependent on market and other conditions and may vary. See “Summary—Financing the Acquisition” for more information. The offering of any series of Notes hereunder is not contingent upon the consummation of the Acquisition or the other Acquisition Capital Markets Transactions. There can be no guarantee that the offerings of the securities to be issued in the Acquisition Capital Markets Transactions may be consummated at the desired time or at all, or on cost-efficient terms. In addition, to the extent (i) Emera raises less than Cdn$6.6 billion in connection with the Acquisition Capital Markets Transactions, or (ii) Emera does not receive payment in full of the Final Instalment of the Convertible Debentures, Emera intends to pay any shortfall by drawing on the Acquisition Credit Facilities and/or using existing cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) or other sources available to Emera in order to consummate the Acquisition. The interest rates and other fees that will be payable by Emera on amounts drawn under the Acquisition Credit Facilities may be more than those expected to be paid on the securities to be issued in the Acquisition Capital Markets Transactions. The terms of the Acquisition Credit Facilities may also be more restrictive than those that Emera expects to be subject to pursuant to the various agreements governing the Acquisition Capital Markets Transactions. Such amounts drawn under the Acquisition Credit Facilities will also be required to be paid within one year, pursuant to the terms of such facilities.

The inability to obtain alternate sources of funding, on attractive terms or at all, to fund the Acquisition or replace the Acquisition Credit Facilities may negatively impact the financial performance of Emera, including the extent to which the Acquisition is accretive. In addition, any movement in interest rates that could affect the underlying cost of these instruments may affect the expected accretion of the Acquisition.

Emera may not receive payment in full of the Final Instalment of the Convertible Debentures

The offering of any series of Notes as contemplated hereunder is not contingent upon payment in full of the Final Instalment of the Convertible Debentures. If a material amount due on payment of the Final Instalment is not paid by holders of Convertible Debentures represented by instalment receipts and Emera is not able to quickly realize on the Convertible Debentures pledged to secure the obligation to pay the Final Instalment, Emera will not be able to use those proceeds to finance, directly or indirectly, part of the purchase price payable for the Acquisition (including Acquisition-Related Expenses) and to reduce amounts outstanding under the Acquisition Credit Facilities, to the extent any amounts are drawn on such facilities in connection with the Acquisition. As a result, Emera may need to draw amounts under the Acquisition Credit Facilities to cover any shortfall, which will increase Emera’s debt service costs and negatively impact the financial performance of Emera until such time as the Acquisition Credit Facilities have been repaid by Emera in full.

Emera does not currently control TECO Energy and its subsidiaries

Although the Acquisition Agreement contains covenants on the part of TECO Energy regarding the operation of its business prior to closing the Acquisition, Emera will not control TECO Energy and its subsidiaries until completion of the Acquisition and the TECO Energy business and results of operations may be adversely affected by events that are outside of the Company’s control during the intervening period. Historic and current performance of TECO Energy’s business and operations may not be indicative of success in future periods. The future performance of TECO Energy may be influenced by, among other factors, economic downturns, existing and future environmental laws and regulations, turmoil in financial markets, unfavourable regulatory decisions, rising interest rates and other factors beyond the Company’s control. As a result of any one or more of these

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factors, among others, the operations and financial performance of TECO Energy may be negatively affected which may adversely affect the future financial results of Emera. See “—Risk Factors Relating to the Post-Acquisition Business and Operations of Emera and TECO Energy.”

Emera expects to incur significant Acquisition-Related Expenses

Emera expects the Acquisition-Related Expenses to be significant. The substantial majority of these costs will be non-recurring expenses resulting from the Acquisition and will consist of transaction costs related to the Acquisition, including costs relating to the financing of the Acquisition and obtaining regulatory approval. Acquisition-Related Expenses may exceed the amounts anticipated by Emera and additional unanticipated costs may be incurred.

TECO Energy and its subsidiaries are subject to business uncertainties and contractual restrictions while the Acquisition is pending that could adversely affect TECO Energy’s financial results

Uncertainty about the effect of the Acquisition on employees or vendors and others, including contractors, may have an adverse effect on TECO Energy. Although TECO Energy intends to take steps designed to reduce any adverse effects, these uncertainties may impair TECO Energy’s and its subsidiaries’ ability to attract, retain and motivate key personnel until the Acquisition is completed, and could cause vendors and others, including contractors, that deal with TECO Energy to seek to change existing business relationships. Employee retention and recruitment may be particularly challenging prior to the completion of the Acquisition, as current employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite TECO Energy’s retention and recruiting efforts, key employees depart or fail to accept employment with TECO Energy or its subsidiaries due to the uncertainty of employment and difficulty of integration or a desire not to remain with the combined company, following completion of the Acquisition. TECO Energy may incur significant costs in identifying, hiring, and retaining replacements for departing employees, which could have a material adverse effect on TECO Energy’s business operations and financial results. TECO Energy expects that matters relating to the Acquisition and integration-related issues will place a significant burden on management, employees and internal resources, which could otherwise have been devoted to other business opportunities. The diversion of management time on Acquisition-related issues could affect TECO Energy’s financial results.

In addition, the Acquisition Agreement restricts TECO Energy and its subsidiaries from taking specified actions until the Acquisition occurs or the Acquisition Agreement is terminated, without Emera’s prior written consent, including, without limitation: (i) making certain material acquisitions and dispositions of assets or businesses; (ii) making any capital expenditures in excess of specified amounts; (iii) incurring indebtedness, subject to certain exceptions; (iv) issuing equity or equity equivalents; and (v) paying quarterly cash dividends in excess of levels agreed upon in the Acquisition Agreement. These restrictions may prevent TECO Energy from pursuing otherwise attractive business opportunities and making other changes to its business prior to consummation of the Acquisition or termination of the Acquisition Agreement.

TECO Energy and Emera have been and may continue to be the target of securities class action suits and derivative suits which could result in substantial costs and divert management attention and resources

Securities class action suits and derivative suits are often brought against companies who have entered into mergers and acquisition transactions. Following the announcement of the execution of the Acquisition Agreement, 12 putative stockholder class actions were filed challenging the Acquisition. In November 2015, the defendants party to the litigation entered into a Memorandum of Understanding (the “MOU”) with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Acquisition. As a result of the MOU, TECO Energy made additional disclosures related to the proposed Acquisition in a proxy supplement filed on November 18, 2015. The MOU provides for the parties to enter into a formal settlement agreement which will be submitted to the Hillsborough Circuit Court Judge for approval after

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completion of the Acquisition. Additionally the judge will consider the award of attorneys’ fees to the plaintiffs’ lawyers. Defending against these claims, even if meritless, can result in substantial costs to TECO Energy and Emera and could divert the attention of its management.

Risk Factors Relating to the Post-Acquisition Business and Operations of Emera and TECO Energy

For additional risk factors relating to Emera, see “Management’s Discussion and Analysis—Enterprise Risk and Risk Management.”

Emera will have a substantial amount of indebtedness which may adversely affect its cash flow and ability to operate its business

After giving effect to the Acquisition, Emera will have a significant amount of debt, including U.S.$4.1 billion of debt of TECO Energy assumed by Emera as a result of the Acquisition. As of March 31, 2016, on a pro forma basis after giving effect to the Acquisition and the Acquisition Capital Markets Transactions, but assuming conversion of all Convertible Debentures to Common Shares, details of which are included in the capitalization table provided herein, Emera would have approximately Cdn$15.5 billion of total indebtedness outstanding. See “Capitalization.”

An offering of Notes could result in a downgrade of Emera’s credit ratings

The change in the capital structure of Emera as a result of the Acquisition, any series of Notes offered hereunder and the other Acquisition Capital Markets Transactions could cause credit rating agencies which rate the outstanding debt obligations of Emera to re-evaluate and potentially downgrade the current credit ratings, which could increase the Company’s borrowing costs.

Emera’s historical and pro forma combined financial information may not be representative of the results of Emera following the Acquisition

The pro forma combined financial information included in this Prospectus has been prepared using the consolidated historical financial statements of Emera and the consolidated historical financial statements of TECO Energy and does not purport to be indicative of the financial information that will result from the operations of Emera on a consolidated basis following the Acquisition. In addition, the pro forma combined financial information included in this Prospectus is based in part on certain assumptions regarding the Acquisition that Emera currently believes are reasonable. Emera makes no assurances that its current assumptions will prove to be accurate over time. Accordingly, the historical and pro forma financial information included in this Prospectus does not necessarily represent the results of operations and financial condition had Emera and TECO Energy operated as a combined entity during the periods presented, or of the results of operations and financial condition in the future. The potential for future business success and operating profitability must be considered in light of the risks, uncertainties, expenses and difficulties typically encountered by recently combined companies. The pro forma combined financial information included in this Prospectus has not been prepared in compliance with Regulation S-X.

In preparing the pro forma financial information contained in this Prospectus, Emera has given effect to (i) the Acquisition Capital Markets Transactions; (ii) the issuance of the Common Shares upon conversion of the Convertible Debentures on the Final Instalment Date (assuming payment in full of the Final Instalment of the Convertible Debentures); and (iii) the consummation of the Acquisition. While Emera’s management believes that the estimates and assumptions underlying the pro forma financial information are reasonable, such assumptions and estimates may be materially different than Emera’s actual experience following completion of the Acquisition. See also “—Risk Factors Relating to the Acquisition,” “Presentation of Financial Information” and “Unaudited Pro Forma Consolidated Financial Statements—Notes to Unaudited Pro Forma Consolidated Financial Statements.”

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In particular, we may not be able to consummate the other offerings of securities forming part of the Acquisition Capital Markets Transactions, either at the desired times or at all, or on cost-effective terms. Any differences in the amounts or terms of the Acquisition Capital Markets Transactions to those set forth in this Prospectus may increase our anticipated debt service costs or reduce our anticipated liquidity as shown in the pro forma financial statements and may have a material adverse effect on the Company’s business, financial condition or future prospects. Among other things, if we are not able to raise Cdn$6.6 billion in aggregate proceeds from the Acquisition Capital Markets Transactions, Emera may be required to draw down amounts, under the Acquisition Credit Facilities, which may also increase Emera’s anticipated debt service costs.

Potential undisclosed liabilities associated with the Acquisition

In connection with the Acquisition, there may be liabilities of TECO Energy and its subsidiaries that the Company failed to discover or was unable to quantify in the due diligence which it conducted prior to the execution of the Acquisition Agreement. The discovery or quantification of any material liabilities of TECO Energy and its subsidiaries could have a material adverse effect on the Company’s business, financial condition or future prospects.

Emera may be unable to successfully combine the businesses of Emera and TECO Energy to realize the anticipated benefits of the Acquisition

The combination of the businesses of Emera and TECO Energy will require the dedication of substantial effort, time and resources on the part of management which may divert management’s focus and resources from other strategic opportunities and from operational matters during this process. There can be no assurance that management will be able to combine the operations of each of the businesses successfully or achieve any of the benefits that are anticipated as a result of the Acquisition. The extent to which the benefits are realized and the timing of such cannot be assured. Any inability of management to successfully combine the operations of Emera and TECO Energy could have a material adverse effect on the Company’s business, financial condition or results of operations.

Emera may not be successful in retaining the services of key personnel of TECO Energy following the Acquisition

Emera currently intends to retain key personnel of TECO Energy following the completion of the Acquisition and to continue to manage and operate TECO Energy as a separate operating company. Emera will compete with other potential employers for employees, and it may not be successful in keeping the services of the executives and other employees that it needs to realize the anticipated benefits of the Acquisition. The Company’s failure to retain key personnel to remain as part of the management team of TECO Energy in the period following the Acquisition could have a material adverse effect on the business and operations of TECO Energy and Emera on a consolidated basis.

Emera is subject to risks associated with its results of operations and financing risks

Management of Emera believes, based on current expectations as to its future performance (which reflects, among other things, the completion of the Acquisition), that the cash flow from its operations and funds available under its Revolving Facility and its ability to access capital markets will be adequate to enable the Company to finance its operations, execute its business strategy and maintain an adequate level of liquidity. However, expected revenue and the costs of planned capital expenditures are only estimates. Moreover, actual cash flows from operations are dependent on regulatory, market and other conditions that are beyond the control of the Company. As such, no assurance can be given that management’s expectations as to future performance will be realized. In addition, management’s expectations as to the Company’s future performance reflect the current state of its information about TECO Energy and its operations and there can be no assurance that such information is correct and complete in all material respects.

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After giving effect to the Acquisition, Emera will have a significant amount of debt, including US$4.1 billion of debt of TECO Energy assumed by Emera as a result of the Acquisition. As of March 31, 2016, on an as adjusted pro forma basis after giving effect to (i) the Acquisition Capital Markets Transactions; (ii) the issuance of the Common Shares upon conversion of the Convertible Debentures on the Final Instalment Date (assuming payment in full of the Final Instalment of the Convertible Debentures); and (iii) the consummation of the Acquisition, details of which are included in the capitalization table provided herein, Emera would have approximately Cdn$15.5 billion of total indebtedness outstanding. See “Capitalization.” The significant increase in the degree of the Company’s leverage could, among other things, limit the Company’s ability to obtain additional financing for working capital, investment in subsidiaries, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; restrict the Company’s flexibility and discretion to operate its business; require Emera to dedicate a portion of cash flows from operations to the payment of interest on its existing indebtedness, in which case such cash flows will not be available for other purposes; cause ratings agencies to re-evaluate or downgrade the Company’s existing credit ratings; expose Emera to increased interest expense on borrowings at variable rates; limit the Company’s ability to adjust to changing market conditions; place Emera at a competitive disadvantage compared to its competitors that have less debt; make Emera vulnerable to any downturn in general economic conditions; and render Emera unable to make expenditures that are important to its future growth strategies.

The Company will need to refinance or reimburse amounts outstanding under the Company’s and TECO Energy’s indebtedness over time. There can be no assurance that any such indebtedness of the Company will be refinanced or that additional financing on commercially reasonable terms will be obtained, if at all.

The ability of the Company to meet its debt service requirements will depend on its ability to generate cash in the future, which depends on many factors, including the financial performance of the Company, debt service obligations, the realization of the anticipated benefits of the Acquisition and working capital and future capital expenditure requirements. In addition, the ability of the Company to borrow funds in the future to make payments on outstanding debt will depend on the satisfaction of covenants in existing credit agreements and other agreements. A failure to comply with any covenants or obligations under the Company’s consolidated indebtedness could result in a default under one or more such instruments, which, if not cured or waived, could result in the termination of distributions by the Company and permit acceleration of the relevant indebtedness. If such indebtedness were to be accelerated, there can be no assurance that the assets of the Company would be sufficient to repay such indebtedness in full. There can also be no assurance that the Company will generate cash flow in amounts sufficient to pay outstanding indebtedness or to fund any other liquidity needs.

National and local economic conditions can have a significant impact on the results of operations, net income and cash flows at TECO Energy and its subsidiaries

The business of TECO Energy is concentrated in Florida and New Mexico. While economic conditions in Florida and New Mexico have improved since the worst of the economic downturn in 2008, if they do not continue to improve or if they should worsen, retail customer growth rates may stagnate or decline, and customers’ energy usage may further decline, adversely affecting TECO Energy’s results of operations, net income and cash flows.

A factor in TECO Energy’s customer growth in both Florida and New Mexico is net in migration of new residents, both domestic and non-U.S. A slowdown in the U. S. economy could reduce the number of new residents and slow customer growth. In addition, New Mexico has significant oil and natural gas production from the San Juan and Permian production basins. The current low oil and natural gas-price environment has reduced drilling activity and oil and natural gas production in some producing regions, which has reduced employment in those industries and industries that serve them. A continuation of these conditions could slow growth in the New Mexico economy, which could reduce earnings and cash flow from NMGC.

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Developments in technology could reduce demand for electricity and gas

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, energy efficiency and more energy-efficient appliances and equipment. Advances in these, or other technologies, could reduce the cost of producing electricity or transporting gas, or otherwise make the existing generating facilities of Tampa Electric uneconomic. In addition, advances in such technologies could reduce demand for electricity or natural gas, which could negatively impact the results of operations, net income and cash flows of TECO Energy and those of the Company following the Acquisition.

TECO Energy’s businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations

TECO Energy’s businesses are affected by variations in general weather conditions and unusually severe weather. Energy sales by its electric and gas utilities are particularly sensitive to variations in weather conditions. Those companies forecast energy sales on the basis of normal weather, which represents a long-term historical average. If climate change or other factors cause significant variations from normal weather, this could have a material impact on energy sales.

PGS and NMGC, which typically have short but significant winter peak periods that are dependent on cold weather, are more weather-sensitive than Tampa Electric, which has both summer and winter peak periods. NMGC typically earns all of its net income in the first and fourth quarters, due to winter weather. Mild winter weather could negatively impact results at TECO Energy and those of Emera following the Acquisition.

TECO Energy’s electric and gas utilities are highly regulated; changes in regulation or the regulatory environment could reduce revenues or increase costs or competition

TECO Energy’s electric and gas utilities operate in highly regulated industries. Their retail operations, including the prices charged, are regulated by the FPSC in Florida and the NMPRC in New Mexico, and Tampa Electric’s wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on TECO Energy’s utilities’ financial performance by, for example, reducing revenues, increasing competition or costs, threatening investment recovery or impacting rate structure.

If Tampa Electric or PGS earn returns on equity above their respective allowed ranges, indicating an overearnings trend, those earnings could be subject to review by the FPSC. Ultimately, prolonged overearnings could result in credits or refunds to customers, which could reduce earnings and cash flow.

Various factors relating to the integration of NMGC could adversely affect TECO Energy’s business and operations

The anticipated accretion to TECO Energy’s earnings from NMGC during the original three-year integration period was based on estimates of synergies from the transaction and growth in the New Mexico economy, which are dependent on local and global economic conditions, normal weather and other factors, which may materially change, including:

• TECO Energy’s estimate of NMGC’s expected operating performance after the completion of the transaction may vary significantly from actual results.

• Over time, TECO Energy will be making significant capital investments to convert several NMGC computer systems to the systems that TECO Energy uses in Florida. These conversions may not be accomplished on time or on budget, which would increase costs for NMGC. In addition, the time required to convert these systems will cause NMGC to operate the existing systems past the end of their normal lives, which could reduce reliability.

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• The potential loss of key employees of TECO Energy or NMGC who may be uncertain about their future roles in the TECO Energy / NMGC organization.

Negative impacts from these factors could have an adverse effect on the anticipated benefits of the Acquisition or TECO Energy’s business, financial condition or results of operations. TECO Energy identified some, but not all, of the actions necessary to achieve its anticipated synergies. Accordingly, the synergies expected from the acquisition of NMGC may not be achievable in its anticipated amount or timeframe or at all.

Changes in the environmental laws and regulations affecting its businesses could increase TECO Energy’s costs or curtail its activities

TECO Energy’s businesses are subject to regulation by various governmental authorities dealing with air, water and other environmental matters. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on TECO Energy, requiring cost-recovery proceedings and/or requiring it to curtail some of its businesses’ activities.

Regulations on the disposal and/or storage of CCRs could add to Tampa Electric’s operating costs

The U.S. EPA published a new CCR rule in the U.S. Federal Register on April 17, 2015 setting federal standards for companies that dispose of or store CCRs in onsite landfills and impoundments. The rule went into effect on October 19, 2015 and contains design and operating standards for CCR management units. Tampa Electric is currently evaluating various options for demonstrating compliance with the rule. The initial assessment is that activities in 2016 will consist primarily of monitoring and testing of the two existing CCR impoundments that are affected by this rule. Potential capital expenditures that may be required to comply with this rule are not expected to be significant. This rule is likely to face continued legal challenges by the utility industry and environmental groups, and legislation may be required to fix certain portions of the rule. At this time, the ultimate outcome of any litigation or legislation is uncertain, so that it is not possible to predict the ultimate impact on Tampa Electric. While certain costs related to environmental compliance are currently recoverable from customers under Florida’s ECRC, TECO Energy cannot be assured that any increased costs associated with the new regulations will be eligible for such treatment.

Federal or state regulation of GHG emissions, depending on how they are enacted and implemented, could increase TECO Energy’s costs or the rates charged to TECO Energy customers, which could curtail sales

Among TECO Energy’s companies, Tampa Electric has the most significant number of stationary sources with air emissions.

Current regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new state or federal environmental regulations. Tampa Electric would expect to recover from customers the costs of power plant modifications or other costs required to comply with new GHG emission regulation. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but TECO Energy cannot be assured that the FPSC would grant such recovery. Under the Clean Power Plan, each state is responsible for implementing its own regulations to accord to the federal standards. Accordingly, a change in Florida’s regulatory landscape could significantly increase Tampa Electric’s costs. Changes in compliance requirements or the interpretation by governmental authorities of existing requirements may impose additional costs on TECO Energy requiring FPSC cost recovery proceedings and/or requiring it to curtail some of its business activities.

The Clean Power Plan establishes state-specific emission rate and mass-based goals measured against a 2012 baseline. As TECO Energy’s investments in lower-GHG production largely occurred before 2012 and are factored into Florida’s baseline generating capacity, TECO Energy may encounter more difficulty than its

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competitors in achieving cost-effective GHG emission reductions. Because the ultimate form of Florida’s state plan remains unknown, the increased compliance costs that TECO Energy may face as a result of the Clean Power Plan are currently uncertain.

On February 9, 2016, the U.S. Supreme Court issued a stay against enforcement of the Clean Power Plan for the electricity sector pending resolution of the legal challenges before the U.S. Court of Appeals for the District of Columbia Circuit. The timing of the resolution of the legal challenges and the removal of the stay by the U.S. Supreme Court is uncertain, but it is likely to delay further actions by the states until 2018.

In 2015, there was a proposed constitutional ballot initiative for the 2016 election approved by the Florida Supreme Court to promote increased direct sale and use of solar energy to generate electricity which has now been delayed to the 2018 election. There is a corresponding legislative proposal for the current 2016 legislative session that could, if successful, promote increased direct sale and use of solar energy to generate electricity

The potential amendment to the Florida constitution in 2018 and potential corresponding 2016 legislation would encourage the installation of solar arrays to generate electricity by retail customers and third parties, and to allow sales of electricity by non-utility generators. Increased use of solar generation and sales by third parties would reduce energy sales and revenues at Tampa Electric. In addition, Tampa Electric could make investments in facilities to serve customers during periods that solar energy is not available that would not be profitable.

NMGC operates high-pressure natural gas transmission pipelines, which involve risks that may result in accidents or otherwise affect its operations

There are a variety of hazards and operating risks inherent in operating high-pressure natural gas transmission pipelines, such as leaks, explosions, mechanical problems, activities of third parties and damage to pipelines, facilities and equipment caused by floods, fires and other natural disasters that may cause substantial financial losses. In addition, these risks could result in significant injury, loss of life, significant damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For pipeline assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, known as High Consequence Areas, the level of damage resulting from these risks could be greater. NMGC does not maintain insurance coverage against all of these risks and losses, and any insurance coverage it might maintain may not fully cover damages caused by those risks and losses. Therefore, should any of these risks materialize, it could have a material adverse effect on TECO Energy’s business, earnings, financial condition and cash flows.

NMGC’s high-pressure transmission pipeline operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase TECO Energy’s cost of operations and affect or limit its business plans

TECO Energy’s pipeline operations are subject to pipeline safety regulation administered by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation. These laws and regulations require TECO Energy to comply with a significant set of requirements for the design, construction, maintenance and operation of its pipelines. These regulations, among other things, include requirements to monitor and maintain the integrity of its pipelines. The regulations determine the pressures at which its pipelines can operate.

PHMSA is designing an integrity verification process intended to create standards to verify maximum allowable operating pressure, and to improve and expand pipeline integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. Pipeline failures or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on TECO Energy’s pipelines. Should any of these risks materialize, it may have a material adverse effect on TECO Energy’s operations, earnings, financial condition and cash flows.

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Results at TECO Energy’s companies may be affected by changes in customer energy-usage patterns

For the past several years, at Tampa Electric, and electric utilities across the United States, weather-normalized electricity consumption per residential customer has declined due to the combined effects of voluntary conservation efforts, economic conditions and improvements in lighting and appliance efficiency.

Forecasts by TECO Energy’s companies are based on normal weather patterns and historical trends in customer energy-usage patterns. The ability of TECO Energy’s utilities to increase energy sales and earnings could be negatively impacted if customers continue to use less energy in response to increased energy efficiency, economic conditions or other factors.

TECO Energy’s computer systems and the infrastructure of its utility companies may be subject to cyber (primarily electronic or internet-based) or physical attacks, which could disrupt operations, cause loss of important data or compromise customer, employee-related or other critical information or systems, or otherwise adversely affect its business and financial results and condition

There have been an increasing number of cyber-attacks on companies around the world, which have caused operational failures or compromised sensitive corporate or customer data. These attacks have occurred over the Internet, through malware, viruses, attachments to e-mails, through persons inside of the organization or through persons with access to systems inside of the organization.

TECO Energy has security systems and infrastructure in place that are designed to prevent such attacks, and these systems are subject to internal, external and regulatory audits to ensure adequacy. Despite these efforts, TECO Energy cannot be assured that a cyber-attack will not cause electric or gas system operational problems, disruptions of service to customers, compromise important data or systems, or subject it to additional regulation, litigation or damage to its reputation.

There have also been physical attacks on critical infrastructure at other utilities. While the transmission and distribution system infrastructure of TECO Energy’s utility companies are designed and operated in a manner intended to mitigate the impact of this type of attack, in the event of a physical attack that disrupts service to customers, revenues would be reduced and costs would be incurred to repair any damage. These types of events, either impacting its facilities or the industry in general, could also cause TECO Energy to incur additional security- and insurance-related costs, and could have adverse effects on its business and financial results and condition.

Potential competitive changes may adversely affect TECO Energy’s regulated electric and gas businesses

There is competition in wholesale power sales across the United States. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Although not expected in the foreseeable future, changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its expected performance.

The gas distribution industry has been subject to competitive forces for a number of years. Gas services provided by TECO Energy’s gas utilities are unbundled for all non-residential customers. Because its gas utilities earn margins on distribution of gas but not on the commodity itself, unbundling has not negatively impacted TECO Energy’s results. However, future structural changes that TECO Energy cannot predict could adversely affect PGS and NMGC.

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Increased customer use of distributed generation could adversely affect TECO Energy’s regulated electric utility business

In many areas of the United States there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, called distributed generation, by individual residential, commercial and industrial customers. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Additionally, the EPA’s Clean Power Plan could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets under the proposed rule.

Increased usage of distributed generation, particularly in those states where solar or wind resources are the most abundant, is reducing utility electricity sales but not reducing the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Continued utility investment that is not supported by increased energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.

The value of TECO Energy’s existing deferred tax benefits are determined by existing tax laws, and could be negatively impacted by changes in these laws

“Comprehensive tax reform” remains a topic of discussion in the U.S. Congress. Such legislation could significantly alter the existing tax code, including a reduction in corporate income tax rates. Although a reduction in the corporate income tax rate could result in lower future tax expense and tax payments, it would reduce the value of TECO Energy’s existing deferred tax asset and could result in a charge to earnings from the write-down of that asset, and it would reduce future tax payments received by TECO Energy from its subsidiaries.

TECO Energy relies on some natural gas transmission assets that it does not own or control to deliver natural gas. If transmission is disrupted, or if capacity is inadequate, TECO Energy’s ability to sell and deliver natural gas and supply natural gas to its customers and its electric generating stations may be hindered

TECO Energy depends on transmission facilities owned and operated by other utilities and energy companies to deliver the natural gas it sells to the wholesale and retail markets, as well as the natural gas it purchases for use in its electric generation facilities. If transmission is disrupted, or if capacity is inadequate, its ability to sell and deliver products and satisfy its contractual and service obligations could be adversely affected.

Disruption of fuel supply could have an adverse impact on the financial condition of TECO Energy

Tampa Electric, PGS and NMGC depend on third parties to supply fuel, including natural gas and coal. As a result, there are risks of supply interruptions and fuel price volatility. Disruption of fuel supplies or transportation services for fuel, whether because of weather-related problems, strikes, lock-outs, break-downs of locks and dams, pipeline failures or other events could impair the ability to deliver electricity or gas or generate electricity and could adversely affect operations. Further, the loss of coal suppliers or the inability to renew existing coal and natural gas contracts at favorable terms could significantly affect the ability to serve customers and have an adverse impact on the financial condition and results of operations of TECO Energy and those of the Company following the Acquisition.

Commodity price changes may affect the operating costs and competitive positions of TECO Energy’s businesses

TECO Energy’s businesses are sensitive to changes in coal, gas, oil and other commodity prices. Any changes in the availability of these commodities could affect the prices charged by suppliers as well as suppliers’ operating costs and the competitive positions of their products and services.

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In the case of Tampa Electric, fuel costs used for generation are affected primarily by the cost of coal and natural gas. Tampa Electric is able to recover prudently incurred costs of fuel through retail customers’ bills, but increases in fuel costs affect electric prices and, therefore, the competitive position of electricity against other energy sources.

The ability to make sales of and the margins earned on wholesale power sales are affected by the cost of fuel to Tampa Electric, particularly as it compares to the costs of other power producers.

In the case of PGS and NMGC, costs for purchased gas and pipeline capacity are recovered through retail customers’ bills, but increases in gas costs affect total retail prices and, therefore, the competitive positions of PGS and NMGC as compared to electricity, other forms of energy and other gas suppliers.

The facilities and operations of TECO Energy could be affected by natural disasters or other catastrophic events

TECO Energy’s facilities and operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g. floods, high winds, fires and earthquakes), equipment failures, vandalism, potentially catastrophic events such as the occurrence of a major accident or incident at one of the sites, and other events beyond the control of TECO Energy. The operation of transmission and distribution systems involves certain risks, including gas leaks, fires, explosions, pipeline ruptures and other hazards and risks that may cause unforeseen interruptions, personal injury or property damage. Any such incident could have an adverse effect on TECO Energy and any costs relating to such events may not be recoverable through insurance or recovered in rates. In certain cases, there is potential that such an event may not excuse TECO Energy’s utility subsidiaries from servicing customers as required by their respective tariffs. In addition, TECO Energy may not be able to recover losses resulting from such events through insurance or rates.

The franchise rights held by TECO Energy’s subsidiaries could be lost in the event of a breach by such TECO Energy subsidiary or could expire and not be renewed

TECO Energy’s subsidiaries hold franchise rights that are memorialized in agreements with selected counterparties throughout the subsidiaries’ service areas. In some cases these rights could be lost in the event of a breach of these agreements by such TECO Energy subsidiary. In addition, these agreements are for set periods and could expire and not be renewed upon expiration of the then-current terms. Selected agreements also contain purchase rights allowing municipalities to purchase the corresponding subsidiary’s system within a given municipality’s boundaries under certain conditions.

Tampa Electric, PGS and NMGC may not be able to secure adequate rights-of-way to construct transmission lines, gas interconnection lines and distribution related facilities and could be required to find alternate ways to provide adequate sources of energy and maintain reliable service for their customers

Tampa Electric, PGS and NMGC rely on federal, state and local governmental agencies and, in particular in New Mexico, cooperation with local Native American tribes and councils to secure right-of-way and siting permits to construct transmission lines, gas interconnection lines and distribution-related facilities. If adequate right-of-way and siting permits to build new transportation and transmission lines cannot be secured:

• Tampa Electric, PGS and NMGC may need to remove its facilities, or abandon its facilities on, the property covered by rights-of-way or franchises and seek alternative locations for its transmission or distribution facilities;

• Tampa Electric, PGS and NMGC may need to rely on more costly alternatives to provide energy to their customers;

• Tampa Electric, PGS and NMGC may not be able to maintain reliability in their service areas; or

• Tampa Electric’s, PGS’s and NMGC’s ability to provide electric or gas service to new customers may be negatively impacted.

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Impairment testing of certain long-lived assets could result in impairment charges

TECO Energy assesses long-lived assets and goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of those assets below their carrying values. To the extent the value of goodwill or a long-lived asset becomes impaired, TECO Energy may be required to record non-cash impairment charges that could have a material adverse impact on TECO Energy’s financial condition and results from operations. In connection with the NMGC acquisition, TECO Energy recorded additional goodwill and long-lived assets that could become impaired.

TECO Energy has substantial indebtedness, which could adversely affect its financial condition and financial flexibility

TECO Energy has substantial indebtedness, which has resulted in fixed charges it is obligated to pay. The level of TECO Energy’s indebtedness and restrictive covenants contained in its debt obligations could limit its ability to obtain additional financing.

TECO Energy, TECO Finance, TEC, NMGC and NMGI must meet certain financial covenants as defined in the applicable agreements to borrow under their respective credit facilities. Also, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments.

Although TECO Energy was in compliance with all required financial covenants as of March 31, 2016, it cannot assure compliance with these financial covenants in the future. TECO Energy’s failure to comply with any of these covenants or to meet its payment obligations could result in an event of default which, if not cured or waived, could result in the acceleration of other outstanding debt obligations. TECO Energy may not have sufficient working capital or liquidity to satisfy its debt obligations in the event of an acceleration of all or a portion of its outstanding obligations. If TECO Energy’s cash flows and capital resources are insufficient to fund its debt service obligations, it may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance its indebtedness. TECO Energy’s ability to restructure or refinance its debt will depend on the condition of the capital markets and TECO Energy’s financial condition at such time. Any refinancing of TECO Energy’s debt could be at higher interest rates and may require TECO Energy to comply with more onerous covenants, which could further restrict TECO Energy’s business operations. The terms of existing or future debt instruments may restrict TECO Energy from adopting some of these alternatives.

TECO Energy also incurs obligations in connection with the operations of its subsidiaries and affiliates that do not appear on its balance sheet. Such obligations include guarantees, letters of credit and certain other types of contractual commitments.

Financial market conditions could limit TECO Energy’s access to capital and increase TECO Energy’s costs of borrowing or refinancing, or have other adverse effects on its results

TECO Finance and TEC have debt maturing in 2016 and subsequent years which may need to be refinanced. Future financial market conditions could limit TECO Energy’s ability to raise the capital it needs and could increase its interest costs, which could reduce earnings. If TECO Energy is not able to issue new debt, or TECO Energy issues debt at interest rates higher than expected, its financial results or condition could be adversely affected.

TECO Energy enters into derivative transactions, primarily with financial institutions as counterparties. Financial market turmoil could lead to a sudden decline in credit quality among these counterparties, which could make in-the-money positions uncollectable

TECO Energy enters into derivative transactions with counterparties, most of which are financial institutions, to hedge its exposure to commodity price and interest rate changes. Although TECO Energy believes it has appropriate credit policies in place to manage the non-performance risk associated with these transactions,

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turmoil in the financial markets could lead to a sudden decline in credit quality among these counterparties. If such a decline occurs for a counterparty with which TECO Energy has an in-the-money position, TECO Energy could be unable to collect from such counterparty.

Declines in the financial markets or in interest rates used to determine benefit obligations could increase TECO Energy’s pension expense or the required cash contributions to maintain required levels of funding for its plan

Under calculation requirements of the Pension Protection Act of 2006, as amended, as of the January 1, 2015 measurement date, TECO Energy’s pension plan was essentially fully funded. Under MAP 21, TECO Energy is not required to make additional cash contributions over the next five years; however TECO Energy may make additional cash contributions from time to time. Any future declines in the financial markets or further declines in interest rates could increase the amount of contributions required to fund its pension plan in the future, and could cause pension expense to increase.

TECO Energy’s financial condition and results could be adversely affected if its capital expenditures are greater than forecast

In 2016, TECO Energy is forecasting capital expenditures at Tampa Electric to support the current levels of customer growth, to comply with the design changes mandated by the FPSC to harden transmission and distribution facilities against hurricane damage, to maintain transmission and distribution system reliability, to maintain coal-fired generating unit reliability and efficiency, and to add generating capacity at the Polk Power Station. TECO Energy is forecasting capital expenditures at PGS to support customer growth, system reliability, conversion of customers from other fuels to natural gas and to replace bare steel and cast iron pipe. Forecasted capital expenditures at NMGC are expected to support customer and system reliability and expansion.

If TECO Energy’s capital expenditures exceed the forecasted levels, it may need to draw on credit facilities or access the capital markets on unfavorable terms. TECO Energy cannot be sure that it will be able to obtain additional financing, in which case its financial position could be adversely affected.

TECO Energy’s financial condition and ability to access capital may be materially adversely affected by ratings downgrades to below investment grade and TECO Energy cannot be assured of any rating improvements in the future

A downgrade to below investment grade by any rating agencies may affect TECO Energy’s ability to borrow, may change requirements for future collateral or margin postings, and would increase financing costs, which may decrease earnings. TECO Energy may also experience greater interest expense than it may have otherwise if, in future periods, it replaces maturing debt with new debt bearing higher interest rates due to any downgrades. In addition, downgrades could adversely affect TECO Energy’s relationships with customers and counterparties.

If the ratings of TEC or NMGC decline to below investment grade, Tampa Electric, PGS or NMGC, as applicable, could be required to post collateral to support their purchases of electricity and gas.

In connection with the sale of TECO Coal to Cambrian, TECO Energy temporarily retained obligations under letters of indemnity that guarantee payments on bonds posted for the reclamation of mines prior to the completion of the transfer of all permits to the purchaser by the Commonwealths of Kentucky and Virginia

These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal’s mining operations. Payments by TECO Energy to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder or TECO Coal or one of the affiliates transferred to Cambrian Coal Corp (“Cambrian”) as part of the sale did not pay the surety company. Pursuant to the Securities Purchase Agreement

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(the “TECO Coal SPA”) for the sale of TECO Coal LLC (“TECO Coal”) to Cambrian, Cambrian is obligated to file applications required in connection with the change of ownership and control of TECO Coal and its affiliates with the appropriate governmental entities with respect to the coal mining permits. Pursuant to the terms of the TECO Coal SPA, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond(s) secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy’s indemnity are released, TECO Energy’s indemnity will remain effective. TECO Energy is working with Cambrian on the process of replacing the bonds and expects the process to be completed in 2016.

Risks Related to the Notes

Rights only as an Equity Holder in the Event of Insolvency

In the event of the occurrence of the Automatic Conversion, with the result that the holder of a series of Notes receives Conversion Preferred Shares on conversion of such series of Notes, the only claim or entitlement of such holder will be in its capacity as a shareholder of Emera. See “Description of Notes—Automatic Conversion” and “Risks Related in an Investment in Conversion Preferred Shares—Insolvency or Winding-Up”.

Liquidity of and Dealings in Notes

It is not expected that the Notes will be listed on any stock exchange. This may affect the pricing of the Notes in the secondary market, the transparency and availability of trading prices, and the liquidity of the Notes. There can be no assurance that an active trading market will develop or be sustained or that the Notes may be resold at or above the initial public offering price. The ability of a holder to pledge Notes or otherwise take action with respect to such holder’s interest in Notes (other than through a Participant) may be limited due to the lack of a physical certificate.

Subordination

Emera’s obligations under the Notes will be subordinated in right of payment to all of Emera’s current and future Senior Indebtedness. This means that Emera will not be permitted to make any payments on the Notes if it defaults on a payment of principal of, premium, if any, or interest on any such Senior Indebtedness or there shall occur an event of default under such Senior Indebtedness and it does not cure the default within the applicable grace period, if the holders of the Senior Indebtedness have the right to accelerate the maturity of such indebtedness or if the terms of such Senior Indebtedness otherwise restrict Emera from making payments to junior creditors. Emera’s guarantee of the Senior Guaranteed Notes to be issued by Emera US Finance and any Senior Notes to be issued by Emera in each case as part of the Acquisition Capital Markets Transactions, will constitute Senior Indebtedness of Emera. See “Description of the Notes—Subordination”.

In addition to the contractual subordination described above, the payment of principal of, premium, if any, and interest on the Notes will be structurally subordinated to any indebtedness and other liabilities of Emera’s subsidiaries.

Emera’s Senior Indebtedness as of March 31, 2016 was approximately Cdn$751 million. As of March 31, 2016, Emera’s subsidiaries had approximately Cdn$2,247 million of outstanding indebtedness that will effectively rank senior to the Notes.

Furthermore, in the event of an insolvency or liquidation of Emera, the claims of creditors of Emera would be entitled to a priority payment over the claims of holders of equity interests of Emera, such as the Conversion Preferred Shares. See “Risks Related to the Notes—Rights only as an Equity Holder in the Event of Insolvency” and “Risks Related to an Investment in Conversion Preferred Shares—Insolvency or Winding-up”.

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No Limit on Debt

The Trust Indenture does not contain any provision limiting Emera’s ability to incur indebtedness generally. Any such indebtedness could rank in priority to the Notes. Emera currently has substantial indebtedness and may incur substantial additional indebtedness in the future.

Early Redemption

Emera may redeem the Notes in the circumstances described in this Prospectus or any Prospectus Supplement relating to the applicable series of Notes. This redemption right may, depending on prevailing market conditions at the time, create reinvestment risk for holders of the Notes in that they may be unable to find a suitable replacement investment with a comparable return to the Notes.

Deferral Right

Unless Emera has paid all accrued and payable interest on the Notes, subject to certain exceptions, Emera may elect, at its sole option, to defer the interest payable on any series of Notes on one or more occasions for up to five consecutive years as described under “Description of the Notes—Deferral Rights”. There is no limit on the number of Deferral Events that may occur. Such deferral will not constitute an event of default or any other breach under the Notes and the Trust Indenture.

Interest in Respect of Deferral Events

During any deferral period, the Notes will be treated as issued with OID at the time of such deferral and all stated interest due after such deferral will be treated as OID. Consequently, a U.S. holder of Notes would be required to include OID in its gross income in the manner described under the heading “Certain U.S. Federal Income Tax Considerations” even though Emera would not make any actual cash payments to holders of Notes during a deferral period.

Investors in the Notes located outside of Canada may have difficulties enforcing civil liabilities

Emera is incorporated under the laws of Nova Scotia. Moreover, substantially all of Emera’s directors, controlling persons and officers, as well as certain of the experts named in this Prospectus, are residents of Canada or other jurisdictions outside of the United States, and all or a substantial portion of their assets and a substantial portion of Emera’s assets are located outside of the United States. Emera will agree, in accordance with the terms of the Trust Indenture, to accept service of process in any suit, action or proceeding with respect to the Trust Indenture or the Notes brought in any federal or state court located in New York City by an agent designated for such purpose, and to submit to the jurisdiction of such courts in connection with such suits, actions or proceedings. Nevertheless, it may be difficult for holders of the Notes to effect service of process within the United States upon directors, officers and experts who are not residents of the United States or to realize in the United States upon judgments of courts of the United States predicated upon civil liability under U.S. federal or state securities laws or other laws of the United States. In addition, there is doubt as to the enforceability in Canada against Emera or against Emera’s directors, officers and experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of courts of the United States, of liabilities predicated solely upon U.S. federal or state securities laws.

An increase in interest rates could result in a decrease in the relative value of the Notes

In general, as market interest rates rise, notes bearing interest at a fixed rate generally decline in value because the premium, if any, over market interest rates will decline. Consequently, if you purchase Notes and market interest rates increase, the market value of your Notes may decline. We cannot predict future levels of market interest rates.

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Emera is a holding company

Emera is a holding company and depends on dividends and other distributions from its subsidiaries. Emera conducts substantially all its operations through subsidiaries, and those subsidiaries generate substantially all of its operating income and cash flow. As a result, distributions or advances from those subsidiaries are the principal source of funds necessary to meet the debt service obligations of Emera. Contractual provisions or laws, as well as the subsidiaries’ financial condition and operating requirements, may limit the ability of Emera to obtain cash from its subsidiaries that it requires to pay its debt service obligations, including any payments required to be made under the Notes.

The tax treatment of the Notes for U.S. federal income tax purposes is uncertain

The treatment of the Notes for U.S. federal income tax purposes is uncertain. The determination of whether an obligation represents a debt or equity interest is based on all the relevant facts and circumstances at the time the obligation is issued. There is no direct legal authority as to the proper U.S. federal income tax treatment of an instrument such as the Notes that is denominated as a debt instrument and has certain significant debt features, but that provides for a possible Automatic Conversion under which an investor could lose its creditor rights upon the occurrence of an Automatic Conversion Event. In the absence of authority addressing the proper characterization of instruments such as the Notes, to the extent required to do so, we intend to treat the Notes as debt for U.S. federal income tax purposes. However, we will not request any ruling from the U.S. Internal Revenue Service, or the IRS, regarding the treatment of the Notes for U.S. federal income tax purposes and the IRS or a court may conclude that the Notes should be treated as equity for U.S. federal income tax purposes.

If the Notes were treated as equity for U.S. federal income tax purposes and we were a “passive foreign investment company,” or PFIC, for any taxable year during which a U.S. investor held the Notes, the U.S. investor could be subject to adverse tax consequences, including increased tax liability on certain gains and payments on the Notes and a requirement to file annual reports with the IRS. We believe that we were not a PFIC for our 2015 taxable year and do not expect to be a PFIC for our 2016 taxable year. However, because the composition of our income and assets will vary over time, and because there are uncertainties in the characterization of certain of our income and assets for PFIC purposes, there can be no assurance that we will not be a PFIC for any taxable year.

Prospective investors should consult their tax advisers as to the proper characterization of the Notes for U.S. federal income tax purposes and the consequences of holding a Note if we are or become a PFIC. See “Certain U.S. Federal Income Tax Considerations.”

If interest payments on the Notes were deferred, U.S. investors would be required to recognize income for U.S. federal income tax purposes in advance of the receipt of cash attributable to such income

In the event we exercise our option to defer payments of interest, the Notes would be treated as retired and reissued for U.S. federal income tax purposes and U.S. investors would be required to treat all stated interest on the deemed reissued Notes as original issue discount, or OID. Consequently, during any period of interest deferral, and any period thereafter, U.S. investors will include all stated interest in gross income as it accrues using a constant yield method before the receipt of cash. See “Certain U.S. Federal Income Tax Considerations.”

Risks Related to an Investment in Conversion Preferred Shares

Dividends

Holders of Conversion Preferred Shares do not have a right to dividends on such shares unless declared by the Board of Directors. The declaration of dividends is in the discretion of the Board of Directors even if Emera has sufficient funds, net of its liabilities, to pay such dividends. Emera may not declare or pay a dividend if there are reasonable grounds for believing that (i) Emera is, or would after the payment be, unable to pay its liabilities as

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they become due, or (ii) the realizable value of Emera’s assets would thereby be less than the aggregate of its liabilities and stated capital of its outstanding shares. Liabilities of Emera will include those arising in the course of its business, indebtedness, including inter-company debt, and amounts, if any, that are owing by Emera under guarantees in respect of which a demand for payment has been made. In addition, a dividend (including a deemed dividend) received on a series of Conversion Preferred Shares may be subject to Canadian non-resident withholding tax and, if any such dividends are so subject, no additional amounts will be payable to holders of such series of Conversion Preferred Shares in respect of such withholding tax. See “Certain Canadian Federal Income Tax Considerations—Conversion Preferred Share—Dividends”.

Insolvency or Winding-Up

The Conversion Preferred Shares do not constitute indebtedness and are equity capital of Emera which rank junior to all indebtedness and other non-equity claims and equally with the other outstanding series of Emera’s First Preferred Shares in the event of an insolvency or winding-up of Emera. If Emera becomes insolvent or is wound up, Emera’s assets must be used to pay liabilities and other debt before payments may be made on the Conversion Preferred Shares and other First Preferred Shares, if any.

No Fixed Maturity

The Conversion Preferred Shares do not have a fixed maturity date and are not redeemable at the option of the holders of the Conversion Preferred Shares. The ability of a holder to liquidate its holdings of Conversion Preferred Shares may be limited.

Voting Rights

Holders of Conversion Preferred Shares will not have any voting rights except in the event of the non-payment of eight quarterly dividends, subject to certain constraints, as described under “Description of Conversion Preferred Shares—Voting Rights”, and “Description of Conversion Preferred Shares—Consideration Shares Ownership,” or otherwise required by law.

Secondary Market and Liquidity

There can be no assurance that an active trading market will develop for the Conversion Preferred Shares following the issuance of any of those shares, or if developed, that such a market will be liquid or sustained at the issue price of such shares. Emera is under no obligation to list the Conversion Preferred Shares on any stock exchange or other market. The ability of a holder to pledge Conversion Preferred Shares or otherwise take action with respect to such holder’s interest therein (other than through a Participant) may be limited due to the lack of a physical certificate.

Market Value

The market value of the Conversion Preferred Shares may fluctuate due to a variety of factors relative to Emera’s business, including announcements of new developments, fluctuations in Emera’s operating results, sales of Emera Preferred Shares, failure to meet analysts’ expectations, the impact of various tax laws or rates and general market conditions or the worldwide economy. There can be no assurance that the market value of the Conversion Preferred Shares will not experience significant fluctuations in the future, including fluctuations that are unrelated to Emera’s performance. Prevailing yields on similar securities will affect the market value of the Conversion Preferred Shares. Assuming all other factors remain unchanged, the market value of the Conversion Preferred Shares would be expected to decline as prevailing yields for similar securities rise and would be expected to increase as prevailing yields for similar securities decline. Spreads over LIBOR and comparable benchmark rates of interest for similar securities will also affect the market value of the Conversion Preferred

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Shares in an analogous manner. In addition, the market value of the Conversion Preferred Shares will be significantly adversely affected in the event that dividends are not paid on such shares. See “Risks Related to an Investment in Conversion Preferred Shares—Dividends”.

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USE OF PROCEEDS

The net proceeds of any offering of Notes will be used as set forth in the applicable Prospectus Supplement. Such uses may include, financing, directly or indirectly, part of the purchase price payable for the Acquisition (including, Acquisition-Related Expenses) and to reduce any amounts outstanding under the Acquisition Credit Facilities, to the extent any amounts are drawn on such facilities in connection with the Acquisition.

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CAPITALIZATION

The following table sets out Emera’s cash and cash equivalents and consolidated capitalization as at March 31, 2016 and on an as adjusted basis, as at such date after giving effect to (i) the Acquisition Capital Markets Transactions, (ii) the issuance of Common Shares upon conversion of the Convertible Debentures on the Final Instalment Date (assuming payment in full of the Final Instalment of the Convertible Debentures), and (iii) consummation of the Acquisition. See “Unaudited Pro Forma Consolidated Financial Statements” and “Summary—Financing the Acquisition” herein and the unaudited condensed consolidated interim financial statements of each of Emera and TECO Energy as at and for the three months ended March 31, 2016, which are incorporated by reference herein.

	As at March 31, 2016 (unaudited)		As adjusted as at March 31, 2016 (unaudited)
	millions of Canadian dollars
Cash and cash equivalents	$	999.5		323.2
Indebtedness:
Current portion of long-term debt(1)(2)		272.6		380.6
Short-term debt(2)		10.2		675.6
Other Long-term debt(2)		3,714.2		8,180.1
Convertible Debentures(3)		681.8		—
Acquisition Capital Markets Transactions(4)		—		6,575.6
Total debt (net of cash)		3,679.3		15,488.7
Shareholders’ equity:
Common Shares(3)		2,199.0		4,321.8
First Preferred Shares		709.5		709.5
Additional contributed surplus		35.3		35.3
Accumulated other comprehensive income		5.8		5.8
Retained earnings(5)		1,142.1		996.0
Total shareholders’ equity		4,091.7		6,068.3
Total capitalization(6)		7,771		21,557.0

(1) Current portion of long-term debt includes Cdn$250 million of the Emera 2.96% senior unsecured notes due 2016. See “Description of Other Indebtedness—Emera MTN notes.”

(2) Other Long-term debt, Current portion of long-term debt and Short-term debt as adjusted at March 31, 2016 give effect to consummation of the Acquisition and assumption by Emera of Cdn$5,356 million of TECO Energy, of which Cdn$4,583.5 million is classified “long-term debt,” Cdn$108 million is classified “current portion of long-term debt” and Cdn$665 is classified “short-term debt”, but does include any indebtedness represented by the Acquisition Capital Markets Transactions, including any series of Notes offered hereunder.

(3) Convertible Debentures as at March 31, 2016 reflects the first instalment of the Convertible Debentures. Convertible Debentures and Common Shares as adjusted at March 31, 2016 gives effect to the issuance of the Common Shares upon conversion of the Convertible Debentures on the Final Instalment Date (assuming payment in full of the remaining Cdn$1,457 million in the Final Instalment of the Convertible Debentures). See “Management’s Discussion and Analysis—Convertible Debentures Represented by Instalment Receipts” and “Description of Other Indebtedness—Convertible Debenture Offering”.

(4) Emera intends to raise up to Cdn$6.6 billion in aggregate principal amount in the Acquisition Capital Markets Transactions. Acquisition Capital Markets Transactions as adjusted at March 31, 2016 assumes consummation of the Acquisition Capital Markets Transactions. The aggregate principal amounts raised by each of the other Acquisition Capital Markets Transactions are dependent on market and other conditions, and may vary. To the extent Emera raises less than Cdn$6.6 billion in connection with the Acquisition Capital Markets Transactions, Emera intends to pay any shortfall by drawing on the Acquisition Credit Facilities and/or using existing cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) or other sources available to Emera in order to consummate the Acquisition. See “Description of Other Indebtedness—Acquisition Credit Facilities.”

(5) Retained Earnings as adjusted at March 31, 2016 gives effect to the consummation of the Acquisition and reflects, among other things (i) Cdn$28 million of interest costs on the Convertible Debentures, and (ii) estimated Acquisition Related Expenses of Cdn$117 million.

(6) Excludes non-controlling interests.

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UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The following unaudited pro forma consolidated financial information is presented to illustrate the estimated effects of (i) the Acquisition Capital Markets Transactions, (ii) the issuance of Common Shares upon conversion of the Convertible Debentures on the Final Instalment Date (assuming payment in full of the Final Instalment of the Convertible Debentures) and (iii) the consummation of the Acquisition. For additional information see “—Notes to the Unaudited Pro Forma Consolidated Financial Statements—Note 2: Description of Transactions.” The unaudited pro forma consolidated balance sheet gives effect to the Acquisition Capital Markets Transactions, the issuance of the Common Shares (as described above) and the Acquisition as if they closed on March 31, 2016. The unaudited pro forma consolidated statements of earnings for the year ended December 31, 2015 and the three months ended March 31, 2016 give effect to the Acquisition and the Acquisition Capital Markets Transactions as if they had closed on January 1, 2015.

The unaudited pro forma consolidated financial statements are presented for illustrative purposes only. The pro forma adjustments are based upon available information and certain assumptions that we believe are reasonable in the circumstances, as described in the notes to the unaudited pro forma consolidated financial statements.

The unaudited pro forma consolidated financial statements are based on TECO Energy’s consolidated financial statements as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015. For more information regarding the foreign exchange translation from U.S. Dollars to Canadian Dollars for TECO Energy’s financial statements see “—Notes to the Unaudited Pro Forma Consolidated Financial Statements—Note 3(j): Foreign Exchange Translations.” TECO Coal was sold in 2015 and as a result, the operating results of the TECO Coal segment are reported as discontinued operations.

The pro forma information presented, including allocation of purchase price, is based on preliminary estimates of fair values of assets acquired and liabilities assumed, available information and assumptions and may be revised as additional information becomes available. The actual adjustments to the consolidated financial statements upon the closing of the Acquisition will depend on a number of factors, including additional information available and the net assets of TECO Energy on the closing date of the Acquisition. Therefore, the actual adjustments will differ from the pro forma adjustments, and the differences may be material. For example, the final purchase price allocation is dependent on, among other things, the finalization of asset and liability valuations. A final determination of these fair values will reflect an independent third-party valuation. This final valuation will be based on the actual net tangible and intangible assets and liabilities of TECO Energy that exist as of the closing date of the Acquisition. Any final adjustment may change the allocation of purchase price, which could affect the fair value assigned to the assets and liabilities and could result in a change to the unaudited pro forma consolidated financial statements, including a change to goodwill.

The unaudited pro forma consolidated financial statements should be read in conjunction with the information contained in “Caution Regarding Unaudited Pro Forma Consolidated Financial Statements,” “Summary—The Acquisition,” “Summary—Financing the Acquisition,” “Summary—Summary Historical and Pro Forma Financial Data,” “Management’s Discussion and Analysis” and the audited and unaudited consolidated financial statements and the related notes incorporated by reference in this Prospectus. All pro forma adjustments and their underlying assumptions are described more fully in “—Notes to the Unaudited Pro Forma Consolidated Financial Statements.”

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UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF EARNINGS

FOR THE YEAR ENDED DECEMBER 31, 2015

	Emera		TECO Energy			Note		Pro Forma Adjustments			Pro Forma Consolidated Statement of Earnings
	millions of Canadian dollars, except for per share amounts
Operating Revenues
Regulated		2,193		3,493								5,686
Non-regulated		596		15								611
Total Operating Revenues		2,789		3,508					—			6,298
Operating Expenses
Regulated fuel for generation and purchased power(1)		815		2,049								2,863
Regulated fuel adjustment mechanism and fixed cost deferrals		42										42
Non-regulated fuel for generation and purchased power		336										336
Non-regulated direct costs		20										20
Operating, maintenance and general		667		29			3(i)		(13	)
							3(i)		(22	)		661
Provincial, state and municipal taxes		64		265								329
Depreciation and amortization		340		446								786
Total Operating Expenses		2,282		2,790					(35	)		5,036
Income from operations		508		719					35			1,261
Income from equity investments		109										109
Other income (expenses)		141		27			3(i)		(119	)		49
Interest expense, net		213		238			3(i)		(40	)
							3(i)		(23	)
							3(d)		284
							3(e)		12			684
Income before provision for income taxes		545		507					(317	)		735
Income tax expense (recovery)		92		199			3(i)		23
							3(i)		(18	)
							3(i)		5
							3(d)		(103	)		197
Net income from continuing operations		452		308					(223	)		538
Discontinued Operations
Income (loss) from discontinued operations				(136	)							(136	)
Provision (benefit) for income taxes				(49	)							(49	)
Income (loss) from discontinued operations, net				(87	)							(87	)
Non-controlling interest in subsidiaries		25										25
Net income of Emera Incorporated		428		222					(223	)		426
Preferred stock dividends		30										30
Net income attributable to common shareholders		397		222					(223	)		396
Adjusted Net income attributable to common shareholders(2)		330		222					(223	)		329
Weighted average shares of common stock outstanding (in millions)
Basic		145.80					3(h)		52.21			198.01
Diluted		146.40					3(h)		52.21			198.61
Earnings per common share
Basic		2.72										2.00
Diluted		2.71										1.99

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	Emera		TECO Energy	Note	Pro Forma Adjustments	Pro Forma Consolidated Statement of Earnings
	millions of Canadian dollars, except for per share amounts
Adjusted Net Income per common share(2)
Basic		2.26					1.66
Diluted		2.25					1.65
Earnings per common share excluding discontinued operations
Basic		2.72					2.44
Diluted		2.71					2.43
Dividends per common share declared		1.66

(1) The TECO Energy statement of earnings includes maintenance costs in regulated fuel for generation and purchased power and the cost of gas sold by the regulated gas distribution companies.

(2) Adjusted Net Income attributable to common shareholders and Adjusted Net Income per common share are non-U.S. GAAP measures, adjusting for the earnings effect of Emera’s mark-to-market adjustments. Non-U.S. GAAP measures are not recognized measures under U.S. GAAP and do not have a standardized meaning prescribed by U.S. GAAP. See “Presentation of Financial Information.”

See accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements.

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UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF EARNINGS

FOR THE QUARTER END MARCH 31, 2016

	Emera			TECO Energy		Note		Pro Forma Adjustments			Pro Forma Consolidated Statement of Earnings
	millions of Canadian dollars (except for per share amounts)
Operating Revenues
Regulated		587			902							1,489
Non-regulated		290			4							295
Total Operating Revenues		877			907							1,784
Operating Expenses
Regulated fuel for generation and purchased power(1)		198			507							705
Regulated fuel adjustment mechanism and fixed cost deferrals		18										18
Non-regulated fuel for generation and purchased power		110										110
Non-regulated direct costs		2										2
Operating, maintenance and general		176							(0	)		175
Provincial, state and municipal taxes		16			73							89
Depreciation and amortization		88			123							211
Total Operating Expenses		607			703				(0	)		1,310
Income from operations		270			204				0			474
Other income (expenses)		(113	)		10		3(i)		140			36
Interest expense, net		75			63		3(i)		(4	)
							3(i)		(22	)
							3(i)		1
							3(d)		76
							3(d)		3			192
Income before provision for income taxes		82			150				86			318
Income tax expense (recovery)		27			49		3(i)		8
							3(i)		18
							3(d)		(28	)		75
Net income from continuing operations		55			101				87			243
Discontinued Operations
Income (loss) from discontinued operations					0							0
Provision (benefit) for income taxes					0							0
Income (loss) from discontinued operations, net					0							0
Non-controlling interest in subsidiaries		4										4
Net income of Emera Incorporated		51			101				87			240
Preferred stock dividends		7										7
Net income attributable to common shareholders		44			101				87			233
Adjusted Net income attributable to common shareholders(2)		120			101				87			309
Weighted average shares of common stock outstanding (in millions)
Basic		148.70					3(h)		52.21			200.91
Diluted		149.30					3(h)		52.21			201.51

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	Emera		TECO Energy	Note	Pro Forma Adjustments	Pro Forma Consolidated Statement of Earnings
	millions of Canadian dollars (except for per share amounts)
Earnings per common share
Basic		0.30					1.16
Diluted		0.30					1.16
Adjusted Net Income per common share(2)
Basic		0.81					1.54
Diluted		0.81					1.53
Earnings per common share excluding discontinued operations
Basic		0.30					1.16
Diluted		0.30					1.16
Dividends per common share declared		0.48

See accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements.

(1) The TECO Energy statement of earnings includes maintenance costs in regulated fuel for generation and purchased power and the cost of gas sold by the regulated gas distribution companies.

(2) Adjusted Net Income attributable to common shareholders and Adjusted Net Income per common share are non-U.S. GAAP measures, adjusting for the earnings effect of Emera’s mark-to-market adjustments. Non-U.S. GAAP measures are not recognized measures under U.S. GAAP and do not have a standardized meaning prescribed by U.S. GAAP. See “Presentation of Financial Information.”

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UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

AS AT MARCH 31, 2016

	Emera		TECO Energy		Note		Pro Forma Adjustments			Pro Forma Consolidated Balance Sheet
	millions of Canadian dollars
ASSETS
Current assets
Cash and cash equivalents		1,000		60		3(b)		(8,423	)
						3(c)		1,457
						3(c)		(44	)
						3(c)		(42	)
						3(d)		6,576
						3(d)		(118	)
						3(e)		(141	)		323
Restricted cash		22									22
Receivables, net		610		311							922
Income taxes receivable		16									16
Inventory		261		253							514
Derivative instruments		92									92
Regulatory assets		78		52							130
Prepaid expenses		40		33							73
Due from related parties		2									2
Other current assets		168									168
Total current assets		2,289		709				(736	)		2,263
Property, plant and equipment, net of accumulated depreciation		6,015		9,797							15,812
Other assets
Income taxes receivable		48									48
Deferred income taxes		47				3(c)		28
						3(c)		14
						3(e)		24			113
Derivative instruments		85									85
Pension and post-retirement asset		9									9
Regulatory assets		619		510							1,129
Net investment in direct financing lease		479									479
Investments subject to significant influence		1,210									1,210
Available-for-sale investments		106									106
Goodwill		248		530		3(b)		(530	)
						3(b)		5,660			5,908
Intangibles, net of accumulated amortization		191									191
Due from related parties		3									3
Other long-term assets		100		103							203
Total other assets		3,144		1,143				5,196			9,483
		11,449		11,649				4,460			27,558

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	Emera		TECO Energy			Note		Pro Forma Adjustments			Pro Forma Consolidated Balance Sheet
	millions of Canadian dollars
LIABILITIES AND SHAREHOLDERS EQUITY
Current liabilities
Short-term debt		10		665								676
Current portion of long-term debt		273		108								381
Accounts payable		372		475								846
Income taxes payable		9		37								45
Convertible Debentures represented by instalment receipts		682					3(c)		(682	)
Derivative instruments		148		29								177
Regulatory liabilities		75		141								216
Pension and post-retirement liabilities		7		27								34
Due to related party		2										2
Other current liabilities		183		75								258
Total current liabilities		1,760		1,557					(682	)		2,635
Long-term liabilities
Long-term debt		3,714		4,526			3(d)		6,458
							3(b)		57			14,756
Deferred income taxes		794		787								1,581
Derivative instruments		79		1								80
Regulatory liabilities		221		920								1,141
Asset retirement obligations		116										116
Pension and post-retirement liabilities		296		360								656
Other long-term liabilities		272		147								420
Total long-term liabilities		5,492		6,743					6,515			18,750
Shareholder’s Equity
Common stock		2,199		305			3(g)		(305	)
							3(c)		2,185
							3(c)		(62	)		4,322
Cumulative preferred stock		710										710
Contributed surplus		35		2,458			3(g)		(2,458	)		35
Accumulated other comprehensive loss		6		(15	)		3(g)		15			6
Retained earnings		1,142		601			3(g)		(601	)
							3(e)		(141	)
							3(e)		24
							3(c)		(42	)
							3(c)		14			996
Total Emera Incorporated equity		4,092		3,350					(1,373	)		6,068
Non-controlling interest in subsidiaries		105										105
Total equity		4,197		3,350					(1,373	)		6,173
Total liabilities and equity		11,449		11,649					4,460			27,558

See accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements.

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Notes to Unaudited Pro Forma Consolidated Financial Statements

As at and for the three months ended March 31, 2016 and for the year ended December 31, 2015

(in millions of Canadian dollars, unless otherwise stated)

1. BASIS OF PRESENTATION

The accompanying unaudited pro forma consolidated financial information is presented to illustrate the estimated effects of (i) the Acquisition Capital Markets Transactions, (ii) the issuance of Common Shares upon conversion of the Convertible Debentures (assuming payment in full of the Final Instalment of the Convertible Debentures) and (iii) the consummation of the Acquisition. The accompanying unaudited pro forma consolidated financial statements have been prepared by management of Emera and are derived from the unaudited and audited consolidated financial statements of Emera as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015, respectively, and the unaudited and audited consolidated financial statements of TECO Energy (refer to footnote 3(j) below for further consideration of the foreign exchange translation) as at and for the three months ended March 31, 2016 and for the year ended December 31, 2015, respectively.

The accompanying unaudited pro forma consolidated financial statements utilize accounting policies that are consistent with those disclosed in Emera’s and TECO Energy’s audited consolidated financial statements and were prepared in accordance with U.S. accounting principles.

The Acquisition has been accounted for using the acquisition method. The purchase price is primarily based upon the regulated assets and liabilities at the date of closing. Based on the purchase price calculation as detailed in the Acquisition Agreement, the estimated net purchase price for the equity of TECO Energy is approximately Cdn$8.6 billion. See “—Note 3(b): Allocation of the Estimate Net Purchase Price.”

The accompanying unaudited pro forma consolidated balance sheet and unaudited pro forma consolidated statements of earnings reflect the Acquisition as if it had closed on March 31, 2016 and January 1, 2015, respectively. The accompanying unaudited pro forma consolidated financial statements may not be indicative of the results that would have been achieved if the transactions reflected therein had been completed on the dates indicated or the results which may be obtained in the future. For instance, the actual purchase price allocation will reflect the fair value, at the purchase date, of the assets acquired and liabilities assumed based upon Emera’s estimation of such assets and liabilities following the closing of the Acquisition and, accordingly, the final purchase price allocation, as it relates principally to goodwill, may differ materially from the preliminary allocation reflected herein. Also, the actual blended interest rate payable on the indebtedness issued in the Acquisition Capital Markets Transactions (and, if necessary, incurred under the Acquisition Credit Facilities) may differ materially from the estimated blended interest rate reflected herein.

The accompanying unaudited pro forma consolidated financial statements should be read in conjunction with the description of the Acquisition and the proposed financing thereof provided elsewhere in this Prospectus; the audited and unaudited consolidated financial statements of TECO Energy, including the notes thereto, incorporated by reference in this Prospectus, and the audited and unaudited consolidated financial statements of Emera, including the notes thereto, incorporated by reference in the Prospectus.

The underlying assumptions for the pro forma adjustments provide a reasonable basis for presenting the significant financial effect directly attributable to the Acquisition. In addition, the unaudited pro forma consolidated financial statements do not reflect any of the synergies or cost reductions that may result from the Acquisition and do not include any restructuring costs or other one-time charges that may be incurred. These pro forma adjustments are based on currently available financial information and certain estimates and assumptions. The actual adjustments to the consolidated financial statements will depend on a number of factors. Therefore, it is expected that the actual adjustments will differ from the pro forma adjustments, and the differences may be material.

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2. DESCRIPTION OF TRANSACTIONS

Pursuant to the Acquisition Agreement among Emera, Emera US Inc., a direct wholly-owned subsidiary of Emera US Holdings Inc. and TECO Energy, Emera will indirectly purchase all of the outstanding common shares of TECO Energy for US$27.55 per share. The estimated net purchase price, including (i) payment for unexercised stock options and performance shares and restricted stock units with the applicable number of shares included in the share count used in the purchase price calculation; and (ii) estimated acquisition costs of Cdn$130 million after tax, will be approximately Cdn$8.6 billion. Emera will also assume TECO Energy’s consolidated debt, which was approximately as adjusted Cdn$5.4 billion as at March 31, 2016 as described herein.

Emera has arranged two committed debt bridge facilities: (i) a US$4.3 billion bridge facility repayable in full on the first anniversary following its advance, and (ii) a US$2.2 billion bridge facility repayable in full on the first anniversary following its advance, which, together with existing cash and other sources available to Emera, an existing Revolving Facility, the Convertible Debentures and Acquisition Capital Markets Transactions, will fully fund the net purchase price and thereby ensure sufficient liquidity to close the Acquisition.

The accompanying unaudited pro forma consolidated financial statements assume that at closing, the Acquisition will be financed through the net proceeds from the Acquisition Capital Markets Transactions, the Convertible Debentures and cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering). The first instalment of Cdn$728 million relating to the Convertible Debenture offering was paid on closing of the Convertible Debenture offering in 2015 and is reflected in Emera’s financial statements as a liability. To the extent (i) Emera raises less than Cdn$6.6 billion in connection with the Acquisition Capital Markets Transactions, or (ii) Emera does not receive payment in full of the Final Instalment of the Convertible Debentures, Emera intends to pay any shortfall by drawing on the Acquisition Credit Facilities and/or using existing cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) or other sources available to Emera in order to consummate the Acquisition.

The accompanying unaudited pro forma consolidated financial statements: (i) reflect the Acquisition Capital Markets Transactions and applicable issuance and financing costs (see “—Note 3(d): Acquisition Capital Markets Transactions”), and (ii) assume that all cash for the Convertible Debentures has been received and immediately converted into Common Shares at the assumed closing date of the Acquisition (see “—Note 3(c): Common Share Issuance”). Therefore, the accompanying unaudited pro forma consolidated statements of earnings do not recognize any additional interest costs associated with the Convertible Debentures. Interest on the Convertible Debentures is expected to be Cdn$87 million. The accompanying unaudited pro forma financial statements also assume that the Acquisition Credit Facilities and Revolving Facility will not be required to be drawn for closing of the Acquisition.

3. PRO FORMA ASSUMPTIONS AND ADJUSTMENTS

(a) Purchase Price and Financing Structure

The following is the estimated net purchase price, estimated net funding requirements and assumed financing structure for the Acquisition. These estimates have been reflected in the accompanying unaudited pro forma consolidated financial statements.

Estimated Net Purchase Price
Unadjusted purchase price	$	13,779
Estimated acquisition costs (Note 3(e))		130
Estimated net purchase price, before assumed debt		13,909
Assumed debt of TECO Energy		(5,356	)
Estimated net purchase price	$	8,553

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Estimated Net Funding Requirements
Estimated net purchase price excluding debt assumed	$	8,553
Assumed debt of TECO Energy		5,356
Convertible Debenture issuance costs (Note 3(c))		90
Acquisition Capital Markets Transactions issuance costs (Note 3 (d))		118
Estimated net funding requirements	$	14,117
Assumed Financing Structure
Assumed debt of TECO Energy	$	5,356
Convertible Debenture issuance (Note 3(c))		2,185
Acquisition Capital Markets Transactions (Note 3(d))		6,576
	$	14,117

(b) Allocation of estimated net purchase price

The estimated net purchase price has been allocated to the estimated fair values of TECO Energy net assets and liabilities as at March 31, 2016 in accordance with the acquisition method, as follows:

	TECO Energy		Fair Value and Other Adjustments			Net Total
	in millions of Canadian dollars
Assets Acquired
Cash and cash equivalents	$	60		—		$	60
Receivables, net		311		—			311
Inventory		253		—			253
Regulatory assets		52		—			52
Prepaid expenses		33		—			33
Total Current Assets		709		—			709
Property, plant and equipment		9,797		—			9,797
Regulatory assets		510		—			510
Goodwill		530		(530	)		0
Other long-term assets		103		—			103
	$	11,649	$	(530	)	$	11,119
Liabilities Assumed
Short-term debt	$	665		—		$
Current portion of long-term debt		108		—			108
Accounts payable		475		—			476
Income taxes payable		37		—			37
Derivative instruments		29		—			29
Regulatory liabilities		141		—			141
Pension and post-retirement liabilities		27		—			27
Other current liabilities		75		—			75
Total Current Liabilities		1,557		—			1,558
Long-term debt		4,526		57			4,583
Deferred income taxes		787		—			787
Derivative instruments		1		—			1
Regulatory liabilities		920		—			920

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	TECO Energy		Fair Value and Other Adjustments		Net Total
	in millions of Canadian dollars
Pension and post-retirement liabilities		360		—		360
Other long-term liabilities		147		—		147
	$	8,299		57	$
Net assets at fair value, as at March 31, 2016					$	2,763
Estimated net purchase price, before assumed debt and acquisition costs					$	8 ,423
Goodwill					$	5,660

TECO Energy is a utility holding company headquartered in Tampa, Florida engaged primarily through its subsidiaries in the regulated vertically- integrated electric utility business in Florida and natural gas transmission and distribution business in Florida and New Mexico. The determination of earnings is based on regulated rates of return that are applied to rate bases and does not change with a change of ownership. “Rate bases” includes jurisdictional rate base, in some cases assets earning a return through clauses and riders, and construction work in progress.

The excess of the estimated net purchase price of the Acquisition, before assumed debt and acquisition costs, over the assumed fair value of net assets acquired from TECO Energy is classified as goodwill on the accompanying unaudited pro forma consolidated balance sheet.

The fair value adjustment on long-term debt relates to non-regulated financing.

(c) Common Share Issuance

In 2015, to finance a portion Acquisition, Emera completed the sale of Cdn$2.185 billion principal amount of 4% convertible unsecured subordinated debentures. These Convertible Debentures were sold on an instalment basis, with one-third paid on closing of the offering, and the remaining payable following satisfaction of conditions precedent to the closing of the Acquisition. For the purposes of these unaudited pro forma consolidated financial statements, the remaining Cdn$1.457 billion relating to the Final Instalment has been received and the Convertible Debentures are assumed to have been fully converted to common shares.

Underwriting costs of Cdn$90 million, of which Cdn$46 million were netted against the proceeds from the first instalment, have been recognized as a deduction from the carrying amount of the equity issued and will result in a corresponding deferred income tax asset of approximately Cdn$28 million based on Emera’s Canadian statutory income tax rate of 31%.

Actual interest costs of Cdn$23 million (Cdn$16 million after-tax) in the year ended December 31, 2015 and Cdn$22 million (Cdn$15 million after-tax) in the three months ended March 31, 2016 incurred on the Convertible Debentures have been removed from Interest Expense, Net as a pro forma adjustment as these costs are directly attributed to the Acquisition and are non-recurring in nature (note 3(i)). The remaining Cdn$42 million (Cdn$28 million after-tax) required to be paid on the Convertible Debentures has been recorded as an adjustment to retained earnings as they are directly attributed to the Acquisition and are non-recurring in nature.

(d) Acquisition Capital Markets Transactions

For the purposes of these unaudited pro forma consolidated financial statements, the Acquisition Capital Markets Transactions are assumed to have raised approximately Cdn$6.6 billion for purposes of financing a portion of the Acquisition.

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The blended interest rate is estimated at 4.4% which would result in incremental interest for the year ended December 31, 2015 and the three months ended March 31, 2016 of Cdn$284 million and Cdn$76 million, respectively. Incremental interest would result in corresponding deferred income tax benefits of Cdn$103 million and Cdn$28 million, respectively based on Emera’s blended U.S. and Canadian income tax rate of 36%.

Estimated issuance costs of Cdn$118 million have been netted against the issuances, and amortized over the term (ten years) of the debt.

(e) Acquisition costs

Acquisition costs are estimated at approximately Cdn$154 million pre-tax (Cdn$130 million after tax) of which Cdn$13 million was incurred in 2015. Acquisition costs include estimated investment banking, accounting, tax, legal, customer benefits negotiated in the settlement to finalize the New Mexico Public Regulation Commission regulatory approval process and other non-financing costs associated with the completion of the Acquisition. These costs have been included as a pro forma adjustment to retained earnings as opposed to being reflected in the unaudited pro forma consolidated statements of earnings of Emera on the basis that these expenses are directly incremental to the Acquisition and are non-recurring in nature.

(f) Income taxes

Income taxes applicable to the pro forma adjustments are calculated at Emera’s average tax rates of 31% (Canadian rate) and 39% (U.S. rate).

The deferred income tax asset and liability is the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities. Deferred income tax assets and liabilities are measured at the tax rates expected to apply when these differences reverse. For the purpose of the accompanying unaudited pro forma consolidated financial statements, average deferred income tax rates of 31% (Canadian rate), 39% (U.S. rate) and 36% (blended U.S. and Canadian rate) have been used.

(g) TECO Energy historical shareholders’ equity

The historical shareholders’ equity of TECO Energy, which includes retained earnings, accumulated other comprehensive income and common shares, is eliminated as a result of the Acquisition.

(h) Earnings per common share

The calculation of the pro forma earnings per Common Share for the year ended December 31, 2015 and for the three months ended March 31, 2016 reflects the assumed issuance of approximately 52.2 million of Common Shares upon conversion of the Convertible Debentures at a net conversion price of Cdn$41.85, as if the issuance had taken place as at January 1, 2015.

(i) Normalizing adjustments for acquisition costs

Mark-to- market pre-tax gains of Cdn$119 million for the year ended December 31, 2015 and pre-tax losses of Cdn$140 million for the three months ended March 31, 2016 (Cdn$101 million after tax gain and Cdn$121 million after tax loss respectively) related to the translation of the Convertible Debenture US$ cash balance and the mark to market adjustments from foreign exchange forward contracts, which are economically hedging the proceeds from the Final Instalment of the Convertible Debentures, have been removed from other income (expenses) as opposed to being reflected in the unaudited pro forma consolidated statements of earnings on the basis that these amounts are directly incremental to the Acquisition and are non-recurring in nature.

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Acquisition related costs of Cdn$22 million (Cdn$17 million after tax) incurred by TECO Energy in the year ended December 31, 2015 have been removed from Operating, Maintenance and General Expense as a pro forma adjustment as these costs are directly incremental to the Acquisition and are non-recurring in nature (US$17 million before tax and US$13 million after tax).

Acquisition related costs of Cdn$75 million (Cdn$53 million after tax) incurred by Emera in the year ended December 31, 2015 and Cdn$25 million (Cdn$17 million after tax) incurred in the three months ended March 31, 2016 have been removed from the income statement as a pro forma adjustment as these costs are directly incremental to the Acquisition and are non-recurring in nature. These costs include actual interest on the Convertible Debentures of Cdn$23 million in the year ended December 31, 2015 and Cdn$22 million in the three months ended March 31, 2016 offset by interest earned on the first instalment proceeds of Cdn$1 million, and bridge fees on Acquisition Credit Facilities of Cdn$40 million in the year ended December 31, 2015 and Cdn$4 million for the three months ended March 31, 2016 removed from Interest Expense and Cdn$13 million in acquisition costs incurred in the year ended December 31, 2015 removed from operating, maintenance and general expense.

(j) Foreign exchange translation

The assets and liabilities of TECO Energy, which has a U.S. dollar functional currency, are translated at the exchange rate in effect as at the unaudited pro forma consolidated balance sheet date of March 31, 2016. Revenues and expenses of TECO Energy’s operations are translated at the weighted average exchange rate in effect during the reporting period. The following exchange rates were utilized for the unaudited pro forma consolidated financial statements:

Balance Sheet (U.S. dollars to Canadian dollars)

Month-end rate—March 31, 2016: 1.2971

Income Statement (U.S. dollars to Canadian dollars)

Weighted average rate—January 1, 2015 to December 31, 2015: 1.2788

Weighted average rate—January 1, 2016 to March 31, 2016: 1.3748

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Pro Forma Non-U.S. GAAP financial measures

EBITDA and Adjusted EBITDA

The following table presents a reconciliation of EBITDA and Adjusted EBITDA to the most directly comparable U.S. GAAP financial measure, on a historical basis and a pro forma basis, for Emera and EBITDA to the most directly comparable U.S. GAAP financial measure, on a historical basis for TECO Energy, for each of the periods indicated. See “Presentation of Financial Information.” The Emera pro forma information for the three months ended March 31, 2016 and the year ended December 31, 2015 set forth below has been prepared using the U.S. dollar to Canadian dollar weighted average rates of 1.3748 (for the period January 1, 2016 to March 31, 2016) and 1.2788 (for the period January 1, 2015 to December 31, 2015), respectively.

	Emera Historical					TECO Energy Historical				Emera Pro Forma
	Three months ended March 31			Year ended December 31		Three months ended March 31		Year ended December 31		Three months ended March 31		Year ended December 31
	2016			2015		2016		2015		2016		2015
	millions of Canadian dollars					millions of U.S. dollars				millions of Canadian dollars
Net Income	$	54.8		$	452.4	$	73.7	$	241.2	$	243.3	$	537.5
Add:
Interest expense, net		75.2			212.6		45.9		186.4		192.1		684.1
Income tax expense (recovery)		26.8			92.4		35.7		155.3		74.7		197.2
Depreciation and amortization		87.5			339.9		89.8		349.0		211		786.2
EBITDA	$	244.3		$	1,097.3	$	245.1	$	931.9	$	721	$	2,205.1
Mark-to-market gain (loss), excluding income tax and interest		(75.1	)		66.1						64.4		(52.8	)
Adjusted EBITDA	$	319.4		$	1,031.2					$	656.6	$	2,257.9

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MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis for Three Months Ended March 31, 2016 and the Year Ended December 31, 2015

This Management’s Discussion and Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments during the first quarter of 2016 relative to the first quarter of 2015; and the full year of 2015 relative to 2014 and 2013; and its financial position as at March 31, 2016 relative to December 31, 2015; and as at December 31, 2015 relative to December 31, 2014. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is presented. Throughout this discussion, “Emera Incorporated,” “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments.

This discussion and analysis should be read in conjunction with the Emera Incorporated MD&A for the first quarter 2016 and unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2016; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2015. Emera follows U.S. GAAP.

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. Emera’s rate-regulated subsidiaries include:

Emera Rate-Regulated Subsidiary or Investment	Accounting Policies Approved/Examined By
Subsidiary
Nova Scotia Power Inc. (“NSPI”)	Nova Scotia Utility and Review Board (“UARB”)
Emera Maine	Maine Public Utilities Commission (“MPUC”) and the Federal Energy Regulatory Commission (“FERC”)
Barbados Light & Power Company Limited (“BLPC”)	Fair Trading Commission, Barbados
Grand Bahama Power Company Limited (“GBPC”)	The Grand Bahama Port Authority (“GBPA”)
Dominica Electricity Services Ltd. (“Domlec”)	Independent Regulatory Commission, Dominica (“IRCD”)
Emera Brunswick Pipeline Company Limited (“EBPC”)	Canadian National Energy Board (“NEB”)
Investment
NSP Maritime Link Inc. (“NSPML”)	UARB
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline LLC (“M&NP”)	NEB and FERC
Labrador Island Link Limited Partnership (“LIL”)	Newfoundland and Labrador Board of Commissioners of Public Utilities
St. Lucia Electricity Services Limited (“Lucelec”)	Government of St. Lucia

All amounts are in Canadian dollars (“CAD”), except for Emera Maine and Emera Caribbean sections of the MD&A, which are reported in U.S. dollars, unless otherwise stated.

Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR at www.sedar.com.

Forward-Looking Information

This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, business prospects

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and opportunities and may not be appropriate for other purposes within the meaning of Canadian securities laws. All such information and statements are made pursuant to safe harbor provisions contained in applicable securities laws. The words “anticipates,” “believes,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “projects,” “schedule,” “should,” “budget,” “forecast,” “might,” “will,” “would,” “targets” and similar expressions are often intended to identify forward- looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations are discussed in the Outlook section of the MD&A and may also include: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; capital market and liquidity risk; the completion of the TECO Energy, Inc. acquisition; uncertainty regarding the length of time required to complete the TECO Energy acquisition; future dividend growth; timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology could reduce demand for electricity; weather; commodity price risk; construction and development risk; unanticipated maintenance and other expenditures; derivative financial instruments and hedging availability and inability to complete the Convertible Debenture Offering and the financing; failure by the Company to repay the acquisition credit facilities; alternate sources of funding that would be used to replace the acquisition credit facilities may not be available when needed; impact of Acquisition-Related Expenses; interest rate risk; credit risk; commercial relationship risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

Structure of MD&A

This MD&A begins with an Introduction and Strategic Overview; followed by the Consolidated Financial Review and Outstanding Common Stock data; then presents information specific to Emera’s consolidated subsidiaries and investments:

• NSPI;

• Emera Maine;

• Emera Caribbean includes BLPC and Domlec and their parent company, Emera (Caribbean) Incorporated (“ECI”), GBPC, Emera Utility Services (Bahamas) Limited (“EUS Bahamas”) and Lucelec;

• Pipelines includes Brunswick Pipeline and M&NP;

• Emera Energy includes Emera Energy Services; Emera Energy Generation which includes Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities”), Brooklyn

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Power Corporation (“Brooklyn Energy”) and Bayside Power Limited Partnership (“Bayside Power”); Bear Swamp; and NWP until its sale on January 29, 2015;

• Corporate and Other includes:

• Interest revenue on intercompany financings and costs associated with corporate activities that are not directly allocated to the operations of Emera’s consolidated subsidiaries and investments;

• Acquisition costs related to the pending Acquisition;

• Emera Utility Services Inc. (“Emera Utility Services”);

• Emera Newfoundland & Labrador Holdings Inc. (“ENL”) and its investments in NSPML and LIL;

• Emera Reinsurance Limited;

• Emera’s investment in Algonquin Power & Utilities Corp. (“APUC”); and

• Other investments.

The Liquidity and Capital Resources, including Consolidated Cash Flow Highlights, Pension Funding, Off- Balance Sheet Arrangements, Outlook, Transactions with Related Parties, Dividends and Payout Ratios, Enterprise Risk and Risk Management, including Financial Instruments, Disclosure and Internal Controls, Critical Accounting Estimates, Changes in Accounting Policies and Practices and Summary of Quarterly Results sections of the MD&A are presented on a consolidated basis.

Introduction and Strategic Overview

Emera Incorporated is a geographically diverse energy and services company that invests in electricity generation, transmission and distribution, gas transmission and utility services. Emera provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States, and the Caribbean. Emera is targeting eight-per-cent annual dividend growth through 2019.

Regulated utilities are the foundation of Emera’s business, providing the Company with strong and consistent earnings. At the core of Emera’s utilities strategy is identifying opportunities to invest in the transition from higher-carbon methods of electricity generation to lower-carbon alternatives. NSPI has invested in wind energy, biomass and hydroelectricity and is on track to meet a minimum 40% renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives, with an emphasis on affordability and fuel cost stability for its customers.

Emera is investing in electricity transmission to help deliver new renewable energy to market. Emera’s ownership in the Maritime Link Project will contribute to the transformation of the electricity market in the Atlantic Provinces, enabling growth in the availability of clean, renewable energy for the region. In addition, the Atlantic Provinces will be connected to the northeastern United States, providing potential for excess renewable energy to be delivered throughout that region.

Since its formation in 2003, Emera Energy has become an active participant in the northeastern United States electricity and natural gas market. It has built a strong marketing, trading and asset management business, based on comprehensive market knowledge, focus on customer service and robust risk management. The integration and performance of the three New England Gas Generating Facilities purchased in 2013 has contributed significantly to the success of Emera Energy.

Energy markets worldwide, in particular across North America, are undergoing foundational changes that have created significant investment opportunities for companies with Emera’s experience and capabilities. Key trends contributing to these investment opportunities include: aging infrastructure, environmental concerns (including

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demand for new, less carbon-intensive and renewable generation), lower-cost natural gas, growing demand for new electric heating solutions, and the requirement for large-scale transmission projects to deliver new energy sources to customers. Within this context, Emera is focused on growing shareholder value by identifying reliable and affordable energy solutions, typically involving the replacement of higher-carbon electricity generation with generation from cleaner sources, and the related transmission and distribution infrastructure to deliver that energy to market.

Emera has strong partnerships and relationships throughout the regions in which it operates and has established a diverse investment and operations profile that links its assets and capabilities in those regions. At the core of Emera’s strategy is the ability to leverage these particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company.

The foundation of Emera’s strategy is its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. The Company will continue to make investments in its regulated utilities to benefit customers and focus on providing rate stability for customers. From time to time, Emera will make acquisitions, both regulated and unregulated, where the business or asset acquired aligns with Emera’s strategic initiatives and delivers shareholder value.

To ensure stability in adjusted net income and cash flows, Emera employs operating and governance models that focus on safety and operational excellence, constructive regulatory approaches, proactive stakeholder engagement and a customer focus through service reliability and rate stability.

Emera targets achieving 75 to 85% of its adjusted income (a non-U.S. GAAP measure described in the section below) from rate-regulated subsidiaries, which generally contribute strong, predictable income and cash flows that fund dividends, reinvestment and which is reflective of the Company’s risk tolerance.

In 2015, approximately 65% of Emera’s adjusted net income was earned by its rate-regulated subsidiaries, which is lower than previous years and the Company’s strategic target. Specifically, the lower percentage of adjusted net income was the result of a substantial increase in Emera Energy’s earnings primarily due to strong performance by the New England Gas Generating Facilities, and a strengthening U.S. dollar. It was not the result of a change in Emera’s risk tolerance, nor is it from additional capital allocations to non-regulated businesses. Rather, it was the result of strong operating and financial performance of existing non-regulated investments and businesses. Following the closing of the Acquisition, the Company is expected to achieve its adjusted net income target.

Emera has grown its asset base to enable growth and deliver on its strategic objectives. Over the last 10 years, Emera’s ability to raise the capital necessary to fund investments has been a strong enabler of the Company’s growth. This was demonstrated in Emera’s recent issue of convertible debentures represented by instalment receipts in relation to the Acquisition. In addition to access to debt and equity capital markets, cash flow from operations will continue to play a role in financing the Company’s future growth. Maintaining strong, investment grade credit ratings is an important component of Emera’s financing strategy.

The energy industry is seasonal in nature. Seasonal patterns and other weather events, including the number and severity of storms, can affect demand for energy and cost of service. Similarly, mark-to-market adjustments that do not qualify for hedge accounting or regulatory accounting can have a material impact on the financial results for a specific period. Results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

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Non-U.S. GAAP Financial Measures

Emera uses financial measures that do not have standardized meaning under U.S. GAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-U.S. GAAP measures by adjusting certain U.S. GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period, as detailed below:

Non-U.S. GAAP measure	U.S. GAAP measure
Adjusted net income attributable to common shareholders or adjusted net income	Net income attributable to common shareholders
Adjusted earnings per common share – basic	Earnings per common share – basic
Adjusted contribution to consolidated net income	Contribution to consolidated net income
Adjusted income before provision for income taxes	Income before provision for income taxes
Adjusted contribution to consolidated earnings per common share – basic	Contribution to consolidated earnings per common share – basic
EBITDA	Net income
Adjusted EBITDA	Net income
Electric margin	Income from operations

Adjusted Net Income and Adjusted Earnings per Common Share—Basic

Emera calculates comparable measures by excluding the effect of:

• the mark-to-market adjustments related to Emera’s held-for-trading derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered;

• the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp and NWP, until NWP’s sale on January 29, 2015;

• the amortization of transportation capacity recognized as a result of certain trading and marketing transactions;

• the mark-to-market adjustments related to an interest rate swap in EBPC; and

• the mark-to-market adjustments included in Emera’s other income related to the effect of USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the Convertible Debenture Offering in connection with the Acquisition.

Management believes excluding from income the effect of these mark-to-market valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows.

Mark-to-market adjustments are further discussed in the Consolidated Financial Highlights section, Emera Energy—Review of 2015, Pipelines—Review of 2015, Corporate and Other—Review of 2015, Emera Energy —Review of 2016, Pipelines—Review of 2016 and Corporate and Other—Review of 2016.

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The following is a reconciliation of reported net income attributable to common shareholders to adjusted net income attributable to common shareholders, and reported earnings per common share—basic to adjusted earnings per common share—basic:

	Three months ended March 31						Year ended December 31
	2016			2015			2015		2014		2013
	millions of Canadian dollars (except per share amounts)
Net income attributable to common shareholders	$	44.3		$	160.1		$	397.2	$	406.7	$	217.5
After-tax mark-to-market gain (loss)		(75.9	)		(11.5	)		67.2		87.5		(41.9	)
Adjusted net income attributable to common shareholders		120.2			171.6			330.0		319.2		259.4
Earnings per common share – basic		0.30			1.10			2.72		2.84		1.64
Adjusted earnings per common share – basic		0.81			1.18			2.26		2.23		1.96

Adjusted Contribution to Consolidated Net Income, Adjusted Income Before Provision for Income Taxes and Adjusted Contribution to Consolidated Earnings per Common Share—Basic

Emera calculates these non-U.S. GAAP measures by excluding the effect of certain mark-to-market adjustments from their respective U.S. GAAP equivalents.

Mark-to-market adjustments are further discussed in “—Consolidated Financial Highlights,” “—Emera Energy—Review of 2015,” “—Pipelines—Review of 2015,” “—Corporate and Other—Review of 2015,” “—Emera Energy—Review of 2016,” “—Pipelines—Review of 2016 and Corporate and Other—Review of 2016.”

Emera EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is a non-U.S. GAAP financial measure used in this Prospectus in respect of Emera. EBITDA is used by numerous investors and lenders to better understand cash flows and credit quality.

“Adjusted EBITDA” is a non-U.S. GAAP financial measure used by Emera. Similar to Adjusted Net Income calculations, this measure represents EBITDA absent the income effect of Emera’s mark-to-market adjustments, as previously discussed.

The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies, but in management’s view appropriately reflects Emera’s specific financial condition. These measures are not intended to replace “Net income” which, as determined in accordance with U.S. GAAP, is an indicator of operating performance. EBITDA and Adjusted EBITDA are discussed further herein.

The following is a reconciliation of reported net income to EBITDA and Adjusted EBITDA:

	Three months ended March 31						Year ended December 31
	2016			2015			2015		2014		2013
	millions of Canadian dollars
Net income		$54.8			$174.1			$452.4		$452.8		$255.3
Interest expense, net		75.2			44.4			212.6		179.8		172.2
Income tax expense (recovery)		26.8			61.4			92.4		113.6		43.3
Depreciation and amortization		87.5			82.8			339.9		329.0		297.8
EBITDA		244.3			362.7			1,097.3		1,075.2		768.6
Mark-to-market gain (loss), excluding income tax and interest		(75.1	)		(21.5	)		66.1		128.7		(60.9	)
Adjusted EBITDA		$319.4			$384.2			$1,031.2		$946.5		$829.5

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TECO Energy EBITDA

EBITDA is a non-U.S. GAAP financial measure used in this Prospectus in respect of TECO Energy. EBITDA is used by numerous investors and lenders to better understand cash flows and credit quality.

TECO Energy’s EBITDA may not be comparable to the EBITDA measures of other companies, but in TECO Energy’s management’s view appropriately reflects TECO Energy’s specific financial condition. This measures is not intended to replace “Net income” which, as determined in accordance with U.S. GAAP, is an indicator of operating performance. TECO Energy’s EBITDA is discussed further herein.

The following is a reconciliation of reported net income from continuing operations to EBITDA:

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014		2013
	millions of U.S. dollars
Net income from continuing operations	$	73.7	$	63.8	$	241.2	$	206.4		$188.7
Interest expense, net		45.9		47.9		186.4		171.1		161.4
Income tax expense		35.7		39.9		155.3		138.9		112.6
Depreciation and amortization		89.8		85.5		349.0		315.3		291.8
EBITDA	$	245.1	$	237.1	$	931.9	$	831.7		$754.5

Electric Margin

“Electric margin” is a non-U.S. GAAP financial measure used to show the amounts that NSPI, BLPC, GBPC and Domlec retain to recover non-fuel costs. Prudently incurred fuel costs are recovered from customers, except in Domlec, where substantially all fuel costs are passed to customers through the fuel pass-through mechanism. Management believes measuring electric margin shows the portion of the utilities’ revenues that directly contribute to Emera’s income as distinguished from the portion of revenues that are managed through fuel adjustment mechanisms, which have a minimal impact on income.

Emera Energy also reports “Electric margin” because the sales price of electricity and the cost of natural gas used to generate it are highly correlated. However, their absolute values can vary materially over time. Emera Energy believes that “Electric margin,” as the net result, provides a meaningful measure of the business’ performance in addition to the absolute values of sales and fuel expenses, which are also reported.

Electric margin, as calculated by Emera, may not be comparable to the electric margin measures of other companies, but in management’s view appropriately reflects Emera’s specific condition. This measure is not intended to replace “Income from operations” which, as determined in accordance with U.S. GAAP, is an indicator of operating performance. Electric margin is discussed further in “NSPI—Electric Margin,” “Emera Caribbean—Electric Margin” and “Emera Energy—Adjusted EBITDA”.

Significant Items Affecting Earnings

2016

After-Tax Mark-to-Market Losses

After-tax mark-to-market losses increased Cdn$64.4 million to Cdn$75.9 million in Q1 2016 compared to Cdn$11.5 million in Q1 2015 primarily due to reversal of the 2015 gain on USD-denominated currency and forward contracts related to the financing of the Acquisition and the amortization of 2015 Emera Energy gas transportation assets. This increase was partially offset by the reversal of 2015 mark- to-market losses and changes in gas and power contract positions at Emera Energy.

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Acquisition-Related Costs

Emera incurred after-tax costs of Cdn$17.5 million (Cdn$0.12 per common share) in Q1 2016 (2015—nil) related to the Acquisition, including legal, advisory, and financing costs.

As discussed and included above in “After-Tax Mark-to-Market Losses,” the foreign currency earnings effect related to the Convertible Debenture Offering USD cash balance and the forward contracts were recorded as a mark-to-market after-tax loss of Cdn$121.1 million in “Other income (expenses), net” in Q1 2016 (2015—nil).

Sale of Common Shares of APUC

On May 17, 2016, Emera announced that it had agreed to sell all of its 50.1 million common shares of APUC, representing approximately 19.3% of the issued and outstanding common shares, to a syndicate of underwriters at Cdn$10.85 per common share for an aggregate gross amount of approximately Cdn$544 million. The sale was completed on May 24, 2016. Emera intends to use the net proceeds from the sale in support of its general financing requirements, including the Acquisition. Emera continues to hold an equity interest in APUC equivalent to approximately 12.9 million common shares (in the form of subscription receipts and dividend equivalents), which upon conversion represent a continuing common equity interest of approximately 4.75%.

2015

After-Tax Mark-to-Market Gains

After-tax mark-to-market gains increased Cdn$32.3 million to Cdn$105.0 million in Q4 2015 compared to Cdn$72.7 million in Q4 2014; and decreased Cdn$20.3 million to Cdn$67.2 million for the year ended December 31, 2015 compared to Cdn$87.5 million in 2014. The increased mark-to-market gains in the quarter are primarily due to the effect of USD-denominated currency and forward contracts related to the Acquisition. The increase is partially offset by changes in gas and power contract positions and amortization of transportation assets in Emera Energy. In addition, the reversal of 2013 mark-to-market losses in 2014 in Emera Energy is primarily responsible for the year-over-year decrease in after-tax mark to-market gains.

Acquisition-Related Costs

Emera incurred after-tax costs of Cdn$30.3 million (Cdn$0.21 per common share) in Q4 2015 related to its pending Acquisition, including legal, advisory, and financing costs. For the year ended December 31, 2015, TECO Energy acquisition-related costs were Cdn$52.8 million after-tax (Cdn$0.36 per common share). There were no such TECO Energy acquisition-related costs for 2014.

As discussed and included above in “After-Tax Mark-to-Market Gains,” the foreign currency earnings effect related to the Convertible Debenture Offering USD cash balance and the forward contracts were recorded as a mark-to-market pre-tax gain of Cdn$118.9 million in “Other income (expenses), net” in Q4 2015.

Further information on the pending Acquisition is in the Developments section of the MD&A.

Gain on Dilution of APUC Equity Investment

In December 2015, APUC closed a 14.355 million common share offering. As a result, Emera recorded a dilution gain of Cdn$11.1 million (after-tax earnings of Cdn$9.4 million or Cdn$0.06 per common share) in “Income from Equity Investments.” The gain was a result of APUC’s share issuance price being higher than Emera’s pre-issuance average book value.

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Barbados Light & Power Company Limited (“BLPC”) Restructuring Costs

BLPC recorded severance costs of Cdn$7.9 million ($6.4 million USD) relating to corporate restructuring, which was recorded in Operating, maintenance and general (“OM&G”) in Q2 2015. BLPC sees no requirement to seek regulatory deferral of these costs. The after-tax effect on Emera’s Consolidated Net Income in Q2 2015, at Emera’s then 80.7% ownership of ECI, was Cdn$5.4 million (Cdn$0.04 per common share).

Sale of Northeast Wind Partnership II, LLC Equity Investment

On January 29, 2015, Emera completed the sale of its 49% interest in NWP for Cdn$282.3 million ($223.3 million USD). This sale resulted in a pre-tax gain of Cdn$18.6 million or Cdn$0.13 per common share (after-tax gain of Cdn$11.5 million or Cdn$0.08 per common share), which was recorded in “Other income (expenses), net” in Q1 2015.

2014

After-Tax Mark-to-Market Gains

After-tax mark-to-market gains (losses) increased Cdn$114.7 million to Cdn$72.7 million in Q4 2014 compared to Cdn$(42.0) million in Q4 2013; and increased Cdn$129.4 million to Cdn$87.5 million for the year ended December 31, 2014 compared to Cdn$(41.9) million in 2013. The increased mark-to-market gains are a result of the reversal of 2013 mark-to-market losses and favourable changes in gas and power contract positions in 2014 at Emera Energy.

Gains on Dilution of APUC Equity Investment

In Q3 2014 and Q4 2014 respectively, APUC closed 16.86 million and 10.05 million common share offerings. In addition, in Q3 2014, an over-allotment option of 2.52 million common shares was exercised. As a result of these two transactions, in Q3 2014, Emera recorded a gain of Cdn$10.8 million (after-tax earnings of Cdn$9.1 million or Cdn$0.06 per common share) and in Q4 2014, a gain of Cdn$7.5 million (after-tax earnings of Cdn$6.4 million or Cdn$0.04 per common share) in “Income from Equity Investments.”

Consolidated Financial Review

In Q1 2016, Emera affiliates in the northeastern United States and Atlantic Canada experienced less demand for electricity as a result of unseasonably warm weather. Specifically, NSPI, Emera Maine and Emera Energy’s New England Gas Generating Facilities results were affected. Below is a table highlighting significant changes between adjusted net income (a non-U.S. GAAP measure described in “Management’s Discussion and Analysis— Non-U.S. GAAP Financial Measures”) from Q1 2015 to Q1 2016.

	Three months ended March 31
	millions of Canadian dollars
Adjusted net income – 2015	$	171.6
Emera Energy (largely due to New England Gas Generation Facilities)(1)		(17.0	)
Acquisition and financing costs relating to the pending Acquisition(1)		(17.5	)
NSPI		(15.5	)
2015 gain on the sale of NWP		(11.5	)
Increased equity earnings from NSPML and LIL		3.8
Other(1)		6.3
Adjusted net income – 2016	$	120.2

(1) These numbers include the impact of the stronger USD.

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Consolidated Financial Highlights

	Three months ended March 31						Year ended December 31
	2016			2015			2015		2014		2013
	millions of Canadian dollars (except per share amounts)
Operating revenues	$	877.0		$	888.5		$	2,789.3	$	2,938.6	$	2,230.2
Income from operations		270.0			232.1			507.7		667.3		407.1
Net income attributable to common shareholders		44.3			160.1			397.2		406.7		217.5
After-tax mark-to-market gain (loss)		(75.9	)		(11.5	)		67.2		87.5		(41.9	)
Adjusted net income attributable to common shareholders		120.2			171.6			330.0		319.2		259.4
Earnings per common share – basic		0.30			1.10			2.72		2.84		1.64
Earnings per common share – diluted		0.30			1.09			2.71		2.82		1.64
Adjusted earnings per common share – basic		0.81			1.18			2.26		2.23		1.96
Dividends per common share declared		0.4750			0.3875			1.6625		1.4750		1.4125
Adjusted EBITDA	$	319.4		$	384.2		$	1,031.2	$	946.5	$	829.5

Operating Unit Contributions to Adjusted Net Income

	Three months ended March 31						Year ended December 31
	2016			2015			2015			2014			2013
	millions of Canadian dollars
NSPI	$	52.5		$	68.0		$	129.9		$	124.9		$	126.0
Emera Maine		9.3			11.5			45.1			42.4			38.4
Emera Caribbean		9.8			8.8			40.5			28.7			33.4
Pipelines		9.7			9.9			39.6			32.7			30.3
Emera Energy		47.9			76.4			130.1			98.2			45.1
Corporate and Other		(9.0	)		(3.0	)		(55.2	)		(7.7	)		(13.8	)
Adjusted net income attributable to common shareholders		120.2			171.6			330.0			319.2			259.4
After-tax mark-to-market gain (loss)		(75.9	)		(11.5	)		67.2			87.5			(41.9	)
Net income attributable to common shareholders	$	44.3		$	160.1		$	397.2		$	406.7		$	217.5

	Three months ended March						Year ended December 31
	2016			2015			2015			2014			2013
	millions of Canadian dollars
Operating cash flow before changes in working capital	$	232.4		$	257.5		$	775.8		$	716.3		$	574.3
Change in working capital		(51.8	)		(137.9	)		(101.6	)		46.2			(10.1	)
Operating cash flow		180.6		$	119.6			674.2			762.5			564.2
Investing cash flow		(139.3	)	$	195.9			(123.7	)		(710.9	)		(921.6	)
Financing cash flow	$	(45.8	)	$	(259.3	)	$	221.1		$	58.2		$	362.1

	Three months ended March 31, 2016		Year ended December 31
			2015		2014		2013
	millions of Canadian dollars
Working capital(1)	$	580.3	$	599.2	$	358.3	$	372.7
Total assets(1)		11,448.6		12,012.3		9,853.4		8,876.8
Total long-term liabilities(1)	$	5,492.1	$	5,580.7	$	5,025.1	$	4,449.7

(1) These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

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Review of 2015

Emera Consolidated Statements of Income

	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
	millions of Canadian dollars (except per share amounts)
Operating revenues – regulated	$	533.8	$	526.7	$	2,192.9	$	2,113.1	$	2,040.8
Operating revenues – non-regulated		197.8		256.0		596.4		825.5		189.4
Total operating revenues		731.6		782.7		2,789.3		2,938.6		2,230.2
Regulated fuel for generation and purchased power		199.9		212.9		814.5		844.3		868.4
Regulated fuel adjustment mechanism and fixed cost deferrals		10.3		5.7		41.6		46.6		(40.8	)
Non-regulated fuel for generation and purchased power		90.7		78.2		335.7		401.1		89.8
Non-regulated direct costs		4.4		9.7		19.5		31.3		52.4
Operating, maintenance and general		173.6		144.0		666.8		560.8		505.0
Provincial, state and municipal taxes		15.8		14.8		63.6		58.2		50.5
Depreciation and amortization		87.9		82.0		339.9		329.0		297.8
Total operating expenses		582.6		547.3		2,281.6		2,271.3		1,823.1
Income from operations		149.0		235.4		507.7		667.3		407.1
Income from equity investments		26.4		15.4		108.6		66.6		38.1
Other income (expenses), net		114.8		2.9		141.1		12.3		25.6
Interest expense, net		70.9		44.7		212.6		179.8		172.2
Income before provision for income taxes		219.3		209.0		544.8		566.4		298.6
Income tax expense (recovery)		20.7		53.7		92.4		113.6		43.3
Net income		198.6		155.3		452.4		452.8		255.3
Non-controlling interest in subsidiaries		6.5		4.1		24.9		19.9		18.5
Net income of Emera Incorporated		192.1		151.2		427.5		432.9		236.8
Preferred stock dividends		—		—		30.3		26.2		19.3
Net income attributable to common shareholders		192.1		151.2		397.2		406.7		217.5
After-tax mark-to-market gain (loss)		105.0		72.7		67.2		87.5		(41.9	)
Adjusted net income attributable to common shareholders(1)		87.1		78.5		330.0		319.2		259.4
Earnings per common share – basic		1.31		1.05		2.72		2.84		1.64
Earnings per common share – diluted		1.30		1.02		2.71		2.82		1.64
Adjusted earnings per common share – basic(1)	$	0.59	$	0.54	$	2.26	$	2.23	$	1.96

(1) A non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”.

Emera Incorporated’s consolidated net income attributable to common shareholders increased Cdn$40.9 million to Cdn$192.1 million in Q4 2015 compared to Cdn$151.2 million for the same period in 2014. For the year ended December 31, 2015, Emera’s consolidated net income attributable to common shareholders decreased Cdn$9.5 million to Cdn$397.2 million compared to Cdn$406.7 million in 2014.

Consolidated Income Statement Highlights for Q1 2016 and Q4 2015

Operational Results

Income from operations increased Cdn$37.9 million to Cdn$270.0 million in Q1 2016 compared to Cdn$232.1 million in Q1 2015 primarily due to mark-to-market increases of Cdn$91.7 million, the impact of a stronger USD and increased marketing and trading margin at Emera Energy. This was partially offset by decreased margin at the New England Gas Generating Facilities and decreased income from operations at NSPI.

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Details of the operating revenues and operating expenses line item variances are described below:

Total operating revenues decreased 1.3% to Cdn$877.0 million in Q1 2016 compared to Cdn$888.5 million in Q1 2015 primarily due to:

• mark-to-market changes increased operating revenues by Cdn$95.9 million.

• a Cdn$60.1 million decrease at the New England Gas Generating Facilities reflecting lower hedged and market commodity prices and decreased sales volumes due to weather;

• a Cdn$49.0 million decrease in NSPI revenues as a result of lower sales volumes due to weather;

• a Cdn$10.5 million decrease at Bayside Power primarily due to lower power prices;

• a Cdn$10.4 million increase at Emera Maine primarily due to the impact of a stronger USD;

• an Cdn$8.1 million increase in marketing and trading margin at Emera Energy primarily due to the impact of a stronger USD and growth in the volume of business.

Total operating expenses decreased 7.5% to Cdn$607.0 million in Q1 2016 compared to Cdn$656.4 million in Q1 2015. This was primarily the result of decreased fuel costs at NSPI and New England Gas Generating Facilities reflecting lower commodity prices and decreased sales volumes due to weather, partially offset by higher operating, maintenance and general expenses (“OM&G”) at NSPI reflecting increased storm costs, and the impact of a stronger USD.

Income from operations decreased Cdn$86.4 million to Cdn$149.0 million in Q4 2015 compared to Cdn$235.4 million in the same quarter in 2014 primarily due to negative mark-to-market changes of Cdn$101.2 million and Cdn$21.0 million in costs related to the pending Acquisition. These decreases were partially offset by Emera Energy’s increased trading and marketing margin, and increased margin at the New England Gas Generation Facilities.

Details of operating revenues and operating expenses line item variances are described below:

Total operating revenues decreased 6.5% to Cdn$731.6 million in Q4 2015 compared to Cdn$782.7 million in Q4 2014 primarily due to:

• Cdn$113.7 million decrease from changes in mark-to-market impacts;

• Cdn$46.0 million increase at the New England Gas Generation Facilities primarily due to major outage work at Bridgeport Energy in 2014 and the effect of a strengthening USD;

• Cdn$22.2 million increase in Emera Energy Services reflecting growth in the volume of business and increased investment in transportation capacity;

• Cdn$9.5 million decrease at BLPC primarily due to lower fuel revenue reflecting lower fuel prices;

• Cdn$6.9 million increase at Emera Maine primarily due to the effect of a strengthening USD, partially offset by decreased sales volumes;

• Cdn$5.8 million increase at NSPI as a result of recovery of prior years’ fuel costs from a 2014 UARB settlement agreement, partially offset by decreased sales volumes due to weather.

Total operating expenses increased 6.4% to Cdn$582.6 million in Q4 2015 compared to Cdn$547.3 million in Q4 2014, primarily due to the effect of a strengthening USD, acquisition costs related to the Acquisition, and increased fuel costs at the New England Gas Generation Facilities reflecting major outage work at Bridgeport Energy in 2014, partially offset by lower fuel prices at BLPC and changes in mark-to-market impacts.

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Income from equity investments

Income from equity investments increased 71.4% in Q4 2015 to Cdn$26.4 million compared to Cdn$15.4 million in the same period in 2014, primarily due to higher APUC earnings in 2015 and a higher pre-tax gain on dilution of Emera’s APUC investment in 2015.

Other income (expenses), net

Other income decreased Cdn$161.1 million to Cdn$(139.2) million in Q1 2016 compared to Cdn$21.9 million in Q1 2015. This was primarily due to mark-to-market losses relating to the effect of USD-denominated currency and forward contracts put into place to economically hedge anticipated proceeds from the Convertible Debenture Offering and the 2015 gain on the sale of NWP.

Other income increased Cdn$111.9 million to Cdn$114.8 million in Q4 2015 compared to Cdn$2.9 million in the same period in 2014. This was primarily due to mark-to-market gains on USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Convertible Debenture Offering for the Acquisition.

Interest expense, net

Interest expense increased Cdn$30.8 million to Cdn$75.2 million in Q1 2016 compared to Cdn$44.4 million in Q1 2015 primarily due to interest on Convertible Debentures represented by instalment receipts related to the pending Acquisition.

Income tax expense (recovery)

Income tax expense decreased Cdn$34.6 million to Cdn$26.8 million in Q1 2016 compared to Cdn$61.4 million in Q1 2015. This was primarily due to decreased income before provision for income taxes including mark-to-market adjustments, partially offset by the non-deductible portion of TECO Energy related mark-to-market losses on USD-denominated currency and forward contracts related to the pending acquisition.

Income tax expense decreased Cdn$33.0 million to Cdn$20.7 million in Q4 2015 compared to Cdn$53.7 million for the same period in 2014 primarily due to decreased income before provision for income taxes including mark-to-market adjustments related to Emera Energy, changes in the proportion of Emera Energy income earned in higher tax rate foreign jurisdictions, and a legislated change by the Province of Nova Scotia to the deferred tax treatment of two wind farms at NSPI. These decreases were partially offset by the taxable portion of mark-to-market gains relating to the effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Convertible Debenture Offering for the Acquisition.

Consolidated Income Statement Highlights for 2015

Operational Results

Income from operations decreased Cdn$159.6 million to Cdn$507.7 million for the year ended December 31, 2015 compared to Cdn$667.3 million in 2014 primarily due to mark-to-market changes of Cdn$189.2 million. Increased margin at the New England Gas Generation Facilities, the effect of the strengthening USD, and increased operating income at NSPI, partially offset by Cdn$51.5 million in expenses relating to the pending Acquisition and Emera Energy’s decreased trading and marketing margin.

Total operating revenues decreased 5.1% to Cdn$2,789.3 million for the year ended December 31, 2015 compared to Cdn$2,938.6 million in the same period in 2014 primarily due to:

• Cdn$203.7 million decrease from changes in mark-to-market impacts

• Cdn$47.3 million decrease at BLPC primarily due to lower fuel revenue reflecting lower fuel prices

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• Cdn$32.6 million decrease in Emera Energy Services reflecting a return to more normal market circumstances following particularly strong market conditions in the northern United States and Ontario in Q1 2014

• Cdn$69.1 million increase at NSPI as a result of recovery of prior years’ fuel costs from the 2014 UARB settlement agreement and higher sales volumes, primarily due to weather

• Cdn$46.3 million increase at the New England Gas Generation Facilities primarily due to higher realized margins, increased generation largely because Bridgeport Energy had a major planned outage in Q4 2014, and the effect of a strengthening USD

• Cdn$41.6 million increase at Emera Maine primarily due to the effect of a strengthening USD, partially offset by decreased sales volumes.

Total operating expenses increased 0.5% to Cdn$2,281.6 million for the year ended December 31, 2015 compared to Cdn$2,271.3 million in 2014. This was primarily due to the effect of a strengthening USD, acquisition costs related to the Acquisition and increased regulated fuel for generation and purchased power at NSPI, partially offset by decreased fuel costs at the New England Gas Generation Facilities and BLPC reflecting lower fuel prices and changes in mark-to-market impacts.

Income from equity investments

Income from equity investments increased Cdn$42.0 million to Cdn$108.6 million for the year ended December 31, 2015 compared to $66.6 million in the same period of 2014. This was primarily due to favourable mark-to-market changes of Cdn$7.7 million, NWP losses in 2014, higher APUC equity earnings, increased allowance for funds used during construction (“AFUDC”) earnings by NSPML, and increased earnings resulting from the increased investment in LIL, partially offset by lower APUC dilution gains in 2015 compared to 2014.

Other income (expenses), net

Other income increased Cdn$128.8 million to Cdn$141.1 million for the year ended December 31, 2015 compared to Cdn$12.3 million in the same period in 2014. This was primarily due to a mark-to-market gains relating to the foreign exchange effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Convertible Debenture Offering for the Acquisition and the gain on the sale of NWP.

Income tax expense (recovery)

Income tax expense decreased Cdn$21.2 million to Cdn$92.4 million for the year ended December 31, 2015 compared to Cdn$113.6 million in 2014. This was primarily due to decreased income before provision for income taxes, including mark-to-market adjustments related to Emera Energy, partially offset by the taxable portion of mark-to-market gains relating to the effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Convertible Debenture Offering financing the Acquisition.

Consolidated Operating Cash Flow Highlights for Q1 2015 and Q1 2016

Operating Activities

Net cash provided by operating activities increased Cdn$61.0 million to Cdn$180.6 million in Q1 2016 compared to Cdn$119.6 million in Q1 2015. Cash from operations before changes in working capital decreased by Cdn$25.1 million primarily due to decreased margin at the New England Gas Generating Facilities and the payment of financing costs related to the pending Acquisition.

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Changes in working capital increased operating cash flows by Cdn$86.1 million primarily due to favourable changes in accounts receivable reflecting lower sales volumes at NSPI and favourable changes in inventory reflecting the purchase of emission credits by the New England Gas Generating Facilities in 2015.

Net cash provided by operating activities decreased Cdn$88.3 million to Cdn$674.2 million for the twelve months ended December 31, 2015 compared to Cdn$762.5 million for the same period in 2014. Cash from operations before changes in working capital increased by Cdn$62.0 million primarily due to higher margins at the New England Gas Generation Facilities, the effect of a strengthening USD and increased Fuel Electric Revenues at NSPI, partially offset by lower trading and marketing margin at Emera Energy Services, payment of acquisition costs related to the Acquisition and the deferral of demand side management (“DSM”) program costs at NSPI.

Changes in working capital decreased operating cash flows by Cdn$150.3 million primarily due to increased receivables reflecting higher posted margin at Emera Energy and increased revenues at NSPI and increased dividends payable, partially offset by favourable changes in fuel inventory at NSPI reflecting increased consumption.

Effect of Foreign Currency Translation

Emera’s foreign currency-denominated results are affected by exchange rate fluctuations. Revenue, operating expense, net income, and adjusted net income are translated at the weighted average rate of exchange. The amounts in the table below are calculated by multiplying the current period foreign denominated results by the change in the weighted average foreign exchange from the prior period. The tables below show the estimated effect of foreign currency translation on key income statement items:

	Q1 2016 vs Q1 2015			Q1 2015 vs Q1 2014
	millions of Canadian dollars (except per share amounts)
Impact on income from continuing operations
Total operating revenues		$48.5			$43.3
Total operating expenses		(25.7	)		(32.5	)
Net income		15.8			9.2
Adjusted net income(1)		7.2			11.0
Impact on earnings per share
Basic		$0.11			$0.06
Basic – adjusted		$0.05			$0.08

	Q4 2015 vs Q4 2014			Q4 2014 vs Q4 2013
	millions of Canadian dollars (except per share amounts)
Impact on income from continuing operations
Total operating revenues		$49.1			$30.7
Total operating expenses		(42.3	)		(15.6	)
Net income		4.0			10.4
Adjusted net income(1)		7.0			2.4
Impact on earnings per share
Basic		0.03			0.7
Adjusted		$0.05			$0.02

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	2015 vs 2014			2014 vs 2013
	millions of Canadian dollars (except per share amounts)
Impact on income from continuing operations
Total operating revenues	$	163.6		$	98.6
Total operating expenses		(139.4	)		(67.0	)
Net income		19.2			22.0
Adjusted net income(1)		26.0			12.1
Impact on earnings per share
Basic		0.13			0.15
Adjusted	$	0.18		$	0.08

(1) A non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures.”

Emera’s weighted average foreign exchange rates are shown in the following tables:

Average equivalent of $1.00 USD	Three months ended March 31
	2016		2015		2014
CAD		1.38		1.24		1.10

	Year ended December 31
Average equivalent of $1.00 USD	2015		2014		2013
CAD	$	1.26	$	1.12	$	1.03

Consolidated Balance Sheets Highlights

Significant changes in the consolidated balance sheets between December 31, 2015 and March 31, 2016 include:

millions of Canadian dollars	Increase (Decrease)			Explanation
Assets
Cash and cash equivalents	$	(73.9	)	Decreased primarily due to the impact of a stronger CAD
Receivables, net		32.9		Increased due to seasonal trends of business at NSPI and Emera Energy
Inventory		(53.5	)	Decreased primarily due to lower fuel inventory volumes as a result of consumption and lower commodity pricing at NSPI
Derivative instruments (current and long-term)		(239.3	)	Decreased primarily due to the effect of a stronger CAD and settlements of derivative instruments at Emera Energy and NSPI
Prepaid expenses		22.1		Increased primarily due to timing of provincial grants in lieu of taxes and insurance payments at NSPI
Property, plant and equipment, net of accumulated depreciation		(173.1	)	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries and depreciation, offset by additions
Investments subject to significant influence		64.4		Increased primarily due to increased investments in LIL and NSPML
Other assets (current and long-term)		(70.2	)	Decreased primarily due to the amortization of transportation/storage capacity assets at Emera Energy
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		(27.5	)	Decreased primarily due to the effect of a stronger CAD on debt held by foreign subsidiaries
Accounts payable		(22.7	)	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries

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millions of Canadian dollars	Increase (Decrease)			Explanation
Derivative instruments (current and long-term)		(218.2	)	Decreased primarily due to settlements of natural gas and power contracts at Emera Energy
Regulatory liabilities (current and long-term)		(74.4	)	Decreased primarily due to changes in regulated derivatives partially offset by an increased FAM regulatory liability at NSPI
Other liabilities (current and long-term)		(47.8	)	Decreased primarily due to the effect of a stronger CAD on the Bear Swamp investment, payment of restructuring costs at Emera Caribbean and timing of accruals
Common stock		41.5		Increased primarily due to issuance of common stock for the dividend reinvestment program
Accumulated other comprehensive income		(130.7	)	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries
Retained earnings		(25.7	)	Decreased due to dividends payments in excess of net income
Non-controlling interest in subsidiaries		(28.8	)	Decreased due to increased ownership by Emera in ECI

Significant changes in the consolidated balance sheets between December 31, 2015 and December 31, 2014 include:

millions of Canadian dollars	Increase (Decrease)		Explanation
Assets
Cash and cash equivalents		$852.3	Increased from proceeds of the convertible debentures and long-term debt and cash from operations, partially offset by increased debt levels, preferred shares repayments and dividends
Receivables, net		63.9	Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries and increased cash collateral position on derivative instrument at NSPI
Income taxes receivable, net of income taxes payable (current and long-term)		52.8	Increased primarily due to the payment of taxes owing for the 2014 tax year by Emera Energy Services and NSPI’s required prepayment of taxes for reassessments relating to the timing of tax deductions under dispute with the Canada Revenue Agency
Derivative instruments (current and long-term)		188.6	Increased primarily due to favourable changes in USD price positions, partially offset by settlements of derivative instruments at NSPI and Emera Energy
Regulatory assets (current and long- term)		96.8	Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries and increased regulatory assets related to deferred income taxes, DSM and regulated derivatives, partially offset by amortization at NSPI
Property, plant and equipment, net of accumulated depreciation		577.8	Increased primarily due to the favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries, increased capital expenditures resulting from major planned outage work at Bridgeport Energy, funding of capital investments at Tiverton Power for 2016 major outage work and increased capital spending at NSPI, partially offset by depreciation

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millions of Canadian dollars	Increase (Decrease)		Explanation
Investments subject to significant influence		117.7	Increased primarily due to reclassification of Bear Swamp investment credit balance to Other Long-Term Liabilities, outstanding APUC subscription receipts which became eligible for conversion in Q4 2015 (originally recorded in Other Assets), dilution gains in APUC, and increased investments in LIL and M&NP, partially offset by the sale of NWP
Available-for-sale investments		31.6	Increased primarily due to investment by Emera Reinsurance Limited and favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries
Goodwill		42.6	Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries
Intangibles		57.6	Increased primarily due to investment by Emera Maine in a customer information system and the favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries
Other assets (current and long-term)		115.2	Increased primarily due to increase in transportation capacity assets in Emera Energy and increased deferred financing costs related to the pending Acquisition, offset by a decrease in APUC subscription receipts which became eligible for conversion in Q4 2015 (now recorded as Investments Subject to Significant Influence)
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		28.3	Increased primarily due to increased debt levels at NSPI to fund the redemption of preferred stock, issuance of long-term debt by EBPC and the effect of a stronger USD on debt held by foreign subsidiaries, partially offset by repayment of long-term debt
Convertible debentures represented by instalment receipts		727.6	Increased due to the issuance of convertible debentures related to the pending Acquisition
Deferred income tax liabilities, net of deferred income tax assets		174.0	Increased primarily due to the utilization of non-capital loss carryforwards and accelerated tax deductions related to property, plant and equipment at NSPI and Emera Maine
Derivative instruments (current and long-term)		240.5	Increased primarily due to a new asset management agreement and unfavourable changes in commodity pricing at Emera Energy and unfavourable mark-to-market impacts relating to interest rate and foreign exchange hedges at EBPC
Regulatory liabilities (current and long- term)		168.7	Increased primarily due to changes in derivative instruments as a result of favourable USD price positions and increased FAM liability at NSPI, partially offset by settlements of derivative instruments at NSPI

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millions of Canadian dollars	Increase (Decrease)			Explanation
Pension and post-retirement liabilities (current and long-term)		(57.8	)	Decreased primarily due to improvement in funded position as a result of greater than expected asset return at NSPI
Other liabilities (current and long-term)		267.7		Increased primarily due to deferred cost impact of parts and capital work delivered for performance in 2015 by a service provider under long-term service agreements at the New England Gas Generation Facilities, and reclassification of Bear Swamp investment credit balance from Investments Subject to Significant Influence
Common stock		141.1		Increased primarily due to issuance of common stock for the dividend reinvestment program and purchase of additional ECI shares
Accumulated other comprehensive loss		(484.1)		Decreased primarily due to the favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries and the amortization of unrecognized pension and post-retirement benefit costs at NSPI
Retained earnings		156.1		Increased due to net income in excess of dividends paid
Non-controlling interest in subsidiaries		(172.7)		Decreased due to increased ownership in ECI

Recent Developments

Emera

Sale of Common Shares of APUC

On May 17, 2016, Emera announced that it had agreed to sell all of its 50.1 million common shares of APUC, representing approximately 19.3% of the issued and outstanding common shares, to a syndicate of underwriters at Cdn$10.85 per common share for an aggregate gross amount of approximately Cdn$544 million. The sale was completed on May 24, 2016. Emera intends to use the net proceeds from the sale in support of its general financing requirements, including the Acquisition. Emera continues to hold an equity interest in APUC equivalent to approximately 12.9 million common shares (in the form of subscription receipts and dividend equivalents), which upon conversion represent a continuing common equity interest of approximately 4.75%.

Pending Acquisition of TECO Energy

On September 4, 2015, the Company announced a definitive agreement for Emera to acquire TECO Energy (NYSE:TE) (the “Acquisition”). TECO Energy shareholders will receive $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.6 billion USD and which includes the assumption of approximately $4.1 billion USD of debt.

TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include: Tampa Electric, an integrated regulated electric utility which serves nearly 725,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution utility which serves nearly 365,000 customers across Florida; and NMGC, a regulated gas distribution utility which serves more than 520,000 customers across New Mexico.

The Acquisition is expected to close mid-2016. Closing of the pending acquisition remains subject to approval by the NMPRC, and the satisfaction of customary closing conditions.

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On April 11, 2016, Emera and TECO Energy filed an unopposed Stipulation Agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of Emera’s proposed Acquisition and the indirect acquisition of NMGC.

The Stipulation Agreement sets out a number of Emera’s commitments including honouring commitments made by TECO Energy in its 2014 acquisition case, investing in the expansion of the natural gas system to underserved communities and the Mexican border, and providing resources to support certain economic growth projects and programs. The Stipulation Agreement is subject to review and approval by the NMPRC. In May, 2016 the hearing examiner held a hearing in connection with the joint application to the NMPRC of the change in control of NMGC affected by the Acquisition. A final order of the NMPRC is expected in mid-2016.

On March 23, 2016, The Committee on Foreign Investment in the United States approval was received.

ECI Amalgamation

On February 24, 2016, the common shareholders of ECI approved an amalgamation transaction, which resulted in an Emera wholly owned subsidiary owning all common shares of ECI. Prior to this, Emera held 95.5% of ECI’s common shares.

To effect the amalgamation, all issued and outstanding common shares of ECI were converted to Class A redeemable preferred shares. In Q1 2016, the Class A redeemable preferred shares of ECI not owned were redeemed. Minority ECI shareholders could elect to receive Cdn$23.26 ($33.30 BBD) in cash per common share (“Cash Offer”) or 2.1 Depositary Receipts (“DR”) per common share, with each DR representing one quarter of a common share of Emera (“DR Offer”); or a combination of the two offers. The total consideration paid to redeem the minority interest was Cdn$15.3 million ($23.4 million BBD), consisting of Cdn$14.4 million of the Cash Offer ($22.0 million BBD) and Cdn$0.9 million of the DR Offer ($1.4 million BBD). The amalgamated entity retained the name Emera (Caribbean) Incorporated.

Convertible Debentures Represented By Instalment Receipts

To finance a portion of the pending Acquisition, Emera, through a direct wholly owned subsidiary (the “Selling Debentureholder”), on September 28, 2015, completed the sale of Cdn$1.9 billion of aggregate principal amount of 4.0% convertible unsecured subordinated debentures, represented by instalment receipts (the “Convertible Debenture Offering”).

On October 2, 2015, in connection with the Convertible Debenture Offering, the underwriters fully exercised an over-allotment option and purchased an additional Cdn$285 million aggregate principal amount of Convertible Debentures at the Convertible Debenture Offering price. The sale of the additional Convertible Debentures brought the aggregate proceeds of the Convertible Debenture Offering to Cdn$2.185 billion, assuming payment of the final instalment.

The Convertible Debentures were sold on an instalment basis at a price of Cdn$1,000 per Convertible Debenture, of which Cdn$333 was paid on closing of the Convertible Debenture Offering and the remaining Cdn$667 (the “Final Instalment”) is payable on a date (“Final Instalment Date”) to be fixed following satisfaction of conditions precedent to the closing of the Acquisition.

Prior to the Final Instalment Date, the Convertible Debentures are represented by instalment receipts. The instalment receipts began trading on the Toronto Stock Exchange (“TSX”) on September 28, 2015 under the symbol “EMA.IR.” The Convertible Debentures will not be listed. The Convertible Debentures will mature on September 29, 2025 and bear interest at an annual rate of 4% per Cdn$1,000 principal amount of Convertible Debentures until and including the Final Instalment Date, after which the interest rate will be 0%. Based on the first instalment of Cdn$333 per Cdn$1,000 principal amount of Convertible Debentures, the effective annual yield to and including the Final Instalment Date is 12%, and the effective annual yield thereafter is 0%.

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If the Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Convertible Debenture Offering, holders of Convertible Debentures who have paid the final instalment on or before the Final Instalment Date will be entitled to receive, on the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, an amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Convertible Debenture Offering had the Convertible Debentures remained outstanding and continued to accrue interest until and including such date (the “Debenture Make-Whole Payment”). No Debenture Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary of the closing of the Convertible Debenture Offering. Under the terms of the instalment receipt agreement, Emera agreed that until such time as the Convertible Debentures have been redeemed in accordance with the foregoing or the Final Instalment Date has occurred, the Company will at all times hold (on a consolidated basis) short-term USD investment grade securities or have cash on hand of not less than the aggregate amount of the first instalment paid on the closing of the Convertible Debenture Offering and the exercise of the over-allotment option, in the event of a mandatory redemption.

At the option of the holders and provided that payment of the Final Instalment has been made, each Convertible Debenture will be convertible into common shares of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of Cdn$41.85 per common share. This is a conversion rate of 23.8949 common shares per Cdn$1,000 principal amount of Convertible Debentures, subject to adjustment in certain events.

Prior to the Final Instalment Date, the Convertible Debentures may not be redeemed by the Company, except that Convertible Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions precedent to the closing of the Acquisition will not be satisfied; (ii) termination of the Acquisition Agreement; and (iii) April 24, 2017, if notice of the Final Instalment Date has not been given to holders on or before April 21, 2017. Upon any such redemption, the Company will pay for each Convertible Debenture: (i) Cdn$333 plus accrued and unpaid interest to the holder of the instalment receipt; and (ii) Cdn$667 to the Selling Debentureholder on behalf of the holder of the instalment receipt in satisfaction of the Final Instalment. In addition, after the Final Instalment Date, any Convertible Debentures not converted may be redeemed by Emera at a price equal to their principal amount plus any unpaid interest which accrued prior to and including the Final Instalment Date.

At maturity, Emera will repay the principal amount of any Convertible Debentures not converted and remaining outstanding in cash. Emera has the right to satisfy the obligation to repay the principal amount due in common shares, which will be valued at 95% of the weighted-average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

The proceeds of the first instalment and the overallotment of the Convertible Debenture Offering were Cdn$727.6 million, or Cdn$681.4 million net of issue costs, and are held and invested in short-term USD investment grade securities. The Convertible Debentures represented by instalment receipts are classified as a current liability on the Consolidated Balance Sheets as the pending Acquisition is expected to close in fiscal 2016. The mark-to-market effect related to the translation of the U.S. foreign currency to Canadian currency is recorded in income, but not reflected in adjusted net income.

The net proceeds of the final instalment payment of the Convertible Debenture Offering are expected to be, in aggregate, approximately Cdn$1.4 billion and will be used, together with the net proceeds of the first instalment payment, to finance, directly or indirectly, the Acquisition and other Acquisition-Related Expenses. To mitigate the foreign currency translation risk associated with the final instalment Emera entered into USD denominated forward contracts, which are recorded on the Consolidated Balance Sheets. The mark-to-market effect on these hedges is reported in the income statement and impacts income, but is not reflected in adjusted income.

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Approximately Cdn$22.1 million (Cdn$15.2 million after-tax) in interest expense associated with the Convertible Debentures was recognized in Q4 2015 and Cdn$22.7 million (Cdn$15.7 million after-tax) was incurred during fiscal 2015 (2014 – nil).

Increase in Common Dividend

On August 10, 2015, Emera’s Board of Directors approved an increase in the annual common share dividend rate from Cdn$1.60 to Cdn$1.90. The first payment was effective November 16, 2015.

Maritime Link Project

On March 6, 2015, NSPML entered into the third of the Maritime Link Project’s three major contracts: construction of approximately 400 kilometres of transmission lines in the provinces of Newfoundland and Labrador and Nova Scotia.

On April 9, 2015, NSPML and the Assembly of Nova Scotia Mi’kmaq Chiefs signed a Socio-Economic Agreement for the Maritime Link Project. Under this agreement, NSPML will support ongoing engagement and commitments made during the Environmental Assessment process, including Mi’kmaq participation in environmental monitoring and employment and business opportunities for Mi’kmaq people.

Emera Maine

Return on Equity (“ROE”) Complaints

On March 3, 2015, the FERC affirmed its June 19, 2014 order approving an ROE on transmission assets of 10.57% for the period October 1, 2011 to December 31, 2012. This order is in respect of the ROE complaint filed with the FERC by the Attorney General of Massachusetts and other parties on September 30, 2011. The March 3, 2015 order is subject to appeal, and a decision is not expected until Q1 2016 at the earliest.

Recent Financing Activity

Emera

On July 3, 2015, Emera announced it would not redeem the 6,000,000 Cumulative 5-Year Rate Reset First Preferred Shares, Series A Shares (the “Series A First Preferred Shares”).

On August 17, 2015, Emera announced that 2,135,364 of its 6,000,000 issued and outstanding Series A First Preferred Shares were tendered for conversion, on a one-for-one basis into Cumulative Floating Rate First Preferred Shares, Series B (the “Series B First Preferred Shares”). As a result of the conversion, Emera has 3,864,636 Series A First Preferred Shares and 2,135,364 Series B First Preferred Shares issued and outstanding. The holders of Series B First Preferred Shares will be entitled to receive floating rate cumulative preferred cash dividends, as and when declared by the Board of Directors. The dividends are payable quarterly in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-bill Rate on the applicable reset date plus 1.84%, by Cdn$25.00.

NSPI

On April 28, 2016, NSPI increased its committed syndicated revolving bank line of credit to Cdn$600 million from Cdn$500 million. The increase will support ongoing business requirements and general corporate purposes.

NSPI Series I Cdn$70 million 8.40% medium-term notes (“MTN”) matured on October 23, 2015 and were repaid.

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On October 15, 2015, NSPI redeemed all of its outstanding Cumulative Redeemable First Preferred Shares, Series D for a redemption price of Cdn$25.00 per share for a total of Cdn$135 million.

On April 30, 2015, NSPI completed the issuance of Cdn$175 million Series AA MTN. The Series AA MTN bear interest at a rate of 3.612% per annum until May 1, 2045. The proceeds of the note offering were used for general corporate purposes, including the repayment of maturing corporate term debt.

EBPC

On February 18, 2015, EBPC completed a senior secured financing consisting of a Cdn$250 million non-revolving term credit facility bearing interest at bankers’ acceptances rates plus 1.75% and expiring on February 18, 2019. The proceeds were used to reduce borrowings under Emera’s revolver, which was previously used to finance the maturity and repayment of an MTN in October 2014.

Emera Energy

On October 8, 2015, Bear Swamp refinanced its $125 million USD bank debt that was due to mature in 2017 and issued $400 million USD in senior secured 10-year bonds, with $375 million USD at a fixed rate of 4.89%, and $25 million USD at a floating rate of LIBOR plus 2.70%. The proceeds of this financing were used to repay existing debt and provide working capital to the joint venture, with the remainder shared equally between Emera and its joint venture partner. After fees and expenses, Emera received a Cdn$178.7 million ($137.3 million USD) non-taxable distribution in Q4 2015.

Appointments

Executive

On January 15, 2016, Greg Blunden was appointed Chief Financial Officer (“CFO”) of Emera, effective March 1, 2016. Mr. Blunden has held financial leadership roles at Emera, Emera Maine and NSPI. Most recently, Mr. Blunden was Vice President, Corporate Strategy & Planning.

On January 15, 2016, Emera’s current CFO, Scott Balfour, was appointed Chief Operating Officer, Northeast and Caribbean, effective March 1, 2016. Mr. Balfour will provide senior executive leadership for Emera’s existing operations, including NSPI, Emera Energy, Emera Maine, Emera Caribbean, EBPC and Emera Utility Services.

On January 15, 2016, Wayne O’Connor was appointed Vice President, Corporate Strategy & Planning for Emera, effective March 1, 2016. Mr. O’Connor will coordinate Emera’s planning and strategy development efforts to grow and expand the Company’s business. Previously, he was Executive Vice- President of Operations at NSPI.

On September 22, 2015, Rob Bennett was appointed President and Chief Executive Officer of Merger Sub, to lead the integration of TECO Energy. Previously, Mr. Bennett had been the Chief Operating Officer, Eastern Canada.

On August 31, 2015, Roman Coba was appointed Chief Information Officer of Emera.

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Outstanding Common Stock Data

Common stock issued and outstanding:	Millions of shares		Millions of Canadian dollars
December 31, 2014		143.78	$	2,016.4
Issuance of common stock(1)		1.25		53.7
Issued for cash under Purchase Plans at market rate		2.10		88.3
Discount on shares purchased under Dividend Reinvestment Plan		—		(4.1	)
Options exercised under senior management stock option plan		0.08		2.3
Employee Share Purchase Plan		—		0.9
December 31, 2015		147.21	$	2,157.5
Issuance of common stock(1)		0.06		2.7
Issued for cash under Purchase Plans at market rate		0.58		26.2
Discount on shares purchased under Dividend Reinvestment Plan		—		(1.2	)
Options exercised under senior management stock option plan		0.50		13.6
Employee Share Purchase Plan		—		0.2
March 31, 2016		148.35	$	2,199.0

(1) During the three months ended March 31 2016, Emera issued 0.06 million (2015 - 1.25 million) common shares to facilitate the creation and issuance of an additional 0.2 million (2015 - 5 million) depositary receipts in connection with the ECI amalgamation transaction. The depositary receipts are listed on the Barbados Stock Exchange.

As at April 25, 2016, the amount of issued and outstanding common shares was 148.4 million.

The weighted average shares of common stock outstanding—basic, which includes both issued, outstanding common stock and outstanding deferred share units, for the three months ended March 31, 2016 was 148.7 million (2015 – 144.9 million).

NSPI

Overview

NSPI was created in 1992 through the privatization of the Crown corporation Nova Scotia Power Corporation (“NSPC”). NSPI is a fully-integrated regulated electric utility and is the primary electricity supplier in Nova Scotia, Canada. NSPI has Cdn$4.6 billion of assets and provides electricity generation, transmission and distribution services to approximately 507,000 customers. NSPI owns 2,483 MW of generating capacity, of which approximately 50% is coal-fired; 28% of which is natural gas and/or oil; 19% of which is hydro and wind and 3% of which is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from independent power producers (“IPP”). These IPPs own and operate 496 MW of wind and biomass fueled generation capacity, which will increase to 552 MW in 2016. NSPI also owns approximately 5,000 kilometres of transmission facilities and 27,000 kilometres of distribution facilities. NSPI has a workforce of approximately 1,700 people.

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings from time to time at its request or at the UARB’s request.

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NSPI is regulated under a cost-of-service model, with rates established to recover prudently incurred costs of providing electricity service to customers, and to provide an appropriate return to investors. NSPI’s target regulated return on equity range is currently 8.75% to 9.25%, based on an actual five-quarter average regulated common equity component of up to 40.0%.

NSPI has a fuel adjustment mechanism (“FAM”), approved by the UARB, allowing NSPI to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. Differences between prudently incurred fuel for generation and purchased power and certain fuel-related costs (“Fuel Costs”) and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

A settlement agreement, approved by the UARB in November 2014, resulted in approximately Cdn$56.0 million of the outstanding FAM regulatory asset balance from the prior year being collected in 2015. Residential customers did not experience a rate increase in 2015, as the FAM recovery of approximately Cdn$56.0 million was offset with the removal of charges previously included in NSPI billings. The charges were on behalf of Efficiency Nova Scotia, a program run by the Province of Nova Scotia and regulated by the UARB. Certain industrial customer classes experienced rate increases of approximately 1.5% in 2015.

On December 21, 2015, the UARB approved NSPI’s setting of the 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as submitted in NSPI’s August and November 2015 filings. The recovery of these costs will begin January 1, 2016. The approved customer rates reset the base cost of fuel rate for 2016 and seek to recover Cdn$13.7 million of prior years’ unrecovered Fuel Costs in 2016. This results in a combined rate decrease for customers of approximately 1%.

In December 2015, the Electricity Plan Implementation (2015) Act (the “Electricity Plan Act”) was enacted by the Province of Nova Scotia. Further information is included in the “—Regulated Fuel Adjustment Mechanism and Fixed Cost Deferrals” section.

Although the market in Nova Scotia is otherwise mature, the transformation of energy supply to lower emission sources has driven organic growth within NSPI as new investments have been made in renewable generation and system reliability projects.

The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix. The most recent target, for years 2015 through 2019, is 25% of electrical energy which will be derived from renewable sources. This target was met for 2015, with 27% of NSPI’s generation mix derived from renewable sources. In 2020, the target is 40% of electrical energy to be derived from renewable sources.

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Review of 2016 and 2015

NSPI Net Income

	Three months ended March 31					Year ended December 31
	2016		2015			2015		2014		2013
	millions of Canadian dollars (except per share amounts)
Operating revenues – regulated	$	397.5	$	446.5		$	1,417.3	$	1,348.2	$	1,334.9
Regulated fuel for generation and purchased power(1)		141.5		189.4			542.8		511.7		556.9
Regulated fuel adjustment mechanism and fixed cost deferrals		17.6		(7.2	)		41.6		46.6		(40.8	)
Operating, maintenance and general		87.4		79.6			298.1		273.6		272.3
Provincial grants and taxes		9.7		9.6			38.5		38.3		37.7
Depreciation and amortization		48.4		51.5			206.5		204.0		213.8
Total operating expenses		304.6		322.9			1,127.5		1,074.2		1,039.9
Income from operations		92.9		123.6			289.8		274.0		295.0
Other expenses net(2)		1.3		3.8			5.7		5.0		7.1
Interest expense, net		31.0		28.8			122.1		116.5		119.6
Income before provision for income taxes		60.6		91.0			162.0		152.5		168.3
Income tax expense (recovery)		8.1		21.0			23.4		19.7		34.4
Net income of Nova Scotia Power Inc.		52.5		70.0			138.6		132.8		133.9
Preferred stock dividends(3)		—		2.0			8.7		7.9		7.9
Contribution to consolidated net income		52.5		68.0			129.9		124.9		126.0
Contribution to consolidated earnings per common share		0.35		0.47			0.89		0.87		0.95
EBITDA(4)	$	140.0	$	171.3		$	490.6	$	473.0	$	501.7

(1) Regulated fuel for generation and purchased power includes affiliate transactions and proceeds from the sale of natural gas.

(2) Other expenses, net is included in “Other income (expenses), net” on the Consolidated Statements of Income.

(3) Preferred stock dividends are included in “Non-controlling interest in subsidiaries” on the Consolidated Statements of Income. In Q4 2015, NSPI redeemed its preferred shares.

(4) A non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures.”

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In Q1 2016, NSPI’s contribution to consolidated net income decreased Cdn$15.5 million to Cdn$52.5 million compared to Cdn$68.0 million in Q1 2015.

Highlights of the changes are summarized in the following table:

	Three months ended March 31
	millions of Canadian dollars
Contribution to consolidated net income–2015	$	68.0
Decreased electric margin (see Electric Margin section below for explanation)		(19.5	)
Increased operating, maintenance and general (“OM&G”) expenses primarily due to higher maintenance and storm costs, partially offset by decreased demand side management (“DSM”) program costs		(7.8	)
Decreased fixed cost deferrals primarily due to 2015 DSM regulatory deferral, partially offset by a reduction in the amount of non-fuel revenues deferred		(5.6	)
Decreased income taxes primarily due to decreased income before provision for income taxes		12.9
Decreased depreciation and amortization primarily due to a lower regulatory amortization as a result of a fixed cost deferral from 2012 being fully amortized in 2015		3.1
Other, net(1)		1.4
Contribution to consolidated net income–2016	$	52.5

NSPI’s contribution to consolidated net income increased Cdn$10.0 million to Cdn$40.1 million in Q4 2015 compared to Cdn$30.1 million in Q4 2014. For the year ended December 31, 2015, NSPI’s contribution to consolidated net income increased Cdn$5.0 million to Cdn$129.9 million in 2015 compared to Cdn$124.9 million in 2014.

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Highlights of the changes are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of Canadian dollars
Contribution to consolidated net income–2013				$	126.0
Increased electric margin primarily due to increased non-fuel electric revenues across all customers groups as a result of increased electricity pricing, partially offset by the FAM audit disallowance					15.8
Decreased fixed cost deferrals primarily due to an increase in the non-fuel revenues and lower depreciation and amortization					(43.2	)
Decreased depreciation and amortization primarily due to reductions in regulatory amortization (see Regulatory Amortization section below for explanation)					9.8
Decreased interest expense, net primarily due to lower levels of long-term debt					3.1
Decreased income tax expense primarily due to increased tax deductions related to higher pension contributions for 2014, decreased income before provision for income taxes and decreased non-deductible regulatory amortization, partially offset by a non-recurring change in unrecognized tax benefits in 2013 due to the enactment of tax legislation related to preferred stock dividends					14.7
Other, net(1)					(1.3	)
Contribution to consolidated net income–2014	$	30.1		$	124.9
Increased electric margin (see Electric Margin section below for explanation)		0.5			13.0
Increased fixed cost deferrals year-over-year primarily due to the new DSM regulatory deferral commencing in 2015, partially offset by an increase in the amount of non-fuel revenues deferred compared to 2014		(1.7	)		30.5
Decreased OM&G expenses quarter-over-quarter primarily due to non-recurring 2014 expenses and increased overhead credits on capital projects, partially offset by higher pension and DSM costs; year-over-year increase is primarily due to increased DSM program costs as a results of legislation, effective January 1, 2015, requiring NSPI to purchase electricity efficiency and conservation activities and higher pension costs, partially offset by lower storm costs		2.7			(24.5	)
Increased interest expense, net primarily due to lower interest revenues related to FAM and fixed cost deferrals and higher debt levels		(1.4	)		(5.6	)
Decreased income tax expense quarter-over-quarter primarily due to a legislated change by the Province of Nova Scotia to the deferred tax treatment of South Canoe and Sable wind farms resulting in prior period deferred income taxes being recorded as regulatory assets in Q4 2015; year-over-year increase primarily due to increased income before provision for income taxes		11.9			(3.7	)
Other, net(1)		(2.0	)		(4.7	)
Contribution to consolidated net income–2015	$	40.1		$	129.9

(1) Amounts exclude variances included in the calculation of electric margin.

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Operating Revenues—Regulated

NSPI’s Operating Revenues—regulated include sales of electricity and other services as summarized in the following table:

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014		2013
	millions of Canadian dollars
Electric revenues	$	391.7	$	440.0	$	1,389.1	$	1,319.2	$	1,304.3
Other revenues		5.8		6.5		28.2		29.0		30.6
Operating revenues – regulated	$	397.5	$	446.5	$	1,417.3	$	1,348.2	$	1,334.9

Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population, weather, and DSM activities. Residential and commercial electricity sales are seasonal, with Q1 being the strongest period, reflecting colder weather and fewer daylight hours in the winter.

NSPI’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other electric revenues consist primarily of sales to municipal electric utilities and revenues from street lighting.

Electric sales volumes are summarized in the following tables by customer class:

Q1 Electric Sales Volumes

Gigawatt hours (“GWh”)

	2016		2015		2014
Residential		1,431		1,589		1,568
Commercial		840		919		883
Industrial		578		602		601
Other		79		111		90
Total		2,928		3,221		3,142

Annual Electric Sales Volumes

GWh

	2015		2014		2013
Residential		4,484		4,370		4,394
Commercial		3,134		3,092		3,148
Industrial		2,457		2,513		2,605
Other		337		312		320
Total		10,412		10,287		10,467

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Electric revenues are summarized in the following tables by customer class:

Q1 Electric Revenues

	2016		2015		2014
	millions of Canadian dollars
Residential	$	223.4	$	248.2	$	232.8
Commercial		109.2		119.4		109.1
Industrial		48.1		57.9		55.8
Other		11.0		14.5		13.3
Total	$	391.7	$	440.0	$	411.0

Electric revenues decreased Cdn$48.3 million to Cdn$391.7 million in Q1 2016 compared to Cdn$440.0 million in Q1 2015. Highlights of the changes are summarized in the following table:

	Three months ended March 31
	millions of Canadian dollars
Electric revenues – 2015	$	440.0
Decreased fuel related electricity pricing effective January 1, 2016		(3.8	)
Decreased commercial and residential sales volume due to weather		(31.5	)
Decreased industrial sales volume		(9.6	)
Other		(3.4	)
Electric revenues – 2016	$	391.7

Annual Electric Revenues

Millions of Canadian dollars

	2015		2014		2013
Residential	$	716.0	$	669.3	$	654.0
Commercial		410.0		387.3		383.9
Industrial		213.8		213.9		218.0
Other		49.3		48.7		48.4
Total	$	1,389.1	$	1,319.2	$	1,304.3

Electric revenues increased Cdn$8.6 million to Cdn$333.5 million in Q4 2015 compared to Cdn$324.9 million in Q4 2014. For the year ended December 31, 2015, electric revenues increased Cdn$69.9 million to Cdn$1,389.1 million compared to Cdn$1,319.2 million in the same period in 2014. Highlights of the changes are summarized in the following table:

	Three months ended December 31	Year ended December 31
	millions of Canadian dollars
Electric revenues – 2013		$	1,304.3
Increased electricity pricing effective January 1, 2014			37.9
Decreased commercial and residential sales volumes, in part due to weather			(12.5	)
Decreased industrial sales volume			(9.4	)
Other			(1.1	)

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	Three months ended December 31			Year ended December 31
	millions of Canadian dollars
Electric revenues – 2014	$	324.9		$	1,319.2
Increased fuel related electricity pricing effective January 1, 2015		13.4			56.0
Decreased commercial and residential sales volumes as a result of decreased load quarter-over-quarter; increased commercial and residential sales volumes year-over-year primarily due to weather and load growth earlier in the year		(4.1	)		19.9
Decreased industrial sales volume		(0.6	)		(5.2	)
Other		(0.1	)		(0.8	)
Electric revenues – 2015	$	333.5		$	1,389.1

Regulated Fuel for Generation and Purchased Power

Capacity

To ensure reliability of service, NSPI must maintain a generating capacity greater than firm peak demand. The total NSPI-owned generation capacity is 2,483 MW, which is supplemented by 496 MW contracted with IPPs and the Community Feed-In Tariff (“COMFIT”) participants. NSPI meets the planning criteria for reserve capacity established by the Maritime Control Area and the Northeast Power Coordinating Council.

NSPI facilities continue to rank among the best in Canada on performance indicators. The high availability and capability of low cost thermal generating stations provide lower-cost energy to customers. In 2015, thermal plant availability was 87.9% compared to 84.2% in 2014. NSPI’s four-year average for thermal plant availability is 85.1%. While this availability is in line with industry standards, it is particularly significant, as the NSPI coal fleet has a higher capacity factor and better forced outage rate than the standard for its class. In addition, the Company has seen performance improvements in 2015, despite the effects of renewable integration.

Q1 Production Volumes

GWh

	2016		2015		2014
Coal and petroleum coke (“petcoke”)		1,688		2,248		2,273
Natural gas		285		164		179
Oil		141		249		135
Purchased power – other		95		87		47
Total non-renewables		2,209		2,748		2,634
Wind and hydro – renewables		406		384		416
Purchased power – renewables, including IPP and COMFIT		469		317		254
Biomass – renewables		70		52		53
Total renewables		945		753		723
Total production volumes		3,154		3,501		3,357

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Annual Production Volumes

GWh

	2015		2014		2013
Coal and petcoke		6,364		6,609		7,098
Natural gas		1,302		1,468		1,317
Oil		265		153		89
Purchased power – other		428		353		491
Total non-renewables		8,359		8,583		8,995
Wind and hydro – renewables		1,275		1,357		1,234
Biomass – renewables		206		258		130
Purchased power – renewables		1,289		849		845
Total renewables		2,770		2,464		2,209
Total production volumes		11,129		11,047		11,204

Q1 Average Fuel Costs

	2016		2015		2014
Dollars per megawatt hour produced	$	45	$	54	$	51

Annual Average Fuel Costs

	2015		2014		2013
Dollars per megawatt hour	$	49	$	46	$	50

Average unit fuel costs decreased in Q1 2016 compared to Q1 2015 primarily due to decreased commodity pricing and decreased load, requiring less generation to be sourced from higher cost alternatives.

Year-over-year, average unit Fuel Costs increased in 2015 compared to the same period in 2014 primarily due to generation costs associated with the COMFIT program and increased load, partially offset by favourable commodity pricing.

NSPI’s Fuel Costs are affected by commodity prices and generation mix which is largely dependent on economic dispatch of the generating fleet, bringing the lowest cost options on stream first (after renewable energy from independent power producers, including COMFIT participants), such that the incremental cost of production increases as sales volumes increase. Generation mix may also be affected by plant outages, availability of renewable generation, plant performance and compliance with environmental standards and regulations.

Historically, coal and petcoke have the lowest per unit fuel cost, after NSPI-owned regulated hydro and wind, which have no fuel cost component. Purchased power, natural gas, oil and biomass have the next lowest fuel cost, depending on the relative pricing of each.

The generation mix is transforming with the addition of new non-dispatchable renewable energy sources such as wind, which typically has a higher cost per megawatt hour.

A large portion of NSPI’s fuel supply comes from international suppliers and is subject to commodity price and foreign exchange risk. NSPI seeks to manage this risk through the use of financial hedging instruments and physical contracts and utilizes a portfolio strategy for fuel procurement with a combination of long, medium, and short-term supply agreements. It also provides for supply and supplier diversification. Foreign exchange risk is managed through forward and swap contracts. Fuel contracts may also be exposed to broader global conditions

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which may include impacts on delivery reliability and price, despite contracted terms. NSPI has a FAM that enables the Company to seek recovery of Fuel Costs to further manage this risk.

Regulated fuel for generation and purchased power decreased Cdn$47.9 million to Cdn$141.5 million in Q1 2016 compared to Cdn$189.4 million in Q1 2015. Highlights of the changes are summarized in the following table:

	Three months ended March 31
	millions of Canadian dollars
Regulated fuel for generation and purchased power – 2015	$	189.4
Change in generation mix		11.2
Decreased commodity prices		(38.2	)
Decreased sales volumes		(18.3	)
Other		(2.6	)
Regulated fuel for generation and purchased power – 2016	$	141.5

Regulated fuel for generation and purchased power increased Cdn$5.0 million to Cdn$132.4 million in Q4 2015 compared to Cdn$127.4 million in Q4 2014. For the year ended December 31, 2015, regulated fuel for generation and purchased power increased Cdn$31.1 million to Cdn$542.8 million compared to Cdn$511.7 million in 2014. Highlights of the changes are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of Canadian dollars
Regulated fuel for generation and purchased power – 2013				$	556.9
Decreased commodity prices					(29.0	)
Changes in generation mix and plant performance					(11.1	)
Decreased sales volumes					(8.8	)
Increased hydro and NSPI-owned wind production					(8.1	)
Changes in solid fuel mix					14.4
Other					(2.6	)
Regulated fuel for generation and purchased power – 2014	$	127.4		$	511.7
Decreased commodity prices		(6.6	)		(38.3	)
Changes in generation mix and plant performance		8.5			51.1
Increased (decreased) sales volumes		(1.5	)		10.6
Increased hydro and NSPI-owned wind production		5.0			3.0
Other		(0.4	)		4.7
Regulated fuel for generation and purchased power – 2015	$	132.4		$	542.8

Regulated Fuel Adjustment Mechanism and Fixed Cost Deferrals

Regulated Fuel Adjustment Mechanism and FAM Regulatory Deferral

NSPI has a Fuel Adjustment Mechanism which enables the Company to seek recovery of Fuel Costs through regularly scheduled rate adjustments. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates in a given year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

The FAM is subject to an incentive, with NSPI retaining or absorbing 10% of the over or under-recovered to a maximum of Cdn$5 million. The incentive was suspended for 2012 to 2015, as a result of UARB approved settlement agreements and is in effect for 2016.

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In December 2015, the UARB approved NSPI’s 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as submitted in NSPI’s filings. Approved customer rates reset the base cost of fuel rate for 2016 and seek to recover Cdn$13.7 million of prior years’ unrecovered Fuel Costs in 2016. Recovery of these costs began January 1, 2016.

On December 18, 2015, the “Electricity Plan Act” was enacted by the Province of Nova Scotia. In accordance with the Electricity Plan Act, NSPI filed with the UARB, on March 7, 2016, a three-year rate plan for Fuel Costs, requesting an average increase of 1.3% for 2017 through 2019. A hearing is scheduled for June 13, 2016. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates during this period will be deferred to a FAM regulatory asset or liability and recovered from or returned to customers subsequent to 2019.

The Electricity Plan Act further directed NSPI to apply any non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of tax benefits for the South Canoe and Sable Wind Projects is to be reserved and applied to the FAM to be used in the 2017 to 2019 period. The exception to this direction is application of a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would otherwise have been required. This amount totals Cdn$4.6 million. Therefore, as at December 31, 2015, NSPI had deferred Cdn$4.6 million of excess non-fuel revenues to 2016 and Cdn$40.1 million of excess non-fuel revenues for the periods 2017 to 2019.

In Q1 2016, NSPI applied Cdn$3.8 million of non-fuel revenues to the FAM for periods 2017 to 2019. This was as a result of applying the tax benefits associated with the South Canoe and Sable Wind Projects, as directed by the Electricity Plan Act.

In November 2014, the UARB approved a settlement agreement that has resulted in Cdn$56.0 million of the 2014 outstanding FAM balance being collected in 2015. The settlement agreement also reduced the outstanding FAM balance of Cdn$86.1 million by Cdn$38.2 million through an offset from the amount owing to customers as a result of an agreement to allocate non-fuel revenues above NSPI’s allowed range of return to the FAM balance, such that the December 31, 2014 FAM regulatory asset was Cdn$47.9 million.

Through a related settlement agreement with stakeholders approved in December 2014, NSPI agreed to apply non-fuel revenues above that required to achieve its approved range of return to reduce the FAM deferral account. This was effective as of January 1, 2015, until the next General Rate Application (“GRA”) approval or similar process where non-fuel rates are adjusted. This settlement agreement required NSPI to contribute a minimum of Cdn$41.3 million to the FAM deferral account by the end of 2015.

As at December 31, 2015, NSPI had exceeded the minimum required contribution of Cdn$41.3 million through the Cdn$38.2 million contributed in 2014, referred to above, and an additional Cdn$44.7 million applied in 2015. Of the Cdn$44.7 million applied in 2015, Cdn$18.3 million relates to changes to the South Canoe and Sable Wind Projects tax treatment.

Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. On July 2, 2014, the FAM audit findings and recommendations relating to fiscal 2012 and 2013 were publicly released, and on January 20, 2015, the UARB disallowed Cdn$6.0 million of 2012 and 2013 fuel-related costs, which included interest of Cdn$0.9 million. The disallowance resulted in a reduction in the amount of FAM deferral in 2014 and resulted in an after-tax impact to 2014 net income of Cdn$3.3 million. The audit for fiscal 2014 and 2015 is currently underway.

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The FAM included in the Statements of Income includes the effect of Fuel Costs in both the current and preceding years, specifically, and as detailed in the table below:

• The difference between actual Fuel Costs and amounts recovered from customers in the current year. This amount, net of the incentive component, is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities” on the Balance Sheets; and

• The recovery from (rebate to) customers of under (over) recovered Fuel Costs from prior years.

The FAM regulatory asset (liability) includes amounts recognized as a regulated fuel adjustment mechanism and associated interest that is included in “Interest expense, net” on the Consolidated Statements of Income. Details of the FAM regulatory asset (liability), classified in “Regulatory assets” or “Regulatory liabilities” on the Consolidated Balance Sheets, are summarized in the following tables:

	2016
	millions of Canadian dollars
FAM regulatory liability – Balance as at January 1	$	(28.3	)
Under (over) recovery of current period Fuel Costs		(10.0	)
Rebate to (recovery from) customers of prior years’ Fuel Costs		(3.8	)
Interest on FAM balance		(0.7	)
Application of non-fuel revenues		(3.8	)
FAM regulatory liability – Balance as at March 31	$	(46.6	)

	2015			2014
	millions of Canadian dollars
FAM regulatory asset – Balance as at January 1	$	47.9		$	86.4
Under (over) recovery of current year Fuel Costs		24.1			(1.3	)
Rebate to (recovery from) customers of prior years’ Fuel Costs		(56.0	)		—
FAM audit disallowance, including interest adjustment		—			(6.0	)
Application of non-fuel revenues		(44.7	)		(38.2	)
Interest on FAM balance		0.4			7.0
FAM regulatory asset (liability) – Balance as at December 31	$	(28.3	)	$	47.9

Of the Cdn$44.7 million non-fuel revenues applied in 2015, Cdn$40.1 million is to be applied to the FAM during the 2017 to 2019 period and Cdn$4.6 million will be applied in 2016.

Regulated Fixed Cost Deferrals and Fixed Cost Recovery Deferral Regulatory Assets

NSPI has the following regulatory assets arising from UARB approved fixed cost deferral mechanisms:

DSM Deferral

In April 2014, the Government of Nova Scotia announced new energy efficiency legislation to remove a previous charge for conservation and efficiency programs from power bills of Nova Scotia customers effective January 1, 2015. In addition, the legislation requires NSPI to purchase electricity efficiency and conservation activities (the “DSM Program Costs”) from EfficiencyOne, the provincially appointed franchisee to deliver energy efficiency programs to Nova Scotians. The DSM Program Costs were set for 2015 at Cdn$35.0 million and have been deferred as a regulatory asset and recoverable from customers over an eight-year period beginning in 2016. In August 2015, the UARB approved a budget of Cdn$102.0 million for the three- year period of 2016 through 2018. The Electricity Plan Act has placed a cap of Cdn$34.0 million on the 2019 DSM spending. The 2016 DSM cost of Cdn$24.7 million will not be deferred. A decision of the timing of the cost recovery for 2017 through 2019 will be made at a future date.

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The DSM Program Costs are recorded in “OM&G,” with an offsetting credit in “Regulated fuel adjustment mechanism and fixed cost deferrals” on Emera’s Consolidated Income Statements, with no effect on net earnings, with the exception of interest on the balance.

Details of the DSM regulatory asset, classified in “Regulatory assets” on the Consolidated Balance Sheets, are summarized in the following table:

	2015
	millions of Canadian dollars
DSM regulatory asset – Balance as at January 1	$	—
Current period DSM Program Costs		35.0
Interest on DSM balance		1.4
DSM regulatory asset – Balance as at December 31	$	36.4

2013/2014 Rate Stabilization Fixed Cost Recovery Deferral

In December 2012, the UARB approved a deferral of recovery of certain fixed costs for fiscal 2013 and 2014 as part of a rate stabilization plan. As previously noted above under the Regulated Fuel Adjustment Mechanism, the resulting regulatory liability at the end of 2014 of Cdn$38.2 million was applied against the FAM regulatory asset balance in 2014 and is included in the application of non-fuel revenues line in the table above.

Electric Margin

NSPI distinguishes electric revenues related to the recovery of Fuel Costs (“Fuel Electric Revenues”) from revenues related to the recovery of non-fuel costs (“Non-Fuel Electric Revenues”) because the FAM effectively seeks to recover all prudently incurred fuel costs, and consequently, Fuel Costs and related revenues do not have a material effect on NSPI’s electric margin or net income, with the exception of the incentive component of the FAM, whereby NSPI retains or absorbs 10% of the over or under recovered amount to a maximum of Cdn$5 million.

Electric margin (a non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP—Electric Margin Reconciliation”) is influenced primarily by revenues relating to non-fuel costs. NSPI’s customer classes contribute differently to NSPI’s Non-Fuel Electric Revenues, with residential and commercial customers contributing more than industrial customers under current rates. Accordingly, changes in residential and commercial load, largely due to the effects of weather, from general economic conditions and from DSM have the largest effect on Non-Fuel Electric Revenues and electric margin. Changes in industrial load, which are generally due to economic conditions, have less of an effect on Non-Fuel Electric Revenues than would a similar volume change in residential and commercial load.

The addition of new generation sources to meet legislated greenhouse gas emission reductions and renewable generation requirements is among the drivers increasing NSPI’s fixed costs. Electric margin, which represents revenues available to cover these costs, has increased in a corresponding manner.

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Operating revenues are summarized in the following table:

	Three months ended March 31						Year ended December 31
	2016			2015			2015			2014(1)			2013(1)
	millions of Canadian dollars
Fuel Electric Revenues – current year	$	152.0		$	165.7		$	518.5		$	512.5		$	488.7
Fuel Electric Revenues – recovery of preceding years		3.8			18.2			56.0			—			29.8
Non-Fuel Electric Revenues		235.9			256.1			814.6			806.7			785.8
Other revenues		5.8			6.5			28.2			29.0			30.6
Operating revenues	$	397.5		$	446.5		$	1,417.3		$	1,348.2		$	1334.9
Electric margin is summarized in the following table:
Fuel Electric Revenues – current year	$	152.0		$	165.7		$	518.5		$	512.5		$	488.7
Fuel Electric Revenues – recovery of preceding years		3.8			18.2			56.0			—			29.8
Total Fuel Electric Revenues		155.8			183.9			574.5			512.5			518.5
Regulated fuel for generation and purchased power		(141.5	)		(189.4	)		(542.8	)		(511.7	)		(556.9	)
Regulated fuel adjustment mechanism		(13.8	)		5.4			(31.9	)		(6.4	)		37.8
Fuel-related foreign exchange gain (loss)(2)		0.2			0.1			0.2			0.5			0.6
Net fuel revenue (expense)		0.7			—			—			(5.1	)		—
Non-Fuel Electric Revenues		235.9			256.1			814.6			806.7			785.8
Electric margin	$	236.6		$	256.1		$	814.6		$	801.6		$	785.8

(1) NSPI removed “Fixed cost deferrals” from its calculation of electric margin in Q2 2014 as management believed it better reflected its business operations. Prior periods have been retroactively restated.

(2) As reported in “Other income (expenses) net,” on the Consolidated Statement of Income.

NSPI’s electric margin decreased Cdn$19.5 million to Cdn$236.6 million in Q1 2016 compared to Cdn$256.1 million in Q1 2015 due to decreased Non-Fuel Electric Revenues primarily due to decreased residential and commercial sales reflecting decreased load, primarily due to weather. NSPI’s electric margin for the year ended December 31, 2015 increased Cdn$13.0 million to Cdn$814.6 million compared to Cdn$801.6 million in 2014 primarily due to increased residential load, largely due to weather and a FAM audit disallowance in 2014.

Q1 Average Electric Margin/MWh

	2016		2015		2014
Dollars per MWh sold	$	81	$	80	$	80

Annual Average Electric Margin/MWh

	2015		2014		2013
Dollars per MWh	$	78	$	78	$	75

NSPI’s electric margin per MWh is consistent quarter-over-quarter and year-over-year.

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Regulatory Amortization

Regulatory amortization is included in “Depreciation and amortization” on the Consolidated Statements of Income. Highlights of the changes in regulatory amortization are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of Canadian dollars
Regulatory amortization – 2013				$	37.4
Decreased pre-2003 income tax regulatory asset amortization(1)					(14.0	)
2012 Large Industrial Customers FCR amortization, which commenced in 2013, following the 2013 General Rate Application settlement agreement					2.4
Other regulatory amortization					(0.9	)
Regulatory amortization – 2014	$	8.9		$	24.9
Decreased 2012 Large Industrial Customers Fixed Cost Recovery amortization, which commenced in 2013, following the 2013 General Rate Application settlement agreement		(2.7	)		(2.7	)
Other regulatory amortization		(1.6	)		(1.4	)
Regulatory amortization – 2015	$	4.6		$	20.8

(1) The UARB’s 2010 ROE decision has allowed NSPI flexibility in the recognition of additional amortization of the pre-2003 income tax regulatory asset in current periods, which accordingly reduces amortization in future periods resulting in a lower customer rate requirement.

Provincial Grants and Taxes

NSPI pays annual grants to the Province of Nova Scotia in lieu of municipal taxation other than deed transfer tax.

Income Taxes

NSPI is subject to corporate income tax at the statutory rate of 31.0% (combined federal and provincial income tax rate) and Part VI.1 tax relating to preferred stock dividends at the statutory rate of 40.0%. NSPI also receives a reduction in its corporate income tax otherwise payable related to the Part VI.1 tax deduction of 43.4% of preferred stock dividends.

Non-U.S. GAAP Measure

Electric Margin Reconciliation

“Electric margin” is a non-U.S. GAAP financial measure used to show the amounts that NSPI retains to recover its non-fuel costs, as effectively all prudently incurred Fuel Costs are recovered through the FAM. NSPI’s electric margin may not be comparable to other companies’ electric margin measures, but in management’s view appropriately reflects NSPI’s regulatory framework. This measure is not intended to replace “Income from operations” which, as determined in accordance with U.S. GAAP, is an indicator of operating performance. Electric margin was discussed in the Financial Review Electric Margin section above.

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	Three months ended March 31					Year ended December 31
	2016		2015			2015		2014(1)		2013(1)
	millions of Canadian dollars
Income from operations	$	92.9	$	123.6		$	289.8	$	274.0	$	295.0
Less:
Fuel Electric Revenues – current and preceding years		155.8		183.9			574.5		512.5		518.5
FAM audit disallowance		—		—			—		5.1		—
Other revenues		5.8		6.5			28.2		29.0		30.6
Add back:
Regulated fuel for generation and purchased power		141.5		189.4			542.8		511.7		556.9
Operating, maintenance and general		87.4		79.6			298.1		273.6		272.3
Property, state and municipal taxes(1)		9.7		9.6			38.5		38.3		37.7
Depreciation and amortization(2)		48.4		51.5			206.5		204.0		213.8
Regulated fuel adjustment mechanism and fixed		17.6		(7.2	)		41.6		46.6		(40.8	)
Other fuel related costs		0.7		—			—		—		—
Electric margin	$	236.6	$	256.1		$	814.6	$	801.6	$	785.8

Emera Maine

Overview

Emera Maine is a transmission and distribution electric utility with assets of approximately Cdn$1.1 billion serving approximately 158,000 customers in the State of Maine in the United States. Effective January 1, 2014, Bangor Hydro Electric Company (“Bangor Hydro”) and Maine Public Service Company (“MPS”) merged, becoming Emera Maine.

Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through Emera Maine’s transmission and distribution networks. Emera Maine owns and operates approximately 1,700 kilometres of transmission facilities and 15,000 kilometres of distribution facilities. Emera Maine’s workforce is approximately 400 people.

Distribution Operations

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. Prior to July 1, 2014, the allowed ROE was 10.2%, on a common equity component of 50%. On July 1, 2014, Emera Maine’s distribution rates increased by 9%. Effective July 1, 2014, the allowed ROE became 9.55%, on a common equity component of 49%.

Transmission Operations

There are two transmission districts in Emera Maine, corresponding to the service territories of the two pre-merger entities.

Bangor Hydro District

Local transmission rates for Bangor Hydro District (the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook) are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. For local transmission operations, the rate for the Bangor Hydro District is set on a 10.57% ROE. The allowed ROE up to October 15, 2014, for these local transmission investments, was 11.14%. Effective October 16, 2014, the allowed ROE changed to 10.57%, pending two outstanding complaints filed with the FERC to challenge the ISO-New England Open Access Transmission Tariff-allowed base ROE of 11.14%. The

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common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015, transmission rates for the Bangor Hydro District increased by approximately 21% in connection with its annual transmission formula rate filing (2014 – increased by 13%). The increase is associated primarily with the under-recovery of prior year regional transmission revenues collected in local rates, as well as the recovery of increased transmission plant in service.

The Bangor Hydro District’s bulk transmission assets are managed by ISO-NE as part of a region-wide pool of assets. ISO-NE manages the region’s bulk power generation and transmission systems and administers the open access transmission tariff. Currently, the Bangor Hydro District along with all other participating transmission providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is based on prior year regionally funded transmission investments, adjusted for current year forecasted investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments ranged from 11.64% to 12.64%. Effective October 16, 2014, the transmission investments allowed ROE changed to a range from 11.07% to 11.74%, pending the two aforementioned complaints filed with FERC. The common equity component is based upon the prior calendar year average balances. The participating transmission providers are also required to contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent.

On June 1, 2015, Bangor Hydro District’s regionally recoverable transmission investments and expenses decreased by 6% (2014 – increased by 7%).

As at December 31, 2015, the Company had accrued Cdn$5.0 million associated with the FERC ROE complaints (2014 – Cdn$7.3 million). Refunds for the first FERC ROE complaint are being made to customers over a one-year period which began with the June 1, 2015 rate change.

MPS District

Local transmission rates for MPS District’s (the franchise electric service territory associated with the former Maine Public Service Company in the Maine counties of Aroostook and a portion of Penobscot) are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers, based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted investments. The current allowed ROE for transmission operations is 10.2%. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015 the transmission rates for the MPS District decreased by approximately 24% for wholesale customers (2014 – increased by 2%) and on July 1, 2015 decreased by 22% for retail customers (2014 – increased by 11%) in connection with its annual transmission formula rate filing. These decreases were primarily due to an increase in wholesale transmission revenue that allows for a decrease in local customer transmission rates.

The MPS District electric service territory is not connected to the New England bulk power system and it is not a member of ISO-NE. MPS District is not a party to the previously discussed ROE complaints at the FERC.

Stranded Cost Recoveries

Stranded cost recoveries in Maine are set by the MPUC. Electric utilities are permitted to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC. Unlike transmission and distribution operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through rates. Generally, regulatory rates to recover stranded costs are set every three years, determined under a traditional cost-of-service approach and are fully recoverable.

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For stranded cost recoveries, the rate for the Bangor Hydro District is set on a 5.9% ROE, with a common equity component of 48% and for the Maine Public Service District it is set on 6.75% ROE with a common equity component of 48%.

Each year on July 1, stranded cost rates are adjusted to reflect recovery of cost deferrals for the prior stranded costs rate year under the full recovery mechanism, as well as factor in any new stranded cost information.

Bangor Hydro District

Bangor Hydro District’s net stranded regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract, and deferrals associated with reconciling stranded costs. These net regulatory assets total approximately Cdn$19.7 million as at December 31, 2015 (2014 – Cdn$25.1 million) or 1.8% of Emera Maine’s net asset base (2014 – 2.3%).

On July 1, 2014, the Bangor Hydro District stranded cost rates decreased by 10%. Earlier, on March 1, 2014, stranded costs rates had increased by 20%. The allowed ROE used in setting the new rates on July 1, 2014, and March 1, 2014, was 5.9%, with a common equity component of 48%. This July 1, 2014 rate decrease remained in effect for all of 2015, and there was no rate change on July 1, 2015.

While the stranded cost revenue requirements differ throughout the period due to changes in annual stranded costs, the actual annual stranded cost revenues are the same during the period. To stabilize the impact of the varying revenue requirements, cost or revenue deferrals are recorded as a regulatory asset or liability, and addressed in subsequent stranded cost rate proceedings, where customer rates are adjusted accordingly.

MPS District

Effective January 1, 2015, the stranded cost rates for the MPS District decreased by approximately 150%. This was principally due to the flow-back to customers of certain benefits received by Emera Maine from Maine Yankee associated with litigation with the United States Department of Energy on nuclear waste disposal. The allowed ROE used in setting the new rates on January 1, 2015 was 6.75%, with a common equity component of 48%. The reduced stranded cost revenues are offset by reductions in expense and do not affect income. This January 1, 2015, rate decrease remained in effect for all of 2015 and there was no rate change on July 1, 2015.

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Review of 2016 and 2015

Emera Maine Net Income

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014		2013
	millions of U.S. dollars (except per share amounts)
Operating revenues – regulated	$	57.7	$	55.8	$	221.6	$	219.0	$	211.2
Operating revenues – non-regulated		0.2		—		0.6		0.5		0.5
Total operating revenues		57.9		55.8		222.2		219.5		211.7
Regulated fuel for generation and purchased power		7.8		7.7		28.9		29.7		30.8
Transmission pool expense(1)		6.3		6.1		25.4		23.9		22.9
Operating, maintenance and general		15.9		13.2		49.1		47.0		44.2
Provincial, state and municipal taxes		3.6		3.5		12.8		11.5		10.2
Depreciation and amortization		10.7		8.8		36.5		43.3		35.9
Total operating expenses		44.3		39.3		152.7		155.4		144.0
Income from operations		13.6		16.5		69.5		64.1		67.7
Other income (expenses), net		0.2		1.1		0.8		4.2		3.3
Interest expense, net		3.6		3.4		13.7		12.2		12.2
Income before provision for income taxes		10.2		14.2		56.6		56.1		58.8
Income tax expense (recovery)		3.4		4.9		21.0		17.7		21.6
Contribution to consolidated net income – USD	$	6.8	$	9.3	$	35.6	$	38.4	$	37.2
Contribution to consolidated net income – CAD	$	9.3	$	11.5	$	45.1	$	42.4	$	38.4
Contribution to consolidated earnings per common share – CAD	$	0.06	$	0.08	$	0.31	$	0.30	$	0.29
Net income weighted average foreign exchange rate – CAD/USD	$	1.37	$	1.24	$	1.27	$	1.10	$	1.03
EBITDA – USD(2)	$	24.5	$	26.4	$	106.8	$	111.6	$	106.9
EBITDA – CAD(2)	$	33.5	$	32.8	$	136.0	$	123.4	$	110.3

(1) Transmission pool expense is included in “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income.

(2) A non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”.

Emera Maine’s USD contribution to consolidated net income in Q1 2016 decreased by US$2.5 million to US$6.8 million compared to $9.3 million in Q1 2015. Highlights of the USD net income changes are summarized in the following table:

	Three months ended March 31
	millions of U.S. dollars
Contribution to consolidated net income – 2015	$	9.3
Increased operating revenues – (see “—Operating Revenues – Regulated”)		1.9
Increased OM&G primarily due to decreased capitalized construction overheads as a result of lower capital spending and storm costs		(2.7	)
Increased depreciation and amortization primarily due to higher plant in service		(1.9	)
Other		0.2
Contribution to consolidated net income – 2016	$	6.8

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Emera Maine’s USD contribution to consolidated net income decreased by U.S.$6.4 million to U.S.$3.9 million in Q4 2015 compared to U.S.$10.3 million in Q4 2014. For the year ended December 31, 2015, Emera Maine’s USD contribution to consolidated net income decreased by U.S.$2.8 million to U.S.$35.6 million compared to U.S.$38.4 million in 2014. Highlights of the USD net income changes are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of U.S. dollars
Contribution to consolidated net income – 2013				$	37.2
Increased operating revenues primarily due to rate changes					7.8
Decreased regulated fuel for purchased power primarily due to changes in purchased power contracts					1.1
Increased OM&G expenses primarily due to decreased capitalized construction overheads and increased storm expenses					(2.8	)
Increased depreciation and amortization primarily due to increased plant in service					(7.4	)
Decreased income tax expense primarily due to decreased income before provision for income taxes, a change in estimate of prior year expected benefit of tax deductions and changes in regulatory amortization					3.9
Other					(1.4	)
Contribution to consolidated net income – 2014	$	10.3		$	38.4
(Decreased) increased operating revenues – see “—Operating Revenues – Regulated”		(3.3	)		2.6
Increased OM&G primarily due to decreased capitalized construction overheads, partially offset by changes in pension and retiree medical expenses		(3.9	)		(2.1	)
Decreased depreciation and amortization due to lower depreciation rates as a result of a 2014 depreciation study and lower regulatory amortization; no change quarter-over-quarter as lower depreciation rates are offset by increased regulatory amortization		—			6.8
Decreased other income primarily due to AFUDC adjustments recognized as a result of a FERC audit		(2.8	)		(3.4	)
Decreased income tax expense quarter-over-quarter primarily due to lower income before provision for income taxes, partially offset by AFUDC adjustments recorded as a result of a FERC audit; year-over-year increase primarily due to decrease in regulatory amortization and AFUDC adjustments recorded as a result of a FERC audit		1.2			(3.3	)
Other		2.4			(3.4	)
Contribution to consolidated net income – 2015	$	3.9		$	35.6

Emera Maine’s CAD contribution to consolidated net income decreased in Q1 2016 by Cdn$2.2 million to Cdn$9.3 million from Cdn$11.5 million in Q1 2015. The impact of a stronger USD, quarter-over-quarter, increased CAD earnings by Cdn$0.9 million for the three months ended March 31, 2016.

Emera Maine’s CAD contribution to consolidated net income decreased by $6.5 million to $5.2 million in Q4 2015 from $11.7 million in Q4 2014. For the year ended December 31, 2015, Emera Maine’s CAD contribution to consolidated net income increased by $2.7 million to $45.1 million from $42.4 million in 2014. The impact of a stronger USD, increased CAD earnings quarter-over-quarter by $0.7 million for the three months ended December 31, 2015 and year-over-year $6.1 million for the year ended December 31, 2015.

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Operating Revenues—Regulated

Emera Maine’s operating revenues—regulated include sales of electricity and other services as summarized in the following table:

Q1 Operating Revenue—Regulated

Millions of U.S. dollars

	Three months ended March 31
	2016		2015
	millions of U.S. dollars
Electric revenues	$	41.7	$	40.0
Transmission pool revenues		11.6		12.2
Resale of purchased power		4.4		3.6
Operating revenues – regulated	$	57.7	$	55.8

Annual Operating Revenue—Regulated

Millions of U.S. dollars

	2015		2014		2013
Electric revenues	$	160.0	$	156.8	$	146.9
Transmission pool revenues		49.1		49.0		50.7
Resale of purchased power		12.5		13.2		13.6
Operating revenues – regulated	$	221.6	$	219.0	$	211.2

Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population and weather.

Q1 Electric Sales Volumes

GWh

	2016		2015		2014
Residential		218		235		232
Commercial		198		207		206
Industrial		81		101		105
Other		4		3		4
Total		501		546		547

Annual Electric Sales Volumes

GWh

	2015		2014		2013
Residential		802		805		801
Commercial		781		788		798
Industrial		423		426		424
Other		14		15		15
Total		2,020		2,034		2,038

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Electric revenues are summarized in the following tables by customer class:

Q1 Electric Revenues

	2016		2015		2014
	millions of U.S. dollars
Residential	$	20.7	$	21.6	$	20.7
Commercial		14.8		14.3		14.9
Industrial		3.2		3.3		4.1
Other(1)		3.0		0.8		2.7
Total	$	41.7	$	40.0	$	42.4

(1) Other revenue includes amounts recognized relating to FERC transmission rate refunds and other transmission revenue adjustments.

Annual Electric Revenues

Millions of U.S. dollars

	2015		2014		2013
Residential	$	76.4	$	75.8	$	71.7
Commercial		57.9		57.2		54.7
Industrial		14.1		14.2		13.1
Other(1)		11.6		9.6		7.4
Total	$	160.0	$	156.8	$	146.9

(1) Other revenue includes amounts recognized relating to FERC transmission rate refunds and other transmission revenue adjustments.

Electric revenues increased US$1.7 million to US$41.7 million in Q1 2016 compared to US$40.0 million in Q1 2015. Highlights of the changes are summarized in the following table:

	Three months ended March 31
	millions of U.S. dollars
Electric revenues – 2015	$	40.0
Increased due to rate changes		3.3
Decreased sales volume primarily due to weather		(3.4	)
Increased due to FERC transmission rate refund reserves		1.2
Amortization of transmission revenue adjustments		0.6
Electric revenues – 2016	$	41.7

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For the year ended December 31, 2015, electric revenues increased US$3.2 million to US$160.0 million in 2015 compared to US$156.8 million in 2014. Highlights of the changes are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of U.S. dollars
Electric revenues – 2013				$	146.9
Decreased sales volumes primarily due to weather					(0.2	)
Increased primarily due to rate changes					9.5
Decreased due to changes in amounts recognized related to the FERC ROE complaints					(2.6	)
Change in estimate for the transmission revenue					3.2
Electric revenues – 2014	$	41.2		$	156.8
Decreased sales volumes primarily due to weather		(1.2	)		(1.1	)
Increased primarily due to rate changes		0.5			3.8
Increased due to FERC transmission rate refund		3.9			6.0
Decreased due to transmission revenue adjustments		(6.4	)		(5.5	)
Electric revenues – 2015	$	38.0		$	160.0

Q1 Average Electric Revenue/MWh

	2016		2015		2014
	U.S. dollars
Dollars per MWh	$	83	$	73	$	78

The change in average electric revenue per MWh in Q1 2016 compared to Q1 2015 reflects increased transmission rates and sales mix.

Annual Electric Revenue

MWh

	2015		2014		2013
Dollars per MWh	$	79	$	77	$	72

The change in average electric revenue per MWh in for the year ended December 31, 2015 compared to the same period in 2014 reflects transmission revenue adjustments and changes in the amounts recorded related to the transmission rate refund associated with the FERC ROE complaints.

Transmission Pool Revenues and Expenses

Transmission pool revenues are recorded in “Operating revenues—regulated” and transmission pool expenses are recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income.

Transmission pool revenues and expenses are summarized in the following table:

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014		2013
	millions of U.S. dollars
Transmission pool revenues	$	11.6	$	12.2	$	49.1	$	49.0	$	50.7
Transmission pool expenses		6.3		6.1		25.4		23.9		22.9
Net transmission pool revenues	$	5.3	$	6.1	$	23.7	$	25.1	$	27.8

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Emera Maine’s net transmission pool revenues decreased US$0.8 million to US$5.3 million in Q1 2016 compared to US$6.1 million in Q1 2015 primarily due to changes in the level of investment in regionally funded transmission assets and the effect of weather.

For the year ended December 31, 2015, net transmission pool revenues decreased US$1.4 million to US$23.7 million compared to US$25.1 million in 2014 primarily due to changes in the level of investment in regionally funded transmission assets and the impacts of weather in the New England region.

Resale of Purchased Power and Regulated Fuel for Generation and Purchased Power

Emera Maine has several above-market power purchase contracts with generators in its Bangor Hydro District service territory. The power purchased under these arrangements is resold at market rates significantly below the contract rates. The difference between the cost of the power purchased under these arrangements and the revenue collected is recovered through stranded cost rates under a full reconciliation rate mechanism.

Resale of purchased power increased US$0.2 million in Q4 2015 to US$3.6 million compared to US$3.4 million in Q4 2014, and for the year ended December 31, 2015 decreased US$0.7 million to US$12.5 million in 2015 compared to US$13.2 million in 2014 primarily due to changes in market rates for electricity in New England in 2015.

Income Taxes

Emera Maine is subject to corporate income tax at the statutory rate of 40.8% (combined U.S. federal and state income tax rate).

Emera Caribbean

Overview

Emera Caribbean includes the following consolidated and non-consolidated investments:

Consolidated Investments

• 100.0% (December 31, 2015 – 95.5%) investment in Emera (Caribbean) Incorporated and its wholly owned subsidiary Barbados Light & Power Company Ltd., a vertically integrated utility and the provider of electricity on the island of Barbados, serving approximately 126,000 customers and regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. BLPC owns 239 MW of oil-fired generation, 116 kilometres of transmission facilities and 2,800 kilometres of distribution facilities. BLPC has a workforce of 330 people. BLPC is regulated under a cost-of-service model with rates set to recover prudently incurred costs of providing electricity service to customers, and to provide an appropriate return to investors. BLPC’s approved allowed regulated return on rate base for 2016 is 10.0%. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. Emera completed the purchase of the remaining 4.5% of common shares from minority shareholders of ECI in Q1 2016.

• 50.0% direct and 30.4% indirect interest through a 60.7% interest in ICD Utilities Limited in Grand Bahama Power Company Ltd. which is a vertically integrated utility and the sole provider of electricity on Grand Bahama Island. GBPC serves approximately 19,000 customers. GBPC owns 98 MW of oil-fired generation, 138 kilometres of transmission facilities and 850 kilometres of distribution facilities and has a workforce of 205 people. GBPC is regulated by GBPA, which has granted GBPC a licensed, regulated and exclusive franchise to generate, transmit and distribute electricity on the island until 2054. A fuel pass-through mechanism provides the opportunity to recover

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all fuel costs in a timely manner. Effective February 1, 2016, the GBPA approved GBPC’s General Rate Application of 8.8% applicable for the 2016 through 2018 period. Residential customers will see decreases up to 4.5%, while commercial customers will see an increase of 1.5%. Commercial customers consume approximately 70% of GBPC’s production. This rate decision will allow for customers to install renewable energy systems and sell their excess energy to GBPC. This is based on a tariff rider scheduled to be in place by Q3 2016.

• 51.9% (December 31, 2015 – 49.6% indirect controlling interest), through ECI, in Dominica Electricity Services Ltd., an integrated utility on the island of Dominica. Domlec serves approximately 36,000 customers and is regulated by the Independent Regulatory Commission, Dominica. Domlec owns 20 MW of oil-fired generation, 7 MW of hydro production, 452 kilometres of transmission facilities and 640 kilometres of distribution facilities. Domlec has a workforce of 238 people. On October 7, 2013, the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014, for a period of 25 years. Domlec’s approved allowable regulated return on rate base for 2016 is 15.0%. A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely manner.

• EUS Bahamas, providing utility construction and plant operation services in The Bahamas.

Equity Investment

• 19.1% (December 31, 2015 – 18.2% indirect interest), through ECI, in St. Lucia Electricity Services Limited, a vertically integrated regulated electric utility on the island of St. Lucia, which is regulated by the Government of St. Lucia. The investment in Lucelec is accounted for on the equity basis.

Review of 2016 and 2015

Emera Caribbean Net Income

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014		2013
	millions of U.S. dollars (except per share amounts)
Operating revenues – regulated	$	71.0	$	83.1	$	346.0	$	432.1	$	427.4
Operating revenues – non-regulated		—		1.9		6.0		8.0		8.7
Total operating revenues		71.0		85.0		352.0		440.1		436.1
Regulated fuel for generation and purchased power		26.7		39.1		158.1		247.6		248.6
Non-regulated direct costs		—		1.8		5.9		7.1		7.6
Operating, maintenance and general		21.6		22.8		101.5		107.3		103.7
Property taxes(1)		0.6		0.4		1.8		1.6		1.5
Depreciation and amortization		9.4		8.6		34.5		33.3		30.9
Total operating expenses		58.3		72.7		301.8		396.9		392.3
Income from operations		12.7		12.3		50.2		43.2		43.8
Income from equity investment		0.4		0.5		2.3		2.1		1.7
Other income (expenses), net		0.3		1.5		4.8		5.7		11.8
Interest expense, net		2.8		2.7		10.8		11.5		11.7
Income before provision for income taxes		10.6		11.6		46.5		39.5		45.6
Income tax expense (recovery)		1.0		1.0		2.4		2.7		3.2
Net income		9.6		10.6		44.1		36.8		42.4
Non-controlling interest in subsidiaries		1.2		2.2		10.2		8.3		8.9
Preferred stock dividends(2)		1.3		1.3		2.5		2.5		1.2
Contribution to consolidated net income – USD	$	7.1	$	7.1	$	31.4	$	26.0	$	32.3

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	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014(1)		2013(1)
	millions of U.S. dollars (except per share amounts)
Contribution to consolidated net income – CAD	$	9.8	$	8.8	$	40.5	$	28.7	$	33.4
Contribution to consolidated earnings per common share – CAD	$	0.07	$	0.06	$	0.28	$	0.20	$	0.25
Net income weighted average foreign exchange rate – CAD/USD	$	1.38	$	1.24	$	1.29	$	1.10	$	1.03
EBITDA – USD(3)	$	22.8	$	22.9	$	91.8	$	84.3	$	88.2
EBITDA – CAD(3)	$	31.5	$	28.3	$	117.9	$	93.0	$	91.1

(1) Included in “Provincial, state and municipal taxes” on the Consolidated Statements of Income.

(2) Preferred stock dividends are included in “Non-controlling interest in subsidiaries” on the Consolidated Statements of Income.

(3) A non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”.

Emera Caribbean’s USD contribution to consolidated net income did not change in Q1 2016 compared to Q1 2015.

For the year ended December 31, 2015, Emera Caribbean’s USD contribution to consolidated net income increased by U.S.$5.4 million to U.S.$31.4 million compared to U.S.$26.0 million in 2014. Highlights of the net income changes are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of U.S. dollars
Contribution to consolidated net income – 2013				$	32.3
Increased OM&G expenses due to restructuring costs at ECI, partially offset by operational cost savings at GBPC					(0.4	)
Decreased other income (expenses), net primarily due to reduced investment income relating to an adjustment to ECI’s self-insurance fund					(3.4	)
Increased preferred dividends due to timing of preferred share issuance					(1.3	)
Effect of the non-taxable gain on acquisition of Domlec, partially offset by the acquisition of controlling interest in Domlec on April 10, 2013					(2.0	)
Other					0.8
Contribution to consolidated net income – 2014	$	5.3		$	26.0
Increased Electric Margin – see “Electric Margin”		1.8			3.7
Decreased OM&G primarily due to lower pension expense, savings and timing of maintenance costs, and restructuring payroll savings at BLPC, lower outage costs at GBPC, and the reversal of Domlec regulatory costs; year-over-year restructuring costs at BLPC offset the decreased OM&G		4.9			5.8
Increased non-controlling interest due to increased earnings from ECI, GBPC and Domlec		(1.0	)		(1.9	)
Other		(1.0	)		(2.2	)
Contribution to consolidated net income – 2015	$	10.0		$	31.4

Emera Caribbean’s CAD contribution to consolidated net income increased by Cdn$1.0 million to Cdn$9.8 million in Q1 2016 compared to Cdn$8.8 million in Q1 2015 as a result of a stronger USD.

For the year ended December 31, 2015, Emera Caribbean’s CAD contribution to consolidated net income increased by Cdn$11.8 million to Cdn$40.5 million in 2015 compared to Cdn$28.7 million in 2014. The impact of a stronger USD year-over-year increased CAD earnings by Cdn$6.0 million in 2015 compared to 2014.

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Operating Revenues—Regulated

Emera Caribbean’s operating revenues—regulated include sales of electricity and other services as summarized in the following table:

Q1 Operating Revenues—Regulated

Millions of U.S. dollars

	Three months ended March 31
	2016		2015
	millions of U.S. dollars
Electric revenues – base rates	$	44.0	$	43.6
Fuel charge		26.1		38.6
Total electric revenues		70.1		82.2
Other revenues		0.9		0.9
Operating revenues – regulated	$	71.0	$	83.1

Annual Operating Revenues—Regulated

Millions of U.S. dollars

	2015		2014		2013(1)
Electric revenues – base rates	$	186.7	$	182.7	$	177.0
Fuel charge		155.4		245.2		247.0
Total electric revenues		342.1		427.9		424.0
Other revenues		3.9		4.2		3.4
Operating revenues – regulated	$	346.0	$	432.1	$	427.4

(1) ECI acquired a 51.9% controlling interest in Domlec on April 10, 2013.

Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q3 being the strongest period, reflecting warmer weather.

Q1 Electric Sales Volumes

GWh

	2016		2015		2014
Residential		109		105		104
Commercial		179		179		177
Industrial		23		27		24
Other		6		6		7
Total		317		317		312

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Annual Electric Sales Volumes

GWh

	2015		2014		2013(1)
Residential		453		440		428
Commercial		764		751		744
Industrial		104		102		93
Other		24		26		26
Total		1,345		1,319		1,291

(1) ECI acquired a 51.9% controlling interest in Domlec on April 10, 2013.

Electric revenues are summarized in the following tables by customer class:

Q1 Electric Revenues

	2016		2015		2014
	millions of U.S. dollars
Residential	$	22.5	$	25.9	$	31.2
Commercial		39.3		46.1		58.5
Industrial		6.8		8.6		8.4
Other		1.5		1.6		1.7
Total	$	70.1	$	82.2	$	99.8

Annual Electric Revenues

Millions of U.S. dollars

	2015		2014		2013(1)
Residential	$	110.9	$	142.9	$	133.2
Commercial		194.8		250.7		251.5
Industrial		30.1		26.9		31.5
Other		6.3		7.4		7.8
Total	$	342.1	$	427.9	$	424.0

(1) ECI acquired a 51.9% controlling interest in Domlec on April 10, 2013.

Electric revenues decreased US$12.1 million to US$70.1 million in Q1 2016 compared to US$82.2 million in Q1 2015. Highlights of the changes are summarized in the following table:

	Three months ended March 31
	millions of U.S. dollars
Electric revenues – 2015	$	82.2
Decreased fuel charge primarily due to lower fuel prices		(12.5	)
Increased due to higher sales volumes at BLPC		0.4
Electric revenues – 2016	$	70.1

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Electric revenues decreased US$21.2 million to US$83.4 million in Q4 2015 compared to US$104.6 million in Q4 2014. For the year ended December 31, 2015, electric revenues decreased US$85.8 million to US$342.1 million compared to US$427.9 million in 2014. Highlights of the changes are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of U.S. dollars
Electric revenues – 2013				$	424.0
Increased due to acquisition of a controlling interest in Domlec					8.2
Decreased fuel charge primarily due to lower fuel prices					(4.8	)
Increased due to higher sales volumes in GBPC					0.5
Electric revenues – 2014	$	104.6		$	427.9
Decreased fuel charge primarily due to lower fuel prices		(23.1	)		(89.8	)
Increased due to higher sales volumes at BLPC and GBPC primarily due to weather		1.9			4.0
Electric revenues – 2015	$	83.4		$	342.1

Q1 Average Electric Revenue/MWh

	2016		2015		2014
	U.S. dollars
Dollars per MWh	$	221	$	259	$	320

The change in average electric revenues per MWh in Q1 2016 compared to Q1 2015 was the result of the decreased fuel charge primarily due to lower fuel prices.

Annual Average Electric Revenue

MWh

	2015		2014		2013(1)
Dollars per MWh	$	254	$	324	$	328

(1) ECI acquired a 51.9% controlling interest in Domlec on April 10, 2013.

The change in average electric revenues for the year ended December 31, 2015 compared to the same period in 2014, is a result of the decreased fuel charge primarily due to lower fuel prices.

Electric Margin

Emera Caribbean distinguishes revenues related to the recovery of fuel costs through the fuel charge from revenues related primarily to the recovery of non-fuel costs (known as “base rates”). Emera Caribbean’s electric margin and net income are influenced primarily by base rates, whereas the fuel charge and fuel costs do not have a material effect on electric margin or net income. Emera Caribbean’s customer classes contribute differently to the Company’s base rate revenue, with residential and commercial customers contributing more than industrial customers. Residential and commercial load is primarily affected by changes in weather and economic conditions, while industrial load is primarily affected by economic conditions.

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Electric margin (a non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP—Electric Margin Reconciliation”) is summarized in the following table:

	Three months ended March 31						Year ended December 31
	2016			2015			2015			2014			2013
	millions of U.S. dollars
Operating revenues – regulated	$	71.0		$	83.1		$	346.0		$	432.1		$	427.4
Less: Other revenues		(0.9	)		(0.9	)		(3.9	)		(4.2	)		(3.4	)
Total electric revenues		70.1			82.2			342.1			427.9			424.0
Total electric revenues are broken down as follows:
Electric revenues – base rate		44.0			43.6			186.7			182.7			177.0
Fuel charge		26.1			38.6			155.4			245.2			247.0
Total electric revenues		70.1			82.2			342.1			427.9			424.0
Regulated fuel for generation and purchased power		26.7			39.1			158.1			247.9			248.6
Regulatory amortization(2)		0.6			0.7			2.9			2.9			2.9
Electric margin	$	42.8		$	42.4		$	181.1		$	177.4		$	172.5

(1) ECI acquired a 51.9% controlling interest in Domlec on April 10, 2013.

(2) Included in “Depreciation and amortization” on the Consolidated Statements of Income.

Emera Caribbean’s electric margin increased US$1.8 million to US$45.7 million in Q4 2015 compared to US$43.9 million in Q4 2014. For the year ended December 31, 2015, electric margin increased US$3.7 million to US$181.1 million compared to US$177.4 million in 2014 primarily due to increased sales volume at BLPC and GBPC primarily due to weather.

Q1 Average Electric Margin

MWh

	2016		2015		2014
	U.S. dollars
Dollars per MWh	$	135	$	134	$	133

Electric margin and average electric margin/MWh is consistent quarter over quarter.

Annual Average Electric Margin

MWh

	2015		2014		2013(1)
Dollars per MWh	$	135	$	134	$	134

(1) ECI acquired a 51.9% controlling interest in Domlec on April 10, 2013

Regulated Fuel for Generation and Purchased Power

Q1 Production Volumes

GWh

	2016		2015		2014
	U.S. dollars
Oil		337		335		330
Hydro		9		7		8
Total		346		342		338

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Regulated fuel for generation and purchased power decreased US$12.4 million to US$26.7 million in Q1 2016 compared to US$39.1 million in Q1 2015 primarily due to lower fuel prices.

Annual Production Volumes

GWh

	2015		2014		2013
Oil		1,441		1,397		1,371
Hydro		25		31		30
Total		1,466		1,428		1,401

Q1 Average Fuel Costs/MWh

	2016		2015		2014
	U.S. dollars
Dollars per MWh	$	77	$	114	$	170

The change in average fuel costs in Q1 2016 compared to Q1 2015 was the result of lower fuel prices.

Annual Average Fuel Costs

MWh

	2015		2014		2013(1)
Dollars per MWh	$	108	$	173		177

(1) ECI acquired a 51.9% controlling interest in Domlec on April 10, 2013.

The change in average fuel costs for the year ended December 31, 2015 compared to the same period in 2014 is a result of lower fuel prices.

For the year ended December 31, 2015, regulated fuel for generation and purchased power decreased US$89.5 million to US$158.1 million compared to US$247.6 million in 2014 primarily due to lower fuel prices.

Regulatory Recovery Mechanisms

BLPC

All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The Fair Trading Commission, Barbados has approved the calculation of the fuel charge, which is adjusted on a monthly basis.

GBPC

All GBPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The GBPA has approved the calculation of the fuel charge, which is adjusted on a monthly basis.

As a component of its regulatory agreement with the GBPA, GBPC has an earnings share mechanism to allow for earnings on rate base to be deferred to a regulatory asset or liability at the rate of 50% of amounts below a nine-percent return on rate base and 50% of amounts above 11% return on rate base respectively.

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Domlec

Substantially all of Domlec fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover fuel costs in a timely manner.

Income Taxes

Emera Caribbean is subject to corporate income tax at the following statutory rates:

• ECI is subject to corporate income tax at the statutory rate of 25.0%;

• BLPC is subject to corporate income tax at the statutory rate of 15.0%;

• GBPC is not subject to corporate income tax;

• Domlec is subject to corporate income tax at the statutory rate of 28.0%; and

• Lucelec is subject to corporate income tax at the statutory rate of 30.0%.

Non-U.S. GAAP Measure

Electric Margin Reconciliation

“Electric margin” is a non-U.S. GAAP financial measure used to show the amounts that BLPC, GBPC and Domlec retain to recover their non-fuel costs, as substantially all prudently incurred fuel costs are recovered from customers.

The companies’ electric margin may not be comparable to electric margin measures of other companies, but in management’s view appropriately reflects Emera’s specific condition. Management believes measuring electric margin shows the portion of revenues managed through fuel adjustment mechanism, which have a minimal impact on income. This measure is not intended to replace “Income from operations” which, as determined in accordance with U.S. GAAP, is an indicator of operating performance.

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014		2013
	millions of U.S. dollars
Income from operations	$	12.7	$	12.3	$	50.2	$	43.2	$	43.8
Less:
Operating revenues – non-regulated		—		1.9		6.0		8.0		78.7
Other revenue		0.9		0.9		3.9		4.2		3.4
Add back:
Non-regulated direct costs		—		1.8		5.9		7.1		7.6
Operating, maintenance and general		21.6		22.8		101.5		107.3		103.7
Property taxes		0.6		0.4		1.8		1.6		1.5
Depreciation and amortization(1)		8.8		7.9		31.6		304.		28.0
Electric margin	$	42.8	$	42.4	$	181.1	$	177.4	$	172.5

(1) Depreciation and amortization excludes $0.6 million of regulatory amortization in Q1 2016 (2015 – $0.7 million) and $2.9 million for the year ended December 31, 2015 (2014 – $2.9 million)

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Pipelines

Overview

Pipelines comprises Emera’s wholly owned Brunswick Pipeline and the Company’s 12.9% interest in the M&NP.

• Brunswick Pipeline is a 145-kilometre pipeline delivering re-gasified natural gas from the Canaport™ liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick, to markets in the northeastern United States for Repsol Energy Canada Ltd. (“RECL”) under a 25-year firm service agreement which expires in 2034. The NEB, which regulates the Brunswick Pipeline, has classified it as a Group II pipeline. The agreement is accounted for as a direct financing lease.

• M&NP is a 1,400-kilometre transmission pipeline built to transport natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. The investment in M&NP is accounted for on the equity basis.

Mark-to-Market Adjustments

Pipelines’ “Interest expense, net” and “Income tax expense (recovery)” are affected by mark-to-market adjustments on an interest rate swap. Pipelines’ income table below shows these amounts net of mark to-market adjustments and details the adjustments in the footnotes.

Review of 2016 and 2015

Pipelines’ Adjusted Net Income (a non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”)

	Three months ended March 31					Year ended December 31
	2016			2015		2015			2014		2013
	millions of Canadian dollars (except per share amounts)
Operating revenues – regulated	$	12.9		$	13.1	$	52.1		$	48.8	$	49.9
Operating, maintenance and general		0.1			0.2		0.4			0.4		0.1
Accretion(1)		0.1			0.1		0.4			0.3		0.2
Income from equity investment		5.9			5.9		23.0			18.4		14.7
Other income (expenses), net		(0.2	)		0.7		0.6			0.6		0.1
Interest expense, net(2)		5.7			6.2		23.3			26.0		27.6
Adjusted income before provision for income taxes		12.7			13.2		51.6			41.1		36.8
Income tax expense (recovery)(3)		3.0			3.3		12.0			8.4		6.5
Adjusted contribution to consolidated net income	$	9.7		$	9.9	$	39.6		$	32.7	$	30.3
After-tax derivative mark-to-market gain (loss)		(0.3	)				(2.1	)				—
Contribution to consolidated net income	$	9.4		$	9.9	$	37.5		$	32.7	$	30.3
Adjusted contribution to consolidated earnings per common share	$	0.07		$	0.07	$	0.27		$	0.23	$	0.23
Contribution to consolidated earnings per common share	$	0.06		$	0.07	$	0.26		$	0.23	$	0.23
Adjusted EBITDA	$	18.5		$	19.5	$	75.3		$	67.4	$	64.6

(1) Accretion related to the reclamation of the pipeline is included in “Depreciation and amortization” on the Consolidated Statements of Income.

(2) Interest expense, net excludes a pre-tax mark-to-market loss of $0.3 million in Q1 2016 compared to nil for the same period in 2015 and $2.9 million loss for the year ended December 31, 2015 compared to nil for the same period in 2014.

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(3) Income tax expense (recovery) excludes $0.8 million recovery relating to mark-to-market losses for the year ended December 31, 2015 compared to nil for the same periods in 2014.

Pipelines’ contribution to consolidated net income in Q1 2016 is consistent with Q1 2015.

Pipelines’ contribution to consolidated net income increased by Cdn$1.8 million to Cdn$10.3 million in Q4 2015 compared to Cdn$8.5 million in Q4 2014 and increased Cdn$4.8 million to Cdn$37.5 million for the year ended December 31, 2015 compared to Cdn$32.7 million in 2014. Highlights of the income changes are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of Canadian dollars
Contribution to consolidated net income – 2013				$	30.3
Increased income from equity investments primarily due to higher equity earnings from M&NP					3.7
Other					(1.3	)
Contribution to consolidated net income – 2014	$	8.5		$	32.7
Increased regulated operating revenues due to a strengthening USD and increased tolls		0.6			3.3
Increased income from equity investments primarily due to increased interruptible transmission revenue from M&NP and the strengthening USD		1.2			4.6
Decreased interest expense, net primarily due to a lower interest rate on EBPC refinancing in Q1 2015		0.8			2.7
Increased income tax expense primarily due to increased income before provision for income taxes		(0.8	)		(3.6	)
After-tax mark-to-market gain (loss) on an interest rate swap entered into in Q2 2015		0.2			(2.1	)
Other		(0.2	)		(0.1	)
Contribution to consolidated net income – 2015	$	10.3		$	37.5

EBPC

The Company records the net investment in a lease under the direct finance method, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. This accounting method has the effect of recognizing higher revenues in the early years of the contract than would have been recorded if the toll revenues were recorded as received.

Income Taxes

EBPC is subject to corporate income tax at the statutory rate of 27.0% (combined Canadian federal and provincial income tax rate).

Emera Energy

Overview

Emera Energy includes the following:

• Emera Energy Services, a wholly owned physical energy marketing and trading business;

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• Emera Energy Generation, consisting of a wholly owned portfolio of electricity generation facilities in New England and the Maritime provinces of Canada with 1,410 megawatts (“MW”) of total capacity;

• Equity investments in the following generation facilities:

• Emera’s 50.0% joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

• Emera’s 49.0% investment in NWP, a 419 MW portfolio of wind energy projects in the northeastern United States which on January 29, 2015 sold to 51% partner, First Wind.

Wholly owned investments are consolidated. The investment in Bear Swamp is accounted for on an equity basis. NWP was accounted for on the equity basis, and its results were included until its sale on January 29, 2015. The gain on the sale of this asset is recorded in “Other income (expenses), net” on the Consolidated Statements of Income.

Mark-to-Market Adjustments

Emera Energy’s “Trading and marketing margin,” “Electricity sales,” “Non-regulated fuel for generation and purchased power,” “Income from equity investments” and “Income tax expense (recovery)” are affected by mark-to-market (“MTM”) adjustments. The Emera Energy income table shows these amounts net of mark-to-market adjustments and details these adjustments in footnotes to the income statement. Management believes that excluding the effect of mark-to-market valuations, and changes thereto, from income until settlement better matches the financial effect of these contracts with the underlying cash flows.

Emera Energy has a number of asset management agreements with counterparties, including local gas distribution utilities, power utilities, and natural gas producers in the northeast. The asset management agreements involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the counterparties’ gas transportation/storage capacity to Emera Energy. Mark-to-market adjustments on these asset management agreements arise on the price differential between the point where gas is sourced and where it is delivered. At inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset, which is amortized over the term of the asset management agreements contract.

Subsequent changes in gas price differentials, to the extent they are not offset by the accounting amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM adjustments may be substantial during the term of the contract, specifically in the winter months of a contract when delivered volumes and market volatility are usually at peak levels. As a contract is realized, and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and the mark-to-market adjustment reduce to zero at the end of the contract term. As the business grows, and asset management agreement volumes increase, MTM volatility resulting in gains and losses may also increase.

Review of 2016 and 2015

Emera Energy Adjusted Contribution to Consolidated Net Income (a non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”)

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014		2013
	millions of Canadian dollars (except per share amounts)
Trading and marketing margin(1)	$	46.9	$	38.8	$	84.9	$	117.5	$	60.3
Electricity sales(2)		180.1		250.9		545.9		520.7		146.2
Total operating revenues – non-regulated		227.0		289.7		630.8		638.2		206.5
Non-regulated fuel for generation and purchased power(3)		114.1		159.9		334.9		384.8		97.9
Operating, maintenance and general		25.3		20.1		79.7		78.7		43.6
Provincial, state and municipal taxes		0.9		1.4		6.6		5.5		0.8

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	Three months ended March 31						Year ended December 31
	2016			2015			2015			2014		2013
	millions of Canadian dollars (except per share amounts)
Depreciation and amortization		10.9			9.3			40.6			37.7		11.2
Total operating expenses		151.2			190.7			461.8			506.7		153.5
Adjusted income (loss) from operations		75.8			99.0			169.0			131.5		53.0
Income from equity investments(4)		3.8			4.0			26.4			12.3		17.1
Other income (expenses), net		(2.6	)		22.2			25.1			2.9		0.2
Interest expense, net		6.2			1.0			19.3			6.2		1.0
Adjusted income (loss) before provision for income taxes		70.8			124.2			201.2			140.5		69.3
Income tax expense (recovery)(5)		22.9			47.8			71.1			42.3		24.2
Adjusted contribution to consolidated net income (loss)	$	47.9		$	76.4		$	130.1		$	98.2	$	45.1
After-tax derivative mark-to-market gain (loss)	$	45.5		$	(11.5	)	$	(31.2	)	$	87.5	$	(41.9	)
Contribution to consolidated net income	$	93.4		$	64.9		$	98.9		$	185.7	$	3.2
Adjusted contribution to consolidated earnings per common share – basic	$	0.32		$	0.53		$	0.89		$	0.69	$	0.34
Contribution to consolidated earnings per common share – basic	$	0.63		$	0.45		$	0.68		$	1.30	$	0.02
Adjusted EBITDA	$	87.9		$	134.5		$	261.1		$	184.4	$	81.5

(1) Marketing and trading margin excludes a pre-tax mark-to-market gain of Cdn$72.3 million for the quarter ended March 31, 2016 (2015 – Cdn$13.9 million gain). and a loss of Cdn$1.8 million for the year ended December 31, 2015 (2014 – Cdn$119.9 million gain)

(2) Electricity sales exclude a pre-tax mark-to-market loss of Cdn$8.3 million for the quarter ended March 31, 2016 (2015 – Cdn$45.8 million loss) and a loss of Cdn$39.1 million for the year ended December 31, 2015 (2014 – Cdn$42.8 million gain)

(3) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market gain of Cdn$2.8 million for the quarter ended March 31, 2016 (2015 – Cdn$7.0 million gain) and a loss of Cdn$6.3 million for the year ended December 31, 2015 (2014 – Cdn$20.8 million loss).

(4) Income from equity investments excludes a pre-tax mark-to-market loss of Cdn$2.4 million for the quarter ended March 31, 2016 (2015 – Cdn$3.4 million gain) and a loss of Cdn$5.6 million for the year ended December 31, 2015 (2014 – Cdn$13.2 million loss)

(5) Income tax expense (recovery) excludes an Cdn$18.9 million expense relating to mark-to-market gains for the quarter ended March 31, 2016 (2015 – Cdn$10.0 million recovery) and Cdn$21.6 million recovery relating to mark-to-market losses for the year ended December 31, 2015 (2014 – Cdn$41.2 million expense)

Emera Energy’s contribution to consolidated net income increased Cdn$28.5 million to Cdn$93.4 million in Q1 2016 compared to Cdn$64.9 million in Q1 2015. Highlights of the net income changes are summarized in the following table:

	Three months ended March 31
	millions of Canadian dollars
Contribution to consolidated net income – 2015	$	64.9
Increased marketing and trading margin – See “—Trading and Marketing Margin”		8.1
Decreased electricity sales primarily due to lower hedged and market power prices at the New England Gas Generating Facilities, lower market prices at Bayside Power, and decreased sales volumes at the New England Gas Generating Facilities driven by weather, partially offset by a stronger USD		(70.8	)

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	Three months ended March 31
	millions of Canadian dollars
Decreased non-regulated fuel for generation and purchased power mainly due to lower hedged and market commodity prices at the New England Gas Generating Facilities, lower market commodity prices at Bayside Power, and decreased purchase volumes at the New England Gas Generating Facilities driven by weather, partially offset by a stronger USD		45.8
Increased OM&G primarily due to a stronger USD and increased performance-based compensation resulting from increased marketing and trading margin		(5.2	)
Decreased other income primarily due to a gain on the sale of NWP in 2015		24.8	)
Increased interest expense, net primarily due to higher interest rates on internal financing		(5.2	)
Decreased income tax expense primarily due to decreased income before provision for income taxes, changes in the proportion of income earned in higher tax rate foreign jurisdictions and a stronger CAD		24.9
Increased mark-to-market, net of tax primarily due to the reversal of 2015 mark-to-market losses and changes in gas and power contract positions, partially offset by amortization of 2015 gas transportation assets		57.0
Other		(1.3	)
Contribution to consolidated net income – 2016	$	93.4

A portion of earnings are exposed to foreign exchange fluctuations, thereby impacting adjusted CAD contribution to net earnings. The impact of a stronger USD, quarter-over-quarter, increased CAD earnings by Cdn$5.3 million in Q1 2016 compared to Q1 2015.

Emera Energy’s contribution to consolidated net income decreased by Cdn$54.3 million to Cdn$39.7 million in Q4 2015 compared to Cdn$94.0 million in Q4 2014. For the year ended December 31, 2015, Emera Energy’s contribution to consolidated net income decreased Cdn$86.8 million to Cdn$98.9 million compared to Cdn$185.7 million in 2014. Highlights of the income changes are summarized in the following table:

	Three months ended December 31	Year ended December 31
	millions of Canadian dollars
Contribution to consolidated net income – 2013		$	3.2
Increased trading and marketing margin primarily due to very strong market conditions in northeastern United States and Ontario in Q1 2014 and a stronger USD			57.2
Increased electricity sales primarily due to the acquisition of the New England Gas Generation Facilities in November 2013, higher power prices and increased sales at Bayside Power			374.5
Increased non-regulated fuel for generation and purchased power primarily due to the acquisition of the New England Gas Generation Facilities in November 2013, higher commodity prices and increased generation at Bayside Power			(286.9	)
Increased OM&G primarily due to the acquisition of the New England Gas Generating Facilities and increased performance-based compensation accruals resulting from increased trading and marketing margin			(35.1	)
Increased depreciation and amortization primarily due to the acquisition of the New England Gas Generation Facilities			(26.5	)
Income from equity investments reflects a non-recurring gain on the settlement of warranty obligations related to certain NWP turbines, decreased curtailments at NWP, recognition of business interruption insurance proceeds related to a 2013 outage at Bear Swamp and favourable pricing at Bear Swamp			(4.8	)

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	Three months ended December 31			Year ended December 31
	millions of Canadian dollars
Increased income tax expense primarily due to increased income before provision for taxes					(18.1	)
Increased mark-to-market gains, net of tax, primarily due to the reversal of 2013 mark-to-market losses and changes in gas and power contract positions, as well as favourable power contracts at the New England Gas Generation Facilities					129.4
Other					(7.2	)
Contribution to consolidated net income – 2014	$	94.0		$	185.7
Increased (decreased) trading and marketing margin – See “Trading and Marketing Margin”		22.2			(32.6	)
Increased electricity sales quarter-over-quarter primarily due to higher sales volumes, reflecting reduced generation for planned outage work at Bridgeport in Q4 2014, which reduced generation and a stronger USD; year-over-year is also partially offset by lower power prices		40.1			25.2
Increased non-regulated fuel for generation and purchased power quarter-over-quarter as a result of higher sales volumes, reflecting reduced generation for planned outage work at Bridgeport in Q4 2014 and a stronger USD; year-over-year reduction is primarily due to lower commodity fuel prices, partially offset by a stronger USD		(24.9	)		49.9
Increased OM&G quarter-over-quarter primarily due to timing of maintenance work at the New England Gas Generation Facilities, the stronger USD and increased performance-based compensation resulting from increased trading and marketing margins; year-over year primarily due to stronger USD, offset by decreased performance-based compensation resulting from decreased trading and marketing margins		(8.7	)		(1.0	)
Increased income from equity investments – See “– Equity Investments”		1.6			14.1
Increased other income (expenses) year-over-year primarily due to a gain on the sale of NWP		0.4			22.2
Increased interest expense, net primarily due to higher interest rates on internal financing		(4.7	)		(13.1	)
Increased income tax expense primarily due to increased income before provision for income taxes; year-over-year increase also due to changes in the proportion of income earned in higher tax rate foreign jurisdiction and a stronger USD		(8.9	)		(28.8	)
Decreased mark-to-market, net of tax, quarter-over-quarter primarily due to changes in gas and power contract positions, and amortization of transportation assets; decreased year-over-year also due to the reversal of 2013 mark-to-market losses in 2014		(68.4	)		(118.7	)
Other		(3.0	)		(4.0	)
Contribution to consolidated net income – 2015	$	39.7		$	98.9

A portion of earnings are exposed to foreign exchange fluctuations thereby impacting adjusted CAD contribution to net earnings. The impact of a stronger USD, quarter-over-quarter, increased earnings in CAD by $3.4 million in Q4 2015 compared to 2014. For the year ended December 31, 2015 the impact of a stronger USD increased earnings in CAD by $11.9 million compared to the same period in 2014.

Energy Services

Emera Energy Services derives revenue and earnings from the wholesale trading and marketing of natural gas, electricity and other energy-related commodities and derivatives within the Company’s risk tolerances, including

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those related to value-at-risk (“VaR”) and credit exposure. Emera Energy purchases and sells physical natural gas and related transportation capacity rights, as well as providing related energy asset management services. Emera Energy Services is also responsible for commercial management of electricity production and fuel procurement for Emera Energy Generation’s fleet. Established in 2002, Emera Energy’s trading and marketing business currently has approximately 80 employees engaged in commercial activities and related back office, legal and other support functions. The primary market for the trading and marketing business is northeastern North America, including the Marcellus shale gas region, the U.S. Gulf Coast and Central Canada. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. Trading and marketing operates in a competitive environment, and its business relies on knowledge of the region’s energy markets, understanding of pipeline infrastructure, a network of counterparty relationships and a focus on customer service. Emera Energy manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.

Adjusted EBITDA

Adjusted EBITDA (a non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”) for Emera Energy’s trading and marketing business is summarized in the following table:

	Three months ended March 31					Year ended December 31
	2016			2015		2015		2014		2013
	millions of Canadian dollars (except per share amounts)
Trading and marketing margin	$	46.9		$	38.8	$	84.9	$	117.5	$	60.3
OM&G		10.4			7.5		21.3		24.8		15.2
Other income (expenses), net		(3.7	)		3.5		5.6		2.6		1.0
Adjusted EBITDA	$	32.8		$	34.8	$	69.2	$	95.3	$	46.1

Trading and Marketing Margin

Trading and marketing margin is comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management services’ revenues.

Marketing and trading margin increased Cdn$8.1 million to Cdn$46.9 million in Q1 2016 compared to Cdn$38.8 million in Q1 2015. his increase is primarily due to a stronger USD and growth in the volume of business, including investment in transportation capacity, which offset the impact of sustained low pricing and volatility in several of Emera Energy’s markets in Q1 2016, largely the result of weather. For the year ended December 31, 2015, trading and marketing margin decreased Cdn$32.6 million to Cdn$84.9 million compared to Cdn$117.5 million in 2014. Q1 2014 saw sustained high pricing and volatility in several of Emera Energy’s markets, largely the result of cold weather. Subsequently, there was a return to more normal market conditions. Trading and marketing margins were also favourably affected by the strengthening USD in Q4 2015 and for the year ended December 31, 2015.

Other Income

Other income decreased Cdn$7.2 million to Cdn$(3.7) million in Q1 2016 compared to Cdn$3.5 million in Q1 2015. This decrease is primarily due to foreign exchange losses recorded in 2016 as a result of the stronger CAD since December 31, 2015.

Generation

Emera Energy wholly owns and operates a portfolio of high efficiency, non-utility electricity generating facilities in northeast North America.

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Information regarding Emera Energy’s wholly owned generation facilities is summarized in the following table:

Wholly Owned Generation Facilities	Location	Capacity (MW)		Commissioning/ In-Service Date		Fuel	Description
New England
Bridgeport(1)	Connecticut		560		1999	Natural gas	Selling electricity and capacity to ISO-NE
Tiverton	Rhode Island		265		2000	Natural gas	Selling electricity and capacity to ISO-NE
Rumford	Maine		265		2000	Natural gas	Selling electricity and capacity to ISO-NE
Total New England			1,090
Maritime Canada
Bayside Power	New Brunswick		290		2001	Natural gas	Long-term power purchase agreement (“PPA”) November – March; Selling electricity to Maritimes and ISO-NE for remainder of year
Brooklyn Energy	Nova Scotia		30		1996	Biomass	Long-term PPA
Total Maritime Canada			320
Total Emera Energy Generation			1,410

(1) A Q2 2015 upgrade at Bridgeport increased its nameplate capacity from 540 MW to 560 MW.

Emera Energy has approximately 125 employees in its generation business. For the portion of output not committed under PPAs, Emera Energy’s generation facilities sell into price-based competitive markets and earn revenues through the physical delivery of power and ancillary services, such as load regulation. The New England facilities also participate in the regional capacity market and are compensated for being available to provide power. The electricity generation business in the northeast is seasonal. Q1, Q3 and Q4 are generally the strongest periods, reflecting colder weather, and fewer daylight hours in the winter season, and cooling load in the summer.

Adjusted EBITDA

Adjusted EBITDA (a non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”) is summarized in the following tables:

	Three months ended March 31
	New England				Maritime Canada					Total
	2016		2015		2016		2015			2016		2015
	millions of Canadian dollars
Energy sales	$	139.3	$	201.3	$	28.3	$	39.0		$	167.6	$	240.3
Capacity and other		12.5		10.6		—		—			12.5		10.6
Electricity sales	$	151.8	$	211.9	$	28.3	$	39.0		$	180.1	$	250.9
Non-regulated fuel for generation and purchased power		94.1		133.4		18.3		28.6			112.4		162.0
Non-regulated electric margin	$	57.7	$	78.5	$	10.0	$	10.4		$	67.7	$	88.9
Provincial taxes		0.7		1.1		0.2		0.3			0.9		1.4
OM&G		9.0		7.3		5.5		4.5			14.5		11.8
Other income (expenses), net		—		1.3		1.1		(1.3	)		1.1		—
Adjusted EBITDA	$	48.0	$	71.4	$	5.4	$	4.3		$	53.4	$	75.7

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Adjusted EBITDA decreased Cdn$22.3 million to Cdn$53.4 million in Q1 2016 from Cdn$75.7 million in Q1 2015 primarily due to lower margins realized in the New England Gas Generating Facilities, reflecting less favourable short-term economic hedges and fewer optimization opportunities driven by weather across the northeastern United States. This was partially offset by the stronger USD, which contributed Cdn$4.7 million.

	Year ended December 31
	2015		2014		2013		2015			2014		2013			2015		2014		2013
	millions of Canadian dollars (except per share amounts)
	New England(1)						Maritime Canada(2)								Total
Energy sales	$	413.9	$	365.9	$	64.0	$	88.3		$	109.4	$	77.8		$	502.2	$	474.9	$	141.8
Capacity and other		43.7		45.8		4.4		—			—		—			43.7		45.8		4.4
Electricity sales		457.6		411.3	$	68.4	$	88.3		$	109.4	$	77.8		$	545.9		520.7	$	146.2
Non-regulated fuel for generation and purchased power		277.3		311.8		48.6		52.2			73.5		47.3			329.5		385.3		95.9
Non-regulated electric margin		180.3		99.5		19.8		36.1			35.9		30.5			216.4		135.4		50.3
Provincial taxes		4.7		4.6		—		0.9			0.9		0.8			5.6		5.5		0.8
OM&G		37.5		29.9		7.1		18.7			21.3		19.3			56.2		51.2		26.4
Other income (expenses), net		1.6				—		(0.7	)		0.3		(0.8	)		0.9		0.3		(0.8	)
Adjusted EBITDA	$	139.7	$	65.0	$	12.7	$	15.8		$	14.0	$	9.6		$	155.5	$	79.0	$	22.3

(1) The New England Gas Generation Facilities were acquired in November 2013.

(2) Brooklyn Energy was acquired in July 2013.

For the year ended December 31, 2015, adjusted EBITDA increased Cdn$76.5 million to Cdn$155.5 million from Cdn$79.0 million in 2014, primarily due to higher margins realized in the New England Gas Generation Facilities, reflecting favourable short-term economic hedges and favourable pricing. The strengthening USD contributed Cdn$17.6 million.

Operating Statistics

	Sales Volumes (GWh)(1)				Plant Availability (%)(2)						Three months ended March 31
											Net Capacity Factor (%)(3)
	2016		2015		2016			2015			2016			2015
New England		1,299		1,410		96.1	%		98.0	%		54.6	%		60.8	%
Maritime Canada		518		483		95.8	%		99.2	%		75.9	%		70.0	%
Total		1,817		1,893		96.0	%		98.3	%		59.3	%		63.1	%

(1) Sales volumes represent the actual electricity output of the plants.

(2) Plant availability represents the percentage of time in the period that the plant was available to generate power regardless of whether it was running. Effectively, it represents 100% availability reduced by planned and unplanned outages.

(3) Net capacity factor is the ratio of the utilization of an asset as compared to its maximum capability, within a particular time frame. It is generally a function of plant availability and plant economic vis-à-vis the market.

Upgrades completed in Q2 2015 at the Bridgeport facility, including a new gas turbine rotor and improved combustion system, added 20 MW of capacity, bringing the plant total to 560 MW. Availability has increased at the New England Gas Generation Facilities due to significant reliability and performance- based investment in 2014.

The New England Gas Generating Facilities sell into price based competitive markets. The primary reason that the overall capacity factor is lower for New England Gas Generating Facilities as compared to the Maritime facilities is because the Rumford Plant, in particular, generally operates with a capacity factor of approximately 20%, reflecting current electricity and gas supply price dynamics in its markets.

153

	Year ended December 31
	2015		2014		2015			2014			2015			2014
	millions of Canadian dollars (except per share amounts)
	Sales Volumes (GWh)(1)				Plant Availability(2)						Net Capacity Factor (%)(3)
New England		4,777		4,375		94.5	%		79.9	%		50.5	%		47.6	%
Maritime Canada		1,699		1,910		92.7	%		91.4	%		61.9	%		69.9	%
Total		6,476		6,285		94.1	%		82.6	%		53.0	%		52.7	%

(1) Sales volumes represent the actual electricity output of the plants.

(2) Plant availability represents the percentage of time in the period that the plant was available to generate power regardless of whether it was running. Effectively, it represents 100% availability reduced by planned and unplanned outages.

(3) Net capacity factor is the ratio of the utilization of an asset as compared to its maximum capability, within a particular time frame. It is generally a function of plant availability and plant economics vis-à-vis the market.

Year-over-year increase in sales volumes was primarily due to fewer outage days in 2015 at the New England Gas Generation Facilities.

Upgrades completed in Q2 2015 at the Bridgeport facility, including a new gas turbine rotor and improved combustion system, added 20 MW of capacity, bringing the plant total to 560 MW. Availability has increased at the New England Gas Generation Facilities due to significant reliability and performance- based investment in 2014.

Equity Investments

Information regarding Emera Energy’s equity investments in generation facilities is summarized below:

Investments in Generation Facilities	Ownership		Location	Capacity (MW)		Fuel	Description
New England
Bear Swamp		50%	Massachusetts		600	Hydro	Long-term PPA and selling electricity and capacity to ISO-NE
NWP(1)		49%	Maine		419	Wind	Long-term PPA and selling electricity and capacity to ISO-NE and New York ISO
Total New England					1,019

(1) On January 29, 2015, Emera completed the sale of NWP to First Wind for $223.3 million USD. Emera’s carrying value of its 49% interest as at December 31, 2014 was $204.4 million USD.

Adjusted income from equity investments

Adjusted income from equity investments (a non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”) is summarized in the following table:

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014			2013(1)
	millions of Canadian dollars (except per share amounts)
Bear Swamp	$	3.8	$	2.1	$	24.5	$	19.2		$	15.8
NWP		—		1.9		1.9		(6.9	)		1.3
Adjusted Income from equity investments	$	3.8	$	4.0	$	26.4	$	12.3		$	17.1

154

Income from equity investments decreased Cdn$0.2 million to Cdn$3.8 million in Q1 2016 compared to Cdn$4.0 million in Q1 2015, largely due to the sale of NWP in Q1 2015 and higher interest costs at Bear Swamp as a result of its Q4 2015 refinancing, largely offset by favourable pricing at Bear Swamp and the effect of a stronger USD. For the year ended December 31, 2015, adjusted income from equity investments increased Cdn$14.1 million to Cdn$26.4 million compared to Cdn$12.3 million in 2014. This was primarily due to the resupply of the contracted power sales in Bear Swamp in 2015 that were not delivered in 2014 due to transmission line outages, NWP losses recorded in 2014 and the strengthening USD.

Other Income

On January 29, 2015, Emera completed the sale of its 49% interest in NWP for Cdn$282.3 million ($223.3 million USD). This sale resulted in a pre-tax gain of Cdn$18.6 million or Cdn$0.13 per common share (after-tax gain of Cdn$11.5 million or Cdn$0.08 per common share), which was recorded in “Other income (expenses), net” on the Consolidated Statements of Income in Q1 2015.

Income Taxes

Emera Energy is subject to corporate income tax at the statutory rate ranging from 39.2 to 41.5% (combined U.S. federal and state income tax rate) on its U.S. sourced income and ranging from 27.0 to 31.0% (combined Canadian federal and provincial income tax rate) on its Canada sourced income.

New England Gas Generation Facilities is subject to corporate income tax at the statutory rate ranging from 35.0 to 40.9% (combined U.S. federal and state income tax rate).

Brooklyn Energy is subject to corporate income tax at the statutory rate of 31.0% (combined Canadian federal and provincial income tax rate).

Bear Swamp Refinancing

On October 8, 2015, Bear Swamp refinanced its $125 million USD bank debt that was due to mature in 2017 and issued $400 million USD in senior secured 10-year bonds, with $375 million USD at fixed rate of 4.89% and $25 million USD at a floating rate of LIBOR plus 2.70%. The proceeds of this financing were used to repay existing debt and provide working capital to the joint venture, with the remainder shared equally between Emera and its joint venture partner. After fees and expenses, Emera received a $178.7 million ($137.3 million USD) non-taxable distribution in Q4 2015.

Corporate and Other

Corporate

Corporate encompasses certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, internal audit, investor relations, risk management, insurance, acquisition-related costs and corporate human resource activities. It also includes interest revenue on intercompany financings recorded in “Intercompany revenue” in the table below, and costs associated with corporate activities that are not directly allocated to the operations of Emera’s consolidated subsidiaries and investments.

155

Other

Other includes the following consolidated and non-consolidated investments:

Consolidated Investments

• Emera Utility Services is a utility services contractor primarily operating in Atlantic Canada (recorded in “Non-regulated operating revenue” in the table below).

• Emera Reinsurance Limited is a captive insurance company providing insurance and reinsurance to Emera and certain of its affiliates, to enable more cost efficient management of risk and deductible levels across Emera (recorded in “OM&G” and “Other income (expenses), net” in the table below).

Non-consolidated investments (recorded in “Income (loss) from equity investments” in the table below)

• Emera’s 19.4% investment in APUC, a diversified generation, transmission and distribution utility traded on the Toronto Stock Exchange under the symbol “AQN.” The distribution group operates in the United States and provides rate regulated water, electricity and natural gas utility services. The non-regulated generation group owns or has interests in a portfolio of North American-based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission group invests in rate-regulated electric transmission and natural gas pipeline systems in the United States and Canada. The investment in APUC is accounted for on an equity basis. As at March 31, 2016, Emera owned 50.1 million common shares, 12.9 million outstanding subscription receipts and dividend equivalents, at an average conversion price of Cdn$9.19. The outstanding subscription receipts and dividend equivalents will automatically convert to common shares in Q4 2016, if an election is not made. On May 17, 2016 Emera announced that it had agreed to sell all of the 50.1 million common shares it held in APUC, representing approximately 19.3% of APUC’s issued and outstanding common shares, to a syndicate of underwriters at Cdn$10.85 per common share for aggregate gross proceeds of approximately Cdn$544 million. The sale was completed on May 24, 2016. Emera continues to hold the subscription receipts and associated dividend equivalents, which represent approximately 4.75% of APUC’s issued and outstanding common shares (after giving effect to the conversion of the subscription receipts and associated dividend equivalents).

• Emera’s 100% investment in ENL, which holds investments in the following:

• Emera’s 100% investment in NSPML, a Cdn$1.56 billion transmission project, including two 170-kilometre subsea cables, between the island of Newfoundland and Nova Scotia. The investment in NSPML is accounted for on the equity basis with equity earnings equal to the return on equity component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017.

• Emera’s 59.0% (December 31, 2015 – 55.1%) investment in the partnership capital of LIL, a Cdn$3.1 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49% of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is expected to go into service in 2017.

• Other investments.

156

Mark-to-Market Adjustments

Specific to the Acquisition, Emera has recorded after-tax mark-to-market losses of Cdn$121.1 million for the three months ended March 31, 2016 (2015 – nil) and after tax mark-to-market gains of Cdn$100.5 million for the year ended December 31, 2015 (2014 – nil) related to the effect of USD-denominated currency and forward contracts put in place to hedge the anticipated proceeds from the Final Instalment of the Convertible Debenture Offering of the pending acquisition, expected to close mid-2016.

“Other income (expenses), net” and “Income tax expense (recovery)” are affected by the mark-to-market adjustments discussed above. Corporate and Other’s income table below shows these amounts net of mark-to-market adjustments and details the adjustments in the footnotes.

Review of 2016 and 2015

Corporate and Other

	Three months ended March 31						Year ended December 31
	2016			2015			2015			2014			2013
	millions of Canadian dollars (except per share amounts)
Intercompany revenue(1)	$	9.9		$	5.3		$	34.2		$	26.0		$	38.3
Non-regulated operating revenue		8.4			8.8			40.1			48.7			43.5
Non-regulated direct costs		8.2			9.7			42.4			46.9			44.6
Operating, maintenance and general		13.7			12.7			104.1			46.2			39.0
Depreciation and amortization		0.7			0.3			1.7			2.3			3.8
Total operating expenses		22.6			22.7			148.2			95.4			87.4
Income (loss) from operations		(4.3	)		(8.6	)		(73.9	)		(20.7	)		(5.6	)
Income (loss) from equity earnings		18.1			11.9			61.3			46.3			3.3
Other income (expenses), net(2)		3.6			(0.2	)		(4.3	)		3.2			16.9
Interest expense		33.1			6.3			48.1			30.9			37.5
Adjusted income (loss) before provision for income taxes(4)		(15.7	)		(3.2	)		(65.0	)		(2.1	)		(22.9	)
Income tax expense (recovery)(3)		(13.7	)		(7.9	)		(40.1	)		(20.6	)		(28.4	)
Preferred stock dividends		7.0			7.7			30.3			26.2			19.3
Adjusted contribution to consolidated net income(4)	$	(9.0	)	$	(3.0	)	$	(55.2	)	$	(7.7	)	$	(13.8	)
After-tax mark-to-market gain (loss)		(121.1	)		—			100.5			—			—
Contribution to consolidated net income	$	(130.1	)	$	(3.0	)	$	45.3		$	(7.7	)	$	(13.8	)
Adjusted contribution to consolidated earnings per common share – basic(4)	$	(0.06	)	$	(0.02	)	$	(0.38	)	$	(0.05	)	$	(0.10	)
Contribution to consolidated earnings per common share – basic	$	(0.87	)	$	(0.02	)	$	0.31		$	(0.05	)	$	(0.10	)
Adjusted EBITDA(4)	$	18.1		$	3.4		$	(15.2	)	$	31.1		$	18.4

(1) Intercompany revenue consists of interest from EBPC, M&NP and Emera Energy Generation.

(2) Other income (expenses) net, excludes a pre-tax mark-to-market loss of $139.5 million in Q1 2016 compared to nil for the same period in 2015 and a pre-tax mark-to-market gain of $118.9 million for the year ended December 31, 2015 (2014-nil).

(3) Income tax expense (recovery), excludes an $18.4 million recovery relating to mark-to-market losses in Q1 2016 compared to nil for the same period in 2015 and an $18.4 million expense for the year ended December 31, 2015 (2014 – nil).

(4) A non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures.”

157

Corporate and Other’s contribution to consolidated net income decreased $127.1 million to $(130.1) million in Q1 2016 compared to $(3.0) million in Q1 2015. Highlights of the income changes are summarized in the following table:

	Three months ended March 31
	millions of U.S. dollars
Contribution to consolidated net income – 2015	$	(3.0	)
Increased intercompany revenue primarily due to the issuance of a loan to Emera Energy Generation		4.6
Income from equity investments – see table entitled “Contribution to consolidated net income – 2013”		6.2
Increased interest expense primarily due to interest on the Acquisition-related convertible debentures represented by instalment receipts		(26.8	)
Increased income tax recovery primarily due to decreased income before provision for income taxes		5.8
After-tax mark-to-market gain (loss) – see “After-Tax Mark-to-Market Gain (Loss)”		(121.1	)
Other		4.2
Contribution to consolidated net income – 2016	$	(130.1	)

For the year ended December 31, 2015, Corporate and Other’s contribution to consolidated net income increased Cdn$53.0 million to Cdn$45.3 million compared to Cdn$(7.7) million in 2014. Highlights of the income changes are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of Canadian dollars
Contribution to consolidated net income – 2013				$	(13.8	)
Decreased intercompany revenue primarily due to lower interest revenue resulting from the repayment of NWP loan in November 2013					(12.3	)
Increased OM&G primarily due to higher deferred compensation costs, partially offset by lower business development costs					(7.2	)
Income from equity investments – see “– Income from Equity Investments”					43.0
Decreased other income primarily due to the 2013 gains on the exchange of APUC subscription receipts to common shares, partially offset by the 2013 AHI investment impairment					(13.7	)
Decreased interest expense primarily due to lower short-term debt levels					6.6
Increased income tax expense primarily due to increased income before provision for income taxes					(7.8	)
Increased preferred stock dividends primarily due to an incremental preferred share issuance					(6.9	)
Other					4.4
Contribution to consolidated net income – 2014	$	0.8		$	(7.7	)
Increased intercompany revenue due to the issuance of a loan to Emera Energy Generation, partially offset by the repayment of an intercompany loan from EBPC		3.1			8.2
Acquisition costs related to the Acquisition		(21.0	)		(51.5	)
Decreased OM&G quarter-over-quarter primarily due to lower performance-based compensation; increased year-over-year primarily due to business development costs not related to the Acquisition		5.1			(6.4	)
Income from equity investments – see Income from Equity Investments section below		13.9			15.0

158

	Three months ended December 31			Year ended December 31
	millions of Canadian dollars
Decreased other income quarter-over-quarter due to the reclassification of APUC subscription receipts; year-over-year due to the losses incurred in Emera Reinsurance from Tropical Storm Erika and the recognition of NSPML as an equity investment in Q2 2014		(4.9	)		(7.5	)
Increased interest expense primarily due to interest on convertible debentures represented by installment receipts, partially offset year-over-year by maturity of long-term debt in Q4 2014		(23.2	)		(17.2	)
Decreased income tax expense primarily due to the decreased income before provision for income taxes		10.3			19.5
Increased preferred stock dividends year-over-year primarily due to issuance of preferred shares in Q2 2014		—			(4.1	)
After-tax mark-to-market gain (loss) – see “After-Tax Mark-to-Market Gain (Loss)”		100.5			100.5
Other		(1.1	)		(3.5	)
Contribution to consolidated net income – 2015	$	83.5		$	45.3

Acquisition-Related Costs

Highlights of the Acquisition-related costs are summarized in the following table:

	Three months ended March 31					Year ended December 31
	2016			2015		2015			2014		2013
	millions of Canadian dollars (except per share amounts)
Operating, maintenance, and general	$	0.1		$	—	$	51.5			—	$	—
Interest expense, net		25.5			—		23.9					—
Income tax expense (recovery)		(8.1	)		—		(22.6	)				—
Acquisition-related costs	$	17.5		$	—	$	52.8		$	—	$	—

After-Tax Mark-to-Market Gain (Loss)

The foreign currency earnings impact related to the translation from the convertible debenture USD cash balance and the mark-to-market adjustments from forward contracts from economically hedging the Convertible Debenture Offering are recorded as a mark-to-market adjustment. These pre-tax losses totaled Cdn$139.5 million in Q1 2016 and are recorded in “Other income (expenses), net” on the Consolidated Statements of Income (Cdn$121.1 million after-tax loss). These losses offset a pre-tax mark-to-market gain of Cdn$118.9 million (Cdn$100.5 million after-tax gain) recorded in Q4 2015. The after-tax mark-to-market gain (loss) is summarized in the following table:

	Three months ended March 31					Year ended December 31
	2016			2015		2015			2014(1)		2013(1)
	millions of Canadian dollars (except per share amounts)
Foreign exchange on USD cash	$	(44.7	)	$	—	$	26.8			—	$	—
Mark-to-market adjustment on USD forward contracts		(94.8	)		—		92.1					—
Income tax expense (recovery)		18.4			—		(18.4	)				—
After-tax mark-to-market gain (loss)	$	(121.1	)	$	—	$	100.5		$	—	$	—

159

Income from Equity Investments

Income from equity investments are summarized in the following table:

	Three months ended March 31				Year ended December 31
	2016		2015		2015		2014(1)		2013(1)
	millions of Canadian dollars (except per share amounts)
APUC	$	9.0	$	6.6	$	36.9		30.4	$	0.4
NSPML		4.4		3.6		14.9		9.5		—
LIL		4.7		1.7		9.5		6.4		5.2
AHI		—		—		—		—		(2.3	)
Income from equity investments	$	18.1	$	11.9	$	61.3	$	46.3	$	3.3

Income from equity investments increased Cdn$6.2 million to Cdn$18.1 million in Q1 2016 compared to Cdn$11.9 million in Q1 2015. Highlights of the changes are summarized in the following table:

	Three months ended March 31
	millions of Canadian dollars
Income from equity investments – 2015	$	11.9
APUC – Higher equity earnings and the reclassification of APUC subscription receipts		2.4
NSPML – AFUDC earnings as a result of increased investment		0.8
LIL – AFUDC earnings as a result of increased investment		3.0
Income from equity investments – 2016	$	18.1

Income from equity investments increased Cdn$13.9 million to Cdn$25.5 million in Q4 2015 compared to Cdn$11.6 million in Q4 2014. For the year ended December 31, 2015, income from equity investments increased Cdn$15.0 million to Cdn$61.3 million compared to Cdn$46.3 million in 2014. Highlights of the income changes are summarized in the following table:

	Three months ended December 31			Year ended December 31
	millions of Canadian dollars
Income from equity investments – 2013				$	3.3
APUC – Increased due to dilution gains resulting from share issuances, higher earnings and 2013 recognition of discontinued operations of $8.3 million					30.0
NSPML – Recognition of the AFUDC earnings of NSPML as income from equity investment					9.5
Other					3.5
Income from equity investments – 2014	$	11.6		$	46.3
APUC – Increased quarter-over-quarter primarily due higher equity earnings in 2015, the reclassification of APUC subscription receipts in 2015 and a higher dilution gain from the share issuance in Q4 2015 compared to dilution gain from share issuance in Q4 2014; year-over-year due to higher equity earnings in 2015, the reclassification of APUC subscription receipts in 2015, partially offset by lower dilution on APUC share issuances in 2015 compared to dilutions related to share issuances in 2014		12.4			6.5
NSPML – Increased year-over-year due to the recognition of the AFUDC earnings of NSPML as income from equity investment		(0.6	)		5.4
LIL – Increase in investment		2.1			3.1
Income from equity investments – 2015	$	25.5		$	61.3

160

NSPML has invested Cdn$796.7 million as at March 31, 2016 of equity, debt and working capital, including Cdn$90.3 million of AFUDC, in the development of the Maritime Link Project. Project to date, Emera has invested a total of Cdn$206.4 million in equity, which is comprised of Cdn$169.3 million in equity contributed and Cdn$37.1 million of accumulated retained earnings, with the remaining costs being funded with working capital and debt. The debt has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9%. Proceeds from the federally guaranteed debt financing completed in April 2014, were used to fund project costs until the Project’s target debt to equity ratio reached 70% to 30% respectively, in Q4 2015. From that point forward, project costs are being funded with debt and equity at a 70% and 30% ratio, with equity contributions of Cdn$14.4 million in Q1 2016.

Emera has invested Cdn$250.4 million in the LIL as at March 31, 2016, which is comprised of Cdn$224.5 million in equity contributed and Cdn$25.9 million of accumulated equity earnings. Equity earnings are being recorded based on an annual rate 8.8% of the equity invested. The rate is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities.

Liquidity and Capital Resources

The Company generates cash primarily through its investments in various regulated and non-regulated energy related entities and investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include general economic downturns in Emera’s markets, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets and changes in environmental legislation. Emera’s subsidiaries maintain solid credit metrics and are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment.

Consolidated Cash Flow Highlights

Significant changes in the statements of cash flows between the three months ended March 31, 2016 and 2015 include:

	2016			2015			$ Change
	millions of Canadian dollars
Cash and cash equivalents, beginning of period	$	1,073.4		$	221.1		$	852.3
Provided by (used in):
Operating cash flow before change in working capital		232.4			257.5			(25.1	)
Change in working capital		(51.8	)		(137.9	)		86.1
Operating activities		180.6			119.6			61.0
Investing activities		(139.3	)		195.9			(335.2	)
Financing activities		(45.8	)		(259.3	)		213.5
Effect of exchange rate changes on cash and cash equivalents		(69.4	)		28.0			(97.4	)
Cash and cash equivalents, end of period	$	999.5		$	305.3		$	694.2

Significant changes in the statements of cash flows between the years ended December 31, 2015 and 2014 include:

	Year ended December 31
	2015			2014		$ Change
	millions of Canadian dollars
Cash and cash equivalents, beginning of period	$	221.1		$	100.8	$	120.3
Provided by (used in):
Operating cash flow before changes in working capital		775.8			716.3		59.5
Change in working capital		(101.6	)		46.2		(147.8	)

161

	Year ended December 31
	2015			2014			$ Change
	millions of Canadian dollars
Operating activities		674.2			762.5			(88.3	)
Investing activities		(123.7	)		(710.9	)		587.2
Financing activities		221.1			58.2			162.9
Effect of exchange rate changes on cash and cash equivalents		80.7			10.5			70.2
Cash and cash equivalents, end of period	$	1,073.4		$	221.1		$	852.3

Operating Cash Flows

Refer to Consolidated Income Statement Highlights and Operating Cash Flow Highlights for details.

Investing Cash Flows

Net cash used in investing activities increased Cdn$335.2 million to Cdn$139.3 million for the three months ended March 31, 2016 compared to net cash provided by investing activities of Cdn$195.9 million for the same period in 2015. The increase was primarily due to proceeds from the sale of NWP in 2015 and increased investments in NSPML and LIL in 2016.

Capital expenditures for the three months ended March 31, 2016, including AFUDC and net of proceeds from disposal of assets, were Cdn$87 million compared to Cdn$83 million during the same period in 2015.

Details of the capital spend are shown below:

• Cdn$48 million at NSPI (2015 – Cdn$51 million);

• Cdn$9 million at Emera Maine (2015 – Cdn$19 million);

• Cdn$22 million at Emera Caribbean (2015 – Cdn$9 million);

• Cdn$6 million at Emera Energy (2015 – Cdn$2 million);

• Cdn$2 million in Corporate and Other (2015 – Cdn$2 million)

Net cash used in investing activities decreased Cdn$587.2 million to Cdn$123.7 million for the year ended December 31, 2015 compared to Cdn$710.9 million for the year ended December 31, 2014. The decrease was primarily due to proceeds from the sale of NWP in 2015, proceeds from the Bear Swamp distribution, purchase of APUC subscription receipts in 2014 and higher levels of investment in NSPML and M&NP in 2014, partially offset by increased capital spend and Emera Maine’s investment in a customer information system.

Capital expenditures, including AFUDC and net of proceeds from disposal of assets, for the year ended December 31, 2015 were Cdn$436 million compared to Cdn$462 million in 2014 primarily due to decreased capital spending in Emera Energy and Emera Maine, partially offset by increased capital spending at Emera Caribbean. Details of the capital spend are shown below:

• Cdn$274 million in NSPI (2014 – Cdn$274 million);

• Cdn$66 million in Emera Maine (2014 – Cdn$85 million);

• Cdn$44 million in Emera Caribbean (2014 – Cdn$30 million);

• Cdn$42 million in Emera Energy (2014 – Cdn$63 million);

• Cdn$10 million in Corporate and Other (2014 – Cdn$10 million)

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Financing Cash Flows

Net cash used in financing activities decreased Cdn$213.5 million to Cdn$45.8 million for the three months ended March 31, 2016 compared to Cdn$259.3 million for the same period in 2015. The decrease was primarily due to the repayment of debt in 2015, partially offset by the 2015 proceeds of the long-term debt issuance by EBPC.

Net cash provided by financing activities increased Cdn$162.9 million to Cdn$221.1 million for the year ended December 31, 2015 compared to Cdn$58.2 million in December 31, 2014. The increase was primarily due to the proceeds of Convertible Debentures represented by instalment receipts related to the pending Acquisition, net of issuance costs, of Cdn$681.4 million and the proceeds of the long-term debt issuance by EBPC and NSPI. This was partially offset by the redemption of NSPI’s preferred shares, repayment of debt in 2015 and the issuance of common and preferred stock in Q1 2014.

Working Capital

As at December 31, 2015, Emera’s cash and cash equivalents were Cdn$1,073.4 million (2014 – Cdn$221.1 million) and Emera’s investment in non-cash working capital was Cdn$599.2 million (2014 – Cdn$358.3 million). Of the Cdn$1,073.4 million of cash and cash equivalents held at December 31, 2015, Cdn$727.6 million is from the proceeds from the Convertible Debentures for the Acquisition and are held in USD. Of the remaining cash and cash equivalents, Cdn$373.2 million is held by Emera’s foreign subsidiaries (2014 – Cdn$206.0 million). A portion of these funds are invested in countries that have certain exchange controls, required approvals, and processes for repatriation. Such funds remain available to fund local operating and capital requirements unless repatriated.

Emera’s future liquidity and capital needs will be predominately for working capital requirements and capital expenditures in support of growth throughout the businesses, as well as acquisitions, dividends and debt servicing. These liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to debt and equity capital markets.

Contractual Obligations

As at March 31, 2016, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

	2016		2017		2018		2019		2020		Thereafter		Total
	millions of Canadian dollars
Long-term debt	$	268.8	$	49.5	$	23.8	$	610.1	$	748.5	$	2,301.2	$	4,001.9
Purchased power(1)		166.5		229.8		204.0		198.7		195.2		2,380.5		3,374.7
Solid fuel supply		114.5		75.7		12.0		—		—		—		202.2
DSM		22.1		34.0		34.9		—		—		—		91.0
Pension and post-retirement obligations(2)		11.1		19.2		19.8		20.2		20.9		716.7		807.9
Asset retirement obligations		5.1		4.0		4.3		4.2		1.7		317.2		336.5
Interest payment obligations(3)		140.0		177.4		175.1		167.7		138.8		2,244.7		3,043.7
Convertible debentures represented by instalment receipts(4)		727.6		—		—		—		—		—		727.6
Interest obligations on the first instalment of convertible debentures represented by instalment receipts(4)		54.1		—		—		—		—		—		54.1
Transportation(5)		188.9		118.6		78.2		43.2		41.1		86.3		556.3

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	2016		2017		2018		2019		2020		Thereafter		Total
	millions of Canadian dollars
Long-term service agreements(6)		48.6		49.6		34.4		47.1		20.4		202.1		402.2
Capital projects		69.2		5.6		—		—		—		—		74.8
Equity investment commitments(7)		356.0		183.0		—		—		—		—		539.0
Leases and other(8)		18.9		9.9		9.0		8.4		7.3		19.0		72.5
	$	2,191.4	$	956.3	$	595.5	$	1,099.6	$	1,173.9	$	8,267.7	$	14,284.4

(1) Annual requirement to purchase 20 to 100% of electricity production from independent power producers over varying contract lengths up to 25 years.

(2) Defined benefit funding contractual obligations were determined based on funding requirements and assuming pension accruals cease as at December 31, 2015. Credited service and earnings are assumed to be crystallized as at December 31, 2015. The Company’s contractual obligations for post-retirement (non-pension) benefits assumes members must be age 55 or over as at December 31, 2015 to be eligible. As the defined benefit pension plans currently undergoes regular reviews to revise contribution requirements and members are still accruing service under the plans, actual future contributions to the plans will differ from the amounts shown.

(3) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at March 31, 2016, including any expected required payment under associated swap agreements.

(4) In 2015, to finance a portion of the pending Acquisition, Emera completed the sale of the Convertible Debentures. The Convertible Debentures were sold on an instalment basis, with 1/3 paid on closing of the Convertible Debenture Offering, and the remaining payable on a date to be fixed following satisfaction of conditions precedent to the closing of the Acquisition.

(5) Purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines.

(6) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(7) Emera has a commitment in connection with the Federal Loan Guarantee (“FLG”) to complete construction of the Maritime Link. Thirty percent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction.

(8) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

Other Contractual Obligations

On September 4, 2015, the Company announced a definitive agreement for Emera to acquire TECO Energy for $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.6 billion USD and includes the assumption of approximately $4.1 billion USD of debt. Further information on the pending Acquisition is discussed in the Developments section.

Forecasted Gross Consolidated Capital Expenditures

For the year ended December 31, 2016, forecasted gross consolidated capital expenditures are as follows:

	NSPI		Emera Maine		Emera Caribbean		Emera Energy		Corporate and Other		Total
	millions of Canadian dollars (except per share amounts)
Generation	$	105.0	$	—	$	17.9	$	29.9	$	—	$	152.8
New renewable generation		—		—		67.3		—		—		67.3

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	NSPI		Emera Maine		Emera Caribbean		Emera Energy		Corporate and Other		Total
	millions of Canadian dollars (except per share amounts)
Transmission		56.1		33.6		5.9		—		—		95.6
Distribution		74.8		34.3		38.3						147.4
Facilities, equipment, vehicles, and other		44.0		17.2		20.1				20.4		101.7
	$	279.9	$	85.1	$	149.5	$	29.9	$	20.4	$	564.8

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately Cdn$1.3 billion committed syndicated revolving bank lines of credit per the table below. NSPI has an active commercial paper program for up to Cdn$500 million, of which the full amount outstanding is backed by NSPI’s operating credit facility referred to below. The amount of commercial paper issued results in an equal amount of its operating credit facility being considered drawn and unavailable.

As at March 31, 2016, the Company’s total credit facilities, outstanding borrowings and available capacity were as follows:

	Maturity		Revolving Credit Facilities		Utilized		Undrawn and Available
	millions of dollars
Emera – Operating and acquisition credit facility		June 2020 – Revolver	$	700	$	276	$	424
NSPI – Operating credit facility		October 2020 – Revolver		600		386		114
Emera Maine – in USD – Operating credit facility		September 2019 – Revolver		80		21		59
Other – in USD – Operating credit facilities		Various		32		2		30

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements as at March 31, 2016.

For the purpose of bridge financing for the pending Acquisition, on September 4, 2015, the Company secured an aggregate of $6.5 billion USD non-revolving term credit facilities from a syndicate of banks. The non-revolving term credit facilities are comprised of a $4.3 billion USD debt bridge facility, repayable in full on the first anniversary following its advance, and a $2.2 billion USD equity bridge facility repayable in full on the first anniversary following its advance. On October 16, 2015, Emera permanently reduced the USD bridge facilities in the amount of $588.3 million USD with the proceeds of the First Instalment of the Convertible Debentures and the proceeds from the Bear Swamp financing. The credit facilities table above does not include the Acquisition Credit Facilities.

Emera is required to effect reductions or make prepayments of the Acquisition Credit Facilities in an amount equal to the net cash proceeds from any common equity, preferred equity, bond or other debt offerings and any non-ordinary course asset sales by Emera and its subsidiaries, subject to certain prescribed exceptions and certain other prescribed transactions. Net proceeds from any such offerings, including the net proceeds of the Final Instalment under the Convertible Debenture and the other Acquisition Capital Markets Transactions, or from any such non-ordinary course asset sales or transactions, including Emera’s sale of a portion of its ownership in APUC, will be applied to permanently reduce the commitments under the Acquisition Credit Facilities or to repay the Acquisition Credit Facilities after they are drawn. Any prepayment under the Acquisition Credit Facilities may not be re-borrowed. The Acquisition Credit Agreements contain customary representations and warranties and affirmative and negative covenants of Emera that will closely resemble those in Emera’s existing revolving credit facility.

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Emera’s future liquidity and capital needs, not including the capital needs to fund the Acquisition, will be predominately for working capital requirements and capital expenditures in support of growth throughout the businesses, potential new acquisitions, dividends and debt servicing. These liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to capital markets.

The cash purchase price of the Acquisition and the Acquisition-Related Expenses will be financed at the closing of the Acquisition with a combination of some or all of the following: (i) the proceeds from the Acquisition Capital Markets Transactions, including any series of Notes offered hereunder, (ii) the receipt of payment in full on the Final Instalment Date of the Final Instalment due under the Convertible Debentures, (iii) amounts drawn under the Acquisition Credit Facilities, if any, and (iv) existing cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) and other sources available to Emera.

Emera and its subsidiaries recent financing activity is discussed further in the Developments section of the MD&A.

Share Capital

Emera

As at December 31, 2015, Emera had 147.21 million (2014 – 143.78 million) common shares issued and outstanding. For the year ended December 31, 2015, 3.43 million common shares were issued (2014 –10.89 million) for net proceeds of Cdn$141.1 million (2014 – Cdn$313.4 million). The issuance of shares was primarily due to facilitate the creation and issuance of depositary receipts in connection with the ECI share acquisition and the dividend reinvestment program.

On December 17, 2015, Emera issued 1.25 million common shares to facilitate the creation and issuance of 5.0 million depositary receipts in connection with the ECI share acquisition.

As at December 31, 2015, Emera had 29.0 million preferred shares issued and outstanding (2014 – 29.0 million).

Pension Funding

For funding purposes, Emera determines required contributions to its largest defined benefit pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the impact of investment gains and losses are recognized over a three-year period. The cash required in 2016 for defined benefit pension plans is expected to be Cdn$19.7 million (2015 – Cdn$ 23.0 million). All pension plan contributions are tax deductible and will be funded with cash from operations.

Emera’s defined benefit pension plans employ a long-term strategic approach with respect to asset allocation, real return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of preserving capital within an acceptable level of risk for the pension fund investments.

To achieve the overall long-term asset allocation, pension assets are managed by external investment managers per the pension plan’s investment policy and governance framework. The asset allocation includes investments in the assets of Canadian and global equities, domestic and global bonds and short- term investments. Emera reviews investment manager performance on a regular basis and adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.

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Emera’s projected contributions to defined contribution pension plans are Cdn$10.0 million for 2016 (2015 – Cdn$9.0 million actual).

Defined Benefit Pension Plan Summary

As at December 31, 2015

millions of Canadian dollars

Plans by region	NSPI Pension Plans		Emera Maine Pension Plans		Caribbean Plans		Total
Assets as at December 31, 2015	$	1,128.6	$	161.5	$	10.3	$	1,300.4
Accounting obligation at December 31, 2015		1,295.8		211.3		12.6		1,519.7
Accounting expense during fiscal 2015	$	56.1	$	6.4	$	0.4	$	62.9

Off-Balance Sheet Arrangements

Defeasance

Upon privatization of the former provincially owned NSPC in 1992, NSPI became responsible for managing a portfolio of defeasance securities that provide principal and interest streams to match the related defeased debt, which at December 31, 2015 totaled Cdn$0.8 billion (2014 – Cdn$0.7 billion). The securities are held in trust for Nova Scotia Power Finance Corporation (“NSPFC”), an affiliate of the Province of Nova Scotia. Approximately 70% of the defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance portfolio has a market value higher than the related debt, reducing the future risk of this portion of the portfolio.

Under the privatization agreements, NSPI administers the defeasance cash flows and obligations pursuant to a Management and Administration Agreement. The NSPFC bank accounts are included in NSPI’s pool of bank accounts under a mirror netting agreement and therefore, from time to time, if any cash accumulates in the NSPFC bank account it is available as an offset until that cash is required to service the defeased NSPC debt.

Guarantees and Letters of Credit

Emera had outstanding the following guarantees and letters of credit on behalf of third parties which are not included within the Consolidated Balance Sheets as at December 31, 2015:

• Emera has provided a completion guarantee to the Government of Canada, whereby it has guaranteed the performance of the obligations of NSPML to cause the completion of the Maritime Link Project, subject to certain conditions set out in that guarantee. The cost of those obligations is estimated to be Cdn$1.577 billion, which reduces in the ordinary course as project costs are paid.

• Emera has provided a guarantee to the Long Island Power Authority on behalf of Bear Swamp for Bear Swamp’s long-term energy and capacity supply agreement with the Long Island Power Authority, which expires on April 30, 2021. The guarantee is for 50% of the relevant obligations under the PPA up to a maximum of $5.1 million USD. As at December 31, 2015, the fair value of the PPA was positive.

• Standby letters of credit in the amount of $20.5 million USD for the benefit of secured parties in connection with a refinancing of the Bear Swamp joint venture and also to third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one-year term and are renewed annually as required.

• A standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2016 and is renewed annually. The amount committed as at December 31, 2015 was Cdn$42.6 million.

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• A standby letter of credit to secure obligations under an unfunded pension plan in Emera Maine. The letter of credit expires in October 2016 and is renewed annually. The amount committed as at December 31, 2015 was $2.7 million USD.

• A standby letter of credit was issued to secure the obligations of Emera Reinsurance Limited under reinsurance agreements. The letter of credit expires in February 2016. The amount committed as at December 31, 2015 was $2.0 million USD.

Outlook

Energy markets across North America are affected by a number of trends that shape the environment in which energy and utility companies are operating. Some of these trends are short-term or cyclical, while others evolve to have a significant long-term impact on businesses and stakeholders across the sector.

Among the key trends influencing Emera’s long-term strategy is the increasing expectation by customers and policy-makers for a permanent reduction in the carbon-equivalent levels of electricity generation. This advocacy drive for cleaner, renewable sources of electricity has become a defining trend in the industry in recent years, not just in the markets Emera serves, but on a global basis. While it is still unclear whether economic volatility and lower fossil fuel prices will slow the pace of this transformation, its impact on the sector continues to be felt in the form of mandated and incented carbon reductions throughout eastern North America and in the Caribbean. As such, investment in wind and hydro generation, and natural gas infrastructure, is likely to continue across the sector.

This transformation in generation and fuel selection also has a significant impact on the requirement for new transmission infrastructure. Increasingly, in addition to the traditional issues of infrastructure life expectancy and changing technology, infrastructure renewal planning must now also take into account the changing energy landscape. Gas extraction from the Marcellus Shale region of the United States, major new hydro developments in Newfoundland and Labrador, and development of new wind farms in northern New England and Atlantic Canada (to name a few) require significant new transmission infrastructure to bring this energy to market.

The capital spending requirements related to this renewal underscore the intense focus placed by customers and regulators on electricity price and affordability that is required by our franchise agreements and basic rate regulation. Going forward, the ability of energy companies to achieve their growth objectives, environmental targets and other goals, will continue to be a key success factor.

As technology advances, so does the availability and demand for affordable new mechanisms that allow consumers to have more control over their energy usage and for utilities to introduce more efficient energy solutions for their customers. This includes grid modernization or ‘smart grid’ advances that, when combined with in-home products such as heat pumps and electric thermal storage units, have the potential to significantly increase energy efficiency for consumers while allowing utilities to better manage peak load demand. In addition, like wind turbine technology, advancements in solar technology have reduced solar generation costs significantly, bringing them more in line with the cost of fossil fuel generation in some higher-cost jurisdictions. This gives rise to customer expectations that they will be able to benefit from options such as distributed generation. Continued and advancing development of energy storage technology will further transform and support the efficient and practical utilization of renewables.

These and other trends create opportunities and challenges for businesses, regulators, investors and other stakeholders within the energy sector, and are expected to drive increased regional cooperation and interconnection within the energy industry. Whether it is the need to transport natural gas and electricity from disparate regions to markets on the eastern seaboard, or the need to gain efficiencies by coordinating electricity generation and dispatch across multiple jurisdictions, inter-regional cooperation has emerged as an important trend in itself.

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Business Outlook

The Acquisition will result in further acquisition costs in 2016. The Acquisition is expected to be accretive to EPS by approximately 5% in the first full year following its completion (2017), growing to more than 10% by the third full year (2019) assuming a USD/CAD exchange rate consistent with that at the time of announcement. Approximately 95% of the expected foreign exchange exposure to close the pending acquisition has been effectively hedged.

Emera’s operations are affected by the U.S. dollar relative to the Canadian dollar. With the disparity between the two currencies, the effect on Emera’s income is noteworthy, as approximately 50% of Emera’s adjusted net income was derived from subsidiaries with a U.S. functional currency. TECO Energy operations are conducted in U.S. dollars and following the pending acquisition, Emera’s consolidated net income and cash flows will be impacted to a greater extent by movements in the U.S. dollar relative to the Canadian dollar.

NSPI

NSPI’s earnings are most directly impacted by the range of rate of return on equity and capital structure approved by the UARB; the prudent management and approved recovery of operating costs, load, the approved recovery of regulatory deferrals; and the timing and amount of capital expenditures.

While NSPI has experienced an unseasonably warm heating season with increased storm activity, NSPI anticipates earning within its allowed ROE range in 2016 and expects its earnings and rate base to be generally consistent with prior years.

Over the past several years, the requirement to reduce Nova Scotia’s reliance upon high carbon and greenhouse gas emitting sources of energy has resulted in NSPI making a significant investment in renewable energy sources and purchasing third party renewable energy. In December 2015, the Electricity Plan Act was enacted by the Province of Nova Scotia, with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period. In accordance with the Electricity Plan Act, NSPI filed a three-year rate plan with the UARB for Fuel Costs in Q1 2016, which requested average annual rate increases of 1.3% for 2017 through 2019. NSPI also announced that it will not file a general rate application for non-fuel costs for the 2017 to 2019 period. This was a result of NSPI continuing to work towards rate stability for customers through a focused effort on operating costs, productivity levels and service improvements.

In 2015, NSPI filed an application with the UARB for the introduction of a regulatory framework to enable the purchase by retail customers of renewable low-impact electricity generated in Nova Scotia from retail suppliers licensed by the UARB. In Q1 2016, the UARB issued a decision affirming NSPI’s proposed framework subject to small revisions. It is expected the market implementation process will be completed by the end of 2016.

Capital expenditures for 2016, including AFUDC are forecasted to be Cdn$282.5 million (2015 – Cdn$274.0 million actual).

Emera Maine

Emera Maine’s earnings are most directly impacted by the combined impacts of the range of rates of return on equity and rate base approved by its regulators, the prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures.

Emera Maine’s 2016 ROE and earnings are expected to be generally consistent with prior years. Its ongoing investment in transmission and distribution infrastructure is expected to result in modest growth in rate base.

Emera Maine has an agreement with Central Maine Power Company to pursue specific transmission opportunities in northern Maine that would relieve transmission congestion and more efficiently collect and

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deliver wind to southern New England markets. As part of this agreement, Emera Maine and Central Maine Power Company jointly responded in Q1 2016 to a request for proposals from Massachusetts, Connecticut and Rhode Island. The demand for new renewable energy, and the infrastructure to deliver that energy to market, is growing as a result of increasing renewable portfolio requirements of the southern New England states.

There are three outstanding pending complaints, with the FERC, to challenge the ISO-New England Open Access Transmission Tariff-allowed base ROE. On March 22, 2016, the Administrative Law Judge (“ALJ”) issued a recommended decision to the FERC with respect to the first two outstanding ROE complaints. The ALJ recommendation for the ENE Case was a 9.59% base ROE, with a 10.42% maximum ROE, and the recommendation for MA AG II Case was a 10.90% base ROE, with a 12.19% maximum ROE. A reserve was calculated on a 10.57% base and represents Emera Maine’s best estimate of the probable outcome for the two outstanding complaints, and no update was made to the reserve based on the ALJ recommendation, as it is pending approval by the FERC and considered uncertain until that time. On April 29, 2016, an additional complaint was filed with FERC challenging the ROE under the ISO-NE transmission tariff. The complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”), a collection of thirteen municipal light departments, seeking to reduce the base transmission ROE to a maximum of 8.93% and the maximum ROE of 11.24%. No reserve has been made as a result of this complaint, as the outcome is considered uncertain.

In 2016, Emera Maine expects to invest approximately Cdn$89.5 million (2015 – Cdn$66 million actual), including approximately Cdn$42.9 million for transmission projects.

Emera Caribbean

Earnings from Emera Caribbean are most directly impacted by the combined impacts of the range of rates of return on rate base approved by their regulators, capital structure, prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures. Earnings are also affected by the investment returns of Emera’s interest in BLPC’s self-insurance fund.

The Barbados economy is forecasted to grow modestly in 2016. With oil being the predominant fuel source for generation of electricity in the Caribbean, reduced oil prices may result in an economic benefit on the island in decreased cost of electricity to ratepayers.

The economy of Grand Bahama is highly correlated to the United States economy. In 2015, the economy of Grand Bahama exhibited signs of improving with economic growth in the industrial sector and weather related growth in the residential sector. 2016 sales are expected to be flat compared to 2015.

Overall, Emera Caribbean earnings and rate base are expected to be generally consistent with prior years. GBPC’s 2016 earnings will reflect its 8.8% allowable return on rate base.

Emera Caribbean plans to invest approximately Cdn$125.2 million in capital programs in 2016 (2015 – Cdn$44.0 million actual). This increase is due to spending on a new solar facility in Barbados.

Pipelines

The timing of the income from Pipelines is predominately a result of capital lease accounting treatment of the Emera Brunswick Pipeline, which yields declining earnings over the life of the asset.

Pipelines’ 2016 earnings are expected to be lower than 2015 as a result of less favourable foreign exchange exposure and higher OM&G costs.

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Emera Energy

Emera Energy Services

Emera Energy Services, Emera Energy’s marketing and trading business, is generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply/demand factors, can provide higher levels of margin opportunity.

In addition to capitalizing on volatility-driven market opportunities, Emera Energy Services expects to continue to grow organically building market share through superior customer service and expanding its geographic reach to adjacent markets, including the Marcellus Shale region.

Planned investment by the industry in gas transportation infrastructure within the northeast United States over the next few years could reduce the degree of volatility recently experienced in the market, all other things being equal. This could negatively affect profitability during certain periods.

Emera Energy Generation

Earnings from Emera Energy Generation’s assets are largely dependent on market conditions, in particular, the relative pricing of electricity and natural gas and capacity pricing for the New England Gas Generation Facilities. Efficient operations of the fleet to ensure unit availability, cost management and effective commercial performance are key success factors.

2016 adjusted earnings from Emera Energy generating assets are expected to be lower than 2015, reflecting lower hedged and expected margins as compared to 2015.

In addition to energy margins and ancillary revenue, the New England Gas Generating Facilities and Bear Swamp earn revenue from capacity payments through the forward capacity market, the annual reconfiguration capacity market and the monthly reconfiguration capacity market. Prices for the forward capacity market, the larger of the two components, are determined through an auction process held annually, three years in advance, providing revenue visibility to 2020, presuming the facilities continue to be available to support their capacity obligations. Details of pricing and estimated revenues are outlined in the table below for the New England Gas Generating facilities, and Emera Energy’s 50% interest in Bear Swamp.

Forward Capacity Auction (“FCA”) Year	Clearing Price in $/kW-month (in USD)	Approximate Estimated Annual Capacity Revenue (in USD) (1)
FCA6 (June 2015 to May 2016)	$3.43	$40 million
FCA7 (June 2016 to May 2017)	$3.15	$40 million
FCA8 (June 2017 to May 2018)	$7.025	$100 million
FCA9 (June 2018 to May 2019)	$9.55 and $11.08(2)	$145 million
FCA 10 (June 2019 to May 2020)	$7.03	$106 million

(1) Includes Emera’s 50% share of Bear Swamp’s capacity revenue

(2) US$11.08 was awarded for the Southeast Massachusetts/Rhode Island zone only and, as such, applies only to Tiverton

Bear Swamp’s adjusted earnings will be lower in 2016 and the first half of 2017 primarily due to higher interest costs as a result of its Q4 2015 refinancing. Beginning Q3 2017, these interest costs are expected to be offset by higher capacity revenues.

In 2016, Emera Energy expects to invest approximately Cdn$41.0 million (2015 – Cdn$42.0 million actual) in capital projects related to its generating assets in order to further improve reliability and increase plant capacity.

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Corporate and Other

Corporate and Other is dependent, in part, on business development and acquisition-related initiatives, which in 2016 will include further costs related to the Acquisition, AFUDC earnings as a result of equity investments in the Maritime Link Project and the Labrador-Island Link, project-based construction services activity by Emera Utility Services, growth in APUC earnings (which Emera accounts one quarter after APUC reports such earnings), corporate financing costs and other corporate activities.

Corporate’s contribution to consolidated net income in 2016 is expected to be lower than 2015 primarily due to further acquisition costs and associated financing initiatives related to the Acquisition. These costs will include a non-cash accounting charge for the difference between Emera’s closing share price on the issuance date of the Convertible Debentures and their exercise price. This will be recognized once contingencies surrounding regulatory and other approvals are resolved.

In February 9, 2016, APUC announced its intention to acquire The Empire District Electric Company in a Cdn$3.4 billion transaction, which is expected to close in Q1 2017. The closing of this transaction and its related financing will reduce Emera’s percentage ownership interest in APUC.

In 2016, Corporate and Other expects to invest approximately Cdn$8.0 million (2015 – Cdn$10.0 million actual).

ENL

NSP Maritime Link Inc. (“NSPML”)

Through its subsidiary, NSP Maritime Link Inc., ENL had invested at March 31, 2016, approximately Cdn$796.7 million of equity, debt and working capital, including Cdn$90.3 million of AFUDC, in the development of the Maritime Link Project. Project to date, ENL has invested Cdn$206.4 million in equity, comprised of Cdn$169.3 million in equity contributed and Cdn$37.1 million of accumulated retained earnings, with the remaining costs being funded with working capital and debt. The debt has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9%.

ENL’s future earnings contribution from the Maritime Link Project will be affected by the amount and timing of capital expenditures for design and construction activities, which will determine the component of costs to be funded by equity. Proceeds from the federally guaranteed debt financing completed in 2014 were used to fund project costs until the Project’s debt to equity ratio reached 70% to 30% respectively in Q4 2015. From that point forward, project costs are being funded with debt and equity at a 70% to 30% ratio, with equity contributions of Cdn$14.4 million in Q1 2016.

Maritime Link Project forecasted equity contributions for 2016 and 2017 are Cdn$160 million and Cdn$156 million respectively, with total equity for the Project estimated to be Cdn$470.9 million.

Labrador Island Link (“LIL”)

ENL is a limited partner with Nalcor Energy in LIL, currently estimated at approximately Cdn$3.1 billion. As at March 31, 2016, ENL has invested Cdn$250.4 million, comprised of Cdn$224.5 million in equity contributed and Cdn$25.9 million of accumulated equity earnings in LIL. Equity earnings are recorded based on an annual rate of 8.8% of the equity invested. The return on ROE is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”). There is currently an application filed by another regulated electrical utility in Newfoundland and Labrador, being heard by the NLPUB, which includes a review of ROE. The NLPUB’s decision on ROE, expected in Q2 2016, will be applicable for all regulated electrical utilities in Newfoundland and Labrador and become the ROE applicable to ENL’s investment in LIL. Future earnings are dependent on the amount and timing of additional equity investments and the approved ROE. Total equity contributions for Q1 2016 for LIL were Cdn$38.4 million.

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LIL forecasted equity contributions for 2016 and 2017 are Cdn$196.0 million and Cdn$27.0 million respectively, with total equity investment, by Emera, in the Project estimated to be Cdn$409.1 million.

Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s consolidated balance sheets.

Transactions with Related Parties

In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate- regulated entities, is recorded in non-regulated operating revenues, with an offset to property, plant and equipment, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction. 2014 balances have been retrospectively restated, consistent with this approach. Below are transactions between Emera and its associated companies reported in the Consolidated Statements of Income:

			Three months ended March 31
	Nature of Service	Presentation	2016			2015
			millions of Canadian dollars
Sales to:
APUC subsidiary	Net sale of natural gas and transportation	Operating revenue – non-regulated	$	2.0		$	1.6
Purchases from:
M&NP	Natural gas transportation capacity	Regulated fuel for generation and purchased power		0.3		$	0.2
M&NP	Natural gas transportation capacity	Operating revenue – non-regulated	$	(8.1	)	$	(6.3	)

Operating revenue—non-regulated includes intercompany profit relating to the sale of natural gas, sale of power, construction, operations management and engineering services, and hedging services to rate- regulated subsidiaries of Emera totaling Cdn$0.3 million for the three months ended March 31, 2016 (2015 – Cdn$(0.2) million).

			Year ended December 31
	New England	Maritime Canada	2015			2014
			millions of Canadian dollars
Sales to:
APUC subsidiary	Net sale of natural gas and transportation	Operating revenue – non-regulated	$	3.0		$	4.4
NWP	Energy management services	Operating revenue – regulated		0.3			1.1
Purchases from:
M&NP	Natural gas transportation capacity	Regulated fuel for generation and purchased power		4.5			3.6
M&NP	Natural gas transportation capacity	Operating revenue – non-regulated		(23.4	)		(23.8	)
NWP	Purchase of power	Regulated fuel for generation and purchased power	$	0.3		$	1.9

Operating revenue—non-regulated includes intercompany profit relating to the sale of natural gas, sale of power, construction, operations management and engineering services, and hedging services to rate- regulated subsidiaries of Emera totaling Cdn$1.6 million for the year ended December 31, 2015 (2014 – Cdn$4.2 million).

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Amounts reported on Emera’s Consolidated Balance Sheets due (to) from its equity investments are summarized in the following tables:

	March 31 2016		December 31 2015
	millions of Canadian dollars
Due from related parties:
NSPML – current	$	1.2	$	1.6
Subsidiary of APUC – current		0.3		0.7
M&NP – loan receivable – long-term		2.5		2.5
Due to related parties:
M&NP – current		2.3		2.1
Net due from (to) related parties	$	1.7	$	2.7

All amounts are under normal interest and credit terms, except for a loan receivable from M&NP bearing interest at 1% per annum maturing on November 30, 2019.

Amounts reported on Emera’s Consolidated Balance Sheets due (to) from its equity investments are summarized in the following tables:

	December 31, 2015		December 31, 2014
	millions of Canadian dollars
Due from related parties:
Subsidiary of APUC – current(1)	$	0.7	$	—
NSPML – current		1.6		3.5
M&NP – loan receivable – long-term		2.5		2.5
Due to related parties:
M&NP – current		2.1		1.6
Net due from (to) related parties	$	2.7	$	4.4

(1) Amount due from a subsidiary of APUC is included in accounts receivable.

All amounts are under normal interest and credit terms, except for a loan receivable from M&NP bearing interest at 1% per annum maturing on November 30, 2019.

Dividends and Payout Ratios

Emera Incorporated’s common share dividends paid in 2015 were Cdn$1.66 (Cdn$0.3875 in Q1, Cdn$0.4000 in Q2 and Q3 and Cdn$0.4750 in Q4) and Cdn$1.48 (Cdn$0.3625 per quarter in Q1, Q2 and Q3 and Cdn$0.3875 in Q4) per common share for 2014, representing a payout ratio of 72.8% of adjusted net income in 2015 and 65.8% for 2014. The increase in the payout ratio is primarily due to an increase in dividends paid greater than growth in adjusted net income.

On August 10, 2015, Emera’s Board of Directors approved an increase in the annual common share dividend rate from Cdn$1.60 to Cdn$1.90 per common share.

Enterprise Risk and Risk Management

Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management. Certain risk management activities for Emera are overseen by the Enterprise Risk Management Committee to ensure such risks are appropriately assessed, monitored and controlled within predetermined risk tolerances established through approved policies.

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The Company’s risk management activities are focused on those areas that most significantly impact profitability, quality of income and cash flow. These risks include, but are not limited to, exposure to regulatory and political risk, acquisition, weather, changes in environmental legislation, energy consumption, foreign exchange, capital market and liquidity risk, interest rate, project development and construction risk, cybersecurity, non-regulated plant operational risk, credit, country, commercial relationships, commodity price risk, future employee benefit plan performance and funding, labour, information technology and un-insured risk.

In this section, Emera describes some of the principal risks that management believes could materially affect its business, revenues, operating income, net income, net assets, or liquidity or capital resources. The nature of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered material may become material in the future.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments in a timely manner. As cost-of-service utilities with an obligation to serve customers, NSPI, Emera Maine, BLPC, GBPC, and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs and investments can be recovered upon approval by the respective regulator of the recovery in adjustments to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. In addition, the commercial and regulatory frameworks under which Emera and its subsidiaries operate can be impacted by significant shifts in government policy and changes in governments. Emera’s investments in entities in which it has significant influence and which are subject to regulatory risk include: NSPML, M&NP, LIL and Lucelec.

During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these subsidiaries and their respective regulators determine whether to allow recovery and to adjust rates based upon the subsidiaries’ evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, fuel-related audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.

Brunswick Pipeline entered into a 25-year firm service agreement, expiring in 2034, with RECL, which was filed with the NEB. The firm service agreement provides for predetermined toll increases after the fifth and fifteenth year of the contract. As a regulated Group II pipeline, the tolls of the Brunswick Pipeline are regulated by the NEB on a complaint basis. EBPC is required to make copies of tariffs and supporting financial information readily available to interested persons.

Persons who cannot resolve traffic, toll and tariff issues with EBPC may file a complaint with the NEB. In the absence of a complaint, the NEB does not normally undertake a detailed examination of the Brunswick Pipeline’s tolls.

Acquisition Risk

The risks associated with Emera’s acquisition strategy include potential difficulties inherent in acquisitions that may adversely affect the results of an acquisition and these include delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies from completed transactions.

Emera mitigates these risks by following systematic procedures for integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to close monitoring and review by the Board of Directors.

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Weather Risk

Shifts in weather patterns affect electric sales volumes and associated revenues and costs. Extreme weather events generally result in increased operating costs associated with restoring power to customers, as a result of unplanned outages. Emera responds to significant weather events related outages according to each subsidiary’s respective emergency services restoration plan.

Changes in Environmental Legislation and Regulation

Emera is subject to legislation and regulation by federal, provincial, state, regional and local authorities with regard to environmental matters, primarily related to its utility operations. This includes laws and regulations setting greenhouse gas (“GHG”) emissions standards and air emissions standards. Emera is also subject to laws and regulations regarding the generation, storage, transportation, use and disposal of hazardous substances and materials.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera.

New emission reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s operations and financial performance. Stricter environmental laws and regulations and enforcement of such laws and regulations in the future could increase Emera’s exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments.

Energy Consumption Risk

Typical of utilities, Emera is affected by demand for energy in the areas in which it operates based upon fluctuations in general economic conditions, such as changes in employment levels, personal disposable income, energy prices and housing starts. Customers’ focus on energy efficiency could also result in changes in energy consumption.

Government policies promoting distributed generation and new technology developments enabling those policies, particularly with rooftop solar, have the potential to impact residential sales and thereby revenues. This could negatively impact operations, net earnings and cash flows. Energy costs and clean energy options have increased demand for products enabling the consumers’ ability to self-generate.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. In 2015, approximately 50% of Emera’s adjusted net income was derived from subsidiaries with U.S. functional currency. As such, its earnings are subject to fluctuations in the Canadian dollar to U.S. dollar exchange rate. As discussed below, the pending Acquisition will increase this percentage significantly.

The Company identifies and hedges significant transactional currency risks in accordance with its policies and procedures. Emera does not currently hedge the value of its investments in foreign subsidiaries.

Exchange gains and losses on net investments in foreign subsidiaries are included in accumulated other comprehensive income (loss).

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The Company enters into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams, capital expenditures and capital projects. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange.

Emera does not enter into hedges for its foreign currency translation exposure on its non-Canadian assets. Any changes in the Canadian exchange rate will affect the equivalent Canadian dollar value of such assets, and the equivalent Canadian dollar value of these assets, revenues and earnings contributions.

Acquisition

The cash consideration for the Acquisition is required to be paid in U.S. dollars, while funds raised in any Canadian dollar offering forming part of the Acquisition Capital Markets Transactions, which may constitute a significant portion of the funds ultimately used to finance the Acquisition, are denominated in Canadian dollars. As a result, increases in the value of the U.S. dollar versus the Canadian dollar prior to either the payment of the final instalment or the close of any Canadian dollar offerings will increase the purchase price translated in Canadian dollars and thereby increase the Canadian dollars required to fund the U.S. dollar purchase price for the Acquisition ultimately obtained by Emera.

The proceeds of the first instalment of the Convertible Debenture Offering and the overallotment were converted to U.S. dollars and invested in short-term U.S. dollar investment grade securities. During the month of October 2015, Emera entered into foreign exchange forward contracts to economically hedge an amount equal to the anticipated proceeds from the Final Instalment of the Convertible Debenture Offering of the Acquisition of $1.457 billion. These foreign exchange contracts are economic hedges and do not qualify for hedge accounting. Therefore, all mark-to-market gains and losses related to the forwards and related to the U.S. denominated cash proceeds will be recognized in net income for the period. Until the hedge settles and the USD denominated cash is used to acquire TECO Energy, foreign exchange fluctuations could create significant mark-to-market adjustments that may result in volatility in Emera’s earnings.

In addition, the operations of TECO Energy are conducted in U.S. dollars. Following the Acquisition, the consolidated net income and cash flows of Emera will be impacted to a greater extent by movements in the U.S. dollar relative to the Canadian dollar. In particular, decreases in the value of the U.S. dollar versus the Canadian dollar following the Acquisition, could negatively impact the Company’s net income as reported in Canadian dollars, which could cause a failure to realize all or some of the anticipated benefits of the Acquisition, including accretion.

Capital Market and Liquidity Risk

Emera’s utility and non-utility operations and projects in development require significant capital investments in property, plant and equipment. Consequently, Emera is an active participant in the debt and equity markets. Any disruption in capital markets could have a material impact on Emera’s ability to fund its operations. Capital markets are global in nature and are affected by numerous events throughout the world economy. Capital market disruptions could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions.

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera forecasts cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed ordinary course capital needs.

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Emera is subject to financial risk associated with changes in its credit ratings. A change to a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations.

Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.

The Company is subject to interest rate risk relating to certain sources of expected funds to effect the TECO Energy acquisition. Any movement in interest rates could affect the underlying cost of the instrument used to fund the Acquisition. The Company may enter into interest rate hedging contracts to limit its exposure to fluctuations in interest rates.

For Emera’s regulated subsidiaries, the cost of debt is generally passed through to ratepayers. While regulatory ROE rates will generally and indirectly follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and raise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives.

Project Development and Construction Risk

ENL’s planned investment in the development of the Maritime Link Project has risks commensurate with any large construction project. Risks related to such large projects include impact on costs of schedule delays and risk of cost overruns. Emera has deployed a robust project and risk management approach to this project, led by a team with extensive experience in large projects. There are also significant contractual terms in place protecting Emera and ENL from any exposure to cost overruns to either of Nalcor’s projects and with specific provisions for Nalcor sharing in cost overruns of the Maritime Link Project.

In February 2015, ENL entered into a contract with Abengoa S.A., a global Spanish energy company, for the transmission line construction on the Maritime Link Project. On November 25, 2015, Abengoa S.A. filed a notice under Spanish law, which provides for pre insolvency protection in Spain, giving ENL up to four months to reach an agreement with creditors to avoid a full insolvency process. ENL is working closely with Abengoa and the performance bond sureties to minimize project impacts. Work on the Project continues.

Cybersecurity Risk

Emera’s reliance on information technology to manage its business exposes the Company to potential risks related to cybersecurity attacks and unauthorized access to the Company’s, customers’, suppliers’, counterparties’ and employees’ sensitive or confidential information, (which may include personally identifiable information and credit information) through hacking, viruses and otherwise (collectively “cybersecurity threats”). The Company uses information technology systems and network infrastructure, which include controls for interconnected systems of generation, distribution, and transmission, some of which is shared with third parties for operating purposes. Through the normal course of business, the Company also collects, processes, and retains sensitive and confidential customer, supplier, counter- party and employee information.

Despite security measures in place, the Company’s systems, assets and information could be vulnerable to cybersecurity attacks and other data security breaches that could cause system failures, disrupt operations,

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adversely affect safety, result in loss of service to customers and release of sensitive or confidential information. Should such cybersecurity threats materialize the Company could suffer costs, losses and damages; all or some of which may not be recoverable through regulatory processes or otherwise.

Emera Energy Trading and Marketing

The majority of Emera’s portfolio of electricity and gas marketing and trading contracts, and in particular its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets, in the event of an operational issue or counterparty default. To measure commodity price risk exposure, Emera employs a number of controls and process, including an estimated value-at-risk analysis of its exposures. The VaR amount represents an estimate of the potential change in fair value that could occur from changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical commodity, primarily in natural gas and power positions. The Company’s commercial arrangements, including the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments, as well as its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are all used to manage and mitigate this risk.

Emera Energy Electricity Sales and Non-Regulated Fuel for Generation and Purchased Power

Emera Energy’s natural gas fired plants in northeastern United States, operating as merchant facilities, are susceptible to the volatility of the New England electricity market and natural gas prices. Market electricity prices are dependent upon a number of factors, including the projected supply and demand of electricity, natural gas prices, the price of other materials used to generate electricity, the cost of complying with applicable environmental and other regulatory requirements and weather conditions. A material change in any one of these factors can materially affect the profitability of the facilities.

Non-Regulated Plant Operational Risk

Emera owns three combined-cycle gas-fired electricity generating facilities in New England (New England Gas Generation Facilities) as well as a gas fired generating facility and biomass fired generating facility in Maritime Canada (Bayside Power and Brooklyn Energy). Power plant operations involve the risk of outages due to failure of generation equipment, transmission lines, pipelines or other equipment, which could make the affected plant unavailable to provide service. Unplanned outages could result in lost revenues, increased capital costs and maintenance expenses, payment of cover costs for any hedges in place, and reduced profitability. Insurance is maintained to mitigate operating risks.

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts.

Country Risk

Operating revenues outside of Canada constituted 45% (28% from the U.S. and 17% from the Caribbean) of Emera’s total operating revenues in 2015 (2014 – 48%, with 31% from the U.S. and 17% from the Caribbean). Emera’s investments are currently in regions where the political and economic risk levels are considered by the

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Company to be acceptable. Emera’s operations in some countries may be subject to the following risks: changes in the rate of economic growth, restrictions on the repatriation of income or capital exchange controls, inflation, the effect of global health, safety and environmental matters or economic conditions and market conditions, and change in financial policy and availability of credit.

Commercial Relationships Risk

The Company is exposed to commercial relationships risk in respect of its reliance on certain key partners, suppliers and customers. The Company manages its commercial relationships risk by monitoring credit risk, as discussed below in Credit Risk, and monitoring of significant developments with its customers, partners and suppliers.

Commodity Price Risk

A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs.

Future Employee Benefit Plan Performance and Funding Risk

Certain Emera subsidiaries have both defined benefit and defined contribution employee benefit plans that cover their employees and retirees. All defined benefit plans are closed to new entrants. The cost of providing these benefit plans varies depending on the plan provisions, interest rates, investment performance and actuarial assumptions concerning the future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used to determine funding levels and contributions to the plans) and expectations around future salary growth, inflation and mortality. Two of the largest drivers of cost are investment performance and interest rates, which are affected by global financial and capital markets. Depending on future interest rates and actual versus expected investment performance, Emera could be required to make larger contributions in the future to fund these plans, which could affect Emera’s cash flows, financial condition and operations.

Labour Risk

Certain Emera employees are subject to collective labour agreements. Approximately 49% of the full-time and term employees within the Emera labour force are represented by local unions.

As at December 31, 2015, approximately 7% of the entire labour force is covered by collective labour agreements that will expire within the next 12 months. Emera seeks to manage this risk through ongoing discussions with local unions. The Company maintains contingency plans in each of its operations to manage and reduce the effect of any potential labor disruption.

Information Technology Risk

Emera relies on various information technology systems to manage operations. This subjects Emera to inherent costs and risks associated with maintaining, upgrading, replacing and changing these systems. This includes impairment of its information technology, potential disruption of internal control systems, substantial capital expenditures, demands on management time and other risks of delays, difficulties in upgrading existing systems, transitioning to new systems or integrating new systems into its current systems.

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Uninsured Risk

Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities, and to provide indemnity in the event of liability to third parties. This is consistent with Emera’s risk management policies. There are certain elements of Emera’s operations which are not insured. These include a significant portion of its electric utilities’ transmission and distribution assets, as is customary in the industry. The cost of this coverage is not economically viable. In addition, Emera accepts deductibles and self-insured retentions under its various insurance policies. Insurance is subject to coverage limits as well as time sensitive claims discovery and reporting provisions and there can be no assurance that the types of liabilities or losses that may be incurred by the Company and its subsidiaries will be covered by insurance. Emera’s regulated utilities would likely apply to their respective regulatory authority to recover any loss or liability through increased customer rates, though there is no assurance the regulatory authority would approve such application in whole or in part.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by Emera and its subsidiaries or claims that fall within a significant self-insured retention could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if regulatory recovery is not available. A limited portion of Emera’s property and casualty insurance is placed with a wholly owned captive insurance company. If a loss is suffered by the captive insurer, it is not able to recover that loss other than through future premiums.

Risk Management Including Financial Instruments

Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management policies and practices are overseen by the Board of Directors. The Company has established a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes establishment of the Enterprise Risk Management Committee, whose responsibilities include preparing and updating a “Risk Dashboard” for the Board of Directors on a quarterly basis. Furthermore, a corporate team independent from operations is responsible for tracking and reporting on market and credit risks.

The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates through contractual protections with counterparties where practicable, as well as by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. Collectively, these contracts and financial instruments are considered “derivatives.”

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to accumulated other comprehensive income (loss) and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period.

Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value, with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

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Derivatives entered into by NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory or property, plant and equipment, depending on the nature of the item being economically hedged. Management believes that any gains or losses resulting from settlement of these derivatives be refunded to or collected from customers in future rates.

Derivatives that do not meet any of the above criteria are designated as held for trading (“HFT”) and are recognized on the balance sheet at fair value. All gains or losses are recognized in net income of the period unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies.

Hedging Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:

As at	March 31 2016			December 31 2015
	millions of Canadian dollars
Derivative instrument assets (current and other assets)		$11.7			$19.8
Derivative instrument liabilities (current and long-term liabilities)		(28.5	)		(46.2	)
Net derivative instrument assets (liabilities)	$	(16.8	)		$(26.4	)

As at	December 31, 2015			December 31, 2014
	millions of Canadian dollars
Derivative instrument assets (current and other assets)		$19.8			$23.0
Derivative instrument liabilities (current and long-term liabilities)		(46.2	)		(19.2	)
Net derivative instrument assets (liabilities)		$(26.4	)		$3.8

Hedging Impact Recognized in Net Income

The Company recognized gains (losses) related to the effective portion of hedging relationships under the following categories:

	Three months ended March 31						Year ended December 31
	2016			2015			2015			2014
	millions of Canadian dollars
Operating revenues – regulated	$	(3.2	)	$	(2.1	)	$	(9.0	)	$	(3.7	)
Non-regulated fuel for generation and purchased power		4.2			5.6			4.8			0.9
Income from equity investments		(0.3	)		(0.2	)		(0.6	)		(0.5	)
Interest expense, net	$	—		$	—			—			(0.2	)
Effective net gains (losses)	$	0.7		$	3.3		$	(4.8	)	$	(3.5	)

The effective net gains (losses) reflected in the above table would be offset in net income by the hedged item realized in the period.

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The Company recognized in net income the following gains (losses) related to the ineffective portion of hedging relationships under the following categories:

	Three months ended March 31						Year ended December 31
	2016			2015			2015			2014
	millions of Canadian dollars
Non-regulated fuel for generation and purchased power	$	(1.0	)	$	(0.6	)	$	(0.1	)	$	2.7
Ineffective gains (losses)	$	(1.0	)	$	(0.6	)	$	(0.1	)	$	2.7

Regulatory Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:

	Three months ended March 31
	2016			2015
	millions of Canadian dollars
Derivative instrument assets (current and other assets)	$	131.3		$	209.9
Regulatory assets (current and other assets)		51.5			64.3
Derivative instrument liabilities (current and long-term liabilities)		(49.8	)		(64.3	)
Regulatory liabilities (current and long-term liabilities)		(131.3	)		(209.9	)
Net asset (liability)	$	1.7		$	—

	December 31, 2015			December 31, 2014
	millions of Canadian dollars
Derivative instrument assets (current and other assets)	$	209.9		$	97.7
Regulatory assets (current and other assets)		64.3			43.6
Derivative instrument liabilities (current and long-term liabilities)		(64.3	)		(40.3	)
Regulatory liabilities (current and long-term liabilities)		(209.9	)		(97.7	)
Net asset (liability)	$	—		$	$3.3

Regulatory Impact Recognized in Net Income

The Company recognized the following net gains (losses) related to derivatives receiving regulatory deferral as follows:

	Three months ended March 31					Year ended December 31
	2016		2015			2015		2014
	millions of Canadian dollars
Regulated fuel for generation and purchased power(1)	$	3.0	$	(1.1	)	$	41.2	$	17.7
Net gains (losses)	$	3.0	$	(1.1	)	$	41.2	$	17.7

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

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Held-for-trading Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to HFT derivatives:

	Three months ended March 31			Year ended December 31
	2016			2015			2014
	millions of Canadian dollars
Derivative instruments assets (current and other assets)	$	33.7		$	95.3		$	107.8
Derivative instruments liabilities (current and long-term liabilities)		(141.8	)		(331.9	)		(145.3	)
Net derivative instrument assets (liabilities)	$	(108.1	)	$	(236.6	)	$	(37.5	)

Held-for-trading Items Recognized in Net Income

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in net income:

	Three months ended March					Year ended December 31
	2016			2015		2015			2014
	millions of Canadian dollars
Non-regulated operating revenues	$	221.6		$	94.0	$	14.4		$	270.4
Non-regulated fuel for generation and purchased power		(0.7	)		0.2		(3.1	)		(5.2	)
Other income (expenses), net		—			—		(0.8	)		—
Net gains (losses)	$	220.9		$	94.2	$	10.5		$	265.2

Other Derivatives Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to other derivatives:

	Three months ended March 2016			December 31, 2015			December 31, 2014
	millions of Canadian dollars
Derivative instruments assets (current and other assets)	$	1.1		$	92.1		$	—
Derivative instruments liabilities (current and long-term liabilities)		(7.0	)		(2.9	)		—
Net derivative instrument assets (liabilities)	$	(5.9	)	$	89.2		$	—

Other Derivatives Recognized in Net Income

The Company recognized in net income the following gains (losses) related to other derivatives:

	Three months ended March 31					Year ended December 31
	2016			2015		2015			2014
	millions of Canadian dollars
Other income (expense)	$	(94.8	)	$	—	$	92.1		$	—
Interest expense, net	$	(0.3	)		—		(2.9	)		—
Total gains (losses)	$	(95.1	)	$	—	$	89.2		$	—

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Disclosure and Internal Controls

The Company, under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, has designed as at March 31, 2016 disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”). These terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings.

The Chief Executive Officer and the Chief Financial Officer have caused to be evaluated under their supervision, with the assistance of Company employees, the effectiveness of the Company’s DC&P and ICFR, and based on that evaluation, have concluded DC&P and ICFR were effective at December 31, 2015.

There have been no changes in Emera or its consolidated subsidiaries’ ICFR during the period beginning on January 1, 2015 and ending on December 31, 2015, which have materially affected or are reasonably likely to materially affect ICFR.

There have been no changes in Emera or its consolidated subsidiaries’ ICFR for the three months ended on March 31, 2016, which has materially affected, or is reasonably likely to materially affect the Company’s ICFR

Critical Accounting Estimates

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made. Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill impairment assessments, income taxes, including deferred taxes, asset retirement obligations, capitalized overhead and valuation of derivative instruments. Actual results may differ significantly from these estimates.

Rate Regulation

The rate-regulated accounting policies of NSPI, Emera Maine, BLPC, Domlec, GBPC, and EBPC may differ from accounting policies for non-rate-regulated companies. NSPI, Emera Maine, BLPC, Domlec, and GBPC’s accounting policies are subject to examination and approval by their respective regulators. These accounting policy differences occur when the regulators render their decisions on rate applications or other matters, and generally involve a difference in the timing of revenue and expense recognition. The accounting for these items is based on the expectation of the future actions of the regulators.

Emera has recorded Cdn$699.5 million (2014 – Cdn$602.7 million) of regulatory assets and Cdn$370.6 million (2014 – Cdn$201.9 million) of regulatory liabilities as at December 31, 2015.

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future experience.

The benefit cost and accrued benefit obligation for employee future benefits included in annual compensation expenses are affected by employee demographics, including age, compensation levels, employment periods, contribution levels and earnings on plan assets.

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Changes to the provision of the plan may also affect current and future pension costs. Benefit costs are also affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation and benefit costs.

The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.

Emera’s accounting policy is to amortize the net actuarial gain or loss, which exceeds 10% of the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”) and the market-related value of assets, over active plan members’ average remaining service period, which is currently nine years. Emera’s use of smoothed asset values further reduces the volatility related to the amortization of actuarial investment experience. As a result, the main cause of volatility in reported pension cost is the discount rate used to determine the PBO.

The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate bonds in each operating entity’s country. The discount rate is determined with reference to bonds which have the same duration as the PBO as at January 1 of the fiscal year. NSPI rounds its discount rate to the nearest 25 basis points. Effective January 1, 2014, Bangor Hydro Electric Company and Maine Public Service Company merged to become Emera Maine. The pension plans related to the pre-merger companies have remained separate and are disclosed separately below. For benefit cost purposes, NSPI’s rate was 4.00% for 2015 (2014 – 5.00%) and Bangor Hydro’s rate was 3.91% for 2015 (2014 – 4.83%), MPS’ rate was 3.77 for 2015 (2014 – 4.59%) and GBPC’s rate for 2015 was 4.75% (2014 – 5.00%).

The expected return on plan assets is based on management’s best estimate of future returns, considering economic and consensus forecasts. The benefit cost calculations assumed that plan assets would earn a rate of return of 5.75% for 2015 (2014 – 6.25%) for NSPI and 7.50% for 2015 and 2014 for Bangor Hydro and MPS, and 6.00% for both 2015 and 2014 for GBPC.

The reported benefit cost for defined benefit and defined contribution plans in 2015, based on management’s best estimate assumptions, is Cdn$73.0 million. While there are numerous assumptions which are used to determine the benefit cost, the discount rate and asset return assumptions have an impact on the calculations.

The following shows the impact on 2015 benefit cost of a 25 basis point change (0.25%) in the discount rate and asset return assumptions:

	0.25% Increase						0.25% Decrease
	2015			2014			2015		2014
	millions of Canadian dollars
Discount rate assumption	$	(5.4	)	$	(5.4	)	$	5.4	$	5.4
Asset return assumption	$	(2.7	)	$	(2.4	)	$	2.6	$	2.4

Unbilled Revenue

Electric revenues are billed on a systematic basis over a one- or two-month period for NSPI and a one- month period for Emera Maine and GBPC. At the end of each month, the Company must make an estimate of energy delivered to customers since the date their meter was last read and of related revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including current month’s generation, estimated customer usage by class, weather, line losses and applicable customer rates. EUS Bahamas and Emera Utility Services include an estimate of work completed under contracts but not yet billed at the end of each month. Based on the extent of the estimates included in the determination of unbilled revenue, actual results may differ from the estimate. As at December 31, 2015, unbilled revenues amount to Cdn$144.2 million (2014 – Cdn$141.1 million) on a base of annual operating revenues of approximately Cdn$2,789.3 million (2014 – Cdn$2,938.6 million).

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Property, Plant and Equipment

Property, plant and equipment represents 51.5% of total assets recognized on the Company’s balance sheet. Included in “Property, plant and equipment” are the generation, transmission and distribution and other assets of the Company. Due to the magnitude of the Company’s property, plant and equipment, changes in estimated depreciation rates can have a material impact on depreciation expense.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated property, plant and equipment are determined based on formal depreciation studies and require the appropriate regulatory approval. NSPI’s last depreciation study was completed in 2010 and approved by the UARB on May 11, 2011. BLPC’s last depreciation study was completed in 2013 and has been submitted for regulatory review. A response time has not been issued. GBPC’s last depreciation study was completed in 2015 and was approved on January 25, 2016. Emera Maine’s last depreciation study was completed in 2013 and was applied to transmission rates effective January 1, 2014 and distribution rates effective July 1, 2014.

Depreciation expense was Cdn$295.9 million for the year ended December 31, 2015 (2014 – Cdn$277.5 million).

Goodwill Impairment Assessments

Goodwill represents the excess of the acquisition purchase price for Emera Maine and GBPC over the fair values assigned to individual assets acquired and liabilities assumed. Emera is required to perform an impairment assessment annually, or in the interim if an event occurs that indicates the fair value of Emera Maine or GBPC may be below its carrying value. Emera performs its annual impairment test as at October 1.

Goodwill arose on the acquisitions of GBPC and Emera Maine. At December 31, 2015, this goodwill had a total carrying amount of Cdn$264.1 million (December 31, 2014 – Cdn$221.5 million)

Emera’s reporting units will first assess qualitative factors to determine whether it is more likely than not that the assets’ fair value is less than the carrying amount, in which case it is necessary to perform the quantitative goodwill impairment test. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value.

Determining the fair market value of goodwill is susceptible to changes from period to period as assumptions about future cash flows are required.

Emera reviewed the carrying amount of goodwill and no material goodwill impairments existed for the year ended December 31, 2015 or 2014.

Income Taxes

Income taxes are determined based on the expected tax treatment of transactions recorded in the consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of jurisdictions, the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of the Company’s tax returns.

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Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit-adjusted risk free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long- lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization.” Any accretion expense not yet approved by the regulator is deferred to a regulatory asset in “Property, plant and equipment” and included in the next depreciation study. Accordingly, changes to the ARO or cost recognition attributable to changes in the factors discussed above, should not impact the results of operations of the Company.

Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.

The key assumptions used to determine the ARO are as follows:

Asset	Credit-adjusted risk-free rate						Estimated undiscounted future obligation (millions of Canadian dollars)				Expected settlement date (number of years)
	2015			2014			2015		2014		2015		2014
Thermal		5.1 – 5.3	%		5.2 – 5.3	%	$	142.8	$	142.8		17 – 28		18 – 29
Hydro		5.1 – 5.3	%		5.1 – 5.3	%		127.6		127.6		16 – 46		17 – 47
Wind		5.1 – 5.2	%		5.1 – 5.2	%		27.4		27.4		13 – 20		14 – 21
Combustion turbines		5.1 – 5.3	%		5.1 – 5.3	%		8.3		8.3		1 – 30		2 – 31
Transmission & distribution		4.3 – 5.8	%		4.1 – 5.8	%		21.5		16.5		1 – 10		1 – 11
Pipeline		3.80	%		3.80	%		18.1		18.1		19.5		19.5
							$	345.7	$	340.7

As at December 31, 2015, the AROs recorded on the balance sheet were Cdn$114.7 million (2014 – Cdn$106.2 million). The Company estimates the undiscounted amount of cash flow required to settle the obligations is approximately Cdn$320.2 million, which will be incurred between 2016 and 2061. The majority of these costs will be incurred between 2032 and 2047.

Capitalized Overhead

As required by their respective regulators, NSPI, Emera Maine, GBPC, BLPC and Domlec capitalize overhead costs that are not directly attributable to specific utility assets, but to the overall capital expenditure program. The methodology for the calculation of capitalized overhead is approved by their respective regulator. For the year ended December 31, 2015, Cdn$71.6 million (2014 – Cdn$68.4 million) of overhead costs were capitalized to capital assets. Any change in the methodology for the calculation and allocation of overhead costs could have a material impact on the amounts recognized as expenses versus assets.

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Financial Instruments

Emera is required to determine the fair value of all derivatives except those which qualify for the normal purchase, normal sale exception. Fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information, including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model.

Level Determinations and Classifications

Emera uses the Level 1, 2 and 3 classifications in the fair value hierarchy. The fair value measurement of a financial instrument is included in only one of the three levels and is based on the lowest level input significant to the derivation of the fair value. Fair values are determined, directly or indirectly, using inputs that are unobservable for the asset or liability. In limited circumstances, Emera may enter into commodity transactions involving non-standard features where market observable data is not available, or contracts with terms that extend beyond five years.

Changes in Accounting Policies and Practices

The new U.S. GAAP accounting policies that are applicable to, and were adopted by Emera, effective during 2016, are described as follows:

Income Statement—Extraordinary and Unusual Items, Accounting Standard Update (“ASU”) 2015-01

In January 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-01, Income Statement—Extraordinary and Unusual Items, which simplifies the income statement presentation requirements by eliminating the concept of extraordinary items. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Consolidation, ASU 2015-02

In February 2015, the FASB issued ASU 2015-02, Consolidation, which changes the analysis a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the variable interest entity (“VIE”) characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. All legal entities are subject to re-evaluation under the revised consolidation model. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Interest—Imputation of Interest, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. The Company has adopted this standard effective Q1 2016 and December 31, 2015 balances have been retrospectively restated. This change resulted in Cdn$62.3 million of deferred financing costs, as at December 31, 2015, previously presented as other assets, being reclassified as a deduction from the carrying amount of the related long-term debt and convertible debentures represented by instalment receipts on the Consolidated Balance Sheets.

ASU No. 2015-15 is effective for annual reporting periods, including interim reporting within those periods, beginning December 15, 2015. As at December 31, 2015, debt issuance costs associated with line-of-credit

189

arrangements included in “Other long-term assets” were Cdn$4.0 million (December 31, 2014 – Cdn$4.1 million) on Emera’s Consolidated Balance Sheets. In accordance with ASU 2015-15 Interest: Imputation of Interest, the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments in other long-term assets on its Consolidated Balance Sheets.

Compensation—Retirement Benefits, ASU 2015-04

In April 2015, the FASB issued ASU 2015-04, Compensation—Retirement Benefits, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard provides certain practical expedients for defined benefit pension or other post-retirement benefit plan measurement dates. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Intangibles—Goodwill and Other—Internal-Use Software, ASU 2015-05

In April 2015, the FASB issued ASU 2015-05, Intangibles—Goodwill and Other—Internal-Use Software, which provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer would account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer would account for the arrangement as a service contract. The guidance does not change GAAP for a customer’s accounting for service contracts. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Technical Corrections and Improvements, ASU 2015-10

In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Improvements, covering a wide range of topics in the codification to correct unintended application of guidance, or make minor improvements to the Codification. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships, ASU 2016-05

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The standard clarifies that a change in the counterparty to a derivative contract, in and of itself, does not require the de-designation of a hedging relationship provided that all other hedge accounting criteria continue to be met. ASU 2016-05 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and early adoption is permitted. Emera has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Investments—Equity Method and Joint Ventures, ASU 2016-07

In March 2016, the FASB issued ASU 2016-07, Investments—Equity Method and Joint Ventures, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard eliminates the requirements of an investor to retroactively account for an investment under the equity method when an investment qualifies for equity method accounting. ASU 2016-07 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016, with early adoption permitted. Emera has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Inventory—Simplifying the Measurement of Inventory, ASU 2015-11

In July 2015, the FASB issued ASU 2015-11, Inventory—Simplifying the Measurement of Inventory. The amendments require an entity to measure inventory at the lower of cost or net realizable value, whereas previously, inventory was measured at the lower of cost or market. ASU 2015-11 is effective for annual reporting

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periods, including interim reporting within those periods, beginning after December 15, 2016. Early adoption is permitted for any interim or annual financial statements that have not yet been issued. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

The new U.S. GAAP accounting policies that are applicable to, and were adopted by Emera, effective during 2015, are described as follows:

Fair Value Measurement Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), ASU 2015-07

In May 2015, the FASB issued ASU 2015-07 removing the requirement to categorize and disclose, within the fair value hierarchy, all investments for which fair value is measured using the net asset value per share as a practical expedient. Emera has early adopted ASU No. 2015-07 effective December 31, 2015 and 2014. The adoption of this update resulted in disclosure of all investments for which fair value is measured using the net asset value per share methodology being disclosed outside of the fair- value hierarchy. As at December 31, 2015, total investments measured using the net asset value per share were $672.4 million (December 31, 2014 – $635.7 million).

Business Combinations—Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16

In September 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-16, Business Combinations—Simplifying the Accounting for Measurement-Period Adjustments. The amendment applies to entities that have reported provisional amounts related to a business combination for which the accounting is incomplete by the end of the reporting period and have an adjustment to provisional amounts previously recognized during a later measurement period. Changes in provisional amounts recorded for acquired assets and liabilities are to be adjusted in the period the adjustment is known, with a corresponding adjustment booked to goodwill. The acquirer is no longer required to revise comparative information from prior years for the effect of changes in provisional amounts. The Company has adopted ASU 2015-16 effective Q3 2015, with no impact on the consolidated financial statements as a result of implementation of this standard.

Income Taxes—Balance Sheet Classification of Deferred Taxes, ASU 2015-17

In November 2015, the FASB issued ASU 2015-17, Income Taxes—Balance Sheet Classification of Deferred Taxes, which simplifies the presentation of deferred income taxes. The amendment requires that deferred tax assets and liabilities be classified as noncurrent on the Consolidated Balance Sheets, regardless of whether the deferred income taxes are expected to be recovered or settled within the next twelve months. ASU-2015-17 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016. Early adoption is permitted for any interim or annual financial statements that have not yet been issued.

The Company has early adopted ASU 2015-17 effective December 31, 2015, and 2014 balances have been retrospectively restated. This change decreased the current deferred income tax asset and liability by Cdn$49.2 million and Cdn$4.1 million respectively on the Consolidated Balance Sheets as at December 31, 2015 (2014 – Cdn$27.9 million and Cdn$15.7 million respectively). As a result of the change the long-term deferred income tax asset increased by Cdn$15.2 million (2014 – Cdn$24.1 million) and the long-term deferred income tax liability decreased by Cdn$29.9 million (2014 – increased by Cdn$11.9 million) on the Consolidated Balance Sheets as at December 31, 2015.

This change also reclassified a Cdn$11.9 million current deferred income tax regulatory liability (2014 – Cdn$8.0 million) to the long-term deferred income tax regulatory asset on the Consolidated Balance Sheets as at December 31, 2015.

191

Future Accounting Pronouncements

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework and a new topic in the Accounting Standards Codification, Topic 606. Accounting Standards Codification 606 also changes the basis for determining when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific aspects of revenue recognition and expands revenue disclosures. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers: Principal versus Agent Considerations. The amendments are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU 2016-10 Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing. The guidance will be effective beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The Company is continuing to evaluate the impact of adoption of these standards on its consolidated financial statements.

Financial Instruments—Recognition and Measurement of Financial Assets and Financial Liabilities, ASU No. 2016-01

In January 2016, the FASB issued ASU 2016-01, Financial Instruments—Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. ASU No. 2016-01 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. Emera is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

Leases (Topic 842), ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases. The standard increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for lease terms of more than 12 months. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. ASU 2016-02 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and will be applied using a modified retrospective approach.

Emera is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

Summary of Quarterly Results

	For the quarter ended
	Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
	2016		2015		2015		2015		2015		2014		2014		2014		2014
	millions of Canadian dollars (except per share amounts)
Operating revenues	$	877.0	$	731.6	$	642.3	$	526.9	$	888.5	$	782.7	$	539.0	$	566.6	$	1,050.3
Net income attributable to common shareholders		44.3		192.1		35.0		10.0		160.1		151.2		28.2		24.5		202.8
Adjusted net income attributable to common shareholders(1)		120.2		87.1		23.3		48.0		171.6		78.5		49.9		44.2		146.6
Earnings per common share – basic		0.30		1.31		0.24		0.07		1.10		1.05		0.20		0.17		1.43
Earnings per common share – diluted		0.30		1.30		0.24		0.07		1.09		1.02		0.20		0.17		1.40
Adjusted earnings per common share – basic(1)		0.81		0.59		0.16		0.33		1.18		0.54		0.35		0.31		1.03

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(1) A non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”.

Quarterly operating revenues and net income attributable to common shareholders are affected by seasonality. The first quarter is generally the strongest because a significant portion of the Company’s operations are in northeastern North America, where winter is the peak electricity season. As the energy industry is seasonal in nature for companies like Emera, seasonal and other weather patterns, as well as the number and severity of storms, can affect the demand for energy and the cost of service. Quarterly results could be affected by items outlined in the Significant Items section and mark-to-market adjustment

Operating Statistics

Five-Year Summary

	Year ended December 31
	2015		2014		2013		2012		2011
Electric energy sales (GWh)
Residential		5,740.5		5,615.7		5,623.6		5,372.2		5,458.9
Commercial		11,153.9		10,989.6		7,156.9		6,174.7		6,562.3
Industrial		2,984.1		2,970.8		3,067.4		2,678.7		3,988.5
Other		373.6		385.3		357.9		371.2		347.0
Total electric energy sales		20,252.1		19,961.4		16,205.8		14,596.8		16,356.7
Sources of energy (GWh)
Thermal – coal		6,364.0		6609.0		7,098.0		6,223.0		6,848.0
– oil		1,668.4		1,584.5		1,417.5		1,355.1		1,070.8
– natural gas		7,782.3		7,691.7		3,685.9		3,726.0		4,304.7
Biomass		272.3		319.8		167.0		—		—
Hydro		1,040.4		1,129.6		1,002.6		828.0		1,414.5
Wind		259.0		258.0		261.0		256.0		247.0
Purchases		4,142.3		3,693.1		3,528.0		3,210.2		3,518.3
Total generation and purchases		21,528.7		21,285.7		17,160.0		15,598.3		17,403.3
Losses and internal use		1,276.6		1,324.3		954.2		1,001.5		1,046.6
Total electric energy sold		20,252.1		19,961.4		16,205.8		14,596.8		16,356.7
Electric customers
Residential		747,629		742,110		738,444		702,738		696,970
Commercial		85,480		82,076		83,612		79,613		79,817
Industrial		2,628		2,637		2,711		2,521		2,517
Other		9,432		10,421		10,510		20,230		10,446
Total electric customers		845,169		837,244		835,277		805,102		789,750
Capacity
Emera-owned generating nameplate capacity(MW)
Coal fired		1,243.0		1,243.0		1,243.0		1,243.0		1,243.0
Dual fired		350.0		350.0		350.0		350.0		350.0
Gas turbines		1,819.0		1,799.0		1,796.5		746.5		666.0
Biomass		90.0		90.0		90.0		—		—
Hydroelectric		402.0		401.6		401.6		395.0		395.0
Wind turbines		82.0		82.0		82.0		82.0		82.0

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	Year ended December 31
	2015		2014		2013		2012		2011
Diesel		241.2		241.2		244.6		231.5		173.0
Steam		40.0		40.0		40.0		40.0		47.0
Independent power producers		593.0		370.0		308.0		300.0		264.0
		4,860.2		4,616.8		4,555.7		3,388.0		3,220.0
Total number of employees		3,454		3,530		3,558		3,374		3,458
km of transmission lines		7,504		7,215		7,224		6,803		6,800
km of distribution lines		46,162		44,811		44,771		39,590		41,600

Regulated Electric	Customers		Employee count		Peak demand (MW)		Energy sales (GWh)		Total assets (billions)		Rate base (billions)		Income (millions)		Allowable ROE 2015			Allowable ROE 2014
NSPI		506,452		1,727		1,825		10,412		4.6		3.8		129.9		8.75-9.25	%		8.75-9.25	%
Emera Maine		157,891		412		388		2,020		1.6		0.9		45.1		10.3	%		10.6	%
BLPC(1)		126,190		330		149		915		0.5		0.4		29.7		10.0	%		10.0	%
GBPC(1)		19,104		205		61		335		0.4		0.3		17.8		10.0	%		10.0	%
Domlec(1)		35,525		238		17		95		0.1		0.1		7.4		15.0	%		15.0	%

(1) These subsidiaries use return on rate base, as opposed to ROE.

Five-Year Financial Summary

	Year ended December 31
	2015		2014		2013			2012			2011
	millions of Canadian dollars
Consolidated Statements of Income
Operating Revenues	$	2,789.3	$	2,938.6	$	2,230.2		$	2,058.6		$	2,064.4
Operating expenses
Regulated fuel for generation and purchased power		814.5		844.3		868.4			810.5			866.4
Regulated fuel and fixed cost adjustments		41.6		46.6		(40.8	)		10.0			(8.5	)
Non-regulated fuel for generation and purchased power		335.7		401.1		89.8			44.5			73.9
Non-regulated direct costs		19.5		31.3		52.4			56.6			60.9
Operating, maintenance and general		666.8		560.8		505.0			462.9			453.3
Provincial, state and municipal taxes		63.6		58.2		50.5			49.4			49.2
Depreciation and amortization		339.9		329.0		297.8			278.2			251.7
Income from operations		507.7		667.3		407.1			346.5			317.5
Income from equity investments and Other income (expenses), net		249.7		78.9		63.7			53.8			77.4
Interest expense, net		212.6		179.8		172.2			167.1			159.4
Income before provision for income taxes		544.8		566.4		298.6			233.2			235.5
Income tax expense (recovery)		92.4		113.6		43.3			(12.4	)		(23.9	)
Net income		452.4		452.8		255.3			245.6			259.4
Non-controlling interest in subsidiaries		24.9		19.9		18.5			13.7			11.7
Net income of Emera Incorporated		427.5		432.9		236.8			231.9			247.7
Preferred stock dividends		30.3		26.2		19.3			11.1			6.6
Net income attributable to common shareholders		397.2		406.7		217.5			220.8			241.1
After-tax mark-to-market gain (loss)		67.2		87.5		(41.9	)		(9.7	)		(3.0	)
Adjusted net income attributable to common shareholders(1)		330.0		319.2		259.4			230.5			244.1
Adjusted EBITDA(1)		1,031.2		946.5		829.5			693.2			649.8
Balance Sheets Information
Current assets(1)		2,595.6		1,410.8		1,152.3			940.2			993.3

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	Year ended December 31
	2015			2014			2013			2012			2011
	millions of Canadian dollars
Property, plant and equipment, net of accumulated depreciation		6,188.0			5,610.2			5,327.7			4,491.1			4,294.4
Other assets
Income taxes receivable		48.7			28.9			27.8			—			—
Deferred income taxes(2)		32.2			57.8			67.8			28.9			33.1
Derivative instruments		167.6			92.0			61.6			23.4			39.6
Pension and post-retirement asset		8.7			5.9			0.5			0.1			0.3
Regulatory assets		605.3			487.7			557.8			376.4			312.2
Net investment in direct financing lease		480.1			484.5			487.2			490.0			492.0
Investments subject to significant influence(3)		1,145.3			1,027.6			739.2			536.6			219.8
Available-for-sale investments		116.0			84.4			74.2			141.8			54.6
Goodwill		264.1			221.5			206.5			193.5			197.7
Intangibles, net of accumulated amortization		191.9			134.3			118.4			114.2			100.7
Due from related parties		2.5			2.5			2.5			151.7			2.8
Other long-term assets		166.3			205.3			53.3			48.5			183.1
Total assets		12,012.3			9,853.4			8,876.8			7,536.4			6,923.6
Current liabilities		2,081.3			1,122.9			1,529.9			951.9			801.7
Long-term liabilities
Long-term debt		3,750.8			3,660.3			3,363.7			3,257.4			3,273.5
Deferred income taxes(2)		761.7			613.3			547.7			312.1			228.6
Derivative instruments		96.1			77.4			27.0			22.4			38.7
Regulatory liabilities		271.7			158.9			119.5			92.5			107.1
Asset retirement obligations		114.7			106.2			98.6			95.0			99.9
Pension and post-retirement liabilities		303.4			360.7			256.4			506.4			530.8
Other long-term liabilities(3)		298.5			48.3			36.8			20.9			19.6
Equity
Common stock		2,157.5			2,016.4			1,703.0			1,643.7			1,385.0
Cumulative preferred stock		709.5			709.5			514.0			391.6			146.7
Contributed surplus		28.8			8.8			4.1			2.8			3.3
Accumulated other comprehensive income (loss)		136.5			(347.6	)		(430.1	)		(775.8	)		(671.7	)
Retained earnings		1,167.8			1,011.7			817.2			788.1			735.9
Total Emera Incorporated equity		4,200.1			3,398.8			2,608.2			2,050.4			1,599.2
Non-controlling interest in subsidiaries		134.0			306.6			289.0			227.4			224.5
Total equity		4,334.1			3,705.4			2,897.2			2,277.8			1,823.7
Total liabilities and equity		12,012.3			9,853.4			8,876.8			7,536.4			6,923.6
Statements of Cash Flow Information
Cash provided by operating activities		674.2			762.5			564.2			397.6			399.5
Cash used in investing activities		(123.7	)		(710.9	)		(921.6	)		(919.4	)		(660.8	)
Cash provided by (used in) financing activities		221.1			58.2			362.1			534.2			331.4
Financial ratios ($ per share)
Earnings per share	$	2.72		$	2.84		$	1.64		$	1.77		$	1.99
Adjusted earnings per share(1)	$	2.26		$	2.23		$	1.96		$	1.85		$	2.02

(1) A non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”.

(2) Emera early adopted ASU 2015-17 Income Taxes – Balance Sheet Classification of Deferred Taxes. The December 31, 2014 and 2015 periods have been restated.

(3) As at December 31, 2015 and 2014, the negative investment balance for Bear Swamp has been reclassified to “Other long-term liabilities” on the Consolidated Balance Sheets. The 2014 and 2015 carrying values have been restated.

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BUSINESS

General Development of the Business

Emera

Emera seeks to deliver long-term growth to investors. Accordingly, annual dividend growth, earnings per common share growth and total shareholder return are the primary measures of performance. Emera is targeting 8% annual dividend growth through 2019. The following table details Emera’s one, three and five-year performance for these metrics, as well as the S&P/TSX Capped Utilities Index annualized total shareholder return for those periods:

	For the Year ended December 31, 2015
	1 year (%)			3 year (%)		5 year (%)
Dividend per share compound annual growth rate(1)		12.7			6.9		7.4
Adjusted earnings per share compound annual growth rate(2)		1.3			6.9		5.9
Emera annualized total shareholder return(2)		16.4			12.1		11.1
S&P/TSX Capped Utilities Index annualized total shareholder return(3)		(3.5	)		2.3		3.5

(1) The dividend per share compound annual growth rate is based on the dividends paid in the year.

(2) The adjusted earnings per share compound annual growth rates do not include Acquisition-related costs and is a non-U.S. GAAP measure described in “Management’s Discussion and Analysis—Non-U.S. GAAP Financial Measures”.

(3) Total shareholder return combines share price appreciation and dividends per common share paid during the fiscal year to show the total return to the shareholder expressed as an annualized percentage assuming dividends are reinvested each time they are paid.

(4) The S&P/TSX Capped Sector Indices provide liquid and tradable benchmarks for related derivative products of Canadian economic sectors. Constituents are selected from a stock pool of S&P/TSX Composite Index Stocks, and the relative weight of any single index constituent is capped at 25%. The indices are based upon the Global Industry Classification Standards (GICS^®). The S&P/TSX Capped Utilities Index imposes capped weights on the index constituents included in the S&P/TSX Composite that are classified in the GICS^® utilities sector.

Energy markets worldwide, in particular across North America, are undergoing foundational changes that have created significant investment opportunities for companies with Emera’s experience and capabilities. Key trends contributing to these investment opportunities include: aging infrastructure, environmental concerns (including demand for new, less carbon-intensive and renewable generation), lower-cost natural gas, growing demand for new electric heating solutions, and the requirement for large-scale transmission projects to deliver new energy sources to customers. Within this context, Emera is focused on growing shareholder value by identifying reliable and affordable energy solutions, typically involving the replacement of higher-carbon electricity generation with generation from cleaner sources, and the related transmission and distribution infrastructure to deliver that energy to market.

Emera has strong partnerships and relationships throughout the regions in which it operates and has established a diverse investment and operations profile that links its assets and capabilities in those regions. Core to Emera’s strategy is the ability to leverage these particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company.

Emera’s strategy is based on its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. The Company expects to continue to make investments in its regulated utilities to benefit customers and focus on providing rate stability to its customers. From time to time, Emera anticipates making acquisitions, both regulated and unregulated, where the business or asset acquired aligns with Emera’s strategic initiatives and delivers shareholder value.

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To ensure stability in Adjusted net income and cash flows, Emera employs operating and governance models that focus on operational excellence, constructive regulatory approaches, proactive stakeholder engagement and a customer focus through service reliability and rate stability.

Emera targets achieving 75% to 85% of its Adjusted net income from rate-regulated subsidiaries, which generally contribute strong, predictable income and cash flows that fund dividends, reinvestment and which is reflective of the Company’s risk tolerance. Emera has an annual dividend growth target of 8% through 2019.

In 2015, approximately 65% of Emera’s Adjusted net income was earned by its rate-regulated subsidiaries, which is lower than 2014 (i.e., 67%) and is lower than its strategic target mentioned above. Specifically, the lower percentage of Adjusted net income from non-rate regulated subsidiaries is a result of a substantial increase in Emera Energy’s earnings primarily due to strong performance by the New England Gas Generation Facilities, and a strengthening U.S. dollar. It is not the result of a change in Emera’s risk tolerance, nor is it from additional capital allocations to non-regulated businesses. Rather, it is the result of strong operating and financial performance of existing non-regulated investments and businesses. Following the closing of the Acquisition, the Company is expected to achieve its Adjusted net income target of 75% to 85%.

Emera has grown its asset base to enable growth and deliver on its strategic objectives. Over the last 10 years, Emera’s ability to raise the capital necessary to fund investments has been a strong enabler of the Company’s growth. This was demonstrated in the Convertible Debenture Offering completed in connection with the Acquisition. In addition to access to debt and equity capital markets, cash flow from operations will continue to play a role in financing the Company’s future growth. Maintaining strong, investment grade credit ratings is an important component of Emera’s financing strategy.

Business Strategy

Emera’s business strategy consists of the following key components:

Focus on identifying reliable and affordable energy solutions, typically including the replacement of higher carbon electricity generation with generation from cleaner sources, and the related transmission and distribution infrastructure to deliver energy to that market

• Emera is investing Cdn$2.2 billion to build the Maritime Link and associated projects, which will bring clean hydro energy from Labrador to Nova Scotia, and create opportunities for surplus renewable energy to supply other markets.

• NSPI has invested in wind energy, biomass and hydroelectricity, which has driven substantial increases in the portion of its generation mix derived from renewable sources (reaching 27% in 2015 and on track to meet its 40% target by 2020).

• Numerous other investments and initiatives are underway, from a new utility grade solar facility in Barbados to the MREI transmission proposal, designed to deliver new wind energy in northern Maine to markets in southern New England.

Develop strong partnerships and relationships throughout the regions in which we operate and utilize a collaborative approach to strategic partnerships

• The foundation of Emera’s strategy is its collaborative approach to strategic partnerships and its ability to develop strong relationships throughout the regions in which it operates. Prime examples of Emera’s success in this areas include:

• The Maritime Link project, where Emera and its partner Nalcor, along with the Government of Canada and the Provinces of Nova Scotia and Newfoundland and Labrador, have entered into numerous agreements and partnerships to deliver and finance the Maritime Link, the Labrador Island Link and the related Muskrat Falls project.

197

• Emera’s SIA with APUC establishes how Emera and APUC will work together to pursue specific strategic investments of mutual benefit. While Emera recently announced that it has reduced its direct investment in APUC, the SIA remains in place as both companies value the partnership.

• Emera has a number of other partnerships and collaborative agreements across its operating regions, including a joint dispatch project between NSPI and NB Power, a partnership between Emera Maine and Central Maine Power Company to develop the MREI, and the Massachusetts Clean Electricity Partnership, an alliance including Brookfield Renewable Partners, Hydro-Québec, Nalcor, NB Power, SunEdison and TDI New England to promote clean energy investments in New England.

Establish a diverse investment and operations profile

• Emera is a geographically diverse company, operating in Canada, the United States, and the Caribbean.

• Its operations include:

• vertically integrated electric utilities in Nova Scotia, Barbados, Dominica and Grand Bahama;

• a transmission and distribution electric utility in Maine;

• a portfolio of generation facilities, including combined-cycle natural gas and pumped storage hydro in Atlantic Canada and the U.S. northeast;

• investments in two natural gas pipelines in Atlantic Canada and New England;

• natural gas marketing and trading;

• a utility services contractor in Atlantic Canada;

• a Cdn$2.2 billion project to bring clean hydro energy from Labrador to Nova Scotia; and

• minority interests in numerous energy projects and companies.

Employ operating and governance models that focus on operational excellence, constructive regulatory approaches, proactive stakeholder engagement and a customer focus through service reliability and rate stability

• Emera’s focus on maintaining the highest standards of governance practices is evident in a number of ways including, for example:

• The Maritime Link project’s on time and on budget record, notwithstanding the ambitious and ground-breaking nature of the project, the changing economic climate during the course of the project, and the challenge other similar projects have had with budget and schedule;

• Emera’s consistently high ranking (2nd overall in 2015) in a survey of governance practices among Canada’s publicly traded companies, conducted each year by the Globe & Mail’s Report on Business; and

• The establishment of operating boards for the Company’s subsidiaries, and the inclusion of local business and community leaders on these boards as well as Emera executives. This practice has helped Emera develop constructive regulatory approaches, proactive stakeholder engagement and maintain a customer focus in its businesses in each of the markets it operates in.

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Competitive Strengths

We believe we have the following key competitive strengths to enable us to carry out our business strategy.

Diverse, increasingly regulated profile

• The portion of Emera’s adjusted net income generated from rate regulated business has grown from 67% in 2014 to 72% in the 12 months ended March 31, 2016. On a pro forma basis, the Acquisition will bring Emera’s regulated earnings to greater than 80%.

• Emera targets achieving 75% to 85% of its adjusted net income from rate-regulated subsidiaries, which contribute strong, predictable income and cash flows, and which is reflective of the Company’s risk tolerance.

Supportive and stable regulatory environments

• Through its long history of operating regulated businesses, Emera has gained an appreciation for the importance of constructive, professional regulatory oversight. The Company’s experience in jurisdictions such as Nova Scotia and Maine, where it has built robust regulatory teams and practices, was a significant factor in making stable regulatory environments a key criteria in its assessment of growth opportunities, including the Acquisition.

Strong balance sheet, cash flow and liquidity position

• Over the last 10 years, Emera’s strong balance sheet, and its ability to raise the capital necessary to fund investments has been a strong enabler of its growth. This was demonstrated in Emera’s issue of the Convertible Debentures represented by instalment receipts in connection with the Acquisition.

• In addition to access to debt and equity capital markets, cash flow from operations has grown substantially, from Cdn$419 million for the year ended December 31, 2010 to approximately Cdn$674 million for the year ended December 31, 2015.

• Emera and its subsidiaries maintain strong credit metrics, and Emera has consistently maintained a strong, investment grade credit rating, which is an important component of Emera’s financing strategy.

Sizeable capital investment plan to drive growth

• Emera has a Cdn$4.2 billion capital investment plan over the next five years, a significant portion of which is related to the Maritime Link and Labrador Island Link projects.

• This capital plan increases to Cdn$8.3 billion, on a pro forma basis, when TECO Energy’s US$4.1 billion in planned capital investments are included.

Disciplined investment criteria

• Emera’s focused growth strategy and disciplined investment criteria has served it well. Throughout the period of declining interest rates, its investment hurdle rate has remained unchanged, ensuring that any investment met long term criteria.

• Similarly, Emera’s strategic target of earning 75-85% of its adjusted net income from rate-regulated subsidiaries meant that the search for growth opportunities in 2014 and 2015 was focused on rate-regulated businesses.

For further information related to Emera’s consolidated revenues for the years ended December 31, 2015, December 31, 2014 and December 31, 2013, see “Management’s Discussion and Analysis.”

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The following discussion summarizes key developments in Emera’s business and operations over the last three completed financial years.

Pending Acquisition of TECO Energy

On September 4, 2015, the Company announced a definitive agreement for Emera to acquire TECO Energy. TECO Energy shareholders will receive $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.6 billion USD and which includes the assumption of approximately $4.1 billion USD of debt.

TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include: Tampa Electric, an integrated regulated electric utility which serves nearly 725,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution utility which serves nearly 365,000 customers across Florida; and NMGC, a regulated gas distribution utility which serves more than 520,000 customers across New Mexico.

Giving effect to the Acquisition as if it closed on March 31, 2016, Emera’s total assets would have increased from approximately Cdn$11 billion (US$9 billion) to approximately Cdn$28 billion (US$21 billion) and the percentage of its EBITDA that is regulated EBITDA would have increased from approximately 70% to over 90% (excluding Emera Corporate and Other (except for ENL) and TECO Energy discontinued operations, TECO Energy Corporate and Other). See “Unaudited Pro Forma Consolidated Financial Statements.” The Acquisition is expected to increase Emera’s consolidated rate base by approximately US$6.5 billion and its total customers by approximately 1.6 million. Following the Acquisition, the regulated utility subsidiaries of Emera will serve approximately 2.5 million customers. Emera has fully committed non-revolving term credit facilities in place from a syndicate of banks in an aggregate amount of $6.5 billion USD to ensure the sufficiency of funding to complete the Acquisition. The Acquisition Credit Facilities are comprised of (i) a $4.3 billion USD debt bridge facility, repayable in full on the first anniversary following its advance, and (ii) a $2.2 billion USD equity bridge facility repayable in full on the first anniversary following its advance. Permanent financing of the Acquisition is expected to be obtained before or after closing, from one or more capital market offerings, including debt and preferred equity, as well as from internally generated sources. A portion of the permanent financing has already been arranged through the sale of $2.185 billion of Convertible Debentures. The Acquisition Credit Facilities are available to address any temporary shortfalls while completing the balance of the permanent financing.

The cash purchase price of the Acquisition and the Acquisition-Related Expenses will be financed at the closing of the Acquisition with a combination of some or all of the following: (i) the proceeds from the Acquisition Capital Markets Transactions including any series of Notes offered hereunder, (ii) the receipt of payment in full on the Final Instalment Date of the Final Instalment due under the Convertible Debentures, (iii) amounts drawn under the Acquisition Credit Facilities, if any, and (iv) existing cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) and other sources available to the Company.

The closing of the Acquisition is expected to occur in mid-2016. It is subject to certain regulatory and government approvals, including approval by the NMPRC and the satisfaction of closing conditions. Below is a summary of the approvals received to date:

• TECO Energy shareholder approval on December 3, 2015;

• FERC approval on January 20, 2016; and

• Committee on Foreign Investment in the United States approval on March 23, 2016.

Additionally, the waiting period expired on February 5, 2016 under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

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On May 2, 2016 the hearing examiner held a hearing in connection with the joint application to the NMPRC of the change in control of NMGC affected by the Acquisition. A final order of the NMPRC is expected in mid-2016.

Emera expects to incur a number of costs associated with completing the Acquisition. The majority of these costs will be non-recurring expenses resulting from the Acquisition, including costs relating to the financing of the Acquisition and obtaining regulatory approvals. Additional unanticipated costs may be incurred relating to the Acquisition.

The following chart provides a summary of Emera’s organizational structure as of December 31, 2015 on a pro forma basis after giving effect to the Acquisition. The chart depicts (i) Emera’s reportable segments (including consolidated and non-consolidated investments) and (ii) selected subsidiaries of Emera

Acquisition Highlights

The Acquisition will propel Emera into a top 20 North American regulated utility as ranked by asset size, with geographic diversity and significant growth potential. TECO Energy represents an accretive opportunity for Emera to further diversify its regulated assets, net income and cash flows in growth markets and constructive regulatory environments, while furthering its strategic objective to supply customers with generation from cleaner sources. Features of the Acquisition and TECO Energy business include:

• Accretive to Earnings, Growth and Scale. Management expects the Acquisition to be accretive to Emera’s earnings per Common Share and to provide support for Emera’s dividend growth target through and beyond 2019 and to improve Emera’s long-term growth due to the favourable growth profile of the Florida and New Mexico economies and constructive regulatory environments. As a result of the Acquisition, Emera will become one of the top 20 largest regulated utility companies in North America as ranked by asset size, helping to ensure access to equity and debt capital markets and economies of scale.

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• Acquisition of a Pure-Play Regulated Utility—Increase in Regulated Net Income. Following the closing of the acquisition of TECO Energy, a utility holding company with virtually all of its net income derived from regulated businesses, the percentage of Emera’s net income that is derived from regulated business is expected to increase from approximately 70% to over 80% (excluding Emera Corporate and Other (except for ENL) and TECO Energy discontinued operations, TECO Energy Corporate and Other).

• Increase in Diversification. The Acquisition will help Emera diversify net income across several regulatory jurisdictions, geographies and business lines. Emera anticipates that this increased diversification in net income derived from regulated businesses will enhance the stability of net income (partially due to complementary seasonality) and overall quality of cash flows, and should also assist in strengthening its credit profile.

• Constructive Regulatory Jurisdictions. The majority of TECO Energy’s earnings are derived from Florida, which is a constructive regulatory environment. The FPSC regulates the operations of Tampa Electric and PGS in Florida. In addition, Tampa Electric has a fuel recovery clause and PGS has recovery clauses in place for purchased gas and cast iron and bare steel pipe replacement, as well as higher increased fixed monthly customer charges that reduce volume sensitivity. NMGC, TECO Energy’s gas operations located in New Mexico, is regulated by the NMPRC, which allows for the basic costs, excluding purchased gas, storage and interstate capacity, to be provided for through rates.

• Rate Base Growth Through Capital Investment. TECO Energy’s continued investment in its gas and electric businesses to support customer growth, system reliability and facilities is expected to drive rate base growth over the next several years. Over the long term, Emera believes there is an opportunity to participate in the shift in generation from high carbon sources to low carbon sources as Tampa Electric moves from coal-fired generation to a diversified portfolio of generation that includes gas-fired generating capacity and renewable energy sources.

• Favourable Florida Economic Indicators. Florida is the third most populous state in the United States and ranks as the fourth largest economy in the United States. According to the Florida Office of Economic & Demographic Research, job growth and improvements in the housing market are expected to contribute to the growth of Florida’s economy and GDP growth is forecast to continue through 2016, with an expected increase of 3.4%.

• Favourable New Mexico Economic Indicators. New Mexico is the 36^th most populous state in the United States. Sustained job growth of approximately 10,000 jobs per year is forecast through 2017 and the current forecast of GDP growth in 2016 in New Mexico is 2.5% as forecasted by the University of New Mexico Bureau of Business & Economic Research.

• Experienced Management Team. TECO Energy’s management has a demonstrated track record of working productively with regulators and policy makers, employing a customer focus and regulatory management philosophy in its operating geographies that results in timely recovery of costs and returns on its capital employed. Emera believes that TECO Energy and Emera have complementary management teams and corporate cultures focused on safety and customer service that will facilitate the combination of Emera and TECO Energy following completion of the Acquisition.

• Community and Stakeholder Engagement. Emera’s approach to combining newly-acquired entities with existing operations is premised on creating value for customers, continuing to invest in the communities in which the acquisition entities operate and aligning Emera’s management team and employee base with those of the acquisition entities. Emera intends to continue to invest in local communities in Florida and New Mexico where TECO Energy operates, to preserve TECO Energy’s existing headquarter locations and local boards of directors in each state and to retain TECO Energy’s existing management team, allowing local managers to be responsive to employees, customers and regulators.

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Executive Appointments

On January 15, 2016, Greg Blunden was appointed Chief Financial Officer of Emera, effective March 1, 2016. Mr. Blunden has held financial leadership roles at Emera, Emera Maine and NSPI. Most recently, Mr. Blunden was Vice President, Corporate Strategy & Planning.

On January 15, 2016, Emera’s current CFO, Scott Balfour, was appointed Chief Operating Officer, Northeast and Caribbean, effective March 1, 2016. Mr. Balfour will provide senior executive leadership for Emera’s existing operations, including NSPI, Emera Energy, Emera Maine, Emera Caribbean, EBPC and Emera Utility Services.

On January 15, 2016, Wayne O’Connor was appointed Vice President, Corporate Strategy & Planning for Emera, effective March 1, 2016. Mr. O’Connor will coordinate Emera’s planning and strategy development efforts to grow and expand the Company’s business. Previously, he was Executive Vice-President of Operations at NSPI.

On September 22, 2015, Rob Bennett was appointed President and Chief Executive Officer of Emera US Inc., a wholly owned subsidiary of Emera, to lead the integration of TECO Energy. Previously, Mr. Bennett had been the Chief Operating Officer, Eastern Canada.

On August 31, 2015, Roman Coba was appointed Chief Information Officer of Emera.

Maritime Link Project and Strategic Partnership with Nalcor Energy on Muskrat Falls Projects

On July 31, 2012, Emera and Nalcor, along with the Provinces of Nova Scotia and Newfoundland and Labrador, executed 13 agreements in respect of the development and transmission of hydroelectric power from Muskrat Falls on the Churchill River in Labrador to the island of Newfoundland, the Province of Nova Scotia and through to New England. The agreements relate to the development of the Muskrat Falls Generating Station, the Labrador Transmission Assets, the Labrador-Island Transmission Link Project and the Maritime Link Project. More specifically, these agreements set out the detailed terms pursuant to which:

• Nalcor will construct and own a 824 MW hydro-electric generating facility at Muskrat Falls on the Lower Churchill River in Labrador and the Labrador Transmission Assets;

• Emera will invest in the Labrador-Island Transmission Link Project; and

• Emera will build, finance and operate for 35 years beginning in 2018, the Maritime Link Project, a transmission project linking the island of Newfoundland to Nova Scotia.

The execution of these agreements was followed, on November 30, 2012, with a finalization of a term sheet detailing the basis upon which the Government of Canada would provide financial support to the Maritime Link Project by way of a loan guarantee. This loan guarantee (the “Federal Loan Guarantee” or “FLG”) provides, among other things, that the Government of Canada would fulfill any payment obligations on the guaranteed debt relating to the Maritime Link Project in the event of a default on the guaranteed debt. The FLG enhances the credit rating of the debt financing of the Maritime Link Project to that of the Government of Canada, thus providing a material reduction to the cost of borrowing for the project.

On December 5, 2012, the Newfoundland and Labrador legislature voted in favour of a bill to approve the Muskrat Falls Generating Station, the Labrador Transmission Assets and the Labrador-Island Transmission Link Project.

On December 17, 2012, Emera and Nalcor entered into a sanction agreement enabling both parties to advance their respective projects. Nalcor officially sanctioned the Muskrat Falls Generating Station and the Labrador-Island Transmission Link Project on December 17, 2012, and at that time revised and finalized its capital cost estimates for the Muskrat Falls Generating Station, including Labrador Transmission Assets, from $2.9 billion to $3.6 billion and from $2.1 billion to $2.6 billion for the Labrador-Island Transmission Link Project. This set the

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stage for construction to begin on the Nalcor projects. On behalf of Emera, ENL’s two subsidiaries, NSPML and ENL Island Link Inc. will respectively carry out the development of the Maritime Link Project and invest in the Labrador-Island Transmission Link Project.

On January 28, 2013, NSPML filed an application with the UARB seeking approval of the Maritime Link Project. Previously, on May 17, 2012, the Province of Nova Scotia passed the Maritime Link Act in order to enable a project specific review of the Maritime Link Project by the UARB. Pursuant to the Maritime Link Act, the Province of Nova Scotia announced the Maritime Link Approval Process Regulations on October 2, 2012, setting out the approval process to be followed for the Maritime Link Project.

On February 11, 2013, ENL Island Link Inc. invested $67.7 million in the Labrador-Island Transmission Link Project.

On June 21, 2013, NSPML received a release from the Federal Environmental Assessment process, as well as environmental approval from the Provinces of Newfoundland and Labrador and Nova Scotia for the Maritime Link Project.

On July 22, 2013, NSPML received the UARB decision on the Maritime Link Project. The UARB approved the Maritime Link Project subject to certain conditions, including an assurance that additional market-priced energy will be available to Nova Scotians. The UARB approved requested project costs of $1.52 billion and the requested variance amount of $60 million, for total approved project costs of $1.58 billion plus AFUDC.

On October 21, 2013, NSPML filed the Maritime Link Project compliance filing with the UARB. The compliance filing sought confirmation from the UARB that NSPML has complied with each of the UARB conditions, including the condition relating to the availability of market-priced energy.

On November 29, 2013, the UARB approved the Maritime Link Project compliance filing and gave its final approval of the Maritime Link Project. Subsequent to that UARB approval, the Nova Scotia government passed legislative amendments to the Maritime Link Act, which clarified certain aspects of the regulatory framework in respect of the Maritime Link Project and provides NSPML with certain legal rights to facilitate the development and operation of the Maritime Link Project.

In early December 2013, Nalcor Energy and the Government of Newfoundland and Labrador announced the Federal Loan Guarantee associated with the Muskrat Falls Generating Station, the Labrador Transmission Assets and the Labrador-Island Transmission Link Project had been issued, and the financing for the Muskrat Falls Hydroelectric Project had been completed.

On December 13, 2013, NSPML filed its first quarterly compliance filing with the UARB, which included an updated capital cost estimate for the Maritime Link Project of $1.577 billion. Based upon this cost estimate and the application of the terms of the agreement with Nalcor, whereby NSPML will pay 20% of the total cost of the Lower Churchill Project Phase I and Maritime Link Project, the amount of this cost estimate that will be NSPML’s responsibility will be $1.5554 billion. The parties have agreed that Nalcor will be responsible for any difference between the $1.5554 billion and the final actual capital costs of the Maritime Link Project, up to $1.577 billion. Any such adjustment will be payable by Nalcor no later than 30 days after the actual capital costs of the Maritime Link Project are finally determined. Any actual capital costs of the Maritime Link Project in excess of the $1.577 billion shall be dealt with in accordance with the provisions of the Maritime Link Joint Development Agreement.

On January 30, 2014, NSPML entered into the first of the Maritime Link Project’s three major contracts: the supply and installation of the high-voltage direct current submarine cable. In February 2014, construction activities began in both Nova Scotia and Newfoundland and Labrador, with the initiation of rights-of-way clearing activities.

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On March 6, 2014, following satisfaction of the relevant conditions in the FLG term sheet, the Government of Canada issued the Federal Loan Guarantee in respect of the Maritime Link Project.

On April 23, 2014, the MLFT completed its offering of $1.3 billion aggregate principal amount of 3.5% amortizing bonds due December 1, 2052 at a price of $999.57 per $1,000 principal amount of bonds for aggregate gross proceeds of approximately $1.3 billion. The amortization of the bonds is from December 1, 2020 to December 1, 2052. The bonds are guaranteed by the Government of Canada under the FLG. The net proceeds are being used to fund construction of the Maritime Link Project.

Together with certain financing entered into earlier by or on behalf of MLFT and NSPML, this bond offering fully satisfied the obligations of Emera under the FLG Payment Obligation Agreement previously entered into between Emera, NSPML and the Government of Canada. Upon completion of the bond offering, Emera became obligated under the FLG Completion Guarantee previously granted by Emera in favour of the Government Canada. Under the FLG Completion Guarantee, Emera has guaranteed the performance of the obligations of NSPML to cause the completion of the Maritime Link Project, in the circumstances and within the timelines provided for in the FLG Completion Guarantee.

On June 26, 2014, NSPML entered into the second of the Maritime Link Project’s three major contracts: the supply and installation of two HVdc converter stations as well as three substations and two transition compounds.

In Q3 2014, the last of NSPML’s labour agreements was signed.

On March 12, 2015, NSPML entered into the third of the Maritime Link Project’s three major contracts, with Abengoa S.A., a global Spanish energy and transmission construction company for the construction of approximately 400 km of transmission lines in the Provinces of Newfoundland and Labrador and Nova Scotia. On November 25, 2015, Abengoa S.A. filed a notice under Spanish law, which provides for pre-insolvency protection in Spain, giving Abengoa S.A. the opportunity to reach an agreement with creditors to avoid a full insolvency process. ENL has worked closely with Abengoa S.A. and the performance bond sureties to minimize project impacts. Work on the Maritime Link Project continues.

On April 9, 2015, NSPML and the Assembly of Nova Scotia Mi’kmaq Chiefs signed a Socio-Economic Agreement for the Maritime Link Project. Under the Socio-Economic Agreement, NSPML will support ongoing engagement and commitments made during the environmental assessment process, including Mi’kmaq participation in environmental monitoring and employment and business opportunities for Mi’kmaq people.

Purchase of Natural Gas Generation Facilities in New England

On November 19, 2013, Emera acquired all of the outstanding equity interests in three combined-cycle gas-fired electricity generating facilities in New England that make up EE New England Gas Generation: Bridgeport Energy (520 MW, since upgraded to 560 MW) in Bridgeport, Connecticut; Tiverton Power (265 MW) in Tiverton, Rhode Island; and Rumford Power (265 MW) in Rumford, Maine, for total cash consideration of $573.9 million CAD ($548.4 million USD). This addition of gas generation in the Northeastern United States has been a strategic objective of Emera and is a complement to its hydro investment in the region.

To finance the transaction, Emera utilized $150 million USD received on repayment of a loan to NWP, which was facilitated by the refinancing of that entity’s indebtedness; a one-year $350 million USD non-revolving credit facility established by an indirect wholly owned subsidiary of Emera; and other cash resources on hand.

First Wind

On June 15, 2012, Emera and First Wind closed their transaction to jointly own and operate a 419 MW portfolio of wind energy projects in the Northeastern United States through a new company, NWP, owned 51% by First

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Wind and 49% by Emera. Emera invested $215 million USD, including transaction costs, and loaned $150 million USD to NWP, to be repaid within five years. On November 14, 2013, Emera received repayment of the $150 million USD loan to NWP in full. First Wind managed and operated the wind energy projects, and Emera Energy Services provided energy management services.

Emera and First Wind also had an agreement relating to additional wind energy projects developed or acquired by First Wind. Under this agreement, on February 11, 2013, Emera, through its interest in NWP, acquired a 49% interest in 34 MW Bull Hill project for $14.4 million USD.

On January 29, 2015, Emera sold its 49% interest in NWP to First Wind for $223.3 million USD.

Strategic Partnership with Algonquin Power & Utilities Corp.

APUC is a diversified generation, transmission and distribution utility traded on the TSX under the symbol “AQN.” The distribution group operates in the United States and provides rate regulated water, electricity and natural gas utility services. The non-regulated generation group owns or has interests in a portfolio of North American-based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission group invests in rate- regulated electric transmission and natural gas pipeline systems in the United States and Canada.

On April 29, 2011, Emera entered into a Strategic Investment Agreement (the “SIA”) with APUC. The SIA establishes how Emera and APUC will work together to pursue specific strategic investments of mutual benefit. The SIA outlines “areas of pursuit” for both Emera and APUC. For Emera, these include investment opportunities related to regulated renewable generation and transmission projects within its service territories, and large electric utilities. For APUC, these include investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. Emera is committed to working with APUC on opportunities that fit within APUC’s “areas of pursuit”.

The SIA also provides for Emera to acquire up to 25% of APUC through the purchase of common shares issued by APUC to fund certain investment opportunities under the SIA. The acquisition of APUC shares is subject to regulatory approval.

APUC share purchases by Emera have generally been made through the acquisition of subscription receipts in exchange for promissory notes at an agreed upon price, which are then exchangeable into common shares upon meeting certain transaction specific conditions, or at a later date at Emera’s option, as applicable. The acquisition and conversion of subscription receipts is subject to approvals required under applicable laws, including the rules of the TSX.

As at March 31, 2016, Emera owned 50.1 million common shares of APUC and had 12.9 million outstanding subscription receipts and dividend equivalents. On May 17, 2016, Emera announced that it had agreed to sell all of its 50.1 million common shares of APUC, representing approximately 19.3% of the issued and outstanding common shares, to a syndicate of underwriters at Cdn$10.85 per common share for an aggregate gross amount of approximately $544 million. The sale was completed on May 24, 2016. Emera intends to use the net proceeds from the sale in support of its general financing requirements, including the Acquisition. Emera continues to hold an equity interest in APUC equivalent to approximately 12.9 million common shares (in the form of subscription receipts and dividend equivalents), which upon conversion represent a continuing common equity interest of approximately 4.75%. The outstanding subscription receipts and dividend equivalents will automatically convert to common shares in Q4 2016, if an election is not made.

As at December 31, 2015, the carrying value of Emera’s investment in APUC was $503.7 million (2014 – Cdn$336.4 million).

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Gains on Dilution of APUC Equity Investment

In December 2015, APUC closed a 14.355 million common share offering. As a result, Emera recorded a dilution gain of $11.1 million (after-tax earnings of $9.4 million or $0.06 per common share) in “Income from Equity Investments,” as described in the MD&A for the year and twelve months ended December 31, 2015.

In Q3 2014 and Q4 2014 respectively, APUC closed 16.86 million and 10.05 million common share offerings. In addition, in Q3 2014, an over-allotment option of 2.52 million common shares was exercised. As a result of these two transactions, in Q3 2014, Emera recorded a gain of $10.8 million (after-tax earnings of $9.1 million or $0.06 per common share) and in Q4 2014, a gain of $7.5 million (after-tax earnings of $6.4 million or $0.04 per common share) in “Income from Equity Investments,” as described in the MD&A.

Empire District Electric Company Transaction

On February 9, 2016, APUC announced its intention to acquire The Empire District Electric Company in a $3.4 billion transaction, which is expected to close in Q1 2017. The closing of this transaction and its related financing is expected to further reduce Emera’s ownership interest.

Nova Scotia Power

Electricity Plan and Rate Stability

On November 9, 2015, the Province of Nova Scotia released its electricity plan to support stable and predictable energy rates until 2019. The electricity plan also provides for the development of performance standards through a 2016 UARB regulatory process. On December 18, 2015, the Province of Nova Scotia enacted the Electricity Plan Act (Nova Scotia) (the “Electricity Plan Act”), which requires NSPI to file a three-year rate plan for Fuel Costs in Q1 2016 and to file a three-year GRA to change non-fuel rates by April 30, 2016. NSPI filed its three year rate plan for Fuel Costs on March 7, 2016, indicating an average annual increase of 1.3% per year from 2017 to 2019. NSPI has also confirmed that no GRA for non-fuel cost will be filed for the 2017 to 2019 period.

The Electricity Plan Act directs NSPI to apply non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of certain tax benefits for the South Canoe Wind Project and the Sable Wind Project is to be reserved to be applied to the FAM in the 2017 to 2019 period. The exception to this direction is to apply a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would have been otherwise required. For more information, see the “Management’s Discussion and Analysis—Regulated Fuel Adjustment Mechanism and Fixed Cost Deferrals.”

Emera Maine

FERC Audit

In November 2014, the FERC commenced an audit covering the 2013 and 2014 period of Bangor Hydro’s compliance with conditions established in FERC’s orders authorizing its acquisition of MPS, which occurred on January 1, 2014. These two predecessor companies formed Emera Maine. The final audit report was released in early January 2016. The findings in the audit report conclude that Emera Maine did not follow the prescribed methodology for the calculation of AFUDC during the audit period and Emera Maine had included, in rates, costs of the Bangor Hydro and MPS merger prior to making the required filings. Emera Maine will fully comply with the recommendations in the audit report, including making the required filings for the merger costs and re-calculating AFUDC for 2013 and 2014, as ordered, which resulted in an immaterial impact on the Company’s consolidated statements of income.

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Emera Maine ROE Proceeding

On September 30, 2011 a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end-users filed a complaint with the FERC alleging that the 11.14 per cent base return on equity under the ISO-NE Open Access Transmission Tariff (“OATT”) was unjust and unreasonable. On June 19, 2014, the FERC issued an order in connection with this complaint, changing the methodology used to set the ROE for transmission assets.

This change would lower the base transmission ROE to 10.57% for the period of October 1, 2011 to December 31, 2012, subject to a further proceeding to finalize the determination of appropriate rates to be used in such calculation. The FERC decision would also lower the cap on the total ROE (inclusive of incentive adders) for transmission assets to 11.74%. In an order issued on October 16, 2014, the FERC confirmed that the ROE set in its earlier order was appropriate.

On March 3, 2015, in response to requests for rehearing from several parties, FERC affirmed its initial order, setting of the base ROE of 10.57% and capping the total ROE, including the effect of incentive adders, at 11.74%. Notices of Appeal to the U.S. Court of Appeals for the DC Circuit were filed by New England Transmission Operators and the complainants in the case on April 30, 2015. In Q2 2015, Emera Maine began processing the refunds to customers, based on a 10.57% ROE. By court order dated August 20, 2015, the DC Court of Appeals decided to hold the appeal of this case in abeyance pending the outcome of the consolidated cases (“ENE Case” and “MA AG II Case”) discussed below.

On December 27, 2012, a second group of consumer advocates, including Environment Northeast filed a complaint with the FERC on similar grounds, arguing that the 11.14% base ROE under the OATT was unjust and unreasonable (the ENE Case). On June 19, 2014, the FERC issued an order in this second ROE case, finding in favour of the complainants and allowing the complaint to proceed. As a result, a new ROE will be calculated and set by the FERC. This complaint created a new 15-month refund period beginning January 1, 2013 through March 31, 2014.

On July 31, 2014, a group of state commissions, state public advocates and end users filed a third complaint with the FERC alleging the ROE earned on transmission investments is unjust and unreasonable and does not reflect current economic conditions (the MA AG II Case). Any potential refund arising from this third complaint will relate to the period from July 31, 2014 to September 30, 2015, and the outcome will set the ROE going forward from the date of decision.

On November 24, 2014, FERC consolidated the ENE Case and MA AG II Case. A subsequent order by the FERC established a schedule for various procedural matters that turned the case over to an Administrative Law Judge in September 2015. Once that judge’s recommended decision is rendered, parties may file exceptions, and then the case is set for decision by FERC.

Emera Maine has recorded net reserves of $6.9 million pre-tax (U.S.$5.0 million) (2014 – Cdn$8.5 million) for these refund complaints as at December 31, 2015, based on a 10.57% ROE.

On March 22, 2016, the Administrative Law Judge issued a recommendation to the FERC with respect to the two outstanding ROE complaints (ENE Case and MA AG II Case). Each complaint was for a 15-month period with the recommendation for the ENE Case being 9.59% ROE, with a 10.42% maximum ROE, and the recommendation for MA AG II Case being 10.90% ROE, with a 12.19% maximum ROE.

On April 29, 2016, an additional complaint was filed with FERC challenging the ROE under the ISO-NE transmission tariff. The complaint was filed by the EMCOS seeking to reduce the base transmission ROE to a maximum of 8.93 per cent and the maximum ROE of 11.24 per cent.

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Emera Maine has recorded a reserve of $5.8 million pre-tax (US$4.5 million) (December 31, 2015—$6.9 million or US$5.0 million) for the first two base transmission ROE rate refund complaints. The reserves recorded for these complaints have been recorded as a component of Regulatory Liabilities on the Consolidated Balance Sheets, and the charges to earnings have been a reduction to Operating revenues—regulated on the Consolidated Statements of Income. The reserve was calculated on a 10.57 per cent base and represents Emera Maine’s best estimate of the probable outcome. No update has been made to the reserve, as a result of the ALJ recommendation as it is pending approval by the FERC and is considered uncertain until that time. No reserve has been made as a result of the EMCOS complaint, as the outcome is considered uncertain.

U.S. GAAP—Exemptive Relief and Companies Act Relief

On April 28, 2014, Emera was granted exemptive relief by the CSA allowing it to continue to report its financial results in accordance with U.S. GAAP (the “Exemptive Relief”). On July 9, 2014, Emera was granted an order pursuant to the Companies Act (Nova Scotia) (the “Companies Act”) exempting it from the Companies Act requirement to prepare its annual financial statements in accordance with IFRS (the “Companies Act Relief”). Both the Exemptive Relief and the Companies Act Relief will remain in effect for Emera until the earlier of: (i) January 1, 2019; (ii) the first day of the Company’s financial year commencing after the Company ceases to have activities subject to rate regulation; and (iii) the effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities. The Exemptive Relief and the Companies Act Relief each replace previous similar exemptive relief that had been granted to Emera in 2012 and 2011 respectively, which would have expired by January 1, 2015.

General Description of the Business—Emera

Emera is an energy and services company with approximately $12 billion in assets. Emera currently provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States, and the Caribbean.

Emera is focused on growing shareholder value by identifying reliable and affordable energy solutions for customers, typically involving the replacement of higher carbon electricity generation with generation from cleaner sources, and the related transmission, distribution infrastructure and delivery of that energy to market.

Emera has strong partnerships and relationships throughout the regions in which it operates and has established a diverse investment and operations profile that links its assets and capabilities in those regions. Core to Emera’s strategy is the ability to leverage these particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company.

Emera’s strategy is based on its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. Emera and its subsidiaries had approximately 3,500 employees at December 31, 2015, approximately 49% of whom are unionized.

Emera has grown its business through investments in its rate-regulated subsidiaries that are beneficial to its customers. Emera’s regulated subsidiaries include:

• NSPI (see “—NSPI”);

• Emera Maine (see “—Emera Maine”);

• BLPC, GBPC and Domlec (see “—Emera Caribbean”); and

• EBPC (see “—Pipelines”).

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Emera has also grown its business through its non-regulated subsidiaries (Emera Energy (see “—Emera Energy”) and Emera Utility Services and EUS Bahamas) and additional regulated and non-regulated strategic investments and activities that include:

• Emera’s 100% investment in NSPML, a $1.5554 billion transmission project, including two 170-kilometre subsea cables, between the island of Newfoundland and Nova Scotia. The investment in NSPML is accounted for on the equity basis with equity earnings equal to the ROE component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017;

• Emera’s 55.1% investment in the partnership capital of LIL, an electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change based on the balance of capital investments required from Emera and Nalcor to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined on completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime Link Projects, such that Emera’s total investment in NSPML and LIL will equal 49% of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is expected to go into service in 2017. Emera’s total investment is expected to approximate Cdn$409.1 million;

• Emera’s 4.75% (March 31, 2016: 23.2%) investment in APUC. APUC is a diversified generation, transmission and distribution utility traded on the TSX under the symbol “AQN.” The distribution group operates in the United States and provides rate regulated water, electricity and natural gas utility services. The non-regulated generation group owns or has interests in a portfolio of North American based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission group invests in rate-regulated electric transmission and natural gas pipeline systems in the United States and Canada. On May 17, 2016 Emera announced that it had agreed to sell all of the 50.1 million common shares it held in APUC, representing approximately 19.3% of APUC’s issued and outstanding common shares, to a syndicate of underwriters at $10.85 per common share for aggregate gross proceeds of approximately Cdn$544 million. The sale was completed on May 24, 2016. Emera continues to hold the subscription receipts and associated dividend equivalents, which represent approximately 4.75% of APUC’s issued and outstanding common shares (after giving effect to the conversion of the subscription receipts and associated dividend equivalents); and

• a 12.9% interest in M&NP.

NSPI

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services in Nova Scotia to approximately 507,000 customers with approximately $4.6 billion in assets and approximately 1,700 employees.

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures.

Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings from time to time at NSPI’s or the UARB’s request. NSPI is regulated under a cost of service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s regulated ROE range for 2013 to 2015 was 8.75% to 9.25%, based on an actual average regulated common equity component of up to 40% of actual average regulated capitalization. NSPI’s targeted regulated ROE range remains unchanged for 2016.

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NSPI operates with a FAM, which enables NSPI to recover fluctuating fuel expenses through annual fuel rate adjustments, which is subject to UARB review and approval. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

As at March 31, 2016 the FAM had a net liability balance of $46.6 million (December 31, 2015 – Cdn$28.3 million net asset).

Market and Sales

NPSI

Revenue and Electricity Sales by Customer Class

	For the year ended December 31
	2015		2014		2015		2014
	Electric Revenues (%)				GWh Electric Sales Volumes (%)
Residential		51.5		50.7		43.1		42.5
Commercial		29.5		29.4		30.1		30.1
Industrial		15.4		16.2		23.6		24.4
Other		3.6		3.7		3.2		3.0
Total		100.0		100.0		100.0		100.0

Energy Sources and Generation

NSPI’s energy sources for its electric energy generation are coal, petroleum coke (“petcoke”), natural gas, heavy fuel oil, hydroelectric energy, light fuel oil (gas turbine), biomass and wind. NSPI also purchases electric energy from IPPs in the Province of Nova Scotia and neighbouring markets outside the Province of Nova Scotia.

NSPI owns 2,483 MW of generating capacity, of which approximately 50% is coal-fired; natural gas and/or oil comprise another 28% of capacity; hydro and wind total 19% and biomass-fueled generation of 3%. In addition, NSPI has contracts to purchase renewable energy from IPPs. These IPPs own 496 MW, increasing to 552 MW in 2016 of wind and biomass-fueled generation capacity.

Comparative costs of fuel sources fluctuate from year to year. For information describing the percentage of total electric energy generated by fuel source and for information related to the cost of electricity generation, see the “Management’s Discussion and Analysis—NSPI—Regulated Fuel for Generation and Purchased Power”.

System Operations

The NSPI Energy Control Center co-ordinates and controls the electric generation and transmission and distribution facilities. The NSPI Energy Control Center is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a communication network used by system operators for remote monitoring and control of the power system components.

Through an interconnection agreement with NB Power, NSPI’s system has access to other regional power systems and the rest of the interconnected North American electric bulk power systems.

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Transmission and Distribution

NSPI transmits and distributes electricity from its generating stations to its customers. NSPI’s transmission system consists of approximately 5,000 km of transmission facilities. The distribution system consists of approximately 27,000 km of distribution facilities.

Contribution to Consolidated Net Income

NSPI’s contribution to Emera’s consolidated net income was $129.9 million in 2015 and $124.9 million in 2014.

Seasonal Nature

Electric sales volume is primarily driven by general economic conditions, population, weather and demand side management. Residential and commercial electricity sales are seasonal in the Province of Nova Scotia, with Q1 typically being the strongest period, reflecting colder weather and fewer daylight hours in the winter season.

Capital Expenditures

NSPI’s capital expenditures in 2015 were Cdn$274 million (2014 – Cdn$274 million).

The UARB prescribes and approves depreciation rates and regulated accounting policies. Depreciation rates are reviewed periodically. A settlement agreement on depreciation rates became effective on January 1, 2012. The overall impact of this settlement agreement on the average depreciation rate was immaterial.

Environmental Considerations

NSPI is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters, primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI.

Conformance with legislative and NSPI’s requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed to December 31, 2015.

The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix. The most recent target for each year of 2015 through 2019 was 25% of electrical energy which will be derived from renewable sources. That target was exceeded for 2015, with 27% of NSPI’s generation mix coming from renewable sources. In 2020, the target is 40% of electrical energy to be derived from renewable sources. The Maritime Link Project will supply 153 MW of firm, on-peak power and approximately 900 GWh per year of renewable electricity to help NSPI meet the legislated target of 40% renewable electricity in 2020. NSPI plans to retire a coal-fired generating unit following the commencement of commercial operations of the Maritime Link.

Emera Maine

On November 29, 2012, Bangor Hydro and MPS submitted a regulatory filing with the MPUC seeking permission to merge into one entity. This proposed change was also subject to regulatory approval by the FERC. The merger application included a proposal to harmonize distribution rates for most residential and small commercial customers on a revenue neutral basis. No change was proposed to other rates or rate classes. Regulatory approval was received in 2013 from the MPUC and FERC for Bangor Hydro and MPS to officially merge on January 1, 2014. Harmonization of rates was deferred to a future case.

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Emera Maine’s transmission operations are regulated by FERC, and its distribution operations and stranded cost recoveries are regulated by the MPUC. Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through the utility’s transmission and distribution networks.

Throughout the discussion below, various references are made to the two predecessor entities to Emera Maine, which existed as separate entities until December 31, 2013.

Emera Maine has approximately U.S.$1.1 billion of assets and approximately U.S.$670 million of net rate base. Emera Maine owns and operates approximately 1,700 km of transmission facilities and 15,000 km of distribution facilities and a workforce of approximately 400 people.

Market and Sales

Approximately 55% of Emera Maine’s electric revenue represents distribution operations, 31% is associated with local transmission operations and 14% relates to stranded cost recoveries. The rates for each element are established in distinct regulatory proceedings.

Emera Maine Revenue and Electricity Sales by Customer Class

	For the year ended December 31
	2015		2014		2015		2014
	Electric Revenues (%)				GWh Electric Sales Volumes (%)
Residential		47.8		48.3		39.7		39.7
Commercial		36.2		36.5		38.7		38.7
Industrial		8.8		9.1		20.9		20.9
Other		7.2		6.1		0.7		0.7
Total		100.0		100.0		100.0		100.0

Distribution Operations

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. Prior to July 1, 2014, the allowed ROE was 10.2%, on a common equity component of 50%. Effective July 1, 2014, the allowed ROE became 9.55% on a common equity component of 49%.

Transmission Operations

There are two transmission districts for Emera Maine, corresponding to the service territories of the two pre-merger entities.

Bangor Hydro District Transmission

Bangor Hydro District’s local transmission rates are regulated by the FERC and set annually on June 1, based upon a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments was 11.14%. Effective October 16, 2014, the allowed ROE changed to 10.57%, pending two outstanding complaints filed with the FERC to challenge the ISO-NE OATT allowed base ROE of 11.14%. The common equity component (i.e., the equity base upon which the allowable ROE is earned) is based upon the prior calendar year actual average balances. Effective June 1, 2015, transmission rates for the Bangor Hydro District increased by approximately 21% in connection with its annual transmission formula rate filing (2014 – increased by 13%). The increase is associated primarily with the under- recovery of prior year regional transmission revenues collected in local rates, as well as the recovery of increased transmission plant in service.

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Bangor Hydro District’s bulk transmission assets are managed by the ISO-NE as part of a region-wide pool of assets. The ISO-NE manages the regions’ bulk power generation and transmission systems and administers the open access transmission tariff. Currently, Bangor Hydro District, along with all other participating transmission providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is based on prior year regionally funded transmission investments, adjusted for current year forecasted investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments ranged from 11.64% to 12.64%. Effective October 16, 2014, the transmission investments allowed ROE changed to a range from 11.07% to 11.74%, pending the two aforementioned complaints filed with FERC. The common equity component is based upon the prior calendar year average balances. The participating transmission providers are also required to contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent. On June 1, 2015, Bangor Hydro District’s regionally recoverable transmission investments and expenses decreased by 6% (2014 – increased by 7%).

As at December 31, 2015, the Company had accrued U.S.$5.0 million associated with the FERC ROE complaints relating to Bangor Hydro District (2014 – U.S.$7.3 million). Refunds for the first FERC ROE complaint are being made to customers over a one-year period which began with the June 1, 2015 rate change.

MPS District Transmission

MPS District local transmission rates are regulated by the FERC and set annually on June 1 for wholesale and July 1 for retail customers, based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted investments. The current allowed ROE for transmission operations is 10.2%. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015, the transmission rates for the MPS District decreased by approximately 24% for wholesale customers (2014 – increased by 2%) and on July 1, 2015 decreased by 22% for retail customers (2014 – increased by 11%) in connection with its annual transmission formula rate filing. These decreases were primarily due to an increase in wholesale transmission revenue that allows for a decrease in local customer transmission rates.

The MPS District electric service territory is not connected to the New England bulk power system and it is not a member of ISO-NE. MPS District is not a party to the previously discussed ROE complaints at the FERC.

Stranded Cost Recoveries

Stranded cost recoveries in Maine are set by the MPUC. Electric utilities are entitled to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC. Unlike transmission and distribution operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through rates. Generally, regulatory rates to recover stranded costs are set every three years, determined under a traditional cost-of-service approach and are fully recoverable. On July 1 of each year, stranded cost rates are adjusted to reflect recovery of cost deferrals for the prior stranded costs rate year under the full recovery mechanism, as well as factor in any new stranded cost information.

Bangor Hydro District Stranded Costs

Bangor Hydro District’s net stranded regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract, and deferrals associated with reconciling stranded costs. These net regulatory assets total approximately U.S.$19.7 million as at December 31, 2015 (2014 – U.S.$25.1 million) or 1.8% of Emera Maine’s net asset base (2014 – 2.3%).

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On July 1, 2014, the Bangor Hydro District stranded cost rates decreased by 10%. Earlier, on March 1, 2014, stranded costs rates had increased by 20%. The allowed ROE used in setting the new rates on July 1, 2014, and March 1, 2014, was 5.9%, with a prescribed common equity component of 48%. The July 1, 2014 rate decrease remained in effect for all of 2015, and there was no rate change on July 1, 2015.

MPS District Stranded Costs

Effective January 1, 2015, the stranded cost rates for the MPS District decreased by approximately 150%. This was principally due to the flow-back to customers of certain benefits received by Emera Maine from Maine Yankee associated with litigation with the United States Department of Energy on nuclear waste disposal. The allowed ROE used in setting the new rates on January 1, 2015 was 6.75%, with a common equity component of 48%. The reduced stranded cost revenues are offset by reductions in expense and do not affect income. The January 1, 2015 rate decrease remained in effect for all of 2015 and there was no rate change on July 1, 2015. MPS District has a net stranded cost regulatory liability of U.S.$2.68 million as of December 31, 2015.

Contribution to Consolidated Net Income

Emera Maine’s contribution to Emera’s consolidated net income was U.S.$35.6 million in 2015 and U.S.$38.4 million in 2014.

Seasonal Nature

Electricity sales in Maine vary significantly over the year; Q1 and Q3 are typically the strongest. Q1 reflects colder weather and few daylight hours in the winter season, while Q3 reflects the hotter summer weather and the impact of summer tourism in the state.

Capital Expenditures

Emera Maine’s capital expenditures for the year ended 2015 were approximately Cdn$66 million (2014 – Cdn$85 million).

Environmental Considerations

Emera Maine is regulated by the U.S. Environmental Protection Agency for compliance with the Federal Water Pollution Control Act, the Clean Air Act, and other U.S. federal statutes, including those governing the treatment and disposal of hazardous wastes. Emera Maine is also regulated by the State of Maine’s Department of Environmental Protection.

Emera Caribbean

As of March 31, 2016, Emera Caribbean includes a 100% indirect interest in BLPC, a 51.9% indirect controlling interest in Domlec, an 80.4% direct and indirect interest in GBPC, a 19.1% indirect interest in Lucelec and a wholly owned indirect interest in Emera Utility Service Bahamas. As of February 25, 2016, Emera Caribbean’s indirect interest in BLPC has increased to 100%.

BLPC

BLPC is a vertically-integrated utility and the provider of electricity on the Caribbean island of Barbados with approximately $0.5 billion of assets. It serves approximately 126,000 customers, has a workforce of approximately 330 employees and is regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted to BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. Emera acquired its indirect interest in BLPC through the purchase of approximately 80.1% of the outstanding

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common shares of LPH, now ECI, and the parent company of BLPC in 2010. In 2015, Emera increased its ownership interest in BLPC to 95.5%. Emera initiated a process to purchase the remaining 4.5% of common shares from minority shareholders of ECI, which was completed on February 25, 2016.

BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and providing an appropriate return to investors. BLPC’s approved allowable regulated return on rate base for 2015 and 2014 is 10%.

A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. The Fair Trading Commission, Barbados has approved the calculation of the fuel charge, which is adjusted on a monthly basis.

Domlec

Domlec is a vertically-integrated utility on the island of Dominica with approximately Cdn$0.1 billion of assets. Domlec serves approximately 36,000 customers, has a workforce of 238 employees, and is regulated by the IRCD. On October 7, 2013, the IRCD issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014 for a period of 25 years. These new licenses replaced the existing license, which was due to expire on December 31, 2015. Domlec’s approved allowable regulated return on rate base for 2015 and 2014 was 15%.

A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely manner.

GBPC

Emera, through its wholly owned subsidiary ECHL, has a 50.0% direct and 30.4% indirect interest in GBPC, a vertically- integrated utility and the sole provider of electricity on Grand Bahama Island in The Bahamas with approximately $0.4 billion of assets. GBPC serves approximately 19,000 customers, has a workforce of approximately 205 employees and is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to generate, transmit and distribute electricity on the island until 2054. GBPC’s approved allowable regulated return on rate base for 2015 and 2014 was 10%. A fuel pass-through mechanism provides the opportunity to recover fuel costs in a timely manner. ECHL holds its indirect interest in GBPC through ICDU, which in turn owns a 50% interest in GBPC. ICDU is listed on the Bahamas International Securities Exchange.

Effective February 1, 2016, the GBPA approved GBPC’s GRA for the 2016 through 2018 period. Residential customers will see decreases of up to 4.5%, while commercial customers will see an increase of 1.5%. Commercial customers consume approximately 70% of GBPC’s production. Rates were approved based upon an 8.8% allowable return on rate base. This rate decision will allow for customers to install renewable energy systems and sell their excess energy to GBPC. This is based on a tariff rider scheduled to be in place by Q3 2016.

On June 29, 2012, GBPC announced a new regulatory rate structure which was approved by the GBPA and became effective July 1, 2012. The new regulatory rate structure consists of two components: (i) a base rate intended to recover GBPC’s operating expenses, depreciation and return on capital investment; and (ii) a fuel charge intended to recover all of GBPC’s fuel costs.

On January 17, 2013, GBPC and the GBPA finalized an Operating Protocol and Regulatory Framework agreement. This agreement formalized the operating protocols and regulatory construct GBPC agreed to in principle in June 2012.

As part of the initial rate case filing under the new regulatory structure, the GBPA approved a return on rate base of 10%. Every three years, commencing in January 2016, base rates will be reviewed and approved by the GBPA.

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As a component of its regulatory agreement with the GBPA, GBPC has an earnings share mechanism to allow for earnings above or below its approved 10% return on rate base to be deferred to a regulatory asset or liability at the rate of 50% of amounts below a 9% return on rate base and 50% of amounts above 11% return on rate base respectively.

Lucelec

Emera indirectly owns a 19.1% interest in Lucelec, a vertically-integrated regulated electric utility on the Caribbean island of St. Lucia. Lucelec is listed on the Eastern Caribbean Securities Exchange.

EUS Bahamas

EUS Bahamas provides utility construction services in The Bahamas.

Market and Sales

Emera Caribbean Revenue and Electricity Sales by Customer Class (1)

	For the year ended December 31
	2015		2014		2015		2014
	Electric Revenues (%)				GWh Electric Sales Volumes (%)
Residential		32.4		33.4		33.7		33.4
Commercial		57.0		58.6		56.8		56.9
Industrial		8.8		6.3		7.7		7.7
Other		1.8		1.7		1.8		2.0
Total		100.0		100.0		100.0		100.0

Information included above includes 100% of BLPC, GBPC and Domlec.

Energy Sources and Generation

BLPC’s and GBPC’s energy sources for their respective electricity generation is primarily heavy fuel oil used for base load generation and light fuel oil used for peaking generation.

BLPC owns approximately 239 MW of generation comprised of: (i) 5 gas turbine units with a combined capacity of 86 MW (light oil and jet fuel oil-fired); (ii) 6 diesel units with a combined capacity of 113 MW (heavy oil-fired); and (ii) 2 steam units with a combined capacity of 40 MW (heavy oil-fired).

GBPC owns approximately 98 MW of heavy fuel oil-fired and medium and slow speed diesel generating units. Domlec owns approximately 20 MW of oil-fired generation and 7 MW of hydro production.

Comparative costs of fuel sources fluctuate from year to year. For information describing the percentage of total electric energy generated by fuel source and for information related to the cost of electricity generation, see the “Management’s Discussion and Analysis—Regulated Fuel for Generation and Purchased Power”.

System Operation

BLPC, GBPC and Domlec have system control centers which co-ordinate and control the electric generation and transmission facilities with the goal of providing a reliable and secure electricity supply while maintaining economy of operations. The system control centre is linked to the generating stations and other key parts of the system by the “Supervisory Control and Data Acquisition” system, a voice and data communications network.

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Transmission and Distribution

BLPC, GBPC and Domlec transmit and distribute electricity from their generating stations to their customers.

BLPC’s transmission system consists of 116 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of 2,800 km of distribution lines which includes distribution supply substations.

GBPC’s transmission system consists of 138 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of approximately 850 km of distribution lines which includes distribution supply substations.

Domlec’s transmission system consists of 452 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of approximately 640 km of distribution lines which includes distribution supply substations.

Contribution to Consolidated Net Income

Emera Caribbean’s contribution to Emera’s consolidated net income was U.S.$31.4 million in 2015 and U.S.$26.0 million in 2014.

Seasonal Nature

Electricity sales and related generation varies significantly over the year in the Caribbean; Q3 is typically the strongest period, reflecting warmer weather.

Capital Expenditures

Emera Caribbean’s capital expenditures for the year ended 2015 were approximately $44 million (2014 – $30 million).

Environmental Considerations

Emera Caribbean has implemented a Health Safety Environmental and Management system to assist in safeguarding the health and safety of its employees, contractors and customers and protection of the environment.

Emera Energy

Emera Energy consists of Emera’s wholly owned Emera Energy Services, EE New England Gas Generation, Bayside Power and Brooklyn Energy; and Emera’s indirect 50% interest in Bear Swamp. On January 29, 2015, Emera sold its interest in NWP to its 51% partner, First Wind.

Emera Energy Services

Emera Energy Services derives revenue and earnings from the wholesale marketing and trading of natural gas, electricity and other energy-related commodities and derivatives within the Company’s strict risk tolerances, including those related to value-at-risk (VaR) and credit exposure. More specifically, Emera Energy purchases and sells physical natural gas and related transportation capacity rights, as well as providing related energy asset management services. EES is also responsible for commercial management of electricity production and fuel procurement for Emera Energy Generation’s fleet. Established in 2002, Emera Energy’s marketing and trading business currently has approximately 80 employees engaged in commercial activities and related back office,

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legal and other support functions. The primary market for the marketing and trading business is northeastern North America, including the Marcellus shale gas region, the U.S. Gulf Coast and Central Canada. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. Marketing and trading operates in a competitive environment, and its business relies on knowledge of the region’s energy markets, understanding of pipeline infrastructure, a network of counterparty relationships and a focus on customer service. Emera Energy invests in physical transportation capacity rights to move gas across its portfolio, utilizes financial products to hedge commodity prices, and minimizes open commodity positions in order to maintain the low to moderate risk profile of its marketing and trading business.

Emera Energy Generation

Emera Energy wholly owns and operates a portfolio of high efficiency, non-utility electricity generating facilities in northeast North America. Emera Energy has approximately 125 employees in its wholly owned generation business. The New England facilities participate in the regional capacity market and are compensated for being available to provide power. For the portion of output not committed under power purchase agreements, Emera Energy’s generation facilities sell into price-based competitive markets and earn revenues through the physical delivery of power and ancillary services, such as load regulation.

Market and Sales

Information regarding these facilities is summarized in the following table:

Wholly Owned Generation Facilities	Location	Capacity (MW)		Commissioning / In-Service Date		Fuel	Description
New England
Bridgeport(1)	Connecticut		560		1999	Natural gas	Selling electricity and capacity to ISO-NE
Tiverton	Rhode Island		265		2000	Natural gas	Selling electricity and capacity to ISO-NE
Rumford	Maine		265		2000	Natural gas	Selling electricity and capacity to ISO-NE
Total New England			1,090
Maritime Canada
Bayside Power	New Brunswick		290		2001	Natural gas	Long-term power purchase agreement November – March; Selling electricity to Maritime Provinces and ISO-NE for remainder of year
Brooklyn Energy	Nova Scotia		30		1996	Biomass	Long-term purchase power agreement
Total Maritime Canada			320
Total			1,410

(1) A Q2 2015 upgrade at Bridgeport increased its nameplate capacity from 540 MW to 560 MW.

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Information regarding Emera Energy’s equity investment in Bear Swamp is summarized below:

Investments in Generation Facilities(1)	Ownership (%)		Location	Capacity (MW)		Fuel	Description
New England
Bear Swamp		50	Massachusetts		600	Hydro	Long-term power purchase agreement and selling electricity and capacity to ISO-NE

(1) In January 29, 2015, Emera completed the sale of its 49% interest in NWP to First Wind for U.S.$223.3 million. Emera’s carrying value of its 49% interest as at December 31, 2014 was U.S.$204.4 million.

Information regarding Emera Energy’s revenues is summarized below:

Emera Energy Revenue

	For the year ended December 31
	2015		2014
Electricity sales	$	463.1	$	517.7
Capacity revenues		43.7		45.8
Marketing and trading margin		83.1		237.4
Total	$	589.9	$	800.9

Contribution to Consolidated Net Income

Emera Energy’s contribution to Emera’s consolidated net income was $98.9 million in 2015 and $185.7 million in 2014.

Seasonal Nature

The electricity generation business in the northeast of the United States is seasonal. Q1, Q3 and Q4 are generally the strongest periods, reflecting colder weather, and fewer daylight hours in the winter season, and cooling load in the summer.

Capital Expenditures

Emera Energy’s capital expenditures for the year ended 2015 were approximately $42 million (2014 – $63 million). The 2015 capital expenditures included a Q2 2015 upgrade at the Bridgeport facility that increased the nameplate capacity from 540 MW to 560 MW. The 2014 capital expenditures included a major refit and upgrade at the Bridgeport facility that increased the nameplate capacity from 520 MW to 540 MW.

Environmental Considerations

Among other environmental laws and regulations, EE New England Gas Generation is subject to the Regional Greenhouse Gas Initiative (RGGI) for carbon dioxide emissions and the Acid Rain Program for sulphur dioxide emissions. EE New England Gas Generation emits approximately two million tons of carbon dioxide per year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions programs could adversely impact financial and operational performance.

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Pipelines

Pipelines consists of Emera’s wholly owned EBPC and Emera’s 12.9% interest in M&NP.

EBPC

EBPC owns Brunswick Pipeline, a 145-km pipeline delivering re-gasified natural gas from the Canaport LNG import terminal near Saint John, New Brunswick to markets in the Northeastern United States. The pipeline travels through southwest New Brunswick and connects with the Maritimes & Northeast Pipeline at the Canada/US border near Baileyville, Maine. Since its commissioning in July 2009, the pipeline has been used solely to transport natural gas for RECL under a 25 year firm service agreement. Brunswick Pipeline is regulated by the NEB, which has classified it as a Group II pipeline.

M&NP

Emera owns a 12.9% interest in the Maritimes & Northeast Pipeline, which is a 1,400 km pipeline that transports natural gas from offshore Nova Scotia to markets in Maritime Provinces and the Northeastern United States.

Contribution to Consolidated Net Income

Emera’s wholly owned EBPC and Emera’s 12.9% interest in M&NP’s contribution to Emera’s consolidated net income was $37.5 million in 2015 and $32.7 million in 2014.

Environmental Considerations

Brunswick Pipeline is regulated by the NEB and subject to both federal and provincial environmental laws and regulations. Brunswick Pipeline has comprehensive integrity, safety and environmental programs in place, including an environmental management system and regularly scheduled physical inspections of the pipeline.

Economic Dependence

Brunswick Pipeline has a 25-year firm transport or pay service agreement with RECL, which runs to 2034. The risk of non- payment is mitigated as Repsol, the parent company of RECL, has provided EBPC with a guarantee for all RECL’s payment obligations under the firm service agreement.

Emera Corporate and Other

Contribution to Consolidated Net Income

Emera Corporate and Other’s contribution to Emera’s consolidated net income was $45.3 million in 2015 and $(7.7) million in 2014. Included in the fiscal 2015 results are acquisition-related after-tax costs of $52.8 million and an after-tax mark-to- market gain of $100.5 million related to the effect of U.S. dollar-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the Convertible Debenture Offering for the Acquisition.

Capital Expenditures

Emera Corporate and Other capital expenditures for the year ended 2015 were approximately $10.0 million (2014 – $10.0 million).

Other Emera Environmental Matters

Emera’s activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air,

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water and solid waste. Emera estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations will be approximately $29.4 million during fiscal 2016 and are estimated to be $55.9 million from 2017 through 2020. The estimated expenditures do not include: (i) costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions; and (ii) expenditures related to the addition of renewable or cleaner energy generation.

TECO Energy

TECO Energy was incorporated in Florida in 1981 as part of a restructuring in which it became the parent corporation of TEC. TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiary, NMGI, owns NMGC. TECO Energy and its subsidiaries had approximately 3,700 employees as of March 31, 2016.

The common stock of TECO Energy trades on the New York Stock Exchange under the symbol “TE”.

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TECO Energy’s revenues from continuing operations by regulated subsidiary for the periods presented as follows:

Revenues⁽¹⁾ from Continuing Operations

	Three months ended March 31, 2016			Year ended December 31, 2015		Year ended December 31, 2014
	millions of U.S. dollars
Tampa Electric	$	424.5		$	2,018.3	$	2,021.0
PGS		131.2			407.5		399.6
NMGC		106.6			316.5		137.5
Total regulated businesses		662.3			2,742.3		2,558.1
Other		(2.8	)		1.2		8.3
Total revenues from continuing operations	$	659.5		$	2,743.5	$	2,566.4

Net Income (Loss) from Continuing Operations

	Three months ended March 31, 2016			Year ended December 31, 2015			Year ended December 31, 2014
	millions of U.S. dollars
Tampa Electric	$	50.2		$	241.0		$	224.5
PGS		13.1			35.3			35.8
NMGC		15.2			24.1			10.5
Total regulated businesses		78.5			300.4			270.8
Other(2)		(4.8	)		(59.2	)		(64.4	)
Net income from continuing operations	$	73.7		$	241.2		$	206.4

(1) Segment revenues include intercompany transactions that are eliminated in the preparation of TECO Energy’s consolidated financial statements.

For further information on the financial condition and results of TECO Energy, reference is made to the audited consolidated financial statements of TECO Energy as at December 31, 2015 and 2014, including the consolidated statements of income, comprehensive income, cash flows and capital for each of the years ended December 31, 2015 and 2014, and the unaudited consolidated financial statements of TECO Energy for the three months ended March 31, 2016, each of which is incorporated by reference in this Prospectus.

Sale of TECO Coal

On September 21, 2015, TECO Diversified, a wholly-owned subsidiary of TECO Energy, entered into a securities purchase agreement for the sale of TECO Coal to Cambrian Coal Corp. The securities purchase agreement did not provide for an up-front purchase payment, but provides for contingent payments of up to U.S.$60 million that may be paid in the years up to 2019 depending on specified coal benchmark prices. TECO Energy retains certain deferred tax assets and personnel related liabilities, but all other TECO Coal assets and liabilities were transferred in the transaction. The retained liabilities included pension liability, which was fully funded at September 30, 2015, and severance agreements, which were paid in 2015. In addition, TECO Energy retained obligations under letters of indemnity that guarantee payments on bonds posted for the reclamation of mines prior to the transfer of all permits to the purchaser by the Commonwealths of Kentucky and Virginia. TECO Energy is working with the purchaser and the respective permitting agencies to have all permits transferred to the purchaser by the end of 2016.

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The securities purchase agreement called for a simultaneous signing and closing, which occurred on September 21, 2015. The closing of this sale essentially completed the process of TECO Energy’s exit from unregulated operations to focus on regulated utility businesses.

As a result of the authorization by TECO Energy’s Board of Directors authorizing it to enter into negotiations for the sale of TECO Coal, effective in the third quarter of 2014 it was classified as asset held for sale and its results for all periods presented are classified on TECO Energy’s financial statements as discontinued operations. TECO Energy recorded a non-cash valuation adjustment of approximately U.S.$76 million, after tax, to the carrying value of TECO Coal to reflect the sales price specified under a sales agreement entered into in October 2014, and an additional U.S.$51 million impairment charge, including a U.S.$7.7 million charge related to black lung liabilities was recorded in 2015.

Tampa Electric

TEC was incorporated in Florida in 1899 and was reincorporated in 1949. TEC is a public utility operating within the State of Florida. Its Tampa Electric division is engaged in the generation, purchase, transmission, distribution and sale of electric energy. The retail territory served comprises an area of about 2,000 square miles in West Central Florida, including Hillsborough County and parts of Polk, Pasco and Pinellas Counties. The principal communities served are Tampa, Temple Terrace, Winter Haven, Plant City and Dade City. In addition, Tampa Electric engages in wholesale sales to utilities and other resellers of electricity. It has two electric generating stations in or near Tampa and one electric generating station in southwestern Polk County, Florida.

Tampa Electric had 2,038 employees as of March 31, 2016, of which 827 were represented by the International Brotherhood of Electrical Workers and 156 were represented by the Office and Professional Employees International Union.

In 2015, Tampa Electric’s total operating revenue was derived approximately 52% from residential sales, 30% from commercial sales, 8% from industrial sales and 10% from other sales, including bulk power sales for resale. The sources of operating revenue and MWH sales for the years indicated were as follows:

Operating Revenue

	Three months ended March 31, 2016			Year ended December 31, 2015		2014
	millions of U.S. dollars
Residential	$	217.4		$	1,040.3	$	1,007.6
Commercial		132.8			608.0		602.0
Industrial – Phosphate		13.1			53.1		59.9
Industrial – Other		25.5			107.1		104.6
Other retail sales of electricity		39.5			177.2		181.9
Deferred and other revenue(1).		(19.4	)
Total retail		408.9			1,985.7		1,956.0
Sales for resale		1.4			3.7		13.0
Other		14.2			28.9		52.0
Total operating revenues	$	424.5		$	2,018.3	$	2,021.0

(1) Primarily reflects the timing of environmental and fuel clause recoveries.

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Megawatt-hour Sales

	Three months ended March 31, 2016		Year ended December 31, 2015		2014
	thousands of MWh
Residential		1,915		9,045		8,656
Commercial		1,388		6,301		6,142
Industrial		461		1,870		1,901
Other retail sales of electricity		401		1,791		1,827
Total retail		4,165		19,007		18,526
Sales for resale		50		115		259
Total energy sold		4,215		19,122		18,785

No significant part of Tampa Electric’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on Tampa Electric. Tampa Electric’s business is not highly seasonal, but winter peak loads are experienced due to electric space heating, fewer daylight hours and colder temperatures and summer peak loads are experienced due to the use of air conditioning and other cooling equipment.

Generation

Tampa Electric has three electric generating stations in service, with a December 2015 net winter generating capability of 4,730 MW. Tampa Electric assets include the Big Bend Power Station (1,632 MW capacity from four coal units and 61 MW from a CT), the Bayside Power Station (1,839 MW capacity from two natural gas combined cycle units and 244 MW from four CTs) and the Polk Power Station (220 MW capacity from the IGCC unit and 732 MW from four CTs). In addition, Tampa Electric installed a 1.6 MW solar array at Tampa International Airport in December 2015.

The Big Bend coal-fired units went into service from 1970 to 1985, and the CT was installed in 2009. The Polk IGCC unit began commercial operation in 1996, and the four CTs began commercial operation from 2000 to 2007. Bayside Unit 1 was completed in April 2003, Unit 2 was completed in January 2004 and Units 3 through 6 were completed in 2009. Both the Phillips Power Station and the City of Tampa Partnership Station were retired in November 2015.

Tampa Electric owns 180 substations having an aggregate transformer capacity of 22,351 Mega Volts Amps. The transmission system consists of approximately 1,302 pole miles (including underground and double-circuit) of high voltage transmission lines, and the distribution system consists of 6,209 pole miles of overhead lines and 5,060 trench miles of underground lines. As of December 31, 2015, there were 747,660 meters in service. All of this property is located in Florida.

All plants and important fixed assets are held in fee simple except that titles to some of the properties are subject to easements, leases, contracts, covenants and similar encumbrances and minor defects of a nature common to properties of the size and character of those of Tampa Electric.

Tampa Electric has easements or other property rights for rights-of-way adequate for the maintenance and operation of its electrical transmission and distribution lines that are not constructed upon public highways, roads and streets. It has the power of eminent domain under Florida law for the acquisition of any such ROW for the operation of transmission and distribution lines. Transmission and distribution lines located in public ways are maintained under franchises or permits.

TEC has a long-term lease for the office building in downtown Tampa, which serves as headquarters for TECO Energy, Tampa Electric and PGS.

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Regulation

Tampa Electric’s retail operations are regulated by the FPSC, which has jurisdiction over retail rates, quality of service and reliability, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices and other matters.

In general, the FPSC’s pricing objective is to set rates at a level that provides an opportunity for the utility to collect total revenues (revenue requirements) equal to its cost to provide service, plus a reasonable return on invested capital.

The costs of owning, operating and maintaining the utility systems, excluding fuel and conservation costs as well as purchased power and certain environmental costs for the electric system, are recovered through base rates. These costs include O&M expenses, depreciation and taxes, as well as a return on investment in assets used and useful in providing electric service (rate base). The rate of return on rate base, which is intended to approximate the individual company’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes (at a zero cost rate) and an allowed ROE. Base rates are determined in FPSC revenue requirement and rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other interested parties.

Tampa Electric’s results for 2015, 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on September 6, 2013, between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On September 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases: U.S.$57.5 million effective November 1, 2013, an additional U.S.$7.5 million effective November 1, 2014, an additional U.S.$5.0 million effective November 1, 2015, and an additional U.S.$110.0 million effective January 1, 2017 or the date that an expansion of Tampa Electric’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective no sooner than January 1, 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital, and Tampa Electric also began using a 15-year amortization period for all computer software retroactive to January 1, 2013. Effective November 1, 2013, Tampa Electric ceased accruing U.S.$8.0 million annually to the FPSC-approved self-insured storm damage reserve.

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Non-power goods and services transactions between Tampa Electric and its affiliates are subject to regulation by the FPSC and FERC, and any charges deemed to be imprudently incurred may be disallowed for recovery from Tampa Electric’s retail and wholesale customers, respectively. Given TECO Energy’s acquisition of NMGC, Tampa Electric and TECO Energy jointly requested a waiver from FERC in order for Tampa Electric to continue to supply a de-minimis level of non-power goods and services to its affiliates. TECO Energy separately notified FERC that it would no longer qualify to be considered a single-state holding company under the Public Utility Holding Company Act of 2005 as of January 1, 2015, and thus it had formed a centralized service company, TECO Services, Inc., which would provide other non-power goods and services to Tampa Electric and its affiliates. On December 31, 2014, FERC granted Tampa Electric’s requested waiver without conditions, effective as of January 1, 2015.

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On June 30, 2014, the company filed its required triennial market-power analysis in support of the company’s continued ability to effect wholesale market-based rate transactions everywhere, except within Tampa Electric’s balancing-authority area. FERC accepted Tampa Electric’s triennial filing on November 24, 2015.

Tampa Electric is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters. See “Business—TECO Energy—Environmental Compliance”.

Competition

Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Distributed generation could also be a source of competition in the future, but has not been a significant factor to date. Tampa Electric intends to retain and expand its retail business by managing costs and providing quality service to retail customers.

Unlike the retail electric business, Tampa Electric competes in the wholesale power market with other energy providers in Florida, including approximately 30 other investor-owned, municipal and other utilities, as well as co-generators and other unregulated power generators with uncontracted excess capacity. Entities compete to provide energy on a short-term basis (i.e., hourly or daily) and on a long-term basis. Competition in these markets is primarily based on having available energy to sell to the wholesale market and the price. In Florida, available energy for the wholesale markets is affected by the state’s Power Plant Siting Act (the “PPSA”), which sets the state’s electric energy and environmental policy, and governs the building of new generation involving steam capacity of 75 MW or more. The PPSA requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits. The effect of the PPSA has been to limit the number of unregulated generating units with excess capacity for sale in the wholesale power markets in Florida.

Tampa Electric is not a major participant in the wholesale market because it uses its lower-cost generation to serve its retail customers rather than the wholesale market.

FPSC rules promote cost-competitiveness in the building of new steam generating capacity by requiring Investor Owned Utilities (“IOUs”), such as Tampa Electric, to issue RFPs prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle greater than 75 MW. These rules, which allow independent power producers and others to bid to supply the new generating capacity, provide a mechanism for expedited dispute resolution, allow bidders to submit new bids whenever the IOU revises its cost estimates for its self-build option, require IOUs to disclose the methodology and criteria to be used to evaluate the bids and provide more stringent standards for the IOUs to recover cost overruns in the event that the self-build option is deemed the most cost-effective.

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Fuel

Approximately 52% of Tampa Electric’s generation of electricity for 2015 was natural gas-fired, with coal representing approximately 48%. Tampa Electric used its generating units to meet approximately 94% of the total system load requirements, with the remaining 6% coming from purchased power. Tampa Electric’s average delivered fuel cost per MMBTU and average delivered cost per unit of fuel burned have been as follows:

	2015		2014		2013		2012		2011
	Average cost per MMBTU
Coal(1)	$	3.34	$	3.48	$	3.36	$	3.57	$	3.46
Natural Gas(2)		4.34		5.68		5.23		5.34		6.20
Oil		22.34		0.00		24.72		23.56		21.21
Composite		3.78		4.16		4.00		4.19		4.38
Average cost per ton of coal burned	$	79.76	$	83.70	$	77.79	$	84.59	$	83.17

(1) Represents the cost of coal and the costs for transportation.

(2) Represents the costs of natural gas, transportation, storage, balancing, hedges for the price of natural gas, and fuel losses for delivery to the energy center.

In 2015, Tampa Electric’s generating stations burned fuels as follows: Bayside Power Station burned natural gas; Big Bend Station, which has SO₂ scrubber capabilities and NO_x reduction systems, burned a combination of high-sulfur coal and petroleum coke, No. 2 fuel oil and natural gas; and Polk Power Station burned a blend of low-sulfur coal and petroleum coke (which was gasified and subject to sulfur and particulate matter removal prior to combustion), natural gas and oil.

Coal

Tampa Electric burned approximately 4.0 million tons of coal and petroleum coke during 2015 and estimates that its combined coal and petroleum coke consumption will be about 4.1 million tons in 2016. During 2015, Tampa Electric purchased approximately 67% of its coal under long-term contracts with five suppliers, and approximately 33% of its coal and petroleum coke in the spot market. Tampa Electric expects to obtain approximately 85% of its coal and petroleum coke requirements in 2016 under long-term contracts with five suppliers and the remaining 15% in the spot market. Tampa Electric has coal transportation agreements with trucking, rail, barge and ocean vessel companies.

Tampa Electric’s long-term contracts provide for revisions in the base price to reflect changes in several important cost factors and for suspension or reduction of deliveries if environmental regulations should prevent Tampa Electric from burning the coal supplied, provided that a good faith effort has been made to continue burning such coal.

In 2015, approximately 84% of Tampa Electric’s coal supply was deep-mined, approximately 7% was surface-mined and the remaining 9% was petroleum coke. Federal surface-mining laws and regulations have not had any material adverse impact on Tampa Electric’s coal supply or results of its operations. Tampa Electric cannot predict, however, the effect of any future mining laws and regulations.

Natural Gas

As of December 31, 2015, approximately 63% of Tampa Electric’s 1,500,000 MMBTU gas storage capacity was full. Tampa Electric has contracted for 78% of its expected gas needs for the April 2016 through October 2016 period. In early March 2016, to meet its generation requirements, Tampa Electric expects to issue RFPs to meet its remaining 2016 gas needs and begin contracting for its 2017 gas needs. Additional volume requirements in excess of projected gas needs are purchased on the short-term spot market.

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Oil

Tampa Electric has an agreement in place to purchase low sulfur No. 2 fuel oil for its Big Bend and Polk Power stations. The agreement has pricing that is based on spot indices.

Franchises and Other Rights

Tampa Electric holds franchises and other rights that, together with its charter powers, govern the placement of Tampa Electric’s facilities on the public rights-of-way as it carries for its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing Tampa Electric’s use of public rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement. The franchises are irrevocable and not subject to amendment without the consent of Tampa Electric (except to the extent certain city ordinances relating to permitting and like matters are modified from time to time), although, in certain events, they are subject to forfeiture.

Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years. The City of Temple Terrace reserved the right to purchase Tampa Electric’s property used in the exercise of its franchise if the franchise is not renewed. In the absence of such right to purchase caused by non-renewal, Tampa Electric would be able to continue to use public rights-of-way within the municipality based on judicial precedent, subject to reasonable rules and regulations imposed by the municipalities.

Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates ranging from September 2017 through August 2043.

Franchise fees expense totaled U.S.$46.5 million in 2015. Franchise fees are calculated using a formula based primarily on electric revenues and are collected on customers’ bills.

Utility operations in Hillsborough, Pasco, Pinellas and Polk Counties outside of incorporated municipalities are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the County Commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates for the Hillsborough County, Pinellas County and Polk County agreements. The agreement covering electric operations in Pasco County expires in 2023.

Capital Expenditures

Tampa Electric’s capital expenditures in 2015 of U.S.$595 million, excluding allowance for funds used during construction (“AFUDC”) debt and equity, included U.S.$215 million for the Polk 2-5 conversion to combined cycle and related transmission system improvements, U.S.$15 million for solar generation projects at Tampa International Airport and the Big Bend Power Station, U.S.$10 million for the conversion of the Big Bend Station boiler ignition system from distillate oil to natural gas, and approximately U.S.$25 million in the first year of its program to replace its Customer Information System with a state-of-the-art Customer Relationship Management and Billing System (“CRMB”). Tampa Electric also spent approximately US$35 million for hurricane storm hardening for both the transmission and distribution systems, and US$20 million for maintenance capital for environmental control equipment and compliance with environmental regulation. Tampa Electric’s 2015 capital expenditures included approximately U.S.$18 million related to environmental compliance and improvement programs, primarily for electrostatic precipitator and scrubber improvements, SCR catalyst replacements and modifications to coal combustion by-product storage areas at the Big Bend Power Station.

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As at December 31, 2015, Tampa Electric expected to spend approximately U.S.$575 million on capital expenditure for 2016. For the transmission and distribution systems, Tampa Electric expects to spend U.S.$210 million in 2016, including approximately U.S.$155 million for normal transmission and distribution system expansion and reliability, and approximately U.S.$40 million for transmission and distribution system storm hardening. Capital expenditures for the existing generating facilities of U.S.$130 million include approximately U.S.$20 million for repair and refurbishments of CTs under long-term agreements with equipment manufacturers, approximately U.S.$50 million for generating system reliability in 2016 and advance purchases for 2017 unit outages. The capital expenditure forecast includes U.S.$35 million, included in the New Generation category, for a 23 MW solar array that Tampa Electric will build, own and operate at the Big Bend Power Station. Included in 2016 capital expenditure forecast is U.S.$20 million to complete the CRMB project described above.

In the 2017 to 2020 period, Tampa Electric expects to spend approximately U.S.$500 million annually to support normal system growth and reliability, environmental compliance and improvements to facilities to serve customers. This level of ongoing capital expenditures reflects the costs for materials and contractors, long-term regulatory requirements for storm hardening, and an active program of transmission and distribution system upgrades which will occur over the forecast period. These programs and requirements include: approximately U.S.$20 million annually for repair and refurbishments of CTs under long-term agreements with equipment manufacturers, average annual expenditures of more than U.S.$90 million to support generating unit availability and reliability; average annual expenditures of almost U.S.$25 million for environmental compliance; average annual expenditures of more than U.S.$35 million for general infrastructure and facilities; average annual expenditures of approximately U.S.$30 million for transmission and distribution system storm hardening; and approximately U.S.$145 million annually for transmission and distribution system capacity improvements to meet expected stronger customer growth and reliability. Included in this period is average annual capital spending of approximately U.S.$25 million to implement the new technology required to modernize the distribution system and install automated metering equipment that is typically associated with “smart grid” technology.

The capital spending forecast for generation includes approximately U.S.$120 million for modifications to the Polk Unit 1 gassifier to produce a high value by-product. Spending on this project and any other revenue enhancing projects must be justified by an internal economic analysis that demonstrates a net benefit.

Tampa Electric’s capital spending forecast includes final amounts related to the conversion of the Polk Units 2 - 5 from peaking service to combined cycle with a January 2017 in-service date. Construction commenced in January 2014. The 2016 capital expenditures support the completion of the construction on the power plant and the related transmission system upgrades, start-up testing and precommissioning activities.

New generation and transmission for the 2017 - 2019 period includes approximately U.S.$195 million based on the assumption of a simple cycle peaking unit scheduled to be in-service in early 2020, and continued success in developing additional solar generation projects similar to the 2 MW project at TIA. Tampa Electric recognizes that the proposed Clean Power Plan favors generating resources with lower or no carbon emissions. Tampa Electric may meet the need for additional generating capacity in 2020 with a conventional peaking unit or some combination of conventional generation distributed generation and/or renewable resources such as solar.

Peoples Gas System

PGS operates as the gas division of TEC. PGS is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in the state of Florida.

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Gas is delivered to the PGS system through three interstate pipelines. PGS does not engage in the exploration for or production of natural gas. PGS operates a natural gas distribution system that served approximately 365,000 customers on average for the three months ended March 31, 2016. The system includes approximately 12,100 miles of mains and 6,900 miles of service lines

PGS had 533 employees as of March 31, 2016. A total of 137 employees in five of PGS’s 14 operating divisions and call center are represented by various union organizations.

Operating Revenue

In 2015, the total throughput for PGS was approximately 1.8 billion therms. Of this total throughput, 6% was gas purchased and resold to retail customers by PGS, 85% was third-party supplied gas that was delivered for retail transportation-only customers and 9% was gas sold off-system. Industrial and power generation customers consumed approximately 60% of PGS’s annual therm volume, commercial customers consumed approximately 27%, off-system sales customers consumed 9% and the remaining balance was consumed by residential customers.

While the residential market represents only a small percentage of total therm volume, residential operations comprised about 35% of total revenues.

Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam. PGS has also seen increased interest and development in natural gas vehicles. There are 42 compressed natural gas filling stations connected to the PGS distribution system.

Revenues and therms for PGS for the periods indicated were as follows:

	Revenues						Therms
	Three months ended March 31, 2016		Year ended 2015		Year ended 2014		Three months ended March 31, 2016		Year ended 2015		Year ended 2014
	millions of U.S. dollars						millions of therms
Residential	$	50.5	$	137.0	$	144.1		32.9		74.9		80.8
Commercial		42.8		138.8		139.1		141.1		470.8		460.5
Industrial		3.3		13.0		13.1		83.5		289.0		274.3
Off system sales		12.9		49.8		39.4		53.9		166.4		84.0
Power generation		2.1		7.2		6.8		190.6		758.3		643.5
Other revenues		16.6		50.5		48.5
Total	$	128.2	$	396.3	$	391.0		502.0		1,759.4		1,543.1

No significant part of PGS’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on PGS. PGS’s business is not highly seasonal, but winter peak throughputs are experienced due to colder temperatures.

Distribution System

PGS’s distribution system extends throughout the areas it serves in Florida and consists of approximately 19,000 miles of pipe, including approximately 12,100 miles of mains and 6,900 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.

PGS’s operations are located in 14 operating divisions throughout Florida. While most of the operations and administrative facilities are owned, a small number are leased.

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Regulation

The operations of PGS are regulated by the FPSC separately from the regulation of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC seeks to set rates at a level that provides an opportunity for a utility such as PGS to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.

The basic costs of providing natural gas service, other than the costs of purchased gas and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS’s weighted cost of capital, primarily includes its cost for debt, deferred income taxes at a zero cost rate, and an allowed ROE. Base rates are determined in FPSC revenue requirements proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties.

PGS’s results reflect base rates established in May 2009, when the FPSC approved a base rate increase of U.S.$19.2 million, which became effective on June 18, 2009 and reflects a return on common equity of 10.75%, which is the middle of a range between 9.75% and 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of U.S.$560.8 million.

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the PGA clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers to its customers. These charges may be adjusted monthly based on a cap approved annually in an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a calendar year recovery period, with a true-up adjustment to reflect the variance of actual costs and usage from the projected charges for prior periods. In November 2015, the FPSC approved PGS’s 2016 PGA cap factor for the period January 2016 through December 2016.

In addition to its base rates and PGA clause charges, PGS customers (except interruptible customers) also pay a per-therm charge for energy conservation and pipeline replacement programs. The conservation charge is intended to permit PGS to recover, on a dollar-for-dollar basis, prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are mandated by Florida law and approved and monitored by the FPSC. PGS is also permitted to earn a return, depreciation expenses and applicable taxes associated with the replacement of cast iron/bare steel infrastructure. PGS projects to have all cast iron and bare steel pipe removed from its system within seven years. Lastly, the FPSC requires natural gas utilities to offer transportation-only service to all non-residential customers.

In addition to economic regulation, PGS is subject to the FPSC’s safety jurisdiction, pursuant to which the FPSC regulates the construction, operation and maintenance of PGS’s distribution system. In general, the FPSC has implemented this by adopting the Minimum Federal Safety Standards and reporting requirements for pipeline facilities and transportation of gas prescribed by the U.S. Department of Transportation in Parts 191, 192 and 199, Title 49, of the Code of Federal Regulations.

PGS is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters. See “—Environmental Compliance.”

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Competition

Although PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.

In Florida, gas service is unbundled for all non-residential customers. PGS has a NaturalChoice program, offering unbundled transportation service to all non-residential customers, as well as residential customers consuming in excess of 1,999 therms annually, allowing these customers to purchase commodity gas from a third party but continue to pay PGS for the transportation. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. PGS had approximately 23,300 transportation-only customers as of December 31, 2015 out of approximately 37,600 eligible customers.

Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly by transporting gas through other facilities and thereby bypassing PGS facilities. In response to this competition, PGS has developed various programs, including the provision of transportation-only services at discounted rates.

Gas Supplies

PGS purchases gas from various suppliers depending on the needs of its customers. The gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers.

Gas is delivered by the Florida Gas Transmission Company through 69 interconnections (gate stations) serving PGS’s operating divisions. In addition, PGS’s Jacksonville division receives gas delivered by a pipeline company through two gate stations located northwest of Jacksonville. Another pipeline company provides delivery through six gate stations. PGS also has one interconnection with its affiliate pipeline company in Clay County, Florida.

Companies with firm pipeline capacity receive priority in scheduling deliveries during times when the pipeline is operating at its maximum capacity. PGS presently holds sufficient firm capacity to permit it to meet the gas requirements of its system commodity customers, except during localized emergencies affecting the PGS distribution system and on abnormally cold days.

Firm transportation rights on an interstate pipeline represent a right to use the amount of the capacity reserved for transportation of gas on any given day. PGS pays reservation charges on the full amount of the reserved capacity whether or not it actually uses such capacity on any given day. When the capacity is actually used, PGS pays a volumetrically-based usage charge for the amount of the capacity actually used. The levels of the reservation and usage charges are regulated by the FERC. PGS actively markets any excess capacity available on a day-to-day basis to partially offset costs recovered through the PGA clause.

PGS procures natural gas supplies using base-load and swing-supply contracts with various suppliers along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices or a fixed price for the contract term.

Neither PGS nor any of the interconnected interstate pipelines have storage facilities in Florida. PGS occasionally faces situations when the demands of all of its customers for the delivery of gas cannot be met. In these instances, it is necessary that PGS interrupt or curtail deliveries to its interruptible customers. In general, the largest of PGS’s industrial customers are in the categories that are first curtailed in such situations. PGS’s

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tariff and transportation agreements with these customers give PGS the right to divert these customers’ gas to other higher priority users during the period of curtailment or interruption. PGS pays these customers for such gas at the price they paid their suppliers or at a published index price, and in either case pays the customer for charges incurred for interstate pipeline transportation to the PGS system.

Franchises and Other Rights

PGS holds franchise and other rights with 116 municipalities and districts throughout Florida. These franchises govern the placement of PGS’s facilities on the public rights-of-way as it carries on its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing PGS’s use of public rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement. The franchises are irrevocable and are not subject to amendment without the consent of PGS, although in certain events they are subject to forfeiture.

Municipalities are prohibited from granting any franchise for a term exceeding 30 years. Several franchises contain purchase options with respect to the purchase of PGS’s property located in the franchise area, if the franchise is not renewed; otherwise, based on judicial precedent, PGS is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.

PGS’s franchise agreements have various expiration dates ranging from the present through 2044. PGS expects to negotiate twelve franchises in 2016. Franchise fees expense totaled U.S.$8.8 million in 2015. Franchise fees are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are collected from only those customers within each franchise area.

Utility operations in areas outside of incorporated municipalities and districts are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the county commission of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates, and these rights are, therefore, considered perpetual.

Capital Expenditures

During the year ended December 31, 2015, PGS capital expenditures were approximately U.S.$95 million, including approximately U.S.$30 million for maintenance of the existing system, U.S.$55 million to expand the system and support customer growth, and U.S.$10 million for replacement of cast iron and bare steel pipe. PGS did not incur any material capital expenditures to meet environmental requirements, nor, as of December 31, 2015, were any anticipated for the 2016 through 2020 period.

As at December 31, 2015, capital expenditures for PGS were expected to be about U.S.$105 million in 2016 and U.S.$430 million during the 2017 to 2020 period. Included in these amounts is an average of approximately U.S.$65 million annually for projects associated with customer growth and system expansion. The PGS capital expenditure forecast includes amounts related to constructing pipelines in the Northeast Florida area to support new Liquefied Natural Gas (LNG) terminals for export and fueling vessels that are dependent on project economics. The remainder represents capital expenditures for ongoing renewal, replacement and system safety, including approximately U.S.$12 million annually for the replacement of cast iron and bare steel pipe, which is recovered through a rider clause approved by the FPSC in 2012.

At PGS, higher capital expenditures are focused on extending the system to serve large commercial or industrial customers that are currently using petroleum and propane as fuel under multi-year contracts. The current natural gas prices and the projections that natural gas prices are going to remain low into the future makes it attractive for these customers to convert from fuels that are more expensive on a cost per MMBTU basis. In the current low oil price environment, the economics of converting to natural gas remain attractive for the long term, and natural gas has lower CO₂ emissions than petroleum based fuels that are attractive to users.

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New Mexico Gas Company

On September 2, 2014, TECO Energy completed the acquisition of NMGI contemplated by the acquisition agreement dated May 25, 2013 by and among TECO Energy, NMGI and Continental Energy Systems LLC. As a result of that acquisition, TECO Energy acquired all of the capital stock of NMGI. NMGI, which was incorporated in the state of Delaware in 2008, is the parent company of NMGC. The aggregate purchase price was U.S.$950 million, which included the assumption of U.S.$200 million of senior secured notes of NMGC, plus certain working capital adjustments.

NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in the state of New Mexico. NMGC operates a natural gas distribution system that served approximately 520,000 customers on average for the three months ended March 31, 2016. The system includes approximately 1,600 miles of transmission pipeline, 10,200 miles of mains and 521,400 service lines. NMGC’s system interconnects with five interstate pipelines.

Operating Revenue

For 2015, the total throughput for NMGC was over 775 million therms. Of this total throughput, 52% was gas purchased and resold to retail customers by NMGC, 42% was third-party supplied gas that was delivered for retail transportation-only customers and 6% was gas sold or transported off-system. Industrial and power generation customers consumed approximately 26% of NMGC’s 2015 annual therm volume, commercial customers consumed approximately 30%, off-system transportation customers consumed 6% and the remaining balance was consumed by residential customers, which represents approximately 38% of total annual therm volume and 72% of NMGC’s total annual revenues.

Revenues and therms for NMGC for the three months ended March 31, 2016 and the year ended December 31, 2015 were as follows:

	Revenues				Therms
	Three months ended March 31, 2016		Year ended December 31, 2015		Three months ended March 31, 2016		Year ended December 31, 2015
	millions of U.S. dollars				millions of therms
Residential	$	77.7	$	229.2		122.6		291.2
Commercial		19.8		59.6		42.0		104.4
Industrial		0.2		1.2		0.4		2.5
Off system sales		0.6		0.3		3.9		1.2
On system transportation		6.6		19.1		95.1		328.7
Off system transportation		0.2		0.9		11.1		47.2
Other revenues		1.5		6.2
Total	$	106.6	$	316.5		275.1		775.2

No significant part of NMGC’s business is dependent upon a single or limited number of customers where the loss of any one or more would have a significant adverse effect on NMGC. NMGC’s business is seasonal with much higher volumes and revenues experienced during colder winter months.

Distribution System

NMGC’s distribution system extends throughout the areas it serves in New Mexico and consists of approximately 11,800 miles of pipe, including approximately 1,600 miles of transmission pipeline and 10,200 miles of distribution lines. Mains and service lines are maintained under rights-of-way, franchises or permits.

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NMGC’s operations are located in six operating areas throughout New Mexico. While most of the operations and administrative facilities are owned, a small number are leased.

Regulation

The operations of NMGC are regulated by the NMPRC. The NMPRC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the NMPRC seeks to set rates at a level that provides an opportunity for a utility such as NMGC to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.

The basic costs of providing natural gas service, other than the costs of purchased gas, gas storage services and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate NMGC’s weighted cost of capital, primarily includes its cost for long-term debt and an allowed ROE. Base rates are determined in NMPRC revenue requirements proceedings which occur at irregular intervals at the initiative of NMGC, the NMPRC or other parties.

In March 2011, NMGC filed an application with the NMPRC seeking authority to increase NMGC’s base rates by approximately U.S.$34.5 million on a normalized annual basis. In September 2011, the parties to the base rate proceeding entered into a settlement. The parties filed an unopposed stipulation reflecting the terms of that settlement with the NMPRC and the unopposed stipulation was approved by the NMPRC on January 31, 2012, revising, among other things, base rates for all service provided on or after February 1, 2012. The revised rates contained in the NMPRC-approved settlement increased NMGC’s base rate revenue by approximately U.S.$21.5 million on a normalized annual basis. The monthly residential customer access fee increased from U.S.$9.59 to U.S.$11.50, with the remaining rate increase reflected in changes to volumetric delivery charges. The parties stipulated that the NMPRC-approved revised rates would not increase again prior to July 31, 2013. Subsequently, as a condition of the August 2014 NMPRC order approving the TECO Energy acquisition of NMGC, the rates were frozen at the approved 2012 levels until the end of 2017. In addition, under the order, NMGC provided $2.0 million of pretax credits on customer bills for the first 12-month period post-closing, effective October 1, 2014, and will provide $4.0 million of pretax credits to customers in each subsequent 12-month period until new base rates are effective, as reported in Note 21 to the TECO Energy consolidated financial statements included in its 10-K filing for the fiscal year ended December 31, 2015.

NMGC recovers the costs it pays for gas supply and interstate transportation for system supply through the PGAC. This charge is designed to recover the costs incurred by NMGC for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC estimates its cost of gas for the next month (taking into consideration the expected cost of gas to be purchased for the next month, expected demand and any prior month under-recovery or over-recovery of NMGC’s cost of gas) and sets the GCBF rate to be used in the next month to recover those estimated costs. For any increase or decrease in cost of gas sold, there is a corresponding increase or decrease in revenue collected through the PGAC. NMGC also has regulatory authority to include a simple interest charge or credit based upon the month-end balance of the PGAC under-recovery or over-recovery of NMGC’s cost of gas. NMGC’s annual PGAC period runs from September 1 to August 31. The NMPRC requires that NMGC file a reconciliation of the PGAC period costs and recoveries, annually in December. Additionally, NMGC must file a PGAC Continuation Filing with the NMPRC every four years. The purpose of the PGAC Continuation Filing is to establish that the continued use of the PGAC is reasonable and necessary. In January 2013, the NMPRC approved the PGAC Continuation Filing allowing for continued use of the PGAC for another four years. NMGC plans to file its next PGAC Continuation Filing in June 2016 for the four-year period ending December 2020.

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In addition to its base rates and PGAC, NMGC’s residential customers and customers utilizing NMGC’s small and medium volume general services also pay a per-therm charge for energy conservation. The conservation charge is intended to permit NMGC to recover, on a dollar-for-dollar basis, prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are approved and monitored by the NMPRC. The NMPRC requires natural gas utilities to offer transportation-only service to all customer classes.

In addition to economic regulation, NMGC is subject to the NMPRC’s safety jurisdiction, pursuant to which the NMPRC regulates the construction, operation and maintenance of NMGC’s distribution system. In general, the NMPRC has implemented this by adopting the Minimum Federal Safety Standards and reporting requirements for pipeline facilities and transportation of gas prescribed by the U.S. Department of Transportation in Parts 191, 192 and 199, Title 49, Code of Federal Regulations.

NMGC is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters. See “—Environmental Compliance.”

Competition

Although NMGC is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil. NMGC has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.

Pursuant to New Mexico statutes and NMPRC rules and regulations, NMGC is required to provide transportation-only services for all customer classes. NMGC receives its base rates for distribution gas delivery services regardless of whether a customer decides to opt for transportation-only service or continue on NMGC’s gas commodity sales service. During the year ended December 31, 2015, NMGC had approximately 4,100 transportation-only end-use customers and approximately 512,000 gas commodity sales service customers. Transportation-only throughput represented 48.5% of total system throughput and 6.3% of total revenue for the year ended December 31, 2015.

Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly by transporting gas through other transmission and distribution providers and thereby bypassing NMGC transmission and distribution facilities. In response to this competition, NMGC has developed various programs, including the provision of transportation-only services at discounted rates.

Gas Supplies

NMGC’s service territory is situated between two large natural gas production basins (the San Juan Basin to the northwest of NMGC’s service territory and the Permian Basin to the southeast of NMGC’s service territory). Natural gas is transported from these production basins on major interstate pipelines to NMGC’s intrastate transmission system and then to customers using its distribution system. The San Juan Basin typically supplies 85% of NMGC’s gas supply, with the Permian Basin supplying most of the remaining balance. NMGC also sources gas from the Piceance Basin in western Colorado and the Green River Basin in Wyoming.

NMGC’s transmission and distribution system interconnects with five interstate pipelines owned by various pipeline companies. NMGC has firm pipeline capacity contracts with these pipeline companies. To enhance gas supply and transportation availability, NMGC has an ownership interest in the Blanco Hub, one of the central supply and marketing points in the San Juan Basin. The Blanco Hub interconnects with NMGC’s transmission

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system as well as major nearby gathering systems and interstate pipelines. To provide for system balancing and peak day supply requirements, NMGC contracts for 3.2 billion cubic feet of underground gas storage capacity and gas storage services in an underground facility in west Texas. This storage facility is connected to two major interstate pipelines that, in turn, connect to NMGC’s transmission and distribution system.

Gas is purchased from various suppliers at market pools and processing plant tailgates from marketers and producers. NMGC has negotiated standard terms and conditions for the purchase of natural gas under the NAESB and the Gas Industry Standards Board forms of agreement. NMGC purchases gas for resale to its jurisdictional gas sales customers in accordance with an annual gas supply plan filed with the NMPRC.

Gas price spikes, which can occur in high demand winter months, have the potential to significantly increase customer bills. To provide a degree of price protection, NMGC utilizes a hedging plan for a portion of the winter gas supply. The gas hedging activity is discussed in more detail in TECO Energy’s Consolidated Financial Statements.

Franchises and Other Rights

Many of NMGC’s transmission and distribution facilities are located on lands that require the grant of rights-of-way or franchises from non-tribal governmental entities, Native American tribes and pueblos, or private landowners. In some cases, renewed rights-of-way or franchises must be submitted to the Federal Bureau of Indian Affairs for approval. For the year ended December 31, 2015, NMGC incurred expenditures for rights-of-way or franchise renewals on Native American tribal and pueblo lands that amounted to U.S.$0.3 million.

In 2011, the New Mexico legislature passed legislation confirming the validity and enforceability of agreements with public utilities that provide access to public rights of way, including expired agreements that have continued to be honoured by both the public utility and the local government according to their terms, regardless of the expiration date of the agreements. Accordingly, some of NMGC’s expired rights-of-way or franchises remain in effect by statute, though NMGC expects to enter into negotiations to renew expired rights-of-way or franchises upon request. Based on current renewal experience with rights-of-way and franchises on Native American tribal and pueblo lands, NMGC believes that it is likely those rights-of-way or franchises will be renewed at prices that are significantly higher than historical levels. NMGC does not have condemnation rights on Native American tribal and pueblo lands, and, if it is unsuccessful in renewing some or all of these expiring or expired rights-of-way or franchises, it could be obligated to remove its facilities from, or abandon its facilities on, the property covered by the rights-of-way or franchises and seek alternative locations for its transmission or distribution facilities. With respect to land held by non-tribal governmental entities and privately-held land, however, NMGC may have condemnation rights and, thus, in the case where rights-of-way or franchises cannot be renewed by negotiation, NMGC would likely exercise such rights rather than remove or abandon facilities and find alternative locations for such facilities. Historically, rights-of-way and franchise costs have been recovered in rates charged to customers, and NMGC will continue to seek to recover rights-of-way and franchise costs in future rates charged to customers.

Capital Expenditures

During the year ended December 31, 2015, NMGC capital expenditures of U.S.$50 million included amounts to support customer growth, system reliability, facilities and equipment to safely and reliably operate the system, and investments in computer systems and technology required to successfully integrate NMGC financial and related systems with TECO Energy systems. During the year ended December 31, 2015, NMGC did not incur any material capital expenditures to meet environmental requirements, nor are any anticipated for the 2016 through 2020 period

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As at December 31, 2015, the expected 2016 capital expenditure for NMGC were approximately U.S.$80 million, which included approximately U.S.$30 million annually for ongoing renewal, replacement and system safety and approximately $10 million annually for system expansion to support growth. As at December 31, 2015, the forecast for capital expenditures in 2016 included approximately U.S.$35 million for a transmission pipeline “looping” project to enhance system reliability and capacity for anticipated growth. The forecast beyond 2016 includes approximately U.S.$25 million for software and systems upgrades, which are components of the integration plans with TECO Energy. The NMGC capital spending forecast in 2017 and 2018 include amounts for additional transmission system looping projects to enhance system reliability and capacity. NMGC’s capital expenditure forecasts may increase in future years as marketing, economic development and system expansion plans are further developed in the integration process.

Environmental Compliance

TECO Energy’s businesses have significant environmental considerations. Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act, and material Clean Water Act implications and impacts by federal and state legislative initiatives. TEC, through its Tampa Electric and PGS divisions, is a PRP for certain Superfund sites and, through its PGS division, for certain former manufactured gas plant sites. NMGC has not been designated as a PRP and has no former manufactured gas plant sites.

Air Quality Control

Emission Reductions

Tampa Electric has undertaken major steps to dramatically reduce its air emissions through a series of voluntary actions, including technology selection (e.g., IGCC) and conversion of coal-fired units to natural-gas fired combined cycle; implementation of a responsible fuel mix taking into account price and reliability impacts to its customers; a substantial capital expenditure program to add BACT emissions controls; implementation of additional controls to accomplish early reductions of certain emissions; and enhanced controls and monitoring systems for certain pollutants.

Tampa Electric, through voluntary negotiations in 1999 with the EPA, the U.S. Department of Justice and the FDEP, signed a consent decree and consent final judgment, as settlement of federal and state litigation, to dramatically decrease emissions from its power plants. Tampa Electric has fulfilled the obligations of the consent decree, and the court terminated the consent decree on November 22, 2013. Termination of the consent final judgment was completed on May 6, 2015.

The emission-reduction requirements of these agreements resulted in the repowering of the coal-fired Gannon Power Station to natural gas, which was renamed as the H. L. Culbreath Bayside Power Station (the “Bayside Power Station”), enhanced availability of flue-gas desulfurization systems (scrubbers) at Big Bend Power Station to help reduce SO_2, and installation of SCR systems for NO_x reduction on Big Bend Power Station Units 1 through 4. Cost recovery for the SCRs began for each unit in the year that the unit entered service through the ECRC. Cost recovery for the repowering of the Bayside Power Station was accomplished in Tampa Electric’s 2008 rate case.

Reductions in mercury emissions also have occurred due to the repowering of the Gannon Power Station to the Bayside Power Station. At the Bayside Power Station, where mercury levels have decreased 99% from 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions have been achieved from the installation of the SCRs at Big Bend Power Station, which have led to a system-wide reduction of mercury emissions of more than 90% from 1998 levels.

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CAIR/CSAPR

As a result of its completed emission reduction actions, Tampa Electric has achieved the emission-reduction levels called for in Phase I and Phase II of CAIR. In July 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR on emissions of SO₂ and NO_x. The federal appeals court reinstated CAIR in December 2008 on an interim basis. In July 2011, the EPA issued the final CAIR replacement rule, called the CSAPR. The final CSAPR focused on reducing SO₂ and NO_x in 27 eastern states that contribute to ozone and/or fine particle pollution in other states. Effective January 1, 2015, CSAPR Phase 1 replaced CAIR; Phase 2 of the CSAPR is expected to be implemented in 2017. Compliance with CSAPR, which would be measured at the individual power plant level, would require the addition of scrubbers or SCRs on most coal-fired power plants. In addition, the rule utilized intrastate emissions allowance trading and limited interstate emissions allowance trading to achieve compliance. All of Tampa Electric’s conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Power Station Unit 1 IGCC unit removes SO₂ in the gasification process.

On December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”) granted a motion to stay the implementation of CSAPR in all aspects, which had been scheduled to take effect January 1, 2013, and ordered the reinstatement of CAIR pending the outcome of the litigation. On August 21, 2012, the court vacated CSAPR entirely and remanded it back to the EPA while leaving the CAIR in place. On April 29, 2014, the U.S. Supreme Court issued an opinion reversing the August 21, 2012 D.C. Circuit decision that had vacated CSAPR. Following the remand of the case to the D.C. Circuit, the EPA requested that the court lift the CSAPR stay and toll the CSAPR compliance deadlines by three years. On October 23, 2014, the D.C. Circuit granted the EPA’s request. Effective January 1, 2015, CSAPR Phase 1 replaced CAIR. Phase 2 of the CSAPR is expected to be implemented in 2017.

SO₂ National Ambient Air Quality Standards (“NAAQS”)

On June 2, 2010, the EPA revised the primary SO₂ NAAQS by establishing a new 1-hour standard at a level of 75 parts per billion (ppb). A part of Hillsborough County north of Big Bend Station has a monitor that violates the 2010 SO₂ NAAQS. Although Big Bend Power Station did not contribute to the violation, it has potential effects on the non-attainment area based on air dispersion modeling evaluations and has committed to accept a more stringent SO2 permit limit to ensure the area achieves compliance with the ambient air standards.

The next phase of the SO₂ NAAQS process will address all ambient SO₂ exceedances located outside the designated non-attainment areas. Air dispersion modeling or ambient air monitoring will be used to determine impacts to these areas beginning no earlier than 2018 but no later than 2021. Additional SO₂ emission reductions may be required depending on the outcome of this process.

Hazardous Air Pollutants (“HAPS”) Maximum Achievable Control Technology (“MACT”) Mercury Air Toxics Standards (“MATS”)

The EPA published proposed rules under National Emission Standards for HAPS on May 3, 2011, pursuant to a court order. These rules are expected to reduce mercury, acid gases, organics, and certain non-mercury metals emissions and require MACT. The final Utility MACT rules, now called Mercury Air Toxics Standards (“MATS”), were published in December 2011 with implementation called for in early 2015 with possible extensions to early 2016 or 2017 under certain specific criteria.

On June 29, 2015, the U.S. Supreme Court remanded the EPA’s MATS to the D.C. Circuit for failing to properly consider the cost of compliance. In December 2015, the D.C. Circuit ruled that MATS would remain in effect while the EPA performed further cost benefit analysis, and in March 2016 the U.S. Supreme Court denied a request from 20 states to stay MATS pending the D.C. Circuit’s review. EPA released a revised cost benefit analysis in April 2016.

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All of Tampa Electric’s conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process. Tampa Electric is uniquely positioned to be able to meet the MATS standards without considerable impacts, compared to others who have not taken similar early actions. Therefore, Tampa Electric expects the co-benefits of these control devices for mercury removal to minimize the impact of this rule and expects that it will be in compliance with MATS with nominal additional capital investment.

Carbon Reductions and GHG

Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 1998, Tampa Electric has reduced its system wide emissions of CO₂ by approximately 20%, bringing emissions to near 1990 levels. Tampa Electric expects emissions of CO₂ to remain near 1990 levels until the addition of the next base load unit, which is scheduled to be in service in January 2017. Tampa Electric estimates that the repowering to natural gas and the shut-down of the Gannon Power Station coal-fired units resulted in an annual decrease in CO₂ emissions of approximately 4.8 million tons below 1998 levels. During this same time frame, the numbers of retail customers and retail energy sales have risen by approximately 30% and 15%, respectively.

Tampa Electric’s power plants currently emit approximately 16 million tons of CO₂ per year. Assuming a projected long-term average annual load growth of more than 1.0%, Tampa Electric could emit approximately 16.3 million tons of CO₂ (an increase of approximately 2%) by 2020 if natural gas-fired peaking and combined-cycle generation additions are used to meet customer demand.

In 2010, the EPA issued its Final Rule on the mandatory reporting of GHGs, requiring facilities that emit 25,000 metric tons or more of CO2, or its equivalent, per year to begin collecting GHG data under a new reporting system on January 1, 2010, with the first annual report due September 28, 2011. Tampa Electric complied with the initial mandatory reporting requirement, in large part through the methods and procedures already utilized, and continues to submit annual reports as required. The rule also required natural gas distribution, underground coal mining facilities, and electric transmission and distribution companies, including PGS, and Tampa Electric, that emit 25,000 metric tons or more of CO2, or its equivalent, per year to begin collecting GHG data under a new reporting system on January 1, 2011, with the first annual report due September 28, 2012. Tampa Electric and PGS complied with the reporting requirements and continue to submit annual reports as required.

In December 2009, the EPA published the final Endangerment Finding in the U.S. Federal Register. Although the finding was technically made in the context of GHG emissions from new motor vehicles and did not, in itself, impose any requirements on industry or other entities, the EPA claims that the finding triggered GHG regulation of a variety of sources under the Clean Air Act. Related to utility sources, the EPA’s “tailoring rule,” which addresses the GHG emission threshold triggers that would require permitting review of new and/or major modifications to existing stationary sources of GHG emissions, became effective January 2, 2011. A recent U.S. Supreme Court ruling narrowed the EPA’s authority to implement this rule but the key provisions remain applicable to Tampa Electric. While this rule does not have an immediate impact on Tampa Electric’s ongoing operations, GHG permitting was recently completed for Tampa Electric’s next base load unit, the Polk Power Station Unit 2–5 conversion to combined cycle.

In June 2013, President Obama announced his Climate Action Plan, a broad package of mostly administrative initiatives aimed at reducing GHG emissions by approximately 17% below 2005 levels by 2020. As part of the Climate Action Plan, the President directed the EPA to issue a draft rule for existing power plants by June 1, 2014, to finalize the rule by June 1, 2015, and to require states to submit implementation plans by June 30, 2016. In response to this directive, on June 2, 2014, the EPA released a comprehensive proposed rule to limit GHG emissions from existing power plants. The EPA’s final rule, the Clean Power Plan, was signed by the Administrator of the EPA on August 3, 2015 and sets emission performance goals that will cut GHG emissions from existing power plants by an average across all states of 32% from their 2005 levels by 2030, with an interim

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goal for the period from 2022 through 2029. Under the final rule, each state would have to reduce carbon dioxide emissions on a state-wide basis by an amount specified by the EPA adopting either a rate- or mass-based approach; the target amount was determined by the EPA’s view of each state’s options, including: making power plant efficiency upgrades; shifting from coal-fired to natural gas-fired generation; and investing in zero- and low-emitting power sources, such as renewable and nuclear energy. Under the methodology employed by the EPA , Florida has state-specific rate- and mass-based GHG targets that are in the middle of the range of goals the EPA has set for individual states. Based on the state-specific rate-based goal, generation capacity in Florida has an emission reduction goal equal to a 25% reduction from the 2012 baseline for GHG emission rate of affected electricity generating units. States are intended to have a great deal of flexibility in designing programs to meet their emission reduction targets, including the three approaches noted above or any other measures they choose to adopt, for example, energy efficiency programs. The final rule was published in the U.S. Federal Register on October 23, 2015. Under the rule as published, states had until September 2016 to submit initial plans to achieve their target emission reductions (subject to extension and EPA approval of the states’ plans).

On January 21, 2016, the U.S. Court of Appeals for the D.C. Circuit denied requests by 27 states and numerous trade groups for a stay that would have barred the EPA from implementing the carbon regulations for the electricity sector, but indicated that it would expedite the process for considering the lawsuits and would hear oral arguments June 2, 2016. However, on February 9, 2016, the U.S. Supreme Court issued a stay against enforcement of the Clean Power Plan for the electricity sector pending resolution of the legal challenges before the D.C. Circuit. In a May 16, 2016 order, the D.C. Circuit rescheduled oral argument before the en banc court to September 27, 2016. The timing of the resolution of the legal challenges and the removal of the stay by the U.S. Supreme Court is uncertain, but it is likely to delay further actions by the states until 2018. Prior to the U.S. Supreme Court ruling, Florida had not begun its rulemaking process, and is currently awaiting final resolution of the legal challenges before proceeding with rulemaking. Tampa Electric is evaluating a number of potential compliance scenarios, but until there is consensus in Florida regarding a state plan it will not be possible to develop a final compliance plan. The outcome of this litigation and the rule-making process and its impact on TECO Energy’s businesses is uncertain at this time; however, it could result in increased operating costs, and/or decreased operations at Tampa Electric’s coal-fired plants. Depending on how the state plan is developed and implemented, the Clean Power Plan could cause an increase in costs or rates charged to customers, which could curtail sales. See “Risk Factors – Risk Factors Relating to the Post-Acquisition Business and Operations of Emera and TECO Energy.”

Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO₂ emissions reductions would be reflected in customers’ bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but it is uncertain if the FPSC would grant such recovery. Prior to the conversion of the coal-fired Gannon Station to the natural gas-fired Bayside Power Station in 2003, nearly all of Tampa Electric’s generation was from coal. Upon completion of that conversion, the mix shifted with the increased use of natural gas. Coal is expected to continue to represent an important component in Tampa Electric’s fuel mix due to the baseload units at the Big Bend Power Station and the coal gasification unit, Polk Unit 1. Tampa Electric’s solid-fuel energy generation was 48% of its total system output in 2015, compared to being approximately 96% of its output in 2001.

Water Supply and Quality

The EPA’s final rule under section 316(b) of the Clean Water Act became effective in October 2014. This rule was initially proposed by EPA in response to citizens’ lawsuits over perceived impacts to aquatic life resulting from operation of cooling water systems in the U.S. from either impingement (on intake screens) or entrainment (through condensers). Tampa Electric uses water from Tampa Bay at its Bayside and Big Bend facilities as cooling water. Both plants use mesh screens to reduce the adverse impacts to aquatic organisms, and Big Bend units 3 and 4 use proprietary fine-mesh screens, BACT, to further reduce impacts to aquatic organisms. Neither

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station has historically demonstrated any significant adverse environmental impacts. Polk Power Station is not covered by this rule since it does not operate an intake on Waters of the U.S. Tampa Electric has two ongoing projects (one for Bayside and one for Big Bend) to negotiate scheduling with the regulating authority and to complete the biological, technical, and financial study elements necessary to comply with the rule. These study elements will ultimately be used by the regulating authority to determine the necessity of cooling water system retrofits for Big Bend and Bayside Power Stations. The full impact of the new regulations on Tampa Electric will depend on the outcome of subsequent legal proceedings challenging the rule, the results of the study elements performed as part of the rules’ implementation, and the actual requirements established by state regulatory agencies.

EPA determined that numeric water quality standards are required in Florida to implement the Clean Water Act. On January 26, 2010, EPA published proposed “Water Quality Standards for the State of Florida’s Lakes and Flowing Waters.” There was a long, litigious path in which EPA and FDEP both proposed criteria. Ultimately, the courts upheld the ruling that the Florida regulations meet the requirements of the Clean Water Act. Both Big Bend and Bayside Power Stations already have allocations allotted by the Nitrogen Management Consortium of the Tampa Bay Estuary Program for total nitrogen, which is the limiting nutrient for Tampa Bay. Other criteria related to streams may still directly affect Polk Power Station’s cooling reservoir discharge to surface water, and may require the station to reduce the amount of nutrients in the cooling reservoir water before discharge.

After the completion of a study into wastewater discharges by the electric utility industry in 2009, the EPA announced its intent to revise the existing steam electric effluent limit guidelines (“ELGs”) that place technology-based limits on wastewater discharges. The final EPA rule was published in the U.S. Federal Register November 3, 2015 and became effective January 4, 2016. The ELGs establish limits for wastewater discharges from flue gas desulfurization (“FGD”) processes, fly ash and bottom ash transport water, leachate from ponds and landfills containing coal combustion residuals (“CCRs”), gasification processes, and flue gas mercury controls. For FGD wastewater, the rule imposed limits for arsenic, mercury, selenium, and nitrate/nitrite which will require the addition of biological treatment at Big Bend Station. Both fly ash and bottom ash transport water have been designated as zero discharge wastewaters, with the exception of use as make-up water in FGD scrubbers. Transport water used as make-up will be subject to FGD wastewater limits at the point of discharge. New limits for gasification processes will likely require additional treatment at Polk Power Station. Cost estimates are being developed based on an evaluation of treatment technologies required to meet the pollutant limits. The new guidelines are expected to be incorporated into NPDES permit renewals to achieve compliance as soon as possible after November 1, 2018, but no later than December 31, 2023.

EPA Waters of the U.S.

In June 2015, the U.S. Army Corps of Engineers and the EPA issued a rule defining “Waters of the United States” (“WOTUS”) for purposes of federal Clean Water Act jurisdiction. The final rule took effect on August 28, 2015. The rule has the effect of defining the scope of agency jurisdiction under the Clean Water Act very broadly. In August 2015, a federal judge in North Dakota issued an injunction against the implementation of the rule in certain states. In October 2015, the Sixth Circuit Court of Appeals issued a nationwide stay of WOTUS, effectively ending the implementation of the rule in the 37 states that were not subject to the prior injunction. This stay is temporary, pending determination of the court’s jurisdiction over the various challenges to the final rule.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a PRP for certain Superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of March 31, 2016, TEC has estimated its ultimate financial liability to be U.S.$33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other” on the consolidated condensed balance sheets included in TECO Energy’s 10-K filing for the fiscal year ended December 31, 2015. The environmental

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remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s allocated actual percentage share of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

Coal Combustion Residuals Recycling and Disposal

EPA’s final CCR rule became effective on October 19, 2015, and regulates CCRs as non-hazardous solid waste. The rule explicitly allows for encapsulated beneficial uses of CCRs in commercial and industrial products. However, non-encapsulated uses in agricultural and construction applications are allowable only if they meet new environmental criteria.

The rule contains design and operating standards for CCR management units. Tampa Electric is currently evaluating various options for demonstrating compliance with the rule. Potential capital expenditures that are required to achieve compliance with this rule are not expected to be significant. On February 2, 2016, the FPSC approved Tampa Electric’s proposed CCR compliance program for cost recovery through the ECRC. The CCR rule has been challenged by both utility and environmental groups. Legislation has also been proposed in Congress to amend certain provisions of the CCR rule. Pending the outcome of the litigation and/or legislative amendment, the ultimate impacts of the CCR rule on Tampa Electric are uncertain at this time; however, it could curtail Tampa Electric’s ability to market CCRs for beneficial reuse. See “Risk Factors—Risk Factors Relating to the Post-Acquisition Business and Operations of Emera and TECO Energy—Regulations on the disposal and/or storage of CCRs could add to Tampa Electric’s operating costs.”

Solar Initiatives

In 2015, Tampa Electric announced plans for a 23-MW utility-scale solar photo voltaic project to be installed at Tampa Electric’s Big Bend Station. This is the largest solar project in the Tampa Bay area, consisting of more than 70,000 solar panels on 125 acres of land owned by Tampa Electric. Upon completion, it will have the capacity to power more than 3,500 homes. In 2015, Tampa Electric completed the construction of a 2-MW solar photo voltaic energy installation at Tampa International Airport (“TIA”), which is Tampa Electric’s first large-scale solar facility. At 2 MW, the solar panels at TIA produce enough electricity to power up to 250 homes. Tampa Electric owns the solar photo voltaic array, and the electricity it produces goes to the grid to benefit all Tampa Electric customers, including the airport. Tampa Electric anticipates developing additional similarly sized small-scale solar photo voltaic installations and we seek opportunities for additional utility-scale installations.

In addition, Tampa Electric has installed 2,135 KW of solar panels to generate electricity from the sun at eight community sites including two schools, Tampa Electric’s Manatee Viewing Center, the Museum of Science and Industry, Tampa’s Lowry Park Zoo, the Florida Aquarium, and LEGOLAND Florida.

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In Florida, a constitutional amendment was proposed that would allow the sale of up to 2 MW of power direct to other customers from rooftop solar panels, potentially bypassing the utility. The Florida Supreme Court ruled that the amendment meets constitutional and statutory requirements to appear on the ballot, however supporters were unable to gather and certify the required number of signatures by the deadline to have it placed on the ballot in 2016. Supporters indicate that they plan to try to have the amendment on the ballot in 2018. Legislation has been proposed for consideration in the 2016 Florida legislative session that essentially mirrors the intent of the constitutional amendment.

A second Florida constitutional amendment regarding solar power generation is proposed for the 2016 ballot that would establish a right for consumers to own or lease solar equipment installed on their property to generate electricity for their own use. State and local governments would retain the ability to protect consumer rights and public health and safety and ensure that consumers that do not choose to install solar are not required to subsidize the costs of backup power and electric grid access for those that do. The Florida Supreme Court ruled that the amendment meets constitutional and statutory requirements to appear on the ballot. Backers of the proposed amendment have gathered and certified the required number of signatures to have it on the 2016 ballot.

Distributed Generation

In many areas of the country there is growing use of rooftop solar panels, small wind turbines and other small-scale methods of power generation, called distributed generation, by individual residential, commercial and industrial customers. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. To date, there has not been a significant amount of distributed generation added to utility systems in Florida. Florida does not have a renewable portfolio standard, and Florida legislation and regulation have minimized social programs and costs in utility rates. However, proposed action by the Florida legislature in 2016 and a potential amendment to the Florida constitution that supporters are seeking to have placed on the ballot in 2018 would encourage the installation of solar arrays to generate electricity by retail customers and third parties, and allow limited sales of electricity by non-utility generators.

Additionally, the EPA’s Clean Power Plan rule, if enacted consistent with the rule published in August 2015, could have the effect of providing greater incentives for distributed generation in order to meet state-based emission reduction targets. Depending on how the rule is implemented, it could have the effect of increasing TECO Energy’s costs or the rates charged to TECO Energy’s customers, which could curtail sales.

Increased usage of distributed generation, particularly in those states where solar or wind resources are the most abundant, is reducing utility electricity sales, but not reducing the need for ongoing investment in infrastructure to maintain or expand the transmission and distribution grid to reliably serve customers. Due to the intermittent availability of renewable resources, utilities must invest in adequate generating resources to meet customer demand at the times that renewable resources are not available. Energy storage technologies, such as batteries, are not yet commercially available to fill this demand. Continued utility investment not supported by increased future energy sales causes rates to increase for customers, which could further reduce energy sales and reduce profitability.

Conservation

Energy conservation is becoming more important in the GHG emissions reduction debate. Tampa Electric supports the FPSC and its efforts to encourage energy efficiency. In 2015, Tampa Electric continued to offer its customers a comprehensive array of residential and commercial programs that enabled the company to meet its required Demand Side Management (DSM) goals, reduce weather-sensitive peak demand and conserve energy. This strategy continues to allow Tampa Electric to delay construction of future generation facilities. Since their inception, the company’s conservation programs have reduced the summer peak demand by 348 MW and the winter peak demand by 740 MW.

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In November 2014, the FPSC established new DSM goals for the 10-year period from 2015 to 2024 for all Florida investor-owned electric utilities. In November 2015, Tampa Electric transitioned into the new 2015-2024 DSM plan by discontinuing nine existing DSM programs; creating one new DSM program; modifying twenty-eight existing DSM programs; and retiring the renewable energy systems initiative. This transition supports the approved FPSC goals which are reasonable, beneficial and cost-effective to all customers as required by the Florida Energy Efficiency & Conservation Act. For Tampa Electric, the summer and winter demand goals are 56.9 and 87.4 MWs, respectively, and the energy goal is 144.3 gigawatt-hours over the 10-year period. Establishing these DSM goals for the 10-year period is required every five years. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause on the customer’s bill. In addition, PGS offers conservation programs that enable customers to reduce their energy consumption, with those costs recovered through a clause on the customer’s gas bill.

Legal Proceedings

Emera

To the knowledge of Emera, there are no legal proceedings that individually or together could potentially involve claims against Emera or its subsidiaries for damages totaling 10% or more of the current assets of Emera, exclusive of interest and costs.

TECO Energy

From time to time, TECO Energy and its subsidiaries are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. TECO Energy believes the claims in which it or its subsidiary is a defendant in each of the pending actions described below are without merit and intends to defend each matter vigorously. TECO Energy is unable at this time to estimate the possible loss or range of loss with respect to these utilities. While the outcome of such proceedings is uncertain, management of TECO Energy does not believe that their ultimate resolution will have a material adverse effect on its results of operations, financial condition, or cash flows. Certain of such legal proceedings of TECO Energy and its subsidiaries are described below.

PGS Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida. PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in October 2016.

NMGC Legal Proceedings

In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).

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In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all similarly situated New Mexico private businesses and enterprises.

In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to NMGC’s financial position as of March 31, 2016.

In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary judgement in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgement, which is pending.

Proceedings in Connection with the Acquisition

Twelve securities class action lawsuits were filed against TECO Energy and its directors by holders of TECO Energy securities following the announcement of the Acquisition. Eleven suits were filed in the Circuit Court for the 13^th Judicial Circuit, in and for Hillsborough County, Florida. They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Acquisition Agreement and sought to enjoin the Acquisition. In addition, several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order. Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose. The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

TECO Energy also received two separate shareholder demand letters from purported shareholders of its stock. Both of these letters demanded that TECO Energy maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices. One of the letters also demanded that TECO Energy refrain from consummating the transaction with Emera. Both of these demand letters have subsequently been withdrawn.

In November 2015, the parties to the lawsuits entered into a memorandum of understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Acquisition. As a result of the memorandum of understanding, TECO Energy made additional disclosures related to the proposed Acquisition in a proxy supplement. Per the terms of the memorandum of understanding, the parties will negotiate a settlement agreement and submit it to the court for approval after the Acquisition is complete. There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.

Claim in connection with the Sale of TECO Coal

As discussed in Note 15 to TECO Energy’s financial statements included in its 10-Q for the three months ended March 31, 2016, which are incorporated by reference herein, TECO Coal was sold on September 21, 2015 to Cambrian. On March 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified asserting

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breach of certain representations, and fraud and willful misconduct in connection therewith, of the TECO Coal SPA.

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

On December 19, 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of TECO Guatemala Holdings, LLC (“TGH”), a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the Dominican Republic Central America—United States Free Trade Agreement, issued an award in the case (the “Award”). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S.$21.1 million, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S.$7.5 million of the costs that it incurred in pursuing the arbitration.

On April 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.

Also on April 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages.

On April 5, 2016, an ICSID ad hoc Committee issued a decision in favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala’s application for annulment of the award and upheld the original U.S.$21.1 million award, plus interest. In addition, the ad hoc Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to pay certain costs relating to the annulment proceedings. Because the ICSID Tribunal’s award of costs to TGH in its original arbitration was based on the ICSID Tribunal’s assessment that TGH had prevailed on liability and Guatemala had partially prevailed on damages, and the latter finding was annulled by the ad hoc Committee, the Committee also annulled the ICSID Tribunal’s award of costs to TGH. As a result, TGH has the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded U.S.$21.1 million), as well as additional interest on the U.S.$21.1 million, and its full costs relating to the original arbitration and the new arbitration proceeding. Results to date do not reflect any benefit of this decision.

PGS Compliance Matter

In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed. As a result of this report, the Office of Public Counsel filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On February 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to U.S.$3.9 million. On April 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain Superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of March 31, 2016, TEC has estimated its

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ultimate financial liability to be U.S.$33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on TEC’s consolidated condensed balance sheets as of December 31, 2015. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s allocated percentage share of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

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MANAGEMENT

Directors

The following information is provided for each Director of Emera as of the date hereof:

Name and Residence	Principal Occupations During the Past Five Years and Other Information	Director Since(1)
Sylvia D. Chrominska(7) Toronto, Ontario Canada	Former Group Head of Global Human Resources and Communications for the Bank of Nova Scotia, where she had global responsibility for human resources, corporate communications, government relations, public policy and corporate social responsibility of the Scotiabank Group. Former Chair of the Board of Scotia Group Jamaica Limited and Former Chair of the Board of Scotiabank Trinidad and Tobago Limited. A director of Wajax Corporation.	2010
Henry E. Demone(4) Lunenburg, Nova Scotia Canada	Chairman of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May 2015. A director of Saputo Inc.	2014
Allan L. Edgeworth(4) Calgary, Alberta Canada	Former President of ALE Energy Inc., a private consulting company. Former President and Chief Executive Officer of Alliance Pipeline. Director of AltaGas Ltd.	2005
James D. Eisenhauer Lunenburg, Nova Scotia Canada	President and Chief Executive Officer of ABCO Group Limited, which has holdings in manufacturing and distribution activities. Former Chair of the NSPI Board of Directors and director of NSPI since 2008.	2011
Christopher G. Huskilson Wellington, Nova Scotia Canada	President and Chief Executive Officer of Emera since November 2004. Director and former Chair of Emera Maine, Director of NSPI, Director of APUC and Chair or Director of a number of other Emera affiliated companies. Since June 1980, Mr. Huskilson has held a number of positions within NSPI and its predecessor, Nova Scotia Power Corporation.	2004
J. Wayne Leonard(2) New Orleans, Louisiana U.S.	Former Chairman and Chief Executive Officer of Entergy Corporation, an integrated electricity producer and retail distributor. Mr. Leonard joined Entergy Corporation as President and Chief Operating Officer in 1998, becoming CEO in 1999. Mr. Leonard serves on the Boards of the Edison Electric Institute and Tidewater, Inc. He has also served on the Board of the Centre for Climate and Energy Solutions.	2014
B. Lynn Loewen, FCPA, FCA(2) Westmount, Quebec Canada	President of Minogue Medical Inc. a healthcare organization which delivers innovative medical technologies to hospitals and clinics. President of Expertech Network Installation Inc. from 2008 to 2011.	2013

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Name and Residence	Principal Occupations During the Past Five Years and Other Information	Director Since(1)
John T. McLennan(3) Mahone Bay, Nova Scotia Canada	Former Chair of the Board from May 2009 to May 2014. Former Board member of Chorus Aviation Inc. from January 2006 to May 2014. Former Chair of the Board of NSPI from May 2006 to May 2009. Former Vice-Chair and Chief Executive Officer of Allstream Inc. (formerly AT&T Canada). He is presently a Director of Amdocs Ltd.	2005
Donald A. Pether(2)(5) Dundas, Ontario Canada	Former Chair of the Board and Chief Executive Officer of ArcelorMittal Dofasco Inc., a Canadian steel producer. Director of Samuel, Son & Co. Ltd. and Schlegel Health Care Inc.	2008
Andrea S. Rosen(6) Toronto, Ontario Canada	Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Director of Alberta Investment Management Corporation and Manulife Financial Corporation.	2007
Richard P. Sergel(3)(4) Wellesley, Massachusetts U.S.	Former President and Chief Executive Officer of the North American Electric Reliability Corporation. Former President and Chief Executive Officer of National Grid USA from 2000 to 2004. Also former President and Chief Executive Officer of the New England Electric System. Presently a director of State Street Corporation. Has also served on the boards of the Edison Electric Institute and the Consortium for Energy Efficiency.	2010
M. Jacqueline Sheppard(8) Calgary, Alberta Canada	Chair of the Board since May 2014. Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Former Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown Corporation. Founder and Lead Director of Black Swan Energy Inc., an Alberta upstream energy company that is private equity financed. Founder and former Director of Marsa Energy Inc., an oil and gas corporation. Director of Cairn Energy PLC, a publicly traded UK based international oil and gas producer. Director of the general partner of Pacific NorthWest LNG LP, which was formed for the purpose of constructing, owning and operating an LNG facility in British Columbia. Director of Seven Generations Energy Ltd.	2009

(1) Denotes the year the individual became a Director of Emera. Directors are elected for a one year term which expires at the termination of Emera’s annual general meeting.

(2) Denotes member of the Audit Committee.

(3) Denotes member of the Nominating and Corporate Governance Committee.

(4) Denotes member of the Management Resources and Compensation Committee.

(5) Denotes Chair of the Nominating and Corporate Governance Committee.

(6) Denotes Chair of the Audit Committee.

(7) Denotes Chair of the Management Resources and Compensation Committee.

(8) Denotes Chair of the Board.

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As of December 31, 2015, the Directors, in total, beneficially owned or controlled, directly or indirectly, approximately 43,439 common shares or less than 1% of the issued and outstanding shares of Emera.

There are no material conflicts of interest between Emera or any of its subsidiaries and any director or officer of Emera or any of its subsidiaries.

Officers

The Officers of Emera as of the date hereof are as follows:

Christopher G. Huskilson President and Chief Executive Officer Wellington, Nova Scotia Canada	President and Chief Executive Officer since November 1, 2004. From July 2003 to November 2004, Chief Operating Officer of Emera. Concurrently held the office of Chief Operating Officer of NSPI until January 2004. Prior to 2003, actively engaged for more than five years in the affairs of NSPI in various managerial and executive capacities.
Greg Blunden Chief Financial Officer Halifax, Nova Scotia Canada	Chief Financial Officer of Emera since March 2016. Prior to that, Vice-President, Corporate Strategy & Planning of Emera.
Scott C. Balfour Chief Operating Officer, Northeast and Caribbean Halifax, Nova Scotia Canada	Chief Operating Officer, Northeast & Caribbean since March 2016. Prior to that, Executive Vice President and Chief Financial Officer of Emera, appointed in April 2012. From September 2005 to January 2011, President and Chief Financial Officer of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company.
Nancy G. Tower, FCPA, FCA Chief Corporate Development Officer Halifax, Nova Scotia Canada	Chief Corporate Development Officer since May 2015. Before that, Executive Vice President Business Development from May 2011 to May 2015. From May 2011 to March 2014 CEO of Emera Newfoundland and Labrador. From November 2005 to May 2011, Executive Vice President and Chief Financial Officer. Prior to 2005, Vice-President Customer Operations for NSPI. From 1997 to 2000, Controller for NSPI.
R. Michael Roberts Chief Human Resources Officer Halifax, Nova Scotia Canada	Chief Human Resources Officer since December 1, 2014. Previously, President, Optimum Talent Atlantic of Halifax. Prior to that, Vice President, Corporate Development at Irving Shipbuilding and Vice President, Human Resources at Bell Aliant.
Bruce A. Marchand Chief Compliance Officer and Chief Legal Officer Halifax, Nova Scotia Canada	Chief Compliance Officer since December 1, 2014. Chief Legal Officer since January 2012. Prior to January 2012, Senior Partner at the law firm of McInnes Cooper.
Daniel P. Muldoon Executive Vice-President Major Renewables and Alternative Energy Halifax, Nova Scotia Canada	Executive Vice-President, Major Renewables and Alternative Energy since May 1, 2014. From June 16, 2011 to March 31, 2013, President and Chief Operating Officer, Emera Utility Services Inc. Prior to that, General Manager Engineering & Construction, Emera.

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Wayne O’Connor Vice President, Corporate Strategy and Planning Halifax, Nova Scotia Canada	Vice President, Corporate Strategy & Planning for Emera since March 2016. Prior to that, Executive Vice President, Operations of NSPL.
Stephen D. Aftanas Corporate Secretary Halifax, Nova Scotia Canada	Corporate Secretary since September 2008. From June 2007 to September 2008, Associate Corporate Secretary. From March 2006 to June 2007, Associate General Counsel, NSPI. Prior to March 2006, Senior Solicitor, Emera.

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THE ACQUISITION AGREEMENT

The Acquisition Agreement contains customary representations, warranties and covenants of TECO Energy, Emera and Merger Sub. The Acquisition Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the execution of the Acquisition Agreement and the closing of the Acquisition and (ii) TECO Energy will not engage in certain transactions during such interim period. The Acquisition Agreement contains covenants by Emera, among others, that Emera will use its reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals.

In addition, the Acquisition Agreement requires Emera (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Acquisition, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide non-public information to, and engage in discussion with, third parties.

Either party may terminate the Acquisition Agreement if (i) the closing of the Acquisition has not occurred by September 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals) or (ii) a law or judgment preventing or prohibiting the closing of the Acquisition has become final. If the Acquisition Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of US$326.9 million.

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DESCRIPTION OF OTHER INDEBTEDNESS

Acquisition Capital Markets Transactions

In connection with financing the Acquisition, in addition to the offering by Emera of any series of Notes pursuant to one or more Prospectus Supplements, Emera U.S. Finance intends to issue Senior Guaranteed Notes. In addition, Emera intends to issue one or more series of Canadian dollar-denominated unsecured senior notes, and may also issue Canadian dollar-denominated unsecured subordinated notes, in each case, on a basis which is exempt from the prospectus requirements of applicable Canadian securities laws. Emera intends to raise up to approximately Cdn$6.6 billion in aggregate principal amount in the Acquisition Capital Markets Transactions. The aggregate principal amounts raised in the Acquisition Capital Markets Transactions are dependent on market and other conditions and may vary. Nothing contained herein shall be deemed to constitute an offer to sell or a solicitation of an offer to buy any of the securities to be issued in the Acquisition Capital Markets Transactions other than any Notes offered hereunder.

Proposed Emera U.S. Finance Senior Guaranteed Notes

As part of the Acquisition Capital Markets Transactions, Emera U.S. Finance intends to issue the Senior Guaranteed Notes. Emera U.S. Finance’s business activities will consist solely of providing funds (directly or indirectly) to EUSHI and a wholly-owned subsidiary of Emera. The Senior Guaranteed Notes will be fully and unconditionally guaranteed (the “guarantees”) by Emera and EUSHI (together, the “Guarantors”).

The Senior Guaranteed Notes and the guarantees will be the senior unsecured indebtedness of Emera U.S. Finance and the Guarantors, respectively, ranking equally in right of payment with all existing and future unsubordinated, unsecured indebtedness of each of Emera U.S. Finance and the Guarantors, and senior in right of payment to all existing and future subordinated indebtedness of each of Emera U.S. Finance and the Guarantors including the Notes. The Senior Guaranteed Notes and the guarantees will be effectively junior in right of payment to all existing and future secured indebtedness (to the extent of the value of the assets securing such debt) of each of Emera U.S. Finance and the Guarantors. The indenture under which the Senior Guaranteed Notes will be issued (the “Senior Guaranteed Note Indenture”) contains no restrictions on the amount of additional unsecured indebtedness Emera U.S. Finance or either of the Guarantors may incur or the amount of indebtedness (whether secured or unsecured) that their respective subsidiaries may incur. The Senior Guaranteed Note Indenture permits Emera U.S. Finance and the Guarantors to incur secured debt subject to certain covenants.

If Emera does not consummate the Acquisition on or prior to the later of: (i) December 31, 2016; and (ii) the date that is no later than June 30, 2017 if the close of the Acquisition has been extended by Emera or TECO Energy in accordance with the terms of the Acquisition Agreement (the “Special Mandatory Redemption Triggering Date”) or the Acquisition Agreement is terminated at any time prior to the Special Mandatory Redemption Triggering Date, then Emera U.S. Finance will be required to redeem each of the outstanding series of Senior Guaranteed Notes on the Special Mandatory Redemption Date at a redemption price equal to 101% of the aggregate principal amount of the Senior Guaranteed Notes, plus accrued and unpaid interest, if any, up to, but excluding, the Special Mandatory Redemption Date.

Proposed Senior Notes

As part of the Acquisition Capital Markets Transactions, Emera intends to issue one or more series of Senior Notes in Canada on a basis which is exempt from the prospectus requirements of applicable Canadian securities laws.

The Senior Notes would be senior unsecured indebtedness of Emera, ranking equally in right of payment with all existing and future unsubordinated, unsecured indebtedness of Emera, and senior in right of payment to all existing and future subordinated indebtedness of Emera. The Senior Notes will be effectively junior in right of payment to all existing and future secured indebtedness (to the extent of the value of the assets securing such debt) of Emera. The indenture under which the Senior Notes would be issued (the “Senior Note Indenture”) will

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contain no restrictions on the amount of additional unsecured indebtedness Emera may incur or the amount of indebtedness (whether secured or unsecured) that its subsidiaries may incur. The Senior Note Indenture would permit Emera to incur secured debt subject to certain covenants.

Proposed Canadian Dollar Subordinated Notes

As part of the Acquisition Capital Markets Transactions, Emera may issue Canadian Dollar Subordinated Notes having similar material attributes and characteristics to any Notes offered hereunder in Canada on a basis which is exempt from the prospectus requirements of applicable Canadian securities laws.

Convertible Debenture Offering

To finance a portion of the Acquisition, on September 28, 2015, Emera, through the Selling Debentureholder, completed the sale of $1.9 billion aggregate principal amount of Convertible Debentures, represented by instalment receipts. On October 2, 2015, in connection with the Convertible Debenture Offering, the underwriters fully exercised an overallotment option and purchased an additional $285 million aggregate principal amount of Convertible Debentures at the Convertible Debenture Offering price.

The Convertible Debentures were sold on an instalment basis at a price of $1,000 per Convertible Debenture, of which $333 was paid on closing of the Convertible Debenture Offering or exercise of over-allotment option, as applicable, with the Final Instalment being payable on the Final Instalment Date.

Prior to the Final Instalment Date, the Convertible Debentures are represented by instalment receipts. The instalment receipts began trading on the TSX on September 28, 2015 under the symbol “EMA.IR.” The Convertible Debentures are not listed. The Convertible Debentures will mature on September 29, 2025 and bear interest at an annual rate of 4.00% per $1,000 principal amount of Convertible Debentures until and including the Final Instalment Date, after which the interest rate will be 0.00%. Based on the first instalment of $333 per $1,000 principal amount of Convertible Debentures, the effective annual yield to and including the Final Instalment Date is 12%, and the effective annual yield thereafter is 0.00%.

If the Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Convertible Debenture Offering, holders of Convertible Debentures who have paid the Final Instalment on or before the Final Instalment Date will be entitled to receive, on the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, the Convertible Debenture Make-Whole Payment.

No Convertible Debenture Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary of the closing of the Convertible Debenture Offering. Under the terms of the instalment receipt agreement, Emera agreed that until such time as the Convertible Debentures have been redeemed in accordance with the foregoing or the Final Instalment Date has occurred, the Company will at all times hold (on

a consolidated basis) short-term U.S. dollar investment grade securities or have cash on hand (including the net proceeds of the first instalment of the Convertible Debenture Offering) of not less than the aggregate amount of the first instalment paid on the closing of the Convertible Debenture Offering and the exercise of the over-allotment option, in the event of a mandatory redemption.

At the option of the holders and provided that payment of the Final Instalment has been made, each Convertible Debenture will be convertible into common shares of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $41.85 per common share. This is a conversion rate of 23.8949 common shares per $1,000 principal amount of Convertible Debentures, subject to adjustment in certain events.

Prior to the Final Instalment Date, the Convertible Debentures may not be redeemed by the Company, except that Convertible Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions precedent to the closing

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of the Acquisition will not be satisfied; (ii) termination of the Acquisition Agreement; and (iii) April 24, 2017, if notice of the Final Instalment Date has not been given to holders on or before April 21, 2017. Upon any such redemption, the Company will pay for each Convertible Debenture: (i) $333 plus accrued and unpaid interest to the holder of the instalment receipt; and (ii) $667 to the Selling Debentureholder on behalf of the holder of the instalment receipt in satisfaction of the Final Instalment. In addition, after the Final Instalment Date, any Convertible Debentures not converted may be redeemed by Emera at a price equal to their principal amount plus any unpaid interest which accrued prior to and including the Final Instalment Date. These costs will include a non-cash accounting charge for the difference between Emera’s closing share price on the issuance date of the Convertible Debentures and their exercise price. This will be recognized once the contingencies surrounding regulatory and other approvals are resolved.

At maturity, Emera will repay the principal amount of any Convertible Debentures not converted and remaining outstanding in cash. Emera has the right to satisfy the obligation to repay the principal amount due in common shares, which will be valued at 95% of the weighted-average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

The proceeds of the first instalment of the Convertible Debenture Offering are held and invested in short-term U.S. dollar investment grade securities. The net proceeds of the Final Instalment will be used, together with the net proceeds of the first instalment, to finance, directly or indirectly, the Acquisition and the Acquisition-Related Expenses. To mitigate the foreign currency translation risk associated with the Final Instalment, Emera entered into USD-denominated forward contracts, which are recorded on the consolidated balance sheets. The mark-to-market effect on these hedges is reported in the income statement and affects income, but is not reflected in adjusted net income.

Acquisition Credit Facilities

For purposes of financing the cash purchase price of the Acquisition, on September 4, 2015, Emera obtained commitment letters from JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Securities LLC, and Scotiabank, an affiliate of Scotia Capital (USA) Inc., respectively, providing for non-revolving syndicated term credit facilities in favour of Emera in an aggregate amount of U.S.$6.5 billion (the “Acquisition Credit Facilities”). The Acquisition Credit Facilities consist of (i) a U.S.$4.3 billion bridge facility repayable in full on the first anniversary following its advance and (ii) a U.S.$2.2 billion bridge facility repayable in full on the first anniversary following its advance.

Emera is required to effect reductions or make prepayments of the Acquisition Credit Facilities in an amount equal to the net cash proceeds from any common equity, preferred equity, bond or other debt offerings and any non-ordinary course asset sales by Emera and its subsidiaries, subject to certain prescribed exceptions and certain other prescribed transactions. Net proceeds from any such offerings, including the net proceeds of the Final Instalment under the Convertible Debentures and any offering of Notes and the other Acquisition Capital Markets Transactions, or from any such non-ordinary course asset sales or transactions, including Emera’s sale of a portion of its ownership interest in APUC, will be applied to permanently reduce the commitments of the lenders under the Acquisition Credit Facilities or to repay the Acquisition Credit Facilities after they are drawn.

The credit agreements pursuant to which the Acquisition Credit Facilities will be extended (the “Acquisition Credit Agreements”) will contain certain prepayment options in favour of Emera and certain prepayment obligations upon the occurrence of certain events. In particular, the net proceeds of any equity or debt offering by Emera and certain of its subsidiaries (other than certain permitted equity or debt offerings subject to certain prescribed exceptions) and of any non-ordinary course asset sales (subject to certain prescribed exceptions) and certain other prescribed transactions will be required to be used to prepay the Acquisition Credit Facilities and any prepayment under the Acquisition Credit Facilities may not be re-borrowed. The Acquisition Credit Agreements will contain customary representations and warranties and affirmative and negative covenants of Emera that will closely resemble those in the Revolving Facility as the same may be amended to reflect the

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Acquisition. As part of these covenants, Emera will generally be required to maintain a consolidated debt to consolidated capitalization ratio of not more than 0.70:1.00. However, subject to prescribed circumstances Emera is permitted to maintain a consolidated debt to consolidated capitalization ratio of not more than 0.75:1.00. Any calculation of the consolidated debt to consolidated capitalization ratio on the date of the Acquisition shall be calculated on a pro forma basis after given effect to the Acquisition and related financings.

Customary fees are payable by Emera in respect of the Acquisition Credit Facilities and amounts outstanding under the Acquisition Credit Facilities will bear interest at market rates.

Revolving Facility

On May 30, 2016, Emera and two of its U.S. subsidiaries, as co-borrowers (together with any additional subsidiaries designated as co-borrowers from time to time, the “Revolver Borrowers”), entered into an amended and restated unsecured revolving credit facility (the “Revolving Facility”) with The Bank of Nova Scotia, as administrative agent, and certain financial institutions, as lenders, under which the Revolver Borrowers may borrow up to $700 million or the equivalent amount in U.S. dollars, with a $50 million sublimit for a swingline facility available only for Canadian borrowers. The Revolving Facility includes a $200 million accordion option. Amounts borrowed may be repaid and re-borrowed until the maturity date (i.e., June 30, 2020), which can be extended for a further period of not more than 3 years, subject to satisfaction of certain conditions. The Revolving Facility includes representations, covenants, and events of default customary for financing transactions of this type, including a consolidated debt to consolidated capitalization maintenance ratio covenant of not more than 0.70:1.00 (which can be increased to 0.75:1.00 in prescribed circumstances). Borrowings under the Revolving Facility can be made in Canadian dollars (available to Canadian borrowers only) or U.S. dollars (available to all Revolver Borrowers). If a borrowing is made under the Revolving Facility, the interest rate will vary depending on the type of drawdown requested. If the loan is Base Rate advance (or, in the case of Canadian dollar loans, a Prime Rate advance), interest will be based on the relevant Base Rate or Prime Rate plus the applicable margin, which ranges between 0% and 0.70% (depending on Emera’s long term debt rating from time to time). Interest on U.S. dollar loans that are LIBOR advances will be based on the LIBO Rate plus the applicable margin, which ranges between 0.80% and 1.70% (depending on Emera’s long term debt rating from time to time). The Revolver Borrowers may also request Canadian dollar and U.S. dollar letters of credit under the Revolving Facility. As of March 31, 2016, Emera had a total of Cdn$276 million outstanding under the Revolving Facility.

Emera MTN Notes

On December 13, 2011, Emera issued Cdn$250 million of 2.96% senior unsecured notes due 2016 (the “Series H Senior Notes”). On November 30, 2009, Emera issued Cdn$225 million of 4.83% senior unsecured notes due 2019 (the “Series G Senior Notes,” and together with the Series H Notes, the “Emera MTN Notes”). The Series H Senior Notes mature in December 2016 and the Series G Senior Notes mature in November 2019. The Emera MTN Notes were issued under Emera’s $500,000,000 Debt Securities program.

The Emera MTN Notes are senior unsecured indebtedness of Emera, ranking equally in right of payment with all existing and future unsubordinated, unsecured indebtedness of Emera, and senior in right of payment to all existing and future subordinated indebtedness of Emera. The Emera MTN Notes are effectively junior in right of payment to all existing and future secured indebtedness (to the extent of the value of the assets securing such debt) of Emera. The trust indenture under which the Emera MTN Notes are issued (the “Emera MTN Indenture”) contains no restrictions on the amount of additional unsecured indebtedness Emera may incur or the amount of indebtedness (whether secured or unsecured) that its subsidiaries may incur. The Emera MTN Indenture permits Emera to incur secured debt subject to compliance with a negative pledge covenant. The Emera MTN Notes are redeemable in whole or in part at any time, at the option of Emera, at make-whole redemption prices as set forth in the Emera MTN Indenture. The Emera MTN Indenture also contains customary events of default.

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Emera Incorporated Subsidiary Debt

Certain of Emera’s subsidiaries have indebtedness to which the Notes will be structurally subordinated. Some of this indebtedness is secured by the assets of or pledges of equity interests in certain of Emera’s subsidiaries. As at March 31, 2016, Emera’s subsidiaries had Cdn$2,247 million in indebtedness. For more information, see “Management’s Discussion and Analysis—Developments—Recent Financing Activity.”

DIVIDEND POLICY

Dividends on the Emera Common Shares are declared at the discretion of the Board of Directors. Emera paid per share cash dividends on the Emera Common Shares of $1.6600 in 2015, $1.4750 in 2014 and $1.4125 in 2013. In August 2015, Emera increased its annual dividend growth target from 6% to 8% through 2019 and the Board of Directors approved a 19% increase in its annual Common Share dividend from $1.60 to $1.90 per Emera Common Share.

Regular quarterly dividends at the prescribed rate have been paid on all of the First Preferred Shares, Series A, the First Preferred Shares, Series B, the First Preferred Shares, Series C, the First Preferred Shares, Series E and the First Preferred Shares, Series F.

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DESCRIPTION OF THE NOTES

Notes

The following is a summary of the rights, privileges, restrictions, obligations and conditions attaching to the Notes and certain provisions of the Trust Indenture. This summary is qualified in its entirety by the provisions of the Trust Indenture. A copy of the form of Trust Indenture may be inspected during normal business hours at Emera’s head office in Halifax, Nova Scotia, during the course of the distribution of the Notes. Following closing of any offering of Notes hereunder, a copy of the Trust Indenture will be available on SEDAR at www.sedar.com.

The specific terms of any offering of the Notes will be set forth in one or more prospectus supplements. You should read this Prospectus and any applicable Prospectus Supplement before you invest in any Notes.

For information concerning the Conversion Preferred Shares into which the Notes are, in certain circumstances, convertible as described under “—Automatic Conversion” below, see “Description of Conversion Preferred Shares”.

Terms of the Notes

The Notes may be issued in one or more separate series. The Prospectus Supplement relating to the particular series of Notes being offered will specify the particular amounts, prices and terms of those Notes. These terms may include:

• the title of the Notes;

• any limit on the aggregate principal amount of the Notes of the series;

• the date on which the Notes will mature;

• the interest rate or rates, or the method of determining those rates;

• the date from which interest will accrue or the method for determining such date;

• the interest payment dates and the regular record dates;

• the places where payments will be made;

• any mandatory or optional redemption provisions;

• any additions to the events of default or covenants included in the Trust Indenture, as described in this Prospectus;

• if other than U.S. dollars, the currency or currencies, or units based on or related to currencies, in which payments on the Notes will be payable;

• whether the Notes will be issued in the form of a global security; and

• any other specific terms of the Notes.

Specified Denominations

The Notes will be issued only in minimum denominations of U.S.$2,000 and integral multiples of U.S.$1,000 in excess thereof.

Maturity Date

Each series of Notes will mature sixty (60) years from the date of issue (the “Maturity Date”).

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Interest

During the initial ten (10) year period following the issuance of any series of Notes, Emera will pay interest on such Notes at the rate specified in the applicable Prospectus Supplement in equal semi-annual installments.

Starting on the date which is ten (10) years from the date of issuance of any series of Notes, Emera will pay interest on such Notes on a quarterly basis in each year during which such Notes are outstanding thereafter until the Maturity Date (each such semi-annual or quarterly date, as applicable, an “Interest Payment Date”).

From the date of issuance of any series of Notes to, but excluding, the date which is ten (10) years from the date of issuance of such Notes, the interest rate on such Notes will be fixed at the rate specified in the applicable Prospectus Supplement, payable in arrears. Starting on the date which is ten (10) years from the date of issuance of any series of Notes and on every quarterly period thereafter until the Maturity Date (each such date, an “Interest Reset Date”), the interest rate on such Notes will be reset at an interest rate per annum equal to the three month LIBOR plus an additional basis points margin as specified in the applicable Prospectus Supplement.

Deferral Right

So long as no event of default has occurred and is continuing, Emera may elect, at its sole option, at any date other than an Interest Payment Date (a “Deferral Date”), to defer the interest payable on any series of Notes on one or more occasions for up to five consecutive years (a “Deferral Period”). There is no limit on the number of Deferral Periods that may occur. Such deferral will not constitute an event of default or any other breach under the Trust Indenture and the Notes. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. A Deferral Period terminates on any interest payment date where Emera pays all accrued and unpaid interest on such date. No Deferral Period may extend beyond the maturity date of the series of Notes.

Emera will give the holders of the Notes written notice of its election to commence or continue a Deferral Period at least 10 and not more than 60 days before the next Interest Payment Date.

Dividend Stopper Undertaking

Unless Emera has paid all accrued and payable interest on any series of Notes, Emera will not:

(i) declare any dividend on the Dividend Restricted Shares or pay any interest on any Parity Notes (other than stock dividends on Dividend Restricted Shares);

(ii) redeem, purchase or otherwise retire any Dividend Restricted Shares or Parity Notes (except (i) with respect to Dividend Restricted Shares, out of the net cash proceeds of a substantially concurrent issue of Dividend Restricted Shares or (ii) pursuant to any purchase obligation, sinking fund, retraction privilege or mandatory redemption provisions attaching to any series of Dividend Restricted Shares); or

(iii) make any payment to holders of any of the Dividend Restricted Shares or any Parity Notes in respect of dividends not declared or paid on such Dividend Restricted Shares or interest not paid on such Parity Notes, respectively (the “Dividend Stopper Undertaking”).

“Dividend Restricted Shares” means, collectively, the preferred shares of Emera (including the Conversion Preferred Shares) and the common shares of Emera.

“Parity Notes” means any class or series of Emera indebtedness currently outstanding or hereafter created which ranks on a parity with the Notes (prior to any Automatic Conversion (as defined below)) as to distributions upon liquidation, dissolution or winding-up.

It is in the interest of Emera to ensure that it timely pays interest on the Notes so as to avoid triggering the Dividend Stopper Undertaking.

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Automatic Conversion

Each series of Notes, including accrued and unpaid interest thereon, will be converted automatically (the “Automatic Conversion”), without the consent of the holders thereof, into shares of a newly issued series of First Preferred Shares of Emera (the “Conversion Preferred Shares”) upon the occurrence of: (i) the making by Emera of a general assignment for the benefit of its creditors or a proposal (or the filing of a notice of its intention to do so) under the Bankruptcy and Insolvency Act (Canada), (ii) any proceeding instituted by Emera seeking to adjudicate it a bankrupt or insolvent or, where Emera is insolvent, seeking liquidation, winding up, dissolution, reorganization, arrangement, adjustment, protection, relief or composition of its debts under any law relating to bankruptcy or insolvency in Canada, or seeking the entry of an order for the appointment of a receiver, interim receiver, trustee or other similar official for Emera or any substantial part of its property and assets in circumstances where Emera is adjudged a bankrupt or insolvent, (iii) a receiver, interim receiver, trustee or other similar official is appointed over Emera or for any substantial part of its property and assets by a court of competent jurisdiction in circumstances where Emera is adjudged a bankrupt or insolvent under any law relating to bankruptcy or insolvency in Canada; or (iv) any proceeding is instituted against Emera seeking to adjudicate it a bankrupt or insolvent, or where Emera is insolvent, seeking liquidation, winding up, dissolution, reorganization, arrangement, adjustment, protection, relief or composition of its debts under any law relating to bankruptcy or insolvency in Canada, or seeking the entry of an order for the appointment of a receiver, interim receiver, trustee or other similar official for Emera or any substantial part of its property and assets in circumstances where Emera is adjudged a bankrupt or insolvent under any law relating to bankruptcy or insolvency in Canada, and either such proceeding has not been stayed or dismissed within sixty (60) days of the institution of any such proceeding or the actions sought in such proceedings occur (including the entry of an order for relief against Emera or the appointment of a receiver, interim receiver, trustee, or other similar official for it or for any substantial part of its property and assets) (each, an “Automatic Conversion Event”).

The Conversion Preferred Shares will carry the right to receive cumulative preferential cash dividends, if, as and when declared by the Board of Directors, subject to the Companies Act (Nova Scotia), at the Perpetual Preferred Share Rate, payable on each semi-annual or quarterly dividend payment date, as the case may be, subject to any applicable withholding tax. See “Description of Conversion Preferred Shares”.

The Automatic Conversion shall occur upon an Automatic Conversion Event (the “Conversion Time”). As of the Conversion Time, each series of Notes shall be automatically converted, without the consent of the holders of the note, into a newly issued series of fully-paid Conversion Preferred Shares. At such time, such series of Notes shall be deemed to be immediately and automatically surrendered and cancelled without need for further action by noteholders, who shall thereupon automatically cease to be holders thereof and all rights of any such holder as a debtholder of Emera shall automatically cease. At the Conversion Time, holders of each series of Notes will receive one Conversion Preferred Share for each U.S.$1,000 principal amount of Notes previously held together with the number of Conversion Preferred Shares (including fractional shares, if applicable) calculated by dividing the amount of accrued and unpaid interest, if any, on the Notes, by U.S.$1,000.

Upon an Automatic Conversion of the Notes, Emera reserves the right not to issue some or all, as applicable, of the Conversion Preferred Shares to Ineligible Persons. In such circumstances, Emera will hold all Conversion Preferred Shares that would otherwise be delivered to Ineligible Persons, as agent for Ineligible Persons, and will attempt to facilitate the sale of such shares through a registered dealer retained by Emera for the purpose of effecting the sale (to parties other than Emera, its affiliates or other Ineligible Persons) on behalf of such Ineligible Persons of such Conversion Preferred Shares. Such sales, if any, may be made at any time and any price. Emera will not be subject to any liability for failing to sell Conversion Preferred Shares on behalf of any such Ineligible Persons or at any particular price on any particular day. The net proceeds received by Emera from the sale of any such Conversion Preferred Shares will be divided among the Ineligible Persons in proportion to the number of Conversion Preferred Shares that would otherwise have been delivered to them, after deducting the costs of sale and any applicable taxes, if any. Emera will make payment of the aggregate net proceeds to the

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Clearing Agency (if the Notes are then held in the book-entry only system) or to the registrar and transfer agent (in all other cases) for distribution to such Ineligible Persons in accordance with the Clearing Agency Procedures or otherwise.

As a precondition to the delivery of any certificate or other evidence of issuance representing any Conversion Preferred Shares or related rights following an Automatic Conversion, Emera may obtain from any holder of Notes (and persons holding Notes represented by such holder of Notes) a declaration, in form and substance satisfactory to Emera, confirming compliance with any applicable regulatory requirements to establish that such holder of Notes is not, and does not represent, an Ineligible Person.

As the events that give rise to an Automatic Conversion are bankruptcy and related events, it is in the interest of Emera to ensure that an Automatic Conversion does not occur, although the events that could give rise to an Automatic Conversion may be beyond Emera’s control.

Redemption Right

Except as may otherwise be provided in a Prospectus Supplement, on or after the date that is ten (10) years from the date of issuance of any series of Notes, Emera may, at its option, on giving not more than 60 nor less than 30 days’ notice to the holders of such Notes , redeem the Notes, in whole at any time or in part from time to time on any Interest Payment Date. The redemption price per U.S.$1,000 principal amount of Notes redeemed on any Interest Payment Date will be 100% of the principal amount thereof, together with accrued and unpaid interest to, but excluding, the date fixed for redemption. Notes that are redeemed shall be cancelled and shall not be reissued.

Redemption on Tax or Rating Event

Except as may otherwise be provided in a Prospectus Supplement, prior to the initial Interest Reset Date and within 90 days of a Tax Event, Emera may, at its option, redeem all (but not less than all) of any series of Notes at a redemption price per U.S.$1,000 principal amount of such Notes equal to 100% of the principal amount thereof, together with accrued and unpaid interest to but excluding the date fixed for redemption.

Except as may otherwise be provided in a Prospectus Supplement, prior to the initial Interest Reset Date and within 90 days of a Rating Event, Emera may, at its option, redeem all (but not less than all) of any series of Notes at a redemption price per U.S.$1,000 principal amount of such Notes equal to 102% of the principal amount thereof, together with accrued and unpaid interest to but excluding the date fixed for redemption.

Additional Optional and Mandatory Redemption Events:

The Prospectus Supplement relating to a particular series of Notes being offered may also include additional optional redemption rights or mandatory redemption events.

Purchase for Cancellation

Subject to the Dividend Stopper Undertaking, the Notes may be purchased, in whole or in part, by Emera in the open market or by tender or private contract. Notes purchased by Emera shall be cancelled and shall not be reissued. The purchase price payable by Emera will be paid in cash.

Subordination

The Notes will be direct unsecured subordinated obligations of Emera. The payment of principal and interest on the Notes, to the extent provided in the Trust Indenture, will be subordinated in right of payment to the prior payment in full of all present and future Senior Indebtedness, and will be effectively subordinated to all indebtedness and obligations of Emera’s subsidiaries.

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“Senior Indebtedness” means obligations (other than non-recourse obligations, Notes issued under the Trust Indenture or any other obligations specifically designated as being subordinate in right of payment to Senior Indebtedness) of, or guaranteed or assumed by, Emera for borrowed money or evidenced by bonds, debentures or notes or obligations of Emera for or in respect of bankers’ acceptances (including the face amount thereof), letters of credit and letters of guarantee (including all reimbursement obligations in respect of each of the forgoing) or other similar instruments, and amendments, renewal, extensions, modifications and refunding of any such indebtedness or obligation. As of March 31, 2016, Emera’s Senior Indebtedness totaled approximately Cdn$751 million.

Events of Default

An event of default in respect of any series Notes will occur only if Emera defaults on the payment of (i) principal or premium, if any, when due and payable or (ii) interest when due and payable and such default continues for 30 days (subject to Emera’s right, at its sole option, to defer interest payments, as described under “Description of the Notes—Deferred Right”).

If an event of default has occurred and is continuing with respect to a series of Notes, and the Notes have not already been automatically converted into Conversion Preferred Shares, then Emera shall without notice from an Indenture Trustee be deemed to be in default under the Trust Indenture and the Notes and the Indenture Trustee may, in its discretion and shall upon the request of holders of not less than one-quarter of the principal amount of Notes of that series then outstanding under the Trust Indenture, demand payment of the principal or premium, if any, together with any accrued and unpaid interest up to (but excluding) such date, which shall immediately become due and payable in cash, and may institute legal proceedings for the collection of such aggregate amount where Emera fails to make payment thereof upon such demand.

Additional Emera Covenants

In addition to the Dividend Stopper Undertaking, Emera will covenant for the benefit of the holders of each series of Notes, that it will not create or issue any Emera Preferred Shares which, in the event of insolvency or winding-up of Emera, would rank in right of payment in priority to the Conversion Preferred Shares.

Issue of Conversion Preferred Shares in Connection with Automatic Conversion

All corporate action necessary to authorize Emera to issue Conversion Preferred Shares pursuant to the terms of the Notes will be completed prior to the closing of any offering of Notes.

Merger, Consolidation, Sale, Lease or Conveyance

The Trust Indenture provides that Emera will not merge, amalgamate or consolidate with any other person and will not sell, lease or convey all or substantially all its assets to any person, unless Emera shall be the continuing person, or unless the successor corporation or person that acquires all or substantially all the assets of Emera shall expressly assume all of the covenants to be performed and conditions to be observed by Emera under the Trust Indenture, and unless immediately after such merger, amalgamation, consolidation, sale, lease or conveyance, Emera, such person or such successor corporation shall not be in default in the performance of the covenants and conditions of such Trust Indenture to be performed or observed by Emera.

If such successor corporation or person that acquires all or substantially all the assets of Emera is organized under the laws of a jurisdiction other than the laws of Canada or any province of territory thereof or the United States, any state thereof or the District of Columbia, such successor corporation or person shall assume Emera’s obligations under the Trust Indenture to pay Additional Amounts, with the name of such successor jurisdiction being included in addition to Canada in each place that Canada appears in “Payment of Additional Amounts”.

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Payment of Additional Amounts

All payments made by or on account of any obligation of Emera under or with respect to the Notes shall be made free and clear of and without withholding or deduction for, or on account of, any present or future tax, duty, levy, impost, assessment or other governmental charge (including penalties, interest and other liabilities related thereto) imposed or levied by or on behalf of the Government of Canada or any province or territory thereof or by any authority or agency therein or thereof having power to tax (hereinafter, “Canadian Taxes”), unless Emera is required to withhold or deduct Canadian Taxes by law or by the interpretation or administration thereof by the relevant government authority or agency. If Emera is so required to withhold or deduct any amount for or on account of Canadian Taxes from any payment made under or with respect to the Notes, Emera shall pay as additional interest such additional amounts (hereinafter “Additional Amounts”) as may be necessary so that the net amount received by each holder of the Notes (including Additional Amounts) after such withholding or deduction shall not be less than the amount the holder of the Notes would have received if such Canadian Taxes had not been withheld or deducted; provided, however, that no Additional Amounts shall be payable with respect to a payment made to a holder of the Notes (hereinafter an “Excluded Holder”) in respect of a beneficial owner (i) with which Emera does not deal at arm’s length (for purposes of the Tax Act) at the time of the making of such payment, (ii) which is subject to such Canadian Taxes by reason of the failure to comply with any certification, identification, information, documentation or other reporting requirement by a holder of the Notes if compliance is required by law, regulation, administrative practice or an applicable treaty as a precondition to exemption from, or a reduction in, the rate of deduction or withholding of, such Canadian Taxes, (iii) where all or any portion of the amount paid to such holder of the Notes is deemed to be a dividend paid to such holder pursuant to subsection 214(16) of the Tax Act, or (iv) which is subject to such Canadian Taxes by reason of its carrying on business in or being connected with Canada or any province or territory thereof otherwise than by the mere holding of Notes or the receipt of payments thereunder. Emera shall make such withholding or deduction and remit the full amount deducted or withheld to the relevant authority as and when required under applicable law.

If a holder of the Notes has received a refund or credit for any Canadian Taxes with respect to which Emera has paid Additional Amounts, such holder of the Notes shall pay over such refund to Emera (but only to the extent of such Additional Amounts), net of all out of-pocket expenses of such holder of the Notes, together with any interest paid by the relevant tax authority in respect of such refund.

Amendment, Supplement and Waiver

The Trust Indenture or the Notes may be amended and any existing default or event of default or compliance with any provision of the Trust Indenture or any series of Notes may be waived by Extraordinary Resolution; provided that, in any case, without the consent of each holder of the outstanding series of Notes affected thereby, Emera and the Indenture Trustee may not (a) extend the stated maturity of the principal of the Notes of that series, (b) reduce the principal amount thereof or reduce the rate or extend the time of payment of interest thereon, (c) reduce any amount payable on redemption thereof, (d) change the place at which or currency in which principal and interest payments are to be made, (e) reduce the amount of any original issue discount security payable upon acceleration or provable in bankruptcy or impair the right to institute suit for the enforcement of any payment on any of the Notes of that series when due, or (f) reduce the aforesaid percentage in principal amount of the Notes of that series.

Issue of Additional Notes

Emera may, at any time and from time to time, issue additional Notes or other subordinated notes without the authorization of holders of any series of Notes. In the event that Emera issues additional series of subordinated notes, the rights, privileges, restrictions and conditions attached to such additional series may vary materially from other series of Notes. In such event, the right of the holders of any series of Notes to receive interest or principal may rank pari passu with the rights of the holders of other subordinated notes.

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Governing Law

The Trust Indenture and the Notes will be governed by and construed in accordance with the laws of the Province of Nova Scotia and the federal laws of Canada applicable therein, other than such provisions of the Trust Indenture which govern American Stock Transfer & Trust Company, LLC’s rights and obligations to holders of the Notes and Emera, which will be governed by the laws of the State of New York.

Book-Entry Only Form

Upon issuance, each series of Notes will be represented by one or more fully registered global securities (the “Global Securities”) registered in the name of Cede & Co. (the nominee of The Depository Trust Company (the “Clearing Agency”)), or such other name as may be requested by an authorized representative of the Clearing Agency. The authorized denominations of each Note will be U.S.$2,000 and integral multiples of U.S.$1,000 in excess thereof. Accordingly, the Notes may be transferred or converted only through the Clearing Agency and its participants. Except as described below, owners of beneficial interests in the Global Securities will not be entitled to receive the Notes in definitive form.

Beneficial interests in the Notes will be represented through book-entry accounts of financial institutions acting on behalf of beneficial owners as direct and indirect participants in the Clearing Agency. Holders of the Notes may elect to hold interests in the Notes in global form through either the Clearing Agency in the U.S. or Clearstream Banking, société anonyme (“Clearstream, Luxembourg”), or Euroclear Bank S.A./N.V. (“Euroclear”), if they are participants in those systems, or indirectly through organizations which are participants in those systems. Clearstream, Luxembourg and Euroclear will hold interests on behalf of their participants through customers’ securities accounts in Clearstream, Luxembourg’s and Euroclear’s names on the books of their respective depositaries, which in turn will hold such interests in customers’ securities accounts in the depositaries’ names on the books of the Clearing Agency.

Each person owning a beneficial interest in a Global Security must rely on the procedures of the Clearing Agency and, if such person is not a participant, on the procedures of the participant through which such person owns its interest in order to exercise any rights of a holder under the Trust Indenture. The laws of some jurisdictions require that certain purchasers of securities take physical delivery of such securities in certificated form. Such limits and such laws may impair the ability to transfer beneficial interests in a Global Security representing the Notes.

The following is based on information furnished by the Clearing Agency:

The Clearing Agency is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. The Clearing Agency holds securities that its participants (“Participants”) deposit with the Clearing Agency. The Clearing Agency also facilitates the settlement among Participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in Participants’ accounts, thereby eliminating the need for physical movement of securities certificates. These direct Participants (“Direct Participants”) include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. The Clearing Agency is a wholly-owned subsidiary of the Depository Trust & Clearing Corporation (“DTCC”). DTCC is the holding company for the Clearing Agency, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the Clearing Agency’s system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (“Indirect Participants”). The rules applicable to the Clearing Agency and its Participants are on file with the SEC.

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Purchases of the Notes under the Clearing Agency’s system must be made by or through Direct Participants, which will receive a credit for such Notes on the Clearing Agency’s records. The ownership interest of each actual purchaser of each Note represented by a Global Security (“Beneficial Owner”) is in turn to be recorded on the Direct Participants’ and Indirect Participants’ records. Beneficial Owners will not receive written confirmation from the Clearing Agency of their purchase. Beneficial Owners are, however, expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct Participants or Indirect Participants through which such Beneficial Owner entered into the transaction. Transfers of ownership interests in a Global Security representing the Notes are to be accomplished by entries made on the books of Participants acting on behalf of Beneficial Owners. Beneficial Owners of a Global Security representing the Notes will not receive the Notes in definitive form representing their ownership interests therein, except in the event that use of the book-entry system for such Notes is discontinued.

To facilitate subsequent transfers, the Global Securities representing the Notes which are deposited with the Clearing Agency are registered in the name of the Clearing Agency’s nominee, Cede & Co., or such other name as may be requested by an authorized representative of the Clearing Agency. The deposit of Global Securities with the Clearing Agency and their registration in the name of Cede & Co. or such other nominee effect no change in beneficial ownership. The Clearing Agency has no knowledge of the actual Beneficial Owners of the Global Securities representing the Notes; the Clearing Agency’s records reflect only the identity of the Direct Participants to whose accounts such Notes are credited, which may or may not be the Beneficial Owners. The Participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by the Clearing Agency to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Neither the Clearing Agency nor Cede & Co. (nor such other nominee of the Clearing Agency) will consent or vote with respect to the Global Securities representing the Notes. Under its usual procedures, the Clearing Agency mails an “omnibus proxy” to Emera as soon as possible after the applicable record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts the Notes are credited on the applicable record date (identified in a listing attached to the omnibus proxy).

Principal, premium, if any, and interest payments on the Global Securities representing the Notes will be made to Cede & Co. (or such other nominee as may be requested by an authorized representative of the Clearing Agency). The Clearing Agency’s practice is to credit Direct Participants’ accounts, upon the Clearing Agency’s receipt of funds and corresponding detailed information from Emera or the Indenture Trustee, on the applicable payment date in accordance with their respective holdings shown on the Clearing Agency’s records. Payments by Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in “street name”, and will be the responsibility of such Participant and not of the Clearing Agency, the applicable Indenture Trustee or Emera, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of principal, premium, if any, and interest to Cede & Co. (or such other nominee as may be requested by an authorized representative of the Clearing Agency) is the responsibility of Emera or the applicable Indenture Trustee (provided it has received funds from Emera), disbursement of such payments to Direct Participants shall be the responsibility of the Clearing Agency, and disbursement of such payments to the Beneficial Owners shall be the responsibility of Direct and Indirect Participants.

The Clearing Agency may discontinue providing its services as securities depository with respect to the Notes at any time by giving reasonable notice to Emera or the Indenture Trustee. Under such circumstances, in the event that a successor securities depository is not obtained, Notes in definitive form are required to be printed and delivered to each holder.

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Emera may decide to discontinue use of the system of book-entry transfers through the Clearing Agency (or a successor securities depositary). In that event, the Notes in definitive form will be printed and delivered.

Clearstream, Luxembourg advises that it is incorporated under the laws of Luxembourg as a professional depositary. Clearstream, Luxembourg holds securities for its participating organizations (“Clearstream participants”), and facilitates the clearance and settlement of securities transactions between Clearstream participants through electronic book-entry changes in accounts of Clearstream participants, thereby eliminating the need for physical movement of certificates. Clearstream, Luxembourg provides to Clearstream participants, among other things, services for safekeeping, administration, clearance and settlement of internationally traded securities and securities lending and borrowing. Clearstream, Luxembourg interfaces with domestic markets in several countries. As a professional depositary, Clearstream, Luxembourg is subject to regulation by the Luxembourg Commission for the Supervision of the Financial Sector (Commission de Surveillance du Secteur Financier). Clearstream participants are recognized financial institutions around the world, including underwriters, securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations and may include the underwriters of an offering of Notes. Indirect access to Clearstream, Luxembourg is also available to others, such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Clearstream participant, either directly or indirectly.

Distributions with respect to interests in the Notes held beneficially through Clearstream, Luxembourg will be credited to cash accounts of Clearstream participants in accordance with its rules and procedures, to the extent received by the Clearing Agency for Clearstream, Luxembourg.

Euroclear advises that it was created in 1968 to hold securities for participants of Euroclear (“Euroclear participants”), and to clear and settle transactions between Euroclear participants through simultaneous electronic book-entry delivery against payment, thereby eliminating the need for physical movement of certificates and any risk from lack of simultaneous transfers of securities and cash. Euroclear includes various other services, including securities lending and borrowing and interfaces with domestic markets in several countries. Euroclear is operated by Euroclear Bank S.A./N.V. (“Euroclear Operator”). All operations are conducted by the Euroclear Operator, and all Euroclear securities clearance accounts and Euroclear cash accounts are accounts with the Euroclear Operator. Euroclear participants include banks (including central banks), securities brokers and dealers and other professional financial intermediaries and may include the underwriters of an offering of Notes. Indirect access to Euroclear is also available to other firms that clear through or maintain a custodial relationship with a Euroclear participant, either directly or indirectly.

Securities clearance accounts and cash accounts with the Euroclear Operator are governed by the Terms and Conditions Governing Use of Euroclear and the related Operating Procedures of the Euroclear System, and applicable Belgian law (collectively, the “Terms and Conditions”). The Terms and Conditions govern transfers of securities and cash within the Euroclear System, withdrawals of securities and cash from the Euroclear System, and receipts of payment with respect to securities in the Euroclear System. All securities in the Euroclear System are held on a fungible basis without attribution of specific certificates to specific securities clearance accounts. The Euroclear Operator acts under the Terms and Conditions only on behalf of Euroclear participants, and has no records of or relationship with persons holding through Euroclear participants.

Distributions with respect to the Notes held beneficially through the Euroclear System will be credited to the cash accounts of Euroclear participants in accordance with the Terms and Conditions, to the extent received by the U.S. depositary for the Euroclear System.

The information in this section concerning the Clearing Agency and the Clearing Agency’s book-entry system, Clearstream, Luxembourg and Euroclear has been obtained from sources that Emera believes to be reliable, but is subject to any changes to the arrangements between Emera and the Clearing Agency and any changes to such procedures that may be instituted unilaterally by the Clearing Agency, Clearstream, Luxembourg and Euroclear.

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Transfers

Transfers of ownership of the Notes will be effected only through records maintained by the Clearing Agency for such Notes with respect to interests of Participants and on the records of Participants with respect to interests of persons other than Participants. Holders of the Notes who are not Participants, but who desire to purchase, sell or otherwise transfer ownership of or other interests in the Notes, may do so only through Participants. The ability of a holder to pledge Notes or otherwise take action with respect to such holder’s interest in Notes (other than through a Participant) may be limited due to the lack of a physical certificate. See “Risk Factors—Risks Related to the Notes—Liquidity of and Dealings in Notes”.

Payments and Deliveries

As long as the Clearing Agency is the registered owner of the Notes, the Clearing Agency will be considered the sole owner of the Notes for the purposes of receiving payments on the Notes or the delivery of Conversion Preferred Shares upon the occurrence of an Automatic Conversion. Payments of interest in respect of Notes will be made by Emera to the Clearing Agency as the registered holder of the Notes and Emera understands that such payments will be forwarded by the Clearing Agency to Participants in accordance with the Clearing Agency Procedures. Deliveries of Conversion Preferred Shares in respect of the exercise or operation of the Automatic Conversion in the limited circumstances described under “—Automatic Conversion” will be made by Emera to the Clearing Agency as the registered holder of the Notes and Emera understands that such shares will be forwarded by the Clearing Agency to Participants in accordance with the Clearing Agency Procedures. As long as the Notes are held in the Clearing Agency book-entry only system, the responsibility and liability of the Indenture Trustee and/or Emera in respect of the Notes is limited to making payment of any amount due on the Notes and/or making delivery of Conversion Preferred Shares in respect thereof to the Clearing Agency.

DESCRIPTION OF CONVERSION PREFERRED SHARES

The following is a summary of the rights, privileges, restrictions and conditions attaching to each series of Conversion Preferred Shares. This summary is qualified in its entirety by Emera’s memorandum of association, as amended, and articles of association, as amended, and the actual terms and conditions of each series of Conversion Preferred Shares.

The specific terms of any offering of the Conversion Preferred Shares will be set for in one or more Prospectus Supplements. You should read this Prospectus and any applicable Prospectus Supplement before you invest in any Notes or Conversion Preferred Shares.

Issue Price

The Conversion Preferred Shares will have an issue price of U.S.$1,000 per share.

No Fixed Maturity

The Conversion Preferred Shares will not have a fixed maturity date.

Dividends

Holders of each series of Conversion Preferred Shares will be entitled to receive cumulative preferential cash dividends, if, as and when declared by the Board of Directors, subject to the Companies Act (Nova Scotia), at the same rate as would have accrued on the related series of Notes (had such Notes remained outstanding) as described under “Description of the Notes—Interest”) (the “Perpetual Preferred Share Rate”), payable on each semi-annual or quarterly dividend payment date, as the case may be, subject to applicable withholding tax. If the Board of Directors does not declare the dividends, or any part thereof, on the Conversion Preferred Shares on or before the dividend payment date for a particular period, such dividend or the unpaid part thereof shall be paid on a subsequent date or dates to be determined by the Board of Directors on which Emera shall have sufficient monies properly available, under the provisions of applicable law and under the provisions of any trust indenture governing bonds, debentures or other securities of Emera, for the payment of the same.

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Redemption of the Conversion Preferred Shares

The Prospectus Supplement relating to the related series of Notes being offered will specify any mandatory or optional redemption terms of the Conversion Preferred Shares.

Presentation for Redemption or Sale

A redemption or sale to Emera of Conversion Preferred Shares will be effected by the holder transferring such holder’s Conversion Preferred Shares to be redeemed or sold to the account of Emera in the Clearing Agency (or, in the event that the Conversion Preferred Shares are not then issued in book-entry only form, by depositing with the transfer agent for the Conversion Preferred Shares, at one of its principal offices, certificates representing such Conversion Preferred Shares).

Purchase for Cancellation

The Prospectus Supplement relating to the related series of Notes being offered will specify any repurchase entitlement of the series of Conversion Preferred Shares relating to the related series of Notes being offered.

Rights on Liquidation

In the event of the liquidation, dissolution or winding-up of Emera, the holders of the Conversion Preferred Shares shall be entitled to receive U.S.$1,000 per share (less any amount that may have been returned to holders as a return of capital), together with all accrued and unpaid dividends thereon, subject to any applicable withholding tax, before any amount shall be paid or any assets of Emera distributed to the holders of Common Shares or any shares ranking junior to the Conversion Preferred Shares. The holders of the Conversion Preferred Shares shall not be entitled to share in any further distribution of the property or assets of Emera.

Restrictions on Dividends and Retirement of Conversion Preferred Shares

So long as any of the Conversion Preferred Shares of any series are outstanding, Emera will not, without the approval of the holders of the Conversion Preferred Shares of that series, given as specified below:

(i) declare any dividend on the Common Shares or any other shares ranking junior to the Conversion Preferred Shares (other than stock dividends on shares ranking junior to the Conversion Preferred Shares); or

(ii) redeem, purchase or otherwise retire any Common Shares or any other shares ranking junior to the Conversion Preferred Shares (except out of the net cash proceeds of a substantially concurrent issue of shares ranking junior to the Conversion Preferred Shares); or

(iii) redeem, purchase or otherwise retire: (i) less than all the Conversion Preferred Shares; or (ii) except pursuant to any purchase obligation, sinking fund, retraction privilege or mandatory redemption provisions attaching to any series of preferred shares of Emera, any other shares ranking on a parity with the Conversion Preferred Shares;

unless, in each case, all dividends on the Conversion Preferred Shares of that series and on all other shares ranking prior to or on a parity with the Conversion Preferred Shares of that series, have been declared and paid or set apart for payment.

Issue of Additional Series of Emera Preferred Shares

Emera may issue other series of Emera Preferred Shares without the authorization of the holders of the Conversion Preferred Shares, as applicable.

Shareholder Approvals

The approval of any amendments to the rights, privileges, restrictions and conditions attaching to the Conversion Preferred Shares of any series may be given by a resolution carried by the affirmative vote of not less

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than 66 2/3% of the votes cast at a meeting of holders of Conversion Preferred Shares at which at least a majority of the outstanding Conversion Preferred Shares of that series is represented or, if no quorum is present at such meeting, at a meeting following such adjourned meeting at which no quorum requirement would apply. Emera will covenant that for so long as the Notes of any series are outstanding no amendment will be made to the rights, privileges, restrictions and conditions of the Conversion Preferred Shares of that series (other than any amendments relating to the Emera Preferred Shares as a class) without the prior approval of the holders of the Notes related to such series by Extraordinary Resolution.

Voting Rights

The voting rights of holders of any series of Conversion Preferred Shares shall be the same as the voting rights of the holders of Emera’s other outstanding series of First Preferred Shares.

The holders of any series of Conversion Preferred Shares will not be entitled to receive notice of or to attend or to vote at any meeting of the shareholders of Emera unless and until Emera shall fail to pay in aggregate eight quarterly dividends on the Conversion Preferred Shares of that series, whether or not consecutive and whether or not dividends have been declared and whether or not there are any monies of Emera properly applicable to the payment of dividends. In that event, the holders of the Conversion Preferred Shares of that series will be entitled to receive notice of, and to attend, all meetings of shareholders at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at such meeting. Such entitlement to vote shall be exercised together with holders of shares of all other series of First Preferred Shares and all other classes or series of classes of shares of the Company bearing the right to vote in similar circumstances. In any such instance, a holder of Conversion Preferred Shares will be entitled to one vote for each share held, subject to the circumstances described below under “Constraints on Share Ownership”. The voting rights of the holders of any series of Conversion Preferred Shares shall forthwith cease upon payment by Emera of all arrears of dividends on any outstanding Conversion Preferred Shares of that series unless and until eight quarterly dividends on such Conversion Preferred Shares shall again be in arrears and unpaid.

Constraints on Share Ownership

As required by the Nova Scotia Power Reorganization (1998) Act (Nova Scotia) and pursuant to the Nova Scotia Power Privatization Act (Nova Scotia), the Articles of Association of Emera (the “Emera Articles”) provide that no person, together with associates thereof, may subscribe for, have transferred to that person, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, or vote, in the aggregate, voting shares of Emera to which are attached more than 15% of the votes attached to all outstanding voting shares of Emera. Non-residents of Canada may not subscribe for, have transferred to them, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, or vote, in the aggregate, voting shares of Emera to which are attached more than 25% of the votes attached to all outstanding voting shares of Emera. Votes cast by non-residents on any resolution at a meeting of common shareholders of Emera will be pro-rated so that such votes will not constitute more than 25% of the total number of votes cast.

The Common Shares, and in certain circumstances the First Preferred Shares, Series A, First Preferred Shares, Series B, First Preferred Shares, Series C, First Preferred Shares, Series E and First Preferred Shares, Series F, are considered to be voting shares for purposes of the constraints on share ownership, and any Conversion Preferred Shares issued upon an Automatic Conversion Event will also in certain circumstances be considered to be voting shares for purposes of the constraints on share ownership.

The Emera Articles contain provisions for the enforcement of these constraints on share ownership including provisions for suspension of voting rights, forfeiture of dividends, prohibitions of share transfer and issuance, compulsory sale of shares and redemption, and suspension of other shareholder rights. The Board of Directors may require shareholders to furnish statutory declarations as to matters relevant to enforcement of the restrictions.

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Tax Election

The Conversion Preferred Shares will be “taxable preferred shares” as defined in the Tax Act for purposes of the tax under Part IV.1 of the Tax Act. The terms of the Conversion Preferred Shares will require Emera to make the necessary election under Part VI.1 of the Tax Act so that corporate holders will not be subject to the tax under Part IV.1 of the Tax Act on dividends received (or deemed to be received) on the Conversion Preferred Shares. See “Certain Canadian Federal Income Tax Considerations”.

Book-Entry Only Form

Unless Emera elects otherwise, the Conversion Preferred Shares will be issued in “book-entry only” form and may be purchased, held and transferred in substantially the same manner as the Notes. See “Description of the Notes—Book-Entry Only Form”.

CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

In the opinion of Osler, Hoskin & Harcourt LLP, counsel to Emera, the following is a summary of the principal Canadian federal income tax considerations generally applicable to a holder of Notes who acquires Notes under any offering hereunder and who, for purposes of the Tax Act and at all relevant times, (i) is not, and is not deemed to be, resident in Canada; (ii) deals at arm’s length with and is not affiliated with Emera or any of its affiliates; (iii) deals at arm’s length with any transferee resident (or deemed to be resident) in Canada to whom the Holder disposes of a Note; (iv) holds Notes and any Conversion Preferred Shares as capital property; (v) does not use or hold the Notes or Conversion Preferred Shares in a business carried on in Canada; and (vi) is not a “specified non-resident shareholder” of Emera for purposes of the Tax Act or a non-resident person not dealing at arm’s length with a “specified shareholder” (within the meaning of subsection 18(5) of the Tax Act) of Emera (a “Non-Resident Holder”). Special rules, which are not discussed in this summary, may apply to certain Non-Resident Holders that are insurers carrying on an insurance business in Canada and elsewhere. This summary assumes that no interest paid on the Notes will be in respect of a debt or other obligation to pay an amount to a person with whom Emera does not deal at arm’s length within the meaning of the Tax Act.

This summary is based upon the current provisions of the Tax Act in force as of the date hereof, all specific proposals to amend the Tax Act publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof (the “Tax Proposals”) and counsel’s understanding of the administrative policies and assessing practices of the CRA published in writing prior to the date hereof. This summary is not exhaustive of all Canadian federal income tax considerations and, except for the Tax Proposals, does not take into account or anticipate any changes in law or CRA administrative policies and assessing practices, whether by way of legislative, governmental or judicial decision or action, nor does it take into account or consider any other federal tax considerations or any provincial, territorial or foreign tax considerations, which may differ materially from those discussed herein. While this summary assumes that the Tax Proposals will be enacted in the form proposed, no assurance can be given that such proposals will be enacted in their current form, or at all.

Generally, for purposes of the Tax Act, all amounts relating to the acquisition, holding or disposition of Notes or Conversion Preferred Shares must be determined in Canadian dollars. Any such amount that is expressed or denominated in a currency other than Canadian dollars must be converted into Canadian dollars using the relevant exchange rate determined in accordance with the Tax Act.

This summary is of a general nature only and is not, and is not intended to be, and should not be construed to be, legal or tax advice to any particular Non-Resident Holder and no representation with respect to the income tax consequences to any particular Non-Resident Holder is made. Prospective purchasers of Notes should consult their own tax advisors with respect to the tax consequences of acquiring, holding and disposing of Notes having regard to their own particular circumstances.

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Notes

Interest on and disposition of the Notes

Under the Tax Act, interest, principal and premium, if any, paid or credited, or deemed to be paid or credited to a Non-Resident Holder on Notes will be exempt from Canadian non-resident withholding tax. No other taxes on income (including taxable capital gains) will be payable under the Tax Act in respect of the acquisition, holding, redemption or disposition of Notes, or the receipt of interest, premium or principal thereon by a Non-Resident Holder solely as a consequence of such acquisition, holding, redemption or disposition of Notes.

Automatic Conversion

A conversion of Notes into Conversion Preferred Shares pursuant to an Automatic Conversion will result in a disposition of such Notes for purposes of the Tax Act for proceeds equal to the fair market value of the Conversion Preferred Shares which the Non-Resident Holder acquires, not including any amount considered to be interest. A Non-Resident Holder will not generally be subject to tax under the Tax Act in respect of such disposition. The aggregate cost to a Non-Resident Holder of the Conversion Preferred Shares ultimately received on an Automatic Conversion will be equal to the fair market value thereof at the time received.

Conversion Preferred Shares

Dividends

A dividend (including a deemed dividend) received on Conversion Preferred Shares by a Non-Resident Holder will generally be subject to Canadian non-resident withholding tax under the Tax Act at a rate of 25 percent, subject to any reduction in the rate of such withholding under the provisions of an income tax treaty or convention. For a Non-Resident Holder who is a resident of the United States and qualifies for the benefits of the Canada- United States Tax Convention, the rate of withholding will generally be reduced to 15 percent or such other applicable rate pursuant to the income tax treaty.

Dispositions

A Non-Resident Holder of Conversion Preferred Shares who disposes of or is deemed to dispose of Conversion Preferred Shares (other than as discussed under “Redemption or Other Acquisition by Emera”) will not be subject to tax in respect of any capital gain realized on a disposition of Conversion Preferred Shares unless the Conversion Preferred Shares constitute “taxable Canadian property” (as defined in the Tax Act) to the Non-Resident Holder at the time of the disposition and the Non-Resident Holder is not entitled to relief under an applicable income tax treaty or convention. The Conversion Preferred Shares will be considered taxable Canadian property if such shares are not listed on a designated stock exchange and, at any time during the 60-month period immediately preceding the disposition, the Conversion Preferred Shares derived (directly or indirectly) more than 50 percent of their fair market value from real or immovable property situated in Canada, Canadian resource properties, timber resource properties or options or interests in respect of any such property, all as defined for the purposes of the Tax Act.

If the Conversion Preferred Shares are considered taxable Canadian property to the Non-Resident Holder, a disposition or deemed disposition of such Conversion Preferred Shares (other than as discussed under “Redemption or Other Acquisition by Emera”) will generally give rise to a capital gain (or a capital loss) equal to the amount by which the proceeds of disposition of such Conversion Preferred Shares, net of any reasonable costs of disposition, exceed (or are less than) the adjusted cost base of such Conversion Preferred Shares to the Non-Resident Holder. Generally, one half of any such capital gain must be included in the Non-Resident Holder’s income for that year and one half of any such capital loss must be deducted against taxable capital gains realized in that year from dispositions of taxable Canadian property. Certain excess allowable capital losses from the dispositions of taxable Canadian property may be claimed in any of the three preceding taxation years or any subsequent taxation year subject to the rules contained in the Tax Act.

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An applicable income tax treaty or convention may apply to exempt a Non- Resident Holder from tax under the Tax Act in respect of a disposition of Conversion Preferred Shares notwithstanding that such shares may constitute taxable Canadian property.

Redemption or Other Acquisition by Emera

If Emera redeems for cash or otherwise acquires the Conversion Preferred Shares, other than by a purchase in the manner in which shares are normally purchased by a member of the public in the open market, the Non-Resident Holder will be deemed to have received a dividend equal to the amount, if any, paid by Emera in excess of the paid-up capital of such shares for purposes of the Tax Act at such time. Such deemed dividend will be subject to the treatment described above under “Dividends”. The difference between the amount paid and the amount of the deemed dividend will be treated as proceeds of disposition for the purposes of computing the capital gain or capital loss arising on a disposition of such shares.

CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS

This disclosure is limited to the U.S. federal tax issues addressed herein. Additional issues may exist that are not addressed in this disclosure and that could affect the U.S. federal tax treatment of the Notes. Prospective investors should seek their own advice based on their particular circumstances from independent tax advisers.

The following are certain U.S. federal income tax consequences to the U.S. Holders (described below) of owning and disposing of the Notes purchased in any offering hereunder at the “issue price,” which is the first price at which a substantial amount of the Notes is sold to the public, and held as capital assets for U.S. federal income tax purposes. This discussion does not describe all of the tax consequences that may be relevant to you in light of your particular circumstances, including alternative minimum tax and Medicare contribution tax consequences, as well as differing tax consequences that may apply if you are, for instance:

• a financial institution;

• a regulated investment company;

• a dealer or trader in securities that uses a mark-to-market method of tax accounting;

• holding the Notes as part of a “straddle” or integrated transaction;

• a person whose functional currency is not the U.S. dollar;

• a tax-exempt entity; or

• a partnership for U.S. federal income tax purposes.

If you are a partnership for U.S. federal income tax purposes, the U.S. federal income tax treatment of you and your partners will generally depend on the status of the partners and your activities. If you are a partnership owning the Notes or a partner in such partnership, you should consult your tax adviser as to your particular U.S. federal income tax consequences of owning the Notes. This discussion is based on the Internal Revenue Code of 1986, as amended, or the Code, administrative pronouncements, judicial decisions and final, temporary and proposed Treasury regulations, changes to any of which subsequent to the date of this document may affect the tax consequences described herein. This discussion does not address any aspect of state, local or non-U.S. taxation, or any taxes other than income taxes.

You should consult your tax adviser with regard to the application of the U.S. federal tax laws to your particular situation, as well as any tax consequences arising under the laws of any state, local or non-U.S. taxing jurisdiction.

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You are a U.S. Holder for purposes of this discussion if for U.S. federal income tax purposes you are a beneficial owner of a Note or a Conversion Preferred Share and are:

• a citizen or individual resident of the United States;

• a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any state therein or the District of Columbia; or

• an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source.

Tax Treatment of the Notes

The determination of whether an obligation represents a debt or equity interest is based on all the relevant facts and circumstances at the time the obligation is issued. There is no direct legal authority as to the proper U.S. federal income tax treatment of an instrument such as the Notes that is denominated as a debt instrument and has certain debt features, but that provides for a possible Automatic Conversion under which an investor could lose its creditor rights upon the occurrence of an Automatic Conversion Event. In the absence of authority addressing the proper characterization of instruments such as the Notes, to the extent required to do so, we intend to treat the Notes as debt for U.S. federal income tax purposes. However, we will not request any ruling from the IRS regarding the treatment of the Notes for U.S. federal income tax purposes and the IRS or a court may conclude that the Notes should be treated as equity for U.S. federal income tax purposes (as described below). Prospective investors should consult their tax advisers as to the proper characterization of the Notes for U.S. federal income tax purposes.

Consequences if the Notes are Treated as Debt Instruments for U.S. Federal Income Tax Purposes

Assuming the treatment of the Notes as debt instruments for U.S. federal income tax purposes is respected, the following U.S. federal income tax consequences should result.

Certain Additional Payments

There are circumstances in which we might be required to make payments on a Note that would increase the yield of the Note, for instance, as described under “Description of the Notes—Redemption on Rating Event or Tax Event.” We believe that the likelihood that we would be required to make such payments is “remote,” and/or that the amount of any such payments, if made, would be “incidental,” in each case within the meaning of the applicable Treasury Regulations. Therefore, we intend to take the position that the possibility of such payments does not result in the Notes being treated as contingent payment debt instruments under the applicable Treasury Regulations. If the IRS takes a contrary position, you may be required to accrue interest income based upon a “comparable yield” (as defined in the Treasury Regulations) determined at the time of issuance of the Notes, with adjustments to such accruals when any contingent payments are made that differ from the payments based on the comparable yield. In addition, any income on the sale or other taxable disposition of the Notes would be treated as interest income rather than as capital gain. You should consult your tax adviser regarding the tax consequences if the Notes were treated as contingent payment debt instruments. The remainder of this discussion assumes that the Notes are not treated as contingent payment debt instruments.

Payments of Interest

Based on current market conditions, and subject to the discussion below relating to our option to defer payments of interest on the Notes, we expect, and this discussion assumes, that the Notes will be issued without original issue discount for U.S. federal income tax purposes.

Under the terms of the Notes, we have the ability to defer payments of interest from time to time for up to five years. United States Treasury Regulations provide that a debt instrument will not be treated as issued with original issue discount, or OID, by reason of its issuer’s ability to defer payments of interest if the likelihood of

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such deferral is “remote.” We intend to take the position, and this discussion assumes, that, as of the date of this Prospectus, the likelihood of deferring payments of interest under the terms of the Notes is “remote” within the meaning of the Treasury Regulations referred to above. Based on the foregoing, we do not intend to treat the Notes as issued with OID by reason of our deferral option. Accordingly, stated interest on the Notes should be taxable to you as ordinary income when paid or accrued in accordance with your method of accounting for U.S. federal income tax purposes. Our position is not binding on the IRS. If the IRS takes a contrary position, you may be required to accrue OID from the time of issuance, as described below, regardless of your method of accounting for U.S. federal income tax purposes.

In the event we exercise our option to defer payments of interest, the Notes would be treated as retired and reissued for their issue price solely for purposes of the OID rules and you would be required to treat all stated interest on the deemed reissued Notes as OID. Consequently, during any period of interest deferral, and any period thereafter, you will include all stated interest in gross income as it accrues using a constant yield method before the receipt of cash. The calculation of the amount of such accruals may be complex, and therefore you should consult your tax adviser regarding the tax consequences if the Notes were treated as issued (or deemed reissued) with OID.

The amount of interest will include any amounts withheld in respect of Canadian taxes and, without duplication, any additional amounts paid with respect thereto. Interest on the Notes will be foreign-source income for foreign tax credit purposes.

Sale or Other Taxable Disposition of the Notes

Upon the sale or other taxable disposition of a Note, you will recognize taxable gain or loss equal to the difference between the amount realized on the sale or other taxable disposition (less any amount equal to accrued but unpaid interest, which will be taxable as interest income, as described above) and your tax basis in the Note. Assuming we do not defer interest payments on the Notes and the Notes are not treated as issued with OID, your tax basis in a Note will generally equal the cost of your Note. If the Notes are treated as issued (or deemed reissued) with OID, your tax basis in a Note will generally equal the cost of your Note, increased by any OID previously included in income, and decreased by payments received on the Note after the date of such issuance (or deemed reissuance). Any gain or loss will generally be U.S.-source income or loss for purposes of computing your foreign tax credit limitation.

Gain or loss realized on the sale or other taxable disposition of a Note will generally be capital gain or loss and will be long-term capital gain or loss if at the time of the sale or other taxable disposition the Note has been held for more than one year. Long-term capital gains recognized by non-corporate U.S. Holders are subject to reduced tax rates. The deductibility of capital losses is subject to limitations.

Automatic Conversion

The conversion of Notes for Conversion Preferred Shares pursuant to the Automatic Conversion should be treated as a tax-free recapitalization for U.S. federal income tax purposes. Thus, no income, gain or loss should be recognized on the conversion except to the extent that there is accrued but unpaid interest at the time of the conversion (which will be treated as such). Any Conversion Preferred Shares will be treated as first being received for the accrued but unpaid interest and the remainder will be treated as received upon conversion of the Notes. Your tax basis in the Conversion Preferred Shares received (other than any such shares received with respect to accrued interest) will equal the tax basis of the Notes that were converted. Your tax basis in the Conversion Preferred Shares received with respect to accrued interest will equal the fair market value of the shares received. Your holding period for the Conversion Preferred Shares received will include your holding period for the Notes converted, except that the holding period of any shares received with respect to accrued interest will commence on the day after the date of receipt.

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Consequences if the Notes are Treated as Equity for U.S. Federal Income Tax Purposes

If the Notes are treated as equity for U.S. federal income tax purposes, the following U.S. federal income tax consequences should result. The discussion under this section generally assumes that we are not, and will not become, a passive foreign investment company, or a PFIC, as described below.

Payments of Interest

Payments of interest on the Notes will be treated as dividends to the extent paid out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. It is expected that payments of interest on the Notes generally will be taxed as dividends.

If you are a non-corporate U.S. Holder, certain dividends paid to you by “qualified foreign corporations” may be taxed at favorable rates. However, these favorable rates are available only if certain conditions are met, including a requirement that you hold the applicable security for a minimum period during which you are not protected from the risk of loss. The IRS has ruled that where a security treated as equity for U.S. federal income tax purposes provides for repayment of the principal amount at maturity, a holder’s creditor rights with respect to the principal repayment may constitute protection from the risk of loss. Therefore, the minimum holding period requirement might not be met with respect to the Notes. If you are a non-corporate U.S. Holder, you should consult your tax adviser with respect to the “qualified dividend income” rules if the Notes are treated as equity for U.S. federal income tax purposes. Interest payments on the Notes will not be eligible for the dividends-received deduction generally available to U.S. corporations under the Code with respect to certain dividends.

The amount of dividend income will include any amounts withheld in respect of Canadian taxes and, without duplication, any additional amounts paid with respect thereto.

Interest on the Notes will be foreign-source income for foreign tax credit purposes. However, if, as described above, your creditor rights with respect to the principal repayment constitute protection from the risk of loss, you may not be able to meet the minimum holding period necessary to claim foreign tax credits in the case that any Canadian tax is withheld from interest payments.

Sale or Other Taxable Disposition of the Notes

Upon the sale or other taxable disposition of a Note, you will recognize taxable gain or loss equal to the difference between the amount realized on the sale or taxable disposition and your tax basis in the Note. Your tax basis in a Note will generally equal the cost of your Note. Gain or loss, if any, will generally be U.S.-source income or loss for purposes of computing your foreign tax credit limitation. Gain or loss realized on the sale or other taxable disposition of a Note will generally be capital gain or loss and will be long-term capital gain or loss if at the time of the sale or other taxable disposition the Note has been held for more than one year. Long-term capital gains recognized by non-corporate taxpayers are subject to reduced tax rates. The deductibility of capital losses is subject to limitations.

PFIC Rules

In general, a non-U.S. corporation will be considered a PFIC for any taxable year in which (1) 75% or more of its gross income is “passive income” under the PFIC rules or (2) 50% or more of the average quarterly value of its assets consists of assets that produce, or are held for the production of, “passive income.” For this purpose, “passive income” generally includes interest, dividends, rents, royalties and certain gains (including gains from transactions in commodities). Exclusions are provided for certain gains from commodities earned in the active conduct of a business. For purposes of determining if a non-U.S. corporation is a PFIC, if the non-U.S. corporation directly or indirectly owns at least 25% by value of the shares of another corporation, it will be treated as if it holds directly its proportionate share of the assets and receives directly its proportionate share of

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the income of such other corporation. If a corporation is treated as a PFIC with respect to you for any taxable year, it generally will continue to be treated as a PFIC with respect to you in all succeeding taxable years, regardless of whether the corporation continues to meet the PFIC requirements in such years, unless certain elections are made.

We believe that we were not a PFIC for our 2015 taxable year and do not expect to be a PFIC for our 2016 taxable year. However, because the composition of our income and assets will vary over time and because there are uncertainties in the characterization of certain of our income and assets for PFIC purposes, there can be no assurance that we will not be a PFIC for any taxable year.

If we were a PFIC for any taxable year during which you owned the Notes, gain recognized by you on a sale or other disposition of the Notes would be allocated ratably over your holding period for the Notes. The amounts allocated to the taxable year of the sale or other disposition and to any year before we became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations, as appropriate, for that taxable year, and an interest charge would be imposed on the resulting tax liability. Similar treatment may apply to certain excess distributions. Certain elections may be available that would result in alternative treatments (such as mark-to-market treatment) of the Notes. You should consult your tax adviser to determine whether any of these elections would be available and, if so, what the consequences of the alternative treatments would be in your particular circumstances.

If we were a PFIC for any taxable year during which you owned the Notes, you would generally be required to file annual returns containing such information as the IRS may require.

Conversion Preferred Shares

The discussion under this section generally assumes that we are not, and will not become, a PFIC, as described above.

Dividends

Distributions on the Conversion Preferred Shares will be treated as dividends to the extent paid out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. It is expected that distributions on the Conversion Preferred Shares generally will be taxed as dividends.

If you are a non-corporate U.S. Holder, certain dividends paid to you by “qualified foreign corporations” may be taxed at favorable rates. We expect that we will constitute a qualified foreign corporation for U.S. federal income tax purposes and that distributions on the Conversion Preferred Shares to non-corporate U.S. Holders that are treated as dividends for U.S. federal income tax purposes will be treated as qualified dividend income eligible for such reduced rates, provided the applicable holding period requirements are met. Distributions on the Conversion Preferred Shares will not be eligible for the dividends-received deduction generally available to U.S. corporations under the Code with respect to certain dividends.

The amount of dividend income will include any amounts withheld in respect of Canadian taxes.

Distributions that are treated as dividends for U.S. federal income tax purposes will be foreign-source income for foreign tax credit limitation purposes. As discussed above, withholding of Canadian tax is imposed at a 25% rate (reduced to 15% for recipients that are residents of the U.S. eligible for benefits under the Canada-United States Tax Convention) both on cash and non-cash distributions by us to persons that are not Canadian residents. Such Canadian tax withholding may exceed your allowable foreign tax credit for the taxable year of the distribution. To the extent a refund of the tax withheld is available to you under the laws of Canada or under the Canada-United States Tax Convention, the amount of tax withheld that is refundable will not be eligible for credit against your U.S. federal income tax liability, whether or not the refund is actually obtained. The foreign tax credit limitation rules are complex and dependent on the specific factual circumstances particular to you. Consequently, you should consult your tax adviser as to the U.S. federal income tax consequences relevant to you.

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Dispositions

Upon a sale or other disposition of Conversion Preferred Shares, you generally will recognize gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and your tax basis in the Conversion Preferred Shares. Gain or loss will generally be capital gain or loss and will be long-term capital gain or loss if at the time of the sale or other taxable disposition the Conversion Preferred Shares have been held for more than one year (including the holding period for the Notes, as applicable). Long-term capital gains recognized by non-corporate taxpayers are subject to reduced tax rates. The deductibility of capital losses is subject to limitations. Gain recognized by you from a sale or other disposition of Conversion Preferred Shares will generally be treated as income from U.S. sources for foreign tax credit limitation purposes.

Backup Withholding and Information Reporting

Information returns may be required to be filed with the IRS in connection with payments on the Notes and proceeds received from a sale or other disposition of the Notes and dividends received with respect to the Conversion Preferred Shares and proceeds from the disposition of those shares, unless you are an exempt recipient. You may also be subject to backup withholding on these payments in respect of your Notes or Conversion Preferred Shares unless you provide your taxpayer identification number and otherwise comply with applicable requirements of the backup withholding rules or you provide proof of an applicable exemption. Amounts withheld under the backup withholding rules are not additional taxes and may be refunded or credited against your U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

You may be required to report information relating to an interest in the Notes or Conversion Preferred Shares or an account through which the Notes or Conversion Preferred Shares are held, subject to certain exceptions (including an exception for Notes or Conversion Preferred Shares held in accounts maintained by certain U.S. financial institutions), by attaching a complete IRS Form 8938 to your tax return for each year in which you hold an interest in the Notes or Conversion Preferred Shares. You should consult your tax adviser regarding information reporting requirements relating to your ownership of the Notes or Conversion Preferred Shares.

PLAN OF DISTRIBUTION

Emera may sell Notes to or through underwriters purchasing as principal and may also sell Notes to one or more purchasers directly or through agents. Any underwriting syndicate in respect of an offering of Notes will be led by J.P. Morgan Securities LLC. Notes may be sold from time to time in one or more transactions at a fixed price or prices. If, in connection with the offering of Notes at a fixed price or prices, the underwriters have made a bona fide effort to sell all of the Notes at the initial offering price fixed in the applicable Prospectus Supplement, the public offering price may be decreased and thereafter further changed, from time to time, to an amount not greater than the initial public offering price fixed in the Prospectus Supplement in which case the compensation realized by the underwriters will be decreased by the amount that the aggregate price paid by purchasers for the Notes is less than the gross proceeds paid by the underwriters to Emera.

Any additional underwriter or agent engaged in connection with the offering and sale of a particular series or issue of Notes will be identified in a Prospectus Supplement along with the terms of the offering, including the public offering price, the proceeds to Emera and any fees, discounts or other compensation payable to the underwriters or agents.

Under agreements which may be entered into by Emera, underwriters and agents who participate in the distribution of Notes may be entitled to indemnification by Emera against certain liabilities, including liabilities arising out of any misrepresentation in this Prospectus and the documents incorporated by reference therein, other than liabilities arising out of any misrepresentation made by underwriters or agents who participate in the offering of Notes.

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There is no market through which any Notes offered hereunder may be sold. Accordingly, purchasers may not be able to resell the Notes purchased under this Prospectus. This may affect the pricing of the Notes in the secondary market, the transparency and availability of trading prices, the liquidity of the Notes, and the extent of issuer regulation. In connection with any offering of Notes, the underwriters or agents may, subject to the foregoing, over-allot or effect transactions which stabilize or maintain the market price of the Notes offered at a level above that which might otherwise prevail in the open market. Such transactions, if commenced, may be discontinued at any time. Any underwriters or agents to or through whom Notes are sold by Emera for public offering and sale may make a market in the Notes, but such underwriters or agents will not be obligated to do so and may discontinue any market making at any time without notice.

This Prospectus qualifies the Notes and the First Preferred Shares into which they are convertible for distribution under the Securities Act (Nova Scotia) in connection with sales of the Notes to purchasers in the United States and elsewhere outside Canada. This Prospectus does not qualify the distribution of any securities sold to purchasers in the Province of Nova Scotia or in any other province or territory of Canada.

EARNINGS COVERAGE RATIOS

The applicable Prospectus Supplement will provide the earnings coverage ratios with respect to the issuance of Notes pursuant to such Prospectus Supplement.

LEGAL MATTERS

Certain legal matters relating to the any offering of Notes will be passed upon on behalf of the Company by Stephen D. Aftanas, Corporate Secretary of Emera, by Davis Polk & Wardwell LLP, New York, New York, and by Osler, Hoskin & Harcourt LLP, Toronto, Ontario.

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

Ernst & Young LLP, Chartered Professional Accountants, Halifax, Nova Scotia, are the auditors of Emera. Ernst & Young LLP report that they are independent of Emera in accordance with the Rules of Professional Conduct of the Institute of Chartered Accountants of Nova Scotia.

The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting (which is included in Management’s Report on Internal Control over Financial Reporting) incorporated in this Prospectus by reference to TECO Energy’s Annual Report on Form 10-K for the year ended December 31, 2015 have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, an independent registered certified public accounting firm, given on the authority of said firm as experts in auditing and accounting.

INTERESTS OF EXPERTS

As at the date of this Prospectus, the partners and associates of Osler, Hoskin & Harcourt LLP, as a group, beneficially own, directly or indirectly, less than 1% of any class of securities of Emera.

TRANSFER AGENT, REGISTRAR, PAYING AGENT AND INDENTURE TRUSTEE

CST Trust Company will be appointed as Canadian trustee, Canadian registrar, Canadian paying agent and Canadian transfer agent in respect of the Notes and American Stock Transfer & Trust Company, LLC will be appointed as U.S. trustee, U.S. registrar, U.S. paying agent and U.S. transfer agent in respect of the Notes. The Notes will be issued in book-entry only form through the Clearing Agency. See “Description of the Notes—Book-Entry Only Form”.

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ENFORCEMENT OF CIVIL LIABILITIES

Emera is incorporated in Nova Scotia. Some of the directors and officers of Emera, and some of the experts named in this Prospectus, are residents of Canada or otherwise reside outside the U.S., and all or a substantial portion of their assets, and a substantial portion of the assets of Emera, are located outside the U.S. Emera has appointed an agent for service of process in the U.S., but it may be difficult for holders of the Notes who reside in the U.S. to effect service within the U.S. upon those directors, officers and experts who are not residents of the U.S. It may also be difficult for holders of the Notes who reside in the U.S. to realize in the U.S. upon judgments of courts of the U.S. predicated upon the civil liability of Emera and the civil liability of the directors and officers of Emera and experts under U.S. federal securities laws.

Emera has been advised by its Canadian counsel, Osler, Hoskin & Harcourt LLP, that a judgment of a U.S. court predicated solely upon civil liability under U.S. federal securities laws would probably be enforceable in Canada if the U.S. court in which the judgment was obtained has a basis for jurisdiction in the matter that would be recognized by a Canadian court for the same purposes. Emera has also been advised by Osler, Hoskin & Harcourt LLP, however, that there is real doubt whether an action could be brought in Canada in the first instance on the basis of liability predicated solely upon U.S. federal securities laws.

J. Wayne Leonard and Richard P. Sergel, two of the Company’s directors, reside outside of Canada and have appointed Emera Incorporated, 5151 Terminal Road, Halifax, Nova Scotia B3J 1A1 as agent for service of process. Purchasers are advised that it may not be possible for investors to enforce judgments obtained in Canada against any person that resides outside of Canada, even if such person has appointed an agent for service of process.

Emera filed with the SEC, concurrently with its registration statement on Form F-10, an appointment of agent for service of process on Form F-X. Under the Form F-X, Emera appointed Emera US Finance LP as its agent for service of process in the U.S. in connection with any investigation or administrative proceeding conducted by the SEC, and any civil suit or action brought against or involving Emera in a U.S. court arising out of or related to or concerning an offering of securities under this Prospectus.

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PART II

INFORMATION NOT REQUIRED TO BE

DELIVERED TO OFFEREES OR PURCHASERS

Indemnification of Certain Persons

Emera Incorporated

Under Emera Incorporated’s (“Emera” or the “Registrant”) Amended Articles of Association, the Registrant must indemnify directors and officers, each former director and officer and each other individual who acts or acted at the Registrant’s request as a director or officer or in a similar capacity of an Other Entity (as defined below) and their respective heirs and legal representatives against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by any such person in respect of any civil, criminal, administrative, investigative, arbitration, mediation, or other proceeding or investigation to which he is made a party or involved in by reason of being or having been a director or officer of the Registrant or such Other Entity at the request of the Registrant or in a similar capacity, provided that: (i) the individual acted honestly and in good faith with a view to the best interests of the Registrant or, as the case may be, to the best interest of the Other Entity for which the individual acted as a director or officer or in a similar capacity at the Registrant’s request; and (ii) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, the individual had reasonable grounds to believe that his conduct was lawful. The Registrant shall, to the full extent permitted by law, advance funds to an individual referred to above for any costs, charges and expenses of a proceeding or investigation provided that such individual shall repay the funds advanced if the individual does not fulfill the conditions of indemnification. The right of any person to indemnification granted is not exclusive of any other rights to which any person seeking indemnification may be entitled under any agreement, resolution or other vote of shareholders or directors, at law or otherwise; and the amount for which such indemnity is proved immediately attaches as a lien on the property of the Registrant and has priority against the members over all other claims. The term “Other Entity” means any affiliate or subsidiary of the Registrant, and any other body corporate, corporation, limited liability company, partnership, joint venture, trust, unincorporated association, unincorporated organization, unincorporated syndicate or other enterprise in which the Registrant, directly or indirectly, now or in the future, holds an interest, whether in debt, equity or otherwise, for which the director, officer or other individual serves or served as a director or officer or in a capacity similar thereto at the request of the Registrant. In addition, no director or officer of the Registrant shall, in the absence of any dishonesty on the part of such director or officer, be liable for the acts, receipts, neglects or defaults of any other director or officer or for joining in any receipt or other act for conformity, or for any loss or expense happening to the Registrant through the insufficiency or deficiency of title to any property acquired by order of the directors for or on behalf of the Registrant, or through the insufficiency or deficiency of any security in or upon which any of the funds of the Registrant are invested, or for any loss or damage arising from the bankruptcy, insolvency or tortious act of any person with whom any funds, securities or effects are deposited, or for any loss occasioned by error of judgment or oversight on his or her part, or for any other loss, damage or misfortune whatsoever which happens in the execution of the duties of his or her office or in relation thereto. The Registrant purchases directors’ and officers’ insurance which provides protection for directors and officers in cases where they incur a liability as a result of their activities on behalf of the Registrant.

Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended, may be permitted to directors, officers or persons controlling Emera pursuant to the foregoing provisions, Emera has been informed that in the opinion of the U.S. Securities and Exchange Commission such indemnification is against public policy as expressed in the Public Utilities Act and is therefore unenforceable.

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EXHIBITS

Exhibit Number	Description
*4.1	Annual Information Form of Emera dated March 30, 2016 for the year ended December 31, 2015.
*4.2	Audited consolidated financial statements of Emera as at and for the years ended December 31, 2015 and December 31, 2014, together with the auditors’ report thereon.
*4.3	Management’s Discussion and Analysis of Emera for the year ended December 31, 2015.
*4.4	Unaudited condensed consolidated interim financial statements of Emera as at and for the three months ended March 31, 2016 and March 31, 2015.
*4.5	Management’s Discussion and Analysis of Emera for the three months ended March 31, 2016.
*4.6	Management Information Circular of Emera distributed in connection with Emera’s annual meeting of shareholders held on May 17, 2016.
*4.7	Audited financial statements of TECO Energy, Inc. contained in TECO Energy, Inc.’s Annual Report on Form 10-K filed with the SEC for the year ended December 31, 2015.
*4.8	Management’s Report on Internal Control over Financial Reporting of TECO Energy contained in TECO Energy, Inc.’s Annual Report on Form 10-K filed with the SEC for the year ended December 31, 2015.
*4.9	Unaudited consolidated financial statements of TECO Energy, Inc. contained in TECO Energy, Inc.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2016.
*4.10	Consent of Osler, Hoskin & Harcourt LLP.
*5.1	Consent of PricewaterhouseCoopers LLP.
*5.2	Consent of Ernst & Young LLP.
*5.3	Consent of Osler, Hoskin & Harcourt LLP.
*5.4	Consent of Davis Polk & Wardwell LLP.
**6.1	Power of Attorney.
*7.1	Form of Indenture among Emera, American Stock Transfer & Trust Company, LLC, as U.S. trustee, and CST Trust Company, as Canadian trustee.
**7.2	Statement of Eligibility under the Trust Indenture Act of 1939, of American Stock Transfer & Trust Company, LLC, as U.S. trustee for the indenture referenced at exhibit 7.1 above.

* Filed herewith.

** Previously filed with the Registrant’s Form F-10 filed with the Securities and Exchange Commission on June 1, 2016.

II-2

PART III

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Item 1. Undertaking

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to the securities registered pursuant to Form F-10 or to transactions in said securities.

Item 2. Consent to Service of Process

(a) Concurrent with the filing of the Registration Statement on Form F-10, the Registrant filed with the Commission a written irrevocable consent and power of attorney on Form F-X.

(b) Concurrent with the filing of the Registration Statement on Form F-10, CST Trust Company, Canadian trustee under the Indenture, filed with the Commission a written irrevocable consent and power of attorney on Form F-X.

(c) Any change to the name or address of the agent for service of the Registrant or the trustee shall be communicated promptly to the Commission by amendment to Form F-X referencing the file number of the relevant registration statement.

III-1

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-10 and has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Halifax, Province of Nova Scotia, Country of Canada, on the 8^th day of June, 2016.

EMERA INCORPORATED
By:	/s/ CHRISTOPHER G. HUSKILSON
	Name: Christopher G. Huskilson
	Title:   President and Chief Executive Officer
By:	/s/ GREGORY W. BLUNDEN
	Name: Gregory W. Blunden
	Title:   Chief Financial Officer

III-2

Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 1 to the Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
* Christopher G. Huskilson	President, Chief Executive Officer (Principal Executive Officer)	May 31, 2016
* Gregory W. Blunden	Chief Financial Officer (Principal Financial and Accounting Officer)	May 31 , 2016
* M. Jacqueline Sheppard	Chair and Director	May 31, 2016
* Sylvia D. Chrominska	Director	May 31, 2016
* Henry E. Demone	Director	May 31, 2016
* Allan L. Edgeworth	Director	May 31, 2016
* James D. Eisenhauer	Director	May 31, 2016
* J. Wayne Leonard	Director	May 31, 2016
* B. Lynn Loewen, FCA	Director	May 31, 2016
* John T. McLennan	Director	May 31, 2016
* Donald A. Pether	Director	May 31, 2016
* Andrea S. Rosen	Director	May 31, 2016
* Richard P. Sergel	Director	May 31, 2016

*By:	/s/ STEPHEN D. AFTANAS
	Name: Stephen D. Aftanas
	Title:   Attorney-in-fact

III-3

AUTHORIZED REPRESENTATIVE

Pursuant to the requirements of Section 6(a) of the Securities Act of 1933, the undersigned has signed this Amendment No. 1 to the Registration Statement, solely in the capacity of the duly authorized representative of Emera Incorporated in the United States, on June 8, 2016 in the City of Halifax, Province of Nova Scotia, Country of Canada.

EMERA US FINANCE LP
By:	/s/ CHRISTOPHER G. HUSKILSON
	Name: Christopher G. Huskilson
	Title: President

By:	/s/ STEPHEN D. AFTANAS
	Name: Stephen D. Aftanas
	Title: Secretary

III-4

EXHIBIT INDEX

Exhibit Number	Description
*4.1	Annual Information Form of Emera dated March 30, 2016 for the year ended December 31, 2015.
*4.2	Audited consolidated financial statements of Emera as at and for the years ended December 31, 2015 and December 31, 2014, together with the auditors’ report thereon.
*4.3	Management’s Discussion and Analysis of Emera for the year ended December 31, 2015.
*4.4	Unaudited condensed consolidated interim financial statements of Emera as at and for the three months ended March 31, 2016 and March 31, 2015.
*4.5	Management’s Discussion and Analysis of Emera for the three months ended March 31, 2016.
*4.6	Management Information Circular of Emera distributed in connection with Emera’s annual meeting of shareholders held on May 17, 2016.
*4.7	Audited financial statements of TECO Energy, Inc. contained in TECO Energy, Inc.’s Annual Report on Form 10-K filed with the SEC for the year ended December 31, 2015.
*4.8	Management’s Report on Internal Control over Financial Reporting of TECO Energy contained in TECO Energy, Inc.’s Annual Report on Form 10-K filed with the SEC for the year ended December 31, 2015.
*4.9	Unaudited consolidated financial statements of TECO Energy, Inc. contained in TECO Energy, Inc.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2016.
*4.10	Consent of Osler, Hoskin & Harcourt LLP.
*5.1	Consent of PricewaterhouseCoopers LLP.
*5.2	Consent of Ernst & Young LLP.
*5.3	Consent of Osler, Hoskin & Harcourt LLP.
*5.4	Consent of Davis Polk & Wardwell LLP.
**6.1	Power of Attorney.
*7.1	Form of Indenture among Emera, American Stock Transfer & Trust Company, LLC, as U.S. trustee, and CST Trust Company, as Canadian trustee.
**7.2	Statement of Eligibility under the Trust Indenture Act of 1939, of American Stock Transfer & Trust Company, LLC, as U.S. trustee for the indenture referenced at exhibit 7.1 above.

* Filed herewith.

** Previously filed with the Registrant’s Form F-10 filed with the Securities and Exchange Commission on June 1, 2016.

III-5

EX-4.1

Exhibit 4.1

Exhibit 4.1
2015
Annual Information Form
Emera Incorporated
March 30, 2016
Emera

2015 Annual Information Form 1

Table of Contents

Definitions	2-9
Cautionary Note Regarding Forward - Looking Information	10-11
Introduction	12
Corporate Structure	13
General Development of the Business	13
Emera Business and Operations Three-Year History	13-23
Financing Activity	23-27
Changes in Business Expected During 2016	27-31
Description of the Business	31-32
NSPI	32-34
Emera Maine	34-37
Emera Caribbean	37-40
Emera Energy	40-42
Pipelines	42-43
Corporate and Other	43
Risk Factors	43
Capital Structure	43
Common Shares	44
Emera First Preferred Shares	44-49
Emera Second Preferred Shares	49
Share Ownership Restrictions	49
NSPI Series D First Preferred Shares	49
Dividends	50-51
Credit Ratings	51-52
Market for Securities	53-54
Directors	55-56
Audit Committee	56-58
Officers	59-60
Certain Proceedings	61
Legal Proceedings and Regulatory Actions	61
No Interest of Management and Others in Material Transactions	61
Material Contracts	62
Experts	62
Additional Information	62
Appendix “A”- Audit Committee Charter	63-68

2015 Annual Information Form 2

DEFINITIONS

For convenience, terms used throughout this 2015 AIF of Emera Incorporated shall have the following meanings:

“Adjusted net income” means net income attributable to common shareholders, as defined by USGAAP excluding the effect of after-tax mark-to-market adjustments related to certain derivative instruments, the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp and NWP, the mark-to-market adjustments related to an interest rate swap in EBPC, the mark-to-market adjustments related to the effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering for the TECO Transaction and the mark-to-market adjustments included in Emera Energy’s margin, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered and the amortization of transportation capacity recognized as a result of certain marketing and trading transactions. See the “Non-GAAP Financial Measures” section of the MD&A for the year ended December 31, 2015, which is incorporated herein by reference;

“AFUDC” means allowance for funds used during construction and represents the cost of financing regulated construction projects and is capitalized to the cost of property, plant and equipment, where permitted by the regulator;

“AIF” means this 2015 Annual Information Form of Emera;

“APUC” means Algonquin Power & Utilities Corp., a company incorporated under the federal laws of Canada and traded on the TSX under the symbol “AQN”;

“Atlantic Provinces” means the region of Canada consisting of the Provinces of New Brunswick, Newfoundland and Labrador, Nova Scotia and Prince Edward Island;

“Bangor Hydro” means Bangor Hydro Electric Company, a transmission and distribution electric utility company incorporated under the laws of the State of Maine and a wholly owned, indirect subsidiary of Emera which merged on January 1, 2014 with MPS to form Emera Maine;

“Bangor Hydro District” means the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis and Aroostook;

“Bayside Power LP” means Bayside Power Limited Partnership, a 290 MW gas-fired electricity generating facility and limited partnership governed by the laws of the Province of New Brunswick and wholly owned indirectly by Emera;

“BBD” means Barbadian dollars;

“Bear Swamp” means Bear Swamp Power Company, LLC, a 600 MW pumped storage hydroelectric company incorporated under the laws of the State of Delaware in which Emera indirectly holds a 50% interest;

“BLPC” means The Barbados Light & Power Company Limited, a vertically integrated electric utility company incorporated under the laws of Barbados and a wholly owned, direct subsidiary of Emera (Caribbean) Incorporated;

“Board” means the Board of Directors of Emera;

“Brooklyn Energy” means Brooklyn Power Corporation, a 30 MW biomass co-generation company incorporated under the laws of the Province of Nova Scotia and a wholly owned indirect subsidiary of Emera;

2015 Annual Information Form 3

“Brunswick Pipeline” means the pipeline delivering re-gasified natural gas from the Canaport LNG gas terminal near Saint John, New Brunswick to markets in the Northeastern United States, which is owned directly by EBPC. The pipeline travels through southwest New Brunswick and connects with M&NP at the Canada/US border near Baileyville, Maine;

“Bull Hill” means Blue Sky East, LLC, a company incorporated under the laws of the State of Delaware which owns a 34.5 MW wind farm located south of Bangor, Maine, and in which Emera held an indirect interest of 49% through its joint venture with First Wind in NWP until January 29, 2015, when Emera sold its interest in NWP;

“CAD” means Canadian dollars;

“CEO” means the President and Chief Executive Officer of Emera;

“Company” means Emera;

“Completion Guarantee” means a completion guarantee granted by Emera in favour of the Government of Canada under which Emera has guaranteed the performance of the obligations of NSP Maritime Link Inc. to cause the completion of the Maritime Link Project in the circumstances and within the timelines provided for in the Completion Guarantee. The Payment Obligation Agreement (as defined below) and Completion Guarantee collectively satisfy the requirement in the FLG term sheet to deliver the “Emera Guarantee Agreement”;

“Computershare” means Computershare Trust Company of Canada;

“Corporate and Other” means Emera’s consolidated investment in Emera Utility Services, Emera Reinsurance Limited and Emera’s non-consolidated investments in ENL, NSP Maritime Link Inc., LIL, APUC and OpenHydro. Corporate and Other also includes other investments and interest revenue on intercompany financings and costs allocated to corporate activities not directly associated with operations, including without limitation, the acquisition costs for the TECO Transaction and the mark-to-market adjustments related to the effect of USD-denominated currency and forward contracts to economically hedge the anticipated proceeds from the Debenture Offering for the TECO Transaction;

“CST” means CST Trust Company;

“DBRS” means the credit rating agency Dominion Bond Rating Service Limited;

“Debentures” means the 4.0% convertible unsecured subordinated debentures of Emera that were issued on September 28 and October 2, 2015 in order to finance a portion of the TECO Transaction;

“Debenture Offering” means the sale of the Debentures by the Selling Debentureholder;

“Directors” mean the directors of Emera and “Director” means one of them;

“Dividend Reinvestment Plan” means the Common Shareholders’ Dividend Reinvestment and Share Purchase Plan;

“Domlec” means Dominica Electricity Services Limited, an integrated electric utility on the island of Dominica, incorporated under the laws of the Commonwealth of Dominica, and an indirect subsidiary of Emera, through Emera (Caribbean) Incorporated;

“DR” means depositary receipt;

“EBH2” means Emera (Barbados) Holdings No. 2 Inc., an indirect wholly owned subsidiary of Emera;

2015 Annual Information Form 4

“EBPC” means Emera Brunswick Pipeline Company Ltd., a company incorporated under the federal laws of Canada and a wholly owned, direct subsidiary of Emera;

“ECC” means NSPI Energy Control Center;

“ECHL” means Emera Caribbean Holdings Limited (formerly Emera Caribbean Limited), a company incorporated under the laws of Barbados and a wholly owned, direct subsidiary of Emera and the direct or indirect parent company of ICDU, GBPC, Emera (Caribbean) Incorporated, BLPC and Domlec;

“ECI” means Emera (Caribbean) Incorporated (formerly Light & Power Holdings Ltd.), a company incorporated under the laws of Barbados and which is an indirect subsidiary of ECHL and the parent company of BLPC;

“EE New England Gas Generation” means Emera Energy Generation II LLC, a company incorporated under the laws of the State of Delaware that holds the New England Gas Generation Facilities and a wholly owned, direct subsidiary of Emera;

“Electricity Plan Act” means the Electricity Plan Implementation (2015) Act;

“Emera” means Emera Incorporated, a public company incorporated under the laws of the Province of Nova Scotia and traded on the TSX under the symbol “EMA”;

“Emera Caribbean” means Emera’s direct and indirect ownership interests in ECHL, Emera (Caribbean) Incorporated, BLPC, Domlec, GBPC, Emera Utility Services Bahamas and Lucelec;

“Emera Energy” means Emera Energy Incorporated, a wholly owned, direct subsidiary of Emera, amalgamated under the laws of the Province of Nova Scotia, and whose business collectively includes the businesses of Emera Energy Services and Emera Energy Generation;

“Emera Energy Generation” means, collectively, EE New England Gas Generation, Bayside Power LP and Brooklyn Energy;

“Emera Energy Services” means Emera Energy Services, Inc., a natural gas and electricity marketing and trading company incorporated under the laws of the State of Delaware and a wholly owned, indirect subsidiary of Emera Energy;

“Emera Guarantee Agreement” means the condition precedent in the FLG term sheet to deliver to the Government of Canada a guarantee of certain payment and performance obligations, which condition precedent was satisfied collectively by the Completion Guarantee (as defined above) and the Payment Obligation Agreement (as defined below);

“Emera Maine” means the company resulting from the merger of Bangor Hydro and MPS under the laws of the State of Maine on January 1, 2014, and a wholly owned indirect subsidiary of Emera;

“Emera Reinsurance Limited” is a captive insurance company incorporated under the laws of Barbados providing insurance and reinsurance to Emera and certain affiliates, to enable more cost efficient management of risk and deductible levels across Emera.

“Emera Utility Services” means Emera Utility Services Inc., a company incorporated under the laws of the Province of New Brunswick and a wholly owned direct subsidiary of Emera, which provides utility construction services in the Atlantic Provinces;

2015 Annual Information Form 5

“Emera Utility Services Bahamas” means Emera Utility Services (Bahamas) Limited, a company incorporated under the laws of the Commonwealth of The Bahamas and a wholly owned indirect subsidiary of Emera ,which provides utility construction services in The Bahamas;

“ENL” means Emera Newfoundland and Labrador Holdings Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly owned, direct subsidiary of Emera, and the parent company of NSP Maritime Link Inc. and ENL Island Link Inc.;

“ENL Island Link Inc.” means ENL Island Link Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly owned, direct subsidiary of ENL;

“Fair Trading Commission, Barbados” means the independent regulator of BLPC;

“FAM” means the fuel adjustment mechanism established by the UARB;

“FERC” means the United States Federal Energy Regulatory Commission;

“Final Instalment” means the remaining $667 per Debenture that is payable on the Final Instalment Date;

“Final Instalment Date” means the date to be fixed following satisfaction of conditions precedent to the closing of the TECO Transaction;

“First Wind” means First Wind Holdings LLC, a company incorporated under the laws of the State of Delaware;

“GBPA” means The Grand Bahama Port Authority, regulator of GBPC;

“GBPC” means Grand Bahama Power Company Limited, a vertically integrated electric utility company incorporated under the laws of the Commonwealth of The Bahamas and a direct and indirect subsidiary of ECHL;

“Government of Canada Bond Yield” means the yield to maturity on such date (assuming semi-annual compounding) of a Canadian dollar denominated non-callable Government of Canada bond with a term to maturity of five years as quoted as of 10:00 a.m. (Toronto time) on such date and which appears on the Bloomberg Screen GCAN5YR Page on such date; provided that, if such rate does not appear on the Bloomberg Screen GCAN5YR Page on such date, the Government of Canada Bond Yield will mean the average of the yields determined by two registered Canadian investment dealers selected by the Company, as being the yield to maturity on such date (assuming semi-annual compounding) which a Canadian dollar denominated non-callable Government of Canada bond would carry if issued in Canadian dollars at 100% of its principal amount on such date with a term to maturity of five years;

“Government of Canada T-bill Rate” means, for any quarterly floating rate period, the average yield expressed as a percentage per annum on three month Government of Canada treasury bills, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable floating rate calculation date;

“GRA” means a general rate application;

“GWh” means the amount of electricity measured in gigawatt hours;

“ICDU” means ICD Utilities Limited, a company incorporated under the laws of the Commonwealth of The Bahamas, traded on the Bahamas International Securities Exchange (BISX) under the symbol “ICD” and a direct subsidiary of ECHL;

“IFRS” means International Financial Reporting Standards;

2015 Annual Information Form 6

“IPPs” means independent power producers;

“IRCD” means the Independent Regulatory Commission, Dominica, the independent regulator of Domlec;

“ISO-NE” means ISO-New England, an independent, non-profit Regional Transmission Organization which oversees the operation of New England’s bulk electric power system and transmission lines, generated and transmitted by its member utilities;

“km” means kilometres;

“Labrador-Island Transmission Link Project” or “LIL” means an electricity transmission project in Newfoundland and Labrador being developed by Nalcor, which will enable the transmission of the Muskrat Falls energy between Labrador and the island of Newfoundland;

“Labrador Transmission Assets” means an electricity transmission project in Labrador between Muskrat Falls and Churchill Falls;

“LNG” means liquefied natural gas;

“Lower Churchill Project Phase I” means the development of the Muskrat Falls Generating Station and associated transmission assets and the Labrador-Island Transmission Link Project;

“LPH” means Light & Power Holdings Ltd., the former name of ECI;

“Lucelec” means St. Lucia Electricity Services Limited, a company incorporated under the laws of St. Lucia in which Emera holds an indirect 18.2% interest through ECHL;

“M&NP” means the Maritimes & Northeast Pipeline, a pipeline that transports natural gas from offshore Nova Scotia to markets in the Maritime Provinces and New England, in which Emera holds an indirect 12.9% interest;

“Make-Whole Payment” means an amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Debenture Offering had the Debentures remained outstanding and continued to accrue interest until and including such date;

“MAM” means Maine & Maritimes Corporation, a company incorporated under the laws of the State of Maine, the parent company of MPS, and a wholly owned, indirect subsidiary of Emera; MAM was dissolved when MPS and Bangor Hydro merged on January 1, 2014, forming Emera Maine;

“Maritime Link” or “NSP Maritime Link Inc.” means NSP Maritime Link Incorporated, a wholly owned direct subsidiary of ENL incorporated under the laws of the Province of Newfoundland and Labrador that is developing the Maritime Link Project;

“Maritime Link Project” means the transmission project including two 170-kilometre sub-sea cables between the island of Newfoundland and the Province of Nova Scotia, being developed by NSP Maritime Link Inc.;

“Maritime Provinces” means the region of Canada consisting of the Provinces of Nova Scotia, New Brunswick and Prince Edward Island;

2015 Annual Information Form 7

“MD&A” means Emera’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2015, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com;

“MLFT” means Maritime Link Financing Trust, a special purpose funding vehicle formed by Emera;

“MMSCFD” means million standard cubic feet per day;

“MPS” means Maine Public Service Company, a transmission and distribution electric utility company incorporated pursuant to the laws of the State of Maine, and a wholly owned, direct subsidiary of MAM which merged on January 1, 2014 with Bangor Hydro to form Emera Maine;

“MPS District” means the franchise electric service territory associated with MPS in northern Maine;

“MPUC” means the Maine Public Utilities Commission, the independent regulator of Emera Maine and of Bangor Hydro and MPS prior to their merger effective January 1, 2014 to form Emera Maine;

“MW” means the amount of electricity measured in megawatts;

“Muskrat Falls Generating Station” means a hydroelectric generating facility at Muskrat Falls being developed by Nalcor on the Lower Churchill River in Labrador;

“Nalcor” means Nalcor Energy, a Newfoundland and Labrador provincial Crown corporation;

“NB Power” means New Brunswick Power, a provincial Crown Corporation responsible for the generation, transmission and distribution of electricity in the Province of New Brunswick;

“NEB” means the Canadian National Energy Board, the independent regulator of EBPC;

“NERC” means North American Electric Reliability Corporation;

“New England” means the region of the Northeastern United States consisting of the States of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont;

“New England Gas Generation Facilities” means a three-facility, 1,090 MW combined-cycle gas-fired electricity generating investment in the Northeastern United States, comprising Bridgeport Energy (560 MW) in Bridgeport, Connecticut; Tiverton Power (265 MW) in Tiverton, Rhode Island; and Rumford Power (265 MW) in Rumford, Maine;

“New England Transmission Operators” means transmission utilities in the ISO-NE territory;

“NLPUB” means Newfoundland and Labrador Board of Commissioners of Public Utilities;

“Northeastern United States” means the region of the United States consisting of New England and the States of New Jersey, New York and Pennsylvania;

“NSPI” or “Nova Scotia Power” means Nova Scotia Power Incorporated, a vertically integrated electric utility incorporated under the laws of the Province of Nova Scotia and a wholly owned direct and indirect subsidiary of Emera;

“NSPI’s Annual Information Form” means the 2015 Annual Information Form of NSPI dated March 30, 2016, a copy of which is available electronically under NSPI’s profile on SEDAR at www.sedar.com;

2015 Annual Information Form 8

“NSPI Board” means the Board of Directors of NSPI;

“NSPI Series D First Preferred Shares” means the cumulative redeemable first preferred shares, Series D of NSPI;

“NWP” means Northeast Wind Partners II, LLC, a company formerly owned 51% by First Wind and 49% by Emera. Emera sold its investment in NWP on January 29, 2015;

“OATT” means open access transmission tariff;

“Officers” mean the Executive Officers of Emera and “Officer” means any one of them;

“Order” means a cease trade order, an order similar to a cease trade order or an order that denies a company access to any exemption under securities legislation that was in effect for a period of more than thirty (30) consecutive days;

“Payment Obligation Agreement” means a payment obligation agreement between Emera, NSP Maritime Link Inc. and the Government of Canada, which together with the Completion Guarantee (as defined above) collectively satisfy the requirement in the FLG term sheet to deliver the “Emera Guarantee Agreement”;

“Pipelines” means EBPC, and Emera’s interest in M&NP;

“Province” means a province of Canada and includes, when the context requires, the provincial government;

“Public Utilities Act” means the Public Utilities Act (Nova Scotia);

“Rating Agencies” means collectively DBRS and S&P, and “Rating Agency” means one of the Rating Agencies;

“RECL” means Repsol Energy Canada Ltd.;

“Repsol” means Repsol YPF, S.A, the parent company of RECL;

“ROE” means return on equity;

“S&P” means the credit rating agency Standard & Poor’s Rating Services;

“Sable Wind Project” means a 13.8 MW wind farm near Canso, Nova Scotia;

“SEDAR” means the System for Electronic Documents Analysis and Retrieval;

“Selling Debentureholder” means Emera Holdings NS Company, a company incorporated under the laws of the Province of Nova Scotia and a wholly owned direct subsidiary of Emera;

“Series A First Preferred Shares” means the cumulative 5-year rate reset first preferred shares, Series A of Emera;

“Series B First Preferred Shares” means the cumulative floating rate first preferred shares, Series B of Emera;

“Series C First Preferred Shares” means the cumulative rate reset first preferred shares, Series C of Emera;

“Series D First Preferred Shares” means the cumulative floating rate first preferred shares, Series D of Emera;

“Series E First Preferred Shares” means the cumulative redeemable first preferred shares, Series E of Emera;

2015 Annual Information Form 9

“Series F First Preferred Shares” means the cumulative redeemable rate reset first preferred shares, Series F of Emera;

“Series G First Preferred Shares” means the cumulative floating rate first preferred shares, Series G of Emera;

“SIA” means the Strategic Investment Agreement dated April 29, 2011 between Emera and APUC;

“South Canoe Wind Project” means a wind farm project approved by the Municipality of the District of Chester on March 14, 2013;

“State” means a state of the United States and includes, when the context requires, the state government;

“TECO Energy” means TECO Energy, Inc., an energy-related holding company incorporated under the laws of the State of Florida with regulated electric and gas utilities in Florida and New Mexico and traded on the New York Stock Exchange under the symbol “TE”.

“TECO Transaction” means the pending acquisition by Emera of TECO Energy;

“TSX” means The Toronto Stock Exchange;

“U.S.” means the United States;

“UARB” means the Nova Scotia Utility and Review Board, the independent regulator of NSPI;

“United States” means the United States of America;

“USD” means U.S. dollars;

“USGAAP” means the accounting principles which are recognized as being generally accepted and which are in effect from time to time in the U.S. as codified by the Financial Accounting Standards Board, or any successor institute; and

“West Sunrise Plant” means GBPC’s 52 MW electricity generation plant located on Grand Bahama Island.

All amounts are in CAD except where otherwise stated.

Reference to “including”, “include”, or “includes” means “including (or includes) but is not limited to” and shall not be construed to limit any general statement preceding it to the specific or similar items or matters immediately following it.

The information presented in this AIF is as of December 31, 2015, unless otherwise specified.

2015 Annual Information Form 10

CAUTIONARY NOTE REGARDING FORWARD – LOOKING INFORMATION

This AIF, including the documents incorporated herein by reference, contains “forward-looking information” and “forward-looking statements” within the meaning of applicable securities laws (collectively, “forward-looking information”). The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecast”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “targets, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. References to “Emera” in this section include references to the subsidiaries of Emera.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements which reflect the current view of Emera’s management with respect to, among other things, Emera’s objectives, plans, financial and operating performance, business prospects and opportunities. The forward-looking information reflects Emera’s managements’ current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or at times which, such events, performance or results will be achieved. All such forward-looking information in this AIF is provided pursuant to safe harbour provisions contained in applicable securities laws.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements regarding: Emera’s revenue, earnings and cash flow; the growth and diversification of Emera’s business and earnings base; future annual earnings growth; expansion of Emera’s business in the U.S. and elsewhere; the completion of announced acquisitions, including the TECO Transaction; the expected compliance by Emera with the regulation of its operations; the expected timing of regulatory decisions; forecasted capital expenditures; the nature, timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; expectations related to annual operating cash flows; the expectation that Emera will continue to have reasonable access to capital in the near to medium term; expected debt maturities and repayments; expectations about increases in interest expense and/or fees associated with credit facilities; no material adverse credit rating actions being expected in the near term; the number of customers served in the future; the successful execution of relationships with third-parties, such as agreements relating to the Maritime Link Project, Muskrat Falls and the Assembly of Nova Scotia Mi’Kmaq Chiefs; the impact of currency fluctuations; expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within Northeastern United States.

The forecasts and projections that make up the forward-looking information are based on reasonable assumptions which include: the receipt of applicable regulatory approvals and requested rate decisions, including with respect to the TECO Transaction; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain transmission and distribution systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and commodity prices; no significant variability in interest rates; the impact of the TECO Transaction on earnings, assets and Emera’s customer base; the ability to receive permanent financing with respect to the TECO Transaction; the continued competitiveness of electricity pricing when compared with other alternative sources of energy; the continued availability of commodity supply; the absence of significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of

2015 Annual Information Form 11

Emera; maintenance of adequate insurance coverage; the ability to obtain and maintain licenses and permits; no material decrease in market energy sales prices; favourable labour relations; and sufficient human resources to deliver service and execute the capital program.

The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations include: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; capital market and liquidity risk; the completion of the TECO Transaction, including uncertainty regarding the length of time required to complete the TECO Transaction; future dividend growth; timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology; weather; commodity price risk; construction and development risk; unanticipated maintenance and other expenditures; derivative financial instruments and hedging availability and inability to complete the Debenture Offering ; failure by Emera to repay the acquisition credit facilities relating to the TECO Transaction; potential unavailability of the acquisition credit facilities relating to the TECO Transaction; alternate sources of funding that would be used to replace the acquisition credit facilities relating to the TECO Transaction may not be available when needed; impact of acquisition related expenses; interest rate risk; credit risk; rating agency risk; commercial relationship risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; market energy sales prices; labour relations; and availability of labour and management resources.

For additional information with respect to Emera’s risk factors, reference should be made to the section of this AIF entitled “Risk Factors”.

Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this AIF and in the documents incorporated herein by reference is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

2015 Annual Information Form 12

INTRODUCTION

Emera is a geographically diverse energy and services company with approximately $12 billion in assets and 2015 revenues of $2.79 billion. Emera invests in electricity generation, transmission and distribution, gas transmission and utility services. Emera’s business continues to grow and evolve. Meeting customer demand for cleaner affordable energy remains central to Emera’s strategy.

Utilities

Regulated utilities are the foundation of Emera’s business, providing the company with strong and consistent earnings. From its beginnings as NS Power Holdings Incorporated in 1998 following the privatization of Nova Scotia Power Corporation in 1992, Emera has grown by investing in its businesses, and through strategic acquisitions. Emera became an international business with the acquisition of Bangor Hydro in 2001, and expanded its investment in the State of Maine by adding Maine & Maritimes Corporation (MAM) in 2010. In the Caribbean, Emera has built a business of scale, starting with its investment in St. Lucia’s electric utility (Lucelec) in 2007, and now holding an indirect majority ownership interest in electric utilities in Barbados, Grand Bahama and Dominica.

At the core of Emera’s utilities strategy is identifying opportunities to invest in the transition from higher carbon methods of electricity generation to lower carbon alternatives. NSPI has invested in wind energy, biomass and hydroelectricity with the result that in 2015, 27% of NSPI’s generation mix was derived from renewable sources, and on track to meet a minimum 40% renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives, with an emphasis on affordability and fuel cost stability for its customers.

Transmission

Emera is investing in electricity transmission to help get new renewable energy to market. Emera’s leadership in the Maritime Link Project is expected to transform the electricity market in the Atlantic Provinces, enabling growth in the availability of clean, renewable energy for the region. In addition, the Atlantic Provinces will be connected to the Northeastern United States, providing potential for excess renewable energy to be delivered throughout that region.

Non-regulated

Since its formation in 2003, Emera Energy has become a leader in the Northeastern United States electricity and natural gas marketplace. It has built a strong marketing, trading and asset management business, based on comprehensive market knowledge, a focus on customer service and strong risk management. The integration and performance of the three New England Gas Generating Facilities purchased in 2013 has contributed significantly to the success of Emera Energy. Natural gas is an effective and reliable back-up for intermittent renewable sources and is a cleaner alternative to other fossil fuels. Emera Energy has invested to improve the performance of its natural gas generation assets in New England, creating long-term value for its business.

As it has grown, Emera has held true to the core values that guide its business: building relationships of integrity, focusing on operations and service excellence, investing in its people, and making safety and health its foremost priority. For more information on the business operations of the Company, refer to the “Description of the Business” section below.

2015 Annual Information Form 13

CORPORATE STRUCTURE

Name and Incorporation

Emera Incorporated was incorporated on July 23, 1998 pursuant to the Companies Act (Nova Scotia). Emera’s principal, head and registered office is located at 5151 Terminal Road, Halifax, Nova Scotia B3J 1A1.

Intercorporate Relationships

The following organizational table sets forth the relationships between Emera and its principal subsidiaries, Emera’s ownership of the respective subsidiaries, as well as their respective jurisdictions of incorporation:

Subsidiaries	Percentage Ownership (%)(1)			Jurisdiction (2)
NSPI		100		Nova Scotia
Emera Maine		100		Maine
EE New England Gas Generation		100		Delaware
Emera Energy Services		100		Canada/United States
GBPC		80.4		The Bahamas
ECI		95.5	(3)	Barbados
EBPC		100		Canada
ENL		100		Newfoundland and Labrador

⁽¹⁾ The percentage of votes attaching to all voting securities beneficially owned, or controlled or directed, directly or indirectly by Emera.

⁽²⁾ Jurisdiction of incorporation, continuance or formation.

⁽³⁾ Emera and ECI are proceeding with a “going private transaction” pursuant to which ECI will amalgamate with Emera (Caribbean) (2016) Inc., a wholly owned subsidiary of EBH2 under the Companies Act (Barbados), in order for Emera to indirectly acquire all of the common shares of ECI that it does not already own. The amalgamation occurred on February 25, 2016 resulting in 100% ownership of the common shares of ECI by EBH2.

Emera’s other subsidiaries together account for less than 10% of total consolidated operating revenues and less than 20% of total consolidated assets of Emera for the year ended December 31, 2015.

GENERAL DEVELOPMENT OF THE BUSINESS

EMERA

Emera seeks to deliver long-term growth to investors. Accordingly, annual dividend growth, earnings per common share growth and total shareholder return are the primary measures of performance. Emera is targeting 8% annual dividend growth through 2019. The following table details Emera’s one, three and five-year performance for these metrics, as well as the S&P/TSX Capped Utilities Index annualized total shareholder return for those periods:

2015 Annual Information Form 14

For the	Year ended December 31, 2015
	1 year (%)			3 year (%)		5 year (%)
Dividend per share compound annual growth rate(1)		12.7			6.9		7.4
Adjusted earnings per share compound annual growth rate(2)		1.3			6.9		5.9
Emera annualized total shareholder return (2)		16.4			12.1		11.1
S&P/TSX Capped Utilities Index annualized total shareholder return (3)		(3.5	)		2.3		3.5

⁽¹⁾ The dividend per share compound annual growth rate is based on the dividends paid in the year.

⁽²⁾  The adjusted earnings per share compound annual growth rates do not include TECO Transaction related costs.

⁽³⁾ Total shareholder return combines share price appreciation and dividends per common share paid during the fiscal year to show the total return to the shareholder expressed as an annualized percentage assuming dividends are reinvested each time they are paid.

⁽⁴⁾ The S&P/TSX Capped Sector Indices provide liquid and tradable benchmarks for related derivative products of Canadian economic sectors. Constituents are selected from a stock pool of S&P/TSX Composite Index Stocks, and the relative weight of any single index constituent is capped at 25%. The indices are based upon the Global Industry Classification Standards (GICS^®). The S&P/TSX Capped Utilities Index imposes capped weights on the index constituents included in the S&P/TSX Composite that are classified in the GICS^® utilities sector.

Energy markets worldwide, in particular across North America, are undergoing foundational changes that have created significant investment opportunities for companies with Emera’s experience and capabilities. Key trends contributing to these investment opportunities include: aging infrastructure, environmental concerns (including demand for new, less carbon-intensive and renewable generation), lower-cost natural gas, growing demand for new electric heating solutions, and the requirement for large-scale transmission projects to deliver new energy sources to customers. Within this context, Emera is focused on growing shareholder value by identifying reliable and affordable energy solutions, typically involving the replacement of higher-carbon electricity generation with generation from cleaner sources, and the related transmission and distribution infrastructure to deliver that energy to market.

Emera has strong partnerships and relationships throughout the regions in which it operates and has established a diverse investment and operations profile that links its assets and capabilities in those regions. Core to Emera’s strategy is the ability to leverage these particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company.

Emera’s strategy is based on its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. The Company expects to continue to make investments in its regulated utilities to benefit customers and focus on providing rate stability to its customers. From time to time, Emera anticipates making acquisitions, both regulated and unregulated, where the business or asset acquired aligns with Emera’s strategic initiatives and delivers shareholder value.

To ensure stability in Adjusted net income and cash flows, Emera employs operating and governance models that focus on operational excellence, constructive regulatory approaches, proactive stakeholder engagement and a customer focus through service reliability and rate stability.

Emera targets achieving 75 to 85% of its Adjusted net income from rate-regulated subsidiaries, which generally contribute strong, predictable income and cash flows that fund dividends, reinvestment and which is reflective of the Company’s risk tolerance. Emera has an annual dividend growth target of 8% through 2019.

In 2015, approximately 65% of Emera’s Adjusted net income was earned by its rate-regulated subsidiaries, which is lower than 2014 (i.e., 67%) and is lower than its strategic target mentioned above. Specifically, the lower percentage of Adjusted net income from non-rate regulated subsidiaries is a result of a substantial increase in Emera Energy’s earnings primarily due to strong performance by the New England Gas Generating Facilities, and a strengthening U.S. dollar. It is not the result of a change in Emera’s risk tolerance, nor is it from additional capital allocations to non-regulated businesses. Rather, it is the result of strong operating and financial performance of existing non-regulated investments

2015 Annual Information Form 15

and businesses. Following the closing of the TECO Transaction, the Company is expected to achieve its Adjusted net income target of 75 to 85%.

Emera has grown its asset base to enable growth and deliver on its strategic objectives. Over the last 10 years, Emera’s ability to raise the capital necessary to fund investments has been a strong enabler of the Company’s growth. This was demonstrated in the Debenture Offering completed in connection with the TECO Transaction. In addition to access to debt and equity capital markets, cash flow from operations will continue to play a role in financing the Company’s future growth. Maintaining strong, investment grade credit ratings is an important component of Emera’s financing strategy.

For further information related to Emera’s consolidated revenues for the years ended December 31, 2015, December 31, 2014 and December 31, 2013, see the “Consolidated Financial Highlights”, “Emera Consolidated Statements of Income” and “2015 Consolidated Income Statement and Operating Cash Flow Highlights” sections in the MD&A, which are incorporated herein by reference.

The following discussion summarizes key developments in Emera’s business and operations over the last three completed financial years.

Pending Acquisition of TECO Energy

On September 4, 2015, the Company announced a definitive agreement for Emera to acquire TECO Energy. TECO Energy shareholders will receive $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.4 billion USD and which includes the assumption of approximately $3.9 billion USD of debt.

TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include: Tampa Electric, an integrated regulated electric utility which serves more than 700,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution utility which serves more than 350,000 customers across Florida; and New Mexico Gas Co., also a regulated gas distribution utility which serves more than 510,000 customers across New Mexico.

Upon completion of the TECO Transaction, Emera will have over $26 billion of assets and more than 2.4 million electric and gas customers. Emera has fully committed non-revolving term credit facilities in place from a syndicate of banks in an aggregate amount of $6.5 billion USD (the “Acquisition Credit Facilities”) to ensure the sufficiency of funding to complete the TECO Transaction. The Acquisition Credit Facilities are comprised of (i) a $4.3 billion USD debt bridge facility, repayable in full on the first anniversary following its advance, and (ii) a $2.2 billion USD equity bridge facility repayable in full on the first anniversary following its advance. Permanent financing of the TECO Transaction is expected to be obtained before or after closing, from one or more capital market offerings, including debt and preferred equity, as well as from internally generated sources. A portion of the permanent financing has already been arranged through the sale of $2.185 billion of Debentures. The Acquisition Credit Facilities are available to address any temporary shortfalls while completing the balance of the permanent financing.

Emera is required to effect reductions or make prepayments of the Acquisition Credit Facilities in an amount equal to the net cash proceeds from any common equity, preferred equity, bond or other debt offerings and any non-ordinary course asset sales by Emera and its subsidiaries, subject to certain prescribed exceptions and certain other prescribed transactions. Net proceeds from any such offerings, including the net proceeds of the Final Instalment under the Debenture Offering, or from any such non-ordinary course asset sales or transactions, will be applied to permanently reduce the commitments of the lenders under the Acquisition Credit Facilities or to repay the Acquisition Credit Facilities after they are drawn. On October 16, 2015, Emera permanently reduced the USD bridge facility in the amount of approximately $588.3 million USD with the proceeds of the first instalment of the Debentures and the proceeds from the Bear Swamp financing.

2015 Annual Information Form 16

The credit agreements pursuant to which the Acquisition Credit Facilities will be extended (the “Acquisition Credit Agreements”) will contain certain prepayment options in favour of Emera and certain prepayment obligations upon the occurrence of certain events. In particular, the net proceeds of any equity or debt offering by Emera and certain of its subsidiaries (other than certain permitted equity or debt offerings subject to certain prescribed exceptions) and of any non-ordinary course asset sales (subject to certain prescribed exceptions) and certain other prescribed transactions will be required to be used to prepay the Acquisition Credit Facilities and any prepayment under the Acquisition Credit Facilities may not be re-borrowed. The Acquisition Credit Agreements will contain customary representations and warranties and affirmative and negative covenants of Emera that will closely resemble those in Emera’s existing revolving credit facility (as the same may be amended to reflect the TECO Transaction).

The cash purchase price of the TECO Transaction and the acquisition related costs will be financed at the closing of the acquisition with one or more of the following sources: (i) net proceeds of the first instalment and the Final Instalment under the Debenture Offering, (ii) net proceeds of any subsequently completed preferred equity or bond or other debt offerings, (iii) amounts drawn under the Acquisition Credit Facilities and Emera’s existing revolving credit facility, and (iv) existing cash on hand and other sources available to the Company. Common equity and other available sources are expected to comprise $1.7 billion USD to $2.1 billion USD of the long-term financing for the acquisition, preferred equity offerings are expected to amount to $0.8 billion USD to $1.2 billion USD and bond or other debt offerings are expected to amount to $3.4 billion USD to $3.8 billion USD.

The closing of the TECO Transaction is expected to occur in mid-2016. It is subject to certain regulatory and government approvals, including approval by the New Mexico Public Regulation Commission and the satisfaction of closing conditions. Below is a summary of the approvals received to date:

• TECO Energy shareholder approval on December 3, 2015;

• FERC approval on January 21, 2016; and

• Committee on Foreign Investment in the United States approval on March 23, 2016.

Additionally, the waiting period expired on February 8, 2016 under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

On December 14, 2015, the New Mexico Public Regulation Commission set a hearing to begin on May 23, 2016 for the joint application of the change in control of New Mexico Gas Co. effected by the TECO Transaction.

Emera expects to incur a number of costs associated with completing the TECO Transaction. The majority of these costs will be non-recurring expenses resulting from the acquisition, including costs relating to the financing of the acquisition and obtaining regulatory approvals. Additional unanticipated costs may be incurred relating to the TECO Transaction.

Executive Appointments

On January 15, 2016, Greg Blunden was appointed Chief Financial Officer (“CFO”) of Emera, effective March 1, 2016. Mr. Blunden has held financial leadership roles at Emera, Emera Maine and NSPI. Most recently, Mr. Blunden was Vice President, Corporate Strategy & Planning.

On January 15, 2016, Emera’s current CFO, Scott Balfour, was appointed Chief Operating Officer, Northeast and Caribbean, effective March 1, 2016. Mr. Balfour will provide senior executive leadership for Emera’s existing operations, including NSPI, Emera Energy, Emera Maine, Emera Caribbean, EBPC and Emera Utility Services.

On January 15, 2016, Wayne O’Connor was appointed Vice President, Corporate Strategy & Planning for Emera, effective March 1, 2016. Mr. O’Connor will coordinate Emera’s planning and strategy development efforts to grow and expand the Company’s business. Previously, he was Executive Vice-President of Operations at NSPI.

2015 Annual Information Form 17

On September 22, 2015, Rob Bennett was appointed President and Chief Executive Officer of Emera U.S. Inc., a wholly owned subsidiary of Emera, to lead the integration of TECO Energy. Previously, Mr. Bennett had been the Chief Operating Officer, Eastern Canada.

On August 31, 2015, Roman Coba was appointed Chief Information Officer of Emera.

Purchase of ECI Outstanding Shares

On November 16, 2015, EBH2 announced its intention to acquire the outstanding common shares of ECI (the “Offer”). Minority ECI shareholders could elect to receive $23.26 ($33.30 BBD) in cash per common share (the “Cash Offer”) or 2.1 Emera DRs representing common shares of Emera (the “DR Offer”) or a combination of the two offers. Each Emera DR initially represented one quarter of an Emera common share.

As a result of the Offer, EBH2 acquired approximately 2.6 million common shares of ECI. As of Janauary 29, 2016, EBH2 had increased its ownership in ECI to 95.9% from 80.7%.

On January 8, 2016, the Emera DRs began trading on the Barbados Stock Exchange.

On January 25, 2016, Emera announced that EBH2 would proceed to acquire the remaining common shares of ECI from minority shareholders at the same Cash Offer and DR Offer, described above, by way of an amalgamation between ECI and a wholly owned subsidiary of EBH2. The amalgamation was completed on February 25, 2016, and EBH2 became the sole common shareholder of ECI. Pursuant to the amalgamation, holders of common shares of ECI received redeemable Class A preferred shares of the amalgamated company, which were redeemed on March 22, 2016.

Maritime Link Project and Strategic Partnership with Nalcor Energy on Muskrat Falls Projects

On July 31, 2012, Emera and Nalcor, along with the Provinces of Nova Scotia and Newfoundland and Labrador, executed 13 agreements in respect of the development and transmission of hydroelectric power from Muskrat Falls on the Churchill River in Labrador to the island of Newfoundland, the Province of Nova Scotia and through to New England. The agreements relate to the development of the Muskrat Falls Generating Station, the Labrador Transmission Assets, the Labrador-Island Transmission Link Project and the Maritime Link Project. More specifically, these agreements set out the detailed terms pursuant to which:

• Nalcor will construct and own a 824 MW hydro-electric generating facility at Muskrat Falls on the Lower Churchill River in Labrador and the Labrador Transmission Assets;

• Emera will invest in the Labrador-Island Transmission Link Project; and

• Emera will build, finance and operate for 35 years beginning in 2018, the Maritime Link Project, a transmission project linking the island of Newfoundland to Nova Scotia.

The execution of these agreements was followed, on November 30, 2012, with a finalization of a term sheet detailing the basis upon which the Government of Canada would provide financial support to the Maritime Link Project by way of a loan guarantee. This loan guarantee (the “Federal Loan Guarantee” or “FLG”) provides, among other things, that the Government of Canada would fulfill any payment obligations on the guaranteed debt relating to the Maritime Link Project in the event of a default on the guaranteed debt. The FLG enhances the credit rating of the debt financing of the Maritime Link Project to that of the Government of Canada, thus providing a material reduction to the cost of borrowing for the project.

On December 5, 2012, the Newfoundland and Labrador legislature voted in favour of a bill to approve the Muskrat Falls Generating Station, the Labrador Transmission Assets and the Labrador-Island Transmission Link Project.

2015 Annual Information Form 18

On December 17, 2012, Emera and Nalcor entered into a sanction agreement enabling both parties to advance their respective projects. Nalcor officially sanctioned the Muskrat Falls Generating Station and the Labrador-Island Transmission Link Project on December 17, 2012, and at that time revised and finalized its capital cost estimates for the Muskrat Falls Generating Station, including Labrador Transmission Assets, from $2.9 billion to $3.6 billion and from $2.1 billion to $2.6 billion for the Labrador-Island Transmission Link Project. This set the stage for construction to begin on the Nalcor projects. On behalf of Emera, ENL’s two subsidiaries, NSP Maritime Link Inc. and ENL Island Link Inc. will respectively carry out the development of the Maritime Link Project and invest in the Labrador-Island Transmission Link Project.

On January 28, 2013, NSP Maritime Link Inc. filed an application with the UARB seeking approval of the Maritime Link Project. Previously, on May 17, 2012, the Province of Nova Scotia passed the Maritime Link Act in order to enable a project specific review of the Maritime Link Project by the UARB. Pursuant to the Maritime Link Act, the Province of Nova Scotia announced the Maritime Link Approval Process Regulations on October 2, 2012, setting out the approval process to be followed for the Maritime Link Project.

On February 11, 2013, ENL Island Link Inc. invested $67.7 million in the Labrador-Island Transmission Link Project.

On June 21, 2013, NSP Maritime Link Inc. received a release from the Federal Environmental Assessment process, as well as environmental approval from the Provinces of Newfoundland and Labrador and Nova Scotia for the Maritime Link Project.

On July 22, 2013, NSP Maritime Link Inc. received the UARB decision on the Maritime Link Project. The UARB approved the Maritime Link Project subject to certain conditions, including an assurance that additional market-priced energy will be available to Nova Scotians. The UARB approved requested project costs of $1.52 billion and the requested variance amount of $60 million, for total approved project costs of $1.58 billion plus AFUDC.

On October 21, 2013, NSP Maritime Link Inc. filed the Maritime Link Project compliance filing with the UARB. The compliance filing sought confirmation from the UARB that NSP Maritime Link Inc. has complied with each of the UARB conditions, including the condition relating to the availability of market-priced energy.

On November 29, 2013, the UARB approved the Maritime Link Project compliance filing and gave its final approval of the Maritime Link Project. Subsequent to that UARB approval, the Nova Scotia government passed legislative amendments to the Maritime Link Act (Nova Scotia), which clarified certain aspects of the regulatory framework in respect of the Maritime Link Project and provides NSP Maritime Link Inc. with certain legal rights to facilitate the development and operation of the Maritime Link Project.

In early December 2013, Nalcor Energy and the Government of Newfoundland and Labrador announced the Federal Loan Guarantee associated with the Muskrat Falls Generating Station, the Labrador Transmission Assets and the Labrador-Island Transmission Link Project had been issued, and the financing for the Muskrat Falls Hydroelectric Project had been completed.

On December 13, 2013, NSP Maritime Link Inc. filed its first quarterly compliance filing with the UARB, which included an updated capital cost estimate for the Maritime Link Project of $1.577 billion. Based upon this cost estimate and the application of the terms of the agreement with Nalcor, whereby NSP Maritime Link Inc. will pay 20% of the total cost of the Lower Churchill Project Phase I and Maritime Link Project, the amount of this cost estimate that will be NSP Maritime Link Inc.’s responsibility will be $1.5554 billion. The parties have agreed that Nalcor will be responsible for any difference between the $1.5554 billion and the final actual capital costs of the Maritime Link Project, up to $1.577 billion. Any such adjustment will be payable by Nalcor no later than 30 days after the actual capital costs of the Maritime

2015 Annual Information Form 19

Link Project are finally determined. Any actual capital costs of the Maritime Link Project in excess of the $1.577 billion shall be dealt with in accordance with the provisions of the Maritime Link Joint Development Agreement.

On January 30, 2014, NSP Maritime Link Inc. entered into the first of the Maritime Link Project’s three major contracts: the supply and installation of the high-voltage direct current submarine cable. In February 2014, construction activities began in both Nova Scotia and Newfoundland and Labrador, with the initiation of rights-of-way clearing activities.

On March 6, 2014, following satisfaction of the relevant conditions in the FLG term sheet, the Government of Canada issued the Federal Loan Guarantee in respect of the Maritime Link Project.

On April 23, 2014, the MLFT completed its offering of $1.3 billion aggregate principal amount of 3.5% amortizing bonds due December 1, 2052 at a price of $999.57 per $1,000 principal amount of bonds for aggregate gross proceeds of approximately $1.3 billion. The amortization of the bonds is from December 1, 2020 to December 1, 2052. The bonds are guaranteed by the Government of Canada under the FLG and have been assigned a rating of “AAA” by S&P and DBRS. The net proceeds are being used to fund construction of the Maritime Link Project.

Together with certain financing entered into earlier by or on behalf of MLFT and NSP Maritime Link Inc., this bond offering fully satisfied the obligations of Emera under the Payment Obligation Agreement previously entered into between Emera, NSP Maritime Link Inc. and the Government of Canada. Upon completion of the bond offering, Emera became obligated under the Completion Guarantee previously granted by Emera in favour of the Government Canada. Under the Completion Guarantee, Emera has guaranteed the performance of the obligations of NSP Maritime Link Inc. to cause the completion of the Maritime Link Project, in the circumstances and within the timelines provided for in the Completion Guarantee.

On June 26, 2014, NSP Maritime Link Inc. entered into the second of the Maritime Link Project’s three major contracts: the supply and installation of two HVdc converter stations as well as three substations and two transition compounds.

In Q3 2014, the last of NSP Maritime Link Inc.’s labour agreements was signed.

On March 12, 2015, NSP Maritime Link Inc. entered into the third of the Maritime Link Project’s three major contracts, with Abengoa S.A., a global Spanish energy and transmission construction company for the construction of approximately 400 km of transmission lines in the Provinces of Newfoundland and Labrador and Nova Scotia. On November 25, 2015, Abengoa S.A. filed a notice under Spanish law, which provides for pre-insolvency protection in Spain, giving Abengoa S.A. the opportunity to reach an agreement with creditors to avoid a full insolvency process. ENL has worked closely with Abengoa S.A. and the performance bond sureties to minimize project impacts. Work on the Maritime Link Project continues.

On April 9, 2015, NSP Maritime Link Inc. and the Assembly of Nova Scotia Mi’kmaq Chiefs signed a Socio-Economic Agreement for the Maritime Link Project. Under the Socio-Economic Agreement, NSP Maritime Link Inc. will support ongoing engagement and commitments made during the environmental assessment process, including Mi’kmaq participation in environmental monitoring and employment and business opportunities for Mi’kmaq people.

2015 Annual Information Form 20

Purchase of Natural Gas Generation Facilities in New England

On November 19, 2013, Emera acquired all of the outstanding equity interests in three combined-cycle gas-fired electricity generating facilities in New England that make up EE New England Gas Generation: Bridgeport Energy (520 MW, since upgraded to 560 MW) in Bridgeport, Connecticut; Tiverton Power (265 MW) in Tiverton, Rhode Island; and Rumford Power (265 MW) in Rumford, Maine, for total cash consideration of $573.9 million CAD ($548.4 million USD). This addition of gas generation in the Northeastern United States has been a strategic objective of Emera and is a complement to its hydro investment in the region.

To finance the transaction, Emera utilized $150 million USD received on repayment of a loan to NWP, which was facilitated by the refinancing of that entity’s indebtedness; a one-year $350 million USD non-revolving credit facility established by an indirect wholly owned subsidiary of Emera; and other cash resources on hand.

First Wind

On June 15, 2012, Emera and First Wind closed their transaction to jointly own and operate a 419 MW portfolio of wind energy projects in the Northeastern United States through a new company, NWP, owned 51% by First Wind and 49% by Emera. Emera invested $215 million USD, including transaction costs, and loaned $150 million USD to NWP, to be repaid within five years. On November 14, 2013, Emera received repayment of the $150 million USD loan to NWP in full. First Wind managed and operated the wind energy projects, and Emera Energy Services provided energy management services.

Emera and First Wind also had an agreement relating to additional wind energy projects developed or acquired by First Wind. Under this agreement, on February 11, 2013, Emera, through its interest in NWP, acquired a 49% interest in 34 MW Bull Hill project for $14.4 million USD.

On January 29, 2015, Emera sold its 49% interest in NWP to First Wind for $223.3 million USD.

Strategic Partnership with Algonquin Power & Utilities Corp.

APUC is a diversified generation, transmission and distribution utility traded on the TSX under the symbol “AQN”. The distribution group operates in the United States and provides rate regulated water, electricity and natural gas utility services. The non-regulated generation group owns or has interests in a portfolio of North American-based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission group invests in rate-regulated electric transmission and natural gas pipeline systems in the United States and Canada.

Emera’s SIA with APUC establishes how Emera and APUC will work together to pursue specific strategic investments of mutual benefit. The SIA outlines “areas of pursuit” for both Emera and APUC. For Emera, these include investment opportunities related to regulated renewable generation and transmission projects within its service territories, and large electric utilities. For APUC, these include investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. Emera is committed to working with APUC on opportunities that fit within APUC’s “areas of pursuit”.

The SIA also provides for Emera to acquire up to 25% of APUC through the purchase of common shares issued by APUC to fund certain investment opportunities under the SIA. The acquisition of APUC shares is subject to regulatory approval. On June 25, 2012, Emera requested FERC and MPUC approval to increase its ownership in APUC to 25%; these approvals have now been received. The MPUC order, received on January 28, 2013, gave approval of Emera’s 25% ownership interest in APUC and stipulated that Emera’s dollar investment in APUC cannot exceed 5% of Emera’s total assets.

2015 Annual Information Form 21

On October 28, 2014, the approval order was appealed by Houlton Water Company and the Industrial Energy Consumer Group. Emera will continue to participate in the court appeal process to support the MPUC’s decision.

APUC share purchases by Emera have generally been made through the acquisition of subscription receipts in exchange for promissory notes at an agreed upon price, which are then exchangeable into common shares upon meeting certain transaction specific conditions, or at a later date at Emera’s option, as applicable. The acquisition and conversion of subscription receipts is subject to approvals required under applicable laws, including the rules of the TSX.

As at December 31, 2015, Emera owned 50.1 million common shares of APUC and had 12.6 million outstanding subscription receipts and dividend equivalents, at an average conversion price of $9.20 and an average book value of $8.03 per share. APUC’s market price per common share was $10.91 as at December 31, 2015 (2014 - $9.64). The outstanding subscription receipts became eligible for conversion into APUC common shares at Emera’s election in Q4 2015 and will automatically convert to common shares in Q4 2016 if an election is not made.

As at December 31, 2015, the carrying value of Emera’s investment in APUC was $503.7 million (2014 - $336.4 million).

Gains on Dilution of APUC Equity Investment

In December 2015, APUC closed a 14.355 million common share offering. As a result, Emera recorded a dilution gain of $11.1 million (after-tax earnings of $9.4 million or $0.06 per common share) in “Income from Equity Investments”, as described in the MD&A.

In Q3 2014 and Q4 2014 respectively, APUC closed 16.86 million and 10.05 million common share offerings. In addition, in Q3 2014, an over-allotment option of 2.52 million common shares was exercised. As a result of these two transactions, in Q3 2014, Emera recorded a gain of $10.8 million (after-tax earnings of $9.1 million or $0.06 per common share) and in Q4 2014, a gain of $7.5 million (after-tax earnings of $6.4 million or $0.04 per common share) in “Income from Equity Investments”, as described in the MD&A.

Empire District Electric Company Transaction

On February 9, 2016, APUC announced its intention to acquire The Empire District Electric Company in a $3.4 billion transaction, which is expected to close in Q1 2017. The closing of this transaction and its related financing is expected to reduce Emera’s ownership interest.

Nova Scotia Power

Electricity Plan and Rate Stability

On November 9, 2015, the Province of Nova Scotia released its electricity plan to support stable and predictable energy rates until 2019. The electricity plan also provides for the development of performance standards through a 2016 UARB regulatory process. On December 18, 2015, the Province of Nova Scotia enacted the Electricity Plan Act, which requires NSPI to file a three-year rate plan for Fuel Costs in Q1 2016 and to file a three-year GRA to change non-fuel rates by April 30, 2016. NSPI filed its three year rate plan for Fuel costs on March 7, 2016, indicating an average annual increase of 1.3 per cent per year from 2017 to 2019. NSPI has also confirmed that no GRA for non-fuel cost will be filed for the 2017 to 2019 period.

The Electricity Plan Act directs NSPI to apply non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of certain tax benefits for the South Canoe Wind Project and the Sable Wind Project is to be reserved to be applied to the FAM in the 2017 to 2019 period. The exception to this direction is to apply

2015 Annual Information Form 22

a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would have been otherwise required. For more information, see the “Regulated Fuel Adjustment Mechanism and FAM Regulatory Deferral” section of the MD&A, which is incorporated herein by reference.

Emera Maine

FERC Audit

In November 2014, the FERC commenced an audit covering the 2013 and 2014 period of Bangor Hydro’s compliance with conditions established in FERC’s orders authorizing its acquisition of MPS, which occurred on January 1, 2014. These two predecessor companies formed Emera Maine. The final audit report was released in early January 2016. The findings in the audit report conclude that Emera Maine did not follow the prescribed methodology for the calculation of AFUDC during the audit period and Emera Maine had included, in rates, costs of the Bangor Hydro and MPS merger prior to making the required filings. Emera Maine will fully comply with the recommendations in the audit report, including making the required filings for the merger costs and re-calculating AFUDC for 2013 and 2014, as ordered, which resulted in an immaterial impact on the Company’s consolidated statements of income.

Emera Maine ROE Proceedings

On September 30, 2011, a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users filed a complaint with the FERC alleging that the 11.14 % base ROE under the ISO-NE OATT was unjust and unreasonable. On June 19, 2014, the FERC issued an order in connection with this complaint, changing the methodology used to set the ROE for transmission assets.

This change would lower the base transmission ROE to 10.57% for the period of October 1, 2011 to December 31, 2012, subject to a further proceeding to finalize the determination of appropriate rates to be used in such calculation. The FERC decision would also lower the cap on the total ROE (inclusive of incentive adders) for transmission assets to 11.74%. In an order issued on October 16, 2014, the FERC confirmed that the ROE set in its earlier order was appropriate.

On March 3, 2015, in response to requests for rehearing from several parties, FERC affirmed its initial Order, setting of the base ROE of 10.57% and capping the total ROE, including the effect of incentive adders, at 11.74%. Notices of Appeal to the U.S. Court of Appeals for the DC Circuit were filed by New England Transmission Operators and the complainants in the case on April 30, 2015. In Q2 2015, Emera Maine began processing the refunds to customers, based on a 10.57% ROE. By court order dated August 20, 2015, the DC Court of Appeals decided to hold the appeal of this case in abeyance pending the outcome of the consolidated cases (“ENE Case” and “MA AG II Case”) discussed below.

On December 27, 2012, a second group of consumer advocates, including Environment Northeast filed a complaint with the FERC on similar grounds, arguing that the 11.14% base ROE under the OATT was unjust and unreasonable (the ENE Case). On June 19, 2014, the FERC issued an order in this second ROE case, finding in favour of the complainants and allowing the complaint to proceed. As a result, a new ROE will be calculated and set by the FERC. This complaint created a new 15-month refund period beginning January 1, 2013 through March 31, 2014.

On July 31, 2014, a group of state commissions, state public advocates and end users filed a third complaint with the FERC alleging the ROE earned on transmission investments is unjust and unreasonable and does not reflect current economic conditions (the MA AG II Case). Any potential refund arising from this third complaint will relate to the period from July 31, 2014 to September 30, 2015, and the outcome will set the ROE going forward from the date of decision.

On November 24, 2014, FERC consolidated the ENE Case and MA AG II Case. A subsequent order by the FERC established a schedule for various procedural matters that turned the case over to an Administrative Law Judge in

2015 Annual Information Form 23

September 2015. Once that judge’s recommended decision is rendered, parties may file exceptions, and then the case is set for decision by FERC.

Emera Maine has recorded net reserves of $6.9 million pre-tax ($5.0 million USD) (2014 - $8.5 million) for these refund complaints as at December 31, 2015, based on a 10.57% ROE.

On March 22, 2016, the Administrative Law Judge issued a recommendation to the FERC with respect to the two outstanding ROE complaints (ENE Case and MA AG II Case). Each complaint was for a 15-month period with the recommendation for the ENE Case being 9.59% ROE, with a 10.42% maximum ROE, and the recommendation for MA AG II Case being 10.90% ROE, with a 12.19% maximum ROE.

USGAAP – Exemptive Relief and Companies Act Relief

On April 28, 2014, Emera was granted exemptive relief by Canadian securities regulators allowing it to continue to report its financial results in accordance with USGAAP (the “Exemptive Relief”). On July 9, 2014, Emera was granted an order pursuant to the Companies Act (Nova Scotia) exempting it from the Companies Act requirement to prepare its annual financial statements in accordance with IFRS (the “Companies Act Relief”). Both the Exemptive Relief and the Companies Act Relief will remain in effect for Emera until the earlier of: (i) January 1, 2019; (ii) the first day of the Company’s financial year commencing after the Company ceases to have activities subject to rate regulation; and (iii) the effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities. The Exemptive Relief and the Companies Act Relief each replace previous similar exemptive relief that had been granted to Emera in 2012 and 2011 respectively, which would have expired by January 1, 2015.

Financing Activity

Emera

Debentures Represented by Instalment Receipts

To finance a portion of the TECO Transaction, on September 28, 2015, Emera, through the Selling Debentureholder, completed the sale of $1.9 billion aggregate principal amount of Debentures, represented by instalment receipts. On October 2, 2015, in connection with the Debenture Offering, the underwriters fully exercised an overallotment option and purchased an additional $285 million aggregate principal amount of Debentures at the Debenture Offering price.

The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which $333 was paid on closing of the Debenture Offering or exercise of over-allotment option, as applicable, with the Final Instalment being payable on the Final Instalment Date.

Prior to the Final Instalment Date, the Debentures are represented by instalment receipts. The instalment receipts began trading on the TSX on September 28, 2015 under the symbol “EMA.IR”. The Debentures will not be listed. The Debentures will mature on September 29, 2025 and bear interest at an annual rate of 4.00% per $1,000 principal amount of Debentures until and including the Final Instalment Date, after which the interest rate will be 0.00%. Based on the first instalment of $333 per $1,000 principal amount of Debentures, the effective annual yield to and including the Final Instalment Date is 12%, and the effective annual yield thereafter is 0.00%.

If the Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Debenture Offering, holders of Debentures who have paid the Final Instalment on or before the Final Instalment Date will be entitled to receive, on the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, the Make-Whole Payment.

2015 Annual Information Form 24

No Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary of the closing of the Debenture Offering. Under the terms of the instalment receipt agreement, Emera agreed that until such time as the Debentures have been redeemed in accordance with the foregoing or the Final Instalment Date has occurred, the Company will at all times hold (on a consolidated basis) short-term USD investment grade securities or have cash on hand of not less than the aggregate amount of the first instalment paid on the closing of the Debenture Offering and the exercise of the over-allotment option, in the event of a mandatory redemption.

At the option of the holders and provided that payment of the Final Instalment has been made, each Debenture will be convertible into common shares of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $41.85 per common share. This is a conversion rate of 23.8949 common shares per $1,000 principal amount of Debentures, subject to adjustment in certain events.

Prior to the Final Instalment Date, the Debentures may not be redeemed by the Company, except that Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions precedent to the closing of the TECO Transaction will not be satisfied; (ii) termination of the TECO Transaction agreement; and (iii) April 24, 2017, if notice of the Final Instalment Date has not been given to holders on or before April 21, 2017. Upon any such redemption, the Company will pay for each Debenture: (i) $333 plus accrued and unpaid interest to the holder of the instalment receipt; and (ii) $667 to the Selling Debentureholder on behalf of the holder of the instalment receipt in satisfaction of the Final Instalment. In addition, after the Final Instalment Date, any Debentures not converted may be redeemed by Emera at a price equal to their principal amount plus any unpaid interest which accrued prior to and including the Final Instalment Date. These costs will include a non-cash accounting charge for the difference between Emera’s closing share price on the issuance date of the convertible debentures and their exercise price. This will be recognized once the contingencies surrounding regulatory and other approvals are resolved.

At maturity, Emera will repay the principal amount of any Debentures not converted and remaining outstanding in cash. Emera has the right to satisfy the obligation to repay the principal amount due in common shares, which will be valued at 95% of the weighted-average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

The proceeds of the first instalment of the Debenture Offering are held and invested in short-term USD investment grade securities. The net proceeds of the Final Instalment will be used, together with the net proceeds of the first instalment, to finance, directly or indirectly, the TECO Transaction and other acquisition related costs. To mitigate the foreign currency translation risk associated with the Final Instalment, Emera entered into USD denominated forward contracts, which are recorded on the consolidated balance sheets. The mark-to-market effect on these hedges is reported in the income statement and affects income, but is not reflected in Adjusted net income.

TECO Transaction Bridge Facility

Emera has fully committed, non-revolving term credit facilities in place from a syndicate amount of $6.5 billion USD, which are referred to herein as the Acquisition Credit Facilities. On October 16, 2015, Emera permanently reduced the Acquisition Credit Facilities in the amount of approximately $588.3 million USD with the proceeds of the first instalment of the Debentures and the proceeds from the Bear Swamp financing.

Revolving Bank Line of Credit

On August 21, 2015, Emera extended the maturity of its $700 million committed syndicated revolving bank line of credit from June 2019 to June 2020, with no change in commercial terms from the prior agreement.

2015 Annual Information Form 25

On November 18, 2014, Emera extended the maturity of its $700 million committed syndicated revolving bank line of credit from June 2018 to June 2019, with no change in commercial terms from the prior agreement.

On November 19, 2013, Emera extended the maturity of its $700 million committed syndicated revolving bank line of credit from June 2017 to June 2018, with no change in commercial terms from the prior agreement.

Non-Revolving Credit Facility

On November 19, 2013, an indirect wholly owned subsidiary of Emera entered in to a $350 million USD non-revolving credit facility. The credit facility was used to partially finance the acquisition of EE New England Gas Generation. During 2014, a portion of this credit facility was repaid using funds from operations and Emera’s existing revolving bank line of credit. The remaining balance of $220 million USD of this non-revolving credit facility was repaid on February 5, 2015 using the proceeds from the sale of NWP.

Medium Term Notes

On October 20, 2014, Emera repaid the Series F $250 million 4.10% five-year medium term notes using its existing revolving bank line of credit. As noted below, the net proceeds of EBPC’s February 19, 2015 senior secured financing were used to repay an intercompany loan with Emera for the construction of the Brunswick Pipeline. The funds from this intercompany loan repayment were used to reduce indebtedness outstanding under Emera’s existing revolving bank line of credit.

Common Share Offering

On January 7, 2014, Emera completed an offering of 8,665,000 common shares, including the exercise of the over-allotment option of 865,000 common shares, at $28.85 per common share, for gross proceeds of $250.0 million and net proceeds of approximately $240.0 million. The net proceeds of the offering were used for general corporate purposes to support the Company’s recently announced growth initiatives and to reduce indebtedness outstanding under Emera’s credit facility.

Preferred Share Offerings

On August 17, 2015, 2,135,364 of Emera’s 6,000,000 issued and outstanding Series A First Preferred Shares were tendered for conversion, on a one-for-one basis, into Series B First Preferred Shares.

On June 9, 2014, Emera issued 8,000,000 Series F First Preferred Shares at $25.00 per share for gross proceeds of $200.0 million and net proceeds of approximately $194.5 million. The net proceeds of this offering were used for general corporate purposes.

On June 10, 2013, Emera issued 5,000,000 Series E First Preferred Shares, including the exercise of the over-allotment option of 1,000,000 Series E Preferred Shares, at $25.00 per share for gross proceeds of $125.0 million and net proceeds of approximately $121.6 million. The net proceeds of this offering were used for general corporate purposes, including the repayment of indebtedness under the Company’s credit facility.

NSPI

On April 30, 2015, NSPI completed the issuance of $175 million Series AA Medium-Term Notes. The Series AA notes bear interest at a rate of 3.612% per annum until May 1, 2045. The proceeds of the note offering were used for general corporate purposes, including the repayment of maturing corporate term debt.

2015 Annual Information Form 26

NSPI’s Series I $70 million 8.40% Medium-Term Notes matured and were repaid on October 23, 2015.

On October 15, 2015, NSPI redeemed all of its issued and outstanding Series D Preferred Shares for an aggregate purchase price of $135 million.

On January 10, 2014, November 18, 2014 and November 16, 2015, NSPI extended the maturity of its $500 million committed syndicated revolving bank line of credit from June 2017 to June 2018, October 2019 and October 2020, respectively, with no change in commercial terms from the prior agreement.

Emera Maine

On September 25, 2014, Emera Maine completed a securities issuance for $110 million USD senior unsecured notes. The 30-year notes bear interest at a rate of 4.34% and will mature on September 25, 2044. Proceeds from the sale of the notes were used to repay existing indebtedness and for other general corporate purposes.

On September 25, 2014, Emera Maine extended the maturity of its $80 million USD revolving senior credit facility from September 2014 to September 2019, with no material change in commercial terms from the prior agreement.

On September 30, 2013, MPS renewed its existing $10 million USD revolving credit facility, with a new expiration date of the earlier of September 30, 2014, or the effective date of the merger between MPS and Bangor Hydro, with no change in terms from the prior agreement, with an expiration date of September 30, 2014. This agreement expired upon the merger of MPS and Emera Maine.

On September 30, 2013, MPS repaid its Maine Public Utility Financing Bank Bonds and associated interest rate hedges with the proceeds from a $25.6 million USD non-revolving credit facility.

ENL

On April 23, 2014, the MLFT completed its offering of $1.3 billion aggregate principal amount of 3.5% amortizing bonds. Further information on this is provided in the General Development of the Business, Development of the Maritime Link Project and Strategic Partnership with Nalcor Energy on Muskrat Falls Projects.

GBPC

On December 15, 2014, GBPC renewed its $20.2 million USD loan agreement to 2021 at a floating rate of LIBOR plus 1.75%. This loan is repayable in 28 equal quarterly installments. All other terms and conditions of the loan agreement remain unchanged.

On January 16, 2013, GBPC issued 32,000 non-voting cumulative redeemable perpetual variable preferred shares at $1,000 Bahamian per share for gross proceeds of $32.0 million Bahamian and net proceeds of $30.9 million Bahamian. The net proceeds of the share offering were used to repay intercompany loans with Emera for the construction of the West Sunrise Plant.

On July 17, 2013, GBPC issued an additional 3,000 non-voting cumulative redeemable perpetual variable preferred shares at $1,000 Bahamian per share for gross proceeds of $3.0 million Bahamian and net proceeds of $2.9 million Bahamian.

EBPC

On February 19, 2015, EBPC completed a senior secured financing consisting of a non-revolving term credit facility for $250 million for a four-year term. The credit facility bears interest at bankers’ acceptances rates plus 1.75% and expires on February 19, 2019. As noted above, the net proceeds of the financing were used to repay a $250 million intercompany loan with Emera for the construction of the Brunswick Pipeline.

2015 Annual Information Form 27

Emera Energy Services

On October 8, 2015, Bear Swamp refinanced its $125 million USD bank debt that was due to mature in 2017 and issued $400 million USD in senior secured 10-year bonds, with $375 million USD at a fixed rate of 4.89%, and $25 million USD at a floating rate of LIBOR plus 2.70%. The proceeds of this financing were used to repay existing debt and provide working capital to the joint venture, with the remainder shared equally between Emera and its joint venture partner. After fees and expenses, Emera received a $178.7 million ($137.3 million USD) non-taxable distribution in Q4 2015.

Changes in Business Expected During 2016

Emera

The TECO Transaction is expected to be accretive to earnings per share by approximately 5% in the first full calendar year following its closing, growing to more than 10% by the third full year assuming a USD/CAD exchange rate consistent with that at the time of announcement of the transaction. As well, approximately 95% of the expected foreign exchange exposure to close the TECO Transaction has been actually or effectively hedged. The TECO Transaction will result in further acquisition costs in 2016.

Emera’s operations are affected by the U.S. dollar relative to the Canadian dollar. Approximately 50% of Emera’s Adjusted net income was derived from subsidiaries with a U.S. functional currency in 2015. TECO Energy’s operations are conducted in U.S. dollars and following the TECO Transaction, Emera’s consolidated net income and cash flows will be affected to a greater extent by movements in the U.S. dollar relative to the Canadian dollar.

NSPI

NSPI’s earnings are most directly affected by the range of rate of return on equity and capital structure approved by the UARB; the prudent management and approved recovery of operating costs, load, and regulatory deferrals and the timing and amount of capital expenditures. NSPI anticipates earning within its allowed ROE range in 2016 and expects its rate base to remain stable. Over the past several years, the requirement to reduce the Province of Nova Scotia’s reliance upon high carbon and greenhouse gas emitting sources of energy has resulted in NSPI making significant investments in renewable energy sources and purchasing third party renewable energy. On November 10, 2015, NSPI announced it does not plan to file a GRA related to electricity rates for 2016.

In December 2015, the Electricity Plan Act was enacted by the Province of Nova Scotia with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period. The Electricity Plan Act requires NSPI to file a three-year rate plan for fuel costs in Q1 2016 and to file a three-year application to change non-fuel rates by April 30, 2016. NSPI filed its three year rate plan for Fuel costs on March 7, 2016, indicating an average annual increase of 1.3 per cent per year from 2017 to 2019. NSPI has also confirmed that no GRA for non-fuel cost will be filed for the 2017 to 2019 period.

NSPI expects to finance its capital expenditures with funds from operations and its credit facilities, as well as continued access to debt capital markets for long-term financing.

Overall, NSPI’s 2016 earnings are expected to be consistent with prior years.

Emera Maine

Emera Maine’s earnings are most directly affected by the combined impacts of the range of rates of return on equity and rate base approved by its regulators, the prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures.

Emera Maine’s 2016 ROE is expected to be consistent with prior years. Its ongoing investment in transmission and distribution infrastructure is expected to result in modest growth in rate base.

2015 Annual Information Form 28

Emera Maine has an agreement with Central Maine Power Company to pursue specific transmission opportunities in Northern Maine that would relieve transmission congestion and more efficiently collect and deliver wind generation to New England markets. As part of this agreement, Emera Maine and Central Maine Power Company jointly responded to a request for proposals for clean energy from Massachusetts, Connecticut and Rhode Island, through an existing jointly owned transmission company, Maine Electric Power Company Inc. (MEPCO). The demand for this renewable energy is growing as a result of increasing renewable portfolio requirements of the southern New England states.

Future earnings will generally reflect the impact of transmission rate decisions by the FERC. Emera Maine has fully reserved for the refunds required as a result of a FERC decision on the allowed ROE set at 10.57%.

Overall, Emera Maine’s 2016 USD earnings are expected to be consistent with prior years.

Emera Caribbean

Earnings from Emera Caribbean are most directly affected by the combined impacts of the range of rates of return on equity and rate base approved by their regulators, capital structure, the prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures. Earnings are also affected by the investment returns of Emera’s interest in BLPC’s self-insurance fund.

The Barbados economy expects growth of approximately 1.8% in 2016. With oil being the predominant fuel source for generation of electricity in the Caribbean, reduced oil prices may result in an economic benefit on the island in decreased cost of electricity to ratepayers. During 2015, BLPC recognized the need to reduce costs in the business to stabilize future rates to customers. BLPC forecasts that it expects to maintain the 2015 cost savings into the future.

The economy of Grand Bahama Island is highly correlated to the United States economy and has exhibited signs of improving economic growth and a corresponding growth in load in the industrial sector and weather related growth in the residential sector.

Effective February 1, 2016, the GBPA approved GBPC’s GRA applicable for the 2016 through 2018 period. Residential customers will see decreases of up to 4.5%, while commercial customers will see an increase of 1.5%. Commercial customers consume approximately 70% of GBPC’s production. Rates were approved based upon an 8.8% return on rate base, reduced from the previous level of 10%. This rate decision also allows for customers to install renewable energy systems and sell their excess energy to GBPC. This is based on a tariff rider scheduled to be in place by Q3 2016.

There are growth opportunities for Emera in the Caribbean market centered on creating and capturing opportunities for cleaner fuels and renewable energy generation. As part of this initiative, construction of a 10 MW solar facility began in Barbados in Q4 2015 and is scheduled for completion in the first half of 2016. In addition, an application to export natural gas to countries with no free trade agreement with the United States, specifically The Bahamas, was filed with the US Department of Energy and approval was received on October 20, 2015, granting long-term multi contract authorization for Emera to export natural gas, by vessel, in the amount of 8 MMSCFD. This complements the authorization received in April 2015 to export up to 25 MMSCFD to countries which have a free trade agreement with the United States.

Overall, Emera Caribbean 2016 USD earnings are expected to be consistent with prior years.

Pipelines

The timing of the income from Pipelines is predominately a result of capital lease accounting treatment which yields declining earnings over the life of the asset.

Pipelines 2016 earnings are expected to be consistent with prior years.

2015 Annual Information Form 29

Emera Energy

Emera Energy Services

Emera Energy Services, Emera Energy’s marketing and trading business, is generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply/demand factors, can provide higher levels of margin opportunity. The past three years have seen favourable market conditions in this regard within Emera Energy’s key markets, with Q1 2014, in particular, experiencing unprecedented market volatility. This was a result of the combined impacts of cold weather, constraints in the supply or transportation of natural gas, and other market factors, and contributed to very strong adjusted earnings¹ from marketing and trading, particularly in 2014. 2015 has seen lower market volatility and pricing, and a resulting decrease in marketing and trading adjusted earnings compared to 2014.

In addition to capitalizing on volatility-driven market opportunities, Emera Energy Services expects to continue to grow organically building market share through superior customer service and expanding its geographic reach to adjacent markets, including the Marcellus Shale region.

Planned investment by the industry in gas transportation infrastructure within the Northeastern United States over the next few years could reduce the degree of volatility recently experienced in the market, all other things being equal. This could negatively affect profitability during certain periods.

Emera Energy Generation

Earnings from Emera Energy Generation’s assets are largely dependent on market conditions, in particular, the relative pricing of electricity and natural gas and capacity pricing for the New England Gas Generation Facilities. Efficient operations of the fleet to ensure unit availability, cost management and effective commercial performance are key success factors.

2016 adjusted earnings from Emera Energy generating assets are expected to be lower than 2015, reflecting lower hedged and expected margins as compared to 2015.

In addition to energy margins and ancillary revenue, the EE New England Gas Generation and Bear Swamp earn revenue from capacity payments through the forward capacity market (FCM), the annual reconfiguration capacity market and the monthly reconfiguration capacity market. Prices for the FCM, the largest of the three components, are determined through an auction process held annually, three years in advance, providing revenue visibility to 2019, presuming the facilities continue to be available to support their capacity obligations. Details of pricing and estimated revenues are outlined in the table below for EE New England Gas Generation, and Emera Energy’s 50% interest in Bear Swamp.

Forward Capacity Auction (“FCA”) Year	Clearing Price in $/kW-month (in USD)	Approximate Estimated Annual Capacity Revenue (in USD) (1)
FCA6 (June 2015 to May 2016)	$3.43	$	40 million
FCA7 (June 2016 to May 2017)	$3.15	$	40 million
FCA8 (June 2017 to May 2018)	$7.025	$	100 million
FCA9 (June 2018 to May 2019)	$9.55 and $11.08 (2)	$	145 million
FCA 10 (June 2019 to May 2020)	$7.03	$	106 million

(1) Includes Emera’s 50% share of Bear Swamp’s capacity revenue

(2) $11.08 was awarded for the Southeast Massachusetts/Rhode Island zone only and, as such, applies only to Tiverton

¹  Emera uses financial measures, such as “adjusted earnings”, that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures by adjusting certain GAAP and non-GAAP measures for specific items it believes are significant, but not reflective of underlying operations in the period. Refer to the Non-GAAP Financial Measures section of Emera’s MD&A for further discussion of these items.

2015 Annual Information Form 30

Bear Swamp’s adjusted earnings will be lower in 2016 and the first half of 2017 primarily due to higher interest costs as a result of its Q4 2015 refinancing. Beginning Q3 2017, these interest costs will be offset by higher capacity revenues.

Corporate and Other

Corporate and Other is dependent, in part, on business development and acquisition related initiatives, which in 2016 will include further acquisition costs related to the TECO Transaction, equity investments in the Maritime Link Project and the Labrador-Island Transmission Link Project, project based construction services activity by Emera Utility Services, growth or fluctuations in APUC earnings (which Emera accounts one quarter after APUC reports such earnings), corporate financing and other corporate activities.

Corporate’s contribution to consolidated net income in 2016 is expected to be lower than 2015 primarily due to further acquisition costs and associated financing initiatives related to the TECO Transaction. These costs will include a non-cash accounting charge for the difference between Emera’s closing share price on the issuance date of the Debentures and their exercise price. This will be recognized upon the closing of the TECO Transaction once the contingencies surrounding regulatory and other approvals are resolved.

On February 9, 2016, APUC announced its intention to acquire The Empire District Electric Company in a $3.4 billion transaction, which is expected to close in Q1 2017. The closing of this transaction and its related financing are expected to reduce Emera’s ownership interest, as Emera did not take part in the equity issuance. Emera is expected to record a non-cash dilution gain on its then interest in APUC at the time of APUC’s closing of this transaction.

ENL

NSPML

As of December 31, 2015 and through its subsidiary, NSP Maritime Link Inc., ENL has incurred total costs of approximately $693.9 million, including $78.1 million of AFUDC, in the development of the Maritime Link Project. As of December 31, 2015, ENL has invested a total of $154.9 million in equity, with remaining costs being funded with working capital and debt, which has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9.0%.

ENL’s future earnings contribution from the Maritime Link Project will be affected by the timing of capital expenditures, which will determine the component of costs to be funded by equity. Funds from the federally guaranteed debt financing completed in April 2014 were used to fund project costs until the project’s debt to equity ratio reached 70% to 30% respectively, which occurred in Q4 2015. From this point forward, project costs are funded with debt and equity at a 70% to 30% ratio, with equity contributions of $13.4 million in Q4 2015.

Maritime Link Project currently forecasted equity contributions for 2016 and 2017 are $157 million and $159 million respectively, with total equity for the project estimated to be $470.9 million.

LIL

ENL is a partner with Nalcor Energy in LIL, which is currently estimated at approximately $3.1 billion. As at December 31, 2015, ENL has invested $207.3 million of equity, including $21.2 million of capitalized equity earnings in LIL. Equity earnings are recorded based on an annual rate of 8.8% of the equity invested. The return on ROE is approved by the NLPUB. There is currently an application being heard by the NLPUB which includes a review of ROE. The NLPUB’s decision on ROE, will be applicable for all regulated electrical utilities in Newfoundland and Labrador and become the ROE applicable to ENL’s investment in LIL.

2015 Annual Information Form 31

ENL has an ongoing equity investment opportunity in LIL. Future earnings are dependent on the timing of additional equity investments and the approved ROE. Total equity contributions for 2015 for LIL are $118.4 million.

LIL currently forecasted equity contributions for 2016 are $223 million, with total equity investment, by Emera, in the project estimated to be $409.1 million.

DESCRIPTION OF THE BUSINESS

General

Emera Incorporated is an energy and services company with approximately $12 billion in assets. Emera currently provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States, and the Caribbean.

Emera is focused on growing shareholder value by identifying reliable and affordable energy solutions for customers, typically involving the replacement of higher carbon electricity generation with generation from cleaner sources, and the related transmission, distribution infrastructure and delivery of that energy to market.

Emera has strong partnerships and relationships throughout the regions in which it operates and has established a diverse investment and operations profile that links its assets and capabilities in those regions. Core to Emera’s strategy is the ability to leverage these particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company.

Emera’s strategy is based on its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. Emera and its subsidiaries had approximately 3,500 employees at December 31, 2015, approximately 49% of whom are unionized.

Emera has grown its business through investments in its rate-regulated subsidiaries that are beneficial to its customers. Emera’s regulated subsidiaries include:

• NSPI (see “NSPI” section below);

• Emera Maine (see “Emera Maine” section below);

• BLPC, GBPC and Domlec (see “Emera Caribbean” section below); and

• EBPC (see “Pipelines” section below).

Emera has also grown its business through its non-regulated subsidiaries (Emera Energy (see “Emera Energy” section below) and Emera Utility Services and Emera Utility Services Bahamas) and additional regulated and non-regulated strategic investments and activities that include:

• Emera’s 100% investment in NSPML, a $1.5554 billion transmission project, including two 170-kilometre subsea cables, between the island of Newfoundland and Nova Scotia. The investment in NSPML is accounted for on the equity basis with equity earnings equal to the ROE component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017;

• Emera’s 55.1% investment in the partnership capital of LIL, a $3.1 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change based on the balance of capital investments required from Emera and Nalcor to complete construction of the LIL. Emera’s ultimate

2015 Annual Information Form 32

percentage investment in LIL will be determined on completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49% of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is expected to go into service in 2017;

• Emera’s 19.59% investment in APUC, excluding outstanding subscription receipts and associated dividend equivalents. APUC is a diversified generation, transmission and distribution utility traded on the TSX under the symbol “AQN”. The distribution group operates in the United States and provides rate regulated water, electricity and natural gas utility services. The non-regulated generation group owns or has interests in a portfolio of North American-based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission group invests in rate-regulated electric transmission and natural gas pipeline systems in the United States and Canada. The investment in APUC is accounted for on the equity basis. There is a one quarter lag in reporting as APUC’s information is generally not publicly available at the time of Emera’s public release of its financial results. As at December 31, 2015, Emera owned 50.1 million common shares, 12.6 million outstanding subscription receipts and dividend equivalents, at an average conversion price of $9.20. The outstanding subscription receipts became eligible for conversion into APUC common shares at Emera’s election in Q4 2015 and will automatically convert to common shares in Q4 2016 if an election is not made;

• a 12.9% interest in M&NP.

NSPI

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services in Nova Scotia to approximately 506,000 customers with approximately $4.6 billion in assets and approximately 1,700 employees.

NSPI is a public utility as defined in the Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings from time to time at NSPI’s or the UARB’s request. NSPI is regulated under a cost of service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s regulated ROE range for 2013 to 2015 was 8.75% to 9.25%, based on an actual average regulated common equity component of up to 40% of actual average regulated capitalization. NSPI’s targeted regulated ROE range remains unchanged for 2016.

NSPI operates with a FAM, which enables NSPI to recover fluctuating fuel expenses through annual fuel rate adjustments, which is subject to UARB review and approval. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

As at December 31, 2015 the FAM has a net liability balance of $28.3 million (2014 - $47.9 million net asset ).

2015 Annual Information Form 33

Market and Sales

NSPI

Revenue and Electricity Sales by Customer Class

	Electric Revenues (%)				GWh Electric Sales Volumes (%)
For the year ended December 31	2015		2014		2015		2014
Residential		51.5		50.7		43.1		42.5
Commercial		29.5		29.4		30.1		30.1
Industrial		15.4		16.2		23.6		24.4
Other		3.6		3.7		3.2		3.0
Total		100.0		100.0		100.0		100.0

Energy Sources and Generation

NSPI’s energy sources for its electric energy generation are coal, petroleum coke (“petcoke”), natural gas, heavy fuel oil, hydroelectric energy, light fuel oil (gas turbine), biomass and wind. NSPI also purchases electric energy from IPPs in the Province of Nova Scotia and neighbouring markets outside the Province of Nova Scotia.

NSPI owns 2,483 MW of generating capacity, of which approximately 50% is coal-fired; natural gas and/or oil comprise another 28% of capacity; hydro and wind total 19% and biomass-fueled generation of 3%. In addition, NSPI has contracts to purchase renewable energy from IPPs. These IPPs own 496 MW, increasing to 552 MW in 2016 of wind and biomass-fueled generation capacity.

Comparative costs of fuel sources fluctuate from year to year. For information describing the percentage of total electric energy generated by fuel source and for information related to the cost of electricity generation, see the “NSPI Regulated Fuel for Generation and Purchased Power” section of the MD&A, which is incorporated herein by reference.

System Operations

The ECC co-ordinates and controls the electric generation and transmission and distribution facilities. The ECC is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a communication network used by system operators for remote monitoring and control of the power system components.

Through an interconnection agreement with NB Power, NSPI’s system has access to other regional power systems and the rest of the interconnected North American electric bulk power systems.

Transmission and Distribution

NSPI transmits and distributes electricity from its generating stations to its customers. NSPI’s transmission system consists of approximately 5,000 km of transmission facilities. The distribution system consists of approximately 27,000 km of distribution facilities.

Contribution to Consolidated Net Income

NSPI’s contribution to Emera’s consolidated net income was $129.9 million in 2015 and $124.9 million in 2014.

Seasonal Nature

Electric sales volume is primarily driven by general economic conditions, population, weather and demand side management. Residential and commercial electricity sales are seasonal in the Province of Nova Scotia, with Q1 typically being the strongest period, reflecting colder weather and fewer daylight hours in the winter season.

2015 Annual Information Form 34

Capital Expenditures

NSPI’s capital expenditures in 2015 were $274 million (2014 - $274 million).

The UARB prescribes and approves depreciation rates and regulated accounting policies. Depreciation rates are reviewed periodically. A settlement agreement on depreciation rates became effective on January 1, 2012. The overall impact of this settlement agreement on the average depreciation rate was immaterial.

Environmental Considerations

NSPI is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters, primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI.

Conformance with legislative and NSPI’s requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed to December 31, 2015.

The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix. The most recent target for each year of 2015 through 2019 was 25% of electrical energy which will be derived from renewable sources. That target was exceeded for 2015, with 27% of NSPI’s generation mix coming from renewable sources. In 2020, the target is 40% of electrical energy to be derived from renewable sources. The Maritime Link Project will supply 153 MW of firm, on-peak power and approximately 900 GWh per year of renewable electricity to help NSPI meet the legislated target of 40% renewable electricity in 2020. NSPI plans to retire a coal-fired generating unit following the commencement of commercial operations of the Maritime Link.

For further information on environmental regulations affecting NSPI, see NSPI’s Annual Information Form.

Emera Maine

On November 29, 2012, Bangor Hydro and MPS submitted a regulatory filing with the MPUC seeking permission to merge into one entity. This proposed change was also subject to regulatory approval by the FERC. The merger application included a proposal to harmonize distribution rates for most residential and small commercial customers on a revenue neutral basis. No change was proposed to other rates or rate classes. Regulatory approval was received in 2013 from the MPUC and FERC for Bangor Hydro and MPS to officially merge on January 1, 2014. Harmonization of rates was deferred to a future case.

Emera Maine’s transmission operations are regulated by FERC, and its distribution operations and stranded cost recoveries are regulated by the MPUC. Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through the utility’s transmission and distribution networks. Throughout the discussion below, various references are made to the two predecessor entities to Emera Maine, which existed as separate entities until December 31, 2013.

Emera Maine has approximately $1.1 billion USD of assets and approximately $670 million USD of net rate base. Emera Maine owns and operates approximately 1,700 km of transmission facilities and 15,000 km of distribution facilities and a workforce of approximately 400 people.

2015 Annual Information Form 35

Market and Sales

Approximately 55% of Emera Maine’s electric revenue represents distribution operations, 31% is associated with local transmission operations and 14% relates to stranded cost recoveries. The rates for each element are established in distinct regulatory proceedings.

Emera Maine Revenue and Electricity Sales by Customer Class

	Electric Revenues (%)				GWh Electric Sales Volumes (%)
For the year ended December 31	2015		2014		2015		2014
Residential		47.8		48.3		39.7		39.7
Commercial		36.2		36.5		38.7		38.7
Industrial		8.8		9.1		20.9		20.9
Other		7.2		6.1		0.7		0.7
Total		100.0		100.0		100.0		100.0

Distribution Operations

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. Prior to July 1, 2014, the allowed ROE was 10.2%, on a common equity component of 50%. Effective July 1, 2014, the allowed ROE became 9.55% on a common equity component of 49%.

Transmission Operations

There are two transmission districts for Emera Maine, corresponding to the service territories of the two pre-merger entities.

Bangor Hydro District Transmission

Bangor Hydro District’s local transmission rates are regulated by the FERC and set annually on June 1, based upon a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments was 11.14%. Effective October 16, 2014, the allowed ROE changed to 10.57%, pending two outstanding complaints filed with the FERC to challenge the ISO-NE OATT allowed base ROE of 11.14%. The common equity component (i.e., the equity base upon which the allowable ROE is earned) is based upon the prior calendar year actual average balances. Effective June 1, 2015, transmission rates for the Bangor Hydro District increased by approximately 21% in connection with its annual transmission formula rate filing (2014 – increased by 13%). The increase is associated primarily with the under-recovery of prior year regional transmission revenues collected in local rates, as well as the recovery of increased transmission plant in service.

Bangor Hydro District’s bulk transmission assets are managed by the ISO-NE as part of a region-wide pool of assets. The ISO-NE manages the regions’ bulk power generation and transmission systems and administers the open access transmission tariff. Currently, Bangor Hydro District, along with all other participating transmission providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is based on prior year regionally funded transmission investments, adjusted for current year forecasted investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments ranged from 11.64% to 12.64%. Effective October 16, 2014, the transmission investments allowed ROE changed to a range from 11.07% to 11.74%, pending the two aforementioned complaints filed with FERC. The common equity component is based upon the prior calendar year average balances. The participating transmission providers are also required to contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent. On June 1, 2015, Bangor Hydro District’s regionally recoverable transmission investments and expenses decreased by 6% (2014 – increased by 7%).

2015 Annual Information Form 36

As at December 31, 2015, the Company had accrued $5.0 million USD associated with the FERC ROE complaints relating to Bangor Hydro District (2014 – $7.3 million USD). Refunds for the first FERC ROE complaint are being made to customers over a one-year period which began with the June 1, 2015 rate change.

MPS District Transmission

MPS District local transmission rates are regulated by the FERC and set annually on June 1 for wholesale and July 1 for retail customers, based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted investments. The current allowed ROE for transmission operations is 10.2%. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015, the transmission rates for the MPS District decreased by approximately 24% for wholesale customers (2014 – increased by 2%) and on July 1, 2015 decreased by 22% for retail customers (2014 – increased by 11%) in connection with its annual transmission formula rate filing. These decreases were primarily due to an increase in wholesale transmission revenue that allows for a decrease in local customer transmission rates.

The MPS District electric service territory is not connected to the New England bulk power system and it is not a member of ISO-NE. MPS District is not a party to the previously discussed ROE complaints at the FERC.

Stranded Cost Recoveries

Stranded cost recoveries in Maine are set by the MPUC. Electric utilities are entitled to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC. Unlike transmission and distribution operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through rates. Generally, regulatory rates to recover stranded costs are set every three years, determined under a traditional cost-of-service approach and are fully recoverable. On July 1 of each year, stranded cost rates are adjusted to reflect recovery of cost deferrals for the prior stranded costs rate year under the full recovery mechanism, as well as factor in any new stranded cost information.

Bangor Hydro District Stranded Costs

Bangor Hydro District’s net stranded regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract, and deferrals associated with reconciling stranded costs. These net regulatory assets total approximately $19.7 million USD as at December 31, 2015 (2014 – $25.1 million USD) or 1.8% of Emera Maine’s net asset base (2014 – 2.3%).

On July 1, 2014, the Bangor Hydro District stranded cost rates decreased by 10%. Earlier, on March 1, 2014, stranded costs rates had increased by 20%. The allowed ROE used in setting the new rates on July 1, 2014, and March 1, 2014, was 5.9%, with a prescribed common equity component of 48%. The July 1, 2014 rate decrease remained in effect for all of 2015, and there was no rate change on July 1, 2015.

MPS District Stranded Costs

Effective January 1, 2015, the stranded cost rates for the MPS District decreased by approximately 150%. This was principally due to the flow-back to customers of certain benefits received by Emera Maine from Maine Yankee associated with litigation with the United States Department of Energy on nuclear waste disposal. The allowed ROE used in setting the new rates on January 1, 2015 was 6.75%, with a common equity component of 48%. The reduced stranded cost revenues are offset by reductions in expense and do not affect income. The January 1, 2015 rate decrease remained in effect for all of 2015 and there was no rate change on July 1, 2015. MPS District has a net stranded cost regulatory liability of $2.68 million USD as of December 31, 2015.

2015 Annual Information Form 37

Contribution to Consolidated Net Income

Emera Maine’s contribution to Emera’s consolidated net income was $35.6 million USD in 2015 and $38.4 million USD in 2014.

Seasonal Nature

Electricity sales in Maine vary significantly over the year; Q1 and Q3 are typically the strongest. Q1 reflects colder weather and few daylight hours in the winter season, while Q3 reflects the hotter summer weather and the impact of summer tourism in the state.

Capital Expenditures

Emera Maine’s capital expenditures for the year ended 2015 were approximately $66 million (2014 – $85 million).

Environmental Considerations

Emera Maine is regulated by the U.S. Environmental Protection Agency for compliance with the Federal Water Pollution Control Act, the Clean Air Act, and other U.S. federal statutes governing the treatment and disposal of hazardous wastes. Emera Maine is also regulated by the State of Maine’s Department of Environmental Protection.

Emera Caribbean

As of December 31, 2015, Emera Caribbean includes a 95.5% indirect interest in BLPC, a 49.6 % indirect controlling interest in Domlec, an 80.4% direct and indirect interest in GBPC, an 18.2% indirect interest in Lucelec and a wholly owned indirect interest in Emera Utility Service Bahamas. As of February 25, 2016, Emera Caribbean’s indirect interest in BLPC has increased to 100%.

BLPC

BLPC is a vertically-integrated utility and the provider of electricity on the Caribbean island of Barbados with approximately $0.5 billion of assets. It serves approximately 126,000 customers, has a workforce of approximately 330 employees and is regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted to BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. Emera acquired its indirect interest in BLPC through the purchase of approximately 80.1% of the outstanding common shares of LPH, now ECI, and the parent company of BLPC in 2010. In 2015, Emera increased its ownership interest in BLPC to 95.5%. Emera initiated a process to purchase the remaining 4.5% of common shares from minority shareholders of ECI, which was completed on February 25, 2016.

BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and providing an appropriate return to investors. BLPC’s approved allowable regulated return on rate base for 2015 and 2014 is 10%.

A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. The Fair Trading Commission, Barbados has approved the calculation of the fuel charge, which is adjusted on a monthly basis.

Domlec

Domlec is a vertically-integrated utility on the island of Dominica with approximately $ 0.1 billion of assets. Domlec serves approximately 36,000 customers, has a workforce of 238 employees, and is regulated by the IRCD. On October 7, 2013, the IRCD issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014 for a period of 25 years. These new licenses replaced the existing license, which was due to expire on December 31, 2015. Domlec’s approved allowable regulated return on rate base for 2015 and 2014 was 15%.

2015 Annual Information Form 38

A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely manner.

GBPC

Emera, through its wholly owned subsidiary ECHL, has a 50.0% direct and 30.4% indirect interest in GBPC, a vertically-integrated utility and the sole provider of electricity on Grand Bahama Island in The Bahamas with approximately $0.4 billion of assets. GBPC serves approximately 19,000 customers, has a workforce of approximately 205 employees and is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to generate, transmit and distribute electricity on the island until 2054. GBPC’s approved allowable regulated return on rate base for 2015 and 2014 was 10%. A fuel pass-through mechanism provides the opportunity to recover fuel costs in a timely manner. ECHL holds its indirect interest in GBPC through ICDU, which in turn owns a 50% interest in GBPC. ICDU is listed on the Bahamas International Securities Exchange.

Effective February 1, 2016, the GBPA approved GBPC’s GRA for the 2016 through 2018 period. Residential customers will see decreases of up to 4.5%, while commercial customers will see an increase of 1.5%. Commercial customers consume approximately 70% of GBPC’s production. Rates were approved based upon an 8.8% allowable return on rate base. This rate decision will allow for customers to install renewable energy systems and sell their excess energy to GBPC. This is based on a tariff rider scheduled to be in place by Q3 2016.

On June 29, 2012, GBPC announced a new regulatory rate structure which was approved by the GBPA and became effective July 1, 2012. The new regulatory rate structure consists of two components: (i) a base rate intended to recover GBPC’s operating expenses, depreciation and return on capital investment; and (ii) a fuel charge intended to recover all of GBPC’s fuel costs.

On January 17, 2013, GBPC and the GBPA finalized an Operating Protocol and Regulatory Framework agreement. This agreement formalized the operating protocols and regulatory construct GBPC agreed to in principle in June 2012.

As part of the initial rate case filing under the new regulatory structure, the GBPA approved a return on rate base of 10%. Every three years, commencing in January 2016, base rates will be reviewed and approved by the GBPA.

As a component of its regulatory agreement with the GBPA, GBPC has an earnings share mechanism to allow for earnings above or below its approved 10% return on rate base to be deferred to a regulatory asset or liability at the rate of 50% of amounts below a 9% return on rate base and 50% of amounts above 11% return on rate base respectively.

Lucelec

Emera owns an 18.2% indirect interest, through ECI’s 19.1% interest in Lucelec, a vertically-integrated regulated electric utility on the Caribbean island of St. Lucia. Lucelec is listed on the Eastern Caribbean Securities Exchange.

Emera Utility Services Bahamas

Emera Utility Services Bahamas provides utility construction services in The Bahamas.

2015 Annual Information Form 39

Market and Sales

Emera Caribbean Revenue and Electricity Sales by Customer Class⁽¹⁾

	Electric Revenues (%)				GWh Electric Sales Volumes (%)
For the year ended December 31	2015		2014		2015		2014
Residential		32.4		33.4		33.7		33.4
Commercial		57.0		58.6		56.8		56.9
Industrial		8.8		6.3		7.7		7.7
Other		1.8		1.7		1.8		2.0
Total		100.0		100.0		100.0		100.0

(1) Information included above includes 100% of BLPC, GBPC and Domlec.

Energy Sources and Generation

BLPC’s and GBPC’s energy sources for its electricity generation is primarily heavy fuel oil used for base load generation and light fuel oil used for peaking generation.

BLPC owns approximately 239 MW of generation comprised of: (i) 5 gas turbine units with a combined capacity of 86 MW (light oil and jet fuel oil-fired); (ii) 6 diesel units with a combined capacity of 113 MW (heavy oil-fired); and (ii) 2 steam units with a combined capacity of 40 MW (heavy oil-fired).

GBPC owns approximately 98 MW of heavy fuel oil-fired and medium and slow speed diesel generating units.

Domlec owns approximately 20 MW of oil-fired generation and 7 MW of hydro production.

Comparative costs of fuel sources fluctuate from year to year. For information describing the percentage of total electric energy generated by fuel source and for information related to the cost of electricity generation, see the “Regulated Fuel for Generation and Purchased Power” section of the MD&A, which is incorporated herein by reference.

System Operation

BLPC, GBPC and Domlec have system control centers which co-ordinate and control the electric generation and transmission facilities with the goal of providing a reliable and secure electricity supply while maintaining economy of operations. The system control centre is linked to the generating stations and other key parts of the system by the “Supervisory Control and Data Acquisition” system, a voice and data communications network.

Transmission and Distribution

BLPC, GBPC and Domlec transmit and distribute electricity from their generating stations to their customers.

BLPC’s transmission system consists of 116 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of 2,800 km of distribution lines which includes distribution supply substations.

GBPC’s transmission system consists of 138 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of approximately 850 km of distribution lines which includes distribution supply substations.

2015 Annual Information Form 40

Domlec’s transmission system consists of 452 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of approximately 640 km of distribution lines which includes distribution supply substations.

Contribution to Consolidated Net Income

Emera Caribbean’s contribution to Emera’s consolidated net income was $31.4 million USD in 2015 and $26.0 million USD in 2014.

Seasonal Nature

Electricity sales and related generation varies significantly over the year in the Caribbean; Q3 is typically the strongest period, reflecting warmer weather.

Capital Expenditures

Emera Caribbean’s capital expenditures for the year ended 2015 were approximately $44 million (2014 – $30 million).

Environmental Considerations

Emera Caribbean has implemented a Health Safety Environmental and Management system to assist in safeguarding the health and safety of its employees, contractors and customers while ensuring protection of the environment.

Emera Energy

Emera Energy consists of Emera’s wholly owned Emera Energy Services, EE New England Gas Generation, Bayside Power LP and Brooklyn Energy; and Emera’s indirect 50% interest in Bear Swamp. On January 29, 2015, Emera sold its interest in NWP to its 51% partner, First Wind.

Emera Energy Services

Emera Energy Services derives revenue and earnings from the wholesale marketing and trading of natural gas, electricity and other energy-related commodities and derivatives within the Company’s strict risk tolerances, including those related to value-at-risk (VaR) and credit exposure. More specifically, Emera Energy purchases and sells physical natural gas and related transportation capacity rights, as well as providing related energy asset management services. EES is also responsible for commercial management of electricity production and fuel procurement for Emera Energy Generation’s fleet. Established in 2002, Emera Energy’s marketing and trading business currently has approximately 80 employees engaged in commercial activities and related back office, legal and other support functions. The primary market for the marketing and trading business is northeastern North America, including the Marcellus shale gas region, the U.S. Gulf Coast and Central Canada. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. Marketing and trading operates in a competitive environment, and its business relies on knowledge of the region’s energy markets, understanding of pipeline infrastructure, a network of counterparty relationships and a focus on customer service. Emera Energy invests in physical transportation capacity rights to move gas across its portfolio, utilizes financial products to hedge commodity prices, and minimizes open commodity positions in order to maintain the low to moderate risk profile of its marketing and trading business.

2015 Annual Information Form 41

Emera Energy Generation

Emera Energy wholly owns and operates a portfolio of high efficiency, non-utility electricity generating facilities in northeast North America. Emera Energy has approximately 125 employees in its wholly owned generation business. The New England facilities participate in the regional capacity market and are compensated for being available to provide power. For the portion of output not committed under power purchase agreements, Emera Energy’s generation facilities sell into price-based competitive markets and earn revenues through the physical delivery of power and ancillary services, such as load regulation.

Market and Sales

Information regarding these facilities is summarized in the following table:

Wholly Owned Generation Facilities	Location	Capacity (MW)		Commissioning / In-Service Date	Fuel	Description
New England
Bridgeport (1)	Connecticut		560	1999	Natural gas	Selling electricity and capacity to ISO-NE
Tiverton	Rhode Island		265	2000	Natural gas	Selling electricity and capacity to ISO-NE
Rumford	Maine		265	2000	Natural gas	Selling electricity and capacity to ISO-NE
Total New England			1,090
Maritime Canada
Bayside	New Brunswick		290	2001	Natural gas	Long-term power purchase agreement November - March; Selling electricity to Maritime Provinces and ISO-NE for remainder of year
Brooklyn	Nova Scotia		30	1996	Biomass	Long-term purchase power agreement
Total Maritime Canada			320
Total			1,410

(1) A Q2 2015 upgrade at Bridgeport increased its nameplate capacity from 540 MW to 560 MW.

Information regarding Emera Energy’s equity investment in Bear Swamp is summarized below:

Investments in Generation Facilities (1)	Ownership (%)		Location	Capacity (MW)		Fuel	Description
New England
Bear Swamp		50	Massachusetts		600	Hydro	Long-term power purchase agreement and selling electricity and capacity to ISO-NE

(1) In January 29, 2015, Emera completed the sale of its 49% interest in NWP to First Wind for $223.3 million USD. Emera’s carrying value of its 49% interest as at December 31, 2014 was $204.4 million USD.

Information regarding Emera Energy’s revenues is summarized below:

Emera Energy Revenue

For the year ended December 31	2015		2014
Electricity sales	$	463.1	$	517.7
Capacity revenues	$	43.7	$	45.8
Marketing and trading margin	$	83.1	$	237.4
Total	$	589.9	$	800.9

2015 Annual Information Form 42

Contribution to Consolidated Net Income

Emera Energy’s contribution to Emera’s consolidated net income was $98.9 million in 2015 and $185.7 million in 2014.

Seasonal Nature

The electricity generation business in the northeast of the United States is seasonal. Q1, Q3 and Q4 are generally the strongest periods, reflecting colder weather, and fewer daylight hours in the winter season, and cooling load in the summer.

Capital Expenditures

Emera Energy’s capital expenditures for the year ended 2015 were approximately $42 million (2014 – $63 million). The 2015 capital expenditures included a Q2 2015 upgrade at the Bridgeport facility that increased the nameplate capacity from 540 MW to 560 MW. The 2014 capital expenditures included a major refit and upgrade at the Bridgeport facility that increased the nameplate capacity from 520 MW to 540 MW.

Environmental Considerations

EE New England Gas Generation is subject to the Regional Greenhouse Gas Initiative (RGGI) for carbon dioxide emissions and the Acid Rain Program for sulphur dioxide emissions. EE New England Gas Generation emits approximately two million tons of carbon dioxide per year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions programs could adversely impact financial and operational performance.

Pipelines

Pipelines consists of Emera’s wholly owned EBPC and Emera’s 12.9% interest in M&NP.

EBPC

EBPC owns Brunswick Pipeline, a 145-km pipeline delivering re-gasified natural gas from the Canaport LNG import terminal near Saint John, New Brunswick to markets in the Northeastern United States. The pipeline travels through southwest New Brunswick and connects with M&NP at the Canada/US border near Baileyville, Maine. Since its commissioning in July 2009, the pipeline has been used solely to transport natural gas for RECL under a 25 year firm service agreement. Brunswick Pipeline is regulated by the NEB, which has classified it as a Group II pipeline.

M&NP

Emera owns a 12.9% interest in M&NP, which is a 1,400 km pipeline that transports natural gas from offshore Nova Scotia to markets in Maritime Provinces and the Northeastern United States.

Contribution to Consolidated Net Income

Pipelines’ contribution to Emera’s consolidated net income was $37.5 million in 2015 and $32.7 million in 2014.

Environmental Considerations

Brunswick Pipeline is regulated by the NEB and subject to both federal and provincial environmental regulations. Brunswick Pipeline has comprehensive integrity, safety and environmental programs in place, including an environmental management system and regularly scheduled physical inspections of the pipeline.

2015 Annual Information Form 43

Economic Dependence

Brunswick Pipeline has a 25-year firm transport or pay service agreement with RECL, which runs to 2034. The risk of non-payment is mitigated as Repsol, the parent company of RECL, has provided EBPC with a guarantee for all RECL’s payment obligations under the firm service agreement.

Corporate and Other

Contribution to Consolidated Net Income

Corporate and Other’s contribution to Emera’s consolidated net income was $45.3 million in 2015 and $(7.7) million in 2014. Included in the fiscal 2015 results are acquisition related after-tax costs of $52.8 million and an after-tax mark-to-market gain of $100.5 million related to the effect of USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the Debenture Offering for the TECO Transaction.

Capital Expenditures

Corporate and Other capital expenditures for the year ended 2015 were approximately $10.0 million (2014 – $10.0 million).

Other Emera Environmental Matters

Emera’s activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste. Emera estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations will be approximately $43.2 million during fiscal 2015 and are estimated to be $63.9 million from 2016 through 2019. The estimated expenditures do not include: (i) costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions; and (ii) expenditures related to the addition of renewable or cleaner energy generation.

Risk Factors

See the “Business Risks and Risk Management” section of the MD&A and “Principal Risks and Uncertainties” in the Commitments and Contingencies note to Emera’s financial statements for the year ended December 31, 2015, which are each incorporated herein by reference.

Capital Structure

The authorized capital of Emera consists of an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares. Each class of preferred shares are issuable in series.

As at December 31, 2015, 147,205,643 common shares, 3,864,636 Series A First Preferred Shares, 2,135,364 Series B First Preferred Shares, 10,000,000 Series C First Preferred Shares, 5,000,000 Series E First Preferred Shares and 8,000,000 Series F First Preferred Shares were issued and outstanding.

2015 Annual Information Form 44

Common Shares

The holders of common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Emera, other than separate meetings of holders of any other class or series of shares, and to one vote in respect of each common share held at such meetings.

The holders of common shares are entitled to dividends on a pro rata basis, as and when declared by the Board. Subject to the rights of the holders of the first preferred shares and second preferred shares, if any, who are entitled to receive dividends in priority to the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other class of shares of Emera.

On the liquidation, dissolution or winding-up of Emera, holders of common shares are entitled to participate rateably in any distribution of assets of Emera, subject to the rights of holders of first preferred shares and second preferred shares, if any, who are entitled to receive the assets of the Company on such a distribution in priority to the holders of the common shares.

There are no pre-emptive, redemption, purchase or conversion rights attaching to the common shares.

The foregoing description is subject to the “Share Ownership Restrictions” section below.

Emera First Preferred Shares

Series A First Preferred Shares

The holders of Series A First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

• where entitled by law;

• for meetings of the holders of first preferred shares as a class and holders of Series A First Preferred Shares as a series; and

• in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series A First Preferred Shares.

In any instance where the holders of Series A First Preferred Shares are entitled to vote, each holder shall have one vote for each Series A Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series A First Preferred Shares were entitled to receive fixed cumulative preferred cash dividends in the amount of $0.2750 per share per quarter during the five-year period commencing on August 15, 2010 and ending on (and inclusive of) August 14, 2015, as and when declared by the Board. For each five-year period after this date, the holders of Series A First Preferred Shares will be entitled to receive reset fixed cumulative preferred cash dividends. The reset annual dividends per share will be determined by multiplying the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 1.84%, by $25.00. The dividend rate for the Series A First Preferred Shares was set at $0.1597 per share per quarter for the five-year period commencing on August 15, 2015 and ending on (and inclusive of) August 14, 2020.

The Series A First Preferred Shares were not redeemable by Emera prior to August 15, 2015. On that date and on August 15 every five years thereafter, Emera has the right in certain circumstances to redeem for cash all or any part of the then outstanding Series A First Preferred Shares at a price of $25.00 per share plus any accrued and unpaid dividends up to but excluding the date fixed for redemption. Emera did not exercise its right to redeem all or any part of the outstanding Series A First Preferred Shares on August 15, 2015.

2015 Annual Information Form 45

Subject to the automatic conversion described below and the right of Emera to redeem the Series A First Preferred Shares, on August 15, 2015 and on August 15 every five years thereafter, the holders of Series A First Preferred Shares have the right to convert any or all of their Series A First Preferred Shares into an equal number of Series B First Preferred Shares. In addition, the Series A First Preferred Shares may be automatically converted by Emera into Series B First Preferred Shares if Emera determines that there are less than 1,000,000 Series A First Preferred Shares outstanding. On August 15, 2015, 2,135,364 issued and outstanding Series A First Preferred Shares were tendered for conversion, on a one-for-one basis, into Series B First Preferred Shares.

Series B First Preferred Shares

The holders of Series B First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

• where entitled by law;

• for meetings of the holders of first preferred shares as a class and holders of Series B First Preferred Shares as a series; and

• in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series B First Preferred Shares.

In any instance where the holders of Series B First Preferred Shares are entitled to vote, each holder shall have one vote for each Series B Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series B First Preferred Shares are entitled to receive floating rate cumulative preferred cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-bill Rate on the applicable reset date plus 1.84%, by $25.00. The dividend rate for the Series B First Preferred Shares was set at $0.1508 per share for the quarter commencing on August 15, 2015 and ended on (and inclusive of) November 14, 2015, and was paid on November 15, 2015. The dividend rate for the Series B First Preferred Shares was subsequently reset to $0.1425 per share for the quarter commencing on November 15, 2015 and ending on (and inclusive of) February 14, 2016.

Emera has the right in certain circumstances to redeem for cash all or any part of the outstanding Series B First Preferred Shares at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on August 15, 2020 and on August 15 every five years thereafter, or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2015.

Subject to the automatic conversion described below and the right of Emera to redeem the Series B First Preferred Shares, on August 15, 2020 and on August 15 every five years thereafter, the holders of Series B First Preferred Shares have the right to convert any or all of their Series B First Preferred Shares into an equal number of Series A First Preferred Shares. In addition, Series B First Preferred Shares may be automatically converted by Emera into Series A First Preferred Shares if Emera determines that there are less than 1,000,000 Series B First Preferred Shares outstanding.

Series C First Preferred Shares

The holders of Series C First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

• where entitled by law;

2015 Annual Information Form 46

• for meetings of the holders of first preferred shares as a class and holders of Series C First Preferred Shares as a series; and

• in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series C First Preferred Shares.

In any instance where the holders of Series C First Preferred Shares are entitled to vote, each holder shall have one vote for each Series C Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series C First Preferred Shares are entitled to receive fixed cumulative preferred cash dividends in the amount of $0.25625 per share per quarter during the six-year period commencing on August 15, 2012 and ending on (and inclusive of) August 14, 2018, as and when declared by the Board. For each five year period after this date, the holders of Series C First Preferred Shares will be entitled to receive reset fixed cumulative preferred cash dividends. The reset annual dividends per share will be determined by multiplying the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 2.65%, by $25.00.

The Series C First Preferred Shares will not be redeemable by Emera prior to August 15, 2018. On that date and on August 15 every five years thereafter, Emera has the right in certain circumstances to redeem for cash all or any part of the then outstanding Series C First Preferred Shares at a price equal to $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption.

Subject to the automatic conversion described below and the right of Emera to redeem Series C First Preferred Shares, on August 15, 2018 and on August 15 every five years thereafter, the holders of Series C First Preferred Shares have the right to convert any or all of their Series C First Preferred Shares into an equal number of Series D First Preferred Shares. In addition, Series C First Preferred Shares may be automatically converted by Emera into Series D First Preferred Shares if Emera determines that there are less than 1,000,000 Series C First Preferred Shares outstanding.

Series D First Preferred Shares

As at December 31, 2015, there were no Series D First Preferred Shares issued and outstanding.

The holders of Series D First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

• where entitled by law;

• for meetings of the holders of first preferred shares as a class and holders of Series D First Preferred Shares as a series; and

• in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series D First Preferred Shares.

In any instance where the holders of Series D First Preferred Shares are entitled to vote, each holder shall have one vote for each Series D Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series D First Preferred Shares will be entitled to receive floating rate cumulative preferred cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-bill Rate on the applicable reset date plus 2.65%, by $25.00.

Emera has the right in certain circumstances to redeem for cash all or any part of the outstanding Series D First Preferred Shares at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on August 15, 2023 and on August 15 every 5 years

2015 Annual Information Form 47

thereafter, or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2018.

Subject to the automatic conversion described below and the right of Emera to redeem the Series D First Preferred Shares, on August 15, 2023 and on August 15 every five years thereafter, the holders of Series D First Preferred Shares have the right to convert any or all of their Series D First Preferred Shares into an equal number of Series C First Preferred Shares. In addition, Series D First Preferred Shares may be automatically converted by Emera into Series C First Preferred Shares if Emera determines that there are less than 1,000,000 Series D First Preferred Shares outstanding.

Series E First Preferred Shares

The holders of Series E First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

• where entitled by law;

• for meetings of the holders of first preferred shares as a class and holders of Series E First Preferred Shares as a series; and

• in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series E First Preferred Shares.

In any instance where the holders of Series E First Preferred Shares are entitled to vote, each holder shall have one vote for each Series E Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series E First Preferred Shares are entitled to receive fixed cumulative preferred cash dividends in the amount of $1.125 per share per annum in perpetuity, subject to the Company’s redemption rights. On or after August 15, 2018, the Company may, on not less than 30 nor more than 60 days’ notice, redeem the Series E First Preferred Shares in whole or in part, at the Company’s option, by the payment in cash of $26.00 per Series E First Preferred Share if redeemed prior to August 15, 2019; at $25.75 per Series E First Preferred Share if redeemed on or after August 15, 2019 but prior to August 15, 2020; at $25.50 per Series E First Preferred Share if redeemed on or after August 15, 2020 but prior to August 15, 2021; at $25.25 per Series E First Preferred Share if redeemed on or after August 15, 2021 but prior to August 15, 2022; and at $25.00 per Series E First Preferred Share if redeemed on or after August 15, 2022, in each case together with all declared and unpaid dividends up to but excluding the date fixed for redemption.

Series F First Preferred Shares

The holders of Series F First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

• where entitled by law;

• for meetings of the holders of first preferred shares as a class and holders of Series F First Preferred Shares as a series; and

• in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series F First Preferred Shares.

In any instance where the holders of Series F First Preferred Shares are entitled to vote, each holder shall have one vote for each Series F First Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series F First Preferred Shares are entitled to receive fixed cumulative preferred cash dividends in the amount of $0.265625 per share per quarter during the period commencing on August 15, 2014 and ending on (and

2015 Annual Information Form 48

inclusive of) February 14, 2020, as and when declared by the Board. For each five-year period after this date, the holders of Series F First Preferred Shares will be entitled to receive reset fixed cumulative preferred cash dividends. The reset annual dividends per share will be determined by multiplying the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 2.63%, by $25.00.

The Series F First Preferred Shares will not be redeemable by Emera prior to February 15, 2020. On that date and on February 15 every five years thereafter, Emera has the right in certain circumstances to redeem for cash all or any part of the then outstanding Series F First Preferred Shares, at a price of $25 per share plus any accrued and unpaid dividends up to but excluding the date fixed for redemption.

Subject to the automatic conversion described below and the right of Emera to redeem the Series F First Preferred Shares, on February 15, 2020 and on February 15 every five years thereafter, the holders of the Series F First Preferred Shares have the right to convert any or all of their Series F First Preferred Shares into an equal number of Series G First Preferred Shares. In addition, Series F First Preferred Shares may be automatically converted by Emera into Series G First Preferred Shares if Emera determines that there are less than 1,000,000 Series F First Preferred Shares outstanding.

Series G First Preferred Shares

As at December 31, 2015, there were no Series G First Preferred Shares issued and outstanding.

The holders of Series G First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

• where entitled by law;

• for meetings of the holders of first preferred shares as a class and holders of Series G First Preferred Shares as a series; and

• in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series G First Preferred Shares.

In any instance where the holders of Series G First Preferred Shares are entitled to vote, each holder shall have one vote for each Series G Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series G First Preferred Shares will be entitled to receive floating rate cumulative preferred cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-bill Rate on the applicable reset date plus 2.63%, by $25.00.

Emera has the right in certain circumstances to redeem for cash all or any part of the outstanding Series G First Preferred Shares at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on February 15, 2025 and on February 15 every five years thereafter, or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after February 15, 2020.

Subject to the automatic conversion described below and the right of Emera to redeem the Series G First Preferred Shares, on February 15, 2025 and on February 15 every five years thereafter, the holders of Series G First Preferred Shares have the right to convert any or all of their Series G First Preferred Shares into an equal number of Series F First Preferred Shares. In addition, Series G First Preferred Shares may be automatically converted by Emera into Series F First Preferred Shares if Emera determines that there are less than 1,000,000 Series G First Preferred Shares outstanding.

2015 Annual Information Form 49

Series A, B, C, D, E, F, G First Preferred Shares

The first preferred shares of each series rank on a parity with the first preferred shares of every other series and are entitled to a preference over the second preferred shares, the common shares, and any other shares ranking junior to the first preferred shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the first preferred shares, the holders of the first preferred shares will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.

Emera Second Preferred Shares

The second preferred shares have special rights, privileges, restrictions and conditions substantially similar to the first preferred shares, except that the second preferred shares rank junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Emera in the event of liquidation, dissolution or winding-up of Emera. As at December 31, 2015, Emera had not issued any second preferred shares.

Share Ownership Restrictions

As required by the Nova Scotia Power Reorganization (1998) Act and pursuant to the Nova Scotia Power Privatization Act, the articles of association of Emera provide that no person, together with associates thereof, may subscribe for, have transferred to that person, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only in the aggregate, voting shares of Emera to which are attached more than 15% of the votes that may ordinarily be cast to elect directors of Emera. Non-residents of Canada may not subscribe for, have transferred to them, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, in the aggregate, voting shares of Emera to which are attached more than 25% of the votes that may ordinarily be cast to elect directors. Votes cast by non-residents on any resolution at a meeting of common shareholders of Emera will be pro-rated so that such votes will not constitute more than 25% of the total number of votes cast.

The common shares, and in certain circumstances the Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares and Series F First Preferred Shares are considered to be voting shares for purposes of the constraints on share ownership.

Emera’s articles of association contain provisions for the enforcement of these constraints on share ownership, including provisions for suspension of voting rights, forfeiture of dividends, prohibitions of share transfer and issuance, compulsory sale of shares and redemption, and suspension of other shareholder rights. Emera’s Board may require shareholders to furnish statutory declarations relevant to the enforcement of the restrictions.

NSPI Series D First Preferred Shares

On October 15, 2015, NSPI redeemed all of its outstanding NSPI Series D First Preferred Shares. As a result, zero NSPI Series D First Preferred Shares were issued and outstanding as of December 31, 2015.

2015 Annual Information Form 50

Dividends

Any dividend payments will be at the Board’s discretion based upon earnings and capital requirements and any other factors as the Board may consider relevant.

The Board approved the payment of the following dividends during the last three completed fiscal years:

Common Shares (1) and (2)
Fiscal Year	Record Date		Date Paid		Dividend (per share) ($)
2015		November 2		November 16		0.4750
		July 31		August 17		0.4000
		May 1		May 15		0.4000
		February 3		February 17		0.3875
2014		November 3		November 17		0.3875
		July 31		August 15		0.3625
		May 1		May 15		0.3625
		February 3		February 17		0.3625
2013		November 1		November 15		0.3625
		July 31		August 15		0.3500
		May 1		May 15		0.3500
		February 1		February 15		0.3500
Series A First Preferred Shares
Fiscal Year	Record Date		Date Paid		Dividend (per share)
2015		November 2		November 15		0.1597
		July 31		August 17		0.2750
		May 1		May 15		0.2750
		February 3		February 17		0.2750
2014		November 3		November 17		0.2750
		July 31		August 15		0.2750
		May 1		May 15		0.2750
		February 3		February 17		0.2750
2013		November 1		November 15		0.2750
		July 31		August 15		0.2750
		May 1		May 15		0.2750
		February 1		February 15		0.2750
Series B First Preferred Shares (3)
Fiscal Year	Record Date		Date Paid		Dividend (per share)
2015		November 2		November 15		0.1508
Series C First Preferred Shares
Fiscal Year	Record Date		Date Paid		Dividend (per share)
2015		November 2		November 15		0.25625
		July 31		August 17		0.25625
		May 1		May 15		0.25625
		February 3		February 17		0.25625
2014		November 3		November 17		0.25625
		July 31		August 15		0.25625
		May 1		May 15		0.25625
		February 3		February 17		0.25625

2015 Annual Information Form 51

2013	November 1	November 15		0.25625
	July 31	August 15		0.25625
	May 1	May 15		0.25625
	February 1	February 15		0.25625
Series E First Preferred Shares (4)
Fiscal Year	Record Date	Date Paid	Dividend (per share)
2015	November 2	November 15		0.28125
	July 31	August 17		0.28125
	May 1	May 15		0.28125
	February 3	February 17		0.28125
2014	November 3	November 17		0.28125
	July 31	August 15		0.28125
	May 1	May 15		0.28125
	February 3	February 17		0.28125
2013	November 1	November 15		0.28125
	July 31	August 15		0.20340
Series F First Preferred Shares (5)
Fiscal Year	Record Date	Date Paid	Dividend (per share)
2015	November 2	November 15		0.265625
	July 31	August 17		0.265625
	May 1	May 15		0.265625
	February 3	February 17		0.265625
2014	November 3	November 17		0.265625
	July 31	August 15		0.195000

(1) On February 6, 2015, Emera approved an increase in the annual common share dividend rates from $1.55 to $1.60. The first payment was effective May 2015.

(2) On August 11, 2015, Emera approved an increase in the annual common share dividend rate from $1.60 to $1.90. The first payment was effective November 2015.

(3) The Series B First Preferred Shares were issued August 17, 2015

(4) The Series E First Preferred Shares were issued June 10, 2013.

(5) The Series F First Preferred Shares were issued June 9, 2014.

Emera maintains the Dividend Reinvestment Plan, which provides an opportunity for shareholders to reinvest dividends to make cash contributions for the purpose of purchasing common shares at a discount of up to 5% from the average market price of Emera’s common shares.

Credit Ratings

Emera has the following credit ratings by the Rating Agencies ⁽¹⁾:

	DBRS	S&P
Corporate	BBB (high)	BBB +
Senior unsecured debt program	BBB(high)	BBB
First Preferred Shares	Pfd-3 (high)	P-2 (low)

(1) Ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities and are indicators of the likelihood of the payment capacity and willingness of an issuer to meet its financial commitment in accordance with the terms of the obligation. The credit ratings assigned by the Rating Agencies are not recommendations to buy, sell, or hold securities in as much as such ratings are not a comment upon the market price of the securities or their stability for a particular investor. The credit ratings assigned to the securities may not reflect the potential impact of all risks on the value of the securities. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a Rating Agency in the future if in its judgment circumstances so warrant.

2015 Annual Information Form 52

DBRS

DBRS’ credit ratings are on a long term debt rating scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB (high) from DBRS with respect to senior unsecured debt is characterized as “adequate credit quality” and is the fourth highest of ten available rating categories. The capacity for the repayment of financial obligations is considered acceptable. Entities rated BBB may be vulnerable to future events. The assignment of a “(high)” or “(low)” designation indicates relative standing within such category.

With respect to the Series A First Preferred Shares, the Series B First Preferred Shares, the Series C First Preferred Shares, the Series E First Preferred Shares and the Series F First Preferred Shares, the rating of Pfd-3 (high) is the highest of three sub-categories within the third highest rating of six standard categories of ratings utilized by DBRS for preferred shares.

On March 11, 2015, DBRS removed Emera from “Under Review with Developing Implications” following the closing of the Brunswick Pipeline financing and the sale of NWP. On the same date, DBRS confirmed Emera’s Issuer Rating and Medium-Term Notes rating at BBB (high) and the Cumulative Preferred Shares Rating at Pfd-3 (high), all with stable trends.

On September 4, 2015, following the announcement of the TECO Transaction, DBRS placed the ratings of Emera “Under Review with Developing Implications”. The rating actions reflect DBRS’s view that while the TECO Transaction would have a relatively neutral impact on Emera’s business risk assessment, the impact on the financial risk assessment was uncertain at the time of the ratings actions, as Emera’s financing plan had not been finalized. DBRS indicated that it will further review Emera’s financing plan when it is finalized.

S&P

S&P’s credit ratings are on a long term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB+ obtained from S&P in respect of the corporate rating indicates that the issuer has adequate capacity to meet its financial commitments and is the fourth highest of ten available rating categories. The rating of BBB from S&P in respect of the senior unsecured debt indicates that the obligation exhibits adequate protection parameters and is the fourth highest of ten available ratings categories. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation. The addition of a “(+)” or “(-)” designation after a rating indicates the relative standing within a particular category.

A P-2 (low) rating with respect to Emera’s Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares and Series F First Preferred Shares is the third lowest of the three sub-categories within the second highest rating of the eight standard categories of ratings utilized by S&P for preferred shares.

On September 8, 2015, S&P revised its outlook on Emera to negative from stable, while affirming all ratings on Emera, including its ‘BBB+’ long-term corporate rating. S&P indicated that the negative outlook is primarily associated with the Debentures and the risk that they will not be converted into equity upon successful close of the TECO Transaction. S&P could revise its outlook to stable within a two-year outlook period, if the Debentures are successfully converted.

Emera has made, or will make, payments in the ordinary course to the rating agencies in connection with the assignment of ratings on both Emera and its securities. In addition, Emera has made customary payments in respect of certain subscription services provided to Emera by the rating agencies during the last two years.

2015 Annual Information Form 53

Market for Securities

Trading Price and Volume

Emera’s common shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares and instalment receipts are listed and posted for trading on the TSX under the symbols “EMA”, “EMA.PR.A”, “EMA.PR.B”, “EMA.PR.C”, “EMA.PR.E”, “EMA.PR.F” and “EMA.IR”, respectively.

The trading volume and high and low price for Emera’s securities for each month of 2015 are set out below:

Common Shares
2015	High($)		Low($)		Volume
January		42.21		38.35		7,322,144
February		43.62		40.76		7,339,844
March		42.30		40.03		8,675,504
April		42.15		40.16		4,588,076
May		42.44		40.17		6,405,646
June		42.30		39.12		5,787,706
July		43.83		39.42		5,091,751
August		47.51		41.67		7,641,029
September		45.29		41.49		13,660,371
October		44.69		42.71		8,982,241
November		43.38		42.00		6,464,684
December		44.01		41.32		8,154,464

Series B First Preferred Shares*
2015	High($)		Low($)		Volume
January
February
March
April
May
June
July
August		14.50		12.02		14,331
September		13.25		11.85		52,285
October		12.90		10.80		63,456
November		14.31		11.99		108,805
December		14.00		12.10		127,536

* The Series B First Preferred Shares commenced trading on August 19, 2015

Series A First Preferred Shares
2015	High($)		Low($)		Volume
January		21.28		17.02		281,745
February		18.02		17.00		184,479
March		18.70		17.25		193,563
April		18.16		15.50		280,249
May		18.54		17.01		84,954
June		17.87		16.70		111,007
July		16.61		14.50		157,143
August		15.94		14.35		111,229
September		15.69		13.45		96,614
October		14.75		12.61		277,140
November		14.89		13.45		111,698
December		14.26		12.47		173,789

Series C First Preferred Shares
2015	High($)		Low($)		Volume
January		25.85		22.08		222,362
February		24.90		23.28		184,333
March		24.84		23.46		393,340
April		24.59		21.00		312,749
May		24.49		22.70		151,381
June		23.67		21.75		120,171
July		22.86		19.79		184,954
August		20.80		19.50		140,486
September		20.00		16.35		341,690
October		20.14		16.41		279,608
November		20.30		18.56		320,321
December		19.74		15.80		462,493

2015 Annual Information Form 54

Series E First Preferred Shares
2015	High($)		Low($)		Volume
January		24.69		22.00		87,660
February		23.80		23.10		136,878
March		24.48		22.81		230,668
April		23.76		23.10		217,778
May		23.75		22.25		52,284
June		23.29		21.52		120,918
July		22.43		21.38		33,039
August		21.25		20.25		31,591
September		21.15		18.96		61,368
October		21.00		19.15		67,754
November		20.94		20.21		62,987
December		20.69		19.20		82,130

Debentures – Instalment Receipts*
2015	High($)		Low($)		Volume
January
February
March
April
May
June
July
August
September		35.50		33.01		1,432,546
October		36.20		33.35		1,396,630
November		34.80		32.02		513,500
December		35.75		30.55		941,485

* The Instalment Receipts commenced trading on September 28, 2015

Series F First Preferred Shares
2015	High($)		Low($)		Volume
January		26.00		24.46		141,646
February		25.39		24.01		102,381
March		25.45		23.53		243,907
April		25.10		21.97		281,340
May		24.70		22.89		63,771
June		23.71		21.84		61,898
July		23.48		21.03		120,376
August		22.09		20.23		130,862
September		21.20		17.43		125,078
October		21.48		17.56		209,786
November		21.50		19.78		230,550
December		20.65		16.74		450,037

Transfer Agent and Registrar

As of December 31, 2015 Computershare acted as Emera’s transfer agent and registrar. The registers of transfers of securities of Emera were located at Computershare’s principal offices in Vancouver, Calgary, Toronto, Montreal and Halifax. Effective March 28, 2016, Emera appointed CST to replace Computershare as Emera’s transfer agent and registrar. The registers of transfers of securities of Emera are located at CST’s principal offices in Vancouver, Calgary, Toronto, Montreal and Halifax.

2015 Annual Information Form 55

Directors and Officers

Directors

The following information is provided for each Director of Emera as of December 31, 2015:

Name and Residence	Principal Occupations During the Past Five Years and Other Information	Director Since (1)
Sylvia D. Chrominska(4) Toronto, Ontario Canada	Former Group Head of Global Human Resources and Communications for the Bank of Nova Scotia, where she had global responsibility for human resources, corporate communications, government relations, public policy and corporate social responsibility of the Scotiabank Group. Former Chair of the Board of Scotia Group Jamaica Limited and Former Chair of the Board of Scotiabank Trinidad and Tobago Limited. A director of Wajax Corporation.	2010
Henry E. Demone(4) Lunenburg, Nova Scotia Canada	Chairman of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May 2015. A director of Saputo Inc.	2014
Allan L. Edgeworth(7) Calgary, Alberta Canada	Former President of ALE Energy Inc., a private consulting company. Former President and Chief Executive Officer of Alliance Pipeline. Director of AltaGas Ltd.	2005
James D. Eisenhauer Lunenburg, Nova Scotia Canada	President and Chief Executive Officer of ABCO Group Limited, which has holdings in manufacturing and distribution activities. Director of NSPI since 2008 and Chair of the NSPI Board of Directors since May 2011.	2011
Christopher G. Huskilson Wellington, Nova Scotia Canada	President and Chief Executive Officer of Emera since November 2004. Director and former Chair of Emera Maine, Director of NSPI, Director of APUC and Chair or Director of a number of other Emera affiliated companies. Since June 1980, Mr. Huskilson has held a number of positions within NSPI and its predecessor, Nova Scotia Power Corporation.	2004
J. Wayne Leonard(2) New Orleans, Louisiana U.S.	Former Chairman and Chief Executive Officer of Entergy Corporation, an integrated electricity producer and retail distributor. Mr. Leonard joined Entergy Corporation as President and Chief Operating Officer in 1998, becoming CEO in 1999. Mr. Leonard serves on the Boards of the Edison Electric Institute and Tidewater, Inc. He has also served on the Board of the Centre for Climate and Energy Solutions.	2014
B. Lynn Loewen, FCA(2) Westmount, Quebec Canada	President of Minogue Medical Inc. a healthcare organization which delivers innovative medical technologies to hospitals and clinics. President of Expertech Network Installation Inc. from 2008 to 2011.	2013
John T. McLennan (3) Mahone Bay, Nova Scotia Canada	Former Chair of the Board from May 2009 to May 2014. Former Board member of Chorus Aviation Inc. from January 2006 to May 2014. Former Chair of the Board of NSPI from May 2006 to May 2009. Former Vice-Chair and Chief Executive Officer of Allstream Inc. (formerly AT&T Canada). He is presently a Director of Amdocs Ltd.	2005
Donald A. Pether(2)(5) Dundas, Ontario Canada	Former Chair of the Board and Chief Executive Officer of ArcelorMittal Dofasco Inc., a Canadian steel producer. Director of Samuel, Son & Co. Ltd. and Schlegel Health Care Inc.	2008

2015 Annual Information Form 56

Name and Residence	Principal Occupations During the Past Five Years and Other Information	Director Since (1)
Andrea S. Rosen(6) Toronto, Ontario Canada	Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Director of Alberta Investment Management Corporation and Manulife Financial Corporation.	2007
Richard P. Sergel(3) (4) Wellesley, Massachusetts U.S.	Former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC). Former President and Chief Executive Officer of National Grid USA from 2000 to 2004. Also former President and Chief Executive Officer of the New England Electric System. Presently a director of State Street Corporation. Has also served on the boards of the Edison Electric Institute and the Consortium for Energy Efficiency.	2010
M. Jacqueline Sheppard(8) (9) Calgary, Alberta Canada	Chair of the Board since May 2014. Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Former Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown Corporation. Founder and Lead Director of Black Swan Energy Inc., an Alberta upstream energy company that is private equity financed. Founder and former Director of Marsa Energy Inc., an oil and gas corporation. Director of Cairn Energy PLC, a publicly traded UK based international oil and gas producer. Director of the general partner of Pacific NorthWest LNG LP, which was formed for the purpose of constructing, owning and operating an LNG facility in British Columbia.	2009

⁽¹⁾ Denotes the year the individual became a Director of Emera. Directors are elected for a one year term which expires at the termination of Emera’s annual general meeting;

⁽²⁾ Denotes member of the Audit Committee;

⁽³⁾ Denotes member of the Nominating and Corporate Governance Committee;

⁽⁴⁾ Denotes member of the Management Resources and Compensation Committee;

⁽⁵⁾ Denotes Chair of the Nominating and Corporate Governance Committee;

⁽⁶⁾ Denotes Chair of the Audit Committee;

⁽⁷⁾ Denotes Chair of the Management Resources and Compensation Committee;

⁽⁸⁾ Denotes Chair of the Board;

⁽⁹⁾ Denotes member of the Board of Directors of ENL.

As of December 31, 2015, the Directors, in total, beneficially owned or controlled, directly or indirectly, approximately 43,439 common shares or less than 1% of the issued and outstanding shares of Emera.

There are no material conflicts of interest between Emera or any of its subsidiaries and any director or officer of Emera or any of its subsidiaries.

Audit Committee

The Audit Committee of Emera is composed of the following four members, all of whom are independent Directors: Andrea S. Rosen (Chair), Donald A. Pether, J. Wayne Leonard and B. Lynn Loewen. The responsibilities and duties of the Committee are set out in the Audit Committee’s Charter, a copy of which is attached as Appendix “A” to this AIF.

The Board believes that the composition of the Audit Committee reflects a high level of financial literacy and experience. Each member of the Audit Committee has been determined by the Board to be “financially literate” as such term is defined under Canadian securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Audit Committee. The following is a description of the education and experience of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of the Audit Committee:

2015 Annual Information Form 57

Andrea S. Rosen, Committee Chair

Vice-Chair of TD Bank Financial Group and President, TD Canada Trust from 2002 to 2005. From 2001 to 2002, Executive Vice President of TD Commercial Banking and Vice Chair TD Securities. Before joining TD Bank, was Vice President of Varity Corporation from 1991 to 1994, and worked at Wood Gundy Inc. (later CIBC-Wood Gundy) in a variety of roles from 1981 to 1990, eventually becoming Vice President and Director. Holds a Bachelor of Laws from Osgoode Hall Law School and a Masters of Business Administration from the Schulich School of Business at York University. Received a Bachelor of Arts from Yale University. Former director and member of the Audit Committee of Hiscox Ltd., a U.K. reporting issuer listed on the London Stock Exchange, and Director and member of the Audit Committee of Manulife Financial Corporation, an issuer listed on The Toronto Stock Exchange, New York Stock Exchange, The Stock Exchange of Hong Kong, and the Philippine Stock Exchange. Director of Alberta Investment Management Corporation.

Donald A. Pether

Former Chair of the Board and Chief Executive Officer of ArcelorMittal Dofasco Inc. a Canadian steel producer. Held various positions at Dofasco, including Vice President, Commercial, Executive Vice President Dofasco Inc. & General Manager Dofasco Hamilton and President and Chief Operating Officer prior to appointment in May 2003 as President and Chief Executive Officer and July 2006 as Chair of the Board. Was Chairman of the Board of Directors of Dofasco de Mexico S.A. de C.V., Dofasco Marion Inc., Powerlasers Limited and Powerlasers Corporation. Served on the board of directors of the International Iron and Steel Institute, the Automotive Parts Manufacturers Association and the Canadian Steel Trade and Employment Congress. He is a Director of Samuel, Son & Co. Ltd. and Schlegel Health Care Inc., and holds a Bachelor of Science in Metallurgical Engineering from the University of Alberta and a Doctor of Laws (Hon) from McMaster University.

J. Wayne Leonard

Former Chairman and Chief Executive Officer of Entergy Corporation, an integrated electricity producer and retail distributor. Joined Entergy Corporation as President and Chief Operating Officer in 1998, becoming CEO in 1999. From 1996 to 1997, President, Energy Commodities Strategic Business Unit and Capital & Trading Group of Cinergy Corporation, and before that its Group Vice President and Chief Financial Officer from 1994 to 1996. Prior to that, held various senior management roles with PSI Energy, Inc., including its Senior Vice President and Chief Financial Officer from 1987 to 1994. Served as an expert witness in numerous utility regulatory proceedings on various policies and financial issues, including, cost of capital and incentive regulation. Received Bachelor of Science, Accounting and Political Science from Ball State University in 1973. He is a Certified Public Accountant (CPA), and obtained MBA from Indiana University in 1987.

B. Lynn Loewen, FCPA, FCA

President of Minogue Medical Inc. a healthcare organization which delivers innovative medical technologies to hospitals and clinics. Fellow of the Institute of Chartered Accountants, she has served in a number of senior roles at Bell Canada, Air Canada Jazz, and Air Nova and also was the Vice President, Financial Controls for BCE. She has served as Chair of the Audit Committee on the Public Sector Pension Investment Board, and was Chair of the Finance and Administration Committee of Mount Allison University. She holds a Bachelor of Commerce from Mount Allison University.

Audit and Non-Audit Services Pre-Approval Process

The Audit Committee is responsible for the oversight of the work of the external auditors. As part of this responsibility, the Committee is required to pre-approve the audit and non-audit services performed by the external auditors in order to assure that they do not impair the external auditors’ independence from the Company. Accordingly, the Audit Committee has adopted an Audit and Non-Audit Pre-Approval Policy, which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the external auditors may be pre-approved.

2015 Annual Information Form 58

Unless a type of service has received the pre-approval of the Audit Committee it will require specific approval by the Audit Committee if it is to be provided by the external auditors. Any proposed services exceeding the pre-approved cost levels will also require specific approval by the Committee.

Auditors’ Fees

The aggregate fees billed by Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2015 and 2014 respectively, were as follows:

Service Fee	2015 ($)		2014 ($)
Audit Fees		1,167,187		1,067,993
Audit-Related Fees		242,568		303,764
Tax Fees		544,615		298,531
Other		125,000		38,900
Total		2,079,370		1,709,188

Audit-related fees for Emera relate to accounting and disclosure consultations and services associated with securities offerings. Tax fees for Emera relate to the structuring of cross-border financing of Emera’s subsidiaries and affiliates as well as tax compliance services and general tax consulting advice on various matters.

2015 Annual Information Form 59

Officers

The Officers of Emera as of December 31, 2015 were as follows:

Christopher G. Huskilson
President and Chief Executive Officer Wellington, Nova Scotia Canada	President and Chief Executive Officer since November 1, 2004. From July 2003 to November 2004, Chief Operating Officer of Emera. Concurrently held the office of Chief Operating Officer of NSPI until January 2004. Prior to 2003, actively engaged for more than five years in the affairs of NSPI in various managerial and executive capacities.
Nancy G. Tower, FCA
Chief Corporate Development Officer Halifax, Nova Scotia Canada	Chief Corporate Development Officer since May 2015. Before that, Executive Vice President Business Development from May 2011 to May 2015. From May 2011 to March 2014 CEO of Emera Newfoundland and Labrador. From November 2005 to May 2011, Executive Vice President and Chief Financial Officer. Prior to 2005, Vice-President Customer Operations for NSPI. From 1997 to 2000, Controller for NSPI.
Scott C. Balfour (1)
Executive Vice President Chief Financial Officer Halifax, Nova Scotia Canada	Executive Vice President and Chief Financial Officer since April 16, 2012. From May 2011 to April 2012, President of Ensimian Capital Corporation. From September 2005 to January 2011, President and Chief Financial Officer of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company.
(1)	Effective March 1, 2016, Scott C. Balfour was appointed Chief Operating Officer, Northeast and Caribbean, Gregory W. Blunden was appointed Chief Financial Officer, and Wayne D. O’Connor was appointed Vice-President Corporate Strategy and Planning.
R. Michael Roberts
Chief Human Resources Officer Halifax, Nova Scotia Canada	Chief Human Resources Officer since December 1, 2014. Previously, President, Optimum Talent Atlantic of Halifax. Prior to that, Vice President, Corporate Development at Irving Shipbuilding and Vice President, Human Resources at Bell Aliant.

2015 Annual Information Form 60

Bruce A. Marchand
Chief Compliance Officer and Chief Legal Officer Halifax, Nova Scotia Canada	Chief Compliance Officer since December 1, 2014. Chief Legal Officer since January 2012. Prior to January 2012, Senior Partner at the law firm of McInnes Cooper.
Daniel P. Muldoon
Executive Vice-President Major Renewables and Alternative Energy Halifax, Nova Scotia Canada	Executive Vice-President, Major Renewables and Alternative Energy since May 1, 2014. From June 16, 2011 to March 31, 2013, President and Chief Operating Officer, Emera Utility Services Inc. Prior to that, General Manager Engineering & Construction, Emera.
Stephen D. Aftanas
Corporate Secretary Halifax, Nova Scotia Canada	Corporate Secretary since September 2008. From June 2007 to September 2008, Associate Corporate Secretary. From March 2006 to June 2007, Associate General Counsel, NSPI. Prior to March 2006, Senior Solicitor, Emera.

2015 Annual Information Form 61

As of December 31, 2015, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, approximately 71,882 common shares or less than 1% of the issued and outstanding shares of Emera.

Certain Proceedings

To the knowledge of Emera, none of the Directors or Officers of the Company:

(1) are, as at the date of this AIF, or have been, within ten years before the date of this AIF, a director, chief executive officer or chief financial officer of any company that:

(a) was subject to an Order that was issued while the Director or Officer was acting in the capacity as director, chief executive officer or chief financial officer; or

(b) was subject to an Order that was issued after the Director or Officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer of chief financial officer;

(2) are, as at the date of this AIF, or have been within ten years before the date of this AIF, a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets;

(3) have, within the ten years before the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the proposed nominee; or

(4) have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory body or has entered in a settlement agreement with a securities regulatory body, or is subject to any penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor making an investment decision.

Legal Proceedings and Regulatory Actions

To the knowledge of Emera, there are no legal proceedings that individually or together could potentially involve claims against Emera or its subsidiaries for damages totaling 10% or more of the current assets of Emera, exclusive of interest and costs.

No Interest of Management and Others in Material Transactions

None of the following persons or companies, namely (a) a Director or Officer of Emera, (b) a person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over, more than 10% of any class or series of Emera’s outstanding voting securities, or (c) an associate or affiliate of any person or company named in (a) or (b), had a material interest in any transaction involving Emera within Emera’s last three completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect Emera.

2015 Annual Information Form 62

Material Contracts

Emera has no material contracts other than those noted below and those entered into in the ordinary course of its business.

Material contracts entered into in connection with the TECO Transaction, namely: Instalment Receipt and Pledge Agreement, Trust Indenture, Underwriting Agreement and Agreement and Plan of Merger, have been filed on SEDAR at www.sedar.com.

Experts

Interest of Experts

Ernst & Young LLP are the external auditors of Emera. Ernst & Young LLP report that they are independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Nova Scotia.

ADDITIONAL INFORMATION

Additional information relating to Emera may be found on SEDAR at www.sedar.com or upon request to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, N.S., B3J 2W5, telephone (902) 428-6096 or fax (902) 428-6171. Additional information, including Directors’ and Officers’ remuneration and indebtedness, principal holders of Emera’s securities and securities authorized for issuance under equity compensation plans, is contained in Emera’s information circular for the most recent annual meeting of Emera’s common shareholders. Additional financial information is provided in Emera’s financial statements and MD&A for the year ended December 31, 2015.

At any time, Emera will provide to any person upon request to the Corporate Secretary, a copy of the Emera Group of Companies’ Standards for Business Conduct.

2015 Annual Information Form 63

Appendix “A”

Emera Incorporated

Audit Committee Charter

PART I

MANDATE AND RESPONSIBILITIES

Committee Purpose

There shall be a committee of the Board of Directors (the “Board”) of Emera Inc. (“Emera”) which shall be known as the Audit Committee (the “Committee”). The Committee shall assist the Board in discharging its oversight responsibilities concerning:

• the quality and integrity of Emera’s financial statements;

• the effectiveness of Emera’s internal control systems over financial reporting;

• the internal audit and assurance process;

• the qualifications, independence and performance of the external auditors;

• major financial risk exposures;

• Emera’s compliance with legal requirements and securities regulations in respect of financial statements and financial reporting; and

• any other duties set out in this Charter or delegated to the Committee by the Board.

1. Financial Reporting

a) The Committee shall be responsible for reviewing, assessing the completeness and clarity of the disclosures in, and recommending to the Board for approval:

i. the audited annual financial statements of Emera, all related Management’s Discussion and Analysis, and earnings press releases;

ii. any documents containing Emera’s audited financial statements; and,

iii. the quarterly financial statements, all related Management’s Discussion and Analysis, and earnings press releases.

b) The Committee shall oversee and assess that adequate procedures are in place for the review of public disclosure of financial information.

2. External Auditors

a) The Committee shall evaluate and recommend to the Board the external auditor to be nominated for the purpose of preparing or issuing the auditor’s report or performing other audit, review, or attest services for Emera, and the compensation of such external auditors.

b) Once appointed, the external auditor shall report directly to the Committee, and the Committee shall oversee the work of the external auditor concerning the preparation or issuance of the auditor’s report or the performance of other audit, review or attest services for Emera.

c) The Committee shall be responsible for resolving disagreements between management and the external auditor concerning financial reporting.

d) At least annually, the Committee shall obtain and review a report by the external auditors describing: (i) the firm’s internal quality control procedures; (ii) any material issues raised by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, with respect to one or more external audits carried out by the firm, and any steps taken to deal with any such issues; and (iii) all relationships between the external auditors and Emera (to assess the auditors’ independence). After reviewing the foregoing report and the external auditors’ work throughout the year, the Committee shall evaluate the auditors’ qualifications, performance and independence. Such evaluation should include the review and evaluation of the lead audit partner and take into account the opinions of Management and the internal auditor. The Committee shall determine that the external audit firm has a process in place to address the rotation of the lead audit partner and other audit partners serving the account as required under prescribed independence rules. The Committee shall make recommendations to the Board on appropriate actions to be taken which the Committee deems necessary to protect and enhance the independence of the external auditor.

2015 Annual Information Form 64

e) The Committee shall regularly review with the external auditors any audit problems or difficulties encountered during the course of the audit work, including any restrictions on the scope of the external auditors’ activities or access to requested information, and Management’s response.

f) The Committee will review differences that were noted or proposed by the external auditors, but that were considered immaterial or insignificant; and any “management” or “internal control” letter issued, or proposed to be issued.

3. Non Audit Services

a) The Committee shall be responsible for reviewing and pre-approving all non-audit services to be provided to Emera, or any of its subsidiaries, by the external auditor.

b) The Committee may establish specific policies and procedures concerning the performance of non-audit services by the external auditor so long as the requirements of applicable legislation and regulation are satisfied.

c) In accordance with policies and procedures established by the Committee, and applicable legislation and regulation, the Committee may delegate the pre-approval of non-audit services to a member of the Committee or a sub-committee thereof.

4. Oversight and Monitoring of Audits

a) The Committee shall review with the external auditor, the internal auditors and Management (i) the audit function generally, (ii) the objectives, staffing, locations, co-ordination, reliance upon Management and internal audit and, (iii) for subsidiaries, reliance on external audit, and general audit approach and scope of proposed audits of the financial statements of Emera and its subsidiaries, (iv) the overall audit plans, (v) the responsibilities of Management, the internal auditors and the external auditor, (vi) the audit procedures to be used and (vii) the timing and estimated budgets of the audits.

b) The Committee shall meet periodically with the internal auditors to discuss the progress of their activities, any significant findings stemming from internal audits, any issues that arise with Management, and the adequacy of Management’s responses in addressing audit-related deficiencies.

c) The Committee shall discuss with the external auditor any issues that arise with Management or the internal

auditors during the course of the audit and the adequacy of Management’s responses in addressing audit-related deficiencies.

d) The Committee shall review with Management the results of internal and external audits.

e) The Committee shall take such other reasonable steps as it may deem necessary to oversee that the audit was conducted in a manner consistent with applicable legal requirements and auditing standards of applicable professional or regulatory bodies.

5. Oversight and Review of Accounting Principles and Practices

The Committee shall oversee, review and discuss with Management, the external auditor and the internal auditors:

a) the quality, appropriateness and acceptability of Emera’s accounting principles and practices used in its financial reporting, changes in Emera’s accounting principles or practices and the application of particular accounting principles and disclosure practices by Management to new transactions or events;

b) all significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including the effects of alternative methods within generally accepted accounting principles on the financial statements and any “other opinions” sought by Management from an independent auditor, other than the Company’s external auditors, with respect to the accounting treatment of a particular item, and other material written communications between the external auditors and management;

c) disagreements between Management and the external auditor or the internal auditors regarding the application of any accounting principles or practices;

d) any material change to Emera’s auditing and accounting principles and practices as recommended by Management, the external auditor or the internal auditors or which may result from proposed changes to applicable generally accepted accounting principles;

e) the effect of regulatory and accounting initiatives on Emera’s financial statements and other financial disclosures;

f) any reserves, accruals, provisions, estimates or Management programs and policies, including factors that affect asset and liability carrying values and the

2015 Annual Information Form 65

timing of revenue and expense recognition, that may have a material effect upon the financial statements of Emera;

g) the use of special purpose entities and the business purpose and economic effect of off-balance sheet transactions, arrangements, obligations, guarantees and other relationships of Emera and their impact on the reported financial results of Emera;

h) any legal matter, claim or contingency that could have a significant impact on the financial statements, Emera’s compliance policies and any material reports, inquiries or other correspondence received from regulators or governmental agencies and the manner in which any such legal matter, claim or contingency has been disclosed in Emera’s financial statements;

i) the treatment for financial reporting purposes of any significant transactions which are not a normal part of Emera’s operations.

6. Hiring Policies

The Committee shall review and approve Emera’s hiring policy concerning partners or employees, as well as former partners and employees, of the present or former external auditors of Emera.

7. Pension Plans

The Committee shall exercise oversight of the pension plans in accordance with the Pension Oversight Framework adopted by Emera.

8. Oversight of Finance Matters

a) The Committee shall review the appointments of key financial executives involved in the financial reporting process of Emera, including the Chief Financial Officer.

b) The Committee may request for review, and shall receive when requested, material tax policies and tax planning initiatives, tax payments and reporting and any pending tax audits or assessments. The Committee shall review Emera’s compliance with tax and financial reporting laws and regulations.

c) The Committee shall meet periodically with Management to review and discuss Emera’s major financial risk exposures and the policy steps Management has taken to monitor and control such exposures, including the use of financial derivatives, hedging activities, and credit and trading risks.

d) The Committee may review any investments or transactions that the Committee wishes to review, or which the internal or external auditor, or any officer of Emera, may bring to the attention of the Committee within the context of this charter.

e) The Committee shall review financial information of material subsidiaries of Emera and any auditor recommendations concerning such subsidiaries.

f) The Committee may request for review, and shall receive when requested, all related party transactions required to be disclosed pursuant to generally accepted accounting principles, and discuss with Management the business rationale for the transactions and whether appropriate disclosures have been made.

9. Internal Controls

The Committee shall oversee:

a) the adequacy and effectiveness of the Company’s internal accounting and financial controls and the recommendations of Management, the external auditor and the internal auditors for the improvement of accounting practices and internal controls;

b) any material or significant weaknesses in the internal control environment;

c) management’s compliance with the Company’s processes, procedures and internal controls; and

d) the practices and procedures adopted to permit management’s assurance on the underlying controls in respect of the CEO/CFO certificates required under applicable securities regulations,

In exercising such oversight, the Committee shall review and discuss each of the foregoing with Management, the external auditor and the internal auditor.

The Committee will carry out the following specific duties:

e) Review and discuss with the Chief Executive Officer and the Chief Financial Officer the procedures undertaken in connection with the Chief Executive Officer and Chief Financial Officer certifications for the annual and interim filings with applicable securities regulatory authorities.

f) Review disclosures made by Emera’s Chief Executive Officer and Chief Financial Officer during their certification process for the annual and interim filing with

2015 Annual Information Form 66

applicable securities regulatory authorities about any significant deficiencies in the design or operation of internal controls which could adversely affect Emera’s ability to record, process, summarize and report financial data or any material weaknesses in the internal controls, and any fraud involving management or other employees who have a significant role in the Emera’s internal controls.

g) Discuss with Emera’s Chief Legal Officer at least annually any legal matters that may have a material impact on the financial statements, operations, assets or compliance policies and any material reports or inquiries received by Emera or any of its subsidiaries from regulators or governmental agencies.

10. Internal Auditors

a) The lead internal auditor shall report directly to the Committee. The Committee shall:

i. approve the appointment of;

ii. review the terms of engagement of;

iii. be consulted with respect to the compensation payable to, and the replacement or termination of;

the lead internal auditor. The Committee shall review the charter, reporting relationship, activities, staffing, organizational structure, and credentials of the internal audit department.

b) The Committee shall review and approve the annual internal audit plan, and all major changes to the plan. The Committee shall review and discuss with the internal auditors the scope, progress, and results of executing the internal audit plan. The Committee shall receive reports on the status of significant findings, recommendations, and management’s responses.

c) The Committee shall obtain from the internal auditors and review summaries of the significant reports to Management prepared by the internal auditors, and the actual reports if requested by the Committee, and Management’s responses to such reports.

d) The Committee shall annually receive and review a report from the internal auditors on executive officers’ compliance with the Company’s Standards of Business Conduct.

e) The Committee shall annually receive and review a report on the Chief Executive Officers’ expense accounts.

f) The Committee may communicate with the internal auditors with respect to their reports and

recommendations, the extent to which prior recommendations have been implemented and any other matters that the internal auditor brings to the attention of the Committee.

g) The Committee shall, annually or more frequently as it deems necessary, evaluate the internal auditors including their activities, organizational structure and qualifications and effectiveness. The internal auditors shall confirm to the Committee that they are in compliance with their professional standards.

h) The Committee shall review the independence of the internal auditors and shall make recommendations to the Board on appropriate actions to be taken which the Committee deems necessary to protect and enhance the independence of the internal auditors.

11. Complaints

The Committee shall oversee procedures relating to the receipt, retention, and treatment of complaints received concerning accounting, internal accounting controls, or auditing matters. The Committee shall also review procedures concerning the confidential, anonymous submission of concerns by Emera’s employees relating to questionable accounting or auditing matters.

12. Other Responsibilities

The Committee shall:

a) Annually, review insurance programs;

b) Review Management’s process for identifying non-compliance with legal and regulatory requirements.

c) Perform such other duties and exercise such powers as may be directed or delegated to the Committee by the Board.

13. Limitation on Authority

Nothing articulated herein is intended to assign to the Committee the Board’s responsibility to oversee Emera’s compliance with applicable laws or regulations or to expand applicable standards of liability under statutory or regulatory requirements for the Directors or the members of the Committee.

2015 Annual Information Form 67

PART II

COMPOSITION

14. Composition

a) Emera’s Articles of Association require that the Committee shall be comprised of no less than three directors none of whom may be officers or employees of Emera nor may they be an officer or employee of any affiliate of Emera. In addition, all members of the Committee shall be independent as required by applicable legislation.

b) The Board shall appoint members to the Committee who are financially literate, as required by applicable legislation, which at a minimum requires that Committee members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Emera’s financial statements.

c) Committee members shall be appointed at the Board meeting following the election of Directors at Emera’s annual shareholders’ meeting and membership may be based upon the recommendation of the Nominating and Corporate Governance Committee.

d) Pursuant to Emera’s Articles of Association, the Board may appoint, remove, or replace any member of the Committee at any time, and a member of the Committee shall cease to be a member of the Committee upon ceasing to be a Director. Subject to the foregoing, each member of the Committee shall hold office as such until the next annual meeting of shareholders after the member’s appointment to the Committee.

e) The Secretary of the Committee shall advise Emera’s internal and external auditors of the names of the members of the Committee promptly following their election.

PART III

COMMITTEE PROCEDURE

15. Meetings

a) Meetings of the Committee may be called by the Chair or at the request of any member. The Committee shall meet at least quarterly.

b) The timing and location of meetings of the Committee, and the calling of and procedure at any such meeting, shall be determined from time to time by the Committee.

c) Emera’s internal and external auditors shall be notified of all meetings of the Committee and shall have the right to appear before and be heard by the Committee.

d) Emera’s internal or external auditors may request the Chair of the Committee to consider any matters which the internal or external auditors believe should be brought to the attention of the Committee or the Board.

16. Separate Sessions

a) The Committee Chair shall meet periodically with the Chief Financial Officer, the lead internal auditor and the external auditor in separate executive sessions to discuss any matters that the Committee or each of these groups believes should be discussed privately.

b) The Chief Financial Officer, the lead internal auditor and the external auditor shall have access to the Committee to bring forward matters requiring its attention.

c) The Committee shall meet periodically without Management present.

17. Quorum

Two members of the Committee present in person, by teleconferencing, or by videoconferencing, or by a combination thereof, will constitute a quorum.

18. Chair

Pursuant to Emera’s Articles of Association, the Committee shall choose one of its members to act as Chair of the Committee, which person shall not be the Chair of Nova Scotia Power Inc.’s Audit Committee. In selecting a Committee Chair, the Committee may consider any recommendation made by the Nominating and Corporate Governance Committee.

19. Secretary and Minutes

Pursuant to Emera’s Articles of Association, the Corporate Secretary of Emera shall act as the Secretary of the Committee. Emera’s Articles of Association require that the Minutes of the Committee be in writing and duly entered into Emera’s records, and the Minutes shall be circulated to all members of the Committee. The Secretary shall maintain all Committee records.

2015 Annual Information Form 68

20. Board Relationships and Reporting

The Committee shall:

a) Review annually the Committee’s Charter;

b) Oversee the appropriate disclosure of the Committee’s Charter as well as other information concerning the Committee which is required to be disclosed by applicable legislation in Emera’s Annual Information Form and any other applicable disclosure documents;

c) Report to the Board at the next following board meeting on any meeting held by the Committee, and as required, regularly report to the Board on Committee activities, issues, and related recommendations; and

d) Maintain free and open communication between the Committee, the external auditors, internal auditors, and Management, and determine that all parties are aware of their responsibilities.

21. Powers

The Committee shall:

a) examine and consider such other matters, and meet with such persons, in connection with the internal or external audit of Emera’s accounts, which the Committee in its discretion determines to be advisable;

b) have the authority to communicate directly with the internal and external auditors; and

c) have the right to inspect all records of Emera or its affiliates and may elect to discuss such records, or any matters relating to the financial affairs of Emera with the officers or auditors of Emera and its affiliates.

22. Experts and Advisors

The Committee may, in consultation with the Chairman of the Board, engage and compensate any outside adviser that it determines necessary in order to carry out its duties.

EX-4.2

Exhibit 4.2

EMERA INCORPORATED

Consolidated

Financial Statements

December 31, 2015 and 2014

1

MANAGEMENT REPORT

Management’s Responsibility for Financial Reporting

The accompanying consolidated financial statements of Emera Incorporated and the information in this annual report are the responsibility of management and have been approved by the Board of Directors (“Board”).

The consolidated financial statements have been prepared by management in accordance with United States Generally Accepted Accounting Principles. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. In preparation of these consolidated financial statements, estimates are sometimes necessary when transactions affecting the current accounting period cannot be finalized with certainty until future periods. Management represents that such estimates, which have been properly reflected in the accompanying consolidated financial statements, are based on careful judgements and are within reasonable limits of materiality. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects. Management has prepared the financial information presented elsewhere in the annual report and has ensured that it is consistent with that in the consolidated financial statements.

Emera Incorporated maintains effective systems of internal accounting and administrative controls, consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate, and that Emera Incorporated’s assets are appropriately accounted for and adequately safeguarded.

The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting and is ultimately responsible for reviewing and approving the consolidated financial statements. The Board carries out this responsibility principally through its Audit Committee.

The Audit Committee is appointed by the Board, and its members are directors who are not officers or employees of Emera Incorporated. The Audit Committee meets periodically with management, as well as with the internal auditors and with the external auditors, to discuss internal controls over the financial reporting process, auditing matters and financial reporting issues, to satisfy itself that each party is properly discharging its responsibilities, and to review the annual report, the consolidated financial statements and the external auditors’ report. The Audit Committee reports its findings to the Board for consideration when approving the consolidated financial statements for issuance to the shareholders. The Audit Committee also considers, for review by the Board and approval by the shareholders, the appointment of the external auditors.

The consolidated financial statements have been audited by Ernst & Young LLP, the external auditors, in accordance with Canadian Generally Accepted Auditing Standards. Ernst & Young LLP has full and free access to the Audit Committee.

February 12, 2016

“Christopher Huskilson”	“Scott Balfour”
President and Chief Executive Officer	Chief Financial Officer

2

INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Emera Incorporated

We have audited the accompanying consolidated financial statements of Emera Incorporated, which comprise the consolidated balance sheets as at December 31, 2015 and 2014, and the consolidated statements of income, comprehensive income, cash flows and changes in equity for the years then ended, and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with United States generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Emera Incorporated as at December 31, 2015 and 2014, and its financial performance and its cash flows for the years then ended in accordance with United States generally accepted accounting principles.

Halifax, Canada	“Ernst & Young LLP”
February 12, 2016	Chartered accountants

3

Emera Incorporated

Consolidated Statements of Income

For the	Year ended December 31
millions of Canadian dollars (except per share amounts)	2015		2014
Operating revenues
Regulated	$	2,192.9	$	2,113.1
Non-regulated		596.4		825.5
Total operating revenues		2,789.3		2,938.6
Operating expenses
Regulated fuel for generation and purchased power		814.5		844.3
Regulated fuel adjustment mechanism and fixed cost deferrals (note 5)		41.6		46.6
Non-regulated fuel for generation and purchased power		335.7		401.1
Non-regulated direct costs		19.5		31.3
Operating, maintenance and general		666.8		560.8
Provincial, state, and municipal taxes		63.6		58.2
Depreciation and amortization		339.9		329.0
Total operating expenses		2,281.6		2,271.3
Income from operations		507.7		667.3
Income from equity investments (note 6)		108.6		66.6
Other income (expenses), net (note 7)		141.1		12.3
Interest expense, net (note 8)		212.6		179.8
Income before provision for income taxes		544.8		566.4
Income tax expense (recovery) (note 9)		92.4		113.6
Net income		452.4		452.8
Non-controlling interest in subsidiaries		24.9		19.9
Net income of Emera Incorporated		427.5		432.9
Preferred stock dividends		30.3		26.2
Net income attributable to common shareholders	$	397.2	$	406.7
Weighted average shares of common stock outstanding (in millions)
Basic		145.8		143.2
Diluted		146.4		147.0
Earnings per common share (note 10)
Basic	$	2.72	$	2.84
Diluted	$	2.71	$	2.82
Dividends per common share declared	$	1.6625	$	1.4750

The accompanying notes are an integral part of these consolidated financial statements.

4

Emera Incorporated

Consolidated Statements of Comprehensive Income

For the millions of Canadian dollars	Year ended December 31
	2015			2014
Net income	$	452.4		$	452.8
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment (1)		434.6			165.2
Cash flow hedges
Net derivative gains (losses) (2)		(33.5	)		(7.7	)
Less: reclassification adjustment for losses (gains) included in income (3)		6.5			3.6
Net effects of cash flow hedges		(27.0	)		(4.1	)
Unrealized gains on available-for-sale investment
Unrealized gain (loss) arising during the period		(2.6	)		0.2
Net unrealized holding gains (losses)		(2.6	)		0.2
Net change in unrecognized pension and post-retirement benefit obligation (4)		107.1			(71.3	)
Other comprehensive income (loss) (5)		512.1			90.0
Comprehensive income (loss)		964.5			542.8
Comprehensive income (loss) attributable to non-controlling interest		52.8			31.6
Comprehensive Income of Emera Incorporated	$	911.7		$	511.2

The accompanying notes are an integral part of these consolidated financial statements.

1) Net of tax expense of $6.6 million (2014 – $2.3 million tax expense) for the year ended December 31, 2015.

2) Net of tax expense of $1.0 million (2014 – $3.7 million tax expense) for the year ended December 31, 2015.

3) Net of tax recovery of $1.7 million (2014 – $0.1 million tax recovery) for the year ended December 31, 2015.

4) Net of tax expense of $8.5 million (2014 – $13.6 million tax recovery) for the year ended December 31, 2015.

5) Net of tax expense of $14.4 million (2014 – $7.7 million tax recovery) for the year ended December 31, 2015.

5

Emera Incorporated

Consolidated Balance Sheets

As at	December 31
millions of Canadian dollars	2015		2014
Assets
Current assets
Cash and cash equivalents	$	1,073.4	$	221.1
Restricted cash (note 12)		19.3		15.9
Receivables, net (note 13)		578.1		514.2
Income taxes receivable		12.1		4.8
Inventory (note 14)		314.3		294.5
Derivative instruments (notes 15 and 16)		249.5		136.5
Regulatory assets (notes 5 and 17)		94.2		115.0
Prepaid expenses		18.3		24.7
Due from related parties (note 18)		1.6		3.5
Other current assets (note 19)		234.8		80.6
Total current assets		2,595.6		1,410.8
Property, plant and equipment, net of accumulated depreciation of $3,732.4 and $3,362.0, respectively (note 20)		6,188.0		5,610.2
Other assets
Income taxes receivable		48.7		28.9
Deferred income taxes (note 9)		32.2		57.8
Derivative instruments (notes 15 and 16)		167.6		92.0
Pension and post-retirement asset (note 21)		8.7		5.9
Regulatory assets (notes 5 and 17)		605.3		487.7
Net investment in direct financing lease (note 22)		480.1		484.5
Investments subject to significant influence (note 6)		1,145.3		1,027.6
Available-for-sale investments (note 23)		116.0		84.4
Goodwill (note 24)		264.1		221.5
Intangibles, net of accumulated amortization of $92.8 and $88.3, respectively		191.9		134.3
Due from related parties (note 18)		2.5		2.5
Other long-term assets (note 25)		166.3		205.3
Total other assets		3,228.7		2,832.4
Total assets	$	12,012.3	$	9,853.4

The accompanying notes are an integral part of these consolidated financial statements.

6

Emera Incorporated

Consolidated Balance Sheets – Continued

As at	December 31
millions of Canadian dollars	2015		2014
Liabilities and Equity
Current liabilities
Short-term debt (note 26)	$	15.9	$	257.6
Current portion of long-term debt		274.0		94.5
Accounts payable		394.2		370.7
Income taxes payable		8.1		33.8
Convertible debentures represented by instalment receipts (note 30)		727.6		—
Derivative instruments (notes 15 and 16)		349.2		127.4
Regulatory liabilities (note 17)		98.9		43.0
Pension and post-retirement liabilities (note 21)		7.0		7.5
Due to related party (note 18)		2.1		1.6
Other current liabilities (note 27)		204.3		186.8
Total current liabilities		2,081.3		1,122.9
Long-term liabilities
Long-term debt (note 28)		3,750.8		3,660.3
Deferred income taxes (note 9)		761.7		613.3
Derivative instruments (notes 15 and 16)		96.1		77.4
Regulatory liabilities (note 17)		271.7		158.9
Asset retirement obligations (note 29)		114.7		106.2
Pension and post-retirement liabilities (note 21)		303.4		360.7
Other long-term liabilities (note 31)		298.5		48.3
Total long-term liabilities		5,596.9		5,025.1
Commitments and contingencies (note 32)
Equity
Common stock, no par value, unlimited shares authorized, 147.21 million and 143.78 million shares issued and outstanding, respectively (note 33)		2,157.5		2,016.4
Cumulative preferred stock, Series A, B, C, E and F, par value $25 per share; unlimited shares authorized, 3.9 million, 2.1 million, 10 million, 5 million, and 8 million shares issued and outstanding, respectively (note 34)		709.5		709.5
Contributed surplus		28.8		8.8
Accumulated other comprehensive income (loss) (note 11)		136.5		(347.6	)
Retained earnings		1,167.8		1,011.7
Total Emera Incorporated equity		4,200.1		3,398.8
Non-controlling interest in subsidiaries (note 35)		134.0		306.6
Total equity		4,334.1		3,705.4
Total liabilities and equity	$	12,012.3	$	9,853.4

The accompanying notes are an integral part of these consolidated financial statements.

Approved on behalf of the Board of Directors

“M. Jacqueline Sheppard”	“Christopher G. Huskilson”
Chair of the Board	President and Chief Executive Officer

7

Emera Incorporated

Consolidated Statements of Cash Flows

For the	Year ended December 31
millions of Canadian dollars	2015			2014
Operating activities
Net income	$	452.4		$	452.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		352.2			341.5
Income from equity investments, net of dividends		(34.1	)		4.8
Allowance for equity funds used during construction		(2.3	)		(9.5	)
Deferred income taxes, net		20.4			39.9
Net change in pension and post-retirement liabilities		37.3			4.1
Regulated fuel adjustment mechanism and fixed cost deferrals		38.8			40.3
Net change in fair value of derivative instruments		95.9			(99.8	)
Net change in regulatory assets and liabilities		(6.3	)		(14.5	)
Net change in capitalized transportation capacity		(133.3	)		(40.3	)
Unrealized foreign exchange gains		(26.8	)		—
Other operating activities, net		(18.4	)		(3.0	)
Changes in non-cash working capital:
Receivables, net		(19.0	)		54.2
Income taxes receivable		(21.6	)		(2.9	)
Inventory		(2.1	)		(41.8	)
Prepaid expenses		8.4			0.9
Due from related party		1.9			(3.5	)
Other current assets		(1.6	)		(0.8	)
Accounts payable		(44.9	)		(0.1	)
Income taxes payable		(31.7	)		0.1
Other current liabilities		9.0			40.1
Net cash provided by operating activities		674.2			762.5
Investing activities
Additions to property, plant and equipment		(369.2	)		(433.7	)
(Increase) decrease in restricted cash		(0.7	)		7.4
Net purchase of investments subject to significant influence, inclusive of acquisition costs		(136.1	)		(155.2	)
Retirement spending, net of salvage		(8.0	)		(7.5	)
Purchase of subscription receipts		—			(110.5	)
Proceeds on sale of investment subject to significant influence		282.3			—
Proceeds on distribution of investment subject to significant influence		178.7			—
Additions to intangible assets		(58.0	)		(16.6	)
Other investing activities		(12.7	)		5.2
Net cash used in investing activities		(123.7	)		(710.9	)

The accompanying notes are an integral part of these consolidated financial statements.

8

Emera Incorporated

Consolidated Statements of Cash Flows – Continued

For the	Year ended December 31
millions of Canadian dollars	2015			2014
Financing activities
Change in short-term debt, net		(261.8	)		(214.3	)
Proceeds from convertible debentures represented by instalment receipts, net of issuance costs (note 30)		681.4			—
Retirement of long-term debt		(90.2	)		(308.9	)
Proceeds from long-term debt		446.5			302.2
Net borrowings (repayments) under committed credit facilities		(201.3	)		27.5
Issuance of common stock, net of issuance costs		87.4			310.0
Issuance of preferred stock, net of issuance costs		—			193.9
Dividends on common stock		(240.4	)		(210.0	)
Dividends on preferred stock		(30.3	)		(26.2	)
Dividends paid by subsidiaries to non-controlling interest		(14.1	)		(13.5	)
Redemption of preferred shares by subsidiary		(135.0	)		—
Other financing activities		(21.1	)		(2.5	)
Net cash provided by financing activities		221.1			58.2
Effect of exchange rate changes on cash and cash equivalents		80.7			10.5
Net increase in cash and cash equivalents		852.3			120.3
Cash and cash equivalents, beginning of period		221.1			100.8
Cash and cash equivalents, end of period	$	1,073.4		$	221.1
Cash and cash equivalents consists of:
Cash	$	995.8		$	160.2
Short-term investments		77.6			60.9
Cash and cash equivalents	$	1,073.4		$	221.1
Supplemental disclosure of cash paid (received):
Interest	$	196.4		$	184.7
Income taxes	$	124.2		$	64.8

The accompanying notes are an integral part of these consolidated financial statements.

9

Emera Incorporated

Consolidated Statements of Changes in Equity

								Accumulated
								Other						Emera			Non-
	Common		Preferred		Contributed			Comprehensive			Retained			Total			Controlling			Total
millions of Canadian dollars	Stock		Stock		Surplus			Income (“AOCI”)			Earnings			Equity			Interest			Equity
2015
Balance, December 31, 2014	$	2,016.4	$	709.5	$	8.8		$	(347.6	)	$	1,011.7		$	3,398.8		$	306.6		$	3,705.4
Net income of Emera Incorporated		—		—		—			—			427.5			427.5			24.9			452.4
Other comprehensive income (loss), net of tax expense of $14.4 million		—		—		—			484.2			—			484.2			27.9			512.1
Dividends declared on preferred stock (note 34)		—		—		—			—			(30.3	)		(30.3	)		—			(30.3	)
Dividends declared on common stock ($1.6625/share)		—		—		—			—			(240.4	)		(240.4	)		—			(240.4	)
Dividends paid and payable by subsidiaries to non-controlling interests		—		—		—			—			—			—			(3.1	)		(3.1	)
Common stock issued under purchase plan		84.2		—		—			—			—			84.2			—			84.2
Senior management stock options exercised		2.3		—		(0.2	)		—			—			2.1			—			2.1
Stock option expense		—		—		1.5			—			—			1.5			—			1.5
Employee Share Purchase Plan		0.9		—		—			—			.			0.9			—			0.9
Preferred dividends paid and payable by subsidiaries to non-controlling interests		—		—		—			—			—			—			(11.9	)		(11.9	)
Redemption of preferred shares by subsidiary		—		—		—			—						—			(132.2	)		(132.2	)
Acquisition of non-controlling interest of ECI		53.7		—		18.9			—			—			72.6			(77.7	)		(5.1	)
Equity method investments		—		—		(0.2	)		(0.1	)		(0.7	)		(1.0	)		—			(1.0	)
Other		—		—								—			—			(0.5	)		(0.5	)
Balance, December 31, 2015	$	2,157.5	$	709.5	$	28.8		$	136.5		$	1,167.8		$	4,200.1		$	134.0		$	4,334.1

The accompanying notes are an integral part of these consolidated financial statements.

10

Emera Incorporated

Consolidated Statements of Changes in Equity – Continued

								Accumulated
								Other						Emera			Non-
	Common		Preferred		Contributed			Comprehensive			Retained			Total			Controlling			Total
millions of Canadian dollars	Stock		Stock		Surplus			Income (“AOCI”)			Earnings			Equity			Interest			Equity
2014
Balance, December 31, 2013	$	1,703.0	$	514.0	$	4.1		$	(430.1	)	$	817.2			2,608.2		$	289.0		$	2,897.2
Net income of Emera Incorporated		—		—		—			—			432.9			432.9			19.9			452.8
Other comprehensive income (loss), net of tax recovery of $7.7 million		—		—		—			78.3			—			78.3			11.7			90.0
Issuance of common stock, net of after-tax issuance costs		242.8		—		—			—			—			242.8			—			242.8
Dividends declared on preferred stock (note 34)		—		—		—			—			(26.2	)		(26.2	)		—			(26.2	)
Dividends declared on common stock ($1.4750/share)		—		—		—			—			(210.0	)		(210.0	)		—			(210.0	)
Dividends paid by subsidiaries to non-controlling interest		—		—		—			—			—			—			(2.3	)		(2.3	)
Issuance of preferred shares, net of after-tax issuance costs		—		195.5		—			—			—			195.5			—			195.5
Common stock issued under purchase plan		63.6		—		—			—			—			63.6			—			63.6
Senior management stock options exercised		6.2		—		(0.5	)		—			—			5.7			—			5.7
Stock option expense		—		—		1.2			—			—			1.2			—			1.2
Employee Share Purchase Plan		0.8		—		—			—			—			0.8			—			0.8
Preferred dividends paid by subsidiaries to non-controlling interest		—		—		—			—			—			—			(10.7	)		(10.7	)
Equity method investments		—		—		4.0			4.2			(2.2	)		6.0			—			6.0
Other		—		—		—			—			—			—			(1.0	)		(1.0	)
Balance, December 31, 2014	$	2,016.4	$	709.5	$	8.8		$	(347.6	)	$	1,011.7			3,398.8		$	306.6		$	3,705.4

The accompanying notes are an integral part of these consolidated financial statements.

11

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2015 and 2014

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both the regulated and non-regulated operations of Emera Incorporated are as follows:

A. Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, as well as gas transmission and utility energy services.

Emera’s primary rate-regulated subsidiaries and investments at December 31, 2015 included the following:

• Nova Scotia Power Inc. (“NSPI”), which is a fully integrated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 506,000 customers;

• Emera Maine provides electric transmission and distribution services to approximately 158,000 customers in the State of Maine in the United States;

• a 95.5 per cent interest in Emera (Caribbean) Incorporated (“ECI”), the parent of The Barbados Light & Power Company Limited (“BLPC”), which is a vertically integrated utility and sole provider of electricity on the island of Barbados, serving approximately 126,000 customers; a 49.6 per cent indirect interest, through ECI’s 51.9 per cent controlling interest, in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving approximately 36,000 customers; and a 18.2 per cent indirect interest, through ECI, in St. Lucia Electricity Services Limited (“Lucelec”), which is a vertically integrated regulated electric utility in St. Lucia;

• a 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited (“ICDU”)) in Grand Bahama Power Company Limited (“GBPC”), which is a vertically integrated utility and sole provider of electricity on Grand Bahama Island, serving approximately 19,000 customers;

• Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), which is a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada (“REC”);

• Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focused on two transmission investments related to the development of an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador, scheduled to be in service in 2017. ENL’s two investments are:

• 100 per cent interest in NSP Maritime Link Inc. (“NSPML”), which is developing the Maritime Link Project, a $1.56 billion transmission project, including two 170-kilometre sub-sea cables, between the island of Newfoundland and Nova Scotia;

• 55.1 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.1 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined on completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is expected to go into service in 2017.

• a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), which is a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States;

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Emera Incorporated and its subsidiaries also own investments in other energy-related companies, including:

• Emera Energy Inc. (“Emera Energy”), includes:

• Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services;

• Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities”), comprising 1,090 MW of combined-cycle gas-fired electricity generating capacity in the northeastern United States;

• Bayside Power Limited Partnership (“Bayside Power”), which is a 290 MW electricity generating facility in Saint John, New Brunswick;

• Brooklyn Power Corporation (“Brooklyn Energy”), which is a 30 MW biomass co-generation merchant electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI;

• a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), which is a 600 MW pumped storage hydroelectric facility in northern Massachusetts;

• a 49.0 per cent interest in Northeast Wind Partners II, LLC (“NWP”), a 419 MW portfolio of wind energy projects in the northeastern United States, which was sold on January 29, 2015;

• Emera Reinsurance Limited, which is a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost efficient management of risk and deductible levels across Emera;

• Emera Utility Services Inc., which is a utility services contractor primarily operating in Atlantic Canada;

• Emera Utility Services (Bahamas) Limited (“EUS Bahamas”) provides utility construction services and plant operation services in The Bahamas;

• a 23.4 per cent investment in Algonquin Power & Utilities Corp. (“APUC”), which is a public company traded on the Toronto Stock Exchange under the symbol “AQN”;

• a 3.3 per cent investment in OpenHydro Group Ltd. (“Open Hydro”);

• and other investments.

Pending acquisition

On September 4, 2015, Emera entered into an Agreement and Plan of Merger pursuant to which, Emera US Inc., a wholly owned indirect subsidiary of Emera, will merge with and into TECO Energy, Inc. (“TECO Energy”), and TECO Energy will survive the merger and become a wholly owned indirect subsidiary of Emera. TECO Energy shareholders will receive $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.4 billion USD, when including assumption of approximately $3.9 billion USD of debt.

The closing of the acquisition, which is expected to occur mid-2016, is subject to certain regulatory and government approvals, including approval by the New Mexico Public Regulation Commission, the Committee on Foreign Investment in the United States, and the satisfaction of closing conditions. TECO Energy shareholder approval was received on December 3, 2015. On December 14, 2015, the New Mexico Public Regulation Commission established hearing to begin May 23, 2016 for the joint application for approval of the change in control of New Mexico Gas Co. effected by the Transaction. On January 21, 2016, the FERC approved the Transaction. On February 8, 2016, the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, waiting period expired.

TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include: Tampa Electric, an integrated regulated electric utility which serves more than 700,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution utility which serves more than 350,000 customers across Florida; and New Mexico Gas

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Co., also a regulated gas distribution utility which serves more than 510,000 customers across New Mexico.

B. Basis of Presentation

These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). In the opinion of management, these consolidated financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera Incorporated.

All dollar amounts are presented in Canadian dollars, unless otherwise indicated.

C. Principles of Consolidation

The consolidated financial statements of Emera Incorporated include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity where Emera is the primary beneficiary, as discussed in Note 37. Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues, with an offset to property, plant and equipment, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction.

D. Use of Management Estimates

The preparation of consolidated financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Significant estimates are included in unbilled revenue, allowance for doubtful accounts, inventory, valuation of derivative instruments, capitalized overhead, depreciation, amortization, regulatory assets and regulatory liabilities (including the determination of the current portion), income taxes (including deferred income taxes), pension and post-retirement benefits, asset retirement obligations (“AROs”), goodwill impairment assessments, valuation of investments and contingencies. Actual results may differ significantly from these estimates.

E. Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an independent third party regulator; are designed to recover the costs of providing the regulated products or services; and it is reasonable to assume rates are set at levels such that the costs can be charged to and collected from customers.

Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable for recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income.

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Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.

For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator.

F. Foreign Currency Translation

Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income.

Assets and liabilities of self-sustaining foreign operations are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average rates for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI.

G. Revenue Recognition

Operating revenues are recognized when electricity is delivered to customers or when products are delivered and services are rendered. Regulated revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on meter readings and estimates, which occur on a systematic basis throughout a month. At the end of each month, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The accuracy of the unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes.

Non-regulated revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured.

The Company records the net investment in a lease under the direct finance method, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.

Other revenues are recognized when services are performed or goods delivered.

H. Stock-Based Compensation

The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company accounts for its plans in accordance with the fair value based method of accounting for stock-based compensation. Stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are measured at fair value and re-measured at fair value at each reporting date with the change in liability recognized in income.

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I. Employee Benefits

The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in AOCI.

J. Earnings per Share

Basic earnings per share (“EPS”) is determined by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the senior management stock option plan and preferred shares of a subsidiary.

K. Cash and Cash Equivalents

Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. Total short-term investments of $77.6 million have an effective interest rate of 0.6 per cent at December 31, 2015 (2014 – $60.9 million with an effective interest rate of 1.0 per cent).

L. Receivables and Allowance for Doubtful Accounts

Customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit risk assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis.

Management estimates uncollectible accounts receivable after considering historical loss experience, current events and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.

M. Inventory

Fuel and materials inventory are measured at the lower of cost or market. Fuel costs are determined using the weighted average method and material costs are determined using the average costing method. Fuel and materials are charged to inventory when purchased and then expensed or capitalized, as appropriate, using the weighted average cost method for fuel and average costing method for materials.

Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purchased, or allocated by the respective government agency.

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N. Property, Plant and Equipment

Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of contributions received in aid of construction.

The cost of additions, including betterments and replacements of units of property, plant and equipment are included in “Property, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions occur.

Normal maintenance projects are expensed as incurred. Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized.

O. Capitalization Policy

The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, AROs and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have future economic benefit.

P. Depreciation

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated assets require the appropriate regulatory approval.

Q. Intangible Assets

Intangible assets consist primarily of computer software, land rights and naming rights with definite lives. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. The service lives of regulated intangible assets require the appropriate regulatory approval.

The estimated useful lives, in years, for each major category of intangibles with definite lives consist of the following:

Computer software	3 to 15
Land rights	50 to 143
Naming rights	1 to 24

The estimated average amortization for each of the next five fiscal years is as follows:

millions of Canadian dollars	2016		2017		2018		2019		2020
Computer software	$	12.1	$	11.9	$	11.6	$	11.3	$	11.9
Land rights		2.0		2.0		2.0		2.0		2.0
Naming rights		0.4		0.2		0.2		0.2		0.2
	$	14.5	$	14.1	$	13.8	$	13.5	$	14.1

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R. Asset Impairment

Goodwill

Goodwill is not amortized, but is subject to an annual impairment test. Emera’s reporting units containing goodwill assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount during the fourth quarter of each year, and interim impairment tests are performed when impairment indicators are present. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value.

Long-Lived Assets

Other long-lived assets require an impairment review when; based on the qualitative assessment, there is more than 50 per cent likelihood that the indefinite-lived intangible asset’s fair value is less than its carrying amount. Emera bases its evaluation of other long-lived assets on the presence of impairment indicators, such as the future economic benefit of the assets, any historical or future profitability measurements, and other external market conditions or factors.

Assets Held and Used: The carrying amount of assets held and used is considered not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value.

Assets Held for Sale: The carrying value of assets held for sale is considered not recoverable if it exceeds the fair value less the cost to sell. An impairment charge is recorded for any excess of the carrying value over the fair value less estimated costs to sell.

Cost and Equity Method Investments

The carrying value of investments accounted for under the cost and equity methods are assessed for impairment by comparing the fair values of these investments to their carrying values, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s fair value.

Financial Assets

The Company assesses at each balance sheet date whether there is objective evidence that a financial asset or a group of financial assets is impaired. In the case of equity securities classified as available-for-sale, an other than temporary decline in the fair value of the security below its cost is considered as an indicator that the securities are impaired. In the case of debt securities classified as available-for-sale, a breach of contract, such as default or delinquency in interest or principal payments, or evidence of significant financial difficulty of the issuer is considered an indicator of impairment. If any such evidence exists for available-for-sale financial assets, the cumulative loss, measured as the difference between the acquisition cost and the current fair value, less any impairment loss on that financial asset previously recognized in income, is removed from AOCI and recognized on the Consolidated Statements of Income.

S. Debt Financing Costs

The Company capitalizes the external costs of obtaining debt financing and includes them as “Other assets” on the Consolidated Balance Sheets. The deferred charge is amortized over the life of the related debt on an effective interest basis and included in “Interest expense, net” on the Consolidated Statements of Income.

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T. Income Taxes and Investment Tax Credits

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.

Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned by Emera Maine on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by United State tax laws and Maine regulatory practices.

Emera’s rate-regulated subsidiaries recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future rates, unless specifically directed otherwise by a regulator.

Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively.

U. Asset Retirement Obligations

An asset retirement obligation (“ARO”) is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is deferred to a regulatory asset in “Property, plant and equipment” and included in the next depreciation study.

Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.

V. Derivatives and Hedging Activities

Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management policies and practices are overseen by the Board of Directors. The Company has established a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes establishment of the Enterprise Risk Management Committee, whose responsibilities include preparing and updating a “Risk Dashboard” for the Board of Directors on a quarterly basis. Furthermore, a corporate team independent from operations is responsible for tracking and reporting on market and credit risks.

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The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as held-for-trading (“HFT”). Collectively, these contracts are considered “derivatives”.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period.

Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value, with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates.

Derivatives that do not meet any of the above criteria are designated as HFT derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory and property, plant and equipment, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of trading and marketing transactions is recognized as an asset in “Other” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows.

W. Derivative Positions and Cash Collateral

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”.

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X. Fair Value Measurement

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (refer to notes 15 and 16), and uses a market approach to do so. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information, including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. The Company uses a fair value hierarchy, based on the relative objectivity of the inputs used to measure fair value, with Level 1 representing the highest.

The three levels of the fair value hierarchy are defined as follows:

Level 1 Valuations – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 Valuations – Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 Valuations – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:

• While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

• The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

• The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Y. Variable Interest Entities

The Company performs ongoing analysis to assess whether it holds any variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities.

VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses or the right to receive benefits of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is not consolidated in the Company’s consolidated financial statements.

Z. Available-for-sale Investments

Assets designated as available-for-sale are non-derivative financial assets (equity and debt securities) intended to be held for an indefinite period of time, and may be sold in response to needs for liquidity or changes in interest rates, exchange rates or equity prices.

Regular purchases and sales of financial assets are recognized at fair value, including transaction costs, on the trade date, the date on which the Company commits to purchase or sell the asset and subsequently carried at fair value based on current bid prices on the market. Unrealized gain and losses

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arising from changes in the fair value of available-for-sale assets are recognized in AOCI until the financial asset is sold, or otherwise disposed of, or until the financial investment is determined to be impaired, at which time the cumulative gain or loss will be included in income for the period.

Interest on available-for-sale debt securities is calculated using the effective interest method and is recognized on the Consolidated Statements of Income in “Other income (expenses), net”. Dividends on available-for-sale equity securities are recognized on the Consolidated Statements of Income in “Other income (expenses), net”.

2. CHANGE IN ACCOUNTING POLICY

Business Combinations – Simplifying the Accounting for Measurement-Period Adjustments, Accounting Standard Update (“ASU”) Number (“No.”) 2015-16

In September 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-16, Business Combinations –Simplifying the Accounting for Measurement-Period Adjustments. The amendment applies to entities that have reported provisional amounts related to a business combination for which the accounting is incomplete by the end of the reporting period and have an adjustment to provisional amounts previously recognized during a later measurement period. Changes in provisional amounts recorded for acquired assets and liabilities are to be adjusted in the period the adjustment is known, with a corresponding adjustment booked to goodwill. The acquirer is no longer required to revise comparative information from prior years for the effect of changes in provisional amounts. The Company has adopted ASU 2015-16 effective Q3 2015, with no impact on the consolidated financial statements as a result of implementation of this standard.

Income Taxes – Balance Sheet Classification of Deferred Taxes, ASU 2015-17

In November 2015, the FASB issued ASU 2015-17, Income Taxes – Balance Sheet Classification of Deferred Taxes, which simplifies the presentation of deferred income taxes. The amendment requires that deferred tax assets and liabilities be classified as noncurrent on the Consolidated Balance Sheets, regardless of whether the deferred income taxes are expected to be recovered or settled within the next twelve months. ASU-2015-17 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016. Early adoption is permitted for any interim or annual financial statements that have not yet been issued.

The Company has early adopted ASU 2015-17 effective December 31, 2015, and 2014 balances have been retrospectively restated. This change decreased the current deferred income tax asset and liability by $49.2 million and $4.1 million respectively on the Consolidated Balance Sheets as at December 31, 2015 (2014 – $27.9 million and $15.7 million respectively). As a result of the change the long-term deferred income tax asset increased by $15.2 million (2014 – $24.1 million) and the long-term deferred income tax liability decreased by $29.9 million (2014 – increased by $11.9 million) on the Consolidated Balance Sheets as at December 31, 2015.

This change also reclassified a $11.9 million current deferred income tax regulatory liability (2014 – $8.0 million) to the long-term deferred income tax regulatory asset on the Consolidated Balance Sheets as at December 31, 2015.

Fair Value Measurement Disclosures for Investments in Certain Entities That Calculate Net Asset Value (“NAV”) per Share (or Its Equivalent), ASU No. 2015-07

In May 2015, the FASB issued ASU 2015-07 removing the requirement to categorize and disclose, within the fair value hierarchy, all investments for which fair value is measured using the net asset value per share as a practical expedient. The Company has early adopted ASU No. 2015-07 effective December 31, 2015 and 2014. The adoption of this update resulted in disclosure of all investments for which fair value is measured using the net asset value per share methodology being disclosed outside of the fair-value hierarchy. As at December 31, 2015, total investments measured using the net asset value per share were $672.4 million (December 31, 2014 – $635.7 million).

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3. FUTURE ACCOUNTING PRONOUNCEMENTS

Revenue from Contracts with Customers, ASU No. 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework and a new topic in the Accounting Standards Codification (“ASC”), Topic 606. ASC 606 also changes the basis for determining when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific aspects of revenue recognition and expands revenue disclosures. On July 9, 2015, the FASB deferred the effective date by one year. This standard will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.

The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

Income Statement – Extraordinary and Unusual Items, ASU No. 2015-01

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items, which simplifies the income statement presentation requirements by eliminating the concept of extraordinary items. ASU No. 2015-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Consolidation, ASU No. 2015-02

In February 2015, the FASB issued ASU 2015-02, Consolidation, which changes the analysis a reporting entity must perform to determine whether it should consolidate certain types of legal entities. All legal entities are subject to re-evaluation under the revised consolidation model. ASU No. 2015-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Interest – Imputation of Interest, No. ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected by the amendments in the update. ASU No. 2015-03 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2015. The adoption of this update will result in the reclassification of debt issuance costs from “Other long-term assets” to “Long-term debt” and “Convertible debentures represented by instalment receipts” on the Company’s consolidated balance sheets. As at December 31, 2015, debt issuance costs included in “Other long-term assets were $66.8 million (December 31, 2014 – $18.8 million).

In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest – Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, which clarifies that the guidance in ASU No. 2015-03 does not apply to line-of-credit arrangements. ASU No. 2015-15 permits an entity to defer and present debt issuance costs as an asset and subsequently amortize these costs ratably over the time of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. ASU No. 2015-15 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2015. As at December 31, 2015, debt issuance costs associated with line-of-credit arrangements included in “Other long-term assets” were $4.0 million (December 31, 2014 – $4.1 million) on the Company’s Consolidated Balance Sheets.

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Compensation – Retirement Benefits, ASU No. 2015-04

In April 2015, the FASB issued ASU 2015-04, Compensation – Retirement Benefits, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard provides certain practical expedients for defined benefit pension or other post-retirement benefit plan measurement dates. ASU No. 2015-04 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Intangibles – Goodwill and Other – Internal-Use Software, ASU No. 2015-05

In April 2015, the FASB issued ASU 2015-05, Intangibles – Goodwill and Other – Internal-Use Software, which provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer’s accounting for service contracts. ASU No. 2015-05 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Technical Corrections and Improvements, ASU No. 2015-10

In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Improvements, covering a wide range of topics in the codification to correct unintended application of guidance, or make minor improvements to the Codification that are not expected to have a significant effect on current accounting practice or create a significant administrative cost. ASU No. 2015-10 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Inventory – Simplifying the Measurement of Inventory, ASU No. 2015-11

In July 2015, the FASB issued ASU 2015-11, Inventory – Simplifying the Measurement of Inventory. The amendments require an entity to measure inventory at the lower of cost or net realizable value, whereas previously, inventory was measured at the lower of cost or market. ASU No. 2015-11 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities, ASU No. 2016-01

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. ASU No. 2016-01 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

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4. SEGMENT INFORMATION

Emera manages its reportable segments separately due to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets.

As at December 31, 2015, Emera has six reportable segments, specifically:

• NSPI;

• Emera Maine;

• Emera Caribbean (ECI and its subsidiaries including BLPC, Domlec, GBPC, EUS Bahamas and an equity investment in Lucelec);

• Pipelines (Brunswick Pipeline and an equity investment in M&NP);

• Emera Energy (Emera Energy Services, New England Gas Generating Facilities, Bayside Power, Brooklyn Energy, equity investments in Bear Swamp and NWP for January 1, 2015 to January 29, 2015, when Emera sold its interest in NWP); and

• Corporate and Other (Emera Utility Services, ENL, Corporate, other strategic investments (including APUC) and holding companies.

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millions of Canadian dollars	NSPI		Emera Maine		Emera Caribbean		Pipelines			Emera Energy			Corporate and Other			Inter- segment Eliminations			Total
For the year ended December 31, 2015
Operating revenues from external customers (1)	$	1,417.3	$	284.1	$	442.5	$	52.1		$	578.0		$	16.1		$	(2.4	)	$	2,787.7
Inter-segment revenues (1)		—		—		7.5		—			11.9			24.0			(41.8	)		1.6
Total operating revenues		1,417.3		284.1		450.0		52.1			589.9			40.1			(44.2	)		2,789.3
Allowance for funds used during construction – debt and equity		4.5		1.6		0.1		—			—			—			—			6.2
Regulated fuel and fixed cost deferral adjustments		41.6		—		—		—			—			—			—			41.6
Depreciation and amortization		206.5		46.6		44.1		0.4			40.6			1.7			—			339.9
Interest expense		119.6		18.8		14.0		9.7			0.7			47.7			—			210.5
Interest revenue		4.8		0.4		—		—			0.7			0.1			—			6.0
Internally allocated interest (2)		—		—		—		(16.5	)		(17.7	)		34.2			—			—
Income from equity investments		—		0.5		3.1		23.0			20.7			61.3			—			108.6
Income tax expense (recovery)		23.4		26.7		3.3		11.2			49.5			(21.7	)		—			92.4
Capital expenditures		270.6		64.6		44.0		—			98.0			9.5			—			486.7
Net income attributable to common shareholders		129.9		45.1		40.5		37.5			98.9			45.3			—			397.2
As at December 31, 2015																	—
Total assets		4,641.6		1,559.8		1,406.8		804.5			1,918.5			1,906.4			(225.3	)		12,012.3
Investments subject to significant influence		—		12.7		39.4		188.7			—			904.5			—			1,145.3
Goodwill		—		158.2		105.5		—			—			0.4			—			264.1
For the year ended December 31, 2014
Operating revenues from external customers (1)	$	1,348.2	$	242.6	$	477.1	$	48.8		$	789.4		$	31.4		$	(3.1	)	$	2,934.4
Inter-segment revenues (1)		—		—		8.8		—			11.5			17.3			(33.4	)		4.2
Total operating revenues		1,348.2		242.6		485.9		48.8			800.9			48.7			(36.5	)		2,938.6
Allowance for funds used during construction – debt and equity		5.9		5.6		0.2		—			—			2.4			—			14.1
Regulated fuel and fixed cost deferral adjustments		46.6		—		—		—			—			—			—			46.6
Depreciation and amortization		204.0		47.9		36.8		0.3			37.7			2.3			—			329.0
Interest expense		112.1		14.4		12.8		—			6.3			30.6			—			176.2
Interest revenue		7.6		0.5		—		—			—			0.1			—			8.2
Internally allocated interest (2)		—		—		—		(26.0	)		—			26.0			—			—
Gain on acquisition		—		—		2.8		—			—			—			—			2.8
Income from equity investments		—		0.4		2.4		18.4			(0.9	)		46.3			—			66.6
Income tax expense (recovery)		19.7		19.5		3.1		8.4			83.5			(20.6	)		—			113.6
Capital expenditures		274.1		79.2		29.4		0.5			63.0			7.3			—			453.5
Net income attributable to common shareholders		124.9		42.4		28.7		32.7			185.7			(7.7	)		—			406.7
As at December 31, 2014
Total assets		4,318.1		1,292.6		1,149.3		783.2			1,645.2			817.7			(152.7	)		9,853.4
Investments subject to significant influence		—		7.6		31.7		171.8			237.1			579.4			—			1,027.6
Goodwill		—		132.7		88.4		—			—			0.4			—			221.5

(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Inter-company transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs.

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Geographical Information

Revenues (1):

For the	Year ended December 31
millions of Canadian dollars	2015		2014
Canada	$	1,546.1	$	1,510.9
United States		785.7		933.8
Barbados		258.9		306.2
The Bahamas		154.3		146.0
Dominica		44.3		41.7
	$	2,789.3	$	2,938.6

(1) Revenues are based on country of origin of the product or service sold

Property Plant and Equipment:

As at millions of Canadian dollars	December 31 2015		December 31 2014
Canada	$	3,482.4	$	3,397.6
United States		1,946.6		1,577.3
Barbados		398.7		332.4
The Bahamas		298.6		252.0
Dominica		61.7		50.9
	$	6,188.0	$	5,610.2

5. REGULATED FUEL ADJUSTMENT MECHANISM AND FIXED COST DEFERRALS

Regulated fuel adjustment mechanism and fixed cost deferrals over (under) recovery consists of the following:

For the	Year ended December 31
millions of Canadian dollars	2015			2014
Regulated fuel adjustment mechanism (see chart below)	$	31.9		$	6.4
Application of non-fuel revenues		44.7			40.2
Fixed cost deferral related to 2015 demand side management (“DSM”)		(35.0	)		—
	$	41.6		$	46.6

Regulated Fuel Adjustment Mechanism

The regulated fuel adjustment mechanism (“FAM”) included in the Consolidated Statements of Income includes the effect of prudently incurred fuel for generation and purchased power and certain fuel related costs (“Fuel Costs”) in both the current and preceding years, specifically, and as detailed in the table below:

• The difference between actual Fuel Costs and amounts recovered from customers in the current year. This amount is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities” on the Consolidated Balance Sheets; and

• The recovery from (rebate to) customers of under (over) recovered Fuel Costs from prior years.

The regulated fuel adjustment mechanism on the Consolidated Statements of Income consisted of the following:

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For the millions of Canadian dollars	Year ended December 31
	2015			2014
Over (Under) recovery of current period Fuel costs	$	(24.1	)	$	1.3
Recovery from (rebate to) customers of prior years’ Fuel costs		56.0			—
FAM audit disallowance		—			5.1
Regulated fuel adjustment mechanism	$	31.9		$	6.4

The deferred FAM amounts are recognized as a “Regulatory asset” or “Regulatory liability” on the Consolidated Balance Sheets. The FAM regulatory liability balance of $28.3 million is disclosed in Note 17 and includes associated interest that is recorded as “Interest expense, net” on the Consolidated Statements of Income.

Pursuant to the FAM Plan of Administration, NSPI’s fuel costs are subject to independent audit. On January 20, 2015, the UARB disallowed $6.0 million of 2012 and 2013 fuel-related costs, which includes interest of $0.9 million. The disallowances resulted in a reduction in the amount of the FAM deferral as at December 31, 2014 and resulted in an after-tax impact to 2014 net income of $3.3 million.

On December 21, 2015, the UARB approved NSPI’s setting of the 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as submitted in NSPI’s August and November 2015 filings. The recovery of these costs will begin January 1, 2016. The approved customer rates reset the base cost of fuel rate for 2016 and seek to recover $13.7 million of prior years’ unrecovered Fuel Costs in 2016. This decision results in a combined average rate decrease for customers of approximately 1 per cent.

On December 18, 2015, the Electricity Plan Implementation (2015) Act (the “Electricity Plan Act”) was enacted by the Province of Nova Scotia. The Electricity Plan Act requires NSPI to file a three-year rate plan for Fuel Costs in Q1 2016 and to file a three-year general rate application to change non-fuel rates by April 30, 2016, if required by NSPI. A primary goal of the Electricity Plan Act is to provide rate stability over those years. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates during this period will be deferred to a FAM regulatory asset or liability and recovered from or returned to customers subsequent to 2019.

The Electricity Plan Act also directs NSPI to apply non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of tax benefits for the South Canoe and Sable Wind Projects is to be reserved to be applied to the FAM in the 2017 to 2019 period. The exception to this direction is to apply a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would have been otherwise required. This amount totals $4.6 million. As a result, as at December 31, 2015, NSPI has deferred $4.6 million of excess non-fuel revenues to 2016 and $40.1 million of excess non-fuel revenues for the periods 2017 to 2019.

A settlement agreement, approved by the UARB in November 2014, resulted in approximately $56.0 million of the outstanding FAM balance as at December 31, 2014 being collected in 2015. The settlement agreement also reduced the FAM regulatory asset at the end of 2014 of $86.1 million by $38.2 million via an offset from the liability balance in the Rate Stabilization deferral account, such that at December 31, 2014 the FAM regulatory asset was $47.9 million.

Through a related settlement agreement with stakeholders in December 2014, NSPI agreed to apply non-fuel revenues above that required to achieve its approved range of return to reduce the FAM deferral account. This was effective as of January 1, 2015, and remains until the next General Rate Application (“GRA”) approval or similar process where non-fuel rates are adjusted. This settlement agreement required NSPI to contribute a minimum of $41.3 million to the FAM deferral account by the end of 2015. As at December 31, 2015, NSPI had exceeded the minimum required contribution through the $38.2 million in 2014 referred to above and an additional $26.4 million in 2015. In 2015, NSPI applied $44.7

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million in excess non-fuel revenues against the FAM; $18.3 million was the result of the change to South Canoe and Sable Wind Projects tax treatment.

Regulated Fixed Cost Deferrals

NSPI has the following regulatory assets arising from UARB approved fixed cost deferral mechanisms:

DSM Deferral

In April 2014, the Government of Nova Scotia announced new energy efficiency legislation to remove a previous charge for conservation and efficiency programs from power bills of Nova Scotia customers effective January 1, 2015. In addition, the legislation requires NSPI to purchase electricity efficiency and conservation activities (“Program Costs”) from EfficiencyOne, the provincially appointed franchisee to deliver energy efficiency programs to Nova Scotians. The Program Costs were set for 2015 at $35.0 million and have been deferred as a regulatory asset and recoverable from customers over an eight-year period beginning in 2016. In August 2015, the UARB approved a budget of $102.0 million for the three-year period of 2016 through 2018. The Electricity Plan Act has placed a cap of $34.0 million on the 2019 DSM spending. The 2016 DSM cost of $24.7 million will not be deferred. A decision of the timing of the cost recovery for 2017 through 2019 will be made at a future date.

The Program Costs are recorded in “OM&G”, with an offsetting credit in “Regulated fuel adjustment mechanism and fixed cost deferrals” on Emera’s Consolidated Income Statements, with no effect on net earnings, with the exception of interest on the balance.

The deferred DSM amounts are recognized as a “Regulatory asset” on the Consolidated Balance Sheets. The DSM regulatory asset balance of $36.4 million is disclosed in Note 17 and includes associated interest that is recorded as “Interest expense, net” on the Consolidated Statements of Income.

2013/2014 Rate Stabilization Fixed Cost Recovery Deferral

In December 2012, the UARB approved a deferral of recovery of certain fixed costs for fiscal 2013 and 2014 as part of a rate stabilization plan. As previously noted above under the Regulated Fuel Adjustment Mechanism, the resulting regulatory liability at the end of 2014 of $38.2 million was applied against the FAM regulatory asset balance in 2014 and is included in the application of non-fuel revenues line in the table above.

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6. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Investments subject to significant influence consisted of the following:

					Equity Income
millions of Canadian dollars	Carrying Value As at December 31				For the year ended December 31					Percentage of Ownership
	2015		2014		2015		2014			2015
APUC (1) (2)	$	503.7	$	336.4	$	36.9	$	30.4			23.4
LIL (3)		208.1		80.1		9.5		6.4			55.1
M&NP (4)		188.7		171.8		23.0		18.4			12.9
NSPML (5)		187.6		159.3		14.9		9.5			100.0
Lucelec (4)		39.4		31.7		3.1		2.4			18.2
Maine Electric Power Company Inc.		7.0		2.9		0.5		0.4			21.7
Chester Static Var Compensator		5.3		4.4		—		—			50.0
Cape Sharp Tidal Venture Ltd.		5.1		3.6		—		—			20.0
Maine Yankee Atomic Power Company (4)		0.4		0.3		—		—			12.0
Bear Swamp (6)		—		—		16.4		16.4			50.0
NWP (7)		—		237.1		4.3		(17.3	)		49.0
	$	1,145.3	$	1,027.6	$	108.6	$	66.6

(1) As at December 31, 2015, the market price/share was $10.91 (December 31, 2014 – $9.64), which indicates a fair market value of this investment of $684.5 million (December 31, 2014 – $483.2 million). Emera holds 50.1 million shares and 12.6 million outstanding subscription receipts and dividend equivalents as at December 31, 2015 at an average book value of $8.03 per share. Carrying value reflects a cash cost of $371.2 million, plus non-cash gains recognized on conversion of subscriptions receipts into common shares, dilution gains or losses, and equity income or loss, less dividends received. In Q4 2015, Emera reclassified outstanding subscription receipts from “Other long-term assets” to Investments subject to significant influence as they became eligible for conversion into APUC common shares.

(2) Emera’s Strategic Investment Agreement with APUC and a ruling by the Maine Public Utilities (“MPUC”) limits Emera’s ownership in APUC to 25 per cent of APUC’s voting securities. The MPUC also stipulated Emera’s dollar investment in APUC cannot exceed 5 per cent of Emera’s total assets. As at December 31, 2015, Emera is in compliance with both of these requirements.

(3) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. Emera’s share of the total partnership capital is 55.1 per cent.

(4) Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in these entities using the equity method. This is consistent with industry practice for similar investments with significant influence.

(5) Until Emera achieved certain critical milestones, including its financing and approvals to enable it to proceed to full construction, Emera recorded the Maritime Link Project development and engineering costs in “Property, plant and equipment” on its Consolidated Balance Sheets. In Q2 2014, when the critical milestones were achieved, and Nalcor Energy was deemed the beneficiary of the asset for financial reporting purposes, Emera began recording the Maritime Link Project as an equity investment, with equity earnings equal to the return on equity component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017. At that time, Emera will record equity earnings equal to 100 per cent of NSPML net earnings.

(6) As at December 31, 2015 and 2014, the credit investment balance has been reclassified to “Other Long-term liabilities” on the Consolidated Balance Sheets. The 2015 and 2014 carrying value has been restated.

(7) On January 29, 2015, Emera completed the sale of its 49 per cent interest in NWP for proceeds of $282.3 million ($223.3 million USD).

Equity investments include a $145.0 million difference between the cost and the underlying fair value of the investees’ assets as at the date of acquisition. The excess is attributable to goodwill.

30

Emera accounts for its variable interest investment in NSPML as an equity investment (note 37). NSPML’s consolidated summarized balance sheet are illustrated as follows:

As at	December 31
millions of Canadian dollars	2015		2014
Balance Sheet
Current assets	$	438.7	$	388.4
Property, plant and equipment		647.7		319.3
Non-current assets		565.6		865.5
Total assets	$	1,652.0	$	1,573.2
Current liabilities	$	129.8	$	100.4
Non-current liabilities		1,334.6		1,313.5
Equity		187.6		159.3
Total liabilities and equity	$	1,652.0	$	1,573.2

Bear Swamp

As at December 31, 2015, the investment balance in Bear Swamp was a credit of $225.0 million (2014 – credit of $20.8 million). The credit investment balance is primarily a result of distributions received in excess of the original cost and earnings. This credit investment balance is recorded as a long-term liability on the Consolidated Balance Sheets (note 31).

On October 8, 2015, Bear Swamp refinanced its $125 million USD bank debt that was due to mature in 2017 and issued $400 million USD in senior secured 10-year bonds, with $375 million USD at a fixed rate of 4.89 per cent, and $25 million USD at a floating rate of LIBOR plus 2.70 per cent. The proceeds of this financing were used to repay existing debt and provide working capital to the joint venture, with the remainder shared equally between Emera and its joint venture partner. After fees and expenses, Emera received a $178.7 million ($137.3 million USD) non-taxable distribution in Q4 2015.

7. OTHER INCOME (EXPENSES), NET

Other income (expenses), net consisted of the following:

For the	Year ended December 31
millions of Canadian dollars	2015			2014
Foreign exchange gains (losses) and mark-to-market adjustments related to the pending TECO Energy acquisition	$	118.9		$	—
Gain on sale of NWP investment		18.6			—
Foreign exchange gains (losses)—Other		3.8			2.6
Allowance for equity funds used during construction		2.3			9.5
Investment income		1.2			1.6
Amortization of defeasance costs		(6.7	)		(7.9	)
Other		3.0			6.5
	$	141.1		$	12.3

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8. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

For the	Year ended December 31
millions of Canadian dollars	2015			2014
Interest on debt	$	192.8		$	186.2
Interest on convertible debentures represented by instalment receipts		22.7			—
Allowance for borrowed funds used during construction		(3.9	)		(4.6	)
Interest revenue		(6.0	)		(8.2	)
Other		7.0			6.4
	$	212.6		$	179.8

9. INCOME TAXES

The income tax provision, for the years ended December 31, differs from that computed using the statutory income tax rate for the following reasons:

millions of Canadian dollars	2015			2014
Income before provision for income taxes	$	544.8		$	566.4
Statutory income tax rate		31.0%			31.0%
Income taxes, at statutory income tax rates		168.9			175.6
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(31.3	)		(33.6	)
Non-taxable portion of mark-to-market gains related to pending TECO Energy acquisition		(18.4	)		—
Tax effect of equity earnings		(11.3	)		(8.4	)
Other		(15.5	)		(20.0	)
Income tax expense (recovery)	$	92.4		$	113.6
Effective income tax rate		17.0%			20.1%

The 2015 and 2014 statutory income tax rate of 31.0 per cent represents the combined Canadian federal and Nova Scotia provincial income tax rates, which are the relevant tax jurisdictions for Emera.

The following reflects the composition of taxes on income from continuing operations for the years ended December 31:

millions of Canadian dollars	2015			2014
Income tax expense (recovery) – current
Domestic	$	41.3		$	56.4
Foreign		30.7			17.3
Income tax expense (recovery) – deferred
Domestic		(3.8	)		(16.7	)
Foreign		(81.7	)		55.3
Operating loss carry forwards
Domestic		10.5			35.4
Foreign		95.4			(34.1	)
Income tax expense (recovery)	$	92.4		$	113.6

The following reflects the composition of income before provision for income taxes for the years ended December 31, 2015.

millions of Canadian dollars	2015		2014
Domestic	$	349.1	$	390.9
Foreign		195.7		175.5
Income before provision for income taxes	$	544.8	$	566.4

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The deferred income tax assets and liabilities as at December 31 consisted of the following:

millions of Canadian dollars	2015			2014
Deferred income tax assets:
Derivative instruments	$	191.5		$	128.2
Pension and post-retirement liabilities		128.9			156.2
Regulatory liabilities		106.7			54.5
Tax loss carry forwards		72.6			161.0
Asset retirement obligations		48.7			45.5
Intangibles		31.8			36.4
Other		98.0			77.8
Total deferred income tax assets before valuation allowance		678.2			659.6
Valuation allowance		(18.2	)		(19.2	)
Total deferred income tax assets after valuation allowance	$	660.0		$	640.4
Deferred income tax liabilities:
Property, plant and equipment	$	920.0		$	841.7
Derivative instruments		251.2			176.7
Net investment in direct financing lease		88.4			82.1
Other		129.9			95.4
Total deferred income tax liabilities	$	1,389.5		$	1,195.9
Consolidated Balance Sheets presentation:
Long-term deferred income tax assets		32.2			57.8
Long-term deferred income tax liabilities		(761.7	)		(613.3	)
Net deferred income tax liabilities	$	(729.5	)	$	(555.5	)

For regulated entities, to the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator. These amounts include a gross up to reflect the income tax associated with future revenues required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets.

The following table summarizes as at December 31, 2015 the net operating loss (“NOL”), capital loss and tax credit carryovers and the associated carryover periods, and the valuation allowances for amounts which Emera has determined that realization is uncertain:

millions of Canadian dollars	Deferred Tax Asset		Valuation Allowance			Net Deferred Tax Asset		Expiration Period
NOL	$	54.0	$	(2.7	)	$	51.3		2016 – 2035
Capital loss		18.6		(15.0	)		3.6		2018 – Indefinite
Tax credit		1.9		—			1.9		2028 – Indefinite

As at December 31, 2015, Emera had a gross NOL carryover of $389.0 million (2014 – $1,074.1 million), capital loss carryover of $88.0 million (2014 – $79.1 million), and a tax credit carryover of $25.0 million (2014 – $4.4 million).

Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that Emera is more likely than not to realize all recorded deferred income tax assets, except for the losses noted above and unrealized capital losses on certain investments. A valuation allowance has been recorded as at December 31, 2015 related to these losses and investments.

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The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows:

millions of Canadian dollars	2015		2014
Balance, January 1	$	4.8	$	5.2
Increases due to tax positions related to current year		0.5		0.1
Increases due to tax positions related to a prior year		0.8		1.7
Decreases due to tax positions related to a prior year		—		(1.2	)
Decreases due to expiration of statute of limitations		—		(1.0	)
Balance, December 31	$	6.1	$	4.8

The total amount of unrecognized tax benefits as at December 31, 2015 was $6.1 million (2014 – $4.8 million), which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $0.6 million (2014 – $0.8 million). No penalties have been accrued. The balance in unrecognized tax benefits could change up to $4.9 million in the next twelve months as a result of settlements of Canada Revenue Agency (“CRA”) audits of NSPI.

The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, US and non-US income and withholding taxes for which deferred taxes might otherwise be required have not been provided for on a cumulative amount of temporary differences related to investments in foreign subsidiaries of approximately $669.4 million as at December 31, 2015 (2014 – $555.4 million). It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred.

Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, St. Lucia and Dominica income tax returns. As at December 31, 2015, the Company’s tax years still open to examination by taxing authorities include 2006 and subsequent years.

NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for its 2006 through 2010 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $62.3 million, including taxes and interest. NSPI has prepaid $22.7 million of the amount in dispute, as required by CRA.

Should NSPI be successful in defending its position, all payments including applicable interest will be refunded with respect to NSPI’s deductions. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the excess, if any, owing to CRA. The related tax deductions will be available in subsequent years.

In Q2 2015, CRA commenced audit of NSPI’s 2011 through 2013 taxation years. Should NSPI receive notices of reassessment for those years, and should the 2014 and 2015 taxation years be similarly reassessed, further payments will be required; however, the ultimate permissibility of the deductions is similarly not in dispute.

NSPI and its advisors believe that NSPI has reported its tax position appropriately and NSPI is disputing the reassessments through the CRA Appeal process. The outcome of this process is not determinable at this time.

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10. EARNINGS PER SHARE

The following table reconciles the computation of basic and diluted earnings per share:

For the	Year ended December 31
millions of Canadian dollars (except per share amounts)	2015		2014
Numerator
Net income attributable to common shareholders	$	397.2	$	406.7
Preferred stock dividends of subsidiary (1)		—		7.7
Diluted numerator		397.2		414.4
Denominator
Weighted average shares of common stock outstanding		144.9		142.4
Weighted average deferred share units outstanding		0.9		0.8
Weighted average shares of common stock outstanding – basic		145.8		143.2
Effect of dilutive securities (1)		—		3.5
Stock-based compensation		0.6		0.3
Weighted average shares of common stock outstanding – diluted		146.4		147.0
Earnings per common share
Basic	$	2.72	$	2.84
Diluted (1)	$	2.71	$	2.82

(1) On October 15, 2015, NSPI redeemed all of its outstanding Cumulative Redeemable First Preferred Shares. Therefore, the preferred shares are excluded from the calculation of diluted earnings per share as at December 31, 2015.

Convertible Debentures Effect on EPS

Following the satisfaction of all conditions precedent to the closing of the acquisition of TECO Energy, at the option of holders and provided that payment of the final installment has been made, each Debenture will be convertible into common shares of Emera at any time after the Final Instalment Date, but prior to maturity or redemption by the Company at a conversion price of $41.85 per common share, being a conversion rate of 23.8949 common shares per $1,000 principal amount of Debentures (note 30). Accordingly, a total of approximately 52.2 million common shares could be issued to convert the Debentures into common shares. When the conditions for closing the acquisition are met, the Debentures will be included as a component of the Company’s diluted EPS.

35

11. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income are as follows:

millions of Canadian dollars	(Losses) gains on derivatives recognized as cash flow hedges			Net change in unrecognized pension and post-retirement benefit costs			Net change on available-for-sale investments			Unrealized (loss) gain on translation of self-sustaining foreign operations			Total AOCI
For the year ended December 31, 2015
Balance, January 1, 2015	$	(7.9	)	$	(424.7	)	$	2.6		$	82.4		$	(347.6	)
Other comprehensive income (loss) before reclassifications		(33.5	)		—			(2.3	)		406.5			370.7
Amounts reclassified from accumulated other comprehensive income loss		6.5			107.1			—			—			113.6
Net current period other comprehensive income (loss)		(27.0	)		107.1			(2.3	)		406.5			484.3
Other		(0.2	)		—			—			—			(0.2	)
Balance, December 31, 2015	$	(35.1	)	$	(317.6	)	$	0.3		$	488.9		$	136.5
millions of Canadian dollars	(Losses) gains on derivatives recognized as cash flow hedges			Net change in unrecognized pension and post-retirement benefit costs			Net change on available-for-sale investments			Unrealized (loss) gain on translation of self-sustaining foreign operations			Total AOCI
For the year ended December 31, 2014
Balance, January 1, 2014	$	(4.2	)	$	(353.4	)	$	2.4		$	(74.9	)	$	(430.1	)
Other comprehensive income (loss) before reclassifications		(7.7	)		—			0.2			153.5			146.0
Amounts reclassified from accumulated other comprehensive income loss (gain)		3.6			(71.3	)		—			—			(67.7	)
Net current period other comprehensive income (loss)		(4.1	)		(71.3	)		0.2			153.5			78.3
Other		0.4			—			—			3.8			4.2
Balance, December 31, 2014	$	(7.9	)	$	(424.7	)	$	2.6		$	82.4		$	(347.6	)

36

The reclassifications out of accumulated other comprehensive income (loss) are as follows:

For the		Year ended December 31
millions of Canadian dollars		2015			2014
	Affected line item in the Consolidated Statements of Income		Amounts reclassified from AOCI
Losses (gain) on derivatives recognized as cash flow hedges
Power and gas swaps	Non-regulated fuel for generation and purchased power	$	(4.8	)	$	(0.9	)
Interest rate swaps	Income from equity investments		0.6			0.5
Interest rate swaps	Interest expense, net		—			0.2
Foreign exchange forwards	Operating revenue – regulated		9.0			3.7
Total before tax			4.8			3.5
	Income tax expense		1.7			0.1
Total net of tax		$	6.5		$	3.6
Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses (gains)	OM&G	$	50.4		$	33.4
Past service costs (gains)	OM&G		(7.1	)		(2.5	)
Amounts reclassified into obligations	Pension and post-retirement benefits		72.3			(115.8	)
Total before tax			115.6			(84.9	)
	Income tax expense (recovery)		(8.5	)		13.6
Total net of tax		$	107.1		$	(71.3	)
Total reclassifications out of AOCI, net of tax, for the period		$	113.6		$	(67.7	)

12. RESTRICTED CASH

Restricted cash consisted of the following:

As at millions of Canadian dollars	December 31 2015		December 31 2014
Restricted cash – BLPC	$	14.8	$	14.9
Restricted cash – Brunswick Pipeline		3.4		—
Restricted cash – Other		1.1		1.0
	$	19.3	$	15.9

13. RECEIVABLES, NET

Receivables, net consisted of the following:

As at millions of Canadian dollars	December 31 2015			December 31 2014
Customer accounts receivable – billed	$	407.0		$	356.0
Customer accounts receivable – unbilled		144.2			141.1
Total customer accounts receivable		551.2			497.1
Allowance for doubtful accounts		(12.6	)		(11.1	)
Customer accounts receivable, net		538.6			486.0
Other		39.5			28.2
	$	578.1		$	514.2

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14. INVENTORY

Inventory consisted of the following:

As at millions of Canadian dollars	December 31 2015		December 31 2014
Fuel	$	185.3	$	185.7
Materials		100.4		87.9
Emission credits (1)		28.6		20.9
	$	314.3	$	294.5

(1) The New England Gas Generating Facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions. In addition, Bridgeport Energy is subject to the Clean Air Interstate Rule for ozone season nitrogen dioxide emission allowances. The emissions credits inventory balance represents the credits purchased to offset the liabilities (note 31) associated with these programs.

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15. DERIVATIVE INSTRUMENTS

Derivative assets and liabilities relating to the foregoing categories consisted of the following:

	Derivative Assets						Derivative Liabilities
As at	December 31						December 31
millions of Canadian dollars	2015			2014			2015			2014
Current
Cash flow hedges
Power swaps	$	7.9		$	8.4		$	0.5		$	0.5
Foreign exchange forwards		—			0.1			14.4			4.5
		7.9			8.5			14.9			5.0
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			—			11.7			5.4
Natural gas purchases and sales		1.5			0.8			0.7			1.4
Heavy fuel oil purchases		—			—			20.5			12.6
Foreign exchange forwards		85.3			36.0			10.5			—
Physical natural gas purchases and sales		1.8			0.1			—			—
		88.6			36.9			43.4			19.4
HFT derivatives
Power swaps and physical contracts		150.8			138.1			118.5			74.1
Foreign exchange options		98.6			—			2.1			—
Natural gas swaps, futures, forwards, physical contracts		—			86.4			358.8			162.3
		249.4			224.5			479.4			236.4
Other derivatives
Foreign exchange forwards		92.1			—			—			—
		92.1			—			—			—
Total gross current derivatives		438.0			269.9			537.7			260.8
Impact of master netting agreements with intent to settle net or simultaneously		(188.5	)		(133.4	)		(188.5	)		(133.4	)
Total current derivatives		249.5			136.5			349.2			127.4
Long-term
Cash flow hedges
Power swaps		11.6			14.5			4.1			3.7
Foreign exchange forwards		0.3			—			27.2			10.5
		11.9			14.5			31.3			14.2
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			—			4.4			4.8
Heavy fuel oil purchases		—			—			16.6			12.9
Foreign exchange forwards		121.4			61.5			—			3.9
		121.4			61.5			21.0			21.6
HFT derivatives
Power swaps and physical contracts		12.9			18.5			28.2			22.2
Natural gas swaps, futures, forwards and physical contracts		72.3			31.7			62.6			53.6
Foreign exchange options		0.4			—			1.4			—
		85.6			50.2			92.2			75.8
Other derivatives
Interest rate swap		—			—			2.9			—
		—			—			2.9			—
Total gross long-term derivatives		218.9			126.2			147.4			111.6
Impact of master netting agreements with intent to settle net or simultaneously		(51.3	)		(34.2	)		(51.3	)		(34.2	)
Total long-term derivatives		167.6			92.0			96.1			77.4
Total derivatives	$	417.1		$	228.5		$	445.3		$	204.8

Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

39

Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table:

	Derivative Assets				Derivative Liabilities
As at	December 31				December 31
millions of Canadian dollars	2015		2014		2015		2014
Regulatory deferral	$	0.1	$	0.7	$	0.1	$	0.7
HFT derivatives		239.7		166.9		239.7		166.9
Total impact of master netting agreements with intent to settle net or simultaneously	$	239.8	$	167.6	$	239.8	$	167.6

Cash Flow Hedges

The Company enters into various derivatives designated as cash flow hedges. Emera enters into power swaps to limit Bear Swamp’s exposure to purchased power prices. Emera also enters into interest rate swaps to fix Bear Swamp’s cost of debt. The Company also enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.

As previously noted, the effective portion of the change in fair value of these derivatives is included in AOCI, until the hedged transactions are recognized in income. The ineffective portion is recognized in income of the period. The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:

For the	Year ended December 31
millions of Canadian dollars	2015									2014
	Power swaps			Interest rate swaps			Foreign exchange forwards			Power swaps		Interest rate swaps			Foreign exchange forwards
Unrealized gain (loss) in non-regulated fuel for generation and purchased power – ineffective portion	$	(0.1	)	$	—		$	—		$	2.7	$	—		$	—
Realized gain (loss) in non-regulated fuel for generation and purchased power		4.8			—			—			0.9		—			—
Realized gain (loss) in operating revenue – Regulated		—			—			(9.0	)		—		—			(3.7	)
Realized gain (loss) in income from equity investments		—			(0.6	)		—			—		(0.5	)		—
Realized gain (loss) in interest expense, net		—			—			—			—		(0.2	)		—
Total gains (losses) in Net income	$	4.7		$	(0.6	)	$	(9.0	)	$	3.6	$	(0.7	)	$	(3.7	)
As at	December 31
millions of Canadian dollars	2015									2014
	Power swaps			Interest rate swaps			Foreign exchange forwards			Power swaps		Interest rate swaps			Foreign exchange forwards
Total unrealized gain (loss) in AOCI – effective portion, net of tax	$	3.5		$	(1.1	)	$	(41.7	)	$	5.2	$	(1.4	)	$	(14.9	)

The Company expects $13.3 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

40

As at December 31, 2015, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:

millions	2016		2017		2018		2019		2020
Power swaps (megawatt hours (“MWh”)) purchases		0.3		0.3		0.3		0.3		0.3
Foreign exchange forwards (USD) sales	$	53.4	$	53.4	$	44.8	$	30.0	$	30.0
Foreign exchange forwards (EURO) purchases		—		2.6		—		—		—

Regulatory Deferral

As previously noted, NSPI and GBPC defer gains and losses on certain derivatives documented as economic hedges, including certain physical contracts that do not qualify for the NPNS exemption.

The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:

For the	Year ended December 31
millions of Canadian dollars	2015									2014
	Commodity swaps and forwards			Physical natural gas purchases and sales			Foreign exchange forwards			Commodity swaps and forwards			Physical natural gas purchases and sales			Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$	(24.0	)	$	—		$	(7.0	)	$	14.3		$	—		$	(4.6	)
Unrealized gain (loss) in regulatory liabilities		1.4			8.8			172.7			7.8			2.4			75.9
Realized (gain) loss in regulatory assets		(3.3	)		—			—			3.3			—			—
Realized (gain) loss in property, plant and equipment		—			—			(1.0	)		—			—			(0.1	)
Realized (gain) loss in inventory (1)		11.5			—			(43.9	)		4.3			—			(16.3	)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		(15.9	)		(7.1	)		(18.2	)		(9.7	)		(2.3	)		(5.7	)
Total change derivative instruments	$	(30.3	)	$	1.7		$	102.6		$	20.0		$	0.1		$	49.2

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable.

Commodity Swaps and Forwards

As at December 31, 2015, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:

	2016		2017		2018
millions	Purchases		Purchases		Purchases
Coal (metric tonnes)		0.3		0.7		0.7
Natural Gas (mmbtu)		3.2		—		—
Heavy fuel oil (bbls)		0.4		0.2		0.1

41

Foreign Exchange Swaps and Forwards

As at December 31, 2015, the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are expected to settle as outlined below:

	2016			2017			2018			2019
Fuel purchases exposure (millions of US dollars)	$	200.4		$	222.3		$	143.0		$	96.5
Weighted average rate		1.0257			1.0707			1.1053			1.1265
% of USD requirements		79	%		93	%		68	%		46	%

Held-for-Trading Derivatives

In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures to economically hedge those physical contracts. These derivatives are all considered HFT.

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:

For the millions of Canadian dollars	Year ended December 31
	2015			2014
Power swaps and physical contracts in non-regulated operating revenues	$	9.8		$	6.4
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		4.6			264.0
Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		(3.1	)		(5.2	)
Foreign exchange options in other income (expenses), net		(0.8	)		—
	$	10.5		$	265.2

As at December 31, 2015, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

millions	2016		2017		2018		2019		2020
Natural gas purchases (Mmbtu)		211.3		65.5		49.9		43.9		43.9
Natural gas sales (Mmbtu)		151.0		35.1		5.4		5.1		4.4
Power purchases (MWh)		1.6		0.6		0.6		0.6		0.6
Power sales (MWh)		2.7		—		—		—		—
Foreign exchange options (USD)	$	20.3	$	12.5	$	4.1		—		—
Foreign exchange forwards (EURO) purchases		—		—		0.2		—		—

Other Derivatives

The Company has recognized the following realized and unrealized gains (losses) with respect to cash flow hedges which documentation requirements have not been met:

For the millions of Canadian dollars	Year ended December 31
	2015					2014
	Interest rate swaps			Foreign exchange forwards		Interest rate swaps		Foreign exchange forwards
Unrealized gain (loss) in other income (expense)	$			$	92.1	$	—	$	—
Unrealized gain (loss) in interest expense, net		(2.9	)		—		—		—
Total gains (losses) in net income	$	(2.9	)	$	92.1	$	—	$	—

42

As at December 31, 2015, the Company had interest rate swaps in place for the $250 million non-revolving term credit facility in Brunswick Pipeline for interest payments until the debt matures in 2019.

As at December 31, 2015, the Company had a foreign exchange forwards in place for $1,121.7 million USD in 2016 to economically hedge the anticipated proceeds from the Debenture Offering for the pending TECO Energy acquisition.

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts.

The Company assesses the potential for credit losses on a regular basis, and where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.

As at December 31, 2015, the maximum exposure the Company has to credit risk is $901.0 million (2014 – $707.3 million), which includes accounts receivable net of collateral/deposits and assets related to derivatives.

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The total cash deposits/collateral on hand as at December 31, 2015 was $94.2 million (2014 – $55.3 million), which mitigates the Company’s maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

As at December 31, 2015, the Company had $83.2 million (2014 – $79.9 million) in financial assets, considered to be past due, which have been outstanding for an average 80.5 days. The fair value of these financial assets is $71.5 million (2014 – $70.3 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric revenue.

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Concentration Risk

The Company’s concentrations of risk consisted of the following:

As at	December 31, 2015					December 31, 2014
	millions of Canadian dollars		% of total exposure			millions of Canadian dollars		% of total exposure
Receivables, net
Regulated utilities
Residential	$	189.3		20	%	$	195.1		26	%
Commercial		102.4		10	%		104.1		14	%
Industrial		29.2		3	%		26.3		4	%
Other		52.8		5	%		39.7		5	%
		373.7		38	%		365.2		49	%
Trading group
Credit rating of A- or above		31.4		3	%		13.5		2	%
Credit rating of BBB- to BBB+		22.1		2	%		29.0		4	%
Not rated		30.8		3	%		44.8		6	%
		84.3		8	%		87.3		12	%
Other accounts receivable		120.1		12	%		61.7		8	%
		578.1		58	%		514.2		69	%
Derivative Instruments (current and long-term)
Credit rating of A- or above		340.1		34	%		203.2		27	%
Credit rating of BBB- to BBB+		69.4		7	%		14.1		2	%
Not rated		7.6		1	%		11.2		2	%
		417.1		42	%		228.5		31	%
	$	995.2		100	%	$	742.7		100	%

Cash Collateral

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”.

The Company’s cash collateral positions consisted of the following:

As at millions of Canadian dollars	December 31 2015		December 31 2014
Cash collateral provided to others	$	106.9	$	45.8
Cash collateral received from others		28.5		2.9

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt to fall below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at December 31, 2015, the total fair value of these derivatives, in a liability position, was $445.3 million (December 31, 2014 – $204.8 million). If the credit ratings of the Company were reduced below investment grade the full value of the net liability position could be required to be posted as collateral for these derivatives.

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16. FAIR VALUE MEASUREMENTS

The following tables set out the classification of the methodology used by the Company to fair value its derivatives:

As at	December 31, 2015
millions of Canadian dollars	Level 1			Level 2		Level 3			Total
Assets
Cash flow hedges
Power swaps	$	19.5		$	—	$	—		$	19.5
Foreign exchange forwards		—			0.3		—			0.3
		19.5			0.3		—			19.8
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			1.4		—			1.4
Foreign exchange forwards		—			206.7		—			206.7
Physical natural gas purchases and sales		—			—		1.8			1.8
		—			208.1		1.8			209.9
HFT derivatives
Power swaps and physical contracts		38.3			—		(7.8	)		30.5
Foreign exchange options		—			0.4		—			0.4
Natural gas swaps, futures, forwards, physical contracts and related transportation		(0.3	)		7.9		56.8			64.4
		38.0			8.3		49.0			95.3
Other derivatives
Foreign exchange forwards		—			92.1		—			92.1
		—			92.1		—			92.1
Total assets		57.5			308.8		50.8			417.1
Liabilities
Cash flow hedges
Power swaps		4.6			—		—			4.6
Foreign exchange forwards		—			41.6		—			41.6
		4.6			41.6		—			46.2
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			16.1		—			16.1
Heavy fuel oil purchases		—			37.1					37.1
Natural gas purchases and sales		0.6			—		—			0.6
Foreign exchange forwards					10.5		—			10.5
		0.6			63.7		—			64.3
HFT derivatives
Power swaps and physical contracts		15.2			—		(2.0	)		13.2
Foreign exchange options		—			3.5		—			3.5
Natural gas swaps, futures, forwards and physical contracts		14.4			22.0		278.8			315.2
		29.6			25.5		276.8			331.9
Other derivatives
Interest rate swap		—			2.9		—			2.9
		—			2.9		—			2.9
Total liabilities		34.8			133.7		276.8			445.3
Net assets (liabilities)	$	22.7		$	175.1	$	(226.0	)	$	(28.2	)

45

As at millions of Canadian dollars	December 31, 2014
	Level 1			Level 2		Level 3			Total
Assets
Cash flow hedges
Power swaps	$	14.2		$	—	$	8.7		$	22.9
Foreign exchange forwards		—			0.1		—			0.1
		14.2			0.1		8.7			23.0
Regulatory deferral
Commodity swaps and forwards
Natural gas purchases and sales		0.1			—		—			0.1
Foreign exchange forwards		—			97.5		—			97.5
Physical natural gas purchases and sales		—			—		0.1			0.1
		0.1			97.5		0.1			97.7
HFT derivatives
Power swaps and physical contracts		66.3			—		(3.4	)		62.9
Natural gas swaps, futures, forwards and physical contracts		(1.8	)		22.3		24.4			44.9
		64.5			22.3		21.0			107.8
Total assets		78.8			119.9		29.8			228.5
Liabilities
Cash flow hedges
Power swaps	$	1.0		$	—	$	3.2		$	4.2
Foreign exchange forwards		—			15.0		—			15.0
		1.0			15.0		3.2			19.2
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			10.2		—			10.2
Natural gas purchases and sales		0.7			—		—			0.7
Heavy fuel oil purchases		—			25.5		—			25.5
Foreign exchange forwards		—			3.9		—			3.9
		0.7			39.6		—			40.3
HFT derivatives
Power swaps and physical contracts		1.3			—		1.5			2.8
Natural gas swaps, futures, forwards and physical contracts		13.5			12.0		117.0			142.5
		14.8			12.0		118.5			145.3
Total liabilities		16.5			66.6		121.7			204.8
Net assets (liabilities)	$	62.3		$	53.3	$	(91.9	)	$	23.7

The change in the fair value of the Level 3 financial assets for the year ended December 31, 2015 was as follows:

	Regulatory Deferral			Cash Flow Hedges and HFT Derivatives
millions of Canadian dollars	Physical natural gas purchases and sales			Power			Natural gas		Total
Balance, January 1, 2015	$	0.1		$	5.3		$	24.4	$	29.8
Increase (reduction) in benefit included in regulated fuel for generation and purchased power		(7.1	)		—			—		(7.1	)
Increase (reduction) in benefit included in non-regulated fuel for generation and purchased power		—			—			—		—
Unrealized gains (losses) included in regulatory assets or liabilities		8.8			—			—		8.8
Total realized and unrealized gains (losses) included in non-regulated operating revenues		—			(8.8	)		32.4		23.6
Net transfers out of Level 3		—			(4.3	)		—		(4.3	)
Balance, December 31, 2015	$	1.8		$	(7.8	)	$	56.8	$	50.8

46

The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2015 was as follows:

	Regulatory Deferral		Cash Flow Hedges and HFT Derivatives
millions of Canadian dollars	Physical natural gas purchases and sales		Power			Natural gas		Total
Balance, January 1, 2015	$	—	$	4.7		$	117.0	$	121.7
Increase (reduction) in benefit included in regulated fuel for generation and purchased power		—		—			—		—
Increase (reduction) in benefit included in non-regulated fuel for generation and purchased power		—		—			—		—
Unrealized gains (losses) included in regulatory assets or liabilities		—		—			—		—
Total realized and unrealized gains (losses) included in non-regulated operating revenues		—		(2.3	)		161.8		159.5
Net transfers out of Level 3		—		(4.4	)		—		(4.4	)
Balance, December 31, 2015	$	—	$	(2.0	)	$	278.8	$	276.8

The Company evaluate the observable input of market data on a quarterly basis in order to determine if transfers between levels is appropriate. For the year ended December 31, 2015, transfer from Level 3 to Level 1 were a result of an increase in observable inputs.

Emera’s Enterprise Risk Management group is responsible for valuation policies, processes and the measurement of fair value. Fair value accounting rules provide a three level hierarchy that prioritizes the inputs used to measure fair value. When possible, determining fair value is based primarily on observable market inputs in active markets.

Contracts with quoted prices available in active markets and exchanges for identical assets or liabilities are classified as level 1 in the hierarchy. For those contracts whereby pricing inputs are either directly or indirectly observable through markets, exchanges or third party sources, but do not qualify as level 1, are classified as level 2 in the hierarchy. For a level 3 classification, the processes and methods of measurement for third-party pricing information and illiquid markets are developed with input and using the market knowledge of the trading operations within Emera and its affiliates.

Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives includes third-party-sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Where possible, Emera also sources multiple broker prices in an effort to evaluate and substantiate these unobservable inputs. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement.

47

The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:

As at	December 31, 2015
millions of Canadian dollars	Fair Value			Valuation Technique		Unobservable Input	Range		Weighted average
Assets
Regulatory deferral – Physical	$	1.8			Modelled pricing	Third-party pricing	$	5.15 - $6.21	$	5.72
natural gas purchases and sales						Probability of default		0.01%		0.01%
HFT derivatives –		(7.8	)		Modelled pricing	Third-party pricing	$	26.27 - $129.20	$	70.45
Power swaps and						Correlation factor		0.98% - 1.00%		0.99%
physical contracts						Probability of default		0.00% - 0.02%		0.00%
						Discount rate		0.00% - 0.15%		0.01%
HFT derivatives –		54.2			Modelled pricing	Third-party pricing	$	1.13 - $9.12	$	3.26
Natural gas swaps,						Probability of default		0.00% - 0.10%		0.01%
futures, forwards,						Discount rate		0.00% - 0.33%		0.04%
physical contracts		2.6			Modelled pricing	Third-party pricing	$	1.25 - $15.74	$	6.19
and related transportation						Basis adjustment		(0.06)% - 0.95%		0.68%
						Probability of default		0.00% - 0.09%		0.00%
						Discount rate		0.00% - 0.08%		0.00%
Total assets		50.8
Liabilities
HFT derivatives –	$	(2.0	)		Modelled pricing	Third-party pricing	$	26.27-$129.20	$	70.82
Power swaps and						Correlation factor		0.98%-1.00%		0.99%
physical contracts						Own credit risk		0.00%-0.02%		0.00%
						Discount rate		0.00%-0.15%		0.01%
HFT derivatives –		278.8			Modelled pricing	Third-party pricing	$	0.74- $10.59	$	5.58
Natural gas swaps, futures,						Probability of default		0.00%-0.03%		0.00%
forwards and physical contracts						Discount rate		0.00%-0.12%		0.01%
Total liabilities		276.8
Net assets (liabilities)	$	(226.0	)

48

As at	December 31, 2014
millions of Canadian dollars	Fair Value			Valuation Technique	Unobservable Input	Range		Weighted average
Assets
Cash flow hedges –	$	8.7		Modelled pricing	Third-party pricing	$	23.23 - $114.99	$	53.97
Power and gas swaps					Probability of default		0.05% - 0.06%		0.05%
					Discount rate		5.06% - 7.53%		6.06%
Regulatory deferral – Physical		0.1		Modelled pricing	Third-party pricing	$	9.52 - $12.94	$	9.52
natural gas purchases and sales					Probability of default		0.05%		0.05%
HFT derivatives –		(4.4	)	Modelled pricing	Third-party pricing	$	46.65 - $103.27	$	70.69
Power swaps and					Probability of default		0.06% - 0.06%		0.06%
physical contracts					Discount rate		0.00% - 4.15%		0.47%
		1.0		Modelled pricing	Third-party pricing	$	27.61 - $127.96	$	62.04
					Correlation factor		0.99% - 1.0%		0.99%
					Probability of default		0.04% - 0.39%		0.14%
					Discount rate		0.00% - 48.63%		11.87%
HFT derivatives –		24.4		Modelled pricing	Third-party pricing	$	1.19 - $11.36	$	5.56
Natural gas swaps,					Probability of default		0.01% - 2.26%		0.46%
futures, forwards and					Discount rate		0.00% - 67.72%		5.28%
Total assets		29.8
Liabilities
Cash flow hedges –	$	3.2		Modelled pricing	Third-party pricing	$	23.23 - $114.99	$	53.97
Power and gas swaps					Own credit risk		0.06% - 0.06%		0.06%
					Discount rate		5.06% - 7.53%		6.06%
HFT derivatives –		1.2		Modelled pricing	Third-party pricing	$	32.99 - $127.96	$	74.58
Power swaps and					Correlation factor		0.99% - 1.00%		0.99%
physical contracts					Own credit risk		0.06% - 0.06%		0.06%
					Discount rate		0.00% - 48.63%		15.37%
		0.3		Modelled pricing	Third-party pricing	$	46.45 - $103.27	$	70.69
					Own credit risk		0.06% - 0.06%		0.06%
					Discount rate		0.00% - 4.15%		0.47%
HFT derivatives –		117.0		Modelled pricing	Third-party pricing	$	1.60 - $14.13	$	3.81
Natural gas swaps,					Basis adjustment		(0.01)% - 0.66%		0.21%
futures, forwards and					Own credit risk		0.06% - 0.06%		0.06%
physical contracts					Discount rate		0.00% - 31.53%		3.52%
Total liabilities		121.7
Net assets (liabilities)	$	(91.9	)

The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following:

As at millions of Canadian dollars	December 31, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including current portion)	$	4,024.8	$	4,486.7	$	3,754.8	$	4,382.9

The fair values of long-term debt instruments, classified as level 3 in the fair value hierarchy, are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturity, without considering the effect of third party credit enhancements.

All other financial assets and liabilities, such as cash and cash equivalents, restricted cash, accounts receivable, short-term debt and accounts payable, are carried at cost. The carrying value approximates fair value due to the short-term nature of these financial instruments.

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17. REGULATORY ASSETS AND LIABILITIES

NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “Act”) and is subject to regulation under the Act by the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s target regulated return on equity (“ROE”) range for 2015 and 2014 was 8.75 per cent to 9.25 per cent based on an actual average regulated common equity component of up to 40 per cent. NSPI has a FAM, which enables it to seek recovery of Fuel Costs through regularly scheduled rate adjustments. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

On December 21, 2012, the UARB approved a General Rate Application (“GRA”) settlement agreement between NSPI and customer representatives which resulted in an average net rate increase of 3 per cent by customer class effective January 1, 2013 and January 1, 2014. To achieve the net 3 per cent increase in rates, the UARB approved a rate stabilization plan under which a portion of non-fuel costs from 2013 and 2014 could be deferred for future recovery. NSPI committed to $27.5 million in non-fuel cost savings over a two-year period beginning in fiscal 2013.

As at December 2014, NSPI had under recovered approximately $86.1 million in Fuel Costs. Pursuant to NSPI’s FAM Plan of Administration, this amount would be recovered commencing in 2015. On November 25, 2014, the UARB approved a settlement agreement that resulted in approximately $56.0 million of the 2014 outstanding FAM balance being collected in 2015. In addition, the UARB directed NSPI to transfer $38.2 million of the payable balance of the rate stabilization deferral account to reduce the FAM balance of $86.1 million, resulting in a revised balance of $47.9 million at December 31, 2014.

Through a related settlement agreement with stakeholders approved in December 2014, NSPI agreed to apply non-fuel revenues above that required to achieve its approved range of return to reduce the FAM deferral account. This was effective as of January 1, 2015, until the next GRA approval or similar process where non-fuel rates are adjusted. This settlement agreement required NSPI to contribute a minimum of $41.3 million to the FAM deferral account by the end of 2015.

As at December 31, 2015, NSPI had exceeded the minimum required contribution of $41.3 million through the $38.2 million contributed in 2014 referred to above and an additional $44.7 million applied in 2015. Of the $44.7 million applied in 2015, $18.3 million relates to changes to South Canoe and Sable Wind Projects tax treatment.

On December 21, 2015, the UARB approved NSPI’s setting of the 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as submitted in NSPI’s August and November 2015 filings. The recovery of these costs will begin January 1, 2016. The approved customer rates seek to recover $13.7 million of prior years’ unrecovered Fuel Costs in 2016 and the current FAM asset on the balance sheet. This results in a combined average rate decrease for customers of approximately 1 per cent.

The excess non-fuel revenues in 2015 include a benefit of $18.3 million which is the result of the changes to South Canoe and Sable Wind Projects tax treatments, as legislated by the Electricity Plan Act. The Electricity Plan Act also directs NSPI to apply sufficient 2015 excess non-fuel revenues, so as to offset 2016 fuel rate increases in certain classes. This amount totals $4.6 million and is included in the $13.7 million current FAM asset on the Consolidated Balance Sheets. The remaining 2015 excess non-fuel

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revenues of $40.1 million, plus interest, have been deferred for future periods beyond 2016, as further directed by the Electricity Plan Act and are classified as long-term FAM liability on the Consolidated Balance Sheets.

Emera Maine

Emera Maine’s core businesses are the transmission and distribution of electricity, with distribution operations and stranded cost recoveries regulated by the Maine Public Utilities Commission (“MPUC”). The transmission operations are regulated by the Federal Energy Regulatory Commission (“FERC”). The rates for these three elements are established in distinct regulatory proceedings.

Distribution Operations

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. Prior to July 1, 2014, the allowed ROE was 10.2 per cent, on a common equity component of 50 per cent.

On July 1, 2014, Emera Maine’s distribution rates increased by nine per cent, including the recovery, over five years, of approximately $5 million USD of costs associated with a major ice storm in Maine in late December 2013. Also, effective July 1, 2014, the allowed ROE became 9.55 per cent, on a common equity component of 49 per cent.

Transmission Operations

There are two transmission districts in Emera Maine, corresponding to the service territories of the two pre-merger entities.

Bangor Hydro District

Transmission rates for Bangor Hydro District’s (the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook) are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. The allowed ROE up to October 15, 2014, for these local transmission investments was 11.14 per cent. Effective October 16, 2014, the allowed ROE changed to 10.57 per cent, pending two outstanding complaints filed with the FERC to challenge the ISO-New England Open Access Transmission Tariff-allowed base ROE of 11.14 per cent. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015, transmission rates for the Bangor Hydro district increased by approximately 21 per cent in connection with its annual transmission formula rate filing (2014 – increased by 13 per cent). The increase is associated primarily with the under-recovery of prior year regional transmission revenues collected in local rates, as well as the recovery of increased transmission plant in service.

Bangor Hydro District’s bulk transmission assets are managed by ISO-New England (“ISO-NE”) as part of a region-wide pool of assets. ISO-NE manages the region’s bulk power generation and transmission systems and administers the open access transmission tariff. Currently, the Bangor Hydro District, along with all other participating transmission providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is based on prior year regionally funded transmission investments, adjusted for current year forecasted investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments ranged from 11.64 per cent to 12.64 per cent. Effective October 16, 2014, the transmission investments allowed ROE changed to a range from 11.07 per cent to 11.74 per cent, pending the two aforementioned complaints filed with FERC. The common equity component is based upon the prior calendar year average balances. The participating transmission providers are also required to contribute to the cost of service of such

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transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent.

On June 1, 2015, Bangor District’s regionally recoverable transmission investments and expenses decreased by 6 per cent (2014 – increased by 7 per cent).

MPS District

Local transmission rates for MPS District’s (the franchise electric service territory associated with the former Maine Public Service Company in northern Maine) are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted investments. The current allowed ROE for transmission operations is 10.2 per cent. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015 the transmission rates for the Maine Public Service district decreased by approximately 24 per cent for wholesale customers (2014 -increased by 2 per cent) and on July 1, 2015 decreased by 22 per cent for retail customers (2014—increased by 11 per cent) in connection with its annual transmission formula rate filing. These decreases were primarily due to an increase in wholesale transmission revenue that allows for a decrease in local customer transmission rates.

The MPS District electric service territory is not connected to the New England bulk power system and it is not a member of ISO-NE. MPS District is not a party to the previously discussed ROE complaints at the FERC.

Stranded Cost Recoveries

Stranded cost recoveries in Maine are set by the MPUC. Electric utilities are permitted to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC. Unlike transmission and distribution operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through rates. Generally, regulatory rates to recover stranded costs are set every three years, determined under a traditional cost-of-service approach and are fully recoverable. Each year on July 1, stranded cost rates in the Bangor District are adjusted to reflect recovery of cost deferrals for the prior stranded costs rate year under the full recovery mechanism, as well as factor in any new stranded cost information.

Bangor District

Bangor District’s net regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract and deferrals associated with reconciling stranded costs. These net regulatory assets total approximately $19.7 million as at December 31, 2015 (2014 – $25.1 million) or 1.8 per cent of Emera Maine’s net asset base (2014 – 2.3 per cent).

On July 1, 2014, the Bangor District stranded cost rates decreased by 10 per cent. Earlier, on March 1, 2014, stranded costs rates had increased by 20 per cent. The allowed ROE used in setting the new rates on July 1, 2014, and March 1, 2014, was 5.9 per cent, with a common equity component of 48 per cent. This July 1, 2014 rate decrease remained in effect for all of 2015 and there was no rate change on July 1, 2015.

While the stranded cost revenue requirements differ throughout the period due to changes in annual stranded costs, the actual annual stranded cost revenues are the same during the period. To stabilize the impact of the varying revenue requirements, cost or revenue deferrals are recorded as a regulatory asset or liability, and addressed in subsequent stranded cost rate proceedings, where customer rates are adjusted accordingly.

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MPS District

Effective January 1, 2015, the stranded cost rates for the Maine Public Service district decreased by approximately 150 per cent. This was principally due to the flow-back to customers of certain benefits received by Emera Maine from Maine Yankee associated with litigation with the United States Department of Energy on nuclear waste disposal. The allowed ROE used in setting the new rates on January 1, 2015 was 6.75 per cent, with a common equity component of 48 per cent. The reduced stranded cost revenues are offset by reductions in expense and do not affect earnings. This January 1, 2015, rate decrease remained in effect for all of 2015 and there was no rate change on July 1, 2015.

The Barbados Light & Power Company Limited

BLPC is a vertically integrated utility and provider of electricity on the island of Barbados.

BLPC is subject to regulation under the Utilities Regulation (Procedural) Rules 2003 by Fair Trading Commission (“The Rules”), Barbados, an independent regulator. The Rules give the Fair Trading Commission, Barbados utility regulation functions, which include establishing principles for arriving at rates to be charged, monitoring the rates charged to ensure compliance, and setting the maximum rates for regulated utility services. The government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028.

BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. BLPC’s approved regulated return on rate base for 2015 and 2014 was 10 per cent.

All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The Fair Trading Commission, Barbados has approved the calculation of the fuel charge, which is adjusted on a monthly basis.

Dominica Electricity Services Ltd

Domlec is an integrated utility on the island of Dominica and is regulated by the Independent Regulatory Commission, Dominica

On October 7, 2013, the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014, for a period of 25 years. Domlec’s approved allowable regulated return on rate base for 2015 and 2014 was 15 per cent.

Domlec fuel costs are passed to customers through a fuel pass-through mechanism which provides the opportunity to recover substantially all fuel costs in a timely manner.

Grand Bahama Power Company Limited

GBPC is a vertically integrated utility and sole provider of electricity on Grand Bahama Island. The Grand Bahama Port Authority (“GBPA”) regulates the utility and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policy to ensure that fuel costs are recovered and a reasonable return earned. GBPC’s approved regulated return on rate base for 2015 and 2014 was 10 per cent.

For the years ended December 31, 2015 and 2014, all GBPC fuel costs are passed to customers through a fuel pass-through mechanism which provides the opportunity to recover substantially all fuel costs in a timely manner.

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Brunswick Pipeline

Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Canaport™ re-gasified liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25-year firm service agreement commencing in July 2009 with Repsol Energy Canada. The pipeline is considered a Group II pipeline regulated by the National Energy Board (“NEB”). The NEB Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the NEB Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.

Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable of recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory precedent set for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income.

Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.

Regulatory assets and liabilities consisted of the following:

As at millions of Canadian dollars	December 31 2015		December 31 2014
Regulatory assets
Deferred income tax regulatory assets	$	431.3	$	340.1
Deferrals related to derivative instruments		67.7		45.6
Unamortized defeasance costs		45.7		52.5
Demand side management deferral (note 5)		36.4		—
Stranded cost recovery		28.5		24.9
Fuel adjustment mechanism (note 5)		13.7		47.9
Pension and post-retirement medical plan		11.9		10.4
Hydro-Quebec Obligation		7.6		6.8
Stranded cost revenue & purchase power reconciliation deferrals		6.1		8.0
2014 Maine storm		6.1		5.3
Purchase power contracts		5.9		7.0
Large industrial customers fixed cost deferral (note 5)		—		15.8
Other		38.6		38.4
	$	699.5	$	602.7
Current	$	94.2	$	115.0
Long-term		605.3		487.7
Total regulatory assets	$	699.5	$	602.7
Regulatory liabilities
Deferrals related to derivative instruments	$	209.9	$	97.7
Self-Insurance Fund		86.8		72.8
Fuel adjustment mechanism (note 5)		42.0		—
Deferred income tax regulatory liabilities		17.6		17.7
Other		14.3		13.7
	$	370.6	$	201.9
Current	$	98.9	$	43.0
Long-term		271.7		158.9
Total regulatory liabilities	$	370.6	$	201.9

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Deferred Income Tax Regulatory Asset and Liability

To the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator.

Deferrals Related to Derivative Instruments

NSPI and GBPC defers changes in fair value of derivatives that are documented as economic hedges or that do not qualify for normal purchase normal sale (“NPNS”) exemption, as a regulatory asset or liability. The realized gain or loss is recognized when the hedged item settles in fuel for generation and purchased power or inventory, depending on the nature of the item being economically hedged.

Unamortized Defeasance Costs

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities held in trust that provide the principal and interest streams to match the related defeased debt, which as at December 31, 2015, totaled $0.8 billion (2014 – $0.7 billion). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amortized over the life of the defeased debt as approved by the UARB.

2015 DSM Deferral

As discussed in Note 5, following the new energy efficiency legislation, the UARB approved the implementation of the 2015 DSM deferral set at $35 million for 2015 and recoverable from customers over an eight year period beginning in 2016. The change in the 2015 DSM regulatory asset balance for the year ended December 31 consisted of the following:

millions of Canadian dollars	2015
DSM regulatory asset – Balance as at January 1	$	—
Current period Program Costs		35.0
Interest on DSM balance		1.4
DSM regulatory asset – Balance as at December 31	$	36.4

Stranded Cost Recovery

Due to the decommissioning of a steam turbine in GBPC during 2012, the GBPA approved the recovery of a $21.4 million USD stranded cost through future electricity rates. These amounts are scheduled to be recovered beginning January 1, 2016.

Fuel Adjustment Mechanism

As discussed in Note 5, the UARB approved the implementation of a FAM for NSPI effective January 1, 2009. The change in the FAM balance for the years ended December 31 consisted of the following:

millions of Canadian dollars	2015			2014
FAM regulatory asset – Balance as at January 1	$	47.9		$	86.4
Under (over) recovery of current year Fuel Costs		24.1			(1.3	)
Rebate to (recovery from) customers of prior years’ Fuel Costs		(56.0	)		—
FAM audit disallowance, including interest adjustment		—			(6.0	)
Application of non-fuel revenues		(44.7	)		(38.2	)
Interest on FAM balance		0.4			7.0
FAM regulatory asset (liability) – Balance as at December 31	$	(28.3	)	$	47.9

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Details of the changes are discussed further in note 5. The FAM balance is recorded on the balance sheet as a current FAM asset of $13.7 million, to be recovered in 2016 and a long-term FAM liability of $42.0 million to be applied during 2017 through 2019 as legislated.

Pension and Post-Retirement Medical Plan

As a result of purchase accounting, all unrecognized actuarial gains and losses, prior service cost, and the net transition asset/liability associated with the pension and post-retirement medical benefit plans were eliminated as a result of the Bangor Hydro Electric Company and Maine Public Service Company mergers. As a result, a regulatory asset of $30 million, equal to these unrecognized amounts, was established at the merger dates. Emera Maine is amortizing the regulatory asset balance over the same period at which the corresponding gains and losses were being amortized when they were a component of pension and post-retirement benefit expense.

Hydro-Quebec Obligation

The obligation associated with Hydro-Quebec represents the estimated present value of Emera Maine’s estimated future payments for net costs associated with ownership and operation of the Hydro-Quebec intertie between the New England utilities and Hydro-Quebec. The obligation has been recognized in other liabilities and the MPUC has permitted recovery of this obligation. The regulatory asset and obligation are being reduced as expenses are incurred, with the reduction of the regulatory asset amortized to purchase power expense.

Stranded Cost Revenue & Purchased Power Reconciliation Deferral

Emera Maine has full recovery of stranded cost revenues and expenses, with deferral of variances between actual amounts and those used to set rates. Stranded cost rates are adjusted periodically to recover these cost deferrals.

2014 Maine Storm

In early November 2014, Emera Maine experienced a major storm in its service territory, with over one-third of the Company’s customers experiencing power outages at the peak of storm. Due to the volume of power outages and significant damage to the electrical system, numerous external resources were utilized to assist with the restoration of electrical service. The total incremental costs associated with the service restoration during the storm event amounted to approximately $5.3 million ($4.6 million USD), and the Company has recorded this amount as a regulatory asset on its consolidated balance sheets as of December 31, 2014. During Q2 2015, the Company made a request to the MPUC for a $5.4 million USD recovery of costs associated with this storm, as well as two other major storms that were expensed in 2014. In June 2015, Emera Maine reached agreement with the MPUC to recover $4.1 million USD of the $5.4 million USD being sought. Emera Maine is recording carrying costs on this deferral retroactive to January 1, 2015 and going forward until the $4.1 million USD is included in rates. The difference between $5.4 million USD originally requested for approval and the $4.1 million USD approved by the MPUC was expensed in Q2 2015.

Purchase Power Contracts

Emera Maine has power purchase contracts, which it was required to negotiate when oil prices were high, with several independent power producers. Bangor Hydro Electric Company attempted to alleviate the adverse impact of these high-cost contracts and in doing so incurred costs to restructure certain of the contracts. The MPUC has allowed Emera Maine to defer these costs and recover them in stranded cost rates. The contract restructuring costs are being recovered over a 20-year period ending in June 2018. In 2011, Bangor Hydro Electric Company entered into a 20-year power purchase contract with a 60-MW wind farm to purchase 20 per cent of the energy generated. Also in 2011, Bangor Hydro Electric Company entered into a 20-year power purchase contract with a 1-MW biomass generator to purchase

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100 per cent of the energy generated. As with the Company’s other power purchase contracts, the MPUC has allowed Bangor Hydro Electric Company full cost recovery for these contracts.

Large Industrial Customers Fixed Cost Deferral

The UARB approved a FCR for 2012 to address uncertainty associated with the operations of two large industrial customers who experienced financial challenges and idled their mills. Where actual sales to these customers in 2012 was less than expected when rates were set, the resultant shortfall in contribution toward non-fuel costs was deferred as a regulatory asset for future recovery. The 2013 GRA settlement agreement, approved on December 21, 2012 by the UARB, allowed recovery of this deferral from customers over a three-year period commencing January 1, 2013.

The change in the large industrial customers regulatory asset balance for the years ended December 31 consisted of the following table:

millions of Canadian dollars	2015			2014
Large industrial customers regulatory asset – Balance as at January 1	$	15.8		$	33.0
Recovery of regulatory asset recorded as regulatory amortization		(16.4	)		(19.1	)
Interest on large industrial customers FCR balance		0.6			1.9
Large industrial customers regulatory asset – Balance as at December 31	$	—		$	15.8

Self-Insurance Fund

ECI has established a SIF primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF, for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that in substance the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF Fund assets by the Company would be subject to existing regulations.

18. RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues, with an offset to property, plant and equipment, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction. 2014 balances have been retrospectively restated, consistent with this approach. Below are transactions between Emera and its associated companies reported in the Consolidated Statements of Income:

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For the millions of Canadian dollars			Year ended December 31
			2015			2014
	Nature of Service	Presentation
Sales to:
APUC subsidiary	Net sale of natural gas and transportation	Operating revenue – non-regulated	$	3.0		$	4.4
NWP	Energy management services	Operating revenue – regulated		0.3			1.1
Purchases from:
M&NP	Natural gas transportation capacity	Regulated fuel for generation and purchased power		4.5			3.6
M&NP	Natural gas transportation capacity	Operating revenue – non-regulated		(23.4	)		(23.8	)
NWP	Purchase of power	Regulated fuel for generation and purchased power	$	0.3		$	1.9

Operating revenue – non-regulated includes intercompany profit relating to the sale of natural gas, sale of power, construction, operations management and engineering services, and hedging services to rate-regulated subsidiaries of Emera totaling $1.6 million for the year ended December 31, 2015 (2014 – $4.2 million).

Amounts reported on Emera’s Consolidated Balance Sheets due (to) from its equity investments are summarized in the following table:

As at millions of Canadian dollars	December 31 2015			December 31 2014
Due from related parties:
Subsidiary of APUC – current (1)	$	0.7		$	—
NSPML – current		1.6			3.5
M&NP – loan receivable – long-term		2.5			2.5
Due to related parties:
M&NP – current		(2.1	)		(1.6	)
Net due from (to) related parties	$	2.7		$	4.4

(1) Amount due from a subsidiary of APUC is included in accounts receivable.

All amounts are under normal interest and credit terms, except for a loan receivable from M&NP bearing interest at 1 per cent per annum maturing on November 30, 2019.

19. OTHER CURRENT ASSETS

Other current assets consisted of the following:

As at millions of Canadian dollars	December 31 2015		December 31 2014
Net investment in direct financing lease	$	5.4	$	5.1
Dividend receivable		6.7		5.0
Capitalized transportation capacity (1)		222.7		70.5
	$	234.8	$	80.6

(1) Capitalized transportation capacity represents the value of transportation received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

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20. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following regulated and non-regulated assets:

As at millions of Canadian dollars	Estimated useful life		December 31 2015			December 31 2014
Generation		3 to 131	$	4,957.0		$	4,415.5
Transmission		10 to 65		1,508.2			1,331.1
Distribution		11 to 80		2,461.7			2,182.9
General plant and other		5 to 57		786.9			722.5
Total cost				9,713.8			8,652.0
Less: Accumulated depreciation				(3,732.4	)		(3,362.0	)
				5,981.4			5,290.0
Construction work in progress				206.6			320.2
Net book value			$	6,188.0		$	5,610.2

For the year ended December 31, 2015, AFUDC of $6.6 million (2014 – $12.0 million) was capitalized to “Property, plant and equipment”.

As a result of regulator-approved accounting policies and depreciation rates, NSPI, Emera Maine and GBPC defer certain costs within “Property, plant and equipment” that would not otherwise be deferred in the absence of rate regulation. Cumulative differences between items recognized for rate regulatory purposes and applicable USGAAP accounting standards including depreciation rates, AFUDC and overhead costs, cannot be separately determined. Cumulative deferred accretion expense related to AROs was $7.9 million as at December 31, 2015 (2014 – $10.3 million).

21. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees; and plans providing non-pension benefits for its retirees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Maine, Connecticut, Rhode Island, Barbados, Dominica and Grand Bahama Island.

Effective April 1, 2015, Emera Maine amended certain post-retirement medical benefits which resulted in a reduction in the pension and post-retirement benefits liability.

Benefit Obligation and Plan Assets

The changes in benefit obligation and plan assets, and the funded status for all plans were as follows:

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For the	Years ended December 31
millions of Canadian dollars	2015						2014
Change in Projected Benefit Obligation and Accumulated Post-retirement Benefit Obligation	Defined benefit pension plans			Non-pension benefit plans			Defined benefit pension plans			Non-pension benefit plans
Balance, January 1	$	1,469.7		$	101.9		$	1,253.3		$	86.0
Service cost		22.1			2.8			17.1			2.8
Plan participant contributions		7.9			0.3			7.5			0.1
Interest cost		58.7			3.5			61.7			4.2
Plan amendments		—			(26.7	)		—			—
Benefits paid		(61.0	)		(5.8	)		(60.0	)		(4.9	)
Actuarial losses		(15.4	)		1.1			175.1			8.7
Special termination		—			—			(0.1	)		—
Foreign currency translation adjustment		37.7			10.4			15.1			5.0
Balance, December 31		1,519.7			87.5			1,469.7			101.9
Change in Plan assets
Balance, January 1		1,204.7			4.6			1,070.0			4.0
Employer contributions		23.0			5.6			52.9			4.8
Plan participant contributions		8.3			—			7.5			—
Benefits paid		(61.0	)		(5.6	)		(60.0	)		(4.8	)
Actual return on assets, net of expenses		96.3			(0.1	)		122.8			0.2
Foreign currency translation adjustment		29.1			0.9			11.5			0.4
Balance, December 31		1,300.4			5.4			1,204.7			4.6
Funded Status, end of year	$	(219.3	)	$	(82.1	)	$	(265.0	)	$	(97.3	)

As at December 31, the aggregate financial position for all pension plans where the Projected Benefit Obligation (PBO) or, for post-retirement benefit plans, the Accumulated Post-retirement Benefit Obligation (APBO), exceeds the plan assets was as follows:

Plans with PBO/APBO in excess of Plan assets
	2015						2014
millions of Canadian dollars	Defined benefit pension plans			Non-pension benefit plans			Defined benefit pension plans			Non-pension benefit plans
PBO/APBO	$	1,489.4		$	87.5		$	1,437.9		$	101.9
Fair value of Plan Assets		1,261.3			5.4			1,167.0			4.6
Funded Status	$	(228.1	)	$	(82.1	)	$	(270.9	)	$	(97.3	)

The Accumulated Benefit Obligation (“ABO”) for the defined benefit pension plans was $1,426.5 million as at December 31, 2015 (2014 – $1,404.8 million). As at December 31, the aggregate financial position for those plans with an ABO in excess of the Plan assets was as follows:

Plans with ABO in excess of Plan assets
	2015			2014
millions of Canadian dollars	Defined benefit pension plans			Defined benefit pension plans
ABO	$	1,424.1		$	1,373.8
Fair value of Plan Assets		1,261.3			1,167.0
Funded Status	$	(162.8	)	$	(206.8	)

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Balance Sheet

The amounts recognized in the Consolidated Balance Sheets as at December 31 consisted of the following:

	2015						2014
millions of Canadian dollars	Defined benefit pension plans			Non-pension benefit plans			Defined benefit pension plans			Non-pension benefit plans
Current liabilities	$	(3.9	)	$	(3.1	)	$	(3.6	)	$	(3.9	)
Long-term liabilities		(224.4	)		(79.0	)		(267.3	)		(93.4	)
Other asset (noncurrent)		8.7			—			5.9			—
Amount included in deferred tax asset		20.6			(3.2	)		22.8			4.1
AOCI after tax adjustment		328.6			(9.2	)		420.4			6.3
Net amount recognized at end of year	$	129.6		$	(94.5	)	$	178.2		$	(86.9	)

Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI. The following tables provide detail on the change in AOCI during fiscal 2015 relating to these items; and the composition of the year-end balance:

Accumulated Other Comprehensive Loss millions of Canadian dollars	Actuarial losses (gains)			Past service (gains) costs
Defined Benefit Pension Plans
Balance, January 1	$	447.7		$	(4.5	)
Amortized in current period		(47.5	)		0.8
Current year addition to AOCI		(47.0	)		—
Transfer to other regulatory asset (1)		(0.1	)		—
Foreign currency translation adjustment		(0.2	)		—
Balance, December 31	$	352.9		$	(3.7	)
Non-pension benefits plans
Balance, January 1	$	16.8		$	(6.5	)
Amortized in current period		(1.6	)		6.3
Current year addition to AOCI		1.3			(27.1	)
Transfer to other regulatory asset (1)		(0.1	)		(1.5	)
Foreign currency translation adjustment		(1.4	)		1.4
Balance, December 31	$	15.0		$	(27.4	)

(1) For Emera Maine, as a result of regulatory accounting, any gain or loss is transferred to regulatory assets and amortized over the same period as the corresponding actuarial gains or losses.

	2015						2014
Accumulated Other Comprehensive Loss millions of Canadian dollars	Defined benefit pension plans			Non-pension benefit plans			Defined benefit pension plans			Non-pension benefit plans
Actuarial losses	$	352.9		$	15.0		$	447.7		$	16.9
Past service (gains)		(3.7	)		(27.4	)		(4.5	)		(6.5	)
Total AOCI on a pre-tax basis		349.2			(12.4	)		443.2			10.4
Less: Amount included in deferred tax asset		(20.6	)		3.2			(22.8	)		(4.1	)
Net amount in AOCI after tax adjustment	$	328.6		$	(9.2	)	$	420.4		$	6.3

The amounts in the foregoing table were not recognized in Emera’s net periodic benefit cost as at December 31.

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Benefit Cost Components	2015						2014
millions of Canadian dollars	Defined benefit pension plans			Non-pension benefit plans			Defined benefit pension plans			Non-pension benefit plans
Service cost	$	22.1		$	2.8		$	17.1		$	2.8
Interest cost		58.7			3.5			61.7			4.2
Expected return on plan assets		(64.6	)		(0.3	)		(63.2	)		(0.2	)
Current year amortization of:
Actuarial losses		47.5			1.6			35.9			0.1
Past service costs (gains)		(0.8	)		(6.3	)		(0.8	)		(1.7	)
Special termination		—			—			(0.1	)		—
Total	$	62.9		$	1.3		$	50.6		$	5.2

The expected return on plan assets is determined based on the market-related value of plan assets of $1,088.7 million as at January 1, 2015 (2014 – $995.1 million), adjusted for interest on certain cash flows during the year. The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period.

Pension Plan Asset Allocations

Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a broad basket of investment and non-investment grade securities. Emera’s target asset allocation is as follows:

Canadian Pension Plans

Asset Class	Target Range at Market
Short-term securities		0%	to	5%
Fixed income		35%	to	50%
Equities:
Canadian		12%	to	22%
Non-Canadian (World)		36%	to	50%

Non-Canadian Pension Plans

Asset Class	Target Range at Market (weighted average)
Short-term securities		0%	to	10%
Fixed income		30%	to	50%
Equities:
US		24%	to	47%
Non-US		14%	to	26%

For Emera Maine, the investment of the Non-Canadian pension assets is overseen by the management team. For GBPC, the investment of Non-Canadian pension assets is overseen by GBPA.

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The fair values of investments as at December 31, 2015, by asset category, are as follows:

	December 31, 2015
millions of Canadian dollars	NAV		Level 1		Total		Percentage
Cash and cash equivalents			$	11.6	$	11.6		0.9%
Equity securities:
Canadian equity				189.8		189.8		14.6%
US equity				239.9		239.9		18.4%
Other equity				240.0		240.0		18.5%
Other investments measured at NAV	$	619.1		—		619.1		47.6%
Total	$	619.1	$	681.3	$	1,300.4		100.0%
	December 31, 2014
millions of Canadian dollars	NAV		Level 1		Total		Percentage
Cash and cash equivalents			$	6.3	$	6.3		0.5%
Equity securities:
Canadian equity				125.3		125.3		10.4%
US equity				234.5		234.5		19.5%
Other equity				234.5		234.5		19.5%
Other investments measured at NAV	$	604.1		—		604.1		50.1%
Total	$	604.1	$	600.6	$	1,204.7		100.0%

Refer to Note 1(Y), “Summary of Significant Accounting Policies – Fair Value Measurement,” for more information on the fair value hierarchy and inputs used to measure fair value. All investments were deemed Level 1 for the years ended December 31, 2015 and 2014.

Investments in Emera or NSPI

As at December 31, 2015 and 2014, the pension funds do not hold any material investments in Emera Incorporated or NSPI securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities.

Canadian Post-Retirement Benefit Plans

There are no assets set aside to pay for the Canadian post-retirement benefit plans. As is common in Canada, post-retirement health benefits are paid from general accounts as required.

US Post-Retirement Benefit Plans

Emera’s US subsidiaries currently provide certain post-retirement health care and life insurance benefits for employees retiring after age 55 who meet eligibility requirements. Post-retirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify plans in whole or in part at any time.

Emera Maine provides retiree medical benefits to certain groups of employees. The Company’s retiree medical expenses are incorporated into rate filings with its regulators and are recovered through its electric rates to customers.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (MMA) added prescription drug coverage to Medicare, with a 28 per cent tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. Emera’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The Company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit post-retirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.

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Emera’s target asset allocation for its US Post-Retirement Benefits Plan is as follows:

Asset Class	Target Range at Market (weighted average)
Short-term securities		10%	to	50%
Fixed income		0%	to	40%
Equities:
US		30%	to	60%
Non-US		0%	to	60%

The fair values of investments as at December 31, 2015, by asset category, are as follows:

	December 31,2015
millions of Canadian dollars	NAV		Level 1		Total		Percentage
Cash and cash equivalents			$	1.4	$	1.4		25.9%
Other investments measured at NAV	$	4.0				4.0		74.1%
Total	$	4.0	$	1.4	$	5.4		100.0%
	December 31, 2014
millions of Canadian dollars	NAV		Level 1		Total		Percentage
Cash and cash equivalents			$	1.2	$	1.2		26.1%
Other investments measured at NAV	$	3.4		—		3.4		73.9%
Total	$	3.4	$	1.2	$	4.6		100.0%

Refer to Note 1(X), “Summary of Significant Accounting Policies – Fair Value Measurement,” for more information on the fair value hierarchy and inputs used to measure fair value. All investments were deemed Level 1 for the years ended December 31, 2015 and 2014.

Investments in Emera or NSPI

As at December 31, 2015 and 2014, the assets related to the post-retirement benefit plans do not hold any material investments in Emera Incorporated or NSPI securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities.

Cash Flows

The following table shows the expected cash flows for defined benefit pension and other post-retirement benefit plans:

millions of Canadian dollars	Defined benefit pension plans		Non-pension benefit plans
Expected employer contributions
2016	$	19.7	$	5.6
Expected benefit payments
2016		65.5		5.6
2017		70.6		5.6
2018		75.1		6.1
2019		79.9		6.3
2020		85.2		6.7
2021 – 2025		488.1		35.9

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Assumptions

The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans:

	2015				2014
(weighted average assumptions)	Defined benefit pension plans		Non-pension benefit plans		Defined benefit pension plans		Non-pension benefit plans
Benefit obligation – December 31:
Discount rate		4.02%		4.04%		3.99%		3.98%
Rate of compensation increase		3.07%		3.50%		3.07%		3.50%
Health care trend – initial (next year)		—		5.50%		—		5.20%
– ultimate		—		4.20%		—		4.30%
– year ultimate reached		—		2020		—		2020
Benefit cost for year ended December 31:
Discount rate		3.99%		3.98%		4.99%		4.90%
Expected long-term return on plan assets		5.91%		—		6.36%		—
Rate of compensation increase		3.07%		3.50%		3.29%		3.50%
Health care trend – initial (current year)		—		5.90%		—		5.20%
– ultimate		—		4.30%		—		4.40%
– year ultimate reached		—		2020		—		2020

Figures shown are weighted averages. Actual assumptions used may differ by plan.

The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan.

The discount rate is based on high-quality long-term Canadian corporate bonds, with maturities matching the estimated cash flows from the pension plan

Sensitivity Analysis for Non-Pension Benefits Plans

The health care cost trend significantly influences the amounts presented for health care plans. An increase or decrease of one percentage point of the assumed health care cost trend would have had the following impact in 2015:

millions of Canadian dollars	Increase		Decrease
Service cost and interest cost	$	1.1	$	(1.0	)
Accumulated post-retirement benefit obligation, December 31		9.2		(7.5	)

Sensitivity Analysis for Defined Benefit Pension Plans

The impact on the 2015 benefit cost of a 25 basis point change (0.25 per cent) in the discount rate and asset return assumptions is as follows:

millions of Canadian dollars	Increase			Decrease
Discount rate assumption	$	(5.4	)	$	5.4
Asset rate assumption		(2.7	)		2.6

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Amounts to be Amortized in the Next Fiscal Year

The following table shows the amounts from the AOCI, which are expected to be recognized as part of the net periodic benefit cost in fiscal 2016:

	2016			2016
millions of Canadian dollars	Defined benefit pension plans			Non-pension benefit plans
Actuarial gains (losses)	$	(41.4	)	$	(2.2	)
Past service gains		0.7			8.7
Total	$	(40.7	)	$	6.5

Defined Contribution Plan

Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2015 was $9.0 million (2014 – $9.6 million).

22. NET INVESTMENT IN DIRECT FINANCING LEASE

Brunswick Pipeline commenced service on July 16, 2009, transporting re-gasified LNG for Repsol Energy Canada under a 25-year firm service agreement. The agreement meets the definition of a direct financing capital lease for accounting purposes. The net investment in direct financing lease consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. Net investment in direct financing lease consisted of the following:

As at millions of Canadian dollars	December 31 2015			December 31 2014
Total minimum lease payments to be received	$	1,201.6		$	1,263.2
Less: amounts representing estimated executory costs		(212.5	)		(222.1	)
Minimum lease payments receivable	$	989.1		$	1,041.1
Estimated residual value of leased property (unguaranteed)		183.0			183.0
Less: unearned finance lease income		(686.6	)		(734.5	)
Net investment in direct financing lease	$	485.5		$	489.6
Principal due within one year (included in “Other current assets”)		5.4			5.1
Net investment in direct financing lease – long-term	$	480.1		$	484.5

Future minimum lease payments to be received for the next five years:

For the	Year ended December 31
millions of Canadian dollars	2016			2017			2018			2019			2020
Minimum lease payments to be received	$	61.6		$	61.6		$	61.6		$	61.6		$	61.6
Less: amounts representing estimated executory costs		(9.8	)		(9.9	)		(10.1	)		(10.3	)		(10.5	)
Minimum lease payments receivable	$	51.8		$	51.7		$	51.5		$	51.3		$	51.1

23. AVAILABLE-FOR-SALE INVESTMENTS

The available-for-sale investments consist primarily of debt and equity investments held in trust on behalf of BLPC’s Self Insurance Fund (“SIF”) for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain of BLPC’s generating, transmission and distribution systems. Any withdrawal of SIF Fund assets by the Company would be subject to existing regulations.

In addition, there are debt and equity investments related to Emera Reinsurance Limited, for captive insurance purposes.

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Emera has classified these investments as available-for-sale and recorded all such investments at their fair market value as at December 31, 2015.

Available-for-sale financial assets measured at fair value include the following:

As at millions of Canadian dollars	NAV		Level 1		Level 2		Level 3		December 31 2015
Common shares	$	—	$	16.4	$	—	$	—	$	16.4
Corporate bonds, debentures, short and medium term notes				—		34.6		—		34.6
Government bonds				—		11.7		—		11.7
Other investments measured at NAV		53.3								53.3
	$	53.3	$	16.4	$	46.3	$	—	$	116.0
As at millions of Canadian dollars	NAV		Level 1		Level 2		Level 3		December 31 2014
Common shares	$		$	13.8	$	—	$	—	$	13.8
Corporate bonds, debentures, short and medium term notes				—		36.1		—		36.1
Government bonds				—		2.8		—		2.8
Other investments measured at NAV		31.7								31.7
	$	31.7	$	13.8	$	38.9	$	—	$	84.4

The fair value of financial instruments traded in active markets, and classified as level one, is based on quoted market prices at the balance sheet date. The quoted market price used for financial assets is the current bid price at the balance sheet date. Fair values within the level two category are determined through the use of quoted prices in active markets for similar assets, which in some cases, are adjusted for factors specific to the asset.

The change in available-for-sale assets is as follows:

As at millions of Canadian dollars	December 31 2015			December 31 2014
Balance, beginning of the year	$	84.4		$	74.2
Additions		34.5			30.3
Disposals		(16.5	)		(27.1	)
	$	102.4		$	77.4
Change in fair value
Realized (loss) gain recognized in income		—			(0.8	)
Gain (loss) recognized in other comprehensive income during the period		13.6			7.8
	$	13.6		$	7.0
Balance, end of the period	$	116.0		$	84.4

There were no impairment provisions for available-for-sale investments for the twelve months ended December 31, 2015 (2014 – nil).

The maturity profile of debt securities included in the available-for-sale assets is as follows:

As at millions of Canadian dollars	December 31 2015		December 31 2014
Maturity within 1 year	$	20.0	$	12.8
Maturity in 1-5 years		26.3		26.1
	$	46.3	$	38.9

The maximum exposure to credit risk at the reporting date is the carrying value of the debt securities. None of these financial instruments are either past due or impaired.

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24. GOODWILL

The change in goodwill for the years ended December 31 is due to the following:

millions of Canadian dollars	2015		2014
Balance, January 1	$	221.5	$	206.5
Impairment (1)		—		(3.3	)
Change in foreign exchange rate		42.6		18.3
Balance, December 31	$	264.1	$	221.5

(1) No goodwill impairment was recorded in 2015. Emera recorded a goodwill impairment charge of $3.3 million in “Operating, maintenance, and general” on the Consolidated Statements of Income during the fourth quarter of 2014. Emera determined that the operating environment, conditions and performance of the Newfoundland division of Emera Utility Services Inc. could no longer support the related goodwill balance.

25. OTHER LONG-TERM ASSETS

Other long-term assets consisted of the following:

As at millions of Canadian dollars	December 31 2015		December 31 2014
Subscription receipts (1)	$	—	$	111.7
Deferred debt financing (2)		70.8		23.0
Capitalized transportation capacity		38.7		31.8
Open Hydro investment		10.0		10.0
Equipment financing receivable		28.7		20.5
Other		18.1		8.3
	$	166.3	$	205.3

(1) In Q4 2015, Emera reclassified outstanding subscription receipts from “Other long-term assets” to Investments subject to significant influence as they became eligible for conversion into APUC common shares.

(2) As at December 31, 2015, the deferred debt financing asset includes $46.2 million related to the $2.185 billion in Debentures to finance a portion of the pending TECO Energy acquisition. The deferred debt financing costs related to the Debentures are being amortized over 10 years, the contractual term of the debentures, in Interest expense, net.

26. SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of the following:

millions of Canadian dollars	2015		Weighted- average interest rate			2014		Weighted- average interest rate
NSPI
Bank indebtedness		15.9		2.70	%		2.3		3.00	%
GBPC
Bank indebtedness		—		—			0.1		5.75	%
Emera Energy
Advances on the non-revolving credit facilities		—		—			255.2		1.36	%
Short-term debt	$	15.9				$	257.6

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The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:

millions of Canadian dollars	Maturity		2015		2014
GBPC – revolving credit facility		2016		18.0		15.1
Emera Energy – non-revolving credit facility (1)		2014		—		255.2
Total				18.0		270.3
Less:
Advances under revolving credit facilities				—		255.3
Use of available facilities				—		255.3
Available capacity under existing agreements			$	18.0	$	15.0

(1) Emera Energy’s non-revolving credit facility was repaid in 2015.

The weighted average interest rate on outstanding short-term debt at December 31, 2015 was 2.70 per cent (2014 – 1.40 per cent).

Credit Facilities

For the purpose of bridge financing for the pending acquisition of TECO Energy, on September 4, 2015, the Company secured an aggregate of US$6.5 billion non-revolving term credit facilities the (“Acquisition Credit Facilities”) from a syndicate of banks. The non-revolving term credit facilities are comprised of a US$4.3 billion debt bridge facility, repayable in full on the first anniversary following its advance, and a US$2.2 billion equity bridge facility repayable in full on the first anniversary following its advance.

Emera is required to effect reductions or make prepayments of the Acquisition Credit Facilities in an amount equal to the net cash proceeds from any common equity, preferred equity, bond or other debt offerings and any nonordinary course asset sales by Emera and its subsidiaries, subject to certain prescribed exceptions and certain other prescribed transactions. Net proceeds from any such offerings, including the net proceeds of the final instalment under the Offering, or from any such non-ordinary course asset sales or transactions, will be applied to permanently reduce the commitments of the lenders under the Acquisition Credit Facilities or to repay the Acquisition Credit Facilities after they are drawn. On October 16, 2015, Emera permanently reduced the USD bridge facilities in the amount of $588.3 million USD with the proceeds of the first instalment of the convertible debentures and the proceeds from the Bear Swamp financing.

The credit agreements pursuant to which the Acquisition Credit Facilities will be extended (the “Acquisition Credit Agreements”) will contain certain prepayment options in favour of Emera and certain prepayment obligations upon the occurrence of certain events. In particular, the net proceeds of any equity or debt offering by Emera and certain of its subsidiaries (other than certain permitted equity or debt offerings subject to certain prescribed exceptions) and of any non-ordinary course asset sales (subject to certain prescribed exceptions) and certain other prescribed transactions will be required to be used to prepay the Acquisition Credit Facilities and any prepayment under the Acquisition Credit Facilities may not be re-borrowed. The Acquisition Credit Agreements will contain customary representations and warranties and affirmative and negative covenants of Emera that will closely resemble those in Emera’s existing revolving credit facility.

Emera has recognized the costs associated with the bridge fees related to the Acquisition Credit Facilities in “Operating, maintenance and general” on Emera’s Consolidated Statements of Income.

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27. OTHER CURRENT LIABILITIES

Other current liabilities consisted of the following:

As at millions of Canadian dollars	December 31 2015		December 31 2014
Accrued charges	$	130.1	$	114.1
Accrued interest on long-term debt		44.1		42.4
Accrued interest on convertible debentures represented by instalment receipts		11.2		—
Emission credits obligations (1)		6.3		20.6
Sales taxes payable		4.2		5.6
Other		8.4		4.1
	$	204.3	$	186.8

(1) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are recorded as inventory (note 14) when purchased and subsequently applied against the emission liabilities at the end of each compliance period.

28. LONG-TERM DEBT

Emera’s long-term debt includes the issuances detailed below. Medium-term notes and debentures are issued under trust indentures at fixed interest rates and are unsecured unless noted below. Also included are certain bankers’ acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year. Long-term debt as at December 31 consisted of the following:

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millions of Canadian dollars	Stated Interest Rate (1)			Effective Interest Rate (2)			Maturity		2015		2014
Emera
Bankers acceptances, LIBOR loans (3)		—			2.00	%		2020	$	239.5	$	437.2
Medium-term notes
Series G		4.83	%		4.89	%		2019		225.0		225.0
Series H		2.96	%		3.05	%		2016		250.0		250.0
										475.0		475.0
Promissory note		—			—			2016		0.3		0.6
Capital lease obligations		—			—			Various		—		0.2
									$	714.8	$	913.0
NSPI
Commercial paper (4)		—			0.85	%		2020	$	369.3	$	349.1
Medium-term notes
Series F		8.85	%		8.21	%		2025		125.0		125.0
Series I		8.40	%		8.43	%		2015		—		70.0
Series L		8.30	%		8.88	%		2036		60.0		60.0
Series M (5)		8.50	%		7.76	%		2026		40.0		40.0
Series N		7.60	%		7.57	%		2097		50.0		50.0
Series P		6.28	%		6.28	%		2029		40.0		40.0
Series R		7.45	%		7.51	%		2031		75.0		75.0
Series S		6.95	%		7.12	%		2033		200.0		200.0
Series V		5.67	%		5.71	%		2035		150.0		150.0
Series W		5.95	%		6.01	%		2039		200.0		200.0
Series X		5.61	%		5.65	%		2040		300.0		300.0
Series Y		4.15	%		4.19	%		2042		250.0		250.0
Series Z		4.50	%		4.57	%		2043		300.0		300.0
Series AA		3.61	%		3.65	%		2045		175.0		—
										1,965.0		1,860.0
Debentures – Series 3		9.75	%		9.99	%		2019		95.0		95.0
Capital lease obligations		—			4.3% & 4.8	%		2016 & 2019		0.5		1.0
									$	2,429.8	$	2,305.1
Emera Maine (6)
LIBOR loans and demand loans (7)		—			1.71	%		2019	$	31.7	$	28.7
General & refunding mortgage bonds (8)
$20 million		8.98	%		8.98	%		2022		27.7		23.2
$30 million		10.25	%		10.25	%		2020		41.5		34.8
										69.2		58.0
Senior unsecured notes
$50 million (9)		5.31	%		5.31	%		2018		18.9		21.1
$20 million		5.87	%		5.87	%		2017		27.7		23.2
$110 million		4.34	%		4.34	%		2044		152.2		127.6
$70 million		3.61	%		3.61	%		2022		96.9		81.2
										295.7		253.1
									$	396.6	$	339.8
EBP
$250 million		3.08	%		3.08	%		2019	$	248.5	$	—
									$	248.5	$	—
GBPC (6)
Unsecured notes		3.44	%		3.44	%		2022	$	23.9	$	23.3
Unsecured notes		3.70	%		3.70	%		2021		52.5		50.6
Bond notes		6.96	%		6.96	%		2020		30.4		25.5
Bond notes		7.16	%		7.16	%		2023		38.8		32.5
									$	145.6	$	131.9

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BLPC & ECI
Senior secured notes
$19.2 million(10)	6.50	%	7.00	%	2021	$	10.8		$	10.1
$20 million(10)	6.65	%	6.65	%	2020		13.8			11.6
$20 million(10)	6.88	%	6.88	%	2025		13.8			11.6
$2.0 million(11)	5.99	%	5.99	%	2015		—			1.2
$7.1 million(6)(12)	2.37	%	2.37	%	2015		—			2.8
$10.1 million(6)(12)	4.31	%	4.31	%	2028		12.0			10.9
$50.5 million(13)	5.75	%	5.75	%	2021		16.2			15.7
$16.0 million(6)	4.50	%	4.58	%	2020		22.5			—
Other							0.3			0.5
						$	89.4		$	64.4
Adjustments
Unamortized debt premium – net							0.1			0.6
Amount due within one year							(274.0	)		(94.5	)
						$	(273.9	)	$	(93.9	)
Long-Term Debt						$	3,750.8		$	3,660.3

(1) The stated interest rate is the coupon rate for any long term debt issuance.

(2) The effective interest rate is the constant rate which will fully amortize the premium/discount and issuance costs over the life of the associated debt when the rate is applied against the net amount of debt less unamortized costs.

(3) Emera’s revolving credit facility matures in June 2020, at which point the Company has the intention to renew under similar terms. The credit facility can be extended annually with the approval of the syndicated banks.

(4) NSPI’s commercial paper is backed by a revolving credit facility, which matures in 2020.

(5) Note is extendable until 2056 at the option of the holders.

(6) Debt issued and payable in USD.

(7) Emera Maine’s revolving credit facility matures in September 2019, at which point the Company has the intention to renew under similar terms.

(8) Secured by property, plant and equipment of Emera Maine.

(9) Sinking fund payments began in 2008.

(10) Debt issued and payable in Barbadian dollars. Borrowings are secured under a Debenture Trust Deed, which creates a first and floating charge on the Company’s property, present and future.

(11) Debt issued and payable in USD. Borrowings are secured under a Debenture Trust Deed which creates a first and floating charge on the Company’s property, present and future.

(12) Cash security in the form of security deposit.

(13) Issued and payable in East Caribbean dollars. Fixed charge over property of Domlec.

The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:

millions of Canadian dollars	Maturity		2015		2014
Emera – revolving credit facility (1)		June 2020	$	700.0	$	700.0
NSPI – revolving credit facility (1)		October 2020		500.0		500.0
Emera Maine – revolving credit facility		September 2019		110.7		92.8
BLPC – revolving credit facility		2017-2021		26.3		22.0
Total				1,337.0		1,314.8
Less:
Borrowings under credit facilities				641.3		816.2
Letters of credit issued inside credit facilities				33.1		13.4
Use of available facilities				674.4		829.6
Available capacity under existing agreements			$	662.6	$	485.2

(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million.

Credit Facilities

NSPI

On April 30, 2015, NSPI completed the issuance of $175 million Series AA Medium-Term Notes (“MTN”). The Series AA notes bear interest at a rate of 3.612 per cent per annum until May 1, 2045. The proceeds of the note offering were used for general corporate purposes, including the repayment of maturing corporate term debt.

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NSPI Series I $70 million 8.40 per cent MTN matured on October 23, 2015.

Brunswick Pipeline

On February 18, 2015, Brunswick Pipeline completed a senior secured financing consisting of a $250 million non-revolving term credit facility bearing interest at bankers’ acceptances rates plus 1.75 per cent and expiring on February 18, 2019. The proceeds were used to reduce borrowings under Emera’s revolver, which was previously used to finance the maturity and repayment of a MTN note in October 2014.

Debt Covenants

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements. Emera’s significant covenants are listed below:

	Financial Covenant	Requirement	As at December 31, 2015
Emera
Syndicated credit facilities	Debt to capital ratio	Less than or equal to 0.70 to 1		0.51:1

Long-Term Debt Maturities

As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follows:

millions of Canadian dollars	2016		2017		2018		2019		2020		Greater than 5 years		Total
Emera	$	250.3	$	—	$	—	$	225.0	$	239.5	$	—	$	714.8
NSPI		0.3		0.1		0.1		95.0		369.3		1,965.0		2,429.8
EBP		—		—		—		248.5		—		—		248.5
Emera Maine		6.3		34.0		6.3		31.7		41.5		276.8		396.6
GBPC		11.8		11.8		11.8		11.8		42.2		56.2		145.6
BLPC		5.3		7.1		7.3		7.6		36.2		25.6		89.1
Total	$	274.0	$	53.0	$	25.5	$	619.6	$	728.7	$	2,323.6	$	4,024.4

29. ASSET RETIREMENT OBLIGATIONS

AROs mostly relate to the reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets may have additional ARO that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the fair value of any related ARO cannot be made.

The change in ARO for the years ended December 31 is as follows:

millions of Canadian dollars	2015			2014
Balance, January 1	$	106.2		$	98.6
Liabilities settled		(1.5	)		(1.4	)
Accretion included in depreciation expense		7.6			7.6
Accretion deferred to regulatory asset (included in property, plant and equipment)		(2.4	)		(2.4	)
Revisions in estimated cash flows		4.1			3.6
Change in foreign exchange rate		0.7			0.2
Balance, December 31	$	114.7		$	106.2

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As at December 31, 2015 and 2014, some of the Company’s transmission and distribution assets may have additional conditional ARO which are not recognized in the financial statements as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. Management will continue to monitor these obligations and a liability will be recognized in the period in which an amount becomes determinable.

30. CONVERTIBLE DEBENTURES REPRESENTED BY INSTALMENT RECEIPTS

To finance a portion of the pending acquisition of TECO Energy, Emera, through a direct wholly owned subsidiary (the “Selling Debentureholder”), on September 28, 2015, completed the sale of $1.9 billion aggregate principal amount of 4.0% convertible unsecured subordinated debentures, represented by instalment receipts (the “Debentures” or the “Debenture Offering”).

On October 2, 2015, in connection with the Debenture Offering, the underwriters fully exercised an over-allotment option and purchased an additional $285 million aggregate principal amount of Debentures at the Debenture Offering price. The sale of the additional Debentures brought the aggregate proceeds of the Debenture Offering to $2.185 billion, assuming payment of the final instalment.

The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which

$333 was paid on closing of the Debenture Offering and the remaining $667 (the “Final Instalment”) is payable on a date (“Final Instalment Date”) to be fixed following satisfaction of conditions precedent to the closing of the acquisition of TECO Energy.

Prior to the Final Instalment Date, the Debentures are represented by instalment receipts. The instalment receipts began trading on the Toronto Stock Exchange (“TSX”) on September 28, 2015 under the symbol “EMA.IR”. The Debentures will not be listed. The Debentures will mature on September 29, 2025 and bear interest at an annual rate of four per cent per $1,000 principal amount of Debentures until and including the Final Instalment Date, after which the interest rate will be 0 per cent. Based on the first instalment of $333 per $1,000 principal amount of Debentures, the effective annual yield to and including the Final Instalment Date is 12 per cent, and the effective annual yield thereafter is 0 per cent.

If the Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Debenture Offering, holders of Debentures who have paid the final instalment on or before the Final Instalment Date will be entitled to receive, on the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, an amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Debenture Offering had the Debentures remained outstanding and continued to accrue interest until and including such date (the “Make-Whole Payment”). No Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary of the closing of the Debenture Offering. Under the terms of the instalment receipt agreement, Emera agreed that until such time as the Debentures have been redeemed in accordance with the foregoing or the Final Instalment Date has occurred, the Company will at all times hold (on a consolidated basis) short-term USD investment grade securities or have cash on hand of not less than the aggregate amount of the first instalment paid on the closing of the Debenture Offering and the exercise of the over-allotment option, in the event of a mandatory redemption.

At the option of the holders and provided that payment of the Final Instalment has been made, each

Debenture will be convertible into common shares of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $41.85 per common share. This is a conversion rate of 23.8949 common shares per $1,000 principal amount of Debentures, subject to adjustment in certain events.

Prior to the Final Instalment Date, the Debentures may not be redeemed by the Company, except that Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions precedent to the

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closing of the acquisition of TECO Energy will not be satisfied; (ii) termination of the acquisition agreement; and (iii) April 24, 2017, if notice of the Final Instalment Date has not been given to holders on or before April 21, 2017. Upon any such redemption, the Company will pay for each Debenture: (i) $333 plus accrued and unpaid interest to the holder of the instalment receipt; and (ii) $667 to the Selling Debentureholder on behalf of the holder of the instalment receipt in satisfaction of the Final Instalment. In addition, after the Final Instalment Date, any Debentures not converted may be redeemed by Emera at a price equal to their principal amount plus any unpaid interest which accrued prior to and including the Final Instalment Date.

At maturity, Emera will repay the principal amount of any Debentures not converted and remaining outstanding in cash. Emera has the right to satisfy the obligation to repay the principal amount due in common shares, which will be valued at 95 per cent of the weighted-average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

The proceeds of the first instalment and the overallotment of the Debenture Offering were $727.6 million, or $681.4 million net of issue costs, and are held and invested in short-term USD investment grade securities. The convertible debentures represented by instalment receipts are classified as a current liability on the Consolidated Balance Sheets as the pending acquisition of TECO Energy is expected to close in fiscal 2016. The mark-to-market effect related to the translation of the US foreign currency to Canadian currency is recorded in income, but not reflected in adjusted net income.

The net proceeds of the final instalment payment of the Debenture Offering are expected to be, in aggregate, approximately $1.4 billion and will be used, together with the net proceeds of the first instalment payment, to finance, directly or indirectly, the pending acquisition of TECO Energy and other acquisition related costs. To mitigate the foreign currency translation risk associated with the final instalment Emera entered into USD denominated forward contracts, which are recorded on the Consolidated Balance Sheets. The mark-to-market effect on these hedges is reported in the income statement and impacts income, but is not reflected in adjusted income.

Approximately $22.1 million ($15.2 million after-tax) in interest expense associated with the Debentures was recognized in Q4 2015 and $22.7 million ($15.7 million after-tax) was incurred during fiscal 2015 (2014 – nil) (note 8).

31. OTHER LONG-TERM LIABILITIES

Other long-term liabilities consisted of the following:

As at	December 31		December 31
millions of Canadian dollars	2015		2014
Funds received in excess of equity investment(1)	$	225.0	$	20.8
Long-term service agreements		37.7		—
Hydro-Quebec obligation		7.6		6.8
Emission credits obligations(2)		6.3		—
Other		21.9		20.7
	$	298.5	$	48.3

(1) Emera has a 50 per cent investment in Bear Swamp. As at December 31, 2015 and 2014, the investment balance in Bear Swamp was a credit. The 2015 and 2014 balances have been restated. The credit investment balance is primarily a result of a $178.7 million distribution received in Q4 2015.

(2) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory (note 14) when purchased and subsequently applied against the emission liabilities at the end of each compliance period.

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32. COMMITMENTS AND CONTINGENCIES

A. Commitments

As at December 31, 2015, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures represented by instalment receipts, long-term debt and AROs) for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2016		2017		2018		2019		2020		Thereafter		Total
Purchased power (1)	$	221.7	$	235.0	$	208.6	$	203.1		199.4	$	2,462.8	$	3,530.6
Coal, biomass, oil and natural gas supply		150.2		82.1		12.2		—		—		—		244.5
DSM (2)		24.7		34.0		34.9		—		—		—		93.6
Transportation (3)		183.6		72.2		55.8		25.7		20.9		86.9		445.1
Long-term service agreements (4)		56.6		45.0		33.6		55.7		18.4		207.1		416.4
Capital projects		68.9		7.1		—		—		—		—		76.0
Equity investment commitments (5)		379.6		159.0		—		—		—		—		538.6
Leases and other (6)		12.6		11.6		9.5		8.9		7.5		27.5		77.6
	$	1,097.9	$	646.0	$	354.6	$	293.4	$	246.2	$	2,784.3	$	5,422.4

(1) Purchased power: annual requirement to purchase 20–100 per cent of electricity production from independent power producers over varying contract lengths up to 25 years.

(2) DSM: program is expected to continue however no amounts have been committed after 2018.

(3) Transportation: purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines.

(4) Long-term service agreements: maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(5) Emera has a commitment in connection with the Federal Loan Guarantee (“FLG”) to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction.

(6) Leases: operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

B. Legal Proceedings

Emera

Between September 16, 2015 and November 2, 2015, purported shareholders of TECO Energy filed twelve separate complaints styled as class action lawsuits in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida or the United States District Court for the Middle District of Florida (the “Merger Litigation”). Each complaint alleges, among other things, that the Board of Directors of TECO Energy breached its fiduciary duties in agreeing to the acquisition agreement and that Emera and/or Emera US Inc. aided and abetted such alleged breaches. The complaints seek to enjoin the merger pursuant to the acquisition agreement.

On November 17, 2015, TECO Energy, Emera, Emera US Inc. and the Board of Directors of TECO Energy entered into a memorandum of understanding with the shareholder plaintiffs to settle all of the Merger Litigation, subject to negotiation of a stipulation of settlement with the plaintiffs and to court approval. The memorandum of understanding provides for all claims against the defendants to be released in exchange for TECO Energy making certain additional disclosures to its shareholders related to the proposed merger (which have now been made).

There is no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.

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Emera Maine

On September 30, 2011, a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users filed a complaint with the Federal Energy Regulatory Commission (“FERC”) alleging that the 11.14 per cent base return on equity (“ROE”) under the ISO-New England (ISO-NE) Open Access Transmission Tariff (“OATT”) was unjust and unreasonable. On June 19, 2014, the FERC issued an order in connection with this complaint, changing the methodology used to set the ROE for transmission assets.

This change would lower the base transmission ROE to 10.57 per cent for the period of October 1, 2011 to December 31, 2012, subject to a further proceeding to finalize the determination of appropriate rates to be used in such calculation. The FERC decision would also lower the cap on the total ROE (inclusive of incentive adders) for transmission assets to 11.74 per cent. In an order issued on October 16, 2014, the FERC confirmed that the ROE set in its earlier order was appropriate. On March 3, 2015, in response to requests for rehearing from several parties, FERC affirmed its initial Order, setting of the base ROE of 10.57 per cent and capping the total ROE, including the effect of incentive adders, at 11.74 per cent. Notices of Appeal to the U.S. Court of Appeals for the DC Circuit were filed by New England Transmission Owners and the Complainants in the case on April 30, 2015. In Q2 2015, Emera Maine began processing the refunds to customers, based on a 10.57 per cent ROE. By court order dated August 20, 2015, the DC Court of Appeals decided to hold the appeal of this case in abeyance pending the outcome of the consolidated cases (“ENE Case” and “MA AG II Case”) discussed below.

On December 27, 2012, a second group of consumer advocates, including Environment Northeast, filed a complaint with the FERC on similar grounds, arguing that the 11.14 per cent base ROE under the OATT was unjust and unreasonable (“the ENE Case”). On June 19, 2014, the FERC issued an order in this second ROE case, finding in favour of the complainants and allowing the complaint to proceed. As a result, a new ROE will be calculated and set by the FERC. This complaint created a new 15-month refund period beginning January 1, 2013 through March 31, 2014.

On July 31, 2014, a group of state commissions, state public advocates and end users filed a third complaint with the FERC alleging the ROE earned on transmission investments is unjust and unreasonable and does not reflect current economic conditions (“the MA AG II Case”). Any potential refund arising from this third complaint will relate to the period from July 31, 2014 to September 30, 2015, and the outcome will set the ROE going forward from the date of decision.

On November 24, 2014, the FERC consolidated the ENE Case and MA AG II Case. A subsequent order by the FERC established a schedule for various procedural matters that turned the case over to an Administrative Law Judge in September 2015. Once that judge’s recommended decision is rendered, parties may file exceptions, and then the case is set for decision by the FERC. A decision is therefore not expected until Q1 2016 at the earliest.

Emera Maine has recorded a reserve of $6.9 million pre-tax ($5.0 million USD) (2014 – $8.5 million) for the base transmission ROE rate refund complaints for the period of October 1, 2011 to May 31, 2015. The reserves recorded for these complaints have been recorded as a component of Regulatory Liabilities on the Consolidated Balance Sheets, and the charges to earnings have been a reduction to Operating revenues – regulated on the Consolidated Statements of Income.

Other Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

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C. Environment

Emera’s activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste. Emera estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations will be approximately $43.2 million during fiscal 2015 and are estimated to be $63.9 million from 2016 through 2019. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 32A. The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions.

NSPI

NSPI is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters, primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI.

Conformance with legislative and NSPI internal requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed to December 31, 2015.

Emera Energy Emissions

The New England Gas Generating Facilities are subject to the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions and the Acid Rain Program for sulphur dioxide emissions. The New England Gas Generating Facilities emit approximately two million tons of carbon dioxide per year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions programs could adversely impact financial and operational performance.

Poly Chlorinated Bi-Phenol Transformers

In response to the Canadian Environmental Protection Act 1999, 2008 Poly Chlorinated Bi-Phenol (“PCB”) Regulations to phase out electrical equipment and liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other oil-filled electrical equipment on its system that do not meet the 2008 PCB Regulations Standard by the end of 2025. This also includes PCB contaminated pole mounted transformers. The combined total cost of these projects is estimated to be $40.1 million and, as at December 31, 2015, approximately $19.7 million (December 31, 2014 – $14.8 million) has been spent to date. NSPI has recognized an ARO of $15.0 million as at December 31, 2015 (December 31, 2014 – $11.8 million) associated with the PCB phase-out program.

D. Principal Risks and Uncertainties

In this section, Emera describes some of the principal risks management believes could materially affect Emera’s business, revenues, operating income, net income, net asset or liquidity or capital resources. The nature of risk is such that no list can be comprehensive, and other risks may arise, or risks not currently considered material may become material in the future.

Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach.

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Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments in a timely manner. As cost-of-service utilities with an obligation to serve, NSPI, Emera Maine, BLPC, GBPC and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs and investments can be recovered upon the respective regulator’s approval of the recovery in adjustments to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. In addition, the commercial and regulatory frameworks under which Emera and its subsidiaries operate can be impacted by significant shifts in government policy and changes in governments. Emera has certain investments subject to significant influence that are subject to regulatory risk and include: APUC, M&NP, NSPML, LIL and Lucelec.

During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these subsidiaries and their respective regulators determine whether to allow recovery and to adjust rates based upon the subsidiaries’ evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, fuel-related audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.

In November 2014, the Federal Energy Regulatory Commission (“FERC”) commenced an audit covering the 2013 and 2014 period of Bangor Hydro Electric Company’s (“BHE”) compliance with conditions established in FERC’s orders authorizing its acquisition of Maine Public Service Company (“MPS”), which occurred on January 1, 2014. These two predecessor companies formed Emera Maine. The final audit report was released in early January 2016. The findings in the audit report conclude that Emera Maine did not follow the prescribed methodology for the calculation of AFUDC during the audit period and Emera Maine had included, in rates, costs of the BHE and MPS merger prior to making the required filings. Emera Maine will fully comply with the recommendations in the audit report, including making the required filings for the merger costs and recalculating AFUDC for 2013 and 2014, as ordered, which resulted in an immaterial impact on the Company’s Consolidated Statements of Income.

Brunswick Pipeline entered into a 25-year firm service agreement with Repsol Energy Canada, which was filed with the NEB. The firm service agreement provides for predetermined toll increases after the fifth and fifteenth year of the contract. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the NEB on a complaint basis. Brunswick Pipeline is required to make copies of tariffs and supporting financial information readily available to interested persons. Persons who cannot resolve traffic, toll and tariff issues with Brunswick Pipeline may file a complaint with the NEB. In the absence of a complaint, the NEB does not normally undertake a detailed examination of Brunswick Pipeline’s tolls.

Changes in Environmental Legislation

Emera is subject to regulation by federal, provincial, state, regional and local authorities with regard to environmental matters; primarily related to its utility operations. This includes laws setting greenhouse gas emissions standards and air emissions standards. Emera is also subject to laws regarding the generation, storage, transportation, use and disposal of hazardous substances and materials.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera.

New emission reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to greenhouse gas emissions

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standards and air emissions standards could adversely affect Emera’s operations and financial performance. Stricter environmental laws and enforcement of such laws in the future could increase Emera’s exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments.

Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and with the objective of achieving full compliance with applicable laws, legislation and company policies and standards. Emera has implemented this policy through the development and application of environmental management systems in its operating subsidiaries. Comprehensive audit programs are also in place to regularly test compliance with such laws, policies and standards.

Commercial Relationships

The Company is exposed to commercial relationship risk in respect of its reliance on certain key partners, supplies and customers. The company manages its commercial relationship risk by monitoring credit risk, and monitoring of significant developments with its customers, partners and suppliers.

ENL

Emera and Nalcor Energy executed agreements pertaining to the development and transmission of hydroelectric power from Muskrat Falls in Labrador to the island of Newfoundland, the Province of Nova Scotia and through to New England. In exchange for the Company’s investment in the Maritime Link Project, estimated to be approximately $1.56 billion, Nalcor has agreed to provide 20 per cent of the output of the Muskrat Falls generating station.

Labour Risk

Certain Emera employees are subject to collective labour agreements; 49 per cent of the full-time and term employees within the Emera group of companies are represented by local unions.

Approximately 7 per cent of Emera’s work force is included in collective labour agreements which will expire within the next 12 months.

Interest Rate Risk

The Company utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. The Company seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.

For the Company’s regulated subsidiaries, the cost of debt is generally passed through to ratepayers. While regulatory ROE rates will generally and indirectly follow the direction of interest rates, regulatory ROE’s are likely to fall in times of reducing interest rates and raise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development initiatives.

The Company is subject to interest rate risk relating to certain sources of expected funds to effect the TECO Energy acquisition. Any movement in interest rates could affect the underlying cost of the instrument used to fund the acquisition. The Company may enter into interest rate hedging contracts to limit its exposure to fluctuations in interest rates.

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Commodity Prices and Foreign Exchange Rate Fluctuations

A substantial amount of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. Fuel contracts may be exposed to broader global conditions which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts. In addition, the adoption and implementation of FAMs in certain subsidiaries has further helped manage this risk. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs.

The Company enters into foreign exchange forward and swap contracts to limit exposure on foreign currency transactions such as fuel purchases and USD revenue streams.

The cash consideration for the TECO Energy acquisition is required to be paid in US dollars, a portion of which will be raised in Canadian dollars. As a result, increases in the value of the US dollar versus the Canadian dollar will increase the purchase price translated in Canadian dollars and thereby increase the Canadian dollars required to fund the USD purchase price for the acquisition ultimately obtained by the Company.

The proceeds of the first instalment of the Debenture Offering were invested in short-term US dollar investment grade securities.

During the month of October 2015, Emera entered into foreign exchange forward contracts to economically hedge an amount equal to the anticipated proceeds from the second instalment of the Debenture Offering of the pending TECO Energy acquisition of $1.457 billion. These foreign exchange forward contracts are economic hedges and do not qualify for hedge accounting. Therefore, all mark-to-market gains and losses will be recognized in net income for the period. In addition, the operations of TECO Energy are conducted in US dollars. Following the acquisition, the consolidated net income of Emera will be impacted to a greater extent by movements in the US dollar relative to the Canadian dollar.

E. Guarantees and Letters of Credit

Emera had outstanding the following guarantees and letters of credit on behalf of third parties which are not included within the Consolidated Balance Sheets as at December 31, 2015:

• Emera has provided a completion guarantee to the Government of Canada, whereby it has guaranteed the performance of the obligations of NSPML to cause the completion of the Maritime Link Project, subject to certain conditions set out in that guarantee. The cost of those obligations is estimated to be $1.577 billion, which reduces in the ordinary course as project costs are paid.

• Emera has provided a guarantee to the Long Island Power Authority (“LIPA”) on behalf of Bear Swamp for Bear Swamp’s long-term energy and capacity supply agreement (“PPA”) with LIPA, which expires on April 30, 2021. The guarantee is for 50 per cent of the relevant obligations under the PPA up to a maximum of $5.1 million USD. As at December 31, 2015, the fair value of the PPA was positive.

• Standby letters of credit in the amount of $20.5 million USD for the benefit of secured parties in connection with a refinancing of the Bear Swamp joint venture and also to third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one-year term and are renewed annually as required.

• A standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2016 and is renewed annually. The amount committed as at December 31, 2015 was $42.6 million.

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• A standby letter of credit to secure obligations under an unfunded pension plan in Emera Maine. The letter of credit expires in October 2016 and is renewed annually. The amount committed as at December 31, 2015 was $2.7 million USD.

• A standby letter of credit was issued to secure the obligations of Emera Reinsurance Limited under reinsurance agreements. The letter of credit expires in February 2016. The amount committed as at December 31, 2015 was $2.0 million USD.

F. Collaborative Arrangements

NSPI

Through NSPI, the Company is a participant in a 23.3 megawatt (“MW”) wind energy project with Renewable Energy Services Ltd. in Point Tupper, Nova Scotia. Percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets with NSPI owning 47.4 per cent. NSPI has a power purchase arrangement to purchase the entire net output of the project and, therefore, NSPI’s portion of the revenues are recorded net, within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses are recorded in operating, maintenance and general (“OM&G”) expenses. In 2015, NSPI recognized $2.8 million net expense (2014 – $3.0 million) in “Regulated fuel for generation and purchased power” and $0.5 million (2014 – $0.5 million) in “OM&G”. As part of this arrangement, NSPI received a portion of an Eco Energy revenue claim totaling $0.3 million in 2015.

Through NSPI, the Company is a participant in a 102 MW wind energy project with South Canoe Development Partnership for South Canoe Wind Farm, in New Ross, Nova Scotia. Percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets, with NSPI owning not more than 49 per cent. NSPI has a power purchase arrangement to purchase the entire net output of the project and therefore NSPI’s portion of the revenues are recorded net, within “Regulated fuel for generation and purchased power”. NSPI’s portion of operating expenses, are recorded in “OM&G”. The project went reached commercial operation in Q2 2015. In 2015, NSPI recognized a $6.4 million net expense in “Regulated fuel for generation and purchased power” and $1.1 million in “OM&G”.

Through NSPI, the Company is a participant in a 13.8 MW wind energy project with Municipality of the District of Guysborough for Sable Wind Farm, near Canso, Nova Scotia. Percentage ownership of the wind farm will be based on the relative value of each party’s project assets by the total project assets, with NSPI owning not more than 49 per cent. NSPI’s has a power purchase arrangement to purchase the entire net output of the project and therefore NSPI’s portion of the revenues are recorded net, within “Regulated fuel for generation and purchased power”. NSPI’s portion of operating expenses, are recorded in “OM&G”. The project went reached commercial operation in Q2 2015. In 2015, NSPI recognized a $1.0 million net expense in “Regulated fuel for generation and purchased power” and $0.1 million in “OM&G”.

Emera Maine

Through Emera Maine, the Company is a party to a collaborative arrangement with National Grid Transmission Services Corporation to develop the Northeast Energy Link (“NEL”) Project. The cost of development activities, including acquisition of land in the transmission corridor and acquisition of necessary governmental and regulatory permits and approvals, are shared equally between the Company and National Grid. Emera Maine has deferred $4.6 million ($3.3 million USD) of costs associated with the NEL project as at December 31, 2015 (December 31, 2014 – $3.6 million), reported in the Consolidated Balance Sheets in “Other” as part of “Other long-term assets”.

Through Emera Maine, the Company is a party to a collaborative arrangement with EDP Renewables (“EDPR”), Central Maine Power (“CMP”) and Maine Electric Power Company Inc. (“MEPCO”) related to

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construction of an electric transmission line in Northern Maine. Emera Maine and CMP retain an option to buy-back the transmission line as part of a larger solution to collect further quantities of wind generation being pursued for development in Northern Maine, for delivery into the ISO-NE market. CMP and Emera Maine agreed to pursue this regional solution together per a Memorandum of Understanding (“MOU”) signed in May 2014. As at December 31, 2015, Emera Maine had deferred $1.4 million ($1.0 million USD) (December 31, 2014 – $1.2 million) associated with this development.

33. COMMON STOCK

Authorized: Unlimited number of non-par value common shares.

	2015					2014
Issued and outstanding:	millions of shares		millions of Canadian dollars			millions of shares		millions of Canadian dollars
Balance, January 1		143.78	$	2,016.4			132.89	$	1,703.0
Issuance of common stock (1)		1.25		53.7			8.66		242.8
Issued for cash under Purchase Plans at market rate		2.10		88.3			1.97		66.6
Discount on shares purchased under Dividend Reinvestment Plan		—		(4.1	)		—		(3.0	)
Options exercised under senior management share option plan		0.08		2.3			0.26		6.2
Employee Share Purchase Plan		—		0.9			—		0.8
Balance, December 31		147.21	$	2,157.5			143.78	$	2,016.4

(1) On December 17, 2015, Emera issued 1.25 million common shares to facilitate the creation and issuance of 5.0 million depositary receipts in connection with the ECI share acquisition. The depositary receipts are listed on the Barbados Stock Exchange.

As at December 31, 2015, there were the following common shares reserved for issuance: 7.3 million (2014 – 7.3 million) under the senior management stock option plan, 1.6 million (2014 – 1.8 million) under the employee common share purchase plan and 3.3 million (2014 – 5.2 million) under the dividend reinvestment plan. The issuance of common shares under the current or proposed common share compensation arrangements will not exceed ten per cent of Emera’s outstanding common shares. As at December 31, 2015, Emera is in compliance with this requirement.

34. CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

					December 31, 2015				December 31, 2014
	Annual Dividend Per Share		Redemption Price per share		Issued and Outstanding		Net Proceeds		Issued and Outstanding		Net Proceeds
Series A	$	0.6388	$	25.00		3,864,636	$	94.5		6,000,000	$	146.7
Series B		Floating	$	25.00		2,135,364	$	52.2		—	$	—
Series C	$	1.0250	$	25.00		10,000,000	$	244.9		10,000,000	$	244.9
Series E	$	1.1250	$	26.00		5,000,000	$	122.4		5,000,000	$	122.4
Series F	$	1.0625	$	25.00		8,000,000	$	195.5		8,000,000	$	195.5

On August 17, 2015, Emera announced that 2,135,364 of its 6,000,000 issues and outstanding Series A Shares were tendered for conversion, on a one-for-one basis into Cumulative Floating Rate First Preferred Shares, Series B (the “Series B Shares”). As a result of the conversion, Emera has 3,864,636 Series A Shares and 2,135,364 Series B Shares issued and outstanding. The 2015 dividends for the Series A and Series B shares were $0.98470 and $0.15080 respectively.

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The First Preferred Shares, Series A, C and F are entitled to receive fixed cumulative cash dividends as and when declared by the Board of Directors of the Corporation in the amounts of $0.6388, $1.025 and $1.0625 per share per annum, respectively for each year up to and excluding August 15, 2020, August 15, 2018, and February 15, 2020, respectively. As at August 15, 2020, August 15, 2018, and February 15, 2020, the holders of the First Preferred Shares Series A, C and F, respectively, are entitled to receive reset fixed cumulative cash dividends. The reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate of the First Preferred Shares, Series A, C and F, respectively, which is the sum of the five-year Government of Canada Bond Yield on the application reset date plus 1.84 per cent, 2.65 per cent, and 2.63 per cent, respectively.

The First Preferred Shares, Series B, are entitled to receive floating rate cumulative cash dividends, as and when declared by the Board of Directors in the amount determined by multiplying $25.00 by the three month Government of Canada Treasury Bill rate plus 1.84 per cent.

The First Preferred Shares, Series E, are entitled to receive fixed rate cumulative cash dividends, as and when declared by the Board of Directors in the amount $1.1250 per annum.

The holders of First Preferred Shares, Series A, C and F will have the right, at their option, to convert their shares into an equal number of Cumulative Floating Rate First Preferred Shares, Series B, D, and G, of the Company, respectively, on August 15, 2020 August 15, 2018, and February 15, 2020, respectively, and every five years thereafter.

The holders of the First Preferred Shares, Series B will have the right, at their option, to convert their shares into an equal number of Series A shares of the Company on August 15, 2020 and every five years thereafter.

The Company has the right to redeem the outstanding Preferred Shares, Series A, C, and F shares without the consent of the holder on August 15, 2020, August 15, 2018, and February 15, 2020 respectively and on August 15, August 15 and February 15 respectively every five years thereafter for cash, in whole or in part at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption.

The Company has the right to redeem the outstanding Preferred Shares, Series B, Series D and Series G shares without the consent of the holder on August 15, 2020, August 15, 2023 and February 15, 2025 respectively and on August 15, August 15 and February 15 every five years thereafter for cash, in whole or in part at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption and $25.50 per share plus all accrued and unpaid dividends on any other date after August 15, 2015, August 15, 2018 and February 15, 2020, respectively.

The Company has the right to redeem the outstanding First Preferred Shares, Series E on or after August 15, 2018 in whole or in part, at the Company’s option, by the payment in cash of $26.00 per Series E Preferred Share if redeemed prior to August 15, 2019; at $25.75 per Series E Preferred Share if redeemed on or after August 15, 2019, but prior to August 15, 2020; at $25.50 per Series E Preferred Share if redeemed on or after August 15, 2020, but prior to August 15, 2021; at $25.25 per Series E Preferred Share if redeemed on or after August 15, 2021, but prior to August 15, 2022; and at $25.00 per Series E Preferred Share if redeemed on or after August 15, 2022, in each case together with all accrued and unpaid dividends up to but excluding the date fixed for redemption.

As the First Preferred Shares, Series A, B, C, E and F are neither redeemable at the option of the shareholder nor have a mandatory redemption date, they are classified as equity and the associated dividends will be deducted on the consolidated statements of earnings immediately before arriving at “Net earnings attributable to common shareholders” and will be shown on the consolidated statement of equity as a deduction from retained earnings.

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The First Preferred Shares of each series rank on a parity with the First preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares will be entitled to attend any meeting of shareholders of the Company and to vote at any such meeting.

35. NON-CONTROLLING INTEREST IN SUBSIDIARIES

Non-controlling interest in subsidiaries consisted of the following:

As at millions of Canadian dollars	December 31 2015		December 31 2014
ICDU	$	51.8	$	40.9
ECI (1)		48.3		99.6
Preferred shares of GBPC		33.5		33.5
Preferred shares of Emera Maine		0.4		0.4
Preferred shares of NSPI (2)		—		132.2
	$	134.0	$	306.6

(1) On December 17, 2015, an indirect wholly-owned subsidiary of Emera acquired approximately 2.6 million ECI shares, increasing its ownership interest from 80.7 per cent to 95.5 per cent.

(2) On October 15, 2015, NSPI redeemed all of its outstanding Cumulative Redeemable First Preferred Shares, Series D for a redemption price of $25.00 per share for a total of $135 million. The issuance costs are treated as a deemed dividend of $2.8 million, recognized when the redemption occurred on October 15, 2015.

Preferred shares of NSPI:

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

	2015				2014
Issued and outstanding:	Millions of shares		Millions of dollars		Millions of shares		Millions of dollars
Outstanding as at December 31		—	$	—		5.4	$	132.2

Preferred shares of GBPC:

Authorized:

35,000 non-voting cumulative redeemable variable perpetual preferred shares

	2015				2014
Issued and outstanding:	number of shares		millions of dollars		number of shares		millions of dollars
Outstanding as at December 31		35,000	$	33.5		35,000	$	33.5

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GBPC Non-Voting Cumulative Variable Perpetual Preferred Stock:

The Preferred Stock is redeemable by GBPC, in whole at any time or in part from time to time, at $1,000 Bahamian per share plus accrued and unpaid dividends.

The Preferred Stock is entitled to a 7.25 per cent per annum fixed cumulative preferential dividend for years 2013 through 2016, 8.50 per cent per annum fixed cumulative preferential dividend for years 2017 through 2019 and 10.00 per cent per annum fixed cumulative preferential dividend after 2020, as and when declared by the Board of Directors, accruing from the date of issue.

The Preferred Shares rank behind all of GBPC’s current and future secured and unsecured debt with any of GBPC’s future preferred stock and ahead of all of GBPC’s current and future common stock.

36. STOCK-BASED COMPENSATION

EMPLOYEE COMMON STOCK PURCHASE PLAN AND COMMON SHAREHOLDERS DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN

All employees may participate in Emera’s Employee Common Share Purchase Plan to which employees make cash contributions of a minimum of $25 to a maximum of $8,000 per year for the purpose of purchasing common shares of Emera. The Company also contributes to the plan a percentage of the employees’ contributions. If an employee contributes any amount up to $3,000 to employees plan account, the Company will contribute 20 per cent of that amount. When an employee contributes any amount over $3,000, up to the $8,000 maximum, the Company will contribute ten per cent of that amount.

The plan allows the reinvestment of dividends. The maximum aggregate number of Emera common shares reserved for issuance under this plan is 4 million common shares.

The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”), which provides an opportunity for shareholders to reinvest dividends and for the purpose of purchasing common shares. The plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends under the Plans.

Compensation cost for shares issued by Emera for the year ended December 31, 2015 under the Employee Common Share Purchase Plan was $0.9 million (2014 – $0.8 million) and is included in “Operating, maintenance and general” on the Consolidated Statements of Income.

STOCK-BASED COMPENSATION PLANS

Stock Option Plan

The Company has a stock option plan that grants options to senior management of the Company for a maximum term of ten years. The option price of the stock options is the closing market price of the stocks on the day before the option is granted. The maximum aggregate number of shares issuable under this plan is 11.7 million shares.

All options granted to date are exercisable on a graduated basis with up to 25 per cent of options exercisable on the first anniversary date and further 25 per cent increments on each of the second, third and fourth anniversaries of the grant. If an option is not exercised within ten years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted.

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If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person due to retirement or termination for other than just cause, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the 24 months following the date the optionee retires, but in any case prior to the expiry of the option in accordance with its terms.

If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person due to employment termination for just cause, resignation or death, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the six months following the date the optionee is terminated, resigns or dies, as applicable, but in any case prior to the expiry of the option in accordance with its terms.

The Company uses the fair value based method to measure the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. The fair value of stock option awards granted was estimated on the date of grant using a Black-Scholes valuation model. The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the Bank of Canada five-year government bond yields. The expected dividend yield incorporates current dividend rates as well as historical dividend increase patterns. Emera’s expected stock price volatility was estimated using its five-year historical volatility.

The following table shows the weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted:

For the year ended December 31,	2015		2014
Weighted average fair value per option	$	2.66	$	2.25
Expected term		5 years		5 years
Risk-free interest rate		0.73%		1.68%
Expected dividend yield		3.65%		4.47%
Expected volatility		14.58%		15.77%

The following table summarizes information related to the stock options for 2015:

	Total Options					Non-Vested Options(1)
	Number of Options			Weighted average exercise price per share		Number of Options			Weighted average grant date fair-value
Outstanding as at December 31, 2014		2,425,493		$	30.54		1,319,421		$	2.66
Granted		581,700			42.71		581,700			2.66
Exercised		(80,125	)		26.29		N/A			N/A
Vested		N/A			N/A		(447,635	)		2.75
Options outstanding December 31, 2015		2,927,068		$	33.07		1,453,486		$	2.64
Options exercisable December 31, 2015(2)(3)		1,473,582		$	29.13

(1) As at December 31, 2015 there was $2.5 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately 2.3 years (2014 – $2.4 million, 2.5 years).

(2) As at December 31, 2015, the weighted average remaining term of vested options was 5.3 years with an aggregate intrinsic value of $20.8 million (2014: 5.5 years, $12.6 million).

(3) As at December 31, 2015 the fair value of options that vested in the year was $1.2 million (2014: $1.1 million).

Compensation cost recognized for stock options for the year ended December 31, 2015 was $1.4 million (2014 – $1.2 million), which is included in “Operating, maintenance and general” on the Consolidated Statements of Income.

As at December 31, 2015, cash received from option exercises was $2.1 million (2014 – $5.7 million). The total intrinsic value of options exercised for the year ended December 31, 2015 was $1.3 million (2014 – $4.2 million). The range of exercise prices for the options outstanding as at December 31, 2015 was $19.88 to $42.71 (2014 – $19.88 to $34.80).

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Share Unit Plans

The Company has deferred share unit (“DSU”) and performance share unit (“PSU”) plans. The DSU and PSU liabilities are marked-to-market at the end of each period based on the common share price at the end of the period.

Deferred Share Unit Plans

Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, referred to as the Dividend Reinvestment Plan (“DRIP”), the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price during the ten trading days ending on the tenth trading day prior to the payment date.

Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50% of the value of their actual annual incentive award (25% in the first year of the program) will be payable in DSUs until the applicable guidelines are met.

When incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee (“MRCC”), payments may be made in the form of actual shares.

In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to recognize singular achievements or to achieve certain corporate objectives.

A summary of the activity related to employee and director DSUs for the year ended December 31, 2015 is presented in the following table:

	Employee DSU			Weighted Average Grant Date Fair Value		Director DSU		Weighted Average Grant Date Fair Value
Outstanding as at December 31, 2014		511,167		$	24.38		301,086	$	29.62
Granted including DRIP		98,442			36.17		61,664		35.14
Exercised		(2,963	)		29.12		—		—
Outstanding and exercisable as at December 31, 2015		606,646		$	26.27		362,750	$	31.36

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Compensation cost recognized for employee and director DSU for the year ended December 31, 2015 was $8.1 million (2014 – $9.1 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2015 were $2.7 million (2014 – $3.1 million); $0.5 million was offset with regulatory assets and regulatory liabilities (2014 – $0.6 million).

Performance Share Unit Plan

Under the PSU plan, executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Dividend equivalents are awarded and are used to purchase additional PSUs, also referred to as DRIP. The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of retirement, disability or death.

A summary of the activity related to employee PSUs for the year ended December 31, 2015 is presented in the following table:

	Employee PSU			Weighted Average Grant Date Fair Value		Aggregate intrinsic value
Outstanding as at December 31, 2014		457,582		$	32.38	$	17.7
Granted including DRIP		247,937			36.79
Exercised		(204,583	)		32.54
Forfeited		(3,440	)		33.63
Outstanding as at December 31, 2015		497,496		$	34.50	$	21.5

Compensation cost recognized for the PSU plan for the year ended December 31, 2015 was $9.6 million (2014 – $8.9 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2015 were $3.1 million (2014 – $2.8 million).

37. VARIABLE INTEREST ENTITIES

The Company performs ongoing analysis to assess whether it holds any variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities.

VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is accounted for using the equity method.

For the years ended, December 31, 2015 and 2014, the Company has identified the following significant VIEs:

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera was not the primary beneficiary since it does not have the controlling financial interest of NSPML. In Q2 2014, when the critical milestones were achieved and Nalcor Energy was deemed the beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link Project. Thus, Emera began recording the Maritime Link Project as an equity investment.

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ECI has established a Self-Insurance Fund (“SIF”) primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF.

The Company has identified certain long-term purchase power agreements that could be defined as variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

As at December 31, 2015, NSPI did not provide a guarantee to RESL (December 31, 2014 – $18.4 million). Until Q4 2015, NSPI held a variable interest in RESL, a VIE for which it was determined that NSPI was not the primary beneficiary since it did not have the controlling financial interest of RESL and did not have the power to direct the operations of the facility.

Emera’s consolidated VIE is recorded as an “Available-for-sale investment” and “Restricted cash”. The following table provides information about Emera’s portion of significant consolidated and unconsolidated VIEs:

As at	December 31, 2015				December 31, 2014
	Total		Maximum		Total		Maximum
millions of Canadian dollars	assets		exposure to loss		assets		exposure to loss
Consolidated VIE
BLPC SIF	$	101.4	$	101.4	$	85.0	$	85.0
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)		187.6		1,007.0		159.3		1,292.1
RESL		—		—		—		18.4

38. COMPARATIVE INFORMATION

These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

39. SUBSEQUENT EVENTS

On January 25, 2016, Emera announced an indirect wholly-owned subsidiary, Emera (Barbados) Holdings No. 2 Inc., (“EBH2”), will proceed to acquire the remaining ECI common shares from minority shareholders. Minority ECI shareholders can elect to receive $33.30 Barbadian dollar (“BBD”) in cash per common share (“Cash Offer”) or 2.1 Depositary Receipts (“DR”) representing common shares of Emera (“DR Offer”) or a combination of the two Offers by way of an amalgamation between ECI and a wholly-owned subsidiary of EBH2. Each Emera DR initially represented one quarter of an Emera common share.

ECI is also proposing to amend the terms of its 5.5 per cent cumulative preferred shares to make them redeemable at a 20 per cent premium to their issuance price. An ECI shareholders’ meeting to vote on the amalgamation and preferred share amendment will take place on February 24, 2016.

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 12, 2016, the date the financial statements were issued.

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EX-4.3

Exhibit 4.3

Management’s Discussion & Analysis

As at February 12, 2016

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments (“Emera”) during the fourth quarter of 2015 relative to the same quarter in 2014; and the full year of 2015 relative to 2014 and 2013; and its financial position as at December 31, 2015 relative to December 31, 2014. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is presented. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments.

This discussion and analysis should be read in conjunction with the Emera Incorporated annual audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2015. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. Emera’s rate-regulated subsidiaries include:

Emera Rate-Regulated Subsidiary or Investment	Accounting Policies Approved/Examined By
Subsidiary
Nova Scotia Power Inc. (“NSPI”)	Nova Scotia Utility and Review Board (“UARB”)
Emera Maine	Maine Public Utilities Commission (“MPUC”) and the Federal Energy Regulatory Commission (“FERC”)
Barbados Light & Power Company Limited (“BLPC”)	Fair Trading Commission, Barbados
Grand Bahama Power Company Limited (“GBPC”)	The Grand Bahama Port Authority (“GBPA”)
Dominica Electricity Services Ltd. (“Domlec”)	Independent Regulatory Commission (“IRC”), Dominica
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)	National Energy Board (“NEB”)
Investment
NSP Maritime Link Inc. (“NSPML”)	UARB
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline LLC (“M&NP”)	NEB and FERC
Labrador Island Link Limited Partnership (“LIL”)	Newfoundland and Labrador Board of Commissioners of Public Utilities
St. Lucia Electricity Services Limited (“Lucelec”)	Government of St. Lucia

All amounts are in Canadian dollars (“CAD”), except for Emera Maine and Emera Caribbean sections of the MD&A, which are reported in US dollars (“USD”), unless otherwise stated.

Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR at www.sedar.com.

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Forward-Looking Information

This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, business prospects and opportunities and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbor provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “could”, “estimates”, “expects”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “budget”, “forecast”, “might”, “will”, “would”, “targets” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations are discussed in the Outlook section of the MD&A and may also include: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; capital market and liquidity risk; the completion of the TECO Energy, Inc. (“TECO Energy”) acquisition; uncertainty regarding the length of time required to complete the TECO Energy acquisition; future dividend growth; timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology could reduce demand for electricity; weather; commodity price risk; construction and development risk; unanticipated maintenance and other expenditures; derivative financial instruments and hedging availability and inability to complete the Debenture Offering and the financing; failure by the Company to repay the acquisition credit facilities; potential unavailability of the acquisition credit facilities; alternate sources of funding that would be used to replace the acquisition credit facilities may not be available when needed; impact of acquisition related expenses; interest rate risk; credit risk; commercial relationship risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

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Structure of MD&A

This MD&A begins with an Introduction and Strategic Overview; followed by the Consolidated Financial Review and Outstanding Common Stock data; then presents information specific to Emera’s consolidated subsidiaries and investments:

• NSPI;

• Emera Maine;

• Emera Caribbean includes BLPC and Domlec and their parent company, Emera (Caribbean) Incorporated (“ECI”), GBPC, Emera Utility Services (Bahamas) Limited (“EUS Bahamas”) and Lucelec;

• Pipelines includes Brunswick Pipeline and M&NP;

• Emera Energy includes Emera Energy Services (“EES”); Emera Energy Generation (“EEG”) which includes Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities”), Brooklyn Power Corporation (“Brooklyn Energy” or “Brooklyn”) and Bayside Power Limited Partnership (“Bayside Power” or “Bayside”); Bear Swamp Power Company LLC (“Bear Swamp”); and Northeast Wind Partners II, LLC (“NWP”) until its sale on January 29, 2015;

• Corporate and Other includes:

• Interest revenue on intercompany financings and costs associated with corporate activities that are not directly allocated to the operations of Emera’s consolidated subsidiaries and investments;

• Acquisition costs related to the pending acquisition of TECO Energy;

• Emera Utility Services Inc. (“Emera Utility Services”);

• Emera Newfoundland & Labrador Holdings Inc. (“ENL”) and its investments:

• NSPML;

• LIL;

• Emera Reinsurance Limited;

• Emera’s investment in Algonquin Power & Utilities Corp. (“APUC”);

• Emera’s investment in OpenHydro Group Ltd. (“Open Hydro”); and

• Other investments

The Liquidity and Capital Resources, including Consolidated Cash Flow Highlights, Pension Funding, Off-Balance Sheet Arrangements, Outlook, Transactions with Related Parties, Dividends and Payout Ratios, Enterprise Risk and Risk Management, including Financial Instruments, Disclosure and Internal Controls, Critical Accounting Estimates, Changes in Accounting Policies and Practices and Summary of Quarterly Results sections of the MD&A are presented on a consolidated basis.

INTRODUCTION AND STRATEGIC OVERVIEW

Emera Incorporated is a geographically diverse energy and services company that invests in electricity generation, transmission and distribution, as well as gas transmission and utility services. Emera provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States, and the Caribbean.

Emera seeks to deliver long-term growth to investors and, accordingly, annual dividend growth, earnings per common share growth and total shareholder return are the primary measures of performance. Emera is targeting eight-per-cent annual dividend growth through 2019. Below are Emera’s one, three and five-year performance for these metrics:

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For the	Year ended December 31, 2015
	1 year			3 year			5 year
Dividend per share compound annual growth rate		12.7	%		6.9	%		7.4	%
Adjusted earnings per share compound annual growth rate		1.3	%		6.9	%		5.9	%
Emera annualized total shareholder return (1)		16.4	%		12.1	%		11.1	%
S&P/TSX Capped Utilities Index annualized total shareholder return (2)		(3.5	)%		2.3	%		3.5	%

(1) Total shareholder return combines share price appreciation and dividends per common share paid during the fiscal year to show the total return to the shareholder expressed as an annualized percentage assuming dividends are reinvested each time they are paid.

(2) The S&P/TSX Capped Sector Indices provide liquid and tradable benchmarks for related derivative products of Canadian economic sectors. Constituents are selected from a stock pool of S&P/TSX Composite Index Stocks, and the relative weight of any single index constituent is capped at 25 per cent. The indices are based upon the Global Industry Classification Standards (GICS®). The S&P/TSX Capped Utilities imposes capped weights on the index constituents included in the S&P/TSX Composite that are classified in the GICS® utilities sector.

Energy markets worldwide, in particular across North America, are undergoing foundational changes that have created significant investment opportunities for companies with Emera’s experience and capabilities. Key trends contributing to these investment opportunities include: aging infrastructure, environmental concerns (including demand for new, less carbon-intensive and renewable generation), lower-cost natural gas, growing demand for new electric heating solutions, and the requirement for large-scale transmission projects to deliver new energy sources to customers. Within this context, Emera is focused on growing shareholder value by identifying reliable and affordable energy solutions, typically involving the replacement of higher-carbon electricity generation with generation from cleaner sources, and the related transmission and distribution infrastructure to deliver that energy to market.

Emera has strong partnerships and relationships throughout the regions in which it operates and has established a diverse investment and operations profile that links its assets and capabilities in those regions. Core to Emera’s strategy is the ability to leverage these particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company.

Emera’s strategy is based on its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. The Company will continue to make investments in its regulated utilities to benefit customers and focus on providing rate stability to its customers. From time to time, Emera will make acquisitions, both regulated and unregulated, where the business or asset acquired aligns with Emera’s strategic initiatives and delivers shareholder value.

To ensure stability in net income and cash flows, Emera employs operating and governance models that focus on operational excellence, constructive regulatory approaches, proactive stakeholder engagement and a customer focus through service reliability and rate stability.

Emera targets achieving 75 to 85 per cent of its adjusted income (a non-GAAP measure described in the section below) from rate-regulated subsidiaries, which generally contribute strong, predictable income and cash flows that fund dividends, reinvestment and is reflective of the Company’s risk tolerance. Emera has an annual dividend growth target of eight per cent through 2019.

In 2015, approximately 65 per cent of Emera’s adjusted net income was earned by its rate-regulated subsidiaries, which is lower than previous years and the strategic target. With the pending close of the TECO Energy acquisition, the Company will achieve its adjusted net income targeted mix. Specifically, this was as the result of a substantial increase in Emera Energy’s earnings primarily due to strong performance by the New England Gas Generating Facilities, and a strengthening US dollar. The current percentage from non-regulated businesses is not the result of a change in Emera’s risk tolerance, nor is it from additional capital allocations to non-regulated businesses. Rather, it is the result of strong operating and financial performance of existing non-regulated investments and businesses.

Emera has grown its asset base to enable growth and deliver on its strategic objectives. Over the last 10 years, Emera’s ability to raise the capital necessary to fund investments has been a strong enabler of the Company’s growth. This was demonstrated in Emera’s recent issue of convertible debentures

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represented by instalment receipts in relation to the pending TECO Energy acquisition. In addition to access to debt and equity capital markets, cash flow from operations will continue to play a role in financing the Company’s future growth. Maintaining strong, investment grade credit ratings is an important component of Emera’s financing strategy.

The energy industry is seasonal in nature. Seasonal patterns and other weather events, including the number and severity of storms, can affect demand for energy and cost of service. Similarly, mark-to-market adjustments arising from commodity purchases or trading activities that do not qualify for hedge accounting or regulatory accounting can have a material impact on the financial results for a specific period. Results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

Non-GAAP Financial Measures

Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures by adjusting certain GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period, as detailed below:

Non-GAAP measure	GAAP measure
Adjusted net income attributable to common shareholders or adjusted net income	Net income attributable to common shareholders
Adjusted earnings per common share – basic	Earnings per common share – basic
Adjusted contribution to consolidated net income	Contribution to consolidated net income
Adjusted income before provision for income taxes	Income before provision for income taxes
Adjusted contribution to consolidated earnings per common share – basic	Contribution to consolidated earnings per common share – basic
EBITDA	Net income
Adjusted EBITDA	Net income
Electric margin	Income from operations

Adjusted Net Income

Emera calculates comparable measures by excluding the effect of:

• the mark-to-market adjustments related to Emera’s held-for-trading (“HFT”) derivative instruments;

• the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp and NWP, until NWP’s sale on January 29, 2015;

• the amortization of transportation capacity recognized as a result of certain trading and marketing transactions;

• the mark-to-market adjustments related to an interest rate swap in Brunswick Pipeline; and

• the mark-to-market adjustments included in Emera’s other income related to the effect of USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the Debenture Offering for the pending TECO Energy acquisition.

Management believes excluding from income the effect of these mark-to-market valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows.

Mark-to-market adjustments are further discussed in the Consolidated Financial Highlights section, Emera Energy – Review of 2015, Pipelines – Review of 2015 and Corporate and Other – Review of 2015.

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The following is a reconciliation of reported net income attributable to common shareholders to adjusted net income attributable to common shareholders, and reported earnings per common share – basic to adjusted earnings per common share – basic:

For the millions of Canadian dollars (except per share amounts)	Three months ended				Year ended
	December 31				December 31
	2015		2014		2015		2014		2013
Net income attributable to common shareholders	$	192.1	$	151.2	$	397.2	$	406.7	$	217.5
After-tax mark-to-market gain (loss)	$	105.0	$	72.7	$	67.2	$	87.5	$	(41.9	)
Adjusted net income attributable to common shareholders	$	87.1	$	78.5	$	330.0	$	319.2	$	259.4
Earnings per common share – basic	$	1.31	$	1.05	$	2.72	$	2.84	$	1.64
Adjusted earnings per common share – basic	$	0.59	$	0.54	$	2.26	$	2.23	$	1.96

EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is a non-GAAP financial measure used by Emera. EBITDA is used by numerous investors and lenders to better understand cash flows and credit quality.

Adjusted EBITDA is a non-GAAP financial measure used by Emera. Similar to Adjusted Net Income calculations, this measure represents EBITDA absent the income effect of Emera’s mark-to-market adjustments, as previously discussed.

The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies, but in management’s view appropriately reflects Emera’s specific financial condition. These measures are not intended to replace “Net income attributable to common shareholders” which, as determined in accordance with GAAP, is an indicator of operating performance. EBITDA and Adjusted EBITDA are discussed further in the Consolidated Financial Review, NSPI, Emera Maine, Emera Caribbean, Pipelines, Emera Energy, and Corporate and Other sections.

EBITDA and Adjusted EBITDA Reconciliation

For the millions of Canadian dollars	Three months ended				Year ended
	December 31				December 31
	2015		2014		2015		2014		2013
Net income	$	198.6	$	155.3	$	452.4	$	452.8	$	255.3
Interest expense, net		70.9		44.7		212.6		179.8		172.2
Income tax expense (recovery)		20.7		53.7		92.4		113.6		43.3
Depreciation and amortization		87.9		82.0		339.9		329.0		297.8
EBITDA		378.1		335.7		1,097.3		1,075.2		768.6
Mark-to-market gain (loss), excluding income tax and interest		119.3		107.7		66.1		128.7		(60.9	)
Adjusted EBITDA	$	258.8	$	228.0	$	1,031.2	$	946.5	$	829.5

Electric Margin

“Electric margin” is a non-GAAP financial measure used to show the amounts that NSPI, BLPC, GBPC and Domlec retain to recover non-fuel costs. Prudently incurred fuel costs are recovered from customers, except in Domlec, where substantially all fuel costs are passed to customers through the fuel pass-through mechanism. Management believes measuring electric margin shows the portion of the utilities’ revenues that directly contribute to Emera’s income as distinguished from the portion of revenues that are managed through fuel adjustment mechanisms, which have a minimal impact on income.

Emera Energy also reports “Electric margin” because the sales price of electricity and the cost of natural gas used to generate it are highly correlated. However, their absolute values can vary materially over time. Emera Energy believes that “Electric margin”, as the net result, provides a meaningful measure of

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the business’ performance in addition to the absolute values of sales and fuel expenses, which are also reported.

Electric margin, as calculated by Emera, may not be comparable to the electric margin measures of other companies, but in management’s view appropriately reflects Emera’s specific condition. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance. Electric margin is discussed further in the NSPI – Electric Margin, the Emera Caribbean – Electric Margin and the Emera Energy – Adjusted EBITDA sections.

Significant Items Affecting Earnings

2015

After-Tax Mark-to-Market Gains

After-tax mark-to-market gains increased $32.3 million to $105.0 million in Q4 2015 compared to $72.7 million in Q4 2014; and decreased $20.3 million to $67.2 million for the year ended December 31, 2015 compared to $87.5 million in 2014. The increased mark-to-market gains in the quarter are primarily due to the effect of USD-denominated currency and forward contracts related to the pending TECO Energy acquisition. The increase is partially offset by changes in gas and power contract positions and amortization of transportation assets in Emera Energy. In addition, the reversal of 2013 mark-to-market losses in 2014 in Emera Energy is primarily responsible for the year-over-year decrease in after-tax mark-to-market gains.

Acquisition Related Costs

Emera incurred after-tax costs of $30.3 million ($0.21 per common share) in Q4 2015 related to its pending acquisition of TECO Energy, including legal, advisory, and financing costs. For the year ended December 31, 2015, TECO Energy acquisition related costs were $52.8 million after-tax ($0.36 per common share). There were no such TECO Energy acquisition related costs for 2014.

As discussed and included above in “After-Tax Mark-to-Market Gains”, the foreign currency earnings effect related to the Debenture Offering USD cash balance and the forward contracts were recorded as a mark-to-market pre-tax gain of $118.9 million in “Other income (expenses), net” in Q4 2015.

Further information on the pending acquisition of TECO Energy is in the Developments section of the MD&A.

Gain on Dilution of APUC Equity Investment

In December 2015, APUC closed a 14.355 million common share offering. As a result, Emera recorded a dilution gain of $11.1 million (after-tax earnings of $9.4 million or $0.06 per common share) in “Income from Equity Investments”. The gain was a result of APUC’s share issuance price being higher than Emera’s pre-issuance average book value.

Barbados Light & Power Company Limited (“BLPC”) Restructuring Costs

BLPC recorded severance costs of $7.9 million ($6.4 million USD) relating to corporate restructuring, which was recorded in Operating, maintenance and general (“OM&G”) in Q2 2015. BLPC sees no requirement to seek regulatory deferral of these costs. The after-tax effect on Emera’s Consolidated Net Income in Q2 2015, at Emera’s then 80.7 per cent ownership of ECI, was $5.4 million ($0.04 per common share).

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Sale of Northeast Wind Partnership II, LLC Equity Investment

On January 29, 2015, Emera completed the sale of its 49 per cent interest in NWP for $282.3 million ($223.3 million USD). This sale resulted in a pre-tax gain of $18.6 million or $0.13 per common share (after-tax gain of $11.5 million or $0.08 per common share), which was recorded in “Other income (expenses), net” in Q1 2015.

2014

After-Tax Mark-to-Market Gains

After-tax mark-to-market gains (losses) increased $114.7 million to $72.7 million in Q4 2014 compared to $(42.0) million in Q4 2013; and increased $129.4 million to $87.5 million for the year ended December 31, 2014 compared to $(41.9) million in 2013. The increased mark-to-market gains are a result of the reversal of 2013 mark-to-market losses and favourable changes in gas and power contract positions in 2014 at Emera Energy.

Gains on Dilution of APUC Equity Investment

In Q3 2014 and Q4 2014 respectively, APUC closed 16.86 million and 10.05 million common share offerings. In addition, in Q3 2014, an over-allotment option of 2.52 million common shares was exercised. As a result of these two transactions, in Q3 2014, Emera recorded a gain of $10.8 million (after-tax earnings of $9.1 million or $0.06 per common share) and in Q4 2014, a gain of $7.5 million (after-tax earnings of $6.4 million or $0.04 per common share) in “Income from Equity Investments”.

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CONSOLIDATED FINANCIAL REVIEW

Consolidated Financial Highlights

For the millions of Canadian dollars (except per share amounts)	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
Operating revenues	$	731.6	$	782.7	$	2,789.3	$	2,938.6	$	2,230.2
Income from operations		149.0		235.4		507.7		667.3		407.1
Net income attributable to common shareholders		192.1		151.2		397.2		406.7		217.5
After-tax mark-to-market gain (loss)		105.0		72.7		67.2		87.5		(41.9	)
Adjusted net income attributable to common shareholders		87.1		78.5		330.0		319.2		259.4
Earnings per common share – basic	$	1.31	$	1.05	$	2.72	$	2.84	$	1.64
Earnings per common share – diluted	$	1.30	$	1.02	$	2.71	$	2.82	$	1.64
Adjusted earnings per common share – basic	$	0.59	$	0.54	$	2.26	$	2.23	$	1.96
Dividends per common share declared	$	—	$	—	$	1.6625	$	1.4750	$	1.4125
Adjusted EBITDA	$	258.8	$	228.0	$	1,031.2	$	946.5	$	829.5

For the millions of Canadian dollars	Three months ended December 31					Year ended December 31
Operating Unit Contributions to Adjusted Net Income	2015			2014		2015			2014			2013
NSPI	$	40.1		$	30.1	$	129.9		$	124.9		$	126.0
Emera Maine		5.2			11.7		45.1			42.4			38.4
Emera Caribbean		13.3			6.1		40.5			28.7			33.4
Pipelines		10.1			8.5		39.6			32.7			30.3
Emera Energy		35.4			21.3		130.1			98.2			45.1
Corporate and Other		(17.0	)		0.8		(55.2	)		(7.7	)		(13.8	)
Adjusted net income attributable to common shareholders	$	87.1		$	78.5	$	330.0		$	319.2		$	259.4
After-tax mark-to-market gain (loss)		105.0			72.7		67.2			87.5			(41.9	)
Net income attributable to common shareholders	$	192.1		$	151.2	$	397.2		$	406.7		$	217.5

For the millions of Canadian dollars	Year ended December 31
	2015			2014			2013
Operating cash flow before changes in working capital	$	775.8		$	716.3		$	574.3
Change in working capital		(101.6	)		46.2			(10.1	)
Operating cash flow	$	674.2		$	762.5		$	564.2
Investing cash flow	$	(123.7	)	$	(710.9	)	$	(921.6	)
Financing cash flow	$	221.1		$	58.2		$	362.1

	December 31
As at millions of Canadian dollars	2015		2014		2013
Working capital (1)	$	599.2	$	358.3	$	372.7
Total assets (1)	$	12,012.3	$	9,853.4	$	8,876.8
Total long-term liabilities (1)	$	5,596.9	$	5,025.1	$	4,449.7

⁽¹⁾  These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

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REVIEW OF 2015

Emera Consolidated Statements of Income

For the millions of Canadian dollars (except per share amounts)	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
Operating revenues – regulated	$	533.8	$	526.7	$	2,192.9	$	2,113.1	$	2,040.8
Operating revenues – non-regulated		197.8		256.0		596.4		825.5		189.4
Total operating revenues		731.6		782.7		2,789.3		2,938.6		2,230.2
Regulated fuel for generation and purchased power		199.9		212.9		814.5		844.3		868.4
Regulated fuel adjustment mechanism and fixed cost deferrals		10.3		5.7		41.6		46.6		(40.8	)
Non-regulated fuel for generation and purchased power		90.7		78.2		335.7		401.1		89.8
Non-regulated direct costs		4.4		9.7		19.5		31.3		52.4
Operating, maintenance and general		173.6		144.0		666.8		560.8		505.0
Provincial, state and municipal taxes		15.8		14.8		63.6		58.2		50.5
Depreciation and amortization		87.9		82.0		339.9		329.0		297.8
Total operating expenses		582.6		547.3		2,281.6		2,271.3		1,823.1
Income from operations		149.0		235.4		507.7		667.3		407.1
Income from equity investments		26.4		15.4		108.6		66.6		38.1
Other income (expenses), net		114.8		2.9		141.1		12.3		25.6
Interest expense, net		70.9		44.7		212.6		179.8		172.2
Income before provision for income taxes		219.3		209.0		544.8		566.4		298.6
Income tax expense (recovery)		20.7		53.7		92.4		113.6		43.3
Net income		198.6		155.3		452.4		452.8		255.3
Non-controlling interest in subsidiaries		6.5		4.1		24.9		19.9		18.5
Net income of Emera Incorporated		192.1		151.2		427.5		432.9		236.8
Preferred stock dividends		—		—		30.3		26.2		19.3
Net income attributable to common shareholders		192.1		151.2		397.2		406.7		217.5
After-tax mark-to-market gain (loss)		105.0		72.7		67.2		87.5		(41.9	)
Adjusted net income attributable to common shareholders	$	87.1	$	78.5	$	330.0	$	319.2	$	259.4
Earnings per common share – basic	$	1.31	$	1.05	$	2.72	$	2.84	$	1.64
Earnings per common share – diluted	$	1.30	$	1.02	$	2.71	$	2.82	$	1.64
Adjusted earnings per common share – basic	$	0.59	$	0.54	$	2.26	$	2.23	$	1.96

Emera Incorporated’s consolidated net income attributable to common shareholders increased $40.9 million to $192.1 million in Q4 2015 compared to $151.2 million for the same period in 2014. For the year ended December 31, 2015, Emera’s consolidated net income attributable to common shareholders decreased $9.5 million to $397.2 million compared to $406.7 million in 2014.

Q4 Consolidated Income Statement Highlights

Operational Results

Income from operations decreased $86.4 million to $149.0 million in Q4 2015 compared to $235.4 million in the same quarter in 2014 primarily due to negative mark-to-market changes of $101.2 million and $21.0 million in costs related to the pending acquisition of TECO Energy. These decreases were partially offset by Emera Energy’s increased trading and marketing margin, and increased margin at the New England Gas Generating Facilities.

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Details of operating revenues and operating expenses line item variances are described below:

Total operating revenues decreased 6.5 per cent to $731.6 million in Q4 2015 compared to $782.7 million in Q4 2014 primarily due to:

• $113.7 million decrease from changes in mark-to-market impacts;

• $46.0 million increase at the New England Gas Generating Facilities primarily due to major outage work at Bridgeport Energy in 2014 and the effect of a strengthening USD;

• $22.2 million increase in Emera Energy Services reflecting growth in the volume of business and increased investment in transportation capacity;

• $9.5 million decrease at BLPC primarily due to lower fuel revenue reflecting lower fuel prices;

• $6.9 million increase at Emera Maine primarily due to the effect of a strengthening USD, partially offset by decreased sales volumes;

• $5.8 million increase at NSPI as a result of recovery of prior years’ fuel costs from a 2014 UARB settlement agreement, partially offset by decreased sales volumes due to weather.

Total operating expenses increased 6.4 per cent to $582.6 million in Q4 2015 compared to $547.3 million in Q4 2014, primarily due to the effect of a strengthening USD, acquisition costs related to the pending TECO Energy acquisition, and increased fuel costs at the New England Gas Generating Facilities reflecting major outage work at Bridgeport Energy in 2014, partially offset by lower fuel prices at BLPC and changes in mark-to-market impacts.

Income from equity investments

Income from equity investments increased 71.4 per cent in Q4 2015 to $26.4 million compared to $15.4 million in the same period in 2014, primarily due to higher APUC earnings in 2015 and a higher pre-tax gain on dilution of Emera’s APUC investment in 2015.

Other income (expenses), net

Other income increased $111.9 million to $114.8 million in Q4 2015 compared to $2.9 million in the same period in 2014. This was primarily due to mark-to-market gains on USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering for the pending TECO Energy acquisition.

Income tax expense (recovery)

Income tax expense decreased $33.0 million to $20.7 million in Q4 2015 compared to $53.7 million for the same period in 2014 primarily due to decreased income before provision for income taxes including mark-to-market adjustments related to Emera Energy, changes in the proportion of Emera Energy income earned in higher tax rate foreign jurisdictions, and a legislated change by the Province of Nova Scotia to the deferred tax treatment of two wind farms at NSPI. These decreases were partially offset by the taxable portion of mark-to-market gains relating to the effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering for the pending TECO Energy acquisition.

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2015 Consolidated Income Statement and Operating Cash Flow Highlights

Operational Results

Income from operations decreased $159.6 million to $507.7 million for the year ended December 31, 2015 compared to $667.3 million in 2014 primarily due to mark-to-market changes of $189.2 million. Increased margin at the New England Gas Generating Facilities, the effect of the strengthening USD, and increased operating income at NSPI, partially offset by $51.5 million in expenses relating to the pending acquisition of TECO Energy and Emera Energy’s decreased trading and marketing margin.

Total operating revenues decreased 5.1 per cent to $2,789.3 million for the year ended December 31, 2015 compared to $2,938.6 million in the same period in 2014 primarily due to:

• $203.7 million decrease from changes in mark-to-market impacts

• $47.3 million decrease at BLPC primarily due to lower fuel revenue reflecting lower fuel prices

• $32.6 million decrease in Emera Energy Services reflecting a return to more normal market circumstances following particularly strong market conditions in the northern United States and Ontario in Q1 2014

• $69.1 million increase at NSPI as a result of recovery of prior years’ fuel costs from the 2014 UARB settlement agreement and higher sales volumes, primarily due to weather

• $46.3 million increase at the New England Gas Generating Facilities primarily due to higher realized margins, increased generation largely because Bridgeport Energy had a major planned outage in Q4 2014, and the effect of a strengthening USD

• $41.6 million increase at Emera Maine primarily due to the effect of a strengthening USD, partially offset by decreased sales volumes.

Total operating expenses increased 0.5 per cent to $2,281.6 million for the year ended December 31, 2015 compared to $2,271.3 million in 2014. This was primarily due to the effect of a strengthening USD, acquisition costs related to the pending TECO Energy acquisition and increased regulated fuel for generation and purchased power at NSPI, partially offset by decreased fuel costs at the New England Gas Generating Facilities and BLPC reflecting lower fuel prices and changes in mark-to-market impacts.

Income from equity investments

Income from equity investments increased $42.0 million to $108.6 million for the year ended December 31, 2015 compared to $66.6 million in the same period of 2014. This was primarily due to favourable mark-to-market changes of $7.7 million, NWP losses in 2014, higher APUC equity earnings, increased allowance for funds used during construction (“AFUDC”) earnings by NSPML, and increased earnings resulting from the increased investment in LIL, partially offset by lower APUC dilution gains in 2015 compared to 2014.

Other income (expenses), net

Other income increased $128.8 million to $141.1 million for the year ended December 31, 2015 compared to $12.3 million in the same period in 2014. This was primarily due to a mark-to-market gains relating to the foreign exchange effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering for the pending TECO Energy acquisition and the gain on the sale of NWP.

Income tax expense (recovery)

Income tax expense decreased $21.2 million to $92.4 million for the year ended December 31, 2015 compared to $113.6 million in 2014. This was primarily due to decreased income before provision for income taxes, including mark-to-market adjustments related to Emera Energy, partially offset by the

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taxable portion of mark-to-market gains relating to the effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering financing the pending TECO Energy acquisition.

Operating Activities

Net cash provided by operating activities decreased $88.3 million to $674.2 million for the twelve months ended December 31, 2015 compared to $762.5 million for the same period in 2014. Cash from operations before changes in working capital increased by $62.0 million primarily due to higher margins at the New England Gas Generating Facilities, the effect of a strengthening USD and increased fuel electric revenues at NSPI, partially offset by lower trading and marketing margin at Emera Energy Services, payment of acquisition costs related to the pending TECO Energy acquisition and the deferral of demand side management (“DSM”) program costs at NSPI.

Changes in working capital decreased operating cash flows by $150.3 million primarily due to increased receivables reflecting higher posted margin at Emera Energy and increased revenues at NSPI and increased dividends payable, partially offset by favourable changes in fuel inventory at NSPI reflecting increased consumption.

Effect of Foreign Currency Translation

Emera’s foreign currency-denominated results are affected by exchange rate fluctuations. Revenue, operating expense, net income, and adjusted net income are translated at the weighted average rate of exchange. The amounts in the table below are calculated by multiplying the current period foreign denominated results by the change in the weighted average foreign exchange from the prior period. The table below shows the estimated effect of foreign currency translation on key income statement items:

millions of Canadian dollars (except per share amounts)	Q4 2015 vs Q4 2014			Q4 2014 vs Q4 2013
Impact on income from continuing operations
Total operating revenues	$	49.1		$	30.7
Total operating expenses		(42.3	)		(15.6	)
Net income		4.0			10.4
Adjusted net income		7.0			2.4
Impact on earnings per share
Basic	$	0.03		$	0.07
Adjusted	$	0.05		$	0.02
millions of Canadian dollars (except per share amounts)	2015 vs 2014			2014 vs 2013
Impact on income from continuing operations
Total operating revenues	$	163.6		$	98.6
Total operating expenses		(139.4	)		(67.0	)
Net income		19.2			22.0
Adjusted net income		26.0			12.1
Impact on earnings per share
Basic	$	0.13		$	0.15
Adjusted	$	0.18		$	0.08

Emera’s weighted average foreign exchange rates are shown in the following table:    

	Twelve months ended
	December 31
Average equivalent of $1.00 USD	2015		2014		2013
CAD	$	1.26	$	1.12	$	1.03

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Consolidated Balance Sheets Highlights

Significant changes in the consolidated balance sheets between December 31, 2015 and December 31, 2014 include:

millions of Canadian dollars	Increase (Decrease)		Explanation
Assets
Cash and cash equivalents	$	852.3	Increased from proceeds of the convertible debentures and long-term debt and cash from operations, partially offset by increased debt levels, preferred shares repayments and dividends
Receivables, net		63.9	Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries and increased cash collateral position on derivative instrument at NSPI
Income taxes receivable, net of income taxes payable (current and long-term)		52.8	Increased primarily due to the payment of taxes owing for the 2014 tax year by EES and NSPI’s required prepayment of taxes for reassessments relating to the timing of tax deductions under dispute with the Canada Revenue Agency
Derivative instruments (current and long-term)		188.6	Increased primarily due to favourable changes in USD price positions, partially offset by settlements of derivative instruments at NSPI and Emera Energy
Regulatory assets (current and long-term)		96.8	Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries and increased regulatory assets related to deferred income taxes, DSM and regulated derivatives, partially offset by amortization at NSPI
Property, plant and equipment, net of accumulated depreciation		577.8	Increased primarily due to the favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries, increased capital expenditures resulting from major planned outage work at Bridgeport Energy, funding of capital investments at Tiverton Power for 2016 major outage work and increased capital spending at NSPI, partially offset by depreciation
Investments subject to significant influence		117.7	Increased primarily due to reclassification of Bear Swamp investment credit balance to Other Long-Term Liabilities, outstanding APUC subscription receipts which became eligible for conversion in Q4 2015 (originally recorded in Other Assets), dilution gains in APUC, and increased investments in LIL and M&NP, partially offset by the sale of NWP
Available-for-sale investments		31.6	Increased primarily due to investment by Emera Reinsurance Limited and favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries
Goodwill		42.6	Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries
Intangibles		57.6	Increased primarily due to investment by Emera Maine in a customer information system and the favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries
Other assets (current and long-term)		115.2	Increased primarily due to increase in transportation capacity assets in Emera Energy and increased deferred financing costs related to the pending acquisition of TECO Energy, offset by a decrease in APUC subscription receipts which became eligible for conversion in Q4 2015 (now recorded as Investments Subject to Significant Influence)
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		28.3	Increased primarily due to increased debt levels at NSPI to fund the redemption of preferred stock, issuance of long-term debt by Brunswick Pipeline and the effect of a stronger USD on debt held by foreign subsidiaries, partially offset by repayment of long-term debt
Convertible debentures represented by instalment receipts		727.6	Increased due to the issuance of convertible debentures related to the pending acquisition of TECO Energy

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Deferred income tax liabilities, net of deferred income tax assets	174.0		Increased primarily due to the utilization of non-capital loss carryforwards and accelerated tax deductions related to property, plant and equipment at NSPI and Emera Maine
Derivative instruments (current and long-term)	240.5		Increased primarily due to a new asset management agreement and unfavourable changes in commodity pricing at Emera Energy and unfavourable mark-to-market impacts relating to interest rate and foreign exchange hedges at Brunswick Pipeline
Regulatory liabilities (current and long-term)	168.7		Increased primarily due to changes in derivative instruments as a result of favourable USD price positions and increased FAM liability at NSPI, partially offset by settlements of derivative instruments at NSPI
Pension and post-retirement liabilities (current and long-term)	(57.8	)	Decreased primarily due to improvement in funded position as a result of greater than expected asset return at NSPI
Other liabilities (current and long-term)	267.7		Increased primarily due to deferred cost impact of parts and capital work delivered for performance in 2015 by a service provider under long-term service agreements at the New England Gas Generating Facilities, and reclassification of Bear Swamp investment credit balance from Investments Subject to Significant Influence
Common stock	141.1		Increased primarily due to issuance of common stock for the dividend reinvestment program and purchase of additional ECI shares
Accumulated other comprehensive loss	(484.1	)	Decreased primarily due to the favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries and the amortization of unrecognized pension and post-retirement benefit costs at NSPI
Retained earnings	156.1		Increased due to net income in excess of dividends paid
Non-controlling interest in subsidiaries	(172.7	)	Decreased due to increased ownership in ECI

Developments

Emera

Purchase of ECI Outstanding Shares

On November 16, 2015, Emera (Barbados) Holdings No. 2 Inc., (“EBH2”), an indirect wholly-owned subsidiary of Emera, announced its intention to acquire the outstanding shares of ECI. Minority ECI shareholders could elect to receive $23.26 ($33.30 Barbadian dollar (“BBD”)) in cash per common share (“Cash Offer”) or 2.1 Depositary Receipts (“DR”) representing common shares of Emera (“DR Offer”) or a combination of the two Offers. Each Emera DR initially represented one quarter of an Emera common share.

On December 17, 2015, EBH2 acquired approximately 2.6 million ECI Shares, increasing its ownership in ECI to 95.5 per cent from 80.7 per cent. The total consideration paid was $58.7 million, with 92 per cent of shareholders electing the DR Offer and 8 per cent electing the Cash Offer.

On January 8, 2016, the DRs began trading on the Barbados Stock Exchange.

On January 25, 2016, Emera announced EBH2 will proceed to acquire the remaining common shares of ECI from minority shareholders at the same Cash Offer and DR Offer, described above, by way of an amalgamation between ECI and a wholly-owned subsidiary of EBH2.

ECI is also proposing to amend the terms of its 5.5 per cent cumulative preferred shares to make them redeemable at a 20 per cent premium to their issuance price. An ECI shareholders’ meeting to vote on the amalgamation and preferred share amendment will take place on February 24, 2016.

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Pending Acquisition of TECO Energy

On September 4, 2015, the Company announced a definitive agreement (“the acquisition agreement”) for Emera to acquire TECO Energy (“the Transaction”) (NYSE:TE). TECO Energy shareholders will receive $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.4 billion USD and includes the assumption of approximately $3.9 billion USD of debt.

TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include: Tampa Electric, an integrated regulated electric utility which serves more than 700,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution utility which serves more than 350,000 customers across Florida; and New Mexico Gas Co., a regulated gas distribution utility which serves more than 510,000 customers across New Mexico.

Upon completion of the Transaction, Emera will have over $26 billion of assets and more than 2.4 million electric and gas customers. Emera has fully committed $6.5 billion USD bridge facilities in place, and financed a portion of the pending acquisition through the sale of $2.185 billion convertible unsecured subordinated debentures, which are described below. The balance of the permanent financing of the Transaction is expected to be obtained before or after closing, from one or more capital market offerings, including debt and preferred equity, as well as from internally generated sources. On October 16, 2015, Emera permanently reduced the USD bridge facilities in the amount of $588.3 million USD with the proceeds of the first instalment of the convertible debentures and the proceeds from the Bear Swamp financing discussed below.

The closing of the Transaction is expected to occur mid-2016. It is subject to certain regulatory and government approvals, including approval by the New Mexico Public Regulation Commission, the Committee on Foreign Investment in the United States, and the satisfaction of closing conditions. Below is a summary of the approvals received to date:

• Shareholder approval on December 3, 2015;

• FERC approval on January 21, 2016;

• Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

On December 14, 2015, the New Mexico Public Regulation Commission set a hearing to begin on May 23, 2016 for the joint application of the change in control of New Mexico Gas Co. effected by the Transaction.

Convertible Debentures Represented By Instalment Receipts

To finance a portion of the pending acquisition of TECO Energy, Emera, through a direct wholly owned subsidiary (the “Selling Debentureholder”), on September 28, 2015, completed the sale of $1.9 billion aggregate principal amount of 4.0% convertible unsecured subordinated debentures, represented by instalment receipts (the “Debentures” or the “Debenture Offering”).

On October 2, 2015, in connection with the Debenture Offering, the underwriters fully exercised an over-allotment option and purchased an additional $285 million aggregate principal amount of Debentures at the Debenture Offering price. The sale of the additional Debentures brought the aggregate proceeds of the Debenture Offering to $2.185 billion, assuming payment of the final instalment.

The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which $333 was paid on closing of the Debenture Offering and the remaining $667 (the “Final Instalment”) is payable on a date (“Final Instalment Date”) to be fixed following satisfaction of conditions precedent to the closing of the acquisition of TECO Energy.

Prior to the Final Instalment Date, the Debentures are represented by instalment receipts. The instalment receipts began trading on the Toronto Stock Exchange (“TSX”) on September 28, 2015 under the symbol “EMA.IR”. The Debentures will not be listed. The Debentures will mature on September 29, 2025 and bear interest at an annual rate of four per cent per $1,000 principal amount of Debentures until and

16

including the Final Instalment Date, after which the interest rate will be 0 per cent. Based on the first instalment of $333 per $1,000 principal amount of Debentures, the effective annual yield to and including the Final Instalment Date is 12 per cent, and the effective annual yield thereafter is 0 per cent.

If the Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Debenture Offering, holders of Debentures who have paid the final instalment on or before the Final Instalment Date will be entitled to receive, on the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, an amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Debenture Offering had the Debentures remained outstanding and continued to accrue interest until and including such date (the “Make-Whole Payment”). No Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary of the closing of the Debenture Offering. Under the terms of the instalment receipt agreement, Emera agreed that until such time as the Debentures have been redeemed in accordance with the foregoing or the Final Instalment Date has occurred, the Company will at all times hold (on a consolidated basis) short-term USD investment grade securities or have cash on hand of not less than the aggregate amount of the first instalment paid on the closing of the Debenture Offering and the exercise of the over-allotment option, in the event of a mandatory redemption.

At the option of the holders and provided that payment of the Final Instalment has been made, each

Debenture will be convertible into common shares of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $41.85 per common share. This is a conversion rate of 23.8949 common shares per $1,000 principal amount of Debentures, subject to adjustment in certain events.

Prior to the Final Instalment Date, the Debentures may not be redeemed by the Company, except that Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions precedent to the closing of the acquisition of TECO Energy will not be satisfied; (ii) termination of the acquisition agreement; and (iii) April 24, 2017, if notice of the Final Instalment Date has not been given to holders on or before April 21, 2017. Upon any such redemption, the Company will pay for each Debenture: (i) $333 plus accrued and unpaid interest to the holder of the instalment receipt; and (ii) $667 to the Selling Debentureholder on behalf of the holder of the instalment receipt in satisfaction of the Final Instalment. In addition, after the Final Instalment Date, any Debentures not converted may be redeemed by Emera at a price equal to their principal amount plus any unpaid interest which accrued prior to and including the Final Instalment Date.

At maturity, Emera will repay the principal amount of any Debentures not converted and remaining outstanding in cash. Emera has the right to satisfy the obligation to repay the principal amount due in common shares, which will be valued at 95 per cent of the weighted-average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

The proceeds of the first instalment and the overallotment of the Debenture Offering were $727.6 million, or $681.4 million net of issue costs, and are held and invested in short-term USD investment grade securities. The convertible debentures represented by instalment receipts are classified as a current liability on the Consolidated Balance Sheets as the pending acquisition of TECO Energy is expected to close in fiscal 2016. The mark-to-market effect related to the translation of the US foreign currency to Canadian currency is recorded in income, but not reflected in adjusted net income.

The net proceeds of the final instalment payment of the Debenture Offering are expected to be, in aggregate, approximately $1.4 billion and will be used, together with the net proceeds of the first instalment payment, to finance, directly or indirectly, the pending acquisition of TECO Energy and other acquisition related costs. To mitigate the foreign currency translation risk associated with the final instalment Emera entered into USD denominated forward contracts, which are recorded on the Consolidated Balance Sheets. The mark-to-market effect on these hedges is reported in the income statement and impacts income, but is not reflected in adjusted income.

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Approximately $22.1 million ($15.2 million after-tax) in interest expense associated with the Debentures was recognized in Q4 2015 and $22.7 million ($15.7 million after-tax) was incurred during fiscal 2015 (2014 – nil).

Increase in Common Dividend

On August 10, 2015, Emera’s Board of Directors approved an increase in the annual common share dividend rate from $1.60 to $1.90. The first payment was effective November 16, 2015.

Maritime Link Project

On March 6, 2015, NSPML entered into the third of the Maritime Link Project’s three major contracts: construction of approximately 400 kilometres of transmission lines in the provinces of Newfoundland and Labrador and Nova Scotia.

On April 9, 2015, NSPML and the Assembly of Nova Scotia Mi’kmaq Chiefs signed a Socio-Economic Agreement for the Maritime Link Project. Under this agreement, NSPML will support ongoing engagement and commitments made during the Environmental Assessment process, including Mi’kmaq participation in environmental monitoring and employment and business opportunities for Mi’kmaq people.

Emera Maine

Return on Equity (“ROE”) Complaints

On March 3, 2015, the FERC affirmed its June 19, 2014 order approving an ROE on transmission assets of 10.57 per cent for the period October 1, 2011 to December 31, 2012. This order is in respect of the ROE complaint filed with the FERC by the Attorney General of Massachusetts and other parties on September 30, 2011. The March 3, 2015 order is subject to appeal, and a decision is not expected until Q1 2016 at the earliest.

Recent Financing Activity

Emera

On July 3, 2015, Emera announced it would not redeem the 6,000,000 Cumulative 5-Year Rate Reset First Preferred Shares, Series A Shares (“the Series A Shares”).

On August 17, 2015, Emera announced that 2,135,364 of its 6,000,000 issued and outstanding Series A Shares were tendered for conversion, on a one-for-one basis into Cumulative Floating Rate First Preferred Shares, Series B (the “Series B Shares”). As a result of the conversion, Emera has 3,864,636 Series A Shares and 2,135,364 Series B Shares issued and outstanding. The holders of Series B Shares will be entitled to receive floating rate cumulative preferred cash dividends, as and when declared by the Board of Directors. The dividends are payable quarterly in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-bill Rate on the applicable reset date plus 1.84 per cent, by $25.00.

NSPI

NSPI Series I $70 million 8.40 per cent medium-term notes (“MTN”) matured on October 23, 2015 and were repaid.

On October 15, 2015, NSPI redeemed all of its outstanding Cumulative Redeemable First Preferred Shares, Series D for a redemption price of $25.00 per share for a total of $135 million.

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On April 30, 2015, NSPI completed the issuance of $175 million Series AA MTN. The Series AA notes bear interest at a rate of 3.612 per cent per annum until May 1, 2045. The proceeds of the note offering were used for general corporate purposes, including the repayment of maturing corporate term debt.

Brunswick Pipeline

On February 18, 2015, Brunswick Pipeline completed a senior secured financing consisting of a $250 million non-revolving term credit facility bearing interest at bankers’ acceptances rates plus 1.75 per cent and expiring on February 18, 2019. The proceeds were used to reduce borrowings under Emera’s revolver, which was previously used to finance the maturity and repayment of an MTN in October 2014.

Emera Energy

On October 8, 2015, Bear Swamp refinanced its $125 million USD bank debt that was due to mature in 2017 and issued $400 million USD in senior secured 10-year bonds, with $375 million USD at a fixed rate of 4.89 per cent, and $25 million USD at a floating rate of LIBOR plus 2.70 per cent. The proceeds of this financing were used to repay existing debt and provide working capital to the joint venture, with the remainder shared equally between Emera and its joint venture partner. After fees and expenses, Emera received a $178.7 million ($137.3 million USD) non-taxable distribution in Q4 2015.

Appointments

Executive

On January 15, 2016, Greg Blunden was appointed Chief Financial Officer (“CFO”) of Emera, effective March 1, 2016. Mr. Blunden has held financial leadership roles at Emera, Emera Maine and NSPI. Most recently, Mr. Blunden was Vice President, Corporate Strategy & Planning.

On January 15, 2016, Emera’s current CFO, Scott Balfour, was appointed Chief Operating Officer, Northeast and Caribbean, effective March 1, 2016. Mr. Balfour will provide senior executive leadership for Emera’s existing operations, including NSPI, Emera Energy, Emera Maine, Emera Caribbean, Emera Brunswick Pipeline and Emera Utility Services.

On January 15, 2016, Wayne O’Connor was appointed Vice President, Corporate Strategy & Planning for Emera, effective March 1, 2016. Mr. O’Connor will coordinate Emera’s planning and strategy development efforts to grow and expand the Company’s business. Previously, he was Executive Vice-President of Operations at NSPI.

On September 22, 2015, Rob Bennett was appointed President and Chief Executive Officer of Emera U.S. Inc., a wholly owned subsidiary of Emera, to lead the integration of TECO Energy. Previously, Mr. Bennett had been the Chief Operating Officer, Eastern Canada.

On August 31, 2015, Roman Coba was appointed Chief Information Officer of Emera.

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OUTSTANDING COMMON STOCK DATA

Common stock Issued and outstanding:	millions of shares		millions of Canadian dollars
December 31, 2013		132.89	$	1,703.0
Issuance of common stock		8.66		242.8
Issued for cash under Purchase Plans at market rate		1.97		66.6
Discount on shares purchased under Dividend Reinvestment Plan		—		(3.0	)
Options exercised under senior management stock option plan		0.26		6.2
Employee Share Purchase Plan		—		0.8
December 31, 2014		143.78	$	2,016.4
Issuance of common stock (1)		1.25		53.7
Issued for cash under Purchase Plans at market rate		2.10		88.3
Discount on shares purchased under Dividend Reinvestment Plan		—		(4.1	)
Options exercised under senior management stock option plan		0.08		2.3
Employee Share Purchase Plan		—		0.9
December 31, 2015		147.21	$	2,157.5

(1) On December 17, 2015, Emera issued 1.25 million common shares to facilitate the creation and issuance of 5.0 million depositary receipts in connection with the ECI share acquisition. The depositary receipts are listed on the Barbados Stock Exchange.

As at January 29, 2016, the amount of issued and outstanding common shares was 147.3 million.

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share units, for the three months ended December 31, 2015 was 146.8 million (2014 – 144.2 million). The weighted average shares of common stock outstanding – basic for the year ended December 31, 2015 was 145.8 million (2014 – 143.2 million).

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NSPI

Overview

NSPI was created in 1992 through the privatization of the Crown corporation Nova Scotia Power Corporation (“NSPC”). NSPI is a fully-integrated regulated electric utility and is the primary electricity supplier in Nova Scotia, Canada. NSPI has $4.6 billion of assets and provides electricity generation, transmission and distribution services to approximately 506,000 customers. NSPI owns 2,483 MW of generating capacity, of which approximately 50 per cent is coal-fired; 28 per cent of which is natural gas and/or oil; 19 per cent of which is hydro and wind and 3 per cent of which is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from independent power producers (“IPP”). These IPPs own and operate 496 MW of wind and biomass fueled generation capacity, which will increase to 552 MW in 2016. NSPI also owns approximately 5,000 kilometres of transmission facilities and 27,000 kilometres of distribution facilities. NSPI has a workforce of approximately 1,700 people.

NSPI is a public utility as defined in the Public Utilities Act (Nova Scotia) (“Act”) and is subject to regulation under the Act by the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings from time to time at its request or at the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates established to recover prudently incurred costs of providing electricity service to customers, and to provide an appropriate return to investors. NSPI’s target regulated return on equity (“ROE”) range for 2015 and 2016 is 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40.0 per cent.

NSPI has a fuel adjustment mechanism (“FAM”), approved by the UARB, allowing NSPI to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. Differences between prudently incurred fuel for generation and purchased power and certain fuel-related costs (“Fuel Costs”) and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

A settlement agreement, approved by the UARB in November 2014, resulted in approximately $56.0 million of the outstanding FAM regulatory asset balance from the prior year being collected in 2015. Residential customers did not experience a rate increase in 2015, as the FAM recovery of approximately $56.0 million was offset with the removal of charges previously included in NSPI billings. The charges were on behalf of Efficiency Nova Scotia, a program run by the Province of Nova Scotia and regulated by the UARB. Certain industrial customer classes experienced rate increases of approximately 1.5 per cent in 2015.

On December 21, 2015, the UARB approved NSPI’s setting of the 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as submitted in NSPI’s August and November 2015 filings. The recovery of these costs will begin January 1, 2016. The approved customer rates reset the base cost of fuel rate for 2016 and seek to recover $13.7 million of prior years’ unrecovered Fuel Costs in 2016. This results in a combined rate decrease for customers of approximately 1 per cent.

In December 2015, the Electricity Plan Implementation (2015) Act (“the Electricity Plan Act”) was enacted by the Province of Nova Scotia. Further information is included in the NSPI Regulated Fuel Adjustment Mechanism and Fixed Cost Deferrals Section.

Although the market in Nova Scotia is otherwise mature, the transformation of energy supply to lower emission sources has driven organic growth within NSPI as new investments have been made in renewable generation and system reliability projects.

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The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix. The most recent target, for years 2015 through 2019, is 25 per cent of electrical energy which will be derived from renewable sources. This target was met for 2015, with 27 per cent of NSPI’s generation mix derived from renewable sources. In 2020, the target is 40 per cent of electrical energy to be derived from renewable sources.

Review of 2015

NSPI Net Income

For the millions of Canadian dollars (except per share amounts)	Three months ended December 31					Year ended December 31
	2015			2014		2015		2014		2013
Operating revenues – regulated	$	338.5		$	332.7	$	1,417.3	$	1,348.2	$	1,334.9
Regulated fuel for generation and purchased power (1)		132.4			127.4		542.8		511.7		556.9
Regulated fuel adjustment mechanism and fixed cost deferrals		10.3			5.7		41.6		46.6		(40.8	)
Operating, maintenance and general		66.2			68.9		298.1		273.6		272.3
Provincial grants and taxes		9.7			9.6		38.5		38.3		37.7
Depreciation and amortization		52.2			53.0		206.5		204.0		213.8
Total operating expenses		270.8			264.6		1,127.5		1,074.2		1,039.9
Income from operations		67.7			68.1		289.8		274.0		295.0
Other expenses net (2)		—			0.7		5.7		5.0		7.1
Interest expense, net		31.3			29.9		122.1		116.5		119.6
Income before provision for income taxes		36.4			37.5		162.0		152.5		168.3
Income tax expense (recovery)		(6.4	)		5.5		23.4		19.7		34.4
Net income of Nova Scotia Power Inc.		42.8			32.0		138.6		132.8		133.9
Preferred stock dividends (3)		2.7			1.9		8.7		7.9		7.9
Contribution to consolidated net income	$	40.1		$	30.1	$	129.9	$	124.9	$	126.0
Contribution to consolidated earnings per common share	$	0.27		$	0.21	$	0.89	$	0.87	$	0.95
EBITDA	$	119.9		$	120.4	$	490.6	$	473.0	$	501.7

(1) Regulated fuel for generation and purchased power includes affiliate transactions and proceeds from the sale of natural gas.

(2) Other expenses, net is included in “Other income (expenses), net” on the Consolidated Statements of Income.

(3) Preferred stock dividends are included in “Non-controlling interest in subsidiaries” on the Consolidated Statements of Income. In Q4 2015, NSPI redeemed its preferred shares.

NSPI’s contribution to consolidated net income increased $10.0 million to $40.1 million in Q4 2015 compared to $30.1 million in Q4 2014. For the year ended December 31, 2015, NSPI’s contribution to consolidated net income increased $5.0 million to $129.9 million in 2015 compared to $124.9 million in 2014.

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Highlights of the changes are summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31			Year ended December 31
Contribution to consolidated net income – 2013				$	126.0
Increased electric margin primarily due to increased non-fuel electric revenues across all customers groups as a result of increased electricity pricing, partially offset by the FAM audit disallowance					15.8
Decreased fixed cost deferrals primarily due to an increase in the non-fuel revenues and lower depreciation and amortization					(43.2	)
Decreased depreciation and amortization primarily due to reductions in regulatory amortization (see Regulatory Amortization section below for explanation)					9.8
Decreased interest expense, net primarily due to lower levels of long-term debt					3.1
Decreased income tax expense primarily due to increased tax deductions related to higher pension contributions for 2014, decreased income before provision for income taxes and decreased non-deductible regulatory amortization, partially offset by a non-recurring change in unrecognized tax benefits in 2013 due to the enactment of tax legislation related to preferred stock dividends					14.7
Other, net (1)					(1.3	)
Contribution to consolidated net income – 2014	$	30.1		$	124.9
Increased electric margin (see Electric Margin section below for explanation)		0.5			13.0
Increased fixed cost deferrals year-over-year primarily due to the new DSM regulatory deferral commencing in 2015, partially offset by an increase in the amount of non-fuel revenues deferred compared to 2014		(1.7	)		30.5
Decreased OM&G expenses quarter-over-quarter primarily due to non-recurring 2014 expenses and increased overhead credits on capital projects, partially offset by higher pension and DSM costs; year-over-year increase is primarily due to increased DSM program costs as a results of legislation, effective January 1, 2015, requiring NSPI to purchase electricity efficiency and conservation activities and higher pension costs, partially offset by lower storm costs		2.7			(24.5	)
Increased interest expense, net primarily due to lower interest revenues related to FAM and fixed cost deferrals and higher debt levels		(1.4	)		(5.6	)
Decreased income tax expense quarter-over-quarter primarily due to a legislated change by the Province of Nova Scotia to the deferred tax treatment of South Canoe and Sable wind farms resulting in prior period deferred income taxes being recorded as regulatory assets in Q4 2015; year-over-year increase primarily due to increased income before provision for income taxes		11.9			(3.7	)
Other, net (1)		(2.0	)		(4.7	)
Contribution to consolidated net income – 2015	$	40.1		$	129.9

(1) Amounts exclude variances included in the calculation of electric margin.

Operating Revenues – Regulated

NSPI’s Operating Revenues – regulated include sales of electricity and other services as summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
Electric revenues	$	333.5	$	324.9	$	1,389.1	$	1,319.2	$	1,304.3
Other revenues		5.0		7.8		28.2		29.0		30.6
Operating revenues – regulated	$	338.5	$	332.7	$	1,417.3	$	1,348.2	$	1,334.9

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Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population, weather, and DSM activities. Residential and commercial electricity sales are seasonal, with Q1 being the strongest period, reflecting colder weather and fewer daylight hours in the winter.

NSPI’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other electric revenues consist primarily of sales to municipal electric utilities and revenues from street lighting.

Electric sales volumes are summarized in the following tables by customer class:

Q4 Electric Sales Volumes Gigawatt hours (“GWh”)
	2015		2014		2013
Residential		1,075		1,083		1,173
Commercial		757		767		811
Industrial		592		630		635
Other		82		75		87
Total		2,506		2,555		2,706

Annual Electric Sales Volumes GWh
	2015		2014		2013
Residential		4,484		4,370		4,394
Commercial		3,134		3,092		3,148
Industrial		2,457		2,513		2,605
Other		337		312		320
Total		10,412		10,287		10,467

Electric revenues are summarized in the following tables by customer class:

Q4 Electric Revenues millions of Canadian dollars
	2015		2014		2013
Residential	$	170.7	$	165.7	$	173.5
Commercial		100.0		97.3		100.1
Industrial		51.1		50.3		55.4
Other		11.7		11.6		13.0
Total	$	333.5	$	324.9	$	342.0

Annual Electric Revenues millions of Canadian dollars
	2015		2014		2013
Residential	$	716.0	$	669.3	$	654.0
Commercial		410.0		387.3		383.9
Industrial		213.8		213.9		218.0
Other		49.3		48.7		48.4
Total	$	1,389.1	$	1,319.2	$	1,304.3

Electric revenues increased $8.6 million to $333.5 million in Q4 2015 compared to $324.9 million in Q4 2014. For the year ended December 31, 2015, electric revenues increased $69.9 million to $1,389.1 million compared to $1,319.2 million in the same period in 2014. Highlights of the changes are summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31			Year ended December 31
Electric revenues – 2013				$	1,304.3
Increased electricity pricing effective January 1, 2014					37.9
Decreased commercial and residential sales volumes, in part due to weather					(12.5	)
Decreased industrial sales volume					(9.4	)
Other					(1.1	)
Electric revenues – 2014	$	324.9		$	1,319.2
Increased fuel related electricity pricing effective January 1, 2015		13.4			56.0
Decreased commercial and residential sales volumes as a result of decreased load quarter-over-quarter; increased commercial and residential sales volumes year-over-year primarily due to weather and load growth earlier in the year		(4.1	)		19.9
Decreased industrial sales volume		(0.6	)		(5.2	)
Other		(0.1	)		(0.8	)
Electric revenues – 2015	$	333.5		$	1,389.1

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Regulated Fuel for Generation and Purchased Power

Capacity

To ensure reliability of service, NSPI must maintain a generating capacity greater than firm peak demand. The total NSPI-owned generation capacity is 2,483 MW, which is supplemented by 496 MW contracted with IPPs and the Community Feed-In Tariff (“COMFIT”) participants. NSPI meets the planning criteria for reserve capacity established by the Maritime Control Area and the Northeast Power Coordinating Council.

NSPI facilities continue to rank among the best in Canada on performance indicators. The high availability and capability of low cost thermal generating stations provide lower-cost energy to customers. In 2015, thermal plant availability was 87.9 per cent compared to 84.2 per cent in 2014. NSPI’s four-year average for thermal plant availability is 85.1 per cent. While this availability is in line with industry standards, it is particularly significant, as the NSPI coal fleet has a higher capacity factor and better forced outage rate than the standard for its class. In addition, the Company has seen performance improvements in 2015, despite the effects of renewable integration.

Q4 Production Volumes GWh
	2015		2014		2013
Coal and petcoke		1,534		1,777		1,842
Natural gas		354		186		423
Oil		8		9		33
Purchased power – other		121		126		57
Total non-renewables		2,017		2,098		2,355
Wind and hydro – renewables		228		391		333
Biomass – renewables		63		62		67
Purchased power – renewables		434		255		214
Total renewables		725		708		614
Total production volumes		2,742		2,806		2,969
Q4 Average Fuel Costs
	2015		2014		2013
Dollars per megawatt hour (“MWh”)	$	48	$	45	$	49

Annual Production Volumes GWh
	2015		2014		2013
Coal and petcoke		6,364		6,609		7,098
Natural gas		1,302		1,468		1,317
Oil		265		153		89
Purchased power – other		428		353		491
Total non-renewables		8,359		8,583		8,995
Wind and hydro – renewables		1,275		1,357		1,234
Biomass – renewables		206		258		130
Purchased power – renewables		1,289		849		845
Total renewables		2,770		2,464		2,209
Total production volumes		11,129		11,047		11,204
Annual Average Fuel Costs
	2015		2014		2013
Dollars per MWh	$	49	$	46	$	50

Average unit Fuel Costs increased in Q4 2015 compared to Q4 2014 primarily due to generation costs associated with the COMFIT program and decreased NSPI-owned hydro generation partially due to the largest hydro site undergoing a planned overhaul this quarter. These costs are partially offset by favourable commodity pricing. Year-over-year, average unit Fuel Costs increased in 2015 compared to the same period in 2014 primarily due to generation costs associated with the COMFIT program and increased load, partially offset by favourable commodity pricing.

NSPI’s Fuel Costs are affected by commodity prices and generation mix which is largely dependent on economic dispatch of the generating fleet, bringing the lowest cost options on stream first (after renewable energy from independent power producers, including COMFIT participants), such that the incremental cost of production increases as sales volumes increase. Generation mix may also be affected by plant outages, availability of renewable generation, plant performance and compliance with environmental standards and regulations.

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Historically, coal and petcoke have the lowest per unit fuel cost, after NSPI-owned regulated hydro and wind, which have no fuel cost component. Purchased power, natural gas, oil and biomass have the next lowest fuel cost, depending on the relative pricing of each.

The generation mix is transforming with the addition of new non-dispatchable renewable energy sources such as wind, which typically has a higher cost per megawatt hour (“MWh”).

A large portion of NSPI’s fuel supply comes from international suppliers and is subject to commodity price and foreign exchange risk. NSPI seeks to manage this risk through the use of financial hedging instruments and physical contracts and utilizes a portfolio strategy for fuel procurement with a combination of long, medium, and short-term supply agreements. It also provides for supply and supplier diversification. Foreign exchange risk is managed through forward and swap contracts. Fuel contracts may also be exposed to broader global conditions which may include impacts on delivery reliability and price, despite contracted terms. NSPI has a FAM that enables the Company to seek recovery of Fuel Costs to further manage this risk.

Regulated fuel for generation and purchased power increased $5.0 million to $132.4 million in Q4 2015 compared to $127.4 million in Q4 2014. For the year ended December 31, 2015, regulated fuel for generation and purchased power increased $31.1 million to $542.8 million compared to $511.7 million in 2014. Highlights of the changes are summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31			Year ended December 31
Regulated fuel for generation and purchased power – 2013				$	556.9
Decreased commodity prices					(29.0	)
Changes in generation mix and plant performance					(11.1	)
Decreased sales volumes					(8.8	)
Increased hydro and NSPI-owned wind production					(8.1	)
Changes in solid fuel mix					14.4
Other					(2.6	)
Regulated fuel for generation and purchased power – 2014	$	127.4		$	511.7
Decreased commodity prices		(6.6	)		(38.3	)
Changes in generation mix and plant performance		8.5			51.1
Increased (decreased) sales volumes		(1.5	)		10.6
Decreased hydro and NSPI-owned wind production		5.0			3.0
Other		(0.4	)		4.7
Regulated fuel for generation and purchased power – 2015	$	132.4		$	542.8

Regulated Fuel Adjustment Mechanism (“FAM”) and Fixed Cost Deferrals

Regulated Fuel Adjustment Mechanism and FAM Regulatory Deferral

NSPI has a Regulated Fuel Adjustment Mechanism which enables the Company to seek recovery of Fuel Costs through regularly scheduled rate adjustments. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

On December 21, 2015, the UARB approved NSPI’s setting of the 2016 base cost of fuel rates and its recovery of prior period unrecovered fuel related costs as submitted in NSPI’s filings. The recovery of these costs will begin January 1, 2016. The approved customer rates reset the base cost of fuel rate for 2016 and seek to recover $13.7 million of prior years’ unrecovered Fuel Costs in 2016. This results in a combined average rate decrease for NSPI customers of approximately 1 per cent.

On December 18, 2015, the Electricity Plan Act was enacted by the Province of Nova Scotia. The Electricity Plan Act requires NSPI to file a three-year rate plan for Fuel Costs in Q1 2016 and to file a

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three-year general rate application to change non-fuel rates by April 30, 2016, if required by NSPI. The primary goal of the Electricity Plan Act is to provide rate stability over those years. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates during this period will be deferred to a FAM regulatory asset or liability and recovered from or returned to customers subsequent to 2019.

The Electricity Plan Act directs NSPI to apply non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of tax benefits for the South Canoe and Sable Wind Projects is to be reserved to be applied to the FAM in the 2017 to 2019 period. The exception to this direction is to apply a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would have been otherwise required. This amount totals $4.6 million. As a result, as at December 31, 2015, NSPI has deferred $4.6 million of excess non-fuel revenues to 2016 and $40.1 million of excess non-fuel revenues for the periods 2017 to 2019.

In November 2014, the UARB approved a settlement agreement that has resulted in $56.0 million of the 2014 outstanding FAM balance being collected in 2015. The settlement agreement also reduced the outstanding FAM balance of $86.1 million by $38.2 million through an offset from the amount owing to customers as a result of an agreement to allocate non-fuel revenues above NSPI’s allowed range of return to the FAM balance, such that the December 31, 2014 FAM regulatory asset was $47.9 million.

Through a related settlement agreement with stakeholders approved in December 2014, NSPI agreed to apply non-fuel revenues above that required to achieve its approved range of return to reduce the FAM deferral account. This was effective as of January 1, 2015, until the next GRA approval or similar process where non-fuel rates are adjusted. This settlement agreement required NSPI to contribute a minimum of $41.3 million to the FAM deferral account by the end of 2015.

As at December 31, 2015, NSPI had exceeded the minimum required contribution of $41.3 million through the $38.2 million contributed in 2014, referred to above, and an additional $44.7 million applied in 2015. Of the $44.7 million applied in 2015, $18.3 million relates to changes to the South Canoe and Sable Wind Projects tax treatment.

Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. On July 2, 2014, the FAM audit findings and recommendations relating to fiscal 2012 and 2013 were publicly released, and on January 20, 2015, the UARB disallowed $6.0 million of 2012 and 2013 fuel-related costs, which included interest of $0.9 million. The disallowance resulted in a reduction in the amount of FAM deferral in 2014 and resulted in an after-tax impact to 2014 net income of $3.3 million. The audit for fiscal 2014 and 2015 is currently underway.

The FAM in the Statements of Income includes the effect of Fuel Costs in both the current and preceding years, specifically:

• The difference between actual Fuel Costs and amounts recovered from customers in the current year. This amount is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities”; and

• The recovery from (rebate to) customers of under (over) recovered Fuel Costs from prior years.

The FAM regulatory asset (liability) includes amounts recognized as a regulated fuel adjustment mechanism and associated interest that is included in “Interest expense, net” on the Consolidated Statements of Income. Details of the FAM regulatory asset (liability), classified in “Regulatory assets or Regulated liabilities” on the Consolidated Balance Sheets, are summarized in the following table:

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millions of Canadian dollars	2015			2014
FAM regulatory asset – Balance as at January 1	$	47.9		$	86.4
Under (over) recovery of current year Fuel Costs		24.1			(1.3	)
Rebate to (recovery from) customers of prior years’ Fuel Costs		(56.0	)		—
FAM audit disallowance, including interest adjustment		—			(6.0	)
Application of non-fuel revenues		(44.7	)		(38.2	)
Interest on FAM balance		0.4			7.0
FAM regulatory asset (liability) – Balance as at December 31	$	(28.3	)	$	47.9

Of the $44.7 million non-fuel revenues applied in 2015, $40.1 million is to be applied to the FAM during the 2017 to 2019 period and $4.6 million will be applied in 2016.

Regulated Fixed Cost Deferrals and Fixed Cost Recovery Deferral Regulatory Assets

NSPI has the following regulatory assets arising from UARB approved fixed cost deferral mechanisms:

DSM Deferral

In April 2014, the Government of Nova Scotia announced new energy efficiency legislation to remove a previous charge for conservation and efficiency programs from power bills of Nova Scotia customers effective January 1, 2015. In addition, the legislation requires NSPI to purchase electricity efficiency and conservation activities (“Program Costs”) from EfficiencyOne, the provincially appointed franchisee to deliver energy efficiency programs to Nova Scotians. The Program Costs were set for 2015 at $35.0 million and have been deferred as a regulatory asset and recoverable from customers over an eight-year period beginning in 2016. In August 2015, the UARB approved a budget of $102.0 million for the three-year period of 2016 through 2018. The Electricity Plan Act has placed a cap of $34.0 million on the 2019 DSM spending. The 2016 DSM cost of $24.7 million will not be deferred. A decision of the timing of the cost recovery for 2017 through 2019 will be made at a future date.

The Program Costs are recorded in “OM&G”, with an offsetting credit in “Regulated fuel adjustment mechanism and fixed cost deferrals” on Emera’s Consolidated Income Statements, with no effect on net earnings, with the exception of interest on the balance.

Details of the DSM regulatory asset, classified in “Regulatory assets” on the Consolidated Balance Sheets, are summarized in the following table:

millions of Canadian dollars	2015
DSM regulatory asset – Balance as at January 1	$	—
Current period Program Costs		35.0
Interest on DSM balance		1.4
DSM regulatory asset – Balance as at December 31	$	36.4

2013/2014 Rate Stabilization Fixed Cost Recovery Deferral

In December 2012, the UARB approved a deferral of recovery of certain fixed costs for fiscal 2013 and 2014 as part of a rate stabilization plan. As previously noted above under the Regulated Fuel Adjustment Mechanism, the resulting regulatory liability at the end of 2014 of $38.2 million was applied against the FAM regulatory asset balance in 2014 and is included in the application of non-fuel revenues line in the table above.

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Electric Margin

NSPI distinguishes electric revenues related to the recovery of Fuel Costs (“fuel electric revenues”) from revenues related to the recovery of non-fuel costs (“non-fuel electric revenues”) because the FAM effectively seeks to recover all prudently incurred fuel costs, and consequently, Fuel Costs and revenues related thereto (Fuel Electric Revenues) do not have a material effect on NSPI’s electric margin or net income.

Electric margin is influenced primarily by revenues relating to non-fuel costs. NSPI’s customer classes contribute differently to the Company’s non-fuel electric revenues, with residential and commercial customers contributing more than industrial customers under current rates. Accordingly, changes in residential and commercial load, largely due to the effects of weather, from general economic conditions and from DSM have the largest effect on non-fuel electric revenues and electric margin. Changes in industrial load, which are generally due to economic conditions, have less of an effect on non-fuel electric revenues than would a similar volume change in residential and commercial load.

The addition of new generation sources to meet legislated greenhouse gas emission reductions and renewable generation requirements is among the drivers increasing NSPI’s fixed costs. Electric margin, which represents the revenues available to cover these costs, has increased in a corresponding manner.

Operating revenues are summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014(1)		2013(1)
Fuel electric revenues – current year	$	123.7	$	124.2	$	518.5	$	512.5	$	488.7
Fuel electric revenues – recovery of preceding years		13.4		—		56.0		—		29.8
Non-fuel electric revenues		196.4		200.7		814.6		806.7		785.8
Other revenues		5.0		7.8		28.2		29.0		30.6
Operating revenues	$	338.5	$	332.7	$	1,417.3	$	1,348.2		1,334.9

Electric margin is summarized in the following table:

Fuel electric revenues – current year	$	123.7		$	124.2		$	518.5		$	512.5		$	488.7
Fuel electric revenues – recovery of preceding years		13.4			—			56.0			—			29.8
Total fuel electric revenues		137.1			124.2			574.5			512.5			518.5
Regulated fuel for generation and purchased power		(132.4	)		(127.4	)		(542.8	)		(511.7	)		(556.9	)
Regulated fuel adjustment mechanism		(4.4	)		(1.5	)		(31.9	)		(6.4	)		37.8
Fuel-related foreign exchange gain (loss) (2)		(0.3	)		(0.1	)		0.2			0.5			0.6
Net fuel revenue (expense)		—			(4.8	)		—			(5.1	)		—
Non-fuel electric revenues		196.4			200.7			814.6			806.7			785.8
Electric margin	$	196.4		$	195.9		$	814.6		$	801.6		$	785.8

(1) NSPI removed “Fixed cost deferrals” from its calculation of electric margin in Q2 2014 as management believed it better reflected its business operations. Prior periods have been retroactively restated.

(2) As reported in “Other income (expenses) net”, on the Consolidated Statement of Income.

NSPI’s electric margin increased $0.5 million to $196.4 million in Q4 2015 compared to $195.9 million in Q4 2014 primarily due to a Q4 2014 FAM audit disallowance, partially offset by decreased residential and commercial load. NSPI’s electric margin for the year ended December 31, 2015 increased $13.0 million to $814.6 million compared to $801.6 million in 2014 primarily due to increased residential load, largely due to weather and a FAM audit disallowance in 2014.

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Q4 Average Electric Margin (Dollars per MWh)
	2015		2014		2013
Dollars per MWh	$	78	$	77	$	76

Annual Average Electric Margin (Dollars per MWh)
	2015		2014		2013
Dollars per MWh	$	78	$	78	$	75

NSPI’s electric margin per MWh is consistent quarter-over-quarter and year-over-year.

Regulatory Amortization

Regulatory amortization is included in “Depreciation and amortization” on the Consolidated Statements of Income. Highlights of the changes in regulatory amortization are summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31			Year ended December 31
Regulatory amortization – 2013	$			$	37.4
Decreased pre-2003 income tax regulatory asset amortization (1)					(14.0	)
2012 Large Industrial Customers FCR amortization, which commenced in 2013, following the 2013 General Rate Application settlement agreement					2.4
Other regulatory amortization					(0.9	)
Regulatory amortization – 2014	$	8.9		$	24.9
Decreased 2012 Large Industrial Customers Fixed Cost Recovery amortization, which commenced in 2013, following the 2013 General Rate Application settlement agreement		(2.7	)		(2.7	)
Other regulatory amortization		(1.6	)		(1.4	)
Regulatory amortization – 2015	$	4.6		$	20.8

(1) The UARB’s 2010 ROE decision has allowed NSPI flexibility in the recognition of additional amortization of the pre-2003 income tax regulatory asset in current periods, which accordingly reduces amortization in future periods resulting in a lower customer rate requirement.

Provincial Grants and Taxes

NSPI pays annual grants to the Province of Nova Scotia in lieu of municipal taxation other than deed transfer tax.

Income Taxes

NSPI is subject to corporate income tax at the statutory rate of 31.0 per cent (combined federal and provincial income tax rate) and Part VI.1 tax relating to preferred stock dividends at the statutory rate of 40.0 per cent. NSPI also receives a reduction in its corporate income tax otherwise payable related to the Part VI.1 tax deduction of 43.4 per cent of preferred stock dividends.

Non-GAAP Measure

Electric Margin Reconciliation

“Electric margin” is a non-GAAP financial measure used to show the amounts that NSPI retains to recover its non-fuel costs, as effectively all prudently incurred Fuel Costs are recovered through the FAM. NSPI’s electric margin may not be comparable to other companies’ electric margin measures, but in management’s view appropriately reflects NSPI’s regulatory framework. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance. Electric margin was discussed in the Financial Review Electric Margin section above.

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For the millions of Canadian dollars	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
Income from operations	$	67.7	$	68.1	$	289.8	$	274.0	$	295.0
Less:
Fuel electric revenues – current and preceding years		137.1		124.2		574.5		512.5		518.5
FAM audit disallowance		—		4.8		—		5.1		—
Other revenues		5.0		7.8		28.2		29.0		30.6
Add back:
Regulated fuel for generation and purchased power		132.4		127.4		542.8		511.7		556.9
Operating, maintenance and general		66.2		68.9		298.1		273.6		272.3
Property, state and municipal taxes		9.7		9.6		38.5		38.3		37.7
Depreciation and amortization		52.2		53.0		206.5		204.0		213.8
Regulated fuel adjustment mechanism and fixed cost deferrals		10.3		5.7		41.6		46.6		(40.8	)
Electric margin	$	196.4	$	195.9	$	814.6	$	801.6	$	785.8

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EMERA MAINE

Overview

Emera Maine is a transmission and distribution (“T&D”) electric utility with assets of approximately $1.1 billion serving approximately 158,000 customers in the State of Maine in the United States. Effective January 1, 2014, Bangor Hydro Electric Company (“Bangor Hydro”) and Maine Public Service Company (“MPS”) merged, becoming Emera Maine.

Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through Emera Maine’s T&D networks. Emera Maine owns and operates approximately 1,700 kilometres of transmission facilities and 15,000 kilometres of distribution facilities. Emera Maine’s workforce is approximately 400 people.

Approximately 55 per cent of Emera Maine’s electric revenue represents distribution operations, 31 per cent is associated with local transmission operations and 14 per cent relates to stranded cost recoveries. The rates for each element are established in distinct regulatory proceedings.

Distribution Operations

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. Prior to July 1, 2014, the allowed ROE was 10.2 per cent, on a common equity component of 50 per cent. On July 1, 2014, Emera Maine’s distribution rates increased by nine per cent. Effective July 1, 2014, the allowed ROE became 9.55 per cent, on a common equity component of 49 per cent.

Transmission Operations

There are two transmission districts in Emera Maine, corresponding to the service territories of the two pre-merger entities.

Bangor Hydro District

Local transmission rates for Bangor Hydro District (the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook) are regulated by the FERC and set annually on June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. The allowed ROE up to October 15, 2014, for these local transmission investments, was 11.14 per cent. Effective October 16, 2014, the allowed ROE changed to 10.57 per cent, pending two outstanding complaints filed with the FERC to challenge the ISO-New England (“ISO-NE”) Open Access Transmission Tariff-allowed base ROE of 11.14 per cent. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015, transmission rates for the Bangor Hydro District increased by approximately 21 per cent in connection with its annual transmission formula rate filing (2014 – increased by 13 per cent). The increase is associated primarily with the under-recovery of prior year regional transmission revenues collected in local rates, as well as the recovery of increased transmission plant in service.

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The Bangor Hydro District’s bulk transmission assets are managed by ISO-NE as part of a region-wide pool of assets. ISO-NE manages the region’s bulk power generation and transmission systems and administers the open access transmission tariff. Currently, the Bangor Hydro District along with all other participating transmission providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is based on prior year regionally funded transmission investments, adjusted for current year forecasted investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments ranged from 11.64 per cent to 12.64 per cent. Effective October 16, 2014, the transmission investments allowed ROE changed to a range from 11.07 per cent to 11.74 per cent, pending the two aforementioned complaints filed with FERC. The common equity component is based upon the prior calendar year average balances. The participating transmission providers are also required to contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent.

On June 1, 2015, Bangor District’s regionally recoverable transmission investments and expenses decreased by 6 per cent (2014 – increased by 7 per cent).

As at December 31, 2015, the Company had accrued $5.0 million associated with the FERC ROE complaints (2014 – $7.3 million). Refunds for the first FERC ROE complaint are being made to customers over a one-year period which began with the June 1, 2015 rate change.

MPS District

Local transmission rates for MPS District’s (the franchise electric service territory associated with the former Maine Public Service Company in the Maine counties of Aroostook and a portion of Penobscot) are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers, based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted investments. The current allowed ROE for transmission operations is 10.2 per cent. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015 the transmission rates for the MPS District decreased by approximately 24 per cent for wholesale customers (2014 – increased by 2 per cent) and on July 1, 2015 decreased by 22 per cent for retail customers (2014 – increased by 11 per cent) in connection with its annual transmission formula rate filing. These decreases were primarily due to an increase in wholesale transmission revenue that allows for a decrease in local customer transmission rates.

The MPS District electric service territory is not connected to the New England bulk power system and it is not a member of ISO-NE. MPS District is not a party to the previously discussed ROE complaints at the FERC.

Stranded Cost Recoveries

Stranded cost recoveries in Maine are set by the MPUC. Electric utilities are permitted to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC. Unlike transmission and distribution operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through rates. Generally, regulatory rates to recover stranded costs are set every three years, determined under a traditional cost-of-service approach and are fully recoverable. Each year on July 1, stranded cost rates are adjusted to reflect recovery of cost deferrals for the prior stranded costs rate year under the full recovery mechanism, as well as factor in any new stranded cost information.

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Bangor Hydro District

Bangor Hydro District’s net stranded regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract, and deferrals associated with reconciling stranded costs. These net regulatory assets total approximately $19.7 million as at December 31, 2015 (2014 – $25.1 million) or 1.8 per cent of Emera Maine’s net asset base (2014 – 2.3 per cent).

On July 1, 2014, the Bangor Hydro District stranded cost rates decreased by 10 per cent. Earlier, on March 1, 2014, stranded costs rates had increased by 20 per cent. The allowed ROE used in setting the new rates on July 1, 2014, and March 1, 2014, was 5.9 per cent, with a common equity component of 48 per cent. This July 1, 2014 rate decrease remained in effect for all of 2015, and there was no rate change on July 1, 2015.

While the stranded cost revenue requirements differ throughout the period due to changes in annual stranded costs, the actual annual stranded cost revenues are the same during the period. To stabilize the impact of the varying revenue requirements, cost or revenue deferrals are recorded as a regulatory asset or liability, and addressed in subsequent stranded cost rate proceedings, where customer rates are adjusted accordingly.

MPS District

Effective January 1, 2015, the stranded cost rates for the MPS District decreased by approximately 150 per cent. This was principally due to the flow-back to customers of certain benefits received by Emera Maine from Maine Yankee associated with litigation with the United States Department of Energy on nuclear waste disposal. The allowed ROE used in setting the new rates on January 1, 2015 was 6.75 per cent, with a common equity component of 48 per cent. The reduced stranded cost revenues are offset by reductions in expense and do not affect income. This January 1, 2015, rate decrease remained in effect for all of 2015 and there was no rate change on July 1, 2015.

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Review of 2015

Emera Maine Net Income

For the millions of USD (except per share amounts)	Three months ended December 31					For the year ended December 31
	2015			2014		2015		2014		2013
Operating revenues – regulated	$	52.6		$	55.9	$	221.6	$	219.0	$	211.2
Operating revenues – non-regulated		0.1			—		0.6		0.5		0.5
Total operating revenues		52.7			55.9		222.2		219.5		211.7
Regulated fuel for generation and purchased power		7.5			9.4		28.9		29.7		30.8
Transmission pool expense (1)		6.1			6.0		25.4		23.9		22.9
Operating, maintenance and general		14.2			10.3		49.1		47.0		44.2
Provincial, state and municipal taxes		2.8			3.2		12.8		11.5		10.2
Depreciation and amortization		9.5			9.5		36.5		43.3		35.9
Total operating expenses		40.1			38.4		152.7		155.4		144.0
Income from operations		12.6			17.5		69.5		64.1		67.7
Other income (expenses), net		(1.9	)		0.9		0.8		4.2		3.3
Interest expense, net		3.4			3.5		13.7		12.2		12.2
Income before provision for income taxes		7.3			14.9		56.6		56.1		58.8
Income tax expense (recovery)		3.4			4.6		21.0		17.7		21.6
Contribution to consolidated net income – USD	$	3.9		$	10.3	$	35.6	$	38.4	$	37.2
Contribution to consolidated net income – CAD	$	5.2		$	11.7	$	45.1	$	42.4	$	38.4
Contribution to consolidated earnings per common share – CAD	$	0.04		$	0.08	$	0.31	$	0.30	$	0.29
Net income weighted average foreign exchange rate – CAD/USD	$	1.33		$	1.14	$	1.27	$	1.10	$	1.03
EBITDA – USD	$	20.2		$	27.9	$	106.8	$	111.6	$	106.9
EBITDA – CAD	$	26.8		$	31.8	$	136.0	$	123.4	$	110.3

(1) Transmission pool expense is included in “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income.

Emera Maine’s USD contribution to consolidated net income decreased by $6.4 million to $3.9 million in Q4 2015 compared to $10.3 million in Q4 2014. For the year ended December 31, 2015, Emera Maine’s USD contribution to consolidated net income decreased by $2.8 million to $35.6 million compared to $38.4 million in 2014. Highlights of the USD net income changes are summarized in the following table:

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For the millions of US dollars	Three months ended December 31			Year ended December 31
Contribution to consolidated net income – 2013				$	37.2
Increased operating revenues primarily due to rate changes					7.8
Decreased regulated fuel for purchased power primarily due to changes in purchased power contracts					1.1
Increased OM&G expenses primarily due to decreased capitalized construction overheads and increased storm expenses					(2.8	)
Increased depreciation and amortization primarily due to increased plant in service					(7.4	)
Decreased income tax expense primarily due to decreased income before provision for income taxes, a change in estimate of prior year expected benefit of tax deductions and changes in regulatory amortization					3.9
Other					(1.4	)
Contribution to consolidated net income – 2014	$	10.3		$	38.4
(Decreased) increased operating revenues – see Operating Revenues – Regulated section below		(3.3	)		2.6
Increased OM&G primarily due to decreased capitalized construction overheads, partially offset by changes in pension and retiree medical expenses		(3.9	)		(2.1	)
Decreased depreciation and amortization due to lower depreciation rates as a result of a 2014 depreciation study and lower regulatory amortization; no change quarter-over-quarter as lower depreciation rates are offset by increased regulatory amortization		—			6.8
Decreased other income primarily due to AFUDC adjustments recognized as a result of a FERC audit		(2.8	)		(3.4	)
Decreased income tax expense quarter-over-quarter primarily due to lower income before provision for income taxes, partially offset by AFUDC adjustments recorded as a result of a FERC audit; year-over-year increase primarily due to decrease in regulatory amortization and AFUDC adjustments recorded as a result of a FERC audit		1.2			(3.3	)
Other		2.4			(3.4	)
Contribution to consolidated net income – 2015	$	3.9		$	35.6

Emera Maine’s CAD contribution to consolidated net income decreased by $6.5 million to $5.2 million in Q4 2015 from $11.7 million in Q4 2014. For the year ended December 31, 2015, Emera Maine’s CAD contribution to consolidated net income increased by $2.7 million to $45.1 million from $42.4 million in 2014. The impact of a stronger USD, increased CAD earnings quarter-over-quarter by $0.7 million for the three months ended December 31, 2015 and year-over-year $6.1 million for the year ended December 31, 2015.

Operating Revenues – Regulated

Emera Maine’s operating revenues – regulated include sales of electricity and other services as summarized in the following table:

Q4 Operating Revenues – Regulated millions of US dollars
	2015		2014		2013
Electric revenues	$	38.0	$	41.2	$	39.3
Transmission pool revenues		11.0		11.3		11.3
Resale of purchased power		3.6		3.4		3.5
Operating revenues – regulated	$	52.6	$	55.9	$	54.1

Annual Operating Revenues – Regulated millions of US dollars
	2015		2014		2013
Electric revenues	$	160.0	$	156.8	$	146.9
Transmission pool revenues		49.1		49.0		50.7
Resale of purchased power		12.5		13.2		13.6
Operating revenues – regulated	$	221.6	$	219.0	$	211.2

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Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population and weather. Electric sales pricing in Maine is regulated, and therefore can change in accordance with regulatory decisions.

Q4 Electric Sales Volumes
GWh	2015		2014		2013
Residential		199		203		209
Commercial		192		193		198
Industrial		94		104		107
Other		3		4		4
Total		488		504		518

Annual Electric Sales Volumes
GWh	2015		2014		2013
Residential		802		805		801
Commercial		781		788		798
Industrial		423		426		424
Other		14		15		15
Total		2,020		2,034		2,038

Electric revenues are summarized in the following tables by customer class:

Q4 Electric Revenues millions of US dollars
	2015		2014		2013
Residential	$	19.2	$	19.8	$	18.9
Commercial		14.8		14.7		14.2
Industrial		3.2		3.8		3.6
Other (1)		0.8		2.9		2.6
Total	$	38.0	$	41.2	$	39.3

Annual Electric Revenues millions of US dollars
	2015		2014		2013
Residential	$	76.4	$	75.8	$	71.7
Commercial		57.9		57.2		54.7
Industrial		14.1		14.2		13.1
Other (1)		11.6		9.6		7.4
Total	$	160.0	$	156.8	$	146.9

(1) Other revenue includes amounts recognized relating to FERC transmission rate refunds and other transmission revenue adjustments.

Electric revenues decreased $3.2 million to $38.0 million in Q4 2015 compared to $41.2 million in Q4 2014. For the year ended December 31, 2015, electric revenues increased $3.2 million to $160.0 million in 2015 compared to $156.8 million in 2014. Highlights of the changes are summarized in the following table:

For the millions of US dollars	Three months ended December 31			Year ended December 31
Electric revenues – 2013				$	146.9
Decreased sales volumes primarily due to weather					(0.2	)
Increased primarily due to rate changes					9.5
Decreased due to changes in amounts recognized related to the FERC ROE complaints					(2.6	)
Change in estimate for the transmission revenue					3.2
Electric revenues – 2014	$	41.2		$	156.8
Decreased sales volumes primarily due to weather		(1.2	)		(1.1	)
Increased primarily due to rate changes		0.5			3.8
Increased due to FERC transmission rate refund		3.9			6.0
Decreased due to transmission revenue adjustments		(6.4	)		(5.5	)
Electric revenues – 2015	$	38.0		$	160.0

Q4 Electric Revenue / MWh
	2015		2014		2013
Dollars per MWh	$	78	$	82	$	76

Annual Average Electric Revenue / MWh
	2015		2014		2013
Dollars per MWh	$	79	$	77	$	72

The change in average electric revenue per MWh in Q4 2015 compared to Q4 2014 and for the year ended December 31, 2015 compared to the same period in 2014 reflects transmission revenue adjustments and changes in the amounts recorded related to the transmission rate refund associated with the FERC ROE complaints.

37

Transmission Pool Revenues and Expenses

Transmission pool expenses are recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income. Transmission pool revenues are recorded in “Operating revenues – regulated” in the Consolidated Statements of Income.

Transmission pool revenues and expenses are summarized in the following table:

For the millions of US dollars	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
Transmission pool revenues	$	11.0	$	11.3	$	49.1	$	49.0	$	50.7
Transmission pool expenses		6.1		6.0		25.4		23.9		22.9
Net transmission pool revenues	$	4.9	$	5.3	$	23.7	$	25.1	$	27.8

Emera Maine’s net transmission pool revenues decreased $0.4 million to $4.9 million in Q4 2015 compared to $5.3 million in Q4 2014. For the year ended December 31, 2015, net transmission pool revenues decreased $1.4 million to $23.7 million compared to $25.1 million in 2014 primarily due to changes in the level of investment in regionally funded transmission assets and the impacts of weather in the New England region.

Resale of Purchased Power and Regulated Fuel for Generation and Purchased Power

Emera Maine has several above-market power purchase contracts with generators in its Bangor District service territory. The power purchased under these arrangements is resold at market rates significantly below the contract rates. The difference between the cost of the power purchased under these arrangements and the revenue collected is recovered through stranded cost rates under a full reconciliation rate mechanism.

Resale of purchased power increased $0.2 million in Q4 2015 to $3.6 million compared to $3.4 million in Q4 2014, and for the year ended December 31, 2015 decreased $0.7 million to $12.5 million in 2015 compared to $13.2 million in 2014 primarily due to changes in market rates for electricity in New England in 2015.

Income Taxes

Emera Maine is subject to corporate income tax at the statutory rate of 40.8 per cent (combined US federal and state income tax rate).

38

EMERA CARIBBEAN

Overview

Emera Caribbean includes the following consolidated and non-consolidated investments:

Consolidated Investments

• 95.5 per cent (2014 – 80.6 per cent) investment in Emera (Caribbean) Incorporated (“ECI”) and its wholly owned subsidiary Barbados Light & Power Company Ltd. (“BLPC”), a vertically integrated utility and the provider of electricity on the island of Barbados, serving approximately 126,000 customers and regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until 2028. BLPC owns 239 MW of oil-fired generation, 116 kilometres of transmission facilities and 2,800 kilometres of distribution facilities. BLPC has a workforce of 330 people. BLPC is regulated under a cost-of-service model with rates set to recover prudently incurred costs of providing electricity service to customers, and to provide an appropriate return to investors. BLPC’s approved allowed regulated return on rate base for 2015 was 10.0 per cent. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. Emera has initiated a process to purchase the remaining 4.5 per cent of common shares from minority shareholders of ECI, with anticipated completion in Q1 2016.

• 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited (“ICDU”) in Grand Bahama Power Company Ltd. (“GBPC”), which is a vertically integrated utility and the sole provider of electricity on Grand Bahama Island. GBPC serves approximately 19,000 customers. GBPC owns 98 MW of oil-fired generation, 138 kilometres of transmission facilities and 850 kilometres of distribution facilities and has a workforce of 205 people. GBPC is regulated by GBPA, which has granted GBPC a licensed, regulated and exclusive franchise to generate, transmit and distribute electricity on the island until 2054. GBPC’s approved allowable regulated return on rate base for 2015 was 10.0 per cent. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. Effective February 1, 2016, the GBPA approved GBPC’s General Rate Application applicable for the 2016 through 2018 period. Residential customers will see decreases up to 4.5 per cent, while commercial customers will see an increase of 1.5 per cent. Commercial customers consume approximately 70 per cent of GBPC’s production. Rates were approved based upon an 8.8 per cent allowable return on rate base. This rate decision will allow for customers to install renewable energy systems and sell their excess energy to GBPC. This is based on a tariff rider scheduled to be in place by Q3 2016.

• 49.6 per cent (2014 – 41.8 per cent) indirect controlling interest, through ECI, in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica. Domlec serves approximately 36,000 customers and is regulated by the Independent Regulatory Commission, Dominica. Domlec owns 20 MW of oil-fired generation, 7 MW of hydro production, 452 kilometres of transmission facilities and 640 kilometres of distribution facilities. Domlec has a workforce of 238 people. On October 7, 2013, the Independent Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014, for a period of 25 years. Domlec’s approved allowable regulated return on rate base for 2015 was 15 per cent. A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely manner.

• EUS Bahamas, providing utility construction and plant operation services in The Bahamas.

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Equity Investment

• 18.2 per cent indirect interest (2014 – 15.4 per cent), through ECI, in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia, which is regulated by the Government of St. Lucia. The investment in Lucelec is accounted for on the equity basis.

Review of 2015

Emera Caribbean Net Income

For the millions of USD (except per share amounts)	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
Operating revenues – regulated	$	84.3	$	105.4	$	346.0	$	432.1	$	427.4
Operating revenues – non-regulated		—		2.2		6.0		8.0		8.7
Total operating revenues		84.3		107.6		352.0		440.1		436.1
Regulated fuel for generation and purchased power		37.0		60.0		158.1		247.6		248.6
Non-regulated direct costs		0.2		1.8		5.9		7.1		7.6
Operating, maintenance and general		23.7		28.6		101.5		107.3		103.7
Property taxes (1)		0.2		0.4		1.8		1.6		1.5
Depreciation and amortization		8.6		7.7		34.5		33.3		30.9
Total operating expenses		69.7		98.5		301.8		396.9		392.3
Income from operations		14.6		9.1		50.2		43.2		43.8
Income from equity investment		0.6		0.4		2.3		2.1		1.7
Other income (expenses), net		1.9		1.3		4.8		5.7		11.8
Interest expense, net		2.7		2.7		10.8		11.5		11.7
Income before provision for income taxes		14.4		8.1		46.5		39.5		45.6
Income tax expense (recovery)		1.5		0.9		2.4		2.7		3.2
Net income		12.9		7.2		44.1		36.8		42.4
Non-controlling interest in subsidiaries		2.9		1.9		10.2		8.3		8.9
Preferred stock dividends (2)		—		—		2.5		2.5		1.2
Contribution to consolidated net income – USD	$	10.0	$	5.3	$	31.4	$	26.0	$	32.3
Contribution to consolidated net income – CAD	$	13.3	$	6.1	$	40.5	$	28.7	$	33.4
Contribution to consolidated earnings per common share – CAD	$	0.09	$	0.04	$	0.28	$	0.20	$	0.25
Net income weighted average foreign exchange rate – CAD/USD	$	1.33	$	1.15	$	1.29	$	1.10	$	1.03
EBITDA – USD	$	25.7	$	18.5	$	91.8	$	84.3	$	88.2
EBITDA – CAD	$	34.3	$	21.0	$	117.9	$	93.0	$	91.1

(1) Included in “Provincial, state and municipal taxes” on the Consolidated Statements of Income.

(2) Preferred stock dividends are included in “Non-controlling interest in subsidiaries” on the Consolidated Statements of Income.

Emera Caribbean’s USD contribution to consolidated net income increased by $4.7 million to $10.0 million in Q4 2015 compared to $5.3 million in Q4 2014. For the year ended December 31, 2015, Emera Caribbean’s USD contribution to consolidated net income increased by $5.4 million to $31.4 million compared to $26.0 million in 2014. Highlights of the net income changes are summarized in the following table:

40

For the millions of US dollars	Three months ended December 31			Year ended December 31
Contribution to consolidated net income – 2013				$	32.3
Increased OM&G expenses due to restructuring costs at ECI, partially offset by operational cost savings at GBPC					(0.4	)
Decreased other income (expenses), net primarily due to reduced investment income relating to an adjustment to ECI’s self-insurance fund					(3.4	)
Increased preferred dividends due to timing of preferred share issuance					(1.3	)
Effect of the non-taxable gain on acquisition of Domlec, partially offset by the acquisition of controlling interest in Domlec on April 10, 2013					(2.0	)
Other					0.8
Contribution to consolidated net income – 2014	$	5.3		$	26.0
Increased Electric Margin – see Electric Margin section		1.8			3.7
Decreased OM&G primarily due to lower pension expense, savings and timing of maintenance costs, and restructuring payroll savings at BLPC, lower outage costs at GBPC, and the reversal of Domlec regulatory costs; year-over-year restructuring costs at BLPC offset the decreased OM&G		4.9			5.8
Increased non-controlling interest due to increased earnings from ECI, GBPC and Domlec		(1.0	)		(1.9	)
Other		(1.0	)		(2.2	)
Contribution to consolidated net income – 2015	$	10.0		$	31.4

Emera Caribbean’s CAD contribution to consolidated net income increased by $7.2 million to $13.3 million in Q4 2015 compared to $6.1 million in Q4 2014. For the year ended December 31, 2015, Emera Caribbean’s CAD contribution to consolidated net income increased by $11.8 million to $40.5 million in 2015 compared to $28.7 million in 2014. The impact of a stronger USD, quarter-over-quarter increased CAD earnings by $1.8 million for the three months ended December 31, 2015 compared to 2014. The impact of a stronger USD year-over-year increased CAD earnings by $6.0 million in 2015 compared to 2014.

Operating Revenues – Regulated

Emera Caribbean’s operating revenues – regulated include sales of electricity and other services as summarized in the following table:

Q4 Operating Revenues – Regulated
millions of US dollars
	2015		2014		2013
Electric revenues – base rates	$	47.1		45.2	$	45.4
Fuel charge		36.3		59.4		60.3
Total electric revenues		83.4		104.6		105.7
Other revenues		0.9		0.8		0.8
Operating revenues – regulated	$	84.3		105.4	$	106.5

Annual Operating Revenues – Regulated
millions of US dollars
	2015		2014		2013*
Electric revenues – base rates	$	186.7	$	182.7	$	177.0
Fuel charge		155.4		245.2		247.0
Total electric revenues		342.1		427.9		424.0
Other revenues		3.9		4.2		3.4
Operating revenues – regulated	$	346.0	$	432.1	$	427.4
*  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10, 2013.

41

Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q3 being the strongest period, reflecting warmer weather.

Q4 Electric Sales Volumes
GWh
	2015		2014		2013
Residential		115		111		110
Commercial		197		189		191
Industrial		25		26		18
Other		7		7		7
Total		344		333		326

Annual Electric Sales Volumes
GWh
	2015		2014		2013*
Residential		453		440		428
Commercial		764		751		744
Industrial		104		102		93
Other		24		26		26
Total		1,345		1,319		1,291
*  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10, 2013.

Electric volumes increased in Q4 2015 compared to Q4 2014 and for the year ended December 31, 2015 as a result of warmer weather.

Electric revenues are summarized in the following tables by customer class:

Q4 Electric Revenues
millions of US dollars
	2015		2014		2013
Residential	$	26.9	$	34.5	$	33.3
Commercial		47.7		60.7		62.9
Industrial		7.2		7.5		7.6
Other		1.6		1.9		1.9
Total	$	83.4	$	104.6	$	105.7

Annual Electric Revenues
millions of US dollars
	2015		2014		2013*
Residential	$	110.9	$	142.9	$	133.2
Commercial		194.8		250.7		251.5
Industrial		30.1		26.9		31.5
Other		6.3		7.4		7.8
Total	$	342.1	$	427.9	$	424.0
*  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10, 2013.

Electric revenues decreased $21.2 million to $83.4 million in Q4 2015 compared to $104.6 million in Q4 2014. For the year ended December 31, 2015, electric revenues decreased $85.8 million to $342.1 million compared to $427.9 million in 2014. Highlights of the changes are summarized in the following table:

For the millions of US dollars	Three months ended December 31			Year ended December 31
Electric revenues – 2013				$	424.0
Increased due to acquisition of a controlling interest in Domlec					8.2
Decreased fuel charge primarily due to lower fuel prices					(4.8	)
Increased due to higher sales volumes in GBPC					0.5
Electric revenues – 2014	$	104.6		$	427.9
Decreased fuel charge primarily due to lower fuel prices		(23.1	)		(89.8	)
Increased due to higher sales volumes at BLPC and GBPC primarily due to weather		1.9			4.0
Electric revenues – 2015	$	83.4		$	342.1

42

Q4 Average Electric Revenue/MWh
	2015		2014		2013
Dollars per MWh	$	242	$	314	$	324

Annual Average Electric Revenue/MWh
	2015		2014		2013*
Dollars per MWh	$	254	$	324	$	328
*  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10, 2013.

The change in average electric revenues in Q4 2015 compared to Q4 2014, and for the year ended December 31, 2015 compared to the same period in 2014, is a result of the decreased fuel charge primarily due to lower fuel prices.

Electric Margin

Emera Caribbean distinguishes revenues related to the recovery of fuel costs through the fuel charge from revenues related primarily to the recovery of non-fuel costs (“base rates”). Emera Caribbean’s electric margin and net income are influenced primarily by base rates, whereas the fuel charge and fuel costs do not have a material effect on electric margin or net income. Emera Caribbean’s customer classes contribute differently to the Company’s base rate revenue, with residential and commercial customers contributing more than industrial customers. Residential and commercial load is primarily affected by changes in weather and economic conditions, while industrial load is primarily affected by economic conditions.

Electric margin is summarized in the following table:

For the millions of US dollars	Three months ended December 31						Year ended December 31
	2015			2014			2015			2014			2013(1)
Operating revenues – regulated	$	84.3		$	105.4		$	346.0		$	432.1		$	427.4
Less: Other revenues		(0.9	)		(0.8	)		(3.9	)		(4.2	)		(3.4	)
Total electric revenues		83.4			104.6			342.1			427.9			424.0
Total electric revenues are broken down as follows:
Electric revenues – base rate	$	47.1		$	45.2		$	186.7		$	182.7		$	177.0
Fuel charge		36.3			59.4			155.4			245.2			247.0
Total electric revenues		83.4			104.6			342.1			427.9			424.0
Regulated fuel for generation and purchased power		37.0			60.0			158.1			247.6			248.6
Regulatory amortization (2)		0.7			0.7			2.9			2.9			2.9
Electric margin	$	45.7		$	43.9		$	181.1		$	177.4		$	172.5

(1) ECI acquired a 51.9 per cent controlling interest in Domlec on April 10, 2013.

(2) Included in “Depreciation and amortization” on the Consolidated Statements of Income.

Emera Caribbean’s electric margin increased $1.8 million to $45.7 million in Q4 2015 compared to $43.9 million in Q4 2014. For the year ended December 31, 2015, electric margin increased $3.7 million to $181.1 million compared to $177.4 million in 2014 primarily due to increased sales volume at BLPC and GBPC primarily due to weather.

Q4 Average Electric Margin / MWh
	2015		2014		2013
Dollars per MWh	$	133	$	132	$	135

Annual Average Electric Margin / MWh
	2015		2014		2013*
Dollars per MWh	$	135	$	134	$	134
*  ECI acquired a 51.9 per cent controlling interest of Domlec on April 10, 2013.

43

Regulated Fuel for Generation and Purchased Power

Q4 Production Volumes
GWh
	2015		2014		2013
Oil		369		349		345
Hydro		6		8		10
Total		375		357		355

Annual Production Volumes
GWh
	2015		2014		2013*
Oil		1,441		1,397		1,371
Hydro		25		31		30
Total		1,466		1,428		1,401
*  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10, 2013

Q4 Average Fuel Costs/MWh
	2015		2014		2013
Dollars per MWh	$	99	$	168	$	172

Annual Average Fuel Costs/MWh
	2015		2014		2013*
Dollars per MWh	$	108	$	173	$	177
*  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10, 2013

The change in average fuel costs in Q4 2015 compared to Q4 2014 and for the year ended December 31, 2015 compared to the same period in 2014 is a result of lower fuel prices.

Regulated fuel for generation and purchased power decreased $23.0 million to $37.0 million in Q4 2015 compared to $60.0 million in Q4 2014. For the year ended December 31, 2015, regulated fuel for generation and purchased power decreased $89.5 million to $158.1 million compared to $247.6 million in 2014 primarily due to lower fuel prices.

Regulatory Recovery Mechanisms

BLPC

All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The Fair Trading Commission, Barbados has approved the calculation of the fuel charge, which is adjusted on a monthly basis.

GBPC

All GBPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The GBPA has approved the calculation of the fuel charge, which is adjusted on a monthly basis.

As a component of its regulatory agreement with the GBPA, GBPC has an Earnings Share Mechanism to allow for earnings on rate base to be deferred to a regulatory asset or liability at the rate of 50 per cent of amounts below a nine-per- cent return on rate base and 50 per cent of amounts above 11 per cent return on rate base respectively.

Domlec

Substantially all of Domlec fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover fuel costs in a timely manner.

44

Income Taxes

Emera Caribbean is subject to corporate income tax at the following statutory rates:

• ECI is subject to corporate income tax at the statutory rate of 25.0 per cent;

• BLPC is subject to corporate income tax at the statutory rate of 15.0 per cent;

• GBPC is not subject to corporate income tax;

• Domlec is subject to corporate income tax at the statutory rate of 28.0 per cent; and

• Lucelec is subject to corporate income tax at the statutory rate of 30.0 per cent.

Non-GAAP Measure

Electric Margin Reconciliation

“Electric margin” is a non-GAAP financial measure used to show the amounts that BLPC, GBPC and Domlec retain to recover their non-fuel costs, as substantially all prudently incurred fuel costs are recovered from customers.

The companies’ electric margin may not be comparable to electric margin measures of other companies, but in management’s view appropriately reflects Emera’s specific condition. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance.

For the millions of US dollars	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
Income from operations	$	14.6	$	9.1	$	50.2	$	43.2	$	43.8
less:
Operating revenues – non-regulated		—		2.2		6.0		8.0		8.7
Other revenue		0.9		0.8		3.9		4.2		3.4
Add back:
Non-regulated direct costs		0.2		1.8		5.9		7.1		7.6
Operating, maintenance and general		23.7		28.6		101.5		107.3		103.7
Property taxes		0.2		0.4		1.8		1.6		1.5
Depreciation and amortization (1)		7.9		7.0		31.6		30.4		28.0
Electric margin	$	45.7	$	43.9	$	181.1	$	177.4	$	172.5

(1) Depreciation and amortization excludes $0.7 million of regulatory amortization in Q4 2015 (2014 – $0.7 million) and $2.9 million for the year ended December 31, 2015 (2014 – $2.9 million)

45

PIPELINES

Overview

Pipelines comprises Emera’s wholly owned Brunswick Pipeline and the Company’s 12.9 per cent interest in the M&NP.

• Brunswick Pipeline is a 145-kilometre pipeline delivering re-gasified natural gas from the Canaport™ liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick, to markets in the northeastern United States for Repsol Energy Canada under a 25-year firm service agreement which expires in 2034. The NEB, which regulates Brunswick Pipeline, has classified it as a Group II pipeline. The agreement is accounted for as a direct financing lease.

• M&NP is a 1,400-kilometre transmission pipeline built to transport natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. The investment in M&NP is accounted for on the equity basis.

Mark-to-Market Adjustments

Pipelines’ “Interest expense, net” and “Income tax expense (recovery)” are affected by mark-to-market adjustments on an interest rate swap. Pipelines’ income table below shows these amounts net of mark-to-market adjustments and details the adjustments in the footnotes.

Review of 2015

Pipelines’ Adjusted Net Income

For the millions of Canadian dollars (except per share amounts)	Three months ended December 31				Year ended December 31
	2015		2014		2015			2014		2013
Operating revenues – regulated	$	13.0	$	12.4	$	52.1		$	48.8	$	49.9
Operating maintenance and general		0.1		0.1		0.4			0.4		0.1
Accretion (1)		0.1		0.1		0.4			0.3		0.2
Income from equity investment		6.5		5.3		23.0			18.4		14.7
Other income (expenses), net		—		0.2		0.6			0.6		0.1
Interest expense, net (2)		6.0		6.8		23.3			26.0		27.6
Adjusted income before provision for income taxes		13.3		10.9		51.6			41.1		36.8
Income tax expense (recovery) (3)		3.2		2.4		12.0			8.4		6.5
Adjusted contribution to consolidated net income	$	10.1	$	8.5	$	39.6		$	32.7	$	30.3
After-tax derivative mark-to-market gain (loss)		0.2		—		(2.1	)		—		—
Contribution to consolidated net income	$	10.3	$	8.5	$	37.5		$	32.7	$	30.3
Adjusted contribution to consolidated earnings per common share	$	0.07	$	0.06	$	0.27		$	0.23	$	0.23
Contribution to consolidated earnings per common share	$	0.07	$	0.06	$	0.26		$	0.23	$	0.23
Adjusted EBITDA	$	19.4	$	17.8	$	75.3		$	67.4	$	64.6

(1) Accretion related to the reclamation of the pipeline is included in “Depreciation and amortization” on the Consolidated Statements of Income.

(2) Interest expense, net excludes a pre-tax mark-to-market gain of $0.2 million in Q4 2015 and $2.9 million loss for the year ended December 31, 2015 compared to nil for the same periods in 2014.

(3) Income tax expense (recovery) excludes a nil expense relating to mark-to-market gains in Q4 2015 and $0.8 million recovery relating to mark-to-market losses for the year ended December 31, 2015 compared to nil for the same periods in 2014.

46

Pipelines’ contribution to consolidated net income increased by $1.8 million to $10.3 million in Q4 2015 compared to $8.5 million in Q4 2014 and increased $4.8 million to $37.5 million for the year ended December 31, 2015 compared to $32.7 million in 2014. Highlights of the income changes are summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31			Year ended December 31
Contribution to consolidated net income – 2013				$	30.3
Increased income from equity investments primarily due to higher equity earnings from M&NP					3.7
Other					(1.3	)
Contribution to consolidated net income – 2014	$	8.5		$	32.7
Increased regulated operating revenues due to a strengthening USD and increased tolls		0.6			3.3
Increased income from equity investments primarily due to increased interruptible transmission revenue from M&NP and the strengthening USD		1.2			4.6
Decreased interest expense, net primarily due to a lower interest rate on Brunswick Pipeline refinancing in Q1 2015		0.8			2.7
Increased income tax expense primarily due to increased income before provision for income taxes		(0.8	)		(3.6	)
After-tax mark-to-market gain (loss) on an interest rate swap entered into in Q2 2015		0.2			(2.1	)
Other		(0.2	)		(0.1	)
Contribution to consolidated net income – 2015	$	10.3		$	37.5

Brunswick Pipeline

The Company records the net investment in a lease under the direct finance method, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. This accounting method has the effect of recognizing higher revenues in the early years of the contract than would have been recorded if the toll revenues were recorded as received.

Income Taxes

Brunswick Pipeline is subject to corporate income tax at the statutory rate of 27.0 per cent (combined Canadian federal and provincial income tax rate).

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EMERA ENERGY

Overview

Emera Energy includes the following:

• Emera Energy Services (“EES”), a wholly owned physical energy marketing and trading business;

• Emera Energy Generation (“EEG”), consisting of a wholly owned portfolio of electricity generation facilities in New England and the Maritime provinces of Canada with 1,410 megawatts (“MW”) of total capacity;

• Equity investments in the following generation facilities:

• Emera’s 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

• Emera’s 49.0 per cent investment in NWP, a 419 MW portfolio of wind energy projects in the northeastern United States which on January 29, 2015 sold to 51 per cent partner, First Wind.

Wholly owned investments are consolidated. The investment in Bear Swamp is accounted for on an equity basis. NWP was accounted for on the equity basis, and its results were included until its sale on January 29, 2015. The gain on the sale of this asset is recorded in “Other income (expenses), net” on the Consolidated Statements of Income.

Mark-to-Market Adjustments

Emera Energy’s “Trading and marketing margin”, “Electricity sales”, “Non-regulated fuel for generation and purchased power”, “Income from equity investments” and “Income tax expense (recovery)” are affected by mark-to-market (“MTM”) adjustments. The Emera Energy income table shows these amounts net of mark-to-market adjustments and details these adjustments in footnotes to the income statement. Management believes that excluding the effect of mark-to-market valuations, and changes thereto, from income until settlement better matches the financial effect of these contracts with the underlying cash flows.

Emera Energy has a number of Asset Management Agreements (“AMAs”) with local gas distribution utilities (“LDCs”) in the northeast. The AMAs involve Emera Energy supplying gas to the LDCs for a specific term, and the corresponding release of utility owned gas transportation/storage capacity to Emera Energy. Mark-to-market adjustments on these AMA’s arise on the price differential between the point where gas is sourced and where it is delivered. At inception, the MTM adjustment is offset fully by the corresponding transportation asset, which is amortized over the term of the AMA contract. Subsequent changes in gas price differentials, to the extent not offset by the accounting amortization of the transportation asset, will result in MTM gains or losses recorded in income. MTM adjustments may be substantial in the early months of a contract when delivered volumes and market volatility are usually at peak levels. As a contract is realized, and volumes reduce, volatility is expected to decrease. Ultimately, the transportation asset and the mark-to-market adjustment reduce to zero at the end of the contract term. As the business grows, and AMA volumes increase, MTM volatility resulting in gains and losses may also increase.

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Review of 2015

Emera Energy Adjusted Contribution to Consolidated Net Income

For the millions of Canadian dollars (except per share amounts)	Three months ended December 31				Year ended December 31
	2015		2014		2015			2014		2013
Trading and marketing margin (1)	$	38.0	$	15.8	$	84.9		$	117.5	$	60.3
Electricity sales (2)		142.5		102.4		545.9			520.7		146.2
Total operating revenues – non-regulated		180.5		118.2		630.8			638.2		206.5
Non-regulated fuel for generation and purchased power (3)		86.5		61.6		334.9			384.8		97.9
Operating, maintenance and general		25.3		16.6		79.7			78.7		43.6
Provincial, state and municipal taxes		2.3		1.2		6.6			5.5		0.8
Depreciation and amortization		10.8		8.9		40.6			37.7		11.2
Total operating expenses		124.9		88.3		461.8			506.7		153.5
Adjusted income (loss) from operations		55.6		29.9		169.0			131.5		53.0
Income from equity investments (4)		3.2		1.6		26.4			12.3		17.1
Other income (expenses), net		1.2		0.8		25.1			2.9		0.2
Interest expense, net		6.1		1.4		19.3			6.2		1.0
Adjusted income (loss) before provision for income taxes		53.9		30.9		201.2			140.5		69.3
Income tax expense (recovery) (5)		18.5		9.6		71.1			42.3		24.2
Adjusted contribution to consolidated net income (loss)	$	35.4	$	21.3	$	130.1		$	98.2	$	45.1
After-tax derivative mark-to-market gain (loss)	$	4.3	$	72.7	$	(31.2	)	$	87.5	$	(41.9	)
Contribution to consolidated net income	$	39.7	$	94.0	$	98.9		$	185.7	$	3.2
Adjusted contribution to consolidated earnings per common share – basic	$	0.24	$	0.15	$	0.89		$	0.69	$	0.34
Contribution to consolidated earnings per common share – basic	$	0.27	$	0.65	$	0.68		$	1.30	$	0.02
Adjusted EBITDA	$	70.8	$	41.2	$	261.1		$	184.4	$	81.5

(1) Trading and marketing margin excludes a pre-tax mark-to-market gain of $37.4 million in Q4 2015 (2014 - $84.6 million gain) and a loss of $1.8 million for the year ended December 31, 2015 (2014 - $119.9 million gain)

(2) Electricity sales exclude a pre-tax mark-to-market loss of $21.9 million in Q4 2015 (2014 – $44.6 million gain) and a loss of $39.1 million for the year ended December 31, 2015 (2014 - $42.8 million gain)

(3) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market loss of $5.4 million in Q4 2015 (2014 – $17.9 million loss) and a loss of $6.3 million for the year ended December 31, 2015 (2014 - $20.8 million loss)

(4) Income from equity investments excludes a pre-tax mark-to-market loss of $9.7 million in Q4 2015 (2014 - $3.6 million loss) and a loss of $5.6 million for the year ended December 31, 2015 (2014 - $13.2 million loss)

(5) Income tax expense (recovery) excludes a $3.9 million recovery relating to mark-to-market gains in Q4 2015 (2014 - $35.0 million expense) and $21.6 million recovery relating to mark-to-market losses for the year ended December 31, 2015 (2014 - $41.2 million expense)

Emera Energy’s contribution to consolidated net income decreased by $54.3 million to $39.7 million in Q4 2015 compared to $94.0 million in Q4 2014. For the year ended December 31, 2015, Emera Energy’s contribution to consolidated net income decreased $86.8 million to $98.9 million compared to $185.7 million in 2014. Highlights of the income changes are summarized in the following table:

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For the millions of Canadian dollars	Three months ended December 31			Year ended December 31
Contribution to consolidated net income – 2013				$	3.2
Increased trading and marketing margin primarily due to very strong market conditions in northeastern United States and Ontario in Q1 2014 and a stronger USD					57.2
Increased electricity sales primarily due to the acquisition of the New England Gas Generating Facilities in November 2013, higher power prices and increased sales at Bayside Power					374.5
Increased non-regulated fuel for generation and purchased power primarily due to the acquisition of the New England Gas Generating Facilities in November 2013, higher commodity prices and increased generation at Bayside Power					(286.9	)
Increased OM&G primarily due to the acquisition of the New England Gas Generating Facilities and increased performance-based compensation accruals resulting from increased trading and marketing margin					(35.1	)
Increased depreciation and amortization primarily due to the acquisition of the New England Gas Generating Facilities					(26.5	)
Income from equity investments reflects a non-recurring gain on the settlement of warranty obligations related to certain NWP turbines, decreased curtailments at NWP, recognition of business interruption insurance proceeds related to a 2013 outage at Bear Swamp and favourable pricing at Bear Swamp					(4.8	)
Increased income tax expense primarily due to increased income before provision for taxes					(18.1	)
Increased mark-to-market gains, net of tax, primarily due to the reversal of 2013 mark-to-market losses and changes in gas and power contract positions, as well as favourable power contracts at the New England Gas Generating Facilities					129.4
Other					(7.2	)
Contribution to consolidated net income – 2014	$	94.0		$	185.7
Increased (decreased) trading and marketing margin – See Trading and Marketing Margin section below		22.2			(32.6	)
Increased electricity sales quarter-over-quarter primarily due to higher sales volumes, reflecting reduced generation for planned outage work at Bridgeport in Q4 2014, which reduced generation and a stronger USD; year-over-year is also partially offset by lower power prices		40.1			25.2
Increased non-regulated fuel for generation and purchased power quarter-over-quarter as a result of higher sales volumes, reflecting reduced generation for planned outage work at Bridgeport in Q4 2014 and a stronger USD; year-over-year reduction is primarily due to lower commodity fuel prices, partially offset by a stronger USD		(24.9	)		49.9
Increased OM&G quarter-over-quarter primarily due to timing of maintenance work at the New England Gas Generating Facilities, the stronger USD and increased performance-based compensation resulting from increased trading and marketing margins; year-over-year primarily due to stronger USD, offset by decreased performance-based compensation resulting from decreased trading and marketing margins		(8.7	)		(1.0	)
Increased income from equity investments – See “Equity Investments” below		1.6			14.1
Increased other income (expenses) year-over-year primarily due to a gain on the sale of NWP		0.4			22.2
Increased interest expense, net primarily due to higher interest rates on internal financing		(4.7	)		(13.1	)
Increased income tax expense primarily due to increased income before provision for income taxes; year-over-year increase also due to changes in the proportion of income earned in higher tax rate foreign jurisdiction and a stronger USD		(8.9	)		(28.8	)

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Decreased mark-to-market, net of tax, quarter-over-quarter primarily due to changes in gas and power contract positions, and amortization of transportation assets; decreased year-over-year also due to the reversal of 2013 mark-to-market losses in 2014		(68.4	)		(118.7	)
Other		(3.0	)		(4.0	)
Contribution to consolidated net income – 2015	$	39.7		$	98.9

A portion of earnings are exposed to foreign exchange fluctuations thereby impacting adjusted CAD contribution to net earnings. The impact of a stronger USD, quarter-over-quarter increased earnings in CAD dollars by $3.4 million in Q4 2015 compared to 2014. For the year ended December 31, 2015 the impact of a stronger USD increased earnings in CAD dollars by $11.9 million compared to the same period in 2014.

Energy Services

Emera Energy Services derives revenue and earnings from the wholesale trading and marketing of natural gas, electricity and other energy-related commodities and derivatives within the Company’s risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure. Emera Energy purchases and sells physical natural gas and related transportation capacity rights, as well as providing related energy asset management services. EES is also responsible for commercial management of electricity production and fuel procurement for Emera Energy Generation’s fleet. Established in 2002, Emera Energy’s trading and marketing business currently has approximately 80 employees engaged in commercial activities and related back office, legal and other support functions. The primary market for the trading and marketing business is northeastern North America, including the Marcellus shale gas region, the US Gulf Coast and Central Canada. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. Trading and marketing operates in a competitive environment, and its business relies on knowledge of the region’s energy markets, understanding of pipeline infrastructure, a network of counterparty relationships and a focus on customer service. Emera Energy manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.

Adjusted EBITDA

Adjusted EBITDA for Emera Energy’s trading and marketing business is summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
Trading and marketing margin	$	38.0	$	15.8	$	84.9	$	117.5	$	60.3
OM&G		7.9		5.0		21.3		24.8		15.2
Other income (expenses), net		1.0		0.8		5.6		2.6		1.0
Adjusted EBITDA	$	31.1	$	11.6	$	69.2	$	95.3	$	46.1

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Trading and Marketing Margin

Trading and marketing margin is comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management services’ revenues.

Trading and marketing margin increased $22.2 million to $38.0 million in Q4 2015 compared to $15.8 million in Q4 2014. This reflects growth in the volume of business, including increased investment in transportation capacity, the value of which is primarily realized in the winter months. For the year ended December 31, 2015, trading and marketing margin decreased $32.6 million to $84.9 million compared to $117.5 million in 2014. Q1 2014 saw sustained high pricing and volatility in several of Emera Energy’s markets, largely the result of cold weather. Subsequently, there was a return to more normal market conditions. Trading and marketing margins were also favourably affected by the strengthening USD in Q4 2015 and for the year ended December 31, 2015.

Generation

Emera Energy wholly owns and operates a portfolio of high efficiency, non-utility electricity generating facilities in northeast North America.

Information regarding Emera Energy’s wholly owned generation facilities is summarized in the following table:

Wholly Owned Generation Facilities	Location	Capacity (MW)		Commissioning/ In-Service Date	Fuel	Description
New England
Bridgeport (1)	Connecticut		560	1999	Natural gas	Selling electricity and capacity to ISO-NE
Tiverton	Rhode Island		265	2000	Natural gas	Selling electricity and capacity to ISO-NE
Rumford	Maine		265	2000	Natural gas	Selling electricity and capacity to ISO-NE
Total New England			1,090
Maritime Canada
Bayside	New Brunswick		290	2001	Natural gas	Long-term power purchase agreement (“PPA”) November - March; Selling electricity to Maritimes and ISO-NE for remainder of year
Brooklyn	Nova Scotia		30	1996	Biomass	Long-term PPA
Total Maritime Canada			320
Total EEG			1,410

(1) A Q2 2015 upgrade at Bridgeport increased its nameplate capacity from 540 MW to 560 MW.

Emera Energy has approximately 125 employees in its generation business. For the portion of output not committed under PPAs, Emera Energy’s generation facilities sell into price-based competitive markets and earn revenues through the physical delivery of power and ancillary services, such as load regulation. The New England facilities also participate in the regional capacity market and are compensated for being available to provide power. The electricity generation business in the northeast is seasonal. Q1, Q3 and Q4 are generally the strongest periods, reflecting colder weather, and fewer daylight hours in the winter season, and cooling load in the summer.

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Adjusted EBITDA

Adjusted EBITDA is summarized in the following table:

For the	Three months ended December 31
	New England				Maritime Canada					Total
millions of Canadian dollars	2015		2014		2015			2014		2015		2014
Energy sales	$	110.7	$	63.3	$	19.9		$	25.8	$	130.6	$	89.1
Capacity and other		11.9		13.3		—			—		11.9		13.3
Electricity sales		122.6		76.6		19.9			25.8		142.5		102.4
Non-regulated fuel for generation and purchased power		72.7		44.9		10.9			15.3		83.6		60.2
Non-regulated electric margin		49.9		31.7		9.0			10.5		58.9		42.2
Provincial taxes		1.3		0.9		0.2			0.2		1.5		1.1
OM&G		12.4		7.5		4.4			3.7		16.8		11.2
Other income (expenses), net		0.3		—		(0.1	)		—		0.2		—
Adjusted EBITDA	$	36.5	$	23.3	$	4.3		$	6.6	$	40.8	$	29.9

Adjusted EBITDA is summarized in the following table:

For the	Year ended December 31
	New England (1)						Maritime Canada (2)								Total
millions of Canadian dollars	2015		2014		2013		2015			2014		2013			2015		2014		2013
Energy sales	$	413.9	$	365.5	$	64.0	$	88.3		$	109.4	$	77.8		$	502.2	$	474.9	$	141.8
Capacity and other		43.7		45.8		4.4		—			—		—			43.7		45.8		4.4
Electricity sales	$	457.6	$	411.3	$	68.4	$	88.3		$	109.4	$	77.8		$	545.9	$	520.7	$	146.2
Non-regulated fuel for generation and purchased power		277.3		311.8		48.6		52.2			73.5		47.3			329.5		385.3		95.9
Non-regulated electric margin		180.3		99.5		19.8		36.1			35.9		30.5			216.4		135.4		50.3
Provincial taxes		4.7		4.6		—		0.9			0.9		0.8			5.6		5.5		0.8
OM&G		37.5		29.9		7.1		18.7			21.3		19.3			56.2		51.2		26.4
Other income (expenses), net		1.6		—		—		(0.7	)		0.3		(0.8	)		0.9		0.3		(0.8	)
Adjusted EBITDA	$	139.7	$	65.0	$	12.7	$	15.8		$	14.0	$	9.6		$	155.5	$	79.0	$	22.3

(1) The New England Gas Generating Facilities were acquired in November 2013.

(2) Brooklyn Energy was acquired in July 2013.

Adjusted EBITDA increased $10.9 million to $40.8 million in Q4 2015 from $29.9 million compared to Q4 2014 primarily due to increased generation, reflecting a major planned outage at Bridgeport Energy in Q4 2014. For the year ended December 31, 2015, adjusted EBITDA increased $76.5 million to $155.5 million from $79.0 million in 2014, primarily due to higher margins realized in the New England Gas Generating Facilities, reflecting favourable short-term economic hedges, favourable pricing. The strengthening USD contributed $17.6 million.

Operating Statistics

For the	Three months ended December 31
	Sales Volumes (GWh) (1)				Plant Availability (%) (2)						Net Capacity Factor (%) (3)
	2015		2014		2015			2014			2015			2014
New England		1,194		777		98.9	%		62.6	%		49.7	%		33.4	%
Maritime Canada		417		525		89.5	%		95.1	%		60.5	%		76.1	%
Total		1,611		1,302		96.8	%		70.0	%		52.1	%		43.2	%

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For the	Year ended December 31
	Sales Volumes (GWh) (1)				Plant Availability (%) (2)						Net Capacity Factor (%) (3)
	2015		2014		2015			2014			2015			2014
New England		4,777		4,375		94.5	%		79.9	%		50.5	%		47.6	%
Maritime Canada		1,699		1,910		92.7	%		91.4	%		61.9	%		69.9	%
Total		6,476		6,285		94.1	%		82.6	%		53.0	%		52.7	%

(1) Sales volumes represent the actual electricity output of the plants.

(2) Plant availability represents the percentage of time in the period that the plant was available to generate power regardless of whether it was running. Effectively, it represents 100% availability reduced by planned and unplanned outages.

(3) Net capacity factor is the ratio of the utilization of an asset as compared to its maximum capability, within a particular time frame. It is generally a function of plant availability and plant economics vis-à-vis the market.

Sales volumes and net capacity factor increased quarter-over-quarter primarily due to the impact of a planned outage and plant upgrade at the Bridgeport facility in Q4 2014; year-over-year increase in sales volumes was primarily due to fewer outage days in 2015 at the New England Gas Generating Facilities.

Upgrades completed in Q2 2015 at the Bridgeport facility, including a new gas turbine rotor and improved combustion system, added 20 MW of capacity, bringing the plant total to 560 MW. Availability has increased at the New England Gas Generating Facilities due to significant reliability and performance-based investment in 2014.

The New England Gas Generating Facilities sell into price based competitive markets. The primary reason that the overall capacity factor is lower for New England Gas Generating Facilities as compared to the Maritime facilities is because the Rumford Power Plant, in particular, generally operates with a capacity factor of approximately 20 per cent, reflecting current electricity and gas supply price dynamics in its markets.

Equity Investments

Information regarding Emera Energy’s equity investments in generation facilities is summarized below:

Investments in Generation Facilities	Ownership	Location	Capacity (MW)		Fuel	Description
New England
Bear Swamp	50 per cent	Massachusetts		600	Hydro	Long-term PPA and selling electricity and capacity to ISO-NE
NWP (1)	49 per cent	Maine		419	Wind	Long-term PPA and selling electricity to ISO-NE and New York ISO (“NYISO”)
Total New England				1,019

(1) On January 29, 2015, Emera completed the sale of NWP to First Wind for $223.3 million USD. Emera’s carrying value of its 49 per cent interest as at December 31, 2014 was $204.4 million USD.

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Adjusted income from equity investments

Adjusted income from equity investments is summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31					Year ended December 31
	2015		2014			2015		2014			2013
Bear Swamp	$	3.2	$	2.4		$	24.5	$	19.2		$	15.8
NWP		—		(0.8	)		1.9		(6.9	)		1.3
Adjusted income from equity investments	$	3.2	$	1.6		$	26.4	$	12.3		$	17.1

Adjusted Income from equity investments increased $1.6 million to $3.2 million in Q4 2015 compared to $1.6 million in Q4 2014 primarily due to transmission line outages that negatively affected power sales at Bear Swamp in 2014, partially offset by higher interest costs as a result of its Q4 2015 refinancing. For the year ended December 31, 2015, adjusted income from equity investments increased $14.1 million to $26.4 million compared to $12.3 million in 2014. This was primarily due to the resupply of the contracted power sales in Bear Swamp in 2015 that were not delivered in 2014 due to transmission line outages, NWP losses recorded in 2014 and the strengthening USD.

Other Income

On January 29, 2015, Emera completed the sale of its 49 per cent interest in NWP for $282.3 million ($223.3 million USD). This sale resulted in a pre-tax gain of $18.6 million or $0.13 per common share (after-tax gain of $11.5 million or $0.08 per common share), which was recorded in “Other income (expenses), net” on the Consolidated Statements of Income in Q1 2015.

Income Taxes

Emera Energy is subject to corporate income tax at the statutory rate ranging from 39.2 to 41.5 per cent (combined US federal and state income tax rate) on its US sourced income and ranging from 27.0 to 31.0 per cent (combined Canadian federal and provincial income tax rate) on its Canada sourced income.

New England Gas Generating Facilities is subject to corporate income tax at the statutory rate ranging from 35.0 to 40.9 per cent (combined US federal and state income tax rate).

Brooklyn Energy is subject to corporate income tax at the statutory rate of 31.0 per cent (combined Canadian federal and provincial income tax rate).

Bear Swamp Refinancing

On October 8, 2015, Bear Swamp refinanced its $125 million USD bank debt that was due to mature in 2017 and issued $400 million USD in senior secured 10-year bonds, with $375 million USD at fixed rate of 4.89 per cent and $25 million USD at a floating rate of LIBOR plus 2.70 per cent. The proceeds of this financing were used to repay existing debt and provide working capital to the joint venture, with the remainder shared equally between Emera and its joint venture partner. After fees and expenses, Emera received a $178.7 million ($137.3 million USD) non-taxable distribution in Q4 2015.

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CORPORATE AND OTHER

Corporate

Corporate includes certain corporate-wide functions including executive management, strategic planning, treasury services, financial reporting, tax planning, corporate business development, corporate governance, internal audit, investor relations, risk management, insurance, acquisition related costs and corporate human resource activities. It also includes interest revenue on intercompany financings recorded in “Intercompany revenue” in the table below, and costs associated with corporate activities that are not directly allocated to the operations of Emera’s consolidated subsidiaries and investments.

Other

Other includes the following consolidated and non-consolidated investments:

Consolidated Investments

• Emera Utility Services is a utility services contractor primarily operating in Atlantic Canada (recorded in “Non-regulated operating revenue” in the table below).

• Emera Reinsurance Limited is a captive insurance company providing insurance and reinsurance to Emera and its affiliates, to enable more cost efficient management of risk and deductible levels across Emera (recorded in “OM&G” and “Other income (expenses), net” in the table below).

Non-consolidated investments (recorded in “Income (loss) from equity investments” in the table below)

• Emera’s 23.4 per cent investment in APUC, including outstanding subscription receipts and associated dividend equivalents. APUC is a diversified generation, transmission and distribution utility traded on the Toronto Stock Exchange (“TSX”) under the symbol “AQN”. The distribution group operates in the United States and provides rate regulated water, electricity and natural gas utility services. The non-regulated generation group owns or has interests in a portfolio of North American-based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission group invests in rate-regulated electric transmission and natural gas pipeline systems in the United States and Canada. The investment in APUC is accounted for on the equity basis. There is a one quarter lag in reporting as APUC’s information is generally not publicly available at the time of Emera’s public release of its financial results. As at December 31, 2015, Emera owned 50.1 million common shares, 12.6 million outstanding subscription receipts and dividend equivalents, at an average conversion price of $9.20. The outstanding subscription receipts became eligible for conversion into APUC common shares at Emera’s election in Q4 2015 and will automatically convert to common shares in Q4 2016 if an election is not made. The subscription receipts are now included in “Investments subject to significant influence” on the Consolidated Balance Sheets.

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• Emera’s 100 per cent investment in ENL, which holds investments in the following:

• Emera’s 100 per cent investment in NSPML, a $1.56 billion transmission project, including two 170-kilometre subsea cables, between the island of Newfoundland and Nova Scotia. The investment in NSPML is accounted for on the equity basis with equity earnings equal to the return on equity component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017.

• Emera’s 55.1 per cent investment in the partnership capital of LIL, a $3.1 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change based on the balance of capital investments required from Emera and Nalcor to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined on completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is expected to go into service in 2017.

• Emera’s 3.3 per cent investment in Open Hydro is accounted for on the cost basis.

• Other investments.

Mark-to-Market Adjustments

Specific to the pending TECO Energy acquisition, Emera has recorded after-tax mark-to-market gains of $100.5 million for the three months and year ended December 31, 2015 (2014 – nil) related to the effect of USD-denominated currency and forward contracts put in place to hedge the anticipated proceeds from the second instalment of the Debenture Offering of the pending acquisition, expected mid-2016.

“Other income (expenses), net” and “Income tax expense (recovery)” are affected by the mark-to-market adjustments discussed above. Corporate and Other’s income table below shows these amounts net of mark-to-market adjustments and details the adjustments in the footnotes.

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Review of 2015

Corporate and Other

For the millions of Canadian dollars	Three months ended December 31						Year ended December 31
	2015			2014			2015			2014			2013
Intercompany revenue (1)	$	9.9		$	6.8		$	34.2		$	26.0		$	38.3
Non-regulated operating revenue		9.9			16.1			40.1			48.7			43.5
Non-regulated direct costs		9.9			15.2			42.4			46.9			44.6
Operating, maintenance and general		32.7			16.8			104.1			46.2			39.0
Depreciation and amortization		0.7			0.5			1.7			2.3			3.8
Total operating expenses		43.3			32.5			148.2			95.4			87.4
Income (loss) from operations		(23.5	)		(9.6	)		(73.9	)		(20.7	)		(5.6	)
Income (loss) from equity earnings		25.5			11.6			61.3			46.3			3.3
Other income (expenses), net (2)		(5.0	)		(0.1	)		(4.3	)		3.2			16.9
Interest expense		29.5			6.3			48.1			30.9			37.5
Adjusted income (loss) before provision for income taxes		(32.5	)		(4.4	)		(65.0	)		(2.1	)		(22.9	)
Income tax expense (recovery) (3)		(15.5	)		(5.2	)		(40.1	)		(20.6	)		(28.4	)
Preferred stock dividends		—			—			30.3			26.2			19.3
Adjusted contribution to consolidated net income	$	(17.0	)	$	0.8		$	(55.2	)	$	(7.7	)	$	(13.8	)
After-tax mark-to-market gain (loss)		100.5			—			100.5			—			—
Contribution to consolidated net income	$	83.5		$	0.8		$	45.3		$	(7.7	)	$	(13.8	)
Adjusted contribution to consolidated earnings per common share – basic	$	(0.12	)	$	0.01		$	(0.38	)	$	(0.05	)	$	(0.10	)
Contribution to consolidated earnings per common share – basic	$	0.57		$	0.01		$	0.31		$	(0.05	)	$	(0.10	)
Adjusted EBITDA	$	(2.3	)	$	2.4		$	(15.2	)	$	31.1		$	18.4

(1) Intercompany revenue consists of interest from Brunswick Pipeline, M&NP and EEG.

(2) Other income (expenses) net, excludes a pre-tax mark-to-market gain of $118.9 million in Q4 2015 and for the year ended December 31, 2015 compared to nil for the same periods in 2014.

(3) Income tax expense (recovery), excludes an $18.4 million expense relating to mark-to-market gains in Q4 2015 and for the year ended December 31, 2015 compared to nil for the same periods in 2014.

Corporate and Other’s contribution to consolidated net income increased by $82.7 million to $83.5 million in Q4 2015 compared to $0.8 million in Q4 2014. For the year ended December 31, 2015, Corporate and Other’s contribution to consolidated net income increased $53.0 million to $45.3 million compared to $(7.7) million in 2014. Highlights of the income changes are summarized in the following table:

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For the millions of Canadian dollars	Three months ended December 31			Year ended December 31
Contribution to consolidated net income – 2013				$	(13.8	)
Decreased intercompany revenue primarily due to lower interest revenue resulting from the repayment of NWP loan in November 2013					(12.3	)
Increased OM&G primarily due to higher deferred compensation costs, partially offset by lower business development costs					(7.2	)
Income from equity investments – see table below for highlights					43.0
Decreased other income primarily due to the 2013 gains on the exchange of APUC subscription receipts to common shares, partially offset by the 2013 AHI investment impairment					(13.7	)
Decreased interest expense primarily due to lower short-term debt levels					6.6
Increased income tax expense primarily due to increased income before provision for income taxes					(7.8	)
Increased preferred stock dividends primarily due to an incremental preferred share issuance					(6.9	)
Other					4.4
Contribution to consolidated net income – 2014	$	0.8		$	(7.7	)
Increased intercompany revenue due to the issuance of a loan to Emera Energy Generation, partially offset by the repayment of an intercompany loan from Brunswick Pipeline		3.1			8.2
Acquisition costs related to the pending TECO Energy acquisition		(21.0	)		(51.5	)
Decreased OM&G quarter-over-quarter primarily due to lower performance-based compensation; increased year-over-year primarily due to business development costs not related to the pending TECO Energy acquisition		5.1			(6.4	)
Income from equity investments – see Income from Equity Investments section below		13.9			15.0
Decreased other income quarter-over-quarter due to the reclassification of APUC subscription receipts; year-over-year due to the losses incurred in Emera Reinsurance from Tropical Storm Erika and the recognition of NSPML as an equity investment in Q2 2014		(4.9	)		(7.5	)
Increased interest expense primarily due to interest on convertible debentures represented by installment receipts, partially offset year-over-year by maturity of long-term debt in Q4 2014		(23.2	)		(17.2	)
Decreased income tax expense primarily due to the decreased income before provision for income taxes		10.3			19.5
Increased preferred stock dividends year-over-year primarily due to issuance of preferred shares in Q2 2014		—			(4.1	)
After-tax mark-to-market gain (loss) – see After-Tax Mark-to-Market Gain (Loss) section below		100.5			100.5
Other		(1.1	)		(3.5	)
Contribution to consolidated net income – 2015	$	83.5		$	45.3

Acquisition Related Costs

Highlights of the acquisition related costs summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31					Year ended December 31
	2015			2014		2015			2014		2013
Operating, maintenance, and general	$	21.0		$	—	$	51.5		$	—	$	—
Interest expense, net		23.3			—		23.9			—		—
Income tax expense (recovery)		(14.0	)		—		(22.6	)		—		—
Acquisition related costs	$	30.3		$	—	$	52.8		$	—	$	—

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After-Tax Mark-to-Market Gain (Loss)

The foreign currency earnings impact related to the translation gain from the convertible debenture USD cash balance and the mark-to-market gain from forward contracts from economically hedging the Debenture Offering are recorded as a mark-to-market adjustment. These pre-tax earnings impacts totaled $118.9 million in “Other income (expenses), net” on the Consolidated Statements of Income ($100.5 million after-tax). The after-tax mark-to-market gain (loss) related to the pending acquisition of TECO Energy is summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31					Year ended December 31
	2015			2014		2015			2014		2013
Foreign exchange on USD cash	$	26.8		$	—	$	26.8		$	—	$	—
Mark-to-market adjustment on USD forward contracts		92.1			—		92.1			—		—
Income tax expense (recovery)		(18.4	)		—		(18.4	)		—		—
After-tax mark-to-market gain (loss)	$	100.5		$	—	$	100.5		$	—	$	—

Income from Equity Investments

Income from equity investments are summarized in the following table:

For the millions of Canadian dollars	Three months ended December 31				Year ended December 31
	2015		2014		2015		2014		2013
APUC	$	18.0	$	5.6	$	36.9	$	30.4	$	0.4
NSPML		3.8		4.4		14.9		9.5		—
LIL		3.7		1.6		9.5		6.4		5.2
AHI		—		—		—		—		(2.3	)
Income from equity investments	$	25.5	$	11.6	$	61.3	$	46.3	$	3.3

Income from equity investments increased $13.9 million to $25.5 million in Q4 2015 compared to $11.6 million in Q4 2014. For the year ended December 31, 2015, income from equity investments increased $15.0 million to $61.3 million compared to $46.3 million in 2014. Highlights of the income changes are summarized in the following table:

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For the millions of Canadian dollars	Three months ended December 31			Year ended December 31
Income from equity investments – 2013				$	3.3
APUC – Increased due to dilution gains resulting from share issuances, higher earnings and 2013 recognition of discontinued operations of $8.3 million					30.0
NSPML – Recognition of the AFUDC earnings of NSPML as income from equity investment					9.5
Other					3.5
Income from equity investments – 2014	$	11.6		$	46.3
APUC – Increased quarter-over-quarter primarily due higher equity earnings in 2015, the reclassification of APUC subscription receipts in 2015 and a higher dilution gain from the share issuance in Q4 2015 compared to dilution gain from share issuance in Q4 2014; year-over-year due to higher equity earnings in 2015, the reclassification of APUC subscription receipts in 2015, partially offset by lower dilution on APUC share issuances in 2015 compared to dilutions related to share issuances in 2014		12.4			6.5
NSPML – Increased year-over-year due to the recognition of the AFUDC earnings of NSPML as income from equity investment		(0.6	)		5.4
LIL – Increase in investment		2.1			3.1
Income from equity investments – 2015	$	25.5		$	61.3

NSPML has cumulatively invested $693.9 million of equity and debt, including $78.1 million of AFUDC, in the development of the Maritime Link Project. Project to date, ENL has invested a total of $154.9 million in equity, with the remaining costs being funded with working capital and debt, which has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9 per cent. Proceeds from the federally guaranteed debt financing completed in April 2014 were used to fund project costs until the Project’s debt to equity ratio reached 70 per cent to 30 per cent respectively, which occurred in Q4 2015. From that point forward, project costs are funded with debt and equity at a 70 per cent to 30 per cent ratio, with equity contributions of $13.4 million in Q4 2015.

Project to date, ENL has invested $207.3 million of equity, including $21.2 million of equity earnings, in LIL. Equity earnings are recorded based on an annual rate of 8.8 per cent of the equity invested. The rate is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities.

LIQUIDITY AND CAPITAL RESOURCES

The Company generates cash primarily through its investments in various regulated and non-regulated energy related entities and investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include general economic downturns in Emera’s markets, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets and changes in environmental legislation. Emera’s subsidiaries maintain solid credit metrics and are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment.

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Consolidated Cash Flow Highlights

Significant changes in the statements of cash flows between the years ended December 31, 2015 and 2014 include:

Year ended December 31 millions of Canadian dollars	2015			2014			$ Change
Cash and cash equivalents, beginning of period	$	221.1		$	100.8		$	120.3
Provided by (used in):
Operating cash flow before changes in working capital		775.8			716.3			59.5
Change in working capital		(101.6	)		46.2			(147.8	)
Operating activities		674.2			762.5			(88.3	)
Investing activities		(123.7	)		(710.9	)		587.2
Financing activities		221.1			58.2			162.9
Effect of exchange rate changes on cash and cash equivalents		80.7			10.5			70.2
Cash and cash equivalents, end of period	$	1,073.4		$	221.1		$	852.3

Operating Cash Flows

Refer to Consolidated Income Statement Highlights for details.

Investing Cash Flows

Net cash used in investing activities decreased $587.2 million to $123.7 million for the year ended December 31, 2015 compared to $710.9 million for the year ended December 31, 2014. The decrease was primarily due to proceeds from the sale of NWP in 2015, proceeds from the Bear Swamp distribution, purchase of APUC subscription receipts in 2014 and higher levels of investment in NSPML and M&NP in 2014, partially offset by increased capital spend and Emera Maine’s investment in a customer information system.

Capital expenditures, including AFUDC and net of proceeds from disposal of assets, for the year ended December 31, 2015 were $436 million compared to $462 million in 2014 primarily due to decreased capital spending in Emera Energy and Emera Maine, partially offset by increased capital spending at Emera Caribbean. Details of the capital spend are shown below:

• $274 million in NSPI (2014 - $274 million);

• $66 million in Emera Maine (2014 - $85 million);

• $44 million in Emera Caribbean (2014 - $30 million);

• $42 million in Emera Energy (2014 - $63 million);

• $10 million in Corporate and Other (2014 – $10 million)

Financing Cash Flows

Net cash provided by financing activities increased $162.9 million to $221.1 million for the year ended December 31, 2015 compared to $58.2 million in December 31, 2014. The increase was primarily due to the proceeds of convertible debentures represented by instalment receipts related to the pending acquisition of TECO Energy, net of issuance costs, of $681.4 million and the proceeds of the long-term debt issuance by Brunswick Pipeline and NSPI. This was partially offset by the redemption of NSPI’s preferred shares, repayment of debt in 2015 and the issuance of common and preferred stock in Q1 2014.

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Working Capital

As at December 31, 2015, Emera’s cash and cash equivalents were $ 1,073.4 million (2014 – $221.1 million) and Emera’s investment in non-cash working capital was $599.2 million (2014 – $358.3 million). Of the $ 1,073.4 million of cash and cash equivalents held at December 31, 2015, $727.6 million is from the proceeds from the convertible debentures for the pending TECO Energy acquisition and are held in USD. Of the remaining cash and cash equivalents, $373.2 million is held by Emera’s foreign subsidiaries (2014 – $206.0 million). A portion of these funds are invested in countries that have certain exchange controls, required approvals, and processes for repatriation. Such funds remain available to fund local operating and capital requirements unless repatriated.

Emera’s future liquidity and capital needs will be predominately for working capital requirements and capital expenditures in support of growth throughout the businesses, as well as acquisitions, dividends and debt servicing. These liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to debt and equity capital markets.

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Contractual Obligations

As at December 31, 2015, commitments for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2016		2017		2018		2019		2020		Thereafter		Total
Long-term debt	$	274.0	$	53.0	$	25.5	$	619.6	$	728.7	$	2,323.6	$	4,024.4
Purchased power (1)		221.7		235.0		208.6		203.1		199.4		2,462.8		3,530.6
Coal, biomass, oil and natural gas supply		150.2		82.1		12.2		—		—		—		244.5
DSM (2)		24.7		34.0		34.9		—		—		—		93.6
Pension and post-retirement obligations (3)		14.8		19.2		19.8		20.2		20.9		716.7		811.6
Asset retirement obligations		5.5		4.0		4.3		4.2		1.7		317.2		336.9
Interest payment obligations (4)		187.7		178.8		176.3		175.3		141.3		2,249.9		3,109.3
Convertible debentures represented by instalment receipts (5)		727.6		—		—		—		—		—		727.6
Interest obligations on the first instalment of convertible debentures represented by instalment receipts (5)		75.9		—		—		—		—		—		75.9
Transportation (6)		183.6		72.2		55.8		25.7		20.9		86.9		445.1
Long-term service agreements (7)		56.6		45.0		33.6		55.7		18.4		207.1		416.4
Capital projects		68.9		7.1		—		—		—		—		76.0
Equity investment commitments (8)		379.6		159.0		—		—		—		—		538.6
Leases and other (9)		12.6		11.6		9.5		8.9		7.5		27.5		77.6
	$	2,383.4	$	901.0	$	580.5	$	1,112.7	$	1,138.8	$	8,391.7	$	14,508.1

(1) Purchased power: annual requirement to purchase 20 - 100 per cent of electricity production from independent power producers over varying contract lengths up to 25 years.

(2) DSM: program is expected to continue however no amounts have been committed after 2018.

(3) Pension and post-retirement obligations: Defined benefit funding contractual obligations were determined based on funding requirements and assuming pension accruals cease as at December 31, 2015. Credited service and earnings are assumed to be crystallized as at December 31, 2015. The Company contractual obligations for post-retirement (non-pension) benefits assumes members must be age 55 or over as at December 31, 2015 to be eligible. As the defined benefit pension plans currently undergoes regular reviews to revise contribution requirements and members are still accruing service under the plans, actual future contributions to the plans will differ from the amounts shown.

(4) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2015 including any expected required payment under associated swap agreements.

(5) Convertible debentures: On September 28, 2015, to finance a portion of the pending acquisition of TECO Energy, Emera completed the sale of $1.9 billion principal amount of 4 per cent convertible unsecured subordinated debentures. On October 2, 2015 the over-allotment option was exercised and $285 million in additional Debentures were sold. The table above shows the obligations as a result of this Debenture Offering. Further information on the Debenture Offering is in the Developments section.

(6) Transportation: purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines.

(7) Long-term service agreements: maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(8) Emera has a commitment in connection with the Federal Loan Guarantee (“FLG”) to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to LIL upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amount as the projects advance through construction.

(9) Leases: operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

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Forecasted Gross Consolidated Capital Expenditures

For the year ended December 31, 2016, forecasted gross consolidated capital expenditures are as follows:

millions of Canadian dollars	NSPI		Emera Maine		Emera Caribbean		Emera Energy		Corporate and Other		Total
Generation	$	105.0	$	—	$	17.9	$	29.9	$	—	$	152.8
New renewable generation		—		—		67.3		—		—		67.3
Transmission		56.1		33.6		5.9		—		—		95.6
Distribution		74.8		34.3		38.3		—		—		147.4
Facilities, equipment, vehicles, and other		44.0		17.2		20.1		—		20.4		101.7
	$	279.9	$	85.1	$	149.5	$	29.9	$	20.4	$	564.8

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $1.3 billion committed syndicated revolving bank lines of credit, as discussed in the table below. NSPI has an active commercial paper program for up to $400 million, of which the full amount outstanding is backed by the Company’s bank line referred to below. The amount of commercial paper issued results in an equal amount of credit being considered drawn and unavailable.

As at December 31, 2015, the Company’s total credit facilities, outstanding borrowings and available capacity were as follows:

millions of dollars	Maturity		Revolving Credit Facilities		Utilized		Undrawn and Available
Emera – Operating and acquisition credit facility		June 2020 – Revolver	$	700	$	268	$	432
NSPI – Operating credit facility (1)		October 2020 – Revolver		500		370		130
Emera Maine – in USD – Operating credit facility		September 2019 – Revolver		80		25		55
Other – in USD – Operating credit facilities		Various		32		—		32

(1) Extended to October 2020 on December 15, 2015.

For the purpose of bridge financing for the pending acquisition of TECO Energy, on September 4, 2015, the Company secured an aggregate of $6.5 billion USD non-revolving term credit facilities (“Acquisition Credit Facilities”) from a syndicate of banks. The non-revolving term credit facilities are comprised of a $4.3 billion USD debt bridge facility, repayable in full on the first anniversary following its advance, and a $2.2 billion USD equity bridge facility repayable in full on the first anniversary following its advance. On October 16, 2015, Emera permanently reduced the USD bridge facilities in the amount of $588.3 million USD with the proceeds of the first instalment of the convertible debentures and the proceeds from the Bear Swamp financing. The credit facilities table above does not include the Acquisition Credit Facilities.

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Emera is required to effect reductions or make prepayments of the Acquisition Credit Facilities in an amount equal to the net cash proceeds from any common equity, preferred equity, bond or other debt offerings and any non-ordinary course asset sales by Emera and its subsidiaries, subject to certain prescribed exceptions and certain other prescribed transactions. Net proceeds from any such offerings, including the net proceeds of the final instalment under the Debenture Offering, or from any such non-ordinary course asset sales or transactions, will be applied to permanently reduce the commitments of the lenders under the Acquisition Credit Facilities or to repay the Acquisition Credit Facilities after they are drawn. Any prepayment under the Acquisition Credit Facilities may not be re-borrowed. The Acquisition Credit Agreements will contain customary representations and warranties and affirmative and negative covenants of Emera that will closely resemble those in Emera’s existing revolving credit facility.

Emera and its subsidiaries’ recent financing activity is discussed further in the Developments section.

As at December 31, 2015, approximately 84 per cent of Emera’s consolidated debt position is fixed rate in nature, with an average term to maturity of approximately 17 years. Emera’s scheduled maturities for debt over the next five years are expected to be $274 million, $53 million, $25 million, $588 million and $120 million for 2016 through 2020 respectively.

Emera’s future liquidity and capital needs, not including the capital needs to fund the pending TECO Energy acquisition, will be predominately for working capital requirements and capital expenditures in support of growth throughout the businesses, as well as potential new acquisitions, dividends and debt servicing. These liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to capital markets.

The cash purchase price of the pending TECO Energy acquisition and the acquisition related costs will be financed at the closing of the acquisition with one or more of the following sources: (i) net proceeds of the first instalment and second instalment under the Debenture Offering, (ii) net proceeds of any subsequently completed preferred equity or bond or other debt offerings, (iii) amounts drawn under the acquisition credit facilities and the revolving facility, and (iv) existing cash on hand and other sources available to the Company. Common equity and other available sources are expected to comprise $1.7 billion USD to $2.1 billion USD of the long-term financing for the acquisition, preferred equity offerings are expected to amount to $0.8 billion USD to $1.2 billion USD and bond or other debt offerings are expected to amount to $3.4 billion USD to $3.8 billion USD.

Emera and its subsidiaries have certain financial and other covenants associated with their debt and credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements. Emera’s significant covenant is listed below:

	Financial Covenant	Requirement	As at December 31, 2015
Emera
Syndicated credit facilities	Debt to capital ratio	Less than or equal to 0.70 to 1		0.51:1

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Credit Ratings

Emera

On March 11, 2015, DBRS removed Emera from “Under Review with Developing Implications” following the closing of the Brunswick Pipeline financing and the sale of NWP. On the same date, DBRS confirmed Emera’s Issuer Rating and Medium-Term Notes rating at BBB (high) and the Cumulative Preferred Shares Rating at Pfd-3 (high), all with Stable trends.

On September 4, 2015, following the announcement of the TECO Energy acquisition, DBRS placed the ratings of Emera ‘Under Review with Developing Implications’. The rating actions reflect DBRS’s view that while the TECO Energy acquisition would have a relatively neutral impact on Emera’s business risk assessment, the impact on the financial risk assessment was at the time of the ratings actions uncertain as Emera’s financing plan had not been finalized. DBRS indicated that it will further review Emera’s financing plan when it is finalized.

On September 8, 2015, Standard and Poor’s (“S&P”) revised its outlook on Emera to negative from stable, while affirming all ratings on Emera, including its ‘BBB+’ long-term corporate rating. S&P indicated that the negative outlook is primarily associated with the Debentures and the risk that they will not be converted into equity upon successful close of the acquisition. S&P could revise its outlook to stable within a two-year outlook period, if the Debentures are successfully converted.

Emera’s credit ratings issued by DBRS and S&P are as follows:

	DBRS	S&P
Long-term corporate	N/A	BBB+
Senior unsecured debt	BBB (high)	BBB

NSPI

On December 18, 2015, DBRS Limited (“DBRS”) affirmed all ratings on NSPI.

On September 8, 2015, Standard and Poor’s Rating Services (“S&P”) affirmed all ratings on NSPI. At the same time it affirmed its rating on Emera and revised Emera’s outlook to negative from stable. The outlook revision for Emera followed Emera’s announcement of the proposed acquisition of TECO Energy. Per S&P’s group rating methodology criteria, NSPI is subject to Emera’s revised outlook.

NSPI’s credit ratings issued by DBRS and S&P are as follows:

	DBRS	S&P
Corporate	N/A	BBB+
Senior unsecured debt	A (low)	BBB+

Emera Maine, BLPC, Domlec and GBPC have no public debt, and accordingly have no requirement for public credit ratings. These utilities believe their credit facilities provide adequate access to capital to support current operations and a base level of capital expenditures. For additional capital needs, these utilities expect to have sufficient access to competitively priced financing in the unsecured or secured debt markets.

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Share Capital

Emera

As at December 31, 2015, Emera had 147.21 million (2014 – 143.78 million) common shares issued and outstanding. For the year ended December 31, 2015, 3.43 million common shares were issued (2014 – 10.89 million) for net proceeds of $141.1 million (2014 – $313.4 million). The issuance of shares was primarily due to facilitate the creation and issuance of depositary receipts in connection with the ECI share acquisition and the dividend reinvestment program.

On December 17, 2015, Emera issued 1.25 million common shares to facilitate the creation and issuance of 5.0 million depositary receipts in connection with the ECI share acquisition.

As at December 31, 2015, Emera had 29.0 million preferred shares issued and outstanding (2014 – 29.0 million).

PENSION FUNDING

For funding purposes, Emera determines required contributions to its largest defined benefit pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the impact of investment gains and losses are recognized over a three-year period. The cash required in 2016 for defined benefit pension plans is expected to be $19.7 million (2015 – $ 23.0 million). All pension plan contributions are tax deductible and will be funded with cash from operations.

Emera’s defined benefit pension plans employ a long-term strategic approach with respect to asset allocation, real return and risk. The underlying objective is to earn an appropriate return, given the Company’s goal of preserving capital within an acceptable level of risk for the pension fund investments.

To achieve the overall long-term asset allocation, pension assets are managed by external investment managers per the pension plan’s investment policy and governance framework. The asset allocation includes investments in the assets of Canadian and global equities, domestic and global bonds and short-term investments. Emera reviews investment manager performance on a regular basis and adjusts the plans’ asset mixes as needed in accordance with the pension plans’ investment policy.

Emera’s projected contributions to defined contribution pension plans are $10.0 million for 2016 (2015 – $9.0 million actual).

Defined Benefit Pension Plan Summary

As at December 31, 2015

in millions of Canadian dollars

Plans by region	NSPI Pension Plans		Emera Maine Pension Plans		Caribbean Plans		Total
Assets as at December 31, 2015	$	1,128.6	$	161.5	$	10.3	$	1,300.4
Accounting obligation at December 31, 2015		1,295.8		211.3		12.6		1,519.7
Accounting expense during fiscal 2015	$	56.1	$	6.4	$	0.4	$	62.9

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OFF-BALANCE SHEET ARRANGEMENTS

Defeasance

Upon privatization of the former provincially owned NSPC in 1992, NSPI became responsible for managing a portfolio of defeasance securities that provide principal and interest streams to match the related defeased debt, which at December 31, 2015 totaled $0.8 billion (2014 – $0.7 billion). The securities are held in trust for Nova Scotia Power Finance Corporation (“NSPFC”), an affiliate of the Province of Nova Scotia. Approximately 70 per cent of the defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance portfolio has a market value higher than the related debt, reducing the future risk of this portion of the portfolio.

Under the privatization agreements, NSPI administers the defeasance cash flows and obligations pursuant to a Management and Administration Agreement. The NSPFC bank accounts are included in NSPI’s pool of bank accounts under a mirror netting agreement and therefore, from time to time, if any cash accumulates in the NSPFC bank account it is available as an offset until that cash is required to service the defeased NSPC debt.

Guarantees and Letters of Credit

Emera had outstanding the following guarantees and letters of credit on behalf of third parties which are not included within the Consolidated Balance Sheets as at December 31, 2015:

• Emera has provided a completion guarantee to the Government of Canada, whereby it has guaranteed the performance of the obligations of NSPML to cause the completion of the Maritime Link Project, subject to certain conditions set out in that guarantee. The cost of those obligations is estimated to be $1.577 billion, which reduces in the ordinary course as project costs are paid.

• Emera has provided a guarantee to the Long Island Power Authority (“LIPA”) on behalf of Bear Swamp for Bear Swamp’s long-term energy and capacity supply agreement (“PPA”) with LIPA, which expires on April 30, 2021. The guarantee is for 50 per cent of the relevant obligations under the PPA up to a maximum of $5.1 million USD. As at December 31, 2015, the fair value of the PPA was positive.

• Standby letters of credit in the amount of $20.5 million USD for the benefit of secured parties in connection with a refinancing of the Bear Swamp joint venture and also to third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one-year term and are renewed annually as required.

• A standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2016 and is renewed annually. The amount committed as at December 31, 2015 was $42.6 million.

• A standby letter of credit to secure obligations under an unfunded pension plan in Emera Maine. The letter of credit expires in October 2016 and is renewed annually. The amount committed as at December 31, 2015 was $2.7 million USD.

• A standby letter of credit was issued to secure the obligations of Emera Reinsurance Limited under reinsurance agreements. The letter of credit expires in February 2016. The amount committed as at December 31, 2015 was $2.0 million USD.

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OUTLOOK

General and Market Trends

Energy markets across North America are affected by a number of trends that shape the environment in which energy and utility companies are operating. Some of these trends are short-term or cyclical, while others evolve to have a significant long-term impact on businesses and stakeholders across the sector.

Among the key trends influencing Emera’s long-term strategy is the increasing expectation by customers and policy-makers for a permanent reduction in the carbon equivalent levels of electricity generation. This advocacy drive for cleaner, renewable sources of electricity has become a defining trend in the industry, not just in the markets Emera serves, but on a global basis. While it is still unclear whether economic volatility and lower fossil fuel prices will slow the pace of this transformation, its impact on the sector continues to be felt in the form of mandated and incented carbon reductions throughout eastern North America and in the Caribbean. As such, investment in wind, solar and hydro generation, and natural gas infrastructure, is likely to continue across the sector.

This transformation in generation and fuel selection also has a significant impact on the requirement for new transmission infrastructure. Increasingly, in addition to the traditional issues of infrastructure life expectancy and changing technology, infrastructure renewal planning must now take into account the changing energy landscape. Gas extraction from the Marcellus Shale region of the United States, major hydro developments in Newfoundland and Labrador, and wind farms in northern New England and Atlantic Canada (to name a few) require significant new transmission infrastructure to bring this energy to market.

The capital spending requirements related to this renewal underscore the intense focus placed by customers and regulators on electricity price and affordability that is required by our franchise agreements and basic rate regulation. Going forward, the ability of energy companies to achieve their growth objectives, environmental targets and other goals, will continue to be a key success factor.

As technology advances, so too does the availability and demand for affordable new mechanisms that allow consumers to have more control over their energy usage and for utilities to introduce more efficient energy solutions for their customers. This includes grid modernization and ‘smart grid’ advances that, when combined with in-home products such as heat pumps and electric thermal storage units, have the potential to significantly increase energy efficiency for consumers while allowing utilities to better manage peak load demand. In addition, wind turbine technology and advancements in solar technology have reduced solar generation costs significantly, bringing them more in line with the cost of fossil fuel generation in some higher-cost jurisdictions. This gives rise to an expectation on the part of customers that they will be able to benefit from options such as distributed generation. Continued and advancing development of energy storage technology will further transform and support the efficient and practical utilization of renewables. This, in turn, raises new issues related to the role of the utility, and the appropriate allocation of existing infrastructure and transmission, generation and distribution costs.

These and other trends create opportunities and challenges for businesses, regulators, investors and other stakeholders within the energy sector, and are expected to drive increased regional cooperation and interconnection within the energy industry. Whether it is the need to transport natural gas and electricity from disparate regions to markets on the eastern seaboard, or the need to gain efficiencies by coordinating electricity generation and dispatch across multiple jurisdictions, inter-regional cooperation has emerged as an important trend itself.

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Business Outlook

The pending TECO Energy acquisition will result in further acquisition costs in 2016. The transaction is expected to be accretive to EPS by approximately 5 per cent in the first full year following its completion (2017), growing to more than 10 per cent by the third full year (2019) assuming a USD/CAD exchange rate consistent with that at the time of announcement. As well, approximately 95 per cent of the expected foreign exchange exposure to close the pending acquisition has been actually or effectively hedged.

Emera’s operations are affected by the US dollar relative to the Canadian dollar. With the increasing disparity between the two currencies, the effect on Emera’s income is noteworthy, as approximately 50 per cent of Emera’s adjusted net income was derived from subsidiaries with a US functional currency. TECO Energy operations are conducted in US dollars and following the pending acquisition, Emera‘s consolidated net income and cash flows will be impacted to a greater extent by movements in the US dollar relative to the Canadian dollar.

NSPI

NSPI’s earnings are most directly impacted by the range of rate of return on equity and capital structure approved by the UARB; the prudent management and approved recovery of operating costs, load, the approved recovery of regulatory deferrals; and the timing and amount of capital expenditures.

NSPI anticipates earning within its allowed ROE range in 2016 and expects its rate base to remain stable. Over the past several years, the requirement to reduce Nova Scotia’s reliance upon high carbon and greenhouse gas emitting sources of energy has resulted in NSPI making a significant investments in renewable energy sources and purchasing third party renewable energy.

On November 10, 2015, NSPI announced it does not plan to file a general rate application related to electricity rates for 2016.

In December 2015, the Electricity Plan Act was enacted by the Province of Nova Scotia, with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period. The Electricity Plan Act requires NSPI to file a three-year rate plan for fuel costs in Q1 2016 and to file a three-year application to change non-fuel rates by April 30, 2016, if required by NSPI. NSPI will continue to work towards rate stability for customers through a focused effort on operating costs, productivity levels and service improvements to meet the requirements of the legislation.

The Company expects to finance its capital expenditures with funds from operations, credit facilities and continued access to debt capital markets for long-term financing.

Emera Maine

Emera Maine’s earnings are most directly impacted by the combined impacts of the range of rates of return on equity and rate base approved by its regulators, the prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures.

Emera Maine’s 2016 ROE is expected to be consistent with prior years. Its ongoing investment in transmission and distribution infrastructure is expected to result in modest growth in rate base.

Emera Maine has an agreement with Central Maine Power Company to pursue specific transmission opportunities in Northern Maine that would relieve transmission congestion and more efficiently collect and deliver wind generation to New England markets. As part of this agreement, Emera Maine and Central Maine Power Company jointly responded to a request for proposals for clean energy from

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Massachusetts, Connecticut and Rhode Island, through an existing jointly owned transmission company, Maine Electric Power Company Inc. (“MEPCO”). The demand for this renewable energy is growing as a result of increasing renewable portfolio requirements of the southern New England states.

Future earnings will generally reflect the impact of transmission rate decisions by the FERC. Emera Maine has fully reserved for the refunds required as a result of a FERC decision on the allowed ROE set at 10.57 per cent.

Overall, Emera Maine 2016 USD earnings are expected to be consistent with prior years.

Emera Caribbean

Earnings from Emera Caribbean are most directly impacted by the combined impacts of the range of rates of return on equity and rate base approved by their regulators, capital structure, the prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures. Earnings are also affected by the investment returns of Emera’s interest in BLPC’s self-insurance fund.

The Barbados economy expects growth of approximately 1.8 per cent forecast for 2016. With oil being the predominant fuel source for generation of electricity in the Caribbean, reduced oil prices may result in an economic benefit on the island in decreased cost of electricity to ratepayers. During 2015, BLPC recognized the need to reduce costs in the business to stabilize future rates to customers. BLPC forecasts to maintain the 2015 cost savings into the future.

The economy of Grand Bahamas is highly correlated to the United States economy and has exhibited signs of improving economic growth and a corresponding growth in load in the industrial sector and weather related growth in the residential sector.

Effective February 1, 2016, the GBPA approved GBPC’s General Rate Application applicable for the 2016 through 2018 period. Residential customers will see decreases up to 4.5 per cent, while commercial customers will see an increase of 1.5 per cent. Commercial customers consume approximately 70 per cent of GBPC’s production. Rates were approved based upon an 8.8 per cent return on rate base, reduced from the previous level of 10 per cent. This rate decision allows for customers to install renewable energy systems and sell their excess energy to GBPC. This is based on a tariff rider scheduled to be in place by Q3 2016.

Tropical Storm Erika affected the island of Dominica on August 27, 2015 and as a result, weaker economic growth is expected to affect sales into 2016. In connection with its pending rate case, Domlec made a preliminary filing in 2014 requesting that a weighted average cost of capital rate of 11.6 per cent be used for rate making purposes. In Q2 2015, the IRC set a cost of capital rate of 8.56 per cent, which Domlec unsuccessfully appealed to the IRC. Domlec made a further appeal to the Dominican court. The rate filing and rate case proceedings will begin after the cost of capital is determined. The cost of capital rate hearing has been delayed, with no new hearing date yet determined due to Tropical Storm Erika.

There are growth opportunities for Emera in the Caribbean market centered on creating and capturing opportunities for cleaner fuels and renewable energy generation. As part of this initiative, construction of a 10 MW solar facility began in Barbados in Q4 2015 and is scheduled for completion in the first half of 2016. In addition, an application to export natural gas to countries with no free trade agreement with the United States, specifically The Bahamas, was filed with the US Department of Energy and approval was received on October 20, 2015, granting long-term multi contract authorization for Emera to export natural gas, by vessel, in the amount of 8 million standard cubic feet per day (“mmscfd”). This complements the authorization received in April 2015 to export up to 25 mmscfd to countries which have a free trade agreement with the United States.

Overall, Emera Caribbean 2016 USD earnings are expected to be consistent with prior years.

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Pipelines

The timing of the income from Pipelines is predominately a result of capital lease accounting treatment which yields declining earnings over the life of the asset.

Pipelines 2016 earnings are expected to be consistent with prior years.

Emera Energy

Emera Energy Services

Emera Energy Services, Emera Energy’s trading and marketing business, is generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply/demand factors, can provide higher levels of margin opportunity. The past three years have seen favourable market conditions in this regard within Emera Energy’s key markets, with Q1 2014, in particular, experiencing unprecedented market volatility. This was a result of the combined impacts of cold weather, constraints in the supply or transportation of natural gas, and other market factors, and contributed to very strong adjusted earnings from trading and marketing, particularly in 2014. 2015 has seen lower market volatility and pricing, and a resulting decrease in trading and marketing adjusted earnings compared to 2014.

In addition to capitalizing on volatility-driven market opportunities, Emera Energy Services expects to continue to grow organically building market share through superior customer service and expanding its geographic reach to adjacent markets, including the Marcellus Shale region.

Planned investment by the industry in gas transportation infrastructure within the Northeast over the next few years could reduce the degree of volatility recently experienced in the market, all other things being equal. This could negatively affect profitability during certain periods.

Emera Energy Generation

Earnings from Emera Energy Generation’s assets are largely dependent on market conditions, in particular, the relative pricing of electricity and natural gas and capacity pricing for the New England Gas Generation Facilities. Efficient operations of the fleet to ensure unit availability, cost management and effective commercial performance are key success factors.

2016 adjusted earnings from Emera Energy generating assets are expected to be lower than 2015, reflecting lower hedged and expected margins as compared to 2015.

In addition to energy margins and ancillary revenue, the New England Gas Generating Facilities and Bear Swamp earn revenue from capacity payments through the forward capacity market (“FCM”), the annual reconfiguration capacity market and the monthly reconfiguration capacity market. Prices for the FCM, the larger of the two components, are determined through an auction process held annually, three years in advance, providing revenue visibility to 2019, presuming the facilities continue to be available to support their capacity obligations. Details of pricing and estimated revenues are outlined in the table below for the New England Gas Generating facilities, and Emera Energy’s 50 per cent interest in Bear Swamp.

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Forward Capacity Auction (“FCA”) Year	Clearing Price in $/kW-month (in USD)	Approximate Estimated Annual Capacity Revenue (in USD) (1)
FCA6 (June 2015 to May 2016)	$3.43	$	40 million
FCA7 (June 2016 to May 2017)	$3.15	$	40 million
FCA8 (June 2017 to May 2018)	$7.025	$	100 million
FCA9 (June 2018 to May 2019)	$9.55 and $11.08 (2)	$	145 million
FCA 10 (June 2019 to May 2020)	$7.03	$	106 million

(1) Includes Emera’s 50 per cent share of Bear Swamp’s capacity revenue

(2) $11.08 was awarded for the Southeast Massachusetts/Rhode Island zone only and, as such, applies only to Tiverton

Bear Swamp’s adjusted earnings will be lower in 2016 and the first half of 2017 primarily due to higher interest costs as a result of its Q4 2015 refinancing. Beginning Q3 2017, these interest costs will be offset by higher capacity revenues.

Corporate and Other

Corporate and Other is dependent, in part, on business development and acquisition related initiatives, which in 2016 will include further acquisition costs related to the pending TECO Energy acquisition, equity investments in the Maritime Link Project and the Labrador-Island Link, project based construction services activity by Emera Utility Services, growth or fluctuations in APUC earnings (which Emera accounts one quarter after APUC reports such earnings), corporate financing and other corporate activities.

Corporate’s contribution to consolidated net income in 2016 is expected to be lower than 2015 primarily due to further acquisition costs and associated financing initiatives related to the pending TECO Energy acquisition. These costs will include a non-cash accounting charge for the difference between Emera’s closing share price on the issuance date of the convertible debentures and their exercise price. This will be recognized once the contingencies surrounding regulatory and other approvals are resolved.

On February 9, 2016, APUC announced its intention to acquire The Empire District Electric Company in a $3.4 billion transaction, which is expected to close in Q1 2017. The closing of this transaction and its related financing will reduce Emera’s ownership interest.

ENL

NSP Maritime Link Inc. (“NSPML”)

Through its subsidiary, NSP Maritime Link Inc., ENL has in total invested approximately $693.9 million of equity and debt, including $78.1 million of AFUDC, in the development of the Maritime Link Project. Project to date, ENL has invested a total of $154.9 million in equity, with the remaining costs being funded with working capital and debt, which has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9 per cent.

ENL’s future earnings contribution from the Maritime Link Project will be affected by the timing of capital expenditures for design and construction activities, which will determine the component of costs to be funded by equity. Proceeds from the federally guaranteed debt financing completed in April 2014 were used to fund project costs until the Project’s debt to equity ratio reached 70 per cent to 30 per cent respectively, which occurred in Q4 2015. From that point forward, project costs are funded with debt and equity at a 70 per cent to 30 per cent ratio, with equity contributions of $13.4 million in Q4 2015.

Maritime Link Project forecasted equity contributions for 2016 and 2017 are $157 million and $159 million respectively, with total equity for the Project estimated to be $470.9 million.

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Labrador Island Link (“LIL”)

ENL is a partner with Nalcor Energy in LIL, which is currently estimated at approximately $3.1 billion. As at December 31, 2015, ENL has invested $207.3 million of equity, including $21.2 million of equity earnings in LIL. Project to date, ENL has invested a total of $186.1 million in equity. Equity earnings are recorded based on an annual rate of 8.8 per cent of the equity invested. The return on ROE is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”). There is currently an application being heard by the NLPUB which includes a review of ROE. The NLPUB’s decision on ROE, expected in Q2 2016, will be applicable for all regulated electrical utilities in Newfoundland and Labrador and become the ROE applicable to ENL’s investment in LIL. ENL has an ongoing equity investment opportunity in LIL. Future earnings are dependent on the timing of additional equity investments and the approved ROE. Total equity contributions for 2015 for LIL are $118.4 million.

LIL forecasted equity contributions for 2016 are $223 million, with total equity investment, by Emera, in the Project estimated to be $409.1 million.

Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s consolidated balance sheets.

TRANSACTIONS WITH RELATED PARTIES

In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues, with an offset to property, plant and equipment, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction. 2014 balances have been retrospectively restated, consistent with this approach. Below are transactions between Emera and its associated companies reported in the Consolidated Statements of Income:

For the millions of Canadian dollars			Year ended December 31
			2015			2014
	Nature of Service	Presentation
Sales to:
APUC subsidiary	Net sale of natural gas and transportation	Operating revenue – non-regulated	$	3.0		$	4.4
NWP	Energy management services	Operating revenue – regulated		0.3			1.1
Purchases from:
M&NP	Natural gas transportation capacity	Regulated fuel for generation and purchased power		4.5			3.6
M&NP	Natural gas transportation capacity	Operating revenue – non-regulated		(23.4	)		(23.8	)
NWP	Purchase of power	Regulated fuel for generation and purchased power	$	0.3		$	1.9

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Operating revenue – non-regulated includes intercompany profit relating to the sale of natural gas, sale of power, construction, operations management and engineering services, and hedging services to rate-regulated subsidiaries of Emera totaling $1.6 million for the year ended December 31, 2015 (2014 – $4.2 million).

Amounts reported on Emera’s Consolidated Balance Sheets due (to) from its equity investments are summarized in the following table:

As at millions of Canadian dollars	December 31 2015			December 31 2014
Due from related parties:
Subsidiary of APUC – current (1)	$	0.7		$	—
NSPML – current		1.6			3.5
M&NP – loan receivable – long-term		2.5			2.5
Due to related parties:
M&NP – current		(2.1	)		(1.6	)
Net due from (to) related parties	$	2.7		$	4.4

(1) Amount due from a subsidiary of APUC is included in accounts receivable.

All amounts are under normal interest and credit terms, except for a loan receivable from M&NP bearing interest at 1 per cent per annum maturing on November 30, 2019.

DIVIDENDS AND PAYOUT RATIOS

Emera Incorporated’s common share dividends paid in 2015 were $1.66 ($0.3875 in Q1, $0.4000 in Q2 and Q3 and $0.4750 in Q4) and $1.48 ($0.3625 per quarter in Q1, Q2 and Q3 and $0.3875 in Q4) per common share for 2014, representing a payout ratio of 72.8 per cent of adjusted net income in 2015 and 65.8 per cent for 2014. The increase in the payout ratio is primarily due to an increase in dividends paid greater than growth in adjusted net income.

On August 10, 2015, Emera’s Board of Directors approved an increase in the annual common share dividend rate from $1.60 to $1.90 per common share.

ENTERPRISE RISK AND RISK MANAGEMENT

Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk management. Certain risk management activities for Emera are overseen by the Enterprise Risk Management Committee to ensure such risks are appropriately assessed, monitored and controlled within predetermined risk tolerances established through approved policies.

The Company’s risk management activities are focused on those areas that most significantly impact profitability, quality of income and cash flow. These risks include, but are not limited to, exposure to regulatory and political risk, acquisition, weather, changes in environmental legislation, energy consumption, foreign exchange, capital market and liquidity risk, interest rate, project development and construction risk, cybersecurity, non-regulated plant operational risk, credit, country, commercial relationships, commodity price risk, future employee benefit plan performance and funding, labour, information technology and un-insured risk.

In this section, Emera describes some of the principal risks that management believes could materially affect its business, revenues, operating income, net income, net assets, or liquidity or capital resources. The nature of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered material may become material in the future.

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Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments in a timely manner. As cost-of-service utilities with an obligation to serve customers, NSPI, Emera Maine, BLPC, GBPC, and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs and investments can be recovered upon approval by the respective regulator of the recovery in adjustments to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. In addition, the commercial and regulatory frameworks under which Emera and its subsidiaries operate can be impacted by significant shifts in government policy and changes in governments. Emera’s investments in entities in which it has significant influence and which are subject to regulatory risk include: NSPML, APUC, M&NP, LIL and Lucelec.

During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these subsidiaries and their respective regulators determine whether to allow recovery and to adjust rates based upon the subsidiaries’ evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, fuel-related audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.

Brunswick Pipeline entered into a 25-year firm service agreement, expiring in 2034, with Repsol Energy Canada (“REC”), which was filed with the NEB. The firm service agreement provides for predetermined toll increases after the fifth and fifteenth year of the contract. As a regulated Group II pipeline, the tolls of Brunswick Pipeline are regulated by the NEB on a complaint basis. Brunswick Pipeline is required to make copies of tariffs and supporting financial information readily available to interested persons. Persons who cannot resolve traffic, toll and tariff issues with Brunswick Pipeline may file a complaint with the NEB. In the absence of a complaint, the NEB does not normally undertake a detailed examination of Brunswick Pipeline’s tolls.

Acquisition Risk

The risks associated with Emera’s acquisition strategy include potential difficulties inherent in acquisitions that may adversely affect the results of an acquisition and these include delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies from completed transactions.

Emera mitigates these risks by following systematic procedures for integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to close monitoring and review by the Board of Directors.

Completion of the Acquisition of TECO Energy

The closing of the acquisition of TECO Energy is subject to the commercial risks associated with a publicly owned regulated utility acquisition per the terms negotiated in the acquisition agreement. The acquisition is subject to approval of certain regulatory and government approvals, including approval by the New Mexico Public Regulation Commission, the Committee on Foreign Investment in the United States, and the satisfaction of closing conditions. Shareholder approval of the transaction was received on December 3, 2015. On December 14, 2015, the New Mexico Public Regulation Commission established a hearing to begin on May 23, 2016 for the joint application for approval of the change in control of New Mexico Gas Co. effected by the Transaction. On January 21, 2016, the FERC approved the Transaction. On February 8, 2016, the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, waiting period expired.

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Failure to obtain the required approvals or satisfy or waive the conditions contained in the acquisition agreement may result in the termination of the acquisition agreement. There is no assurance that such closing conditions will be satisfied or waived. Accordingly, there can be no assurance that Emera will complete the acquisition in the timeframe or on the basis described herein, if at all. The termination of the acquisition agreement may have a negative effect on the price of the instalment receipts, the Debentures and the common shares and will result in the redemption of the Debentures. If the closing of the acquisition does not take place as contemplated, the Company could suffer adverse consequences, including the loss of investor confidence.

A substantial delay in obtaining regulatory approvals or the imposition of unfavourable terms and/or conditions in such approvals could have a material adverse effect on the Company’s ability to complete the acquisition and on the Company’s or TECO Energy’s business, financial condition or results of operations. In addition, in the event that such regulatory agencies impose unfavourable terms and/or conditions on Emera or any TECO Energy utility (including the requirement to sell or divest of certain assets or limitations on the future conduct of the individual or combined entities), the Company would still be required to complete the transaction on the terms set forth in the acquisition agreement. Emera intends to complete the acquisition within three days of obtaining the required TECO Energy shareholder approval and regulatory approvals and satisfaction of the other required closing conditions.

Emera expects the pending acquisition of TECO Energy will provide benefits to the Company, including that the acquisition will be accretive to Emera’s EPS by approximately five per cent in the first full year following its completion (2017), excluding acquisition related expenses, growing to more than 10 per cent by the third full year (2019), assuming a USD/CAD exchange rate consistent with that at the time of announcement. As well, approximately 95 per cent of the expected foreign exchange exposure to close the pending acquisition has been actually or effectively hedged. In addition, the availability of net operating loss carry-forwards and alternative minimum tax credits, if utilized, are expected to provide significant accretion to Emera’s cash position. However, there is a risk that some or all of the expected benefits of the acquisition may fail to materialize, or may not occur within the time periods anticipated by the Company. The realization of such benefits may be affected by a number of factors, many of which are beyond the control of the Company. The challenge of combining previously independent businesses makes evaluating the Company’s business and future financial prospects difficult. The past financial performance of the Company may not be indicative of its future financial performance. In addition, any regulatory approvals required in connection with the acquisition may include terms which could have an adverse effect on the Company’s financial performance, including reduced revenues or investment recovery, increased competition or costs, or adverse alterations to the rate structure.

Failure to realize the anticipated benefits of the acquisition may impact the financial performance of the Company, the price of its common shares and the ability of Emera to continue to pay dividends on its common shares at current levels or at all. The declaration of dividends by the Company is at the discretion of the Board of Directors.

In addition to the potential liability for damages for breach of the acquisition agreement by Emera, if (i) the acquisition agreement is terminated by either party due to a failure to obtain the required regulatory approvals by the end date specified in the acquisition agreement, or because there is a final and non-appealable legal restraint that relates to the required regulatory approvals, or if TECO Energy terminates the acquisition agreement based on a failure by Emera to perform its agreements with respect to the receipt of the required regulatory approvals, and, in each case, at the time of such termination the TECO Energy shareholder approval shall have been obtained and the other closing conditions on behalf of Emera shall have been satisfied or waived (except for those conditions, that by their nature, are to be satisfied at the closing of the acquisition, but which conditions would be satisfied, or would be capable of being satisfied, if the closing of the Acquisition were to occur on the date of such termination and those conditions that have not been satisfied as a result of a breach of the acquisition agreement by Emera), or (ii) TECO Energy terminates the acquisition agreement in the event that all applicable closing conditions have been satisfied or waived and Emera fails to close the acquisition because of a failure of any person or entity to provide acquisition financing, then Emera will be obligated to pay to TECO Energy a fee of $326.9 million USD in cash.

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For the purpose of financing the pending acquisition, Emera completed a $2.185 billion Debenture Offering in September and October 2015, including the exercise of an over-allotment. The Company also obtained a commitment letter for an aggregate of $6.5 billion USD non-revolving credit facilities. On October 16, 2015, Emera permanently reduced the USD bridge facilities in the amount of $588.3 million USD with the proceeds of the first instalment of the convertible debentures and the proceeds from the Bear Swamp financing. The commitment of the lenders to enter into the acquisition credit facilities is subject to certain standard conditions, which may result in such facilities becoming unavailable to Emera in certain circumstances. If the acquisition credit facilities become unavailable to Emera, Emera may not be able to complete the acquisition.

Completion of the acquisition is not conditional on the completion of the Debenture Offering by the Company or on the Company obtaining financing on favourable terms or at all. If a material amount due on payment of the final instalment is not paid by holders of instalment receipts and the Company is not able to quickly realize on the Debentures pledged to secure the obligation to pay the final instalment, the Company will not be able to use those proceeds to repay the acquisition credit facilities. As a result, it may take Emera longer than anticipated to repay the acquisition credit facilities which may have a negative impact on the consolidated capitalization of Emera until such time as the acquisition credit facilities have been repaid by Emera in full.

There is no guarantee that alternate sources of funding will be available to Emera or its affiliates at the desired time or at all, or on cost-effective terms. The inability to obtain alternate sources of funding to fund the acquisition or replace the acquisition credit facilities may negatively impact the financial performance of Emera, including the extent to which the acquisition is accretive. In addition, any movement in interest rates that could affect the underlying cost of these instruments may affect the expected accretion of the acquisition.

Emera expects to incur a number of costs associated with completing the acquisition. The majority of these costs will be non-recurring expenses resulting from the acquisition and will consist of transaction costs related to the acquisition, including costs relating to the financing of the acquisition and obtaining regulatory approvals. Additional unanticipated costs may be incurred relating to the acquisition.

Between September 16, 2015 and November 2, 2015, purported shareholders of TECO Energy filed twelve separate complaints styled as class action lawsuits in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida or the United States District Court for the Middle District of Florida (the “Merger Litigation”). Each complaint alleges, among other things, that the Board of Directors of TECO Energy breached its fiduciary duties in agreeing to the acquisition agreement and that Emera and/or Emera US Inc. aided and abetted such alleged breaches. The complaints seek to enjoin the merger pursuant to the acquisition agreement.

On November 17, 2015, TECO Energy, Emera, Emera US Inc. and the Board of Directors of TECO Energy entered into a memorandum of understanding with the shareholder plaintiffs to settle all of the Merger Litigation, subject to negotiation of a stipulation of settlement with the plaintiffs and to court approval. The memorandum of understanding provides for all claims against the defendants to be released in exchange for TECO Energy making certain additional disclosures to its shareholders related to the proposed merger (which have now been made).

There is no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.

Weather Risk

Shifts in weather patterns affect electric sales volumes and associated revenues and costs. Extreme weather events generally result in increased operating costs associated with restoring power to customers, as a result of unplanned outages. Emera responds to significant weather events related outages according to each subsidiary’s respective emergency services restoration plan.

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Changes in Environmental Legislation

Emera is subject to regulation by federal, provincial, state, regional and local authorities with regard to environmental matters; primarily related to its utility operations. This includes laws setting greenhouse gas (“GHG”) emissions standards and air emissions standards. Emera is also subject to laws regarding the generation, storage, transportation, use and disposal of hazardous substances and materials.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera.

New emission reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s operations and financial performance. Stricter environmental laws and enforcement of such laws in the future could increase Emera’s exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments.

Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and with the objective of achieving full compliance with applicable laws, legislation and company policies and standards. Emera has implemented this policy through the development and application of environmental management systems in its operating subsidiaries. Comprehensive audit programs are also in place to regularly test compliance with such laws, policies and standards.

Energy Consumption Risk

Typical of utilities, Emera is affected by demand for energy in the areas in which it operates based upon fluctuations in general economic conditions, such as changes in employment levels, personal disposable income, energy prices and housing starts. Customers’ focus on energy efficiency could also result in changes in energy consumption.

Government policies promoting distributed generation (“DG”) and new technology developments enabling those policies, particularly with rooftop solar, have the potential to impact residential sales and thereby revenues. This could negatively impact operations, net earnings and cash flows. Energy costs and clean energy options have increased demand for products enabling the consumers’ ability to self-generate.

Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. In 2015, approximately 50 per cent of Emera’s adjusted net income was derived from subsidiaries with US functional currency. As such, its earnings are subject to fluctuations in the Canadian dollar to US dollar exchange rate. As discussed below, the pending acquisition of TECO Energy will increase this percentage significantly.

The Company identifies and hedges significant transactional currency risks in accordance with its policies and procedures. Emera does not currently hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries are included in accumulated other comprehensive income (loss) (“AOCI”).

The Company enters into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenues streams, capital expenditures and capital projects. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange.

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Emera does not enter into hedges for its foreign currency translation exposure on its non-Canadian assets. Any changes in the Canadian exchange rate will affect the equivalent Canadian dollar value of such assets, and the equivalent Canadian dollar value of these assets, revenues and earnings contributions.

Pending TECO Energy Acquisition

The cash consideration for the acquisition is required to be paid in US dollars, while funds raised in the Debenture Offering or any other Canadian dollar offering, which may constitute a significant portion of the funds ultimately used to finance the acquisition, are denominated in Canadian dollars. As a result, increases in the value of the US dollar versus the Canadian dollar prior to either the payment of the final instalment or the close of any Canadian dollar offerings will increase the purchase price translated in Canadian dollars and thereby increase the Canadian dollars required to fund the US dollar purchase price for the acquisition ultimately obtained by Emera.

The proceeds of the first instalment of the Debenture Offering and the overallotment were converted to US dollars and invested in short-term US dollar investment grade securities. During the month of October 2015, Emera entered into foreign exchange forward contracts to economically hedge an amount equal to the anticipated proceeds from the second instalment of the Debenture Offering of the pending TECO Energy acquisition of $1.457 billion. These foreign exchange contracts are economic hedges and do not qualify for hedge accounting. Therefore, all mark-to-market gains and losses related to the forwards and related to the US denominated cash proceeds will be recognized in net income for the period. Until the hedge settles and the USD denominated cash is used to acquire TECO Energy, foreign exchange fluctuations could create significant mark-to-market adjustments that may result in volatility in Emera’s earnings.

In addition, the operations of TECO Energy are conducted in US dollars. Following the acquisition, the

consolidated net income and cash flows of Emera will be impacted to a greater extent by movements in the US dollar relative to the Canadian dollar. In particular, decreases in the value of the US dollar versus the Canadian dollar following the acquisition, could negatively impact the Company’s net income as reported in Canadian dollars, which could cause a failure to realize all or some of the anticipated benefits of the acquisition, including accretion.

Capital Market and Liquidity Risk

Emera’s utility and non-utility operations and projects in development require significant capital investments in property, plant and equipment. Consequently, Emera is an active participant in the debt and equity markets. Any disruption in capital markets could have a material impact on Emera’s ability to fund its operations. Capital markets are global in nature and are affected by numerous events throughout the world economy. Capital market disruptions could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions.

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera forecasts cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to capital markets. The Company reasonably expects liquidity sources to exceed ordinary course capital needs.

Emera is subject to financial risk associated with changes in its credit ratings. A change to a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of adequate credit support for subsidiary operations.

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Interest Rate Risk

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.

The Company is subject to interest rate risk relating to certain sources of expected funds to effect the TECO Energy acquisition. Any movement in interest rates could affect the underlying cost of the instrument used to fund the acquisition. The Company may enter into interest rate hedging contracts to limit its exposure to fluctuations in interest rates.

For Emera’s regulated subsidiaries, the cost of debt is generally passed through to ratepayers. While regulatory ROE rates will generally and indirectly follow the direction of interest rates, such that regulatory ROE’s are likely to fall in times of reducing interest rates and raise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives.

Project Development and Construction Risk

ENL’s planned investment in the development of the Maritime Link Project has risks commensurate with any large construction project. Risks related to such large projects include impact on costs of schedule delays and risk of cost overruns. Emera has deployed a robust project and risk management approach to this project, led by a team with extensive experience in large projects. There are also significant contractual terms in place protecting Emera and ENL from any exposure to cost overruns to either of Nalcor’s projects and with specific provisions for Nalcor sharing in cost overruns of the Maritime Link Project.

In February 2015, ENL entered into a contract with Abengoa S.A., a global Spanish energy company, for the transmission line construction on the Maritime Link Project. On November 25, 2015, Abengoa S.A. filed a notice under Spanish law, which provides for pre insolvency protection in Spain, giving the company up to four months to reach an agreement with creditors to avoid a full insolvency process. ENL is working closely with Abengoa and the performance bond sureties to minimize project impacts. Work on the Project continues.

Cybersecurity Risk

Emera’s reliance on information technology to manage its business exposes the Company to potential risks related to cybersecurity attacks and unauthorized access to the Company’s, customers’, suppliers’, counterparties’ and employees’ sensitive or confidential information, (which may include personally identifiable information and credit information) through hacking, viruses and otherwise (collectively “cybersecurity threats”). The Company uses information technology systems and network infrastructure, which include controls for interconnected systems of generation, distribution, and transmission, some of which is shared with third parties for operating purposes. Through the normal course of business, the Company also collects, processes, and retains sensitive and confidential customer, supplier, counter-party and employee information.

Despite security measures in place, the Company’s systems, assets and information could be vulnerable to cybersecurity attacks and other data security breaches that could cause system failures, disrupt operations, adversely affect safety, result in loss of service to customers and release of sensitive or confidential information. Should such cybersecurity threats materialize the Company could suffer costs, losses and damages; all or some of which may not be recoverable through regulatory processes or otherwise.

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Emera Energy Trading and Marketing

The majority of Emera’s portfolio of electricity and gas marketing and trading contracts, and in particular its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets, in the event of an operational issue or counterparty default. To measure commodity price risk exposure, Emera employs a number of controls and process, including an estimated value-at-risk (“VaR”) analysis of its exposures. The VaR amount represents an estimate of the potential change in fair value that could occur from changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical commodity, primarily in natural gas and power positions. The Company’s commercial arrangements, including the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments, as well as its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are all used to manage and mitigate this risk.

Emera Energy Electricity Sales and Non-Regulated Fuel for Generation and Purchased Power

Emera Energy’s natural gas fired plants in northeastern United States, operating as merchant facilities, are susceptible to the volatility of the New England electricity market and natural gas prices. Market electricity prices are dependent upon a number of factors, including the projected supply and demand of electricity, natural gas prices, the price of other materials used to generate electricity, the cost of complying with applicable environmental and other regulatory requirements and weather conditions. A material change in any one of these factors can materially affect the profitability of the facilities.

Non-Regulated Plant Operational Risk

Emera owns three combined-cycle gas-fired electricity generating facilities in New England (New England Gas Generating Facilities) as well as a gas fired generating facility and biomass fired generating facility in Maritime Canada (Bayside Power and Brooklyn Energy). Power plant operations involve the risk of outages due to failure of generation equipment, transmission lines, pipelines or other equipment, which could make the affected plant unavailable to provide service. Unplanned outages could result in lost revenues, increased capital costs and maintenance expenses, payment of cover costs for any hedges in place, and reduced profitability. Insurance is maintained to mitigate operating risks.

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts.

Country Risk

Operating revenues outside of Canada constituted 45 per cent (28 per cent from the US and 17 per cent from the Caribbean) of Emera’s total operating revenues in 2015 (2014 – 48 per cent, with 31 per cent from the US and 17 per cent from the Caribbean). Emera’s investments are currently in regions where the political and economic risk levels are considered by the Company to be acceptable. Emera’s operations in some countries may be subject to the following risks: changes in the rate of economic growth, restrictions on the repatriation of income or capital exchange controls, inflation, the effect of global health, safety and environmental matters or economic conditions and market conditions, and change in financial policy and availability of credit.

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Commercial Relationships Risk

The Company is exposed to commercial relationships risk in respect of its reliance on certain key partners, suppliers and customers. The Company manages its commercial relationships risk by monitoring credit risk, as discussed below in Credit Risk, and monitoring of significant developments with its customers, partners and suppliers.

Commodity Price Risk

A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs.

Future Employee Benefit Plan Performance and Funding Risk

Certain Emera subsidiaries have both defined benefit and defined contribution employee benefit plans that cover their employees and retirees. All defined benefit plans are closed to new entrants. The cost of providing these benefit plans varies depending on the plan provisions, interest rates, investment performance and actuarial assumptions concerning the future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used to determine funding levels and contributions to the plans) and expectations around future salary growth, inflation and mortality. Two of the largest drivers of cost are investment performance and interest rates, which are affected by global financial and capital markets. Depending on future interest rates and actual versus expected investment performance, Emera could be required to make larger contributions in the future to fund these plans, which could affect Emera’s cash flows, financial condition and operations.

Labour Risk

Certain Emera employees are subject to collective labour agreements. Approximately 49 per cent of the full-time and term employees within the Emera labour force are represented by local unions.

As at December 31, 2015, approximately seven per cent of the entire labour force is covered by collective labour agreements that will expire within the next 12 months. Emera seeks to manage this risk through ongoing discussions with local unions. The Company maintains contingency plans in each of its operations to manage and reduce the effect of any potential labor disruption.

Information Technology Risk

Emera relies on various information technology systems to manage operations. This subjects Emera to inherent costs and risks associated with maintaining, upgrading, replacing and changing these systems. This includes impairment of its information technology, potential disruption of internal control systems, substantial capital expenditures, demands on management time and other risks of delays, difficulties in upgrading existing systems, transitioning to new systems or integrating new systems into its current systems.

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Uninsured Risk

Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities, and to provide indemnity in the event of liability to third parties. This is consistent with Emera’s risk management policies. There are certain elements of Emera’s operations which are not insured. These include a significant portion of its electric utilities’ transmission and distribution assets, as is customary in the industry. The cost of this coverage is not economically viable. In addition, Emera accepts deductibles and self-insured retentions under its various insurance policies. Insurance is subject to coverage limits as well as time sensitive claims discovery and reporting provisions and there can be no assurance that the types of liabilities or losses that may be incurred by the Company and its subsidiaries will be covered by insurance. Emera’s regulated utilities would likely apply to their respective regulatory authority to recover any loss or liability through increased customer rates, though there is no assurance the regulatory authority would approve such application in whole or in part.

The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by Emera and its subsidiaries or claims that fall within a significant self-insured retention could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if regulatory recovery is not available. A limited portion of Emera’s property and casualty insurance is placed with a wholly owned captive insurance company. If a loss is suffered by the captive insurer, it is not able to recover that loss other than through future premiums.

RISK MANAGEMENT INCLUDING FINANCIAL INSTRUMENTS

Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management policies and practices are overseen by the Board of Directors. The Company has established a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes establishment of the Enterprise Risk Management Committee, whose responsibilities include preparing and updating a “Risk Dashboard” for the Board of Directors on a quarterly basis. Furthermore, a corporate team independent from operations is responsible for tracking and reporting on market and credit risks.

The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates through contractual protections with counterparties where practicable, as well as by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. Collectively, these contracts and financial instruments are considered “derivatives”.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period.

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Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value, with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, inventory or property, plant and equipment, depending on the nature of the item being economically hedged. Management believes that any gains or losses resulting from settlement of these derivatives be refunded to or collected from customers in future rates.

Derivatives that do not meet any of the above criteria are designated as HFT and are recognized on the balance sheet at fair value. All gains or losses are recognized in net income of the period unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies.

Hedging Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:

As at millions of Canadian dollars	December 31 2015			December 31 2014
Derivative instrument assets (current and other assets)	$	19.8		$	23.0
Derivative instrument liabilities (current and long-term liabilities)		(46.2	)		(19.2	)
Net derivative instrument assets (liabilities)	$	(26.4	)	$	3.8

Hedging Impact Recognized in Net Income

The Company recognized gains (losses) related to the effective portion of hedging relationships under the following categories:

For the millions of Canadian dollars	Year ended December 31
	2015			2014
Operating revenues – regulated	$	(9.0	)	$	(3.7	)
Non-regulated fuel for generation and purchased power		4.8			0.9
Income from equity investments		(0.6	)		(0.5	)
Interest expense, net		—			(0.2	)
Effective net gains (losses)	$	(4.8	)	$	(3.5	)

The effective net gains (losses) reflected in the above table would be offset in net income by the hedged item realized in the period.

The Company recognized in net income the following gains (losses) related to the ineffective portion of hedging relationships under the following categories:

For the millions of Canadian dollars	Year ended December 31
	2015			2014
Non-regulated fuel for generation and purchased power	$	(0.1	)	$	2.7
Ineffective gains (losses)	$	(0.1	)	$	2.7

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Regulatory Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:

As at millions of Canadian dollars	December 31 2015			December 31 2014
Derivative instrument assets (current and other assets)	$	209.9		$	97.7
Regulatory assets (current and other assets)		64.3			43.6
Derivative instrument liabilities (current and long-term liabilities)		(64.3	)		(40.3	)
Regulatory liabilities (current and long-term liabilities)		(209.9	)		(97.7	)
Net asset (liability)	$	—		$	3.3

Regulatory Impact Recognized in Net Income

The Company recognized the following net gains (losses) related to derivatives receiving regulatory deferral as follows:

For the millions of Canadian dollars	Year ended December 31
	2015		2014
Regulated fuel for generation and purchased power (1)	$	41.2	$	17.7
Net gains (losses)	$	41.2	$	17.7

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

Held-for-trading Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to HFT derivatives:

As at millions of Canadian dollars	December 31 2015			December 31 2014
Derivative instruments assets (current and other assets)	$	95.3		$	107.8
Derivative instruments liabilities (current and long-term liabilities)		(331.9	)		(145.3	)
Net derivative instrument assets (liabilities)	$	(236.6	)	$	(37.5	)

Held-for-trading Items Recognized in Net Income

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in net income:

For the millions of Canadian dollars	Year ended December 31
	2015			2014
Non-regulated operating revenues	$	14.4		$	270.4
Non-regulated fuel for generation and purchased power		(3.1	)		(5.2	)
Other income (expenses), net		(0.8	)		—
Net gains (losses)	$	10.5		$	265.2

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Other Derivatives Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to other derivatives:

As at millions of Canadian dollars	December 31 2015			December 31 2014
Derivative instrument assets (current and other assets)	$	92.1		$	—
Derivative instrument liabilities (current and long-term liabilities)	$	(2.9	)	$	—
Net derivative instrument assets (liabilities)	$	89.2		$	—

Other Derivatives Recognized in Net Income

The Company recognized in net income the following gains (losses) related to other derivatives:

For the millions of Canadian dollars	Year ended December 31
	2015			2014
Other income (expense)	$	92.1		$	—
Interest expense, net		(2.9	)		—
Total gains (losses)	$	89.2		$	—

DISCLOSURE AND INTERNAL CONTROLS

The Company, under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, has designed as at December 31, 2015 disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”) as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”).

The Chief Executive Officer and the Chief Financial Officer have caused to be evaluated under their supervision, with the assistance of Company employees, the effectiveness of the Company’s DC&P and ICFR, and based on that evaluation, have concluded DC&P and ICFR were effective at December 31, 2015.

There have been no changes in Emera or its consolidated subsidiaries’ ICFR during the period beginning on January 1, 2015 and ending on December 31, 2015, which have materially affected or are reasonably likely to materially affect ICFR.

CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made. Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill impairment assessments, income taxes, asset retirement obligations, capitalized overhead and valuation of derivative instruments. Actual results may differ significantly from these estimates.

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Rate Regulation

The rate-regulated accounting policies of NSPI, Emera Maine, BLPC, Domlec, GBPC, and Brunswick Pipeline may differ from accounting policies for non-rate-regulated companies. NSPI, Emera Maine, BLPC, Domlec, and GBPC’s accounting policies are subject to examination and approval by their respective regulators. These accounting policy differences occur when the regulators render their decisions on rate applications or other matters, and generally involve a difference in the timing of revenue and expense recognition. The accounting for these items is based on the expectation of the future actions of the regulators.

Emera has recorded $699.5 million (2014 - $602.7 million) of regulatory assets and $370.6 million (2014 - $201.9 million) of regulatory liabilities as at December 31, 2015.

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future experience.

The benefit cost and accrued benefit obligation for employee future benefits included in annual compensation expenses are affected by employee demographics, including age, compensation levels, employment periods, contribution levels and earnings on plan assets.

Changes to the provision of the plan may also affect current and future pension costs. Benefit costs are also affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation and benefit costs.

The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.

Emera’s accounting policy is to amortize the net actuarial gain or loss, which exceeds 10 per cent of the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”) and the market-related value of assets, over active plan members’ average remaining service period, which is currently nine years. Emera’s use of smoothed asset values further reduces the volatility related to the amortization of actuarial investment experience. As a result, the main cause of volatility in reported pension cost is the discount rate used to determine the PBO.

The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate bonds in each operating entity’s country. The discount rate is determined with reference to bonds which have the same duration as the PBO as at January 1 of the fiscal year. NSPI rounds its discount rate to the nearest 25 basis points. Effective January 1, 2014, Bangor Hydro Electric Company and Maine Public Service Company merged to become Emera Maine. The pension plans related to the pre-merger companies have remained separate and are disclosed separately below. For benefit cost purposes, NSPI’s rate was 4.00 per cent for 2015 (2014 – 5.00 per cent) and Bangor Hydro’s rate was 3.91 per cent for 2015 (2014 – 4.83 per cent), MPS’ rate was 3.77 for 2015 (2014 – 4.59 per cent) and GBPC’s rate for 2015 was 4.75 per cent (2014 – 5.00 per cent).

The expected return on plan assets is based on management’s best estimate of future returns, considering economic and consensus forecasts. The benefit cost calculations assumed that plan assets would earn a rate of return of 5.75 per cent for 2015 (2014 – 6.25 per cent) for NSPI and 7.50 per cent for 2015 and 2014 for Bangor Hydro and MPS, and 6.00 per cent for both 2015 and 2014 for GBPC.

The reported benefit cost for defined benefit and defined contribution plans in 2015, based on management’s best estimate assumptions, is $73.0 million. While there are numerous assumptions which

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are used to determine the benefit cost, the discount rate and asset return assumptions have an impact on the calculations.

The following shows the impact on 2015 benefit cost of a 25 basis point change (0.25 per cent) in the discount rate and asset return assumptions:

	0.25% Increase						0.25% Decrease
millions of dollars	2015			2014			2015		2014
Discount rate assumption	$	(5.4	)	$	(5.4	)	$	5.4	$	5.4
Asset return assumption	$	(2.7	)	$	(2.4	)	$	2.6	$	2.4

Unbilled Revenue

Electric revenues are billed on a systematic basis over a one- or two-month period for NSPI and a one-month period for Emera Maine and GBPC. At the end of each month, the Company must make an estimate of energy delivered to customers since the date their meter was last read and of related revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including current month’s generation, estimated customer usage by class, weather, line losses and applicable customer rates. EUS Bahamas and Emera Utility Services include an estimate of work completed under contracts but not yet billed at the end of each month. Based on the extent of the estimates included in the determination of unbilled revenue, actual results may differ from the estimate. As at December 31, 2015, unbilled revenues amount to $144.2 million (2014 – $141.1 million) on a base of annual operating revenues of approximately $2,789.3 million (2014 – $2,938.6 million).

Property, Plant and Equipment

Property, plant and equipment represents 51.5 per cent of total assets recognized on the Company’s balance sheet. Included in “Property, plant and equipment” are the generation, transmission and distribution and other assets of the Company. Due to the magnitude of the Company’s property, plant and equipment, changes in estimated depreciation rates can have a material impact on depreciation expense.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated property, plant and equipment are determined based on formal depreciation studies and require the appropriate regulatory approval. NSPI’s last depreciation study was completed in 2010 and approved by the UARB on May 11, 2011. BLPC’s last depreciation study was completed in 2013 and has been submitted for regulatory review. A response time has not been issued. GBPC’s last depreciation study was completed in 2015 and was approved on January 25, 2016. Emera Maine’s last depreciation study was completed in 2013 and was applied to transmission rates effective January 1, 2014 and distribution rates effective July 1, 2014.

Depreciation expense was $295.9 million for the year ended December 31, 2015 (2014 – $277.5 million).

Goodwill Impairment Assessments

Goodwill represents the excess of the acquisition purchase price for Emera Maine and GBPC over the fair values assigned to individual assets acquired and liabilities assumed. Emera is required to perform an impairment assessment annually, or in the interim if an event occurs that indicates the fair value of Emera Maine or GBPC may be below its carrying value. Emera performs its annual impairment test as at October 1.

Goodwill arose on the acquisitions of GBPC and Emera Maine. At December 31, 2015, this goodwill had a total carrying amount of $264.1 million (December 31, 2014 – $221.5 million)

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Emera’s reporting units will first assess qualitative factors to determine whether it is more likely than not that the assets’ fair value is less than the carrying amount, in which case it is necessary to perform the quantitative goodwill impairment test. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value.

Determining the fair market value of goodwill is susceptible to changes from period to period as assumptions about future cash flows are required.

Emera reviewed the carrying amount of goodwill and no material goodwill impairments existed for the year ended December 31, 2015 or 2014.

Income Taxes

Income taxes are determined based on the expected tax treatment of transactions recorded in the consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of jurisdictions, the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of the Company’s tax returns.

Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit-adjusted risk free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any accretion expense not yet approved by the regulator is deferred to a regulatory asset in “Property, plant and equipment” and included in the next depreciation study. Accordingly, changes to the ARO or cost recognition attributable to changes in the factors discussed above, should not impact the results of operations of the Company.

Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.

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The key assumptions used to determine the ARO are as follows:

Asset	Credit-adjusted risk-free rate						Estimated undiscounted future obligation (millions of dollars)				Expected settlement date (number of years)
	2015			2014			2015		2014		2015		2014
Thermal		5.1 – 5.3	%		5.2 – 5.3	%	$	142.8	$	142.8		17 – 28		18 – 29
Hydro		5.1 – 5.3	%		5.1 – 5.3	%		127.6		127.6		16 – 46		17 – 47
Wind		5.1 – 5.2	%		5.1 – 5.2	%		27.4		27.4		13 – 20		14 – 21
Combustion turbines		5.1 – 5.3	%		5.1 – 5.3	%		8.3		8.3		1 – 30		2 – 31
Transmission & distribution		4.3 – 5.8	%		4.1 – 5.8	%		21.5		16.5		1 – 10		1 – 11
Pipeline		3.80	%		3.80	%		18.1		18.1		19.5		19.5
							$	345.7	$	340.7

As at December 31, 2015, the AROs recorded on the balance sheet were $114.7 million (2014 – $106.2 million). The Company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $320.2 million, which will be incurred between 2016 and 2061. The majority of these costs will be incurred between 2032 and 2047.

Capitalized Overhead

As required by their respective regulators, NSPI, Emera Maine, GBPC, BLPC and Domlec capitalize overhead costs that are not directly attributable to specific utility assets, but to the overall capital expenditure program. The methodology for the calculation of capitalized overhead is approved by their respective regulator. For the year ended December 31, 2015, $71.6 million (2014 – $68.4 million) of overhead costs were capitalized to capital assets. Any change in the methodology for the calculation and allocation of overhead costs could have a material impact on the amounts recognized as expenses versus assets.

Financial Instruments

Emera is required to determine the fair value of all derivatives except those which qualify for the normal purchase, normal sale exception. Fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information, including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model.

Level Determinations and Classifications

Emera uses the Level 1, 2 and 3 classifications in the fair value hierarchy. The fair value measurement of a financial instrument is included in only one of the three levels and is based on the lowest level input significant to the derivation of the fair value. Fair values are determined, directly or indirectly, using inputs that are unobservable for the asset or liability. In limited circumstances, Emera may enter into commodity transactions involving non-standard features where market observable data is not available, or contracts with terms that extend beyond five years.

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CHANGES IN ACCOUNTING POLICIES AND PRACTICES

Business Combinations – Simplifying the Accounting for Measurement-Period Adjustments, Accounting Standard Update (“ASU”) Number (“No.”) 2015-16

In September 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-16, Business Combinations – Simplifying the Accounting for Measurement-Period Adjustments. The amendment applies to entities that have reported provisional amounts related to a business combination for which the accounting is incomplete by the end of the reporting period and have an adjustment to provisional amounts previously recognized during a later measurement period. Changes in provisional amounts recorded for acquired assets and liabilities are to be adjusted in the period the adjustment is known, with a corresponding adjustment booked to goodwill. The acquirer is no longer required to revise comparative information from prior years for the effect of changes in provisional amounts. The Company has adopted ASU 2015-16 effective Q3 2015, with no impact on the consolidated financial statements as a result of implementation of this standard.

Income Taxes – Balance Sheet Classification of Deferred Taxes, ASU 2015-17

In November 2015, the FASB issued ASU 2015-17, Income Taxes – Balance Sheet Classification of Deferred Taxes, which simplifies the presentation of deferred income taxes. The amendment requires that deferred tax assets and liabilities be classified as noncurrent on the Consolidated Balance Sheets, regardless of whether the deferred income taxes are expected to be recovered or settled within the next twelve months. ASU-2015-17 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016. Early adoption is permitted for any interim or annual financial statements that have not yet been issued.

The Company has early adopted ASU 2015-17 effective December 31, 2015, and 2014 balances have been retrospectively restated. This change decreased the current deferred income tax asset and liability by $49.2 million and $4.1 million respectively on the Consolidated Balance Sheets as at December 31, 2015 (2014 – $27.9 million and $15.7 million respectively). As a result of the change the long-term deferred income tax asset increased by $15.2 million (2014 – $24.1 million) and the long-term deferred income tax liability decreased by $29.9 million (2014 – increased by $11.9 million) on the Consolidated Balance Sheets as at December 31, 2015.

This change also reclassified a $11.9 million current deferred income tax regulatory liability (2014 – $8.0 million) to the long-term deferred income tax regulatory asset on the Consolidated Balance Sheets as at December 31, 2015.

Fair Value Measurement Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), ASU No. 2015-07

In May 2015, the FASB issued ASU 2015-07 removing the requirement to categorize and disclose, within the fair value hierarchy, all investments for which fair value is measured using the net asset value per share as a practical expedient. The Company has early adopted ASU No. 2015-07 effective December 31, 2015 and 2014. The adoption of this update resulted in disclosure of all investments for which fair value is measured using the net asset value per share methodology being disclosed outside of the fair-value hierarchy. As at December 31, 2015, total investments measured using the net asset value per share were $672.4 million (December 31, 2014 - $635.7 million).

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Future Accounting Pronouncements

Revenue from Contracts with Customers, ASU No. 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework and a new topic in the Accounting Standards Codification (“ASC”), Topic 606. ASC 606 also changes the basis for determining when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific aspects of revenue recognition and expands revenue disclosures. On July 9, 2015, the FASB deferred the effective date by one year. This standard will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.

The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

Income Statement – Extraordinary and Unusual Items, ASU No. 2015-01

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items, which simplifies the income statement presentation requirements by eliminating the concept of extraordinary items. ASU No. 2015-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Consolidation, ASU No. 2015-02

In February 2015, the FASB issued ASU 2015-02, Consolidation, which changes the analysis a reporting entity must perform to determine whether it should consolidate certain types of legal entities. All legal entities are subject to re-evaluation under the revised consolidation model. ASU No. 2015-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Interest – Imputation of Interest, No. ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected by the amendments in the update. ASU No. 2015-03 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2015. The adoption of this update will result in the reclassification of debt issuance costs from “Other long-term assets” to “Long-term debt” and “Convertible debentures represented by instalment receipts” on the Company’s consolidated balance sheets. As at December 31, 2015, debt issuance costs included in “Other long-term assets were $66.8 million (December 31, 2014 - $18.8 million).

In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest – Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, which clarifies that the guidance in ASU No. 2015-03 does not apply to line-of-credit arrangements. ASU No. 2015-15 permits an entity to defer and present debt issuance costs as an asset and subsequently amortize these costs ratably over the time of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. ASU No. 2015-15 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2015. As at December 31, 2015, debt issuance costs associated with line-of-credit arrangements included in “Other long-term assets” were $4.0 million (December 31, 2014 - $4.1 million) on the Company’s Consolidated Balance Sheets.

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Compensation – Retirement Benefits, ASU No. 2015-04

In April 2015, the FASB issued ASU 2015-04, Compensation – Retirement Benefits, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard provides certain practical expedients for defined benefit pension or other post-retirement benefit plan measurement dates. ASU No. 2015-04 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Intangibles – Goodwill and Other – Internal-Use Software, ASU No. 2015-05

In April 2015, the FASB issued ASU 2015-05, Intangibles – Goodwill and Other – Internal-Use Software, which provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer’s accounting for service contracts. ASU No. 2015-05 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Technical Corrections and Improvements, ASU No. 2015-10

In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Improvements, covering a wide range of topics in the codification to correct unintended application of guidance, or make minor improvements to the Codification that are not expected to have a significant effect on current accounting practice or create a significant administrative cost. ASU No. 2015-10 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

Inventory – Simplifying the Measurement of Inventory, ASU No. 2015-11

In July 2015, the FASB issued ASU 2015-11, Inventory – Simplifying the Measurement of Inventory. The amendments require an entity to measure inventory at the lower of cost or net realizable value, whereas previously, inventory was measured at the lower of cost or market. ASU No. 2015-11 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities, ASU No. 2016-01

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. ASU No. 2016-01 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

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SUMMARY OF QUARTERLY RESULTS

For the quarter ended millions of dollars (except per share amounts)	Q4 2015		Q3 2015		Q2 2015		Q1 2015		Q4 2014		Q3 2014		Q2 2014		Q1 2014
Operating revenues	$	731.6	$	642.3	$	526.9	$	888.5	$	782.7	$	539.0	$	566.6	$	1,050.3
Net income attributable to common shareholders		192.1		35.0		10.0		160.1		151.2		28.2		24.5		202.8
Adjusted net income attributable to common shareholders		87.1		23.3		48.0		171.6		78.5		49.9		44.2		146.6
Earnings per common share – basic		1.31		0.24		0.07		1.10		1.05		0.20		0.17		1.43
Earnings per common share – diluted		1.30		0.24		0.07		1.09		1.02		0.20		0.17		1.40
Adjusted earnings per common share – basic		0.59		0.16		0.33		1.18		0.54		0.35		0.31		1.03

Quarterly operating revenues and net income attributable to common shareholders are affected by seasonality. The first quarter is generally the strongest because a significant portion of the Company’s operations are located in northeast North America, where winter is the peak electricity season. As the energy industry is seasonal in nature for companies like Emera, seasonal and other weather patterns, as well as the number and severity of storms, can affect the demand for energy and the cost of service. Quarterly results could be affected by items outlined in the Significant Items section and mark-to-market adjustments.

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OPERATING STATISTICS

FIVE-YEAR SUMMARY

Year ended December 31	2015		2014		2013		2012		2011
Electric energy sales (GWh)
Residential		5,740.5		5,615.7		5,623.6		5,372.2		5,458.9
Commercial		11,153.9		10,989.6		7,156.9		6,174.7		6,562.3
Industrial		2,984.1		2,970.8		3,067.4		2,678.7		3,988.5
Other		373.6		385.3		357.9		371.2		347.0
Total electric energy sales		20,252.1		19,961.4		16,205.8		14,596.8		16,356.7
Sources of energy (GWh)
Thermal – coal		6,364.0		6,609.0		7,098.0		6,223.0		6,848.0
– oil		1,668.4		1,584.5		1,417.5		1,355.1		1,070.8
– natural gas		7,782.3		7,691.7		3,685.9		3,726.0		4,304.7
Biomass		272.3		319.8		167.0		—		—
Hydro		1,040.4		1,129.6		1,002.6		828.0		1,414.5
Wind		259.0		258.0		261.0		256.0		247.0
Purchases		4,142.3		3,693.1		3,528.0		3,210.2		3,518.3
Total generation and purchases		21,528.7		21,285.7		17,160.0		15,598.3		17,403.3
Losses and internal use		1,276.6		1,324.3		954.2		1,001.5		1,046.6
Total electric energy sold		20,252.1		19,961.4		16,205.8		14,596.8		16,356.7
Electric customers
Residential		747,629		742,110		738,444		702,738		696,970
Commercial		85,480		82,076		83,612		79,613		79,817
Industrial		2,628		2,637		2,711		2,521		2,517
Other		9,432		10,421		10,510		20,230		10,446
Total electric customers		845,169		837,244		835,277		805,102		789,750
Capacity
Emera-owned generating nameplate capacity (MW)
Coal fired		1,243.0		1,243.0		1,243.0		1,243.0		1,243.0
Dual fired		350.0		350.0		350.0		350.0		350.0
Gas turbines		1,819.0		1,799.0		1,796.5		746.5		666.0
Biomass		90.0		90.0		90.0		—		—
Hydroelectric		402.0		401.6		401.6		395.0		395.0
Wind turbines		82.0		82.0		82.0		82.0		82.0
Diesel		241.2		241.2		244.6		231.5		173.0
Steam		40.0		40.0		40.0		40.0		47.0
Independent power producers		593.0		370.0		308.0		300.0		264.0
		4,860.2		4,616.8		4,555.7		3,388.0		3,220.0
Total number of employees		3,454		3,530		3,558		3,374		3,458
km of transmission lines		7,504		7,215		7,224		6,803		6,800
km of distribution lines		46,162		44,811		44,771		39,590		41,600

REGULATED ELECTRIC			Employee		Peak demand		Energy sales		Total assets		Rate base		Income		Allowable ROE			Allowable ROE
	Customers		count		(MW)		(Gwh)		(billions)		(billions)		(millions)		2015			2014
NSPI		506,452		1,727		1,825		10,412		4.6		3.8	$	129.9		8.75-9.25	%		8.75-9.25	%
Emera Maine		157,891		412		388		2,020		1.6		0.9		45.1		10.3	%		10.6	%
BLPC (1)		126,190		330		149		915		0.5		0.4		29.7		10.0	%		10.0	%
GBPC(1)		19,104		205		61		335		0.4		0.3		17.8		10.0	%		10.0	%
Domlec (1)		35,525		238		17		95		0.1		0.1		7.4		15.0	%		15.0	%

(1) These subsidiaries use return on rate base, as opposed to ROE.

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FIVE-YEAR FINANCIAL SUMMARY

For the year ended December 31	2015		2014		2013			2012			2011
millions of Canadian dollars
Consolidated Statements of Income
Operating Revenues	$	2,789.3	$	2,938.6	$	2,230.2		$	2,058.6		$	2,064.4
Operating expenses
Regulated fuel for generation and purchased power		814.5		844.3		868.4			810.5			866.4
Regulated fuel and fixed cost adjustments		41.6		46.6		(40.8	)		10.0			(8.5	)
Non-regulated fuel for generation and purchased power		335.7		401.1		89.8			44.5			73.9
Non-regulated direct costs		19.5		31.3		52.4			56.6			60.9
Operating, maintenance and general		666.8		560.8		505.0			462.9			453.3
Provincial, state and municipal taxes		63.6		58.2		50.5			49.4			49.2
Depreciation and amortization		339.9		329.0		297.8			278.2			251.7
Income from operations		507.7		667.3		407.1			346.5			317.5
Income from equity investments and Other income (expenses), net		249.7		78.9		63.7			53.8			77.4
Interest expense, net		212.6		179.8		172.2			167.1			159.4
Income before provision for income taxes		544.8		566.4		298.6			233.2			235.5
Income tax expense (recovery)		92.4		113.6		43.3			(12.4	)		(23.9	)
Net income		452.4		452.8		255.3			245.6			259.4
Non-controlling interest in subsidiaries		24.9		19.9		18.5			13.7			11.7
Net income of Emera Incorporated		427.5		432.9		236.8			231.9			247.7
Preferred stock dividends		30.3		26.2		19.3			11.1			6.6
Net income attributable to common shareholders		397.2		406.7		217.5			220.8			241.1
After-tax mark-to-market gain (loss)		67.2		87.5		(41.9	)		(9.7	)		(3.0	)
Adjusted net income attributable to common shareholders		330.0		319.2		259.4			230.5			244.1
Adjusted EBITDA		1,031.2		946.5		829.5			693.2			649.8
Balance Sheets Information
Current assets (1)		2,595.6		1,410.8		1,152.3			940.2			993.3
Property, plant and equipment, net of accumulated depreciation		6,188.0		5,610.2		5,327.7			4,491.1			4,294.4
Other assets
Income taxes receivable		48.7		28.9		27.8			—			—
Deferred income taxes (1)		32.2		57.8		67.8			28.9			33.1
Derivative instruments		167.6		92.0		61.6			23.4			39.6
Pension and post-retirement asset		8.7		5.9		0.5			0.1			0.3
Regulatory assets		605.3		487.7		557.8			376.4			312.2
Net investment in direct financing lease		480.1		484.5		487.2			490.0			492.0
Investments subject to significant influence (2)		1,145.3		1,027.6		739.2			536.6			219.8
Available-for-sale investments		116.0		84.4		74.2			141.8			54.6
Goodwill		264.1		221.5		206.5			193.5			197.7
Intangibles, net of accumulated amortization		191.9		134.3		118.4			114.2			100.7
Due from related parties		2.5		2.5		2.5			151.7			2.8
Other long-term assets		166.3		205.3		53.3			48.5			183.1
Total assets		12,012.3		9,853.4		8,876.8			7,536.4			6,923.6

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FIVE-YEAR FINANCIAL SUMMARY (continued)

For the year ended December 31	2015			2014			2013			2012			2011
millions of Canadian dollars
Current liabilities		2,081.3			1,122.9			1,529.9			951.9			801.7
Long-term liabilities
Long-term debt		3,750.8			3,660.3			3,363.7			3,257.4			3,273.5
Deferred income taxes (1)		761.7			613.3			547.7			312.1			228.6
Derivative instruments		96.1			77.4			27.0			22.4			38.7
Regulatory liabilities		271.7			158.9			119.5			92.5			107.1
Asset retirement obligations		114.7			106.2			98.6			95.0			99.9
Pension and post-retirement liabilities		303.4			360.7			256.4			506.4			530.8
Other long-term liabilities (2)		298.5			48.3			36.8			20.9			19.6
Equity
Common stock		2,157.5			2,016.4			1,703.0			1,643.7			1,385.0
Cumulative preferred stock		709.5			709.5			514.0			391.6			146.7
Contributed surplus		28.8			8.8			4.1			2.8			3.3
Accumulated other comprehensive income (loss)		136.5			(347.6	)		(430.1	)		(775.8	)		(671.7	)
Retained earnings		1,167.8			1,011.7			817.2			788.1			735.9
Total Emera Incorporated equity		4,200.1			3,398.8			2,608.2			2,050.4			1,599.2
Non-controlling interest in subsidiaries		134.0			306.6			289.0			227.4			224.5
Total equity		4,334.1			3,705.4			2,897.2			2,277.8			1,823.7
Total liabilities and equity		12,012.3			9,853.4			8,876.8			7,536.4			6,923.6
Statements of Cash Flow Information
Cash provided by operating activities		674.2			762.5			564.2			397.6			399.5
Cash used in investing activities		(123.7	)		(710.9	)		(921.6	)		(919.4	)		(660.8	)
Cash provided by (used in) financing activities		221.1			58.2			362.1			534.2			331.4
Financial ratios ($ per share)
Earnings per share	$	2.72		$	2.84		$	1.64		$	1.77		$	1.99
Adjusted earnings per share	$	2.26		$	2.23		$	1.96		$	1.85		$	2.02

(1) Emera early adopted ASU 2015-17 Income Taxes – Balance Sheet Classification of Deferred Taxes, which simplifies the presentation of deferred income taxes effective Q4 2015. The December 31, 2014 and 2015 periods have been restated

(2) As at December 31, 2015 and 2014, the negative investment balance for Bear Swamp has been reclassified to “Other long-term liabilities” on the Consolidated Balance Sheets. The 2014 and 2015 carrying values have been restated.

99

EX-4.4

Exhibit 4.4

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

March 31, 2016 and 2015

1

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)

For the millions of Canadian dollars (except per share amounts)	Three months ended March 31
	2016			2015
Operating revenues
Regulated	$	586.6		$	631.2
Non-regulated		290.4			257.3
Total operating revenues		877.0			888.5
Operating expenses
Regulated fuel for generation and purchased power		197.7			255.0
Regulated fuel adjustment mechanism and fixed cost deferrals (note 5)		17.6			(7.2	)
Non-regulated fuel for generation and purchased power		109.8			150.4
Non-regulated direct costs		2.3			4.4
Operating, maintenance and general		175.7			155.1
Provincial, state and municipal taxes		16.4			15.9
Depreciation and amortization		87.5			82.8
Total operating expenses		607.0			656.4
Income from operations		270.0			232.1
Income from equity investments (note 6)		26.0			25.9
Other income (expenses), net (note 7)		(139.2	)		21.9
Interest expense, net (note 8)		75.2			44.4
Income before provision for income taxes		81.6			235.5
Income tax expense (recovery) (note 9)		26.8			61.4
Net income		54.8			174.1
Non-controlling interest in subsidiaries		3.5			6.3
Net income of Emera Incorporated		51.3			167.8
Preferred stock dividends		7.0			7.7
Net income attributable to common shareholders	$	44.3		$	160.1
Weighted average shares of common stock outstanding (in millions)
Basic		148.7			144.9
Diluted		149.3			148.8
Earnings per common share (note 10)
Basic	$	0.30		$	1.10
Diluted	$	0.30		$	1.09
Dividends per common share declared	$	0.4750		$	0.3875

The accompanying notes are an integral part of these condensed consolidated financial statements.

2

Emera Incorporated

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

For the millions of Canadian dollars	Three months ended March 31
	2016			2015
Net income	$	54.8		$	174.1
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment (1)		(161.5	)		189.4
Cash flow hedges
Net derivative gains (losses) (2)		14.1			(15.9	)
Less: reclassification adjustment for losses (gains) included in income (3)		0.9			(1.1	)
Net effects of cash flow hedges		15.0			(17.0	)
Unrealized gains on available-for-sale investment
Unrealized gain (loss) arising during the period		0.4			0.4
Net unrealized holding gains (losses)		0.4			0.4
Net change in unrecognized pension and post-retirement benefit obligation (4)		8.6			10.6
Other comprehensive income (loss) (5)		(137.5	)		183.4
Comprehensive income (loss)		(82.7	)		357.5
Comprehensive income (loss) attributable to non-controlling interest		(3.3	)		19.5
Comprehensive Income of Emera Incorporated	$	(79.4	)	$	338.0

The accompanying notes are an integral part of these condensed consolidated financial statements.

1) Net of tax expense of $1.8 million (2015 – $0.1 million tax expense) for the three months ended March 31, 2016.

2) Net of tax expense of $0.1 million (2015 – $0.2 million tax expense) for the three months ended March 31, 2016.

3) Net of tax recovery of $1.6 million (2015 – $2.2 million tax recovery) for the three months ended March 31, 2016.

4) Net of tax expense of nil (2015 – $0.6 million tax expense) for the three months ended March 31, 2016.

5) Net of tax expense of $0.3 million (2015 – $1.3 million tax recovery) for the three months ended March 31, 2016.

3

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)

As at	March 31		December 31
millions of Canadian dollars	2016		2015
Assets
Current assets
Cash and cash equivalents	$	999.5	$	1,073.4
Restricted cash		22.2		19.3
Receivables, net (note 12)		610.3		577.4
Income taxes receivable		15.8		12.1
Inventory (note 13)		260.8		314.3
Derivative instruments (notes 14 and 15)		92.4		249.5
Regulatory assets (notes 5 and 16)		78.2		94.2
Prepaid expenses		40.4		18.3
Due from related parties (note 17)		1.5		2.3
Other current assets (note 18)		168.3		234.8
Total current assets		2,289.4		2,595.6
Property, plant and equipment, net of accumulated depreciation of $3,723.0 and $3,732.4, respectively		6,014.9		6,188.0
Other assets
Income taxes receivable		48.3		48.7
Deferred income taxes		47.0		32.2
Derivative instruments (notes 14 and 15)		85.4		167.6
Pension and post-retirement asset (note 19)		8.6		8.7
Regulatory assets (notes 5 and 16)		619.1		605.3
Net investment in direct financing lease		478.7		480.1
Investments subject to significant influence (note 6)		1,209.7		1,145.3
Available-for-sale investments (note 20)		106.2		116.0
Goodwill		247.6		264.1
Intangibles, net of accumulated amortization of $93.8 and $92.8, respectively		190.9		191.9
Due from related parties (note 17)		2.5		2.5
Other long-term assets		100.3		104.0
Total other assets		3,144.3		3,166.4
Total assets	$	11,448.6	$	11,950.0

The accompanying notes are an integral part of these consolidated financial statements.

4

Emera Incorporated

Condensed Consolidated Balance Sheets – (Unaudited) Continued

As at	March 31		December 31
millions of Canadian dollars	2016		2015
Liabilities and Equity
Current liabilities
Short-term debt	$	10.2	$	15.9
Current portion of long-term debt		272.6		274.0
Accounts payable		371.5		394.2
Income taxes payable		8.6		8.1
Convertible debentures represented by instalment receipts (note 22)		681.8		681.5
Derivative instruments (notes 14 and 15)		147.9		349.2
Regulatory liabilities (note 16)		75.0		98.9
Pension and post-retirement liabilities (note 19)		7.0		7.0
Due to related party (note 17)		2.3		2.1
Other current liabilities (note 21)		182.7		204.3
Total current liabilities		1,759.6		2,035.2
Long-term liabilities
Long-term debt		3,714.2		3,734.6
Deferred income taxes		793.6		761.7
Derivative instruments (notes 14 and 15)		79.2		96.1
Regulatory liabilities (note 16)		221.2		271.7
Asset retirement obligations		115.6		114.7
Pension and post-retirement liabilities (note 19)		296.0		303.4
Other long-term liabilities (note 23)		272.3		298.5
Total long-term liabilities		5,492.1		5,580.7
Commitments and contingencies (note 24)
Equity
Common stock, no par value, unlimited shares authorized, 148.35 million and 147.21 million shares issued and outstanding, respectively (note 25)		2,199.0		2,157.5
Cumulative preferred stock, Series A, B, C, E and F, par value $25 per share; unlimited shares authorized, 3.9 million, 2.1 million, 10 million, 5 million, and 8 million shares issued and outstanding, respectively		709.5		709.5
Contributed surplus		35.3		28.8
Accumulated other comprehensive income (loss) (note 11)		5.8		136.5
Retained earnings		1,142.1		1,167.8
Total Emera Incorporated equity		4,091.7		4,200.1
Non-controlling interest in subsidiaries (note 26)		105.2		134.0
Total equity		4,196.9		4,334.1
Total liabilities and equity	$	11,448.6	$	11,950.0

The accompanying notes are an integral part of these consolidated financial statements.

Approved on behalf of the Board of Directors

“M. Jacqueline Sheppard”	“Christopher G. Huskilson”
Chair of the Board	President and Chief Executive Officer

5

Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the millions of Canadian dollars	Three months ended March 31
	2016			2015
Operating activities
Net income	$	54.8		$	174.1
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		90.7			85.6
Income from equity investments, net of dividends		(12.6	)		(12.8	)
Allowance for equity funds used during construction		(0.9	)		(0.3	)
Deferred income taxes, net		8.8			12.3
Net change in pension and post-retirement liabilities		6.5			6.3
Regulated fuel adjustment mechanism and fixed cost deferrals		17.4			(8.4	)
Net change in fair value of derivative instruments		(28.6	)		4.7
Net change in regulatory assets and liabilities		(4.6	)		2.2
Net change in capitalized transportation capacity		56.3			15.3
Unrealized foreign exchange loss		44.7			—
Other operating activities, net		(0.1	)		(21.5	)
Changes in non-cash working capital:
Receivables, net		(53.7	)		(92.7	)
Income taxes receivable		(6.7	)		(13.5	)
Inventory		47.9			20.5
Prepaid expenses		(23.3	)		(28.0	)
Due from related party		0.3			(0.9	)
Other current assets		0.2			(0.5	)
Accounts payable		(2.3	)		(6.7	)
Income taxes payable		4.1			1.3
Other current liabilities		(18.3	)		(17.4	)
Net cash provided by operating activities		180.6			119.6
Investing activities
Additions to property, plant and equipment		(77.2	)		(81.0	)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		(53.1	)		—
Additions to intangible assets		(8.3	)		(1.5	)
Proceeds on sale of investment subject to significant influence		—			282.3
Other investing activities		(0.7	)		(3.9	)
Net cash (used in) provided by investing activities		(139.3	)		195.9
Financing activities
Change in short-term debt, net		(7.2	)		(271.9	)
Retirement of long-term debt		(4.0	)		(6.5	)
Proceeds from long-term debt		—			250.0
Net borrowings (repayments) under committed credit facilities		20.7			(168.4	)
Issuance of common stock, net of issuance costs (note 25)		14.6			2.5
Dividends on common stock		(47.0	)		(40.1	)
Dividends on preferred stock		(7.0	)		(7.7	)
Dividends paid by subsidiaries to non-controlling interest		(1.8	)		(3.9	)
Other financing activities		(14.1	)		(13.3	)
Net cash used in financing activities		(45.8	)		(259.3	)
Effect of exchange rate changes on cash and cash equivalents		(69.4	)		28.0
Net (decrease) increase in cash and cash equivalents		(73.9	)		84.2
Cash and cash equivalents, beginning of period		1,073.4			221.1
Cash and cash equivalents, end of period	$	999.5		$	305.3
Cash and cash equivalents consists of:
Cash	$	260.2		$	235.5
Short-term investments		739.3			69.8
Cash and cash equivalents	$	999.5		$	305.3
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	23.0		$	15.6

The accompanying notes are an integral part of these consolidated financial statements.

6

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

								Accumulated
								Other						Emera			Non-
	Common		Preferred		Contributed			Comprehensive			Retained			Total			Controlling			Total
millions of Canadian dollars	Stock		Stock		Surplus			Income (“AOCI”)			Earnings			Equity			Interest			Equity
For the three months ended March 31, 2016
Balance, December 31, 2015	$	2,157.5	$	709.5	$	28.8		$	136.5		$	1,167.8		$	4,200.1		$	134.0		$	4,334.1
Net income of Emera Incorporated		—		—		—			—			51.3			51.3			3.5			54.8
Other comprehensive income (loss), net of tax expense of $0.3 million		—		—		—			(130.7	)		—			(130.7	)		(6.8	)		(137.5	)
Dividends declared on preferred stock (Series A: $0.1597/share, Series B: $0.1425/share, Series C: $0.25625/share, Series E: $0.28125/share and Series F: $0.265625/share)		—		—		—			—			(7.0	)		(7.0	)		—			(7.0	)
Dividends declared on common stock ($0.4750/share)		—		—		—			—			(70.0	)		(70.0	)		—			(70.0	)
Common stock issued under purchase plan		25.0		—		—			—			—			25.0			—			25.0
Senior management stock options exercised		13.6		—		(1.0	)		—			—			12.6			—			12.6
Stock option expense				—		0.4			—			—			0.4			—			0.4
Employee Share Purchase Plan		0.2		—		—			—			—			0.2			—			0.2
Preferred dividends paid and payable by subsidiaries to non-controlling interest		—		—		—			—			—			—			(1.8	)		(1.8	)
Acquisition of non-controlling interest of ECI		2.7		—		7.1			—			—			9.8			(23.7	)		(13.9	)
Balance, March 31, 2016	$	2,199.0	$	709.5	$	35.3		$	5.8		$	1,142.1		$	4,091.7		$	105.2		$	4,196.9

The accompanying notes are an integral part of these condensed consolidated financial statements.

7

Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited) – Continued

							Accumulated
							Other						Emera			Non-
	Common		Preferred		Contributed		Comprehensive			Retained			Total			Controlling			Total
millions of Canadian dollars	Stock		Stock		Surplus		Income (“AOCI”)			Earnings			Equity			Interest			Equity
For the three months ended March 31, 2015
Balance, December 31, 2014	$	2,016.4	$	709.5	$	8.8	$	(347.6	)	$	1,011.7		$	3,398.8		$	306.6		$	3,705.4
Net income of Emera Incorporated		—		—		—		—			167.8			167.8			6.3			174.1
Other comprehensive income (loss), net of tax recovery of $1.3 million		—		—		—		170.2			—			170.2			13.2			183.4
Dividends declared on preferred stock (Series A: $0.275/share, Series C: $0.25625/share, Series E: $0.28125/share and Series F: $0.265625/share)		—		—		—		—			(7.7	)		(7.7	)		—			(7.7	)
Dividends declared on common stock ($0.3875/share)		—		—		—		—			(55.7	)		(55.7	)		—			(55.7	)
Dividends paid by subsidiaries to non-controlling interest		—		—		—		—			—			—			(0.7	)		(0.7	)
Common stock issued under purchase plan		17.4		—		—		—			—			17.4			—			17.4
Senior management stock options exercised		0.6		—		—		—			—			0.6			—			0.6
Stock option expense		—		—		0.3		—			—			0.3			—			0.3
Other stock-based compensation		0.2		—		—		—			—			0.2			—			0.2
Preferred dividends paid by subsidiaries to non-controlling interest		—		—		—		—			—			—			(3.5	)		(3.5	)
Other		—		—		—		—			—			—			(0.1	)		(0.1	)
Balance, March 31, 2015	$	2,034.6	$	709.5	$	9.1	$	(177.4	)	$	1,116.1		$	3,691.9		$	321.8		$	4,013.7

The accompanying notes are an integral part of these condensed consolidated financial statements.

8

Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements

As at March 31, 2016 and 2015

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both the regulated and non-regulated operations of Emera Incorporated are as follows:

A. Nature of Operations

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, gas transmission and utility energy services.

Emera’s primary rate-regulated subsidiaries and investments at March 31, 2016 included the following:

• Nova Scotia Power Inc. (“NSPI”), which is a fully integrated electric utility and the primary electricity supplier in Nova Scotia, serving 507,000 customers;

• Emera Maine provides electric transmission and distribution services to 158,000 customers in the State of Maine in the United States;

• a 100.0 per cent interest (December 31, 2015 – 95.5 per cent) in Emera (Caribbean) Incorporated (“ECI”), the parent of The Barbados Light & Power Company Limited (“BLPC”), which is a vertically integrated utility and sole provider of electricity on the island of Barbados, serving 126,000 customers; a 51.9 per cent interest (December 31, 2015 – 49.6 per cent indirect interest) through ECI in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving 36,000 customers; and a 19.1 per cent indirect interest (December 31, 2015 – 18.2 per cent indirect interest) through ECI in St. Lucia Electricity Services Limited (“Lucelec”), which is a vertically integrated regulated electric utility in St. Lucia;

• a 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited (“ICDU”)) in Grand Bahama Power Company Limited (“GBPC”), which is a vertically integrated utility and sole provider of electricity on Grand Bahama Island, serving 19,000 customers;

• Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), which is a 145-kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25-year firm service agreement with Repsol Energy Canada (“REC”), which expires in 2034;

• Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focused on two transmission investments related to the development of an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat Falls on the Lower Churchill River in Labrador, scheduled to be in service in 2017. ENL’s two investments are:

• 100 per cent interest in NSP Maritime Link Inc. (“NSPML”), which is developing the Maritime Link Project, a $1.56 billion transmission project, including two 170-kilometre sub-sea cables, between the island of Newfoundland and Nova Scotia;

• 59.0 per cent investment (December 31, 2015 – 55.1 per cent) in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.1 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL ?is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined on completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is expected to go into service in 2017.

9

• a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), which is a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States;

Emera Incorporated and its subsidiaries also own investments in other energy-related companies, including:

• Emera Energy Inc. (“Emera Energy”), includes:

• Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services;

• Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities”), comprising 1,090 MW of combined-cycle gas-fired electricity generating capacity in the northeastern United States;

• Bayside Power Limited Partnership (“Bayside Power”), which is a 290 MW electricity generating facility in Saint John, New Brunswick;

• Brooklyn Power Corporation (“Brooklyn Energy”), which is a 30 MW biomass co-generation merchant electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with NSPI;

• a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), which is a 600 MW pumped storage hydroelectric facility in northern Massachusetts;

• Emera Reinsurance Limited, which is a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost efficient management of risk and deductible levels across Emera;

• Emera Utility Services Inc., which is a utility services contractor primarily operating in Atlantic Canada;

• a 19.4 per cent (December 31, 2015 – 19.6 per cent) investment in Algonquin Power & Utilities Corp. (“APUC”), which is a public company traded on the Toronto Stock Exchange under the symbol “AQN”;

• and other investments.

Pending acquisition

On September 4, 2015, Emera entered into an Agreement and Plan of Merger pursuant to which, Emera US Inc., a wholly owned indirect subsidiary of Emera, will merge with and into TECO Energy, Inc. (“TECO Energy”), and TECO Energy will survive the merger and become a wholly owned indirect subsidiary of Emera (“the Transaction”). TECO Energy shareholders will receive $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.4 billion USD, and includes the assumption of approximately $3.9 billion USD of debt.

The closing of the acquisition, expected to occur mid-2016, is subject to approval by the New Mexico Public Regulation Commission (“NMPRC”), and the satisfaction of customary closing conditions. On April 11, 2016, Emera and TECO Energy filed an unopposed Stipulation Agreement reflecting a settlement reached with intervening parties in the acquisition case pending before the NMPRC for approval of Emera’s proposed acquisition of TECO Energy and the indirect acquisition of the New Mexico Gas Co. The hearing for Emera’s pending acquisition of TECO Energy occurred on May 2, 2016. A decision is expected mid-2016.

TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include: Tampa Electric, an integrated regulated electric utility which serves nearly 725,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution utility which serves nearly 365,000 customers across Florida; and New Mexico Gas Co., also a regulated gas distribution utility which serves more than 515,000 customers across New Mexico.

10

B. Basis of Presentation

These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). They do not contain all disclosures required by USGAAP for annual audited financial statements. Accordingly, the financial statements should be read in conjunction with Emera Incorporated’s annual audited financial statements as at and for the year ended December 31, 2015.

In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera Incorporated. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2016.

All dollar amounts are presented in Canadian dollars, unless otherwise indicated.

C. Use of Management Estimates

The preparation of consolidated financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Significant estimates are included in unbilled revenue, allowance for doubtful accounts, inventory, valuation of derivative instruments, capitalized overhead, depreciation, amortization, regulatory assets and regulatory liabilities (including the determination of the current portion), income taxes (including deferred income taxes), pension and post-retirement benefits, asset retirement obligations (“AROs”), goodwill impairment assessments, valuation of investments and contingencies. Actual results may differ significantly from these estimates.

D. Seasonal Nature of Operations

Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity sales and related generation vary significantly over the year; the first quarter is typically the strongest period, reflecting colder weather and fewer daylight hours in the winter season in northeastern North America, where a substantial portion of Emera’s electricity business is located. Certain quarters may also be impacted by the number and severity of storms.

2. CHANGE IN ACCOUNTING POLICY

The new US GAAP accounting policies that are applicable to, and were adopted by Emera, effective during 2016, are described as follows:

Income Statement – Extraordinary and Unusual Items, Accounting Standard Update (“ASU”) 2015-01

In January 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items, which simplifies the income statement presentation requirements by eliminating the concept of extraordinary items. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

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Consolidation, ASU 2015-02

In February 2015, the FASB issued ASU 2015-02, Consolidation, which changes the analysis a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the variable interest entity (“VIE”) characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. All legal entities are subject to re-evaluation under the revised consolidation model. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Interest – Imputation of Interest, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. The Company has adopted this standard effective Q1 2016 and December 31, 2015 balances have been retrospectively restated. This change resulted in $62.3 million of deferred financing costs, as at December 31, 2015, previously presented as other assets, being reclassified as a deduction from the carrying amount of the related long-term debt and convertible debentures represented by instalment receipts on the Consolidated Balance Sheets.

In accordance with ASU 2015-15 Interest: Imputation of Interest, the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments in other long-term assets on its Consolidated Balance Sheets.

Compensation – Retirement Benefits, ASU 2015-04

In April 2015, the FASB issued ASU 2015-04, Compensation – Retirement Benefits, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard provides certain practical expedients for defined benefit pension or other post-retirement benefit plan measurement dates. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Intangibles – Goodwill and Other – Internal-Use Software, ASU 2015-05

In April 2015, the FASB issued ASU 2015-05, Intangibles – Goodwill and Other – Internal-Use Software, which provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer would account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer would account for the arrangement as a service contract. The guidance does not change GAAP for a customer’s accounting for service contracts. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Technical Corrections and Improvements, ASU 2015-10

In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Improvements, covering a wide range of topics in the codification to correct unintended application of guidance, or make minor improvements to the Codification. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Inventory – Simplifying the Measurement of Inventory, ASU 2015-11

In July 2015, the FASB issued ASU 2015-11, Inventory – Simplifying the Measurement of Inventory. The amendments require an entity to measure inventory at the lower of cost or net realizable value, whereas previously, inventory was measured at the lower of cost or market. ASU 2015-11 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016. Early adoption is permitted for any interim or annual financial statements that have not yet been issued. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

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Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships, ASU 2016-05

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The standard clarifies that a change in the counterparty to a derivative contract, in and of itself, does not require the de-designation of a hedging relationship provided that all other hedge accounting criteria continue to be met. ASU 2016-05 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and early adoption is permitted. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Investments – Equity Method and Joint Ventures, ASU 2016-07

In March 2016, the FASB issued ASU 2016-07, Investments – Equity Method and Joint Ventures, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard eliminates the requirements of an investor to retroactively account for an investment under the equity method when an investment qualifies for equity method accounting. ASU 2016-07 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016, with early adoption permitted. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

3. FUTURE ACCOUNTING PRONOUNCEMENTS

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework and a new topic in the Accounting Standards Codification (“ASC”), Topic 606. ASC 606 also changes the basis for determining when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific aspects of revenue recognition and expands revenue disclosures. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers: Principal versus Agent Considerations. The amendments are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU 2016-10 Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing. The guidance will be effective beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The Company is continuing to evaluate the impact of adoption of these standards on its consolidated financial statements.

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities, ASU 2016-01

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. ASU 2016-01 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

Leases (Topic 842), ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases. The standard increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for lease terms of more than 12 months. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. ASU 2016-02 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and will be applied using a modified retrospective approach. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

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4. SEGMENT INFORMATION

Emera manages its reportable segments separately due to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets.

As at March 31, 2016, Emera has six reportable segments, specifically:

• NSPI;

• Emera Maine;

• Emera Caribbean (ECI and its subsidiaries including BLPC, Domlec, GBPC, and an equity investment in Lucelec);

• Pipelines (Brunswick Pipeline and an equity investment in M&NP);

• Emera Energy (Emera Energy Services, New England Gas Generating Facilities, Bayside Power, Brooklyn Energy and an equity investment in Bear Swamp; and

• Corporate and Other (Emera Utility Services, ENL, Corporate, other strategic investments (including APUC) and holding companies.

millions of Canadian dollars	NSPI		Emera Maine		Emera Caribbean		Pipelines		Emera Energy		Corporate and Other			Inter- Segment Eliminations			Total
For the three months ended March 31, 2016
Operating revenues from external customers (1)	$	397.5	$	79.6	$	97.6	$	12.9	$	287.7	$	2.0		$	(0.6	)	$	876.7
Inter-segment revenues (1)		—		—		—		—		3.3		6.4			(9.4	)		0.3
Total operating revenues		397.5		79.6		97.6		12.9		291.0		8.4			(10.0	)		877.0
Net income attributable to common shareholders		52.5		9.3		9.8		9.4		93.4		(130.1	)		—			44.3
For the three months ended March 31, 2015
Operating revenues from external customers (1)	$	446.5	$	69.2	$	103.0	$	13.1	$	254.2	$	3.2		$	(0.5	)	$	888.7
Inter-segment revenues (1)		—		—		2.4		—		3.6		5.6			(11.8	)		(0.2	)
Total operating revenues		446.5		69.2		105.4		13.1		257.8		8.8			(12.3	)		888.5
Net income attributable to common shareholders		68.0		11.5		8.8		9.9		64.9		(3.0	)		—			160.1

(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Inter-company transactions which have not been eliminated are measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are included in determining reportable segments.

5. REGULATED FUEL ADJUSTMENT MECHANISM AND FIXED COST DEFERRALS

NSPI’s regulated fuel adjustment mechanism and fixed cost deferrals is recognized in the Consolidated Statements of Income and consisted of the following:

For the millions of Canadian dollars	Three months ended March 31
	2016		2015
Regulated fuel adjustment mechanism (see chart below)	$	13.8	$	(5.4	)
Application of non-fuel revenue		3.8		7.0
Regulated fixed cost deferral related to 2015 demand side management		—		(8.8	)
	$	17.6	$	(7.2	)

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Regulated Fuel Adjustment Mechanism

The regulated fuel adjustment mechanism (“FAM”) included in the Consolidated Statements of Income includes the effect of prudently incurred fuel for generation and purchased power and certain fuel related costs (“Fuel Costs”) in both the current and preceding years, specifically, and as detailed in the table below:

• The difference between actual Fuel Costs and amounts recovered from customers in the current year. This amount is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities” on the Consolidated Balance Sheets; and

• The recovery from (rebate to) customers of under (over) recovered Fuel Costs from prior years.

The FAM is subject to an incentive, with NSPI retaining or absorbing 10 per cent of the over or under-recovered amount to a maximum of $5 million. The incentive was suspended for 2012 to 2015, as a result of UARB approved settlement agreements and is in effect for 2016.

The regulated fuel adjustment mechanism on the Consolidated Statements of Income consisted of the following:

For the millions of Canadian dollars	Three months ended March 31
	2016		2015
Over (Under) recovery of current period Fuel Costs	$	10.0	$	(23.6	)
Recovery from (rebate to) customers of prior years’ Fuel Costs		3.8		18.2
Regulated fuel adjustment mechanism	$	13.8	$	(5.4	)

The deferred FAM amounts are recognized as a “Regulatory asset” or “Regulatory liability” on the Consolidated Balance Sheets. The FAM regulatory asset balance of $8.5 million and the FAM regulatory liability balance of $55.1 million is disclosed in Note 16 and includes associated interest recorded as “Interest expense, net” on the Consolidated Statements of Income.

In December 2015, the UARB approved NSPI’s 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as submitted in NSPI’s filings. Approved customer rates reset the base cost of fuel rate for 2016 and seek to recover a total of $13.7 million of prior years’ unrecovered Fuel Costs in 2016. Recovery of these costs began January 1, 2016.

On December 18, 2015, the Electricity Plan Implementation (2015) Act (the “Electricity Plan Act”) was enacted by the Province of Nova Scotia. In accordance with the Electricity Plan Act, NSPI filed with the UARB, on March 7, 2016, a three-year rate plan for Fuel Costs, requesting an average increase of 1.3 per cent for 2017 through 2019. A hearing is scheduled for June 13, 2016. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates during this period will be deferred to a FAM regulatory asset or liability and recovered from or returned to customers subsequent to 2019.

Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. The audit for fiscal 2014 and 2015 is currently underway.

Application of Non-Fuel Revenues

The Electricity Plan Act further directed NSPI to apply any non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of tax benefits for the South Canoe and Sable Wind Projects is to be reserved to be applied to the FAM to be used in the 2017 to 2019 period. The exception to this direction is application of a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would have been otherwise required. This amount totals $4.6 million. As a result, as at December 31, 2015,

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NSPI has deferred $4.6 million of excess non-fuel revenues to 2016 and $40.1 million of excess non-fuel revenues for the periods 2017 to 2019.

In Q1 2016, NSPI applied $3.8 million of non-fuel revenues to the FAM for periods 2017 to 2019. This was a result of applying the tax benefits associated with the South Canoe and Sable Wind Projects as directed by the Electricity Plan Act.

Fixed Cost Deferral Related to 2015 DSM

In April 2014, the Government of Nova Scotia announced new energy efficiency legislation to remove a previous charge for conservation and efficiency programs from electricity bills of Nova Scotia customers effective January 1, 2015. In addition, the legislation requires NSPI to purchase electricity efficiency and conservation activities (“Program Costs”) from EfficiencyOne, the provincially appointed franchisee to deliver energy efficiency programs to Nova Scotians. The Program Costs were set for 2015 at $35 million and were deferred as a regulatory asset and recoverable from customers over an eight-year period beginning in 2016. In August 2015, the UARB approved a budget of $102.0 million for the three-year period of 2016 through 2018. The Electricity Plan Act placed a cap of $34.0 million on 2019 DSM spending. The 2016 DSM cost of $24.7 million will not be deferred and will be charged to earnings.

The deferred DSM amounts from 2015 are recognized as a “Regulatory asset” on the Consolidated Balance Sheets. The DSM regulatory asset balance of $35.6 million is disclosed in Note 16 and includes associated interest that is recorded as “Interest expense, net” on the Consolidated Statements of Income.

For the millions of Canadian dollars	2016
DSM regulatory asset – Balance as at January 1	$	36.4
Recovery of regulatory asset recorded as regulatory amortization		(1.5	)
Interest on DSM balance		0.7
DSM regulatory asset – Balance as at March 31	$	35.6

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6. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Investments subject to significant influence consisted of the following:

	Carrying Value as at				Equity Income For the three months ended March 31				Percentage of Ownership
	March 31		December 31
millions of Canadian dollars	2016		2015		2016		2015		2016
APUC (1) (2)	$	520.1	$	503.7	$	9.0	$	6.6		19.4
LIL (3)		251.1		208.1		4.7		1.7		59.0
NSPML		206.4		187.6		4.4		3.6		100.0
M&NP		178.2		188.7		5.9		5.9		12.9
Lucelec		36.8		39.4		0.6		0.6		19.1
Maine Electric Power Company Inc.		6.6		7.0		—		0.1		21.7
Cape Sharp Tidal Venture Ltd.		5.2		5.1		—		—		20.0
Chester Static Var Compensator		4.9		5.3		—		—		50.0
Maine Yankee Atomic Power Company		0.4		0.4		—		—		12.0
Bear Swamp (4)		—		—		1.4		3.1		50.0
Northeast Wind Partnership II, LLC (“NWP”)		—		—		—		4.3		—
	$	1,209.7	$	1,145.3	$	26.0	$	25.9

(1) As at March 31, 2016, the market price per share was $10.87 (December 31, 2015 – $10.91), which indicates a fair market value of this investment of $685.4 million (December 31, 2015 – $684.5 million). Emera holds 50.1 million shares and 12.9 million outstanding subscription receipts and dividend equivalents as at March 31, 2016 at an average book value of $8.25 per share. Carrying value reflects a cash cost of $371.2 million, plus non-cash gains recognized on conversion of prior subscriptions receipts into common shares, dilution gains or losses, and equity income or loss, less dividends received. The outstanding subscription receipts, with an average conversion price of $9.19 will automatically convert to common shares in Q4 2016 if an election is not made. If converted, Emera’s interest would increase to 23.2 per cent.

(2) Emera’s Strategic Investment Agreement with APUC and a ruling by the Maine Public Utilities (“MPUC”) limits Emera’s ownership in APUC to 25 per cent of APUC’s voting securities. The MPUC also stipulated Emera’s dollar investment in APUC cannot exceed 5 per cent of Emera’s total assets. As at March 31, 2016, Emera is in compliance with both of these requirements.

(3) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. Emera’s share of the total partnership capital is 59.0 per cent.

(4) Bear Swamp’s credit investment balance is recorded in “Other long-term liabilities” on the Consolidated Balance Sheets.

Equity investments include a $138.1 million difference between the cost and the underlying fair value of the investees’ assets as at the date of acquisition. The excess is attributable to goodwill.

Emera accounts for its variable interest investment in NSPML as an equity investment (note 27). NSPML’s consolidated summarized balance sheet is illustrated as follows:

As at millions of Canadian dollars	March 31 2016		December 31 2015
Balance Sheet
Current assets	$	501.2	$	438.7
Property, plant and equipment		750.7		647.7
Non-current assets		466.0		565.6
Total assets	$	1,717.9	$	1,652.0
Current liabilities	$	173.0	$	129.8
Non-current liabilities		1,338.5		1,334.6
Equity		206.4		187.6
Total liabilities and equity	$	1,717.9	$	1,652.0

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7. OTHER INCOME (EXPENSES), NET

Other income (expenses), net consisted of the following:

For the millions of Canadian dollars	Three months ended March 31
	2016			2015
Allowance for equity funds used during construction	$	0.9		$	0.3
Investment income		0.5			0.3
Foreign exchange gains (losses)		(1.5	)		1.9
Amortization of defeasance costs		(1.7	)		(1.7	)
Foreign exchange gains (losses) and mark-to-market adjustments related to the pending TECO Energy acquisition		(139.5	)		—
Gain on sale of NWP investment		—			18.6
Other		2.1			2.5
	$	(139.2	)	$	21.9

8. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

For the millions of Canadian dollars	Three months ended March 31
	2016			2015
Interest on debt	$	48.7		$	47.3
Interest on convertible debentures represented by instalment receipts (1)		21.9			—
Allowance for borrowed funds used during construction		(0.7	)		(2.2	)
Interest revenue		(0.9	)		(2.1	)
Other		6.2			1.4
	$	75.2		$	44.4

(1) In 2015, Emera completed the sale of $2.1 billion four per cent convertible unsecured subordinated debentures represented by instalment receipts (“Debentures” or “the Debenture Offering” or “Convertible Debentures”).

9. INCOME TAXES

The income tax provision differs from that computed using the statutory income tax rate for the following reasons:

For the millions of Canadian dollars	Three months ended March 31
	2016			2015
Income before provision for income taxes	$	81.6		$	235.5
Statutory income tax rate		31.0%			31.0%
Income taxes, at statutory income tax rate		25.3			73.0
Non-deductible portion of mark-to-market losses related to pending TECO Energy acquisition		21.6			—
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(13.1	)		(9.4	)
Tax effect of equity earnings		(2.9	)		(2.3	)
Tax effect of foreign exchange		(2.3	)		2.9
Other		(1.8	)		(2.8	)
Income tax expense (recovery)	$	26.8		$	61.4
Effective income tax rate		32.8%			26.1%

The 2016 and 2015 statutory income tax rate of 31.0 per cent represents the combined Canadian federal and Nova Scotia provincial corporate income tax rates, which are the relevant tax jurisdictions for Emera.

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The following reflects the composition of taxes on income from continuing operations presented in the Condensed Consolidated Statements of Income:

For the millions of Canadian dollars	Three months ended March 31
	2016		2015
Income tax expense (recovery) – current	$	18.0	$	49.1
Income tax expense (recovery) – deferred		8.8		12.3
Income tax expense (recovery)	$	26.8	$	61.4

NSPI and the Canada Revenue Agency (“CRA”) are currently in a dispute with respect to the timing of certain tax deductions for NSPI’s 2006 through 2010 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $62.3 million, including interest. NSPI has prepaid $22.7 million of the amount in dispute, as required by CRA.

Should NSPI be successful in defending its position, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the excess, if any, owing to CRA. The related tax deductions will be available in subsequent years.

In Q2 2015, CRA commenced audit of NSPI’s 2011 through 2013 taxation years. Should NSPI receive notices of reassessment for those years, and should the 2014 and 2015 taxation years be similarly reassessed, further payments will be required; however, the ultimate permissibility of these deductions is similarly not in dispute.

NSPI and its advisors believe that NSPI has reported its tax position appropriately and NSPI is disputing the reassessments through the CRA Appeal process. The outcome of this process is not determinable at this time.

10. EARNINGS PER SHARE

The following table reconciles the computation of basic and diluted earnings per share:

For the millions of Canadian dollars (except per share amounts)	Three months ended March 31
	2016		2015
Numerator
Net income attributable to common shareholders	$	44.3	$	160.1
Preferred stock dividends of subsidiary		—		2.0
Diluted numerator		44.3		162.1
Denominator
Weighted average shares of common stock outstanding		147.7		144.0
Weighted average deferred share units outstanding		1.0		0.9
Weighted average shares of common stock outstanding – basic		148.7		144.9
Effect of dilutive securities		—		3.3
Stock-based compensation		0.6		0.6
Weighted average shares of common stock outstanding – diluted		149.3		148.8
Earnings per common share
Basic	$	0.30	$	1.10
Diluted	$	0.30	$	1.09

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Effect on EPS of Convertible Debentures

Following the satisfaction of all conditions precedent to the closing of the acquisition of TECO Energy, at the option of holders and provided that payment of the final installment has been made, each Debenture will be convertible into common shares of Emera. This conversion can occur at any time after the Final Instalment Date, but prior to maturity or redemption by the Company. The conversion price is $41.85 per common share, and the conversion rate is 23.8949 common shares per $1,000 principal amount of Debentures (note 22). Accordingly, a total of approximately 52.2 million common shares could be issued to convert the Debentures into common shares. When the conditions for closing the acquisition are met, the Debentures will be included as a component of the Company’s diluted EPS.

11. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income (loss), net of tax, are as follows:

millions of Canadian dollars	(Losses) gains on derivatives recognized as cash flow hedges			Net change in unrecognized pension and post-retirement benefit costs			Net change in available-for-sale investments		Unrealized (loss) gain on translation of self-sustaining foreign operations			Total AOCI
For the three months ended March 31, 2016
Balance, January 1, 2016	$	(35.1	)	$	(317.6	)	$	0.3	$	488.9		$	136.5
Other comprehensive income (loss) before reclassifications		14.1			—			0.4		(154.7	)		(140.2	)
Amounts reclassified from accumulated other comprehensive income loss (gain)		0.9			8.6			—		—			9.5
Net current period other comprehensive income (loss)		15.0			8.6			0.4		(154.7	)		(130.7	)
Balance, March 31, 2016	$	(20.1	)	$	(309.0	)	$	0.7	$	334.2		$	5.8
millions of Canadian dollars	(Losses) gains on derivatives recognized as cash flow hedges			Net change in unrecognized pension and post-retirement benefit costs			Net change in available-for-sale investments		Unrealized (loss) gain on translation of self-sustaining foreign operations			Total AOCI
For the three months ended March 31, 2015
Balance, January 1, 2015	$	(7.9	)	$	(424.7	)	$	2.6	$	82.4		$	(347.6	)
Other comprehensive income (loss) before reclassifications		(15.9	)		—			0.4		176.2			160.7
Amounts reclassified from accumulated other comprehensive income loss (gain)		(1.1	)		10.6			—		—			9.5
Net current period other comprehensive income (loss)		(17.0	)		10.6			0.4		176.2			170.2
Balance, March 31, 2015	$	(24.9	)	$	(414.1	)	$	3.0	$	258.6		$	(177.4	)

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The reclassifications out of accumulated other comprehensive income (loss) are as follows:

For the millions of Canadian dollars		Three months ended March 31
		2016			2015
	Affected line item in the Consolidated Statements of Income		Amounts reclassified from AOCI
Losses (gain) on derivatives recognized as cash flow hedges
Power and gas swaps	Non-regulated fuel for generation and purchased power	$	(4.2	)	$	(5.6	)
Interest rate swaps	Income from equity investments		0.3			0.2
Foreign exchange forwards	Operating revenue – regulated		3.2			2.1
Total before tax			(0.7	)		(3.3	)
	Income tax expense (recovery)		1.6			2.2
Total net of tax		$	0.9		$	(1.1	)
Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses (gains)	OM&G	$	10.9		$	11.9
Past service costs (gains)	OM&G		(2.3	)		(0.7	)
Total before tax			8.6			11.2
	Income tax expense (recovery)		—			(0.6	)
Total net of tax		$	8.6		$	10.6
Net change in available-for-sale investments
Total reclassifications out of AOCI, net of tax, for the period		$	9.5		$	9.5

12. RECEIVABLES, NET

Receivables, net consisted of the following:

As at millions of Canadian dollars	March 31 2016			December 31 2015
Customer accounts receivable – billed	$	437.8		$	406.3
Customer accounts receivable – unbilled		146.6			144.2
Total customer accounts receivable		584.4			550.5
Allowance for doubtful accounts		(12.1	)		(12.6	)
Customer accounts receivable, net		572.3			537.9
Other		38.0			39.5
	$	610.3		$	577.4

13. INVENTORY

Inventory consisted of the following:

As at millions of Canadian dollars	March 31 2016		December 31 2015
Fuel	$	141.1	$	185.3
Materials		98.8		100.4
Emission credits (1)		20.9		28.6
	$	260.8	$	314.3

(1) The New England Gas Generating Facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions. In addition, Bridgeport Energy is subject to the Clean Air Interstate Rule for ozone season nitrogen dioxide emission allowances. The emissions credits inventory balance represents the credits purchased to offset the liabilities (notes 21 and 23) associated with these programs.

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14. DERIVATIVE INSTRUMENTS

The Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to:

• commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations;

• foreign exchange fluctuations on foreign currency denominated purchases and sales; and

• interest rate fluctuations on debt securities.

The Company also enters into physical contracts for energy commodities. Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches:

1. Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exception if the criteria are no longer met.

2. Derivatives that qualify for hedge accounting are recorded at fair value on the balance sheet. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge the identified cash flow risk both at the inception and over the term of the derivative. Specifically for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in fair value from cash flow hedges is recognized in net income in the reporting period.

Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

3. Derivatives entered into by NSPI and GBPC that are documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates.

4. Derivatives that do not meet any of the above criteria are designated as held-for-trading (“HFT”) derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

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Derivative assets and liabilities relating to the foregoing categories consisted of the following:

	Derivative Assets						Derivative Liabilities
As at	March 31			December 31			March 31			December 31
millions of Canadian dollars	2016			2015			2016			2015
Current
Cash flow hedges
Power swaps	$	5.3		$	7.9		$	0.5		$	0.5
Foreign exchange forwards		0.3			—			10.2			14.4
		5.6			7.9			10.7			14.9
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			—			7.7			11.7
Natural gas purchases and sales		0.7			1.5			2.3			0.7
Heavy fuel oil purchases		—			—			16.4			20.5
Foreign exchange forwards		56.2			85.3			7.6			10.5
Physical natural gas purchases and sales		0.8			1.8			—			—
		57.7			88.6			34.0			43.4
HFT derivatives
Power swaps and physical contracts		21.1			150.8			23.7			118.5
Foreign exchange options		0.3			98.6			1.0			2.1
Natural gas swaps, futures, forwards, physical contracts		64.0			—			132.1			358.8
		85.4			249.4			156.8			479.4
Other derivatives
Foreign exchange forwards		1.1			92.1			3.8			—
		1.1			92.1			3.8			—
Total gross current derivatives		149.8			438.0			205.3			537.7
Impact of master netting agreements with intent to settle net or simultaneously		(57.4	)		(188.5	)		(57.4	)		(188.5	)
Total current derivatives		92.4			249.5			147.9			349.2
Long-term
Cash flow hedges
Power swaps		5.7			11.6			3.7			4.1
Foreign exchange forwards		0.4			0.3			14.1			27.2
		6.1			11.9			17.8			31.3
Regulatory deferral
Commodity swaps and forwards
Coal purchases		3.0			—			4.0			4.4
Heavy fuel oil purchases		—			—			13.3			16.6
Foreign exchange forwards		72.0			121.4			—			—
		75.0			121.4			17.3			21.0
HFT derivatives
Power swaps and physical contracts		14.1			12.9			27.5			28.2
Natural gas swaps, futures, forwards and physical contracts		24.2			72.3			47.4			62.6
Foreign exchange options		0.7			0.4			0.7			1.4
		39.0			85.6			75.6			92.2
Other derivatives
Interest rate swap		—			—			3.2			2.9
		—			—			3.2			2.9
Total gross long-term derivatives		120.1			218.9			113.9			147.4
Impact of master netting agreements with intent to settle net or simultaneously		(34.7	)		(51.3	)		(34.7	)		(51.3	)
Total long-term derivatives		85.4			167.6			79.2			96.1
Total derivatives	$	177.8		$	417.1		$	227.1		$	445.3

Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

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Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table:

	Derivative Assets				Derivative Liabilities
As at	March 31		December 31		March 31		December 31
millions of Canadian dollars	2016		2015		2016		2015
Regulatory deferral	$	1.4	$	0.1	$	1.4	$	0.1
HFT derivatives		90.7		239.7		90.7		239.7
Total impact of master netting agreements with intent to settle net or simultaneously	$	92.1	$	239.8	$	92.1	$	239.8

Cash Flow Hedges

The Company enters into various derivatives designated as cash flow hedges. Emera enters into power swaps to limit Bear Swamp’s exposure to purchased power prices. Emera also enters into interest rate swaps to fix Bear Swamp’s cost of debt. The Company also enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.

As previously noted, the effective portion of the change in fair value of these derivatives is included in AOCI, until the hedged transactions are recognized in income. The ineffective portion is recognized in income of the period. The amounts related to cash flow hedges recorded in income and AOCI consisted of the following:

For the millions of Canadian dollars	Three months ended March 31
	2016									2015
	Power Swaps			Interest Rate Swaps			Foreign Exchange Forwards			Power Swaps			Interest Rate Swaps			Foreign Exchange Forwards
Unrealized gain (loss) in Non-regulated fuel for generation and purchased power – ineffective portion	$	(1.0	)	$	—		$	—		$	(0.6	)	$	—		$	—
Realized gain (loss) in Non-regulated fuel for generation and purchased power		4.2			—			—			5.6			—			—
Realized gain (loss) in Operating revenue – Regulated		—			—			(3.2	)		—			—			(2.1	)
Realized gain (loss) in Income from equity investments		—			(0.3	)		—			—			(0.2	)		—
Total gains (losses) in Net income	$	3.2		$	(0.3	)	$	(3.2	)	$	5.0		$	(0.2	)	$	(2.1	)
As at millions of Canadian dollars	March 31 2016									December 31 2015
	Power Swaps			Interest Rate Swaps			Foreign Exchange Forwards			Power Swaps			Interest Rate Swaps			Foreign Exchange Forwards
Total unrealized gain (loss) in AOCI – effective portion, net of tax	$	0.9		$	(0.9	)	$	(23.6	)	$	3.5		$	(1.1	)	$	(41.7	)

The Company expects $8.7 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

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As at March 31, 2016, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:

millions	2016		2017		2018		2019		2020
Power swaps (megawatt hours (“MWh”)) purchases		0.2		0.3		—		—		—
Foreign exchange forwards (USD) sales		40.4		53.4		44.8		30.0		30.0
Foreign exchange forwards (EURO) purchases		—		2.6		—		—		—

Regulatory Deferral

As previously noted, NSPI and GBPC defer gains and losses on certain derivatives documented as economic hedges, including certain physical contracts that do not qualify for the NPNS exemption.

The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:

For the millions of Canadian dollars	Three months ended March 31, 2016
	Commodity swaps and forwards		Physical natural gas purchases and sales			Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$	4.1	$	—		$	2.9
Unrealized gain (loss) in regulatory liabilities		0.9		(1.0	)		(50.4	)
Realized (gain) loss in regulatory assets		1.7		—			—
Realized (gain) loss in inventory (1)		—		—			(19.4	)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		5.7		—			(8.7	)
Total change in derivative instruments	$	12.4	$	(1.0	)	$	(75.6	)

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable.

For the millions of Canadian dollars	Three months ended March 31, 2015
	Commodity swaps and forwards			Physical natural gas purchases and sales			Foreign exchange forwards
Unrealized gain (loss) in regulatory assets	$	(8.3	)	$	—		$	(2.7	)
Unrealized gain (loss) in regulatory liabilities		(0.1	)		4.7			92.6
Realized (gain) loss in regulatory assets		3.4			—			—
Realized (gain) loss in inventory (1)		(0.7	)		—			(12.7	)
Realized (gain) loss in property, plant and equipment		—			—			(1.0	)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		4.0			(0.1	)		(2.8	)
Total change in derivative instruments	$	(1.7	)	$	4.6		$	73.4

(1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed.

(2) Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable.

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Commodity Swaps and Forwards

As at March 31, 2016, the Company had the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:

	2016		2017-2019
millions	Purchases		Purchases
Coal (metric tonnes)		0.2		2.3
Natural Gas (mmbtu)		3.2		—
Heavy fuel oil (bbls)		0.5		0.5

Foreign Exchange Swaps and Forwards

As at March 31, 2016, the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are expected to settle as outlined below:

	2016			2017-2019
Fuel purchases exposure (millions of US dollars)	$	150.8		$	461.8
Weighted average rate		1.0331			1.0932
% of USD requirements		96	%		90	%

Held-for-Trading Derivatives

In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures to economically hedge those physical contracts. These derivatives are all considered HFT.

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:

For the millions of Canadian dollars	Three months ended March 31
	2016			2015
Power swaps and physical contracts in non-regulated operating revenues	$	(5.5	)	$	1.5
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		227.9			92.5
Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		0.9			(1.8	)
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		(1.6	)		2.0
Foreign exchange options in non-regulated operating revenue		(0.8	)		—
	$	220.9		$	94.2

As at March 31, 2016, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

millions	2016		2017		2018		2019		2020
Natural gas purchases (Mmbtu)		194.5		60.6		49.9		43.9		43.9
Natural gas sales (Mmbtu)		155.8		33.8		6.1		5.8		5.1
Power purchases (MWh)		0.6		0.6		0.6		0.6		0.6
Power sales (MWh)		1.7		0.3		0.3		0.3		0.3
Foreign exchange options (USD)	$	14.9	$	12.5	$	4.1		—		—
Foreign exchange forwards (EURO) purchases		—		0.2		—		—		—

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Other Derivatives

The Company has recognized the following realized and unrealized gains (losses) with respect to cash flow hedges which documentation requirements have not been met:

For the millions of Canadian dollars	Three months ended March 31
	2016						2015
	Interest rate swaps			Foreign exchange forwards			Interest rate swaps		Foreign exchange forwards
Unrealized gain (loss) in other income (expense)	$			$	(94.8	)	$	—	$	—
Unrealized gain (loss) in interest expense, net		(0.3	)		—			—		—
Total gains (losses) in net income	$	(0.3	)	$	(94.8	)	$	—	$	—

As at March 31, 2016, the Company had interest rate swaps in place for the $250 million non-revolving term credit facility in Brunswick Pipeline for interest payments until the debt matures in 2019.

As at March 31, 2016, the Company had a foreign exchange forwards in place for $1,121.7 million USD in 2016 to economically hedge the anticipated proceeds from the Debenture Offering for the pending TECO Energy acquisition.

Credit Risk

The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts.

The Company assesses the potential for credit losses on a regular basis, and where appropriate, recognizes provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

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As at March 31, 2016, the Company had $86.3 million (December 31, 2015 – $83.2 million) in financial assets, considered to be past due, which have been outstanding for an average 78 days. The fair value of these financial assets is $75.1 million (December 31, 2015 – $71.5 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric revenue.

Cash Collateral

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”.

The Company’s cash collateral positions consisted of the following:

As at millions of Canadian dollars	March 31 2016		December 31 2015
Cash collateral provided to others	$	124.9	$	106.9
Cash collateral received from others		1.4		28.5

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt to fall below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at March 31, 2016, the total fair value of these derivatives, in a liability position, was $227.1 million (December 31, 2015 – $445.3 million). If the credit ratings of the Company were reduced below investment grade the full value of the net liability position could be required to be posted as collateral for these derivatives.

15. FAIR VALUE MEASUREMENTS

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exemption (see note 14), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:

Level 1 – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 – Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows:

• While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

• The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

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• The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

The following tables set out the classification of the methodology used by the Company to fair value its derivatives:

As at	March 31, 2016
millions of Canadian dollars	Level 1			Level 2		Level 3			Total
Assets
Cash flow hedges
Power swaps	$	11.0		$	0.2	$	—		$	11.2
Foreign exchange forwards		—			0.5		—			0.5
		11.0			0.7		—			11.7
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			1.7		—			1.7
Natural gas purchases and sales		—			0.6		—			0.6
Foreign exchange forwards		—			128.2		—			128.2
Physical natural gas purchases and sales		—			—		0.8			0.8
		—			130.5		0.8			131.3
HFT derivatives
Power swaps and physical contracts		(3.7	)		0.4		4.8			1.5
Foreign exchange options		—			1.0		—			1.0
Natural gas swaps, futures, forwards, physical contracts and related transportation		2.0			8.7		20.5			31.2
		(1.7	)		10.1		25.3			33.7
Other derivatives
Foreign exchange forwards		—			1.1		—			1.1
		—			1.1		—			1.1
Total assets		9.3			142.4		26.1			177.8
Liabilities
Cash flow hedges
Power swaps		4.2			—		—			4.2
Foreign exchange forwards		—			24.3		—			24.3
		4.2			24.3		—			28.5
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			10.4		—			10.4
Heavy fuel oil purchases		—			29.6		—			29.6
Natural gas purchases and sales		2.1			0.1		—			2.2
Foreign exchange forwards					7.6		—			7.6
		2.1			47.7		—			49.8
HFT derivatives
Power swaps and physical contracts		12.2			0.9		4.6			17.7
Foreign exchange options		—			1.7		—			1.7
Natural gas swaps, futures, forwards and physical contracts		6.9			19.5		96.0			122.4
		19.1			22.1		100.6			141.8
Other derivatives
Foreign exchange forwards		—			3.8		—			3.8
Interest rate swap		—			3.2		—			3.2
		—			7.0		—			7.0
Total liabilities		25.4			101.1		100.6			227.1
Net assets (liabilities)	$	(16.1	)	$	41.3	$	(74.5	)	$	(49.3	)

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As at	December 31, 2015
millions of Canadian dollars	Level 1			Level 2		Level 3			Total
Assets
Cash flow hedges
Power swaps	$	19.5		$	—	$	—		$	19.5
Foreign exchange forwards		—			0.3		—			0.3
		19.5			0.3		—			19.8
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			1.4		—			1.4
Foreign exchange forwards		—			206.7		—			206.7
Physical natural gas purchases and sales		—			—		1.8			1.8
		—			208.1		1.8			209.9
HFT derivatives
Power swaps and physical contracts		38.3			—		(7.8	)		30.5
Foreign exchange forwards		—			0.4		—			0.4
Natural gas swaps, futures, forwards and physical contracts		(0.3	)		7.9		56.8			64.4
		38.0			8.3		49.0			95.3
Other derivatives
Foreign exchange forwards		—			92.1		—			92.1
		—			92.1		—			92.1
Total assets		57.5			308.8		50.8			417.1
Liabilities
Cash flow hedges
Power swaps	$	4.6		$	—	$	—		$	4.6
Foreign exchange forwards		—			41.6		—			41.6
		4.6			41.6		—			46.2
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			16.1		—			16.1
Natural gas purchases and sales		0.6			—		—			0.6
Heavy fuel oil purchases		—			37.1		—			37.1
Foreign exchange forwards		—			10.5		—			10.5
		0.6			63.7		—			64.3
HFT derivatives
Power swaps and physical contracts		15.2			—		(2.0	)		13.2
Foreign exchange options		—			3.5		—			3.5
Natural gas swaps, futures, forwards and physical contracts		14.4			22.0		278.8			315.2
		29.6			25.5		276.8			331.9
Other derivatives
Interest rate swaps		—			2.9		—			2.9
		—			2.9		—			2.9
Total liabilities		34.8			133.7		276.8			445.3
Net assets (liabilities)	$	22.7		$	175.1	$	(226.0	)	$	(28.2	)

The Company evaluates the observable inputs of market data on a quarterly basis in order to determine if transfers between levels is appropriate. For the three months ended March 31, 2016, there were no transfers between levels.

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The change in the fair value of the Level 3 financial assets for the three months ended March 31, 2016 was as follows:

	Regulatory Deferral			Cash Flow Hedges and HFT Derivatives
millions of Canadian dollars	Physical natural gas purchases and sales			Power Swaps			Natural gas			Total
Balance, January 1, 2016	$	1.8		$	(7.8	)	$	56.8		$	50.8
Unrealized gains (losses) included in regulatory assets or liabilities		(1.0	)		—			—			(1.0	)
Total realized and unrealized gains (losses) included in non-regulated operating revenues		—			12.6			(36.3	)		(23.7	)
Balance, March 31, 2016	$	0.8		$	4.8		$	20.5		$	26.1

The change in the fair value of the Level 3 financial liabilities for the three months ended March 31, 2016 was as follows:

	Regulatory Deferral		Cash Flow Hedges and HFT Derivatives
millions of Canadian dollars	Heavy fuel oil purchases		Power			Natural gas			Total
Balance, January 1, 2016	$	—	$	(2.0	)	$	278.8		$	276.8
Total realized and unrealized gains (losses) included in non-regulated operating revenues		—		6.6			(182.8	)		(176.2	)
Balance, March 31, 2016	$	—	$	4.6		$	96.0		$	100.6

Emera’s Enterprise Risk Management group is responsible for valuation policies, processes and the measurement of fair value. Fair value accounting rules provide a three level hierarchy that prioritizes the inputs used to measure fair value. When possible, determining fair value is based primarily on observable market inputs in active markets.

Contracts with quoted prices available in active markets and exchanges for identical assets or liabilities are classified as level 1 in the hierarchy. For those contracts whereby pricing inputs are either directly or indirectly observable through markets, exchanges or third party sources, but do not qualify as level 1, are classified as level 2 in the hierarchy. For a level 3 classification, the processes and methods of measurement for third-party pricing information and illiquid markets are developed with input and using the market knowledge of the trading operations within Emera and its affiliates.

Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives includes third-party-sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Where possible, Emera also sources multiple broker prices in an effort to evaluate and substantiate these unobservable inputs. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement.

The following table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy:

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As at	March 31, 2016
millions of Canadian dollars	Fair Value			Valuation Technique		Unobservable Input		Range		Weighted average
Assets
Regulatory deferral – Physical	$	0.8			Modelled pricing		Third-party pricing		$4.09 - $4.70	$	4.36
natural gas purchases and sales							Probability of default		0.07%		0.01%
HFT derivatives –		4.4			Modelled pricing		Third-party pricing		$18.85 - $74.05	$	30.20
Power swaps and							Probability of default		0.00% - 0.02%		0.00%
physical contracts							Discount rate		0.02% - 0.05%		0.03%
		0.4			Modelled pricing		Third-party pricing		$21.51 - $78.42	$	35.74
							Correlation factor		0.99% - 0.99%		0.99%
							Probability of default		0.00% - 0.01%		0.01%
							Discount rate		0.02% - 0.11%		0.06%
HFT derivatives –		11.7			Modelled pricing		Third-party pricing		$1.35 - $7.76	$	2.63
Natural gas swaps,							Probability of default		0.00% - 0.03%		0.01%
futures, forwards,							Discount rate		0.00% - 0.27%		0.05%
physical contracts		8.8			Modelled pricing		Third-party pricing		$1.07 - $7.71	$	2.66
and related transportation							Basis adjustment		-0.12% - 0.74%		0.46%
							Probability of default		0.00% - 0.01%		0.00%
							Discount rate		0.00% - 0.07%		0.00%
Total assets		26.1
Liabilities
HFT derivatives –	$	4.4			Modelled pricing		Third-party pricing		$18.85 - $74.05	$	30.48
Power swaps and							Own credit risk		0.00% - 0.01%		0.01%
physical contracts							Discount rate		0.02% - 0.05%		0.03%
		0.2			Modelled pricing		Third-party pricing		$21.51 - $78.42	$	35.26
							Correlation factor		0.99% - 0.99%		0.99%
							Own credit risk		0.00% - 0.01%		0.01%
							Discount rate		0.02% - 0.11%		0.06%
HFT derivatives –		74.7			Modelled pricing		Third-party pricing		$1.04 - $7.76	$	2.80
Natural gas swaps, futures,							Own credit risk		0.00% - 0.03%		0.00%
forwards and physical contracts							Discount rate		0.00% - 0.08%		0.02%
		21.3			Modelled pricing		Third-party pricing		$1.07 - $7.75	$	2.86
							Basis adjustment		-0.12% - 0.74%		0.18%
							Own credit risk		0.00% - 0.25%		0.00%
							Discount rate		0.00% - 0.07%		0.01%
Total liabilities		100.6
Net assets (liabilities)	$	(74.5	)

The financial assets and liabilities included on the Consolidated Balance Sheets that are not measured at fair value consisted of the following:

As at millions of Canadian dollars	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including current portion)	$	3,986.8	$	4,579.7	$	4,008.6	$	4,382.9

The fair values of long-term debt instruments, classified as level 3 in the fair value hierarchy, are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturity, without considering the effect of third party credit enhancements.

All other financial assets and liabilities, such as cash and cash equivalents, restricted cash, accounts receivable, short-term debt and accounts payable, are carried at cost. The carrying value approximates fair value due to the short-term nature of these financial instruments.

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16. REGULATORY ASSETS AND LIABILITIES

A summary of the Company’s regulatory assets and liabilities is provided below. For a detailed description of the nature of the Company’s regulatory assets and liabilities, refer to Note 17 in Emera’s 2015 annual audited consolidated financial statements.

As at millions of Canadian dollars	March 31 2016		December 31 2015
Regulatory assets
Deferred income tax regulatory asset	$	457.9	$	431.3
Deferrals related to derivative instruments		54.5		67.7
Unamortized defeasance costs		44.0		45.7
2015 Demand side management deferral (note 5)		35.6		36.4
Stranded cost recovery		27.5		28.5
Pension and post-retirement medical plan		10.8		11.9
Regulated fuel adjustment mechanism (note 5)		8.5		13.7
Hydro-Quebec obligation		7.0		7.6
2014 Maine storms		5.8		6.1
Asset impairment recovery		5.2		5.5
Purchased power contracts		4.9		5.9
Stranded cost revenue & purchase power reconciliation deferrals		4.6		6.1
Other		31.0		33.1
	$	697.3	$	699.5
Current	$	78.2	$	94.2
Long-term		619.1		605.3
Total regulatory assets	$	697.3	$	699.5
Regulatory liabilities
Deferrals related to derivative instruments	$	131.3	$	209.9
Self-Insurance Fund		81.8		86.8
Regulated fuel adjustment mechanism (note 5)		55.1		42.0
Deferred income tax regulatory liabilities		16.3		17.6
Other		11.7		14.3
	$	296.2	$	370.6
Current	$	75.0	$	98.9
Long-term		221.2		271.7
Total regulatory liabilities	$	296.2	$	370.6

17. RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues, with an offset to property, plant and equipment, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction. Below are transactions between Emera and its associated companies reported in the Consolidated Statements of Income:

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For the millions of Canadian dollars			Three months ended March 31
			2016			2015
	Nature of Service	Presentation
Sales to:
APUC subsidiary	Net sale of natural gas and transportation	Operating revenue – non-regulated	$	2.0		$	1.6
Purchases from:
M&NP	Natural gas transportation capacity	Regulated fuel for generation and purchased power		0.3		$	0.2
M&NP	Natural gas transportation capacity	Operating revenue – non-regulated	$	(8.1	)		(6.3	)

Operating revenue – non-regulated includes intercompany profit relating to the sale of natural gas, sale of power, construction, operations management and engineering services, and hedging services to rate-regulated subsidiaries of Emera totaling $0.3 million for the three months ended March 31, 2016 (2015 – $(0.2) million).

Amounts reported on Emera’s Consolidated Balance Sheets due (to) from its equity investments are summarized in the following table:

As at millions of Canadian dollars	March 31 2016		December 31 2015
Due from related parties:
NSPML – current	$	1.2	$	1.6
Subsidiary of APUC – current		0.3		0.7
M&NP – loan receivable – long-term		2.5		2.5
Due to related parties:
M&NP – current		2.3		2.1
Net due from (to) related parties	$	1.7	$	2.7

All amounts are under normal interest and credit terms, except for a loan receivable from M&NP bearing interest at 1 per cent per annum maturing on November 30, 2019.

18. OTHER CURRENT ASSETS

Other current assets consisted of the following:

As at millions of Canadian dollars	March 31 2016		December 31 2015
Net investment in direct financing lease	$	5.5	$	5.4
Dividend receivable		6.5		6.7
Capitalized transportation capacity (1)		156.3		222.7
	$	168.3	$	234.8

(1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

19. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees; and plans providing non-pension benefits for its retirees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Maine, Connecticut, Massachusetts, Rhode Island, Barbados, Dominica and Grand Bahama Island.

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The net benefit cost of providing the defined benefit pension and non-pension benefit plans is detailed below:

For the millions of Canadian dollars	Three months ended March 31
	2016			2015
Defined benefit pension plans
Service cost	$	5.5		$	5.5
Interest cost		15.1			14.6
Expected return on plan assets		(16.8	)		(16.0	)
Current year amortization of:
Actuarial losses (gains)		10.5			11.8
Past service costs (gains)		(0.2	)		(0.2	)
Total defined benefit pension plans		14.1			15.7
Non-pension benefits plan
Service cost		0.7			0.8
Interest cost		0.9			1.0
Expected return on plan assets		(0.1	)		—
Current year amortization of:
Actuarial losses (gains)		0.5			0.3
Past service costs (gains)		(2.1	)		(0.5	)
Total non-pension benefits plans		(0.1	)		1.6
Total defined benefit plans	$	14.0		$	17.3

20. AVAILABLE-FOR-SALE INVESTMENTS

The available-for-sale investments consist primarily of debt and equity investments held in trust on behalf of BLPC’s Self Insurance Fund (“SIF”) for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain of BLPC’s generating, transmission and distribution systems. Any withdrawal of SIF Fund assets by the Company would be subject to existing regulations.

In addition, these investments include debt and equity investments related to Emera Reinsurance Limited, for captive insurance purposes.

Available-for-sale financial assets are measured at fair value and classified in the fair value hierarchy as follows:

As at millions of Canadian dollars	March 31
	NAV (1)		Level 1		Level 2		Level 3		2016
Common shares		—	$	15.8	$	—	$	—	$	15.8
Corporate bonds, debentures, short and medium term notes		—		—		29.1		—		29.1
Government bonds		—		—		10.9		—		10.9
Other investments measured at NAV		50.4								50.4
	$	50.4	$	15.8	$	40.0	$	—	$	106.2
As at millions of Canadian dollars	December 31
	NAV (1)		Level 1		Level 2		Level 3		2015
Common shares	$	—	$	16.4	$	—	$	—	$	16.4
Corporate bonds, debentures, short and medium term notes		—		—		34.6		—		34.6
Government bonds		—		—		11.7		—		11.7
Other investments measured at NAV		53.3								53.3
	$	53.3	$	16.4	$	46.3	$	—	$	116.0

(1) Certain investments are permitted to be measured at fair value using the net asset value (“NAV”) per share practical expedient under USGAAP accounting standards.

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The fair value of financial instruments traded in active markets, and classified as level one, is based on quoted market prices at the balance sheet date. The quoted market price used for financial assets is the current bid price at the balance sheet date. Fair values within the level 2 category are determined through the use of quoted prices in active markets for similar assets, which in some cases, are adjusted for factors specific to the asset.

The primary pricing inputs in determining the equity and fixed assets mutual funds are the mutual funds’ NAVs. The funds are open-ended mutual funds, and there are no trading restrictions on the funds.

The change in available-for-sale assets is as follows:

As at millions of Canadian dollars	March 31 2016			December 31 2015
Balance, beginning of the year	$	116.0		$	84.4
Additions		—			34.5
Disposals		(3.5	)		(16.5	)
	$	112.5		$	102.4
Change in fair value
Gain (loss) recognized in other comprehensive income during the period		(6.3	)		13.6
	$	(6.3	)	$	13.6
Balance, end of the period	$	106.2		$	116.0

There were no impairment provisions for available-for-sale investments for the three months ended March 31, 2016 (2015 – nil).

The maturity profile of debt securities included in the available-for-sale assets is as follows:

As at millions of Canadian dollars	March 31 2016		December 31 2015
Maturity within 1 year	$	15.9	$	20.0
Maturity in 1-5 years		24.1		26.3
	$	40.0	$	46.3

The maximum exposure to credit risk at the reporting date is the carrying value of the debt securities. None of these financial instruments are either past due or impaired.

21. OTHER CURRENT LIABILITIES

Other current liabilities consisted of the following:

As at millions of Canadian dollars	March 31 2016		December 31 2015
Accrued charges	$	107.3	$	130.1
Accrued interest on long-term debt		40.8		44.1
Sales taxes payable		13.6		4.2
Accrued interest on convertible debentures represented by instalment receipts		11.2		11.2
Emission credits obligations (1)		1.8		6.3
Other		8.0		8.4
	$	182.7	$	204.3

(1) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are recorded as inventory (note 13) when purchased and subsequently applied against the emission liabilities at the end of each compliance period.

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22. CONVERTIBLE DEBENTURES REPRESENTED BY INSTALMENT RECEIPTS

To finance a portion of the pending acquisition of TECO Energy, Emera, through a direct wholly owned subsidiary (the “Selling Debentureholder”), on September 28, 2015, completed the sale of $1.9 billion aggregate principal amount of 4.0 per cent convertible unsecured subordinated debentures, represented by instalment receipts.

On October 2, 2015, in connection with the Debenture Offering, the underwriters fully exercised an over-allotment option and purchased an additional $285 million aggregate principal amount of Debentures at the Debenture Offering price. The sale of the additional Debentures brought the aggregate proceeds of the Debenture Offering to $2.185 billion, assuming payment of the final instalment.

The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which $333 was paid on closing of the Debenture Offering and the remaining $667 (the “Final Instalment”) is payable on a date (“Final Instalment Date”) to be fixed following satisfaction of conditions precedent to the closing of the acquisition of TECO Energy.

Approximately $21.9 million ($15.1 million after-tax) (2015 – nil) in interest expense associated with the Debentures was recognized in Q1 2016.

For a detailed description of the terms of the Debentures, refer to Note 30 in Emera’s annual audit consolidated financial statements.

23. OTHER LONG-TERM LIABILITIES

Other long-term liabilities consisted of the following:

As at millions of Canadian dollars	March 31 2016		December 31 2015
Funds received in excess of equity investment (1)	$	209.5	$	225.0
Long-term service agreements		30.6		37.7
Emission credits obligations (2)		7.7		6.3
Other		24.5		29.5
	$	272.3	$	298.5

(1) Emera has a 50 per cent investment in Bear Swamp. The investment balance in Bear Swamp is a credit primarily a result of a $178.7 million distribution received in Q4 2015.

(2) Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for the related emissions. Emission credits are capitalized to inventory (note 13) when purchased and subsequently applied against the emission liabilities at the end of each compliance period.

24. COMMITMENTS AND CONTINGENCIES

A. Commitments

As at March 31, 2016, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures represented by instalment receipts, long-term debt and AROs) for each of the next five years and in aggregate thereafter consisted of the following:

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millions of Canadian dollars	2016		2017		2018		2019		2020		Thereafter		Total
Purchased power (1)	$	166.5	$	229.8	$	204.0	$	198.7		195.2	$	2,380.5	$	3,374.7
Solid fuel supply		114.5		75.7		12.0		—		—		—		202.2
DSM		22.1		34.0		34.9		—		—		—		91.0
Transportation (2)		188.9		118.6		78.2		43.2		41.1		86.3		556.3
Long-term service agreements (3)		48.6		49.6		34.4		47.1		20.4		202.1		402.2
Capital projects		69.2		5.6		—		—		—		—		74.8
Equity investment commitments (4)		356.0		183.0		—		—		—		—		539.0
Leases and other (5)		18.9		9.9		9.0		8.4		7.3		19.0		72.5
	$	984.7	$	706.2	$	372.5	$	297.4	$	264.0	$	2,687.9	$	5,312.7

(1) Annual requirement to purchase 20 to 100 per cent of electricity production from independent power producers over varying contract lengths up to 25 years.

(2) Purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines.

(3) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(4) Emera has a commitment in connection with the Federal Loan Guarantee (“FLG”) to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction.

(5) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

B. Legal Proceedings

Emera

Between September 16, 2015 and November 2, 2015, purported shareholders of TECO Energy filed 12 separate complaints styled as class action lawsuits in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida or the United States District Court for the Middle District of Florida (the “Merger Litigation”). Each complaint alleges, among other things, that the Board of Directors of TECO Energy breached its fiduciary duties in agreeing to the acquisition agreement and that Emera and/or Emera US Inc. aided and abetted such alleged breaches. The complaints sought to enjoin the merger pursuant to the acquisition agreement.

On November 17, 2015, TECO Energy, Emera, Emera US Inc. and the Board of Directors of TECO Energy entered into a memorandum of understanding with the shareholder plaintiffs to settle all of the Merger Litigation, subject to negotiation of a stipulation of settlement with the plaintiffs and to court approval. The memorandum of understanding provides for all claims against the defendants to be released in exchange for TECO Energy making certain additional disclosures to its shareholders related to the proposed merger, which have now been made.

There is no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.

Emera Maine

On September 30, 2011, a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users filed a complaint with the Federal Energy Regulatory Commission (“FERC”) alleging that the 11.14 per cent base return on equity (“ROE”) under the ISO-New England (“ISO-NE”) Open Access Transmission Tariff (“OATT”) was unjust and unreasonable. On June 19, 2014, the FERC issued an order in connection with this complaint, changing the methodology used to set the ROE for transmission assets.

This change would lower the base transmission ROE to 10.57 per cent for the period of October 1, 2011 to December 31, 2012, subject to a further proceeding to finalize the determination of appropriate rates to be used in such calculation. The FERC decision would also lower the cap on the total ROE (inclusive of incentive adders) for transmission assets to 11.74 per cent. In an order issued on October 16, 2014, the FERC confirmed that the ROE set in its earlier order was appropriate. On March 3, 2015, in response to

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requests for rehearing from several parties, FERC affirmed its initial Order, setting of the base ROE of 10.57 per cent and capping the total ROE, including the effect of incentive adders, at 11.74 per cent. Notices of Appeal to the U.S. Court of Appeals for the DC Circuit were filed by New England Transmission Owners and the Complainants in the case on April 30, 2015. In Q2 2015, Emera Maine began processing refunds to customers, based on a 10.57 per cent ROE. By court order dated August 20, 2015, the DC Court of Appeals decided to hold the appeal of this case in abeyance pending the outcome of the consolidated cases (“ENE Case” and “MA AG II Case”) discussed below.

On December 27, 2012, a second group of consumer advocates, including Environment Northeast, filed a complaint with the FERC on similar grounds, arguing that the 11.14 per cent base ROE under the OATT was unjust and unreasonable (“the ENE Case”). On June 19, 2014, the FERC issued an order in this second ROE case, finding in favour of the complainants and allowing the complaint to proceed. As a result, a new ROE will be calculated and set by the FERC. This complaint created a new 15-month refund period beginning January 1, 2013 through March 31, 2014.

On July 31, 2014, a group of state commissions, state public advocates and end users filed a third complaint with the FERC alleging the ROE earned on transmission investments is unjust and unreasonable and does not reflect current economic conditions (“the MA AG II Case”). Any potential refund arising from this third complaint will relate to the period from July 31, 2014 to September 30, 2015, and the outcome will set the ROE going forward from the date of decision.

On November 24, 2014, the FERC consolidated the ENE Case and MA AG II Case. A subsequent order by the FERC established a schedule for various procedural matters that turned the case over to an Administrative Law Judge in September 2015.

On March 22, 2016, the Administrative Law Judge (“ALJ”) issued a recommended decision to the FERC with respect to the two outstanding ROE complaints (ENE Case and MA AG II Case). Each complaint was for a 15-month period commencing December 27, 2012 and July 31, 2014 respectively. The recommendation for the ENE Case was a 9.59 per cent base ROE, with a 10.42 per cent maximum ROE, and the recommendation for MA AG II Case was a 10.90 per cent base ROE, with a 12.19 per cent maximum ROE.

On April 29, 2016, an additional complaint was filed with FERC challenging the ROE under the ISO-NE transmission tariff. The complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”), a collection of thirteen municipal light departments, seeking to reduce the base transmission ROE to a maximum of 8.93 per cent and the maximum ROE of 11.24 per cent.

Emera Maine has recorded a reserve of $5.8 million pre-tax ($4.5 million USD) (December 31, 2015 – $6.9 million or $5.0 million USD) for the first two base transmission ROE rate refund complaints. The reserves recorded for these complaints have been recorded as a component of Regulatory Liabilities on the Consolidated Balance Sheets, and the charges to earnings have been a reduction to Operating revenues – regulated on the Consolidated Statements of Income. The reserve was calculated on a 10.57 per cent base and represents Emera Maine’s best estimate of the probable outcome. No update has been made to the reserve, as a result of the ALJ recommendation as it is pending approval by the FERC and is considered uncertain until that time. No reserve has been made as a result of the EMCOS complaint, as the outcome is considered uncertain.

Other Legal Proceedings

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

C. Environment

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Emera’s activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste. Emera estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations will be approximately $29.4 million during fiscal 2016 and are estimated to be $55.9 million from 2017 through 2020. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 24A. The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions.

NSPI is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters, primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI.

Conformance with legislative and NSPI internal requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed to March 31, 2016.

Poly Chlorinated Bi-Phenol Transformers

In response to the Canadian Environmental Protection Act 1999, 2008 Poly Chlorinated Bi-Phenol (“PCB”) Regulations to phase out electrical equipment and liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other oil-filled electrical equipment on its system that do not meet the 2008 PCB Regulations Standard by the end of 2025. This also includes PCB contaminated pole mounted transformers. The combined total cost of these projects is estimated to be $40.1 million and, as at March 31, 2016, approximately $21.1 million (December 31, 2015 – $19.7 million) has been spent to date. NSPI has recognized an ARO of $14.9 million as at March 31, 2016 (December 31, 2015 – $15.0 million) associated with the PCB phase-out program.

Emera Energy Emissions

The New England Gas Generating Facilities are subject to the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions and the Acid Rain Program for sulphur dioxide emissions. The New England Gas Generating Facilities emit approximately two million tons of carbon dioxide per year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions programs could adversely impact financial and operational performance.

D. Principal Risks and Uncertainties

In this section, Emera describes some of the principal risks management believes could materially affect Emera’s business, revenues, operating income, net income, net asset or liquidity or capital resources. The nature of risk is such that no list can be comprehensive, and other risks may arise, or risks not currently considered material may become material in the future.

Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach.

Regulatory and Political Risk

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments in a timely manner. As cost-of-service utilities

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with an obligation to serve, NSPI, Emera Maine, BLPC, GBPC and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs and investments can be recovered upon the respective regulator’s approval of the recovery in adjustments to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. In addition, the commercial and regulatory frameworks under which Emera and its subsidiaries operate can be impacted by significant shifts in government policy and changes in governments. Emera has certain investments subject to significant influence that are subject to regulatory risk and include: APUC, M&NP, NSPML, LIL and Lucelec.

During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these subsidiaries and their respective regulators determine whether to allow recovery and to adjust rates based upon the subsidiaries’ evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, fuel-related audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements.

On April 13, 2016, in association with a distribution rate application, the MPUC ordered an audit of Emera Maine’s implementation of its new customer information system and customer service performance, including billing and reliability. The audit is expected to commence in Q2 2016 and conclude in the second half of 2016.

Changes in Environmental Legislation

Emera is subject to regulation by federal, provincial, state, regional and local authorities with regard to environmental matters; primarily related to its utility operations. This includes laws setting greenhouse gas emissions standards and air emissions standards. Emera is also subject to laws regarding the generation, storage, transportation, use and disposal of hazardous substances and materials.

In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera.

New emission reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to greenhouse gas emissions standards and air emissions standards could adversely affect Emera’s operations and financial performance. Stricter environmental laws and enforcement of such laws in the future could increase Emera’s exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments.

Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and with the objective of achieving full compliance with applicable laws, legislation and company policies and standards. Emera has implemented this policy through the development and application of environmental management systems in its operating subsidiaries. Comprehensive audit programs are also in place to regularly test compliance with such laws, policies and standards.

Commercial Relationships

The Company is exposed to commercial relationship risk in respect of its reliance on certain key partners, supplies and customers. The company manages its commercial relationship risk by monitoring credit risk, and monitoring of significant developments with its customers, partners and suppliers.

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ENL

Emera and Nalcor Energy executed agreements pertaining to the development and transmission of hydroelectric power from Muskrat Falls in Labrador to the island of Newfoundland, the Province of Nova Scotia and through to New England. In exchange for the Company’s investment in the Maritime Link Project, estimated to be approximately $1.56 billion, Nalcor has agreed to provide 20 per cent of the output of the Muskrat Falls generating station.

Interest Rate Risk

The Company utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. The Company seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.

For the Company’s regulated subsidiaries, the cost of debt is generally passed through to ratepayers. While regulatory ROE rates will generally and indirectly follow the direction of interest rates, regulatory ROE’s are likely to fall in times of reducing interest rates and raise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development initiatives.

The Company is subject to interest rate risk relating to certain sources of expected funds to effect the pending TECO Energy acquisition. Any movement in interest rates could affect the underlying cost of the instrument used to fund the acquisition. The Company may enter into interest rate hedging contracts to limit its exposure to fluctuations in interest rates.

Commodity Prices and Foreign Exchange Rate Fluctuations

A substantial amount of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. Fuel contracts may be exposed to broader global conditions which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts. In addition, the adoption and implementation of FAMs in certain subsidiaries has further helped manage this risk. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs.

The Company enters into foreign exchange forward and swap contracts to limit exposure on foreign currency transactions such as fuel purchases and USD revenue streams.

The cash consideration for the pending TECO Energy acquisition is required to be paid in US dollars, a portion of which will be raised in Canadian dollars. As a result, increases in the value of the US dollar versus the Canadian dollar will increase the purchase price translated in Canadian dollars and thereby increase the Canadian dollars required to fund the USD purchase price for the acquisition ultimately obtained by the Company.

The proceeds of the first instalment of the Debenture Offering were invested in short-term US dollar investment grade securities.

During October 2015, Emera entered into foreign exchange forward contracts to economically hedge an amount equal to the anticipated proceeds from the second instalment of the Debenture Offering of the pending TECO Energy acquisition of $1.457 billion. These foreign exchange forward contracts are economic hedges and do not qualify for hedge accounting. Therefore, all mark-to-market gains and losses will be recognized in net income for the period. In addition, the operations of TECO Energy are conducted in US dollars. Following the acquisition, the consolidated net income of Emera will be impacted to a greater extent by movements in the US dollar relative to the Canadian dollar.

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E. Guarantees and Letters of Credit

There were no changes in Emera’s standby letters of credit since December 31, 2015.

25. COMMON STOCK

Authorized: Unlimited number of non-par value common shares.

Issued and outstanding:	millions of shares		millions of Canadian dollars
Balance, December 31, 2015		147.21	$	2,157.5
Issuance of common stock (1)		0.06		2.7
Issued for cash under Purchase Plans at market rate		0.58		26.2
Discount on shares purchased under Dividend Reinvestment Plan		—		(1.2	)
Options exercised under senior management share option plan		0.50		13.6
Stock-based compensation		—		0.2
Balance, March 31, 2016		148.35	$	2,199.0

(1) During the three months ended March 31 2016, Emera issued 0.06 million common shares to facilitate the creation and issuance of 0.2 million depositary receipts in connection with the ECI amalgamation transaction. The depositary receipts are listed on the Barbados Stock Exchange.

26. NON-CONTROLLING INTEREST IN SUBSIDIARIES

Non-controlling interest in subsidiaries consisted of the following:

As at millions of Canadian dollars	March 31 2016		December 31 2015
ICDU	$	48.8	$	51.8
Preferred shares of GBPC		33.5		33.5
Domlec (1)		22.5		48.3
Preferred shares of Emera Maine		0.4		0.4
	$	105.2	$	134.0

(1) On March 22, 2016, an indirect wholly-owned subsidiary of Emera acquired 0.7 million ECI shares, increasing Emera’s ownership interest from 95.5 to 100 per cent.

27. VARIABLE INTEREST ENTITIES

The Company performs ongoing analysis to assess whether it holds any VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities.

VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is accounted for using the equity method.

For the three months ended March 31, 2016, the Company has identified the following significant VIEs:

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera was not the primary beneficiary since it does not have the controlling financial interest of NSPML. In Q2 2014, critical milestones were achieved and Nalcor Energy was deemed the beneficiary of the asset for financial reporting purposes, as they have authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link Project. Thus, Emera records the Maritime Link Project as an equity investment.

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ECI has established a Self Insurance Fund (“SIF”) primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF.

The Company has identified certain long-term purchase power agreements that could be defined as variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

Emera’s consolidated VIE in the BLPC SIF is recorded as an “Available-for-sale investment” and “Restricted cash”. The following table provides information about Emera’s portion of significant consolidated and unconsolidated VIEs:

As at millions of Canadian dollars	March 31, 2016				December 31, 2015
	Total assets		Maximum exposure to loss		Total assets		Maximum exposure to loss
Consolidated VIE
BLPC SIF	$	95.9	$	95.9	$	101.4	$	101.4
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)		206.4		917.0		187.6		1,007.0

28. COMPARATIVE INFORMATION

These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income.

29. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through May 9, 2016, the date the financial statements were issued.

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EX-4.5

Exhibit 4.5

Management’s Discussion & Analysis

As at May 9, 2016

Management’s Discussion & Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments (“Emera”) during the first quarter of 2016 relative to 2015; and its financial position as at March 31, 2016 relative to December 31, 2015. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is also presented. Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments.

This discussion and analysis should be read in conjunction with the Emera Incorporated unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2016; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2015. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”).

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to the timing of recognition of certain assets, liabilities, revenues and expenses. Emera’s rate-regulated subsidiaries and investments include:

Emera Rate-Regulated Subsidiary or Investment	Accounting Policies Approved/Examined By
Subsidiary
Nova Scotia Power Inc. (“NSPI”)	Nova Scotia Utility and Review Board (“UARB”)
Emera Maine	Maine Public Utilities Commission (“MPUC”) and the Federal Energy Regulatory Commission (“FERC”)
Barbados Light & Power Company Limited (“BLPC”)	Fair Trading Commission, Barbados
Grand Bahama Power Company Limited (“GBPC”)	The Grand Bahama Port Authority (“GBPA”)
Dominica Electricity Services Ltd. (“Domlec”)	Independent Regulatory Commission, Dominica (“IRC”)
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)	National Energy Board (“NEB”)
Investment
NSP Maritime Link Inc. (“NSPML”)	UARB
Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline LLC (“M&NP”)	NEB and FERC
Labrador Island Link Limited Partnership (“LIL”)	Newfoundland and Labrador Board of Commissioners of Public Utilities
St. Lucia Electricity Services Limited (“Lucelec”)	Government of St. Lucia

All amounts are in Canadian dollars (“CAD”), except for the Emera Maine and Emera Caribbean sections of the MD&A, which are reported in US dollars (“USD”), unless otherwise stated.

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Additional information related to Emera, including the Company’s Annual Information Form, can be found on SEDAR at www.sedar.com.

Forward-Looking Information

This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations regarding future growth, results of operations, performance, business prospects and opportunities and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made pursuant to safe harbor provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “could”, “estimates”, “expects”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “budget”, “forecast”, “might”, “will”, “would”, “targets” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved.

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations are discussed in the Outlook section of the MD&A and may also include: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; capital market and liquidity risk; completion of the TECO Energy, Inc. (“TECO Energy”) acquisition; uncertainty regarding the length of time required to complete the TECO Energy acquisition; future dividend growth; timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology could reduce demand for electricity; weather; commodity price risk; construction and development risk; unanticipated maintenance and other expenditures; derivative financial instruments and hedging availability and inability to complete the Debenture Offering and the financing; failure by the Company to repay the acquisition credit facilities; alternate sources of funding that would be used to replace the acquisition credit facilities may not be available when needed; impact of acquisition related expenses; interest rate risk; credit risk; commercial relationship risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; market energy sales prices; labour relations; and availability of labour and management resources.

Readers are cautioned not to place undue reliance on forward-looking information as actual results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

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Structure of MD&A

This MD&A begins with an Introduction and Strategic Overview; followed by the Consolidated Financial Review and Outstanding Common Stock data; then presents information specific to Emera’s consolidated subsidiaries and investments:

• NSPI;

• Emera Maine;

• Emera Caribbean includes BLPC and Domlec and their parent company, Emera (Caribbean) Incorporated (“ECI”), GBPC, and Lucelec;

• Pipelines includes Brunswick Pipeline and M&NP;

• Emera Energy includes Emera Energy Services (“EES”); Emera Energy Generation (“EEG”) which includes Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities”), Brooklyn Power Corporation (“Brooklyn Energy” or “Brooklyn”) and Bayside Power Limited Partnership (“Bayside Power” or “Bayside”); Bear Swamp Power Company LLC (“Bear Swamp”);

• Corporate and Other includes:

• Interest revenue on intercompany financings and costs associated with corporate activities that are not directly allocated to the operations of Emera’s consolidated subsidiaries and investments;

• Acquisition costs related to the pending acquisition of TECO Energy;

• Emera Utility Services Inc. (“Emera Utility Services”);

• Emera Newfoundland & Labrador Holdings Inc. (“ENL”) and its investments in NSPML and LIL;

• Emera Reinsurance Limited;

• Emera’s investment in Algonquin Power & Utilities Corp. (“APUC”) and;

• Other investments

The Liquidity and Capital Resources, including Consolidated Cash Flow Highlights, Outlook, Transactions with Related Parties, Risk Management and Financial Instruments, Disclosure and Internal Controls, Critical Accounting Estimates, Changes in Accounting Policies and Practices and Summary of Quarterly Results sections of the MD&A are presented on a consolidated basis.

INTRODUCTION AND STRATEGIC OVERVIEW

Emera Incorporated is a geographically diverse energy and services company that invests in electricity generation, transmission and distribution, gas transmission and utility services. Emera provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States, and the Caribbean. Emera is targeting eight-per-cent annual dividend growth through 2019.

Regulated utilities are the foundation of Emera’s business, providing the Company with strong and consistent earnings. At the core of Emera’s utilities strategy is identifying opportunities to invest in the transition from higher-carbon methods of electricity generation to lower-carbon alternatives. NSPI has invested in wind energy, biomass and hydroelectricity and is on track to meet a minimum 40 per cent renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives, with an emphasis on affordability and fuel cost stability for its customers.

Emera is investing in electricity transmission to help deliver new renewable energy to market. Emera’s ownership in the Maritime Link Project will contribute to the transformation of the electricity market in the Atlantic Provinces, enabling growth in the availability of clean, renewable energy for the region. In addition, the Atlantic Provinces will be connected to the northeastern United States, providing potential for excess renewable energy to be delivered throughout that region.

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Since its formation in 2003, Emera Energy has become an active participant in the northeastern United States electricity and natural gas market. It has built a strong marketing, trading and asset management business, based on comprehensive market knowledge, focus on customer service and robust risk management. The integration and performance of the three New England Gas Generating Facilities purchased in 2013 has contributed significantly to the success of Emera Energy.

Energy markets worldwide, in particular across North America, are undergoing foundational changes that have created significant investment opportunities for companies with Emera’s experience and capabilities. Key trends contributing to these investment opportunities include: aging infrastructure, environmental concerns (including demand for new, less carbon-intensive and renewable generation), lower-cost natural gas, growing demand for new electric heating solutions, and the requirement for large-scale transmission projects to deliver new energy sources to customers. Within this context, Emera is focused on growing shareholder value by identifying reliable and affordable energy solutions, typically involving the replacement of higher-carbon electricity generation with generation from cleaner sources, and the related transmission and distribution infrastructure to deliver that energy to market.

Emera has strong partnerships and relationships throughout the regions in which it operates and has established a diverse investment and operations profile that links its assets and capabilities in those regions. At the core of Emera’s strategy is the ability to leverage these particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company.

The foundation of Emera’s strategy is its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. The Company will continue to make investments in its regulated utilities to benefit customers and focus on providing rate stability for customers. From time to time, Emera will make acquisitions, both regulated and unregulated, where the business or asset acquired aligns with Emera’s strategic initiatives and delivers shareholder value.

To ensure stability in adjusted net income and cash flows, Emera employs operating and governance models that focus on safety and operational excellence, constructive regulatory approaches, proactive stakeholder engagement and a customer focus through service reliability and rate stability.

Emera targets achieving 75 to 85 per cent of its adjusted income (a non-GAAP measure described in the section below) from rate-regulated subsidiaries, which generally contribute strong, predictable income and cash flows that fund dividends, reinvestment and which is reflective of the Company’s risk tolerance.

In 2015, approximately 65 per cent of Emera’s adjusted net income was earned by its rate-regulated subsidiaries, which is lower than previous years and the Company’s strategic target. Specifically, the lower percentage of adjusted net income was the result of a substantial increase in Emera Energy’s earnings primarily due to strong performance by the New England Gas Generating Facilities, and a strengthening US dollar. It was not the result of a change in Emera’s risk tolerance, nor is it from additional capital allocations to non-regulated businesses. Rather, it was the result of strong operating and financial performance of existing non-regulated investments and businesses. Following the close of the pending TECO Energy acquisition, the Company is expected to achieve its adjusted net income target.

Emera has grown its asset base to enable growth and deliver on its strategic objectives. Over the last 10 years, Emera’s ability to raise the capital necessary to fund investments has been a strong enabler of the Company’s growth. This was demonstrated in Emera’s recent issue of convertible debentures represented by instalment receipts in relation to the pending TECO Energy acquisition. In addition to access to debt and equity capital markets, cash flow from operations will continue to play a role in financing the Company’s future growth. Maintaining strong, investment grade credit ratings is an important component of Emera’s financing strategy.

The energy industry is seasonal in nature. Seasonal patterns and other weather events, including the number and severity of storms, can affect demand for energy and cost of service. Similarly, mark-to-

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market adjustments that do not qualify for hedge accounting or regulatory accounting can have a material impact on the financial results for a specific period. Results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole.

Non-GAAP Financial Measures

Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the non-GAAP measures by adjusting certain GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period, as detailed below:

Non-GAAP measure	GAAP measure
Adjusted net income attributable to common shareholders or adjusted net income	Net income attributable to common shareholders
Adjusted earnings per common share – basic	Earnings per common share – basic
Adjusted contribution to consolidated net income	Contribution to consolidated net income
Adjusted income before provision for income taxes	Income before provision for income taxes
Adjusted contribution to consolidated earnings per common share – basic	Contribution to consolidated earnings per common share – basic
EBITDA	Net income
Adjusted EBITDA	Net income
Electric margin	Income from operations

Adjusted Net Income

Emera calculates an adjusted net income measure by excluding the effect of:

• the mark-to-market adjustments related to Emera’s held-for-trading (“HFT”) derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered;

• the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp;

• the amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading transactions;

• the mark-to-market adjustments related to an interest rate swap in Brunswick Pipeline; and

• the mark-to-market adjustments included in Emera’s other income related to the effect of pending TECO Energy acquisition related USD-denominated currency and forward contracts. These contracts were put in place to economically hedge the anticipated proceeds from the 2015 sale of $2.1 billion four per cent convertible unsecured subordinated debentures represented by instalment receipts (“the Debenture Offering” or “Debentures” or “Convertible Debentures”) for the pending TECO Energy acquisition.

Management believes excluding from income the effect of these mark-to-market valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows and the ongoing operations of the business, and allows investors to better understand and evaluate the business. Management and the Board of Directors use this non-GAAP measure for evaluation of performance and incentive compensation.

Mark-to-market adjustments are further discussed in the Consolidated Financial Highlights section, Emera Energy – Review of 2016, Pipelines – Review of 2016 and Corporate and Other – Review of 2016.

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The following is a reconciliation of reported net income attributable to common shareholders to adjusted net income attributable to common shareholders, and reported earnings per common share – basic to adjusted earnings per common share – basic:

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2016			2015
Net income attributable to common shareholders	$	44.3		$	160.1
After-tax mark-to-market gain (loss)	$	(75.9	)	$	(11.5	)
Adjusted net income attributable to common shareholders	$	120.2		$	171.6
Earnings per common share – basic	$	0.30		$	1.10
Adjusted earnings per common share – basic	$	0.81		$	1.18

EBITDA and Adjusted EBITDA

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is a non-GAAP financial measure used by Emera. EBITDA is used by numerous investors and lenders to better understand cash flows and credit quality. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, make capital expenditures and finance working capital requirements.

Adjusted EBITDA is a non-GAAP financial measure used by Emera. Similar to adjusted net income calculations, this measure represents EBITDA absent the income effect of Emera’s mark-to-market adjustments, as previously discussed.

The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies, but in management’s view appropriately reflects Emera’s specific financial condition. These measures are not intended to replace “Net income attributable to common shareholders” which, as determined in accordance with GAAP, is an indicator of operating performance. EBITDA and Adjusted EBITDA are discussed further in the Consolidated Financial Review, NSPI, Emera Maine, Emera Caribbean, Pipelines, Emera Energy, and Corporate and Other sections.

EBITDA and Adjusted EBITDA Reconciliation

For the	Three months ended
millions of Canadian dollars	March 31
	2016			2015
Net income	$	54.8		$	174.1
Interest expense, net		75.2			44.4
Income tax expense (recovery)		26.8			61.4
Depreciation and amortization		87.5			82.8
EBITDA		244.3			362.7
Mark-to-market gain (loss), excluding income tax and interest		(75.1	)		(21.5	)
Adjusted EBITDA	$	319.4		$	384.2

Electric Margin

“Electric margin” is a non-GAAP financial measure used to show the amounts that NSPI, BLPC, GBPC and Domlec retain to recover non-fuel costs. Prudently incurred fuel costs are recovered from customers, except in Domlec, where substantially all fuel costs are passed to customers through the fuel pass-through mechanism. Management believes measuring electric margin shows the portion of these utilities’ revenues that directly contribute to Emera’s income as distinguished from the portion of revenues that are managed through fuel adjustment mechanisms, which have a minimal impact on income.

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Emera Energy also reports “Electric margin” because the sales price of electricity and the cost of natural gas used to generate it are highly correlated. However, their absolute values can vary materially over time. Emera Energy believes that “Electric margin”, as the net result, provides a meaningful measure of business performance in addition to the absolute values of sales and fuel expenses, which are also reported.

Electric margin, as calculated by Emera, may not be comparable to the electric margin measures of other companies, but in management’s view appropriately reflects Emera’s specific condition. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance. Electric margin is discussed further in the NSPI – Electric Margin, the Emera Caribbean – Electric Margin and the Emera Energy – Adjusted EBITDA sections.

Significant Items Affecting Earnings

2016

After-Tax Mark-to-Market Losses

After-tax mark-to-market losses increased $64.4 million to $75.9 million in Q1 2016 compared to $11.5 million in Q1 2015 primarily due to reversal of the 2015 gain on USD-denominated currency and forward contracts related to the financing of the pending TECO Energy acquisition and the amortization of 2015 Emera Energy gas transportation assets. This increase was partially offset by the reversal of 2015 mark-to-market losses and changes in gas and power contract positions at Emera Energy.

Acquisition Related Costs

Emera incurred after-tax costs of $17.5 million ($0.12 per common share) in Q1 2016 (2015 – nil) related to its pending acquisition of TECO Energy, including legal, advisory, and financing costs.

As discussed and included above in “After-Tax Mark-to-Market Losses”, the foreign currency earnings effect related to the Debenture Offering USD cash balance and the forward contracts were recorded as a mark-to-market after-tax loss of $121.1 million in “Other income (expenses), net” in Q1 2016 (2015 – nil).

2015

Sale of Northeast Wind Partnership II, LLC (“NWP”) Equity Investment

On January 29, 2015, Emera completed the sale of its 49-per-cent interest in NWP for $282.3 million ($223.3 million USD). This sale resulted in a pre-tax gain of $18.6 million or $0.13 per common share (after-tax gain of $11.5 million or $0.08 per common share), which was recorded in “Other income (expenses), net” in Q1 2015.

CONSOLIDATED FINANCIAL REVIEW

In Q1 2016, Emera affiliates in the northeastern United States and Atlantic Canada experienced less demand for electricity as a result of unseasonably warm weather. Specifically, NSPI, Emera Maine and Emera Energy’s New England Gas Generating Facilities results were affected. Below is a table highlighting significant changes between adjusted net income from 2015 to 2016.

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For the	Three months ended
millions of Canadian dollars	March 31
Adjusted net income – 2015	$	171.6
Emera Energy (largely due to New England Gas Generation Facilities) (1)		(17.0	)
Acquisition and financing costs relating to the pending acquisition of TECO Energy (1)		(17.5	)
NSPI		(15.5	)
2015 gain on the sale of NWP		(11.5	)
Increased equity earnings from NSPML and LIL		3.8
Other (1)		6.3
Adjusted net income – 2016	$	120.2

(1) These numbers include the impact of the stronger USD.

Consolidated Financial Highlights

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2016			2015
Operating revenues	$	877.0		$	888.5
Income from operations		270.0			232.1
Net income attributable to common shareholders		44.3			160.1
After-tax mark-to-market gain (loss)		(75.9	)		(11.5	)
Adjusted net income attributable to common shareholders		120.2			171.6
Earnings per common share – basic	$	0.30		$	1.10
Earnings per common share – diluted	$	0.30		$	1.09
Adjusted earnings per common share – basic	$	0.81		$	1.18
Dividends per common share declared	$	0.4750		$	0.3875
Adjusted EBITDA	$	319.4		$	384.2
For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2016			2015
Operating Unit Contributions to Adjusted Net Income
NSPI	$	52.5		$	68.0
Emera Maine		9.3			11.5
Emera Caribbean		9.8			8.8
Pipelines		9.7			9.9
Emera Energy		47.9			76.4
Corporate and Other		(9.0	)		(3.0	)
Adjusted net income attributable to common shareholders	$	120.2		$	171.6
After-tax mark-to-market gain (loss)		(75.9	)		(11.5	)
Net income attributable to common shareholders	$	44.3		$	160.1
For the	Three months ended March 31
millions of Canadian dollars	2016			2015
Operating cash flow before changes in working capital	$	232.4		$	257.5
Change in working capital		(51.8	)		(137.9	)
Operating cash flow	$	180.6		$	119.6
Investing cash flow	$	(139.3	)	$	195.9
Financing cash flow	$	(45.8	)	$	(259.3	)
As at	March 31			December 31
millions of Canadian dollars	2016			2015
Working capital	$	580.3		$	599.2
Total assets	$	11,448.6		$	11,950.0

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Q1 Consolidated Income Statement and Operating Cash Flow Highlights

Operational Results

Income from operations increased $37.9 million to $270.0 million in Q1 2016 compared to $232.1 million in Q1 2015 primarily due to mark-to-market increases of $91.7 million, the impact of a stronger USD and increased marketing and trading margin at Emera Energy. This was partially offset by decreased margin at the New England Gas Generating Facilities and decreased income from operations at NSPI.

Details of the operating revenues and operating expenses line item variances are described below:

Total operating revenues decreased 1.3 per cent to $877.0 million in Q1 2016 compared to $888.5 million in Q1 2015 primarily due to:

• mark-to-market changes increased operating revenues by $95.9 million.

• a $60.1 million decrease at the New England Gas Generating Facilities reflecting lower hedged and market commodity prices and decreased sales volumes due to weather;

• a $49.0 million decrease in NSPI revenues as a result of lower sales volumes due to weather;

• a $10.5 million decrease at Bayside primarily due to lower power prices;

• a $10.4 million increase at Emera Maine primarily due to the impact of a stronger USD;

• an $8.1 million increase in marketing and trading margin at Emera Energy primarily due to the impact of a stronger USD and growth in the volume of business.

Total operating expenses decreased 7.5 per cent to $607.0 million in Q1 2016 compared to $656.4 million in Q1 2015. This was primarily the result of decreased fuel costs at NSPI and New England Gas Generating Facilities reflecting lower commodity prices and decreased sales volumes due to weather, partially offset by higher operating, maintenance and general expenses (“OM&G”) at NSPI reflecting increased storm costs, and the impact of a stronger USD.

Other income (expenses), net

Other income decreased $161.1 million to $(139.2) million in Q1 2016 compared to $21.9 million in Q1 2015. This was primarily due to mark-to-market losses relating to the effect of USD-denominated currency and forward contracts put into place to economically hedge anticipated proceeds from the Debenture Offering financing and the 2015 gain on the sale of NWP.

Interest expense, net

Interest expense increased $30.8 million to $75.2 million in Q1 2016 compared to $44.4 million in Q1 2015 primarily due to interest on convertible debentures represented by instalment receipts related to the pending acquisition of TECO Energy.

Income tax expense (recovery)

Income tax expense decreased $34.6 million to $26.8 million in Q1 2016 compared to $61.4 million in Q1 2015. This was primarily due to decreased income before provision for income taxes including mark-to-market adjustments, partially offset by the non-deductible portion of TECO Energy related mark-to-market losses on USD-denominated currency and forward contracts related to the pending acquisition.

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Operating Activities

Net cash provided by operating activities increased $61.0 million to $180.6 million in Q1 2016 compared to $119.6 million in Q1 2015. Cash from operations before changes in working capital decreased by $25.1 million primarily due to decreased margin at the New England Gas Generating Facilities and the payment of financing costs related to the pending acquisition of TECO Energy.

Changes in working capital increased operating cash flows by $86.1 million primarily due to favourable changes in accounts receivable reflecting lower sales volumes at NSPI and favourable changes in inventory reflecting the purchase of emission credits by the New England Gas Generating Facilities in 2015.

Effect of Foreign Currency Translation

Emera’s foreign currency-denominated results are affected by exchange rate fluctuations. Revenue, operating expense, net income, and adjusted net income are translated at the weighted average rate of exchange. The amounts in the table below are calculated by multiplying the current period foreign denominated results by the change in the weighted average foreign exchange from the prior period. The table below shows the estimated effect of foreign currency translation on key income statement items:

millions of Canadian dollars (except per share amounts)	Q1 2016 vs Q1 2015			Q1 2015 vs Q1 2014
Impact on income from continuing operations
Total operating revenues	$	48.5		$	43.3
Total operating expenses		(25.7	)		(32.5	)
Net income		15.8			9.2
Adjusted net income		7.2			11.0
Impact on earnings per share
Basic	$	0.11		$	0.06
Basic -adjusted	$	0.05		$	0.08

Emera’s weighted average exchange rates are shown in the following table:

	Three months ended March 31
Average equivalent of $1.00 USD	2016		2015		2014
CAD		1.38		1.24		1.10

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Consolidated Balance Sheets Highlights

Significant changes in the consolidated balance sheets between December 31, 2015 and March 31, 2016 include:

	Increase
millions of Canadian dollars	(Decrease)			Explanation
Assets
Cash and cash equivalents	$	(73.9	)	Decreased primarily due to the impact of a stronger CAD
Receivables, net		32.9		Increased due to seasonal trends of business at NSPI and Emera Energy
Inventory		(53.5	)	Decreased primarily due to lower fuel inventory volumes as a result of consumption and lower commodity pricing at NSPI
Derivative instruments (current and long-term)		(239.3	)	Decreased primarily due to the effect of a stronger CAD and settlements of derivative instruments at Emera Energy and NSPI
Prepaid expenses		22.1		Increased primarily due to timing of provincial grants in lieu of taxes and insurance payments at NSPI
Property, plant and equipment, net of accumulated depreciation		(173.1	)	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries and depreciation, offset by additions
Investments subject to significant influence		64.4		Increased primarily due to increased investments in LIL and NSPML
Other assets (current and long-term)		(70.2	)	Decreased primarily due to the amortization of transportation/storage capacity assets at Emera Energy
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		(27.5	)	Decreased primarily due to the effect of a stronger CAD on debt held by foreign subsidiaries
Accounts payable		(22.7	)	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries
Derivative instruments (current and long-term)		(218.2	)	Decreased primarily due to settlements of natural gas and power contracts at Emera Energy
Regulatory liabilities (current and long-term)		(74.4	)	Decreased primarily due to changes in regulated derivatives, partially offset by an increased FAM regulatory liability at NSPI
Other liabilities (current and long-term)		(47.8	)	Decreased primarily due to the effect of a stronger CAD on the Bear Swamp investment, payment of restructuring costs at Emera Caribbean and timing of accruals
Common stock		41.5		Increased primarily due to issuance of common stock for the dividend reinvestment program
Accumulated other comprehensive income		(130.7	)	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries
Retained earnings		(25.7	)	Decreased due to dividends payments in excess of net income
Non-controlling interest in subsidiaries		(28.8	)	Decreased due to increased ownership by Emera in ECI

Developments

Emera

Pending Acquisition of TECO Energy

On September 4, 2015, the Company announced a definitive agreement (“the acquisition agreement”) for Emera to acquire TECO Energy (NYSE:TE) (“the Transaction”). TECO Energy shareholders will receive $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.4 billion USD and includes the assumption of approximately $3.9 billion USD of debt.

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TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include: Tampa Electric, an integrated regulated electric utility which serves nearly 725,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution utility which serves nearly 365,000 customers across Florida; and New Mexico Gas Co., a regulated gas distribution utility which serves more than 515,000 customers across New Mexico.

The Transaction is expected to close mid-2016. Closing of the pending acquisition remains subject to approval by the New Mexico Public Regulation Commission (“NMPRC”), and the satisfaction of customary closing conditions.

On April 11, 2016, Emera and TECO Energy filed an unopposed Stipulation Agreement reflecting a settlement reached with intervening parties in the acquisition case pending before the NMPRC for approval of Emera’s proposed acquisition of TECO Energy and the indirect acquisition of New Mexico Gas Co.

The Stipulation Agreement sets out a number of Emera’s commitments including honouring commitments made by TECO Energy in its 2014 acquisition case, investing in the expansion of the natural gas system to underserved communities and the Mexican border, and providing resources to support certain economic growth projects and programs. The Stipulation Agreement is subject to review and approval by the NMPRC. The hearing for Emera’s pending acquisition of TECO Energy occurred on May 2, 2016. A decision is expected mid-2016.

On March 23, 2016, The Committee on Foreign Investment in the United States approval was received.

ECI Amalgamation

On February 24, 2016, the common shareholders of ECI approved an amalgamation transaction, which resulted in an Emera wholly owned subsidiary owning all common shares of ECI. Prior to this, Emera held 95.5 per cent of ECI’s common shares.

To effect the amalgamation, all issued and outstanding common shares of ECI were converted to Class A redeemable preferred shares. In Q1 2016, the Class A redeemable preferred shares of ECI not owned were redeemed. Minority ECI shareholders could elect to receive $23.26 ($33.30 Barbadian dollars (“BBD”)) in cash per common share (“Cash Offer”) or 2.1 Depositary Receipts (“DR”) per common share, with each DR representing one quarter of a common share of Emera (“DR Offer”); or a combination of the two offers. The total consideration paid to redeem the minority interest was $15.3 million ($23.4 million BBD), consisting of $14.4 million of the Cash Offer ($22.0 million BBD) and $0.9 million of the DR Offer ($1.4 million BBD). The amalgamated entity retained the name Emera (Caribbean) Incorporated.

Recent Financing Activity

NSPI

On April 28, 2016, NSPI increased its committed syndicated revolving bank line of credit to $600 million from $500 million. The increase will support ongoing business requirements and general corporate purposes.

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OUTSTANDING COMMON STOCK DATA

Common stock	millions of		millions of Canadian
Issued and outstanding:	shares		dollars
December 31, 2014		143.78	$	2,016.4
Issuance of common stock (1)		1.25		53.7
Issued for cash under Purchase Plans at market rate		2.10		88.3
Discount on shares purchased under Dividend Reinvestment Plan		—		(4.1	)
Options exercised under senior management stock option plan		0.08		2.3
Employee Share Purchase Plan		—		0.9
December 31, 2015		147.21	$	2,157.5
Issuance of common stock (1)		0.06		2.7
Issued for cash under Purchase Plans at market rate		0.58		26.2
Discount on shares purchased under Dividend Reinvestment Plan		—		(1.2	)
Options exercised under senior management stock option plan		0.50		13.6
Employee Share Purchase Plan		—		0.2
March 31, 2016		148.35	$	2,199.0

1) During the three months ended March 31 2016, Emera issued 0.06 million (2015 - 1.25 million) common shares to facilitate the creation and issuance of an additional 0.2 million (2015 - 5 million) depositary receipts in connection with the ECI amalgamation transaction. The depositary receipts are listed on the Barbados Stock Exchange.

As at April 25, 2016, the amount of issued and outstanding common shares was 148.4 million.

The weighted average shares of common stock outstanding – basic, which includes both issued, outstanding common stock and outstanding deferred share units, for the three months ended March 31, 2016 was 148.7 million (2015 – 144.9 million).

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NSPI

Overview

NSPI is a fully-integrated regulated electric utility with assets of approximately $4.6 billion. It is the primary electricity supplier in Nova Scotia providing electricity generation, transmission and distribution services to approximately 507,000 customers. NSPI’s target regulated return on equity (“ROE”) range is currently 8.75 per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40.0 per cent.

Review of 2016

NSPI Net Income

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2016		2015
Operating revenues – regulated	$	397.5	$	446.5
Regulated fuel for generation and purchased power (1)		141.5		189.4
Regulated fuel adjustment mechanism and fixed cost deferrals		17.6		(7.2	)
Operating, maintenance and general		87.4		79.6
Provincial grants and taxes		9.7		9.6
Depreciation and amortization		48.4		51.5
Total operating expenses		304.6		322.9
Income from operations		92.9		123.6
Other expenses, net		1.3		3.8
Interest expense, net		31.0		28.8
Income before provision for income taxes		60.6		91.0
Income tax expense (recovery)		8.1		21.0
Net income of Nova Scotia Power Inc.		52.5		70.0
Preferred stock dividends		—		2.0
Contribution to consolidated net income	$	52.5	$	68.0
Contribution to consolidated earnings per common share	$	0.35	$	0.47
EBITDA	$	140.0	$	171.3

(1) Regulated fuel for generation and purchased power includes affiliate transactions and proceeds from the sale of natural gas.

In Q1 2016, NSPI’s contribution to consolidated net income decreased $15.5 million to $52.5 million compared to $68.0 million in Q1 2015.

Highlights of the net income changes are summarized in the following table:

For the	Three months ended
millions of Canadian dollars	March 31
Contribution to consolidated net income – 2015	$	68.0
Decreased electric margin (see Electric Margin section below for explanation)		(19.5	)
Increased operating, maintenance and general (“OM&G”) expenses primarily due to higher maintenance and storm costs, partially offset by decreased demand side management (“DSM”) program costs		(7.8	)
Decreased fixed cost deferrals primarily due to 2015 DSM regulatory deferral, partially offset by a reduction in the amount of non-fuel revenues deferred		(5.6	)
Decreased income taxes primarily due to decreased income before provision for income taxes		12.9
Decreased depreciation and amortization primarily due to a lower regulatory amortization as a result of a fixed cost deferral from 2012 being fully amortized in 2015		3.1
Other, net (1)		1.4
Contribution to consolidated net income – 2016	$	52.5

(1) Amounts exclude variances included in the calculation of electric margin.

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Operating Revenues – Regulated

NSPI’s Operating Revenues – regulated include sales of electricity and other services as summarized in the following table:

For the	Three months ended March 31
millions of Canadian dollars	2016		2015
Electric revenues	$	391.7	$	440.0
Other revenues		5.8		6.5
Operating revenues – regulated	$	397.5	$	446.5

Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population, weather, and DSM activities. Residential and commercial electricity sales are seasonal, with Q1 being the strongest period, reflecting colder weather and fewer daylight hours in the winter.

NSPI’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other electric revenues consist primarily of sales to municipal electric utilities and revenues from street lighting.

Electric sales volumes are summarized in the following tables by customer class:

Q1 Electric Sales Volumes Gigawatt hours (“GWh”)
	2016		2015		2014
Residential		1,431		1,589		1,568
Commercial		840		919		883
Industrial		578		602		601
Other		79		111		90
Total		2,928		3,221		3,142

Electric revenues are summarized in the following tables by customer class:

Q1 Electric Revenues
millions of Canadian dollars
	2016		2015		2014
Residential	$	223.4	$	248.2	$	232.8
Commercial		109.2		119.4		109.1
Industrial		48.1		57.9		55.8
Other		11.0		14.5		13.3
Total	$	391.7	$	440.0	$	411.0

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Electric revenues decreased $48.3 million to $391.7 million in Q1 2016 compared to $440.0 million in Q1 2015. Highlights of the changes are summarized in the following table:

For the	Three months ended
millions of Canadian dollars	March 31
Electric revenues – 2015	$	440.0
Decreased fuel related electricity pricing effective January 1, 2016		(3.8	)
Decreased commercial and residential sales volume due to weather		(31.5	)
Decreased industrial sales volume		(9.6	)
Other		(3.4	)
Electric revenues – 2016	$	391.7

Regulated Fuel for Generation and Purchased Power

Q1 Production Volumes
GWh
	2016		2015		2014
Coal and petroleum coke (“petcoke”)		1,688		2,248		2,273
Natural gas		285		164		179
Oil		141		249		135
Purchased power – other		95		87		47
Total non-renewables		2,209		2,748		2,634
Wind and hydro – renewables		406		384		416
Purchased power – renewables, including IPP and COMFIT		469		317		254
Biomass – renewables		70		52		53
Total renewables		945		753		723
Total production volumes		3,154		3,501		3,357
Q1 Average Fuel Costs
	2016		2015		2014
Dollars per megawatt hour (“MWh”) produced	$	45	$	54	$	51

Average unit fuel costs decreased in Q1 2016 compared to Q1 2015 primarily due to decreased commodity pricing and decreased load, requiring less generation to be sourced from higher cost alternatives.

NSPI’s Fuel Costs are affected by commodity prices and generation mix which is largely dependent on economic dispatch of the generating fleet, bringing the lowest cost options on stream first (after renewable energy from independent power producers (“IPP”), including Community Feed-In Tariff (“COMFIT”) participants), such that the incremental cost of production generally increases as sales volumes increase. Generation mix may also be affected by plant outages, availability of renewable generation, plant performance and compliance with environmental standards and regulations.

Historically, coal and petcoke have the lowest per unit fuel cost, after NSPI-owned regulated hydro and wind, which have no fuel cost component. Purchased power, natural gas, oil and biomass have the next lowest fuel cost, depending on the relative pricing of each.

The generation mix is transforming with the addition of new non-dispatchable renewable energy sources such as wind, including IPP and COMFIT, which typically has a higher cost per MWh.

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Regulated fuel for generation and purchased power decreased $47.9 million to $141.5 million in Q1 2016 compared to $189.4 million in Q1 2015. Highlights of the changes are summarized in the following table:

For the	Three months ended
millions of Canadian dollars	March 31
Regulated fuel for generation and purchased power – 2015	$	189.4
Change in generation mix		11.2
Decreased commodity prices		(38.2	)
Decreased sales volumes		(18.3	)
Other		(2.6	)
Regulated fuel for generation and purchased power – 2016	$	141.5

Regulated Fuel Adjustment Mechanism (“FAM”) and Fixed Cost Deferrals

Regulated Fuel Adjustment Mechanism and FAM Regulatory Deferral

NSPI has a Fuel Adjustment Mechanism which enables it to seek recovery of Fuel Costs through regularly scheduled rate adjustments. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates in a given year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

The FAM is subject to an incentive, with NSPI retaining or absorbing 10 per cent of the over or under-recovered to a maximum of $5 million. The incentive was suspended for 2012 to 2015, as a result of UARB approved settlement agreements and is in effect for 2016.

In December 2015, the UARB approved NSPI’s 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as submitted in NSPI’s filings. Approved customer rates reset the base cost of fuel rate for 2016 and seek to recover $13.7 million of prior years’ unrecovered Fuel Costs in 2016. Recovery of these costs began January 1, 2016.

On December 18, 2015, the Electricity Plan Implementation (2015) Act (the “Electricity Plan Act”) was enacted by the Province of Nova Scotia. In accordance with the Electricity Plan Act, NSPI filed with the UARB, on March 7, 2016, a three-year rate plan for Fuel Costs, requesting an average increase of 1.3 per cent for 2017 through 2019. A hearing is scheduled for June 13, 2016. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates during this period will be deferred to a FAM regulatory asset or liability and recovered from or returned to customers subsequent to 2019.

The Electricity Plan Act further directed NSPI to apply any non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of tax benefits for the South Canoe and Sable Wind Projects is to be reserved and applied to the FAM to be used in the 2017 to 2019 period. The exception to this direction is application of a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would otherwise have been required. This amount totals $4.6 million. Therefore, as at December 31, 2015, NSPI had deferred $4.6 million of excess non-fuel revenues to 2016 and $40.1 million of excess non-fuel revenues for the periods 2017 to 2019.

In Q1 2016, NSPI applied $3.8 million of non-fuel revenues to the FAM for periods 2017 to 2019. This was as a result of applying the tax benefits associated with the South Canoe and Sable Wind Projects, as directed by the Electricity Plan Act.

Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. The audit for fiscal 2014 and 2015 is currently underway.

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The FAM included in the Statements of Income includes the effect of Fuel Costs in both the current and preceding years, specifically, and as detailed in the table below:

• The difference between actual Fuel Costs and amounts recovered from customers in the current year. This amount, net of the incentive component, is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities” on the Balance Sheets; and

• The recovery from (rebate to) customers of under (over) recovered Fuel Costs from prior years.

The FAM regulatory asset (liability) includes amounts recognized as a regulated fuel adjustment mechanism and associated interest that is included in “Interest expense, net” on the Consolidated Statements of Income. Details of the FAM regulatory asset (liability), classified in “Regulatory assets” or “Regulatory liabilities” on the Consolidated Balance Sheets, are summarized in the following table:

millions of Canadian dollars	2016
FAM regulatory liability – Balance as at January 1	$	(28.3	)
Under (over) recovery of current period Fuel Costs		(10.0	)
Rebate to (recovery from) customers of prior years’ Fuel Costs		(3.8	)
Interest on FAM balance		(0.7	)
Application of non-fuel revenues		(3.8	)
FAM regulatory liability – Balance as at March 31	$	(46.6	)

Electric Margin

NSPI distinguishes electric revenues related to the recovery of Fuel Costs (“fuel electric revenues”) from revenues related to the recovery of non-fuel costs (“non-fuel electric revenues”) because the FAM effectively seeks to recover all prudently incurred fuel costs, and consequently, Fuel Costs and related revenues (Fuel Electric Revenues) do not have a material effect on NSPI’s electric margin or net income, with the exception of the incentive component of the FAM, whereby NSPI retains or absorbs 10 per cent of the over or under recovered amount to a maximum of $5 million.

Electric margin is influenced primarily by revenues relating to non-fuel costs. NSPI’s customer classes contribute differently to NSPI’s non-fuel electric revenues, with residential and commercial customers contributing more than industrial customers under current rates. Accordingly, changes in residential and commercial load, largely due to the effects of weather, from general economic conditions and from DSM have the largest effect on non-fuel electric revenues and electric margin. Changes in industrial load, which are generally due to economic conditions, have less of an effect on non-fuel electric revenues than would a similar volume change in residential and commercial load.

The addition of new generation sources to meet legislated greenhouse gas emission reductions and renewable generation requirements is among the drivers increasing NSPI’s fixed costs. Electric margin, which represents revenues available to cover these costs, has increased in a corresponding manner.

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Operating revenues are summarized in the following table:

For the	Three months ended March 31
millions of Canadian dollars	2016		2015
Fuel electric revenues – current year	$	152.0	$	165.7
Fuel electric revenues – recovery of preceding years		3.8		18.2
Non-fuel electric revenues		235.9		256.1
Other revenues		5.8		6.5
Operating revenues	$	397.5	$	446.5

Electric margin is summarized in the following table:

Fuel electric revenues – current year	$	152.0		$	165.7
Fuel electric revenues – recovery of preceding years		3.8			18.2
Total fuel electric revenues		155.8			183.9
Regulated fuel for generation and purchased power		(141.5	)		(189.4	)
Regulated fuel adjustment mechanism		(13.8	)		5.4
Fuel-related foreign exchange gain (loss) (1)		0.2			0.1
Net fuel revenue (expense) (2)		0.7			—
Non-fuel electric revenues		235.9			256.1
Electric margin	$	236.6		$	256.1

(1) As reported in “Other expenses, net” on the Consolidated Statements of Income.

(2) Net fuel revenue is a result of the FAM incentive.

NSPI’s electric margin decreased $19.5 million to $236.6 million in Q1 2016 compared to $256.1 million in Q1 2015 due to decreased non-fuel electric revenues primarily due to decreased residential and commercial sales reflecting decreased load, primarily due to weather.

Q1 Average Electric Margin/MWh
	2016		2015		2014
Dollars per MWh sold	$	81	$	80	$	80

NSPI’s electric margin per MWh is consistent period over period.

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Non-GAAP Measure

Electric Margin Reconciliation

“Electric margin” is a non-GAAP financial measure used to show the amounts that NSPI retains to recover its non-fuel costs, as effectively all prudently incurred Fuel Costs are recovered through the FAM. NSPI’s electric margin may not be comparable to other companies’ electric margin measures, but in management’s view appropriately reflects NSPI’s regulatory framework. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance. Electric margin was discussed in the Financial Review Electric Margin section above.

For the	Three months ended
millions of Canadian dollars	March 31
	2016		2015
Income from operations	$	92.9	$	123.6
Less:
Fuel electric revenue		155.8		183.9
Other revenue		5.8		6.5
Add back:
Regulated fuel for generation and purchased power		141.5		189.4
Operating, maintenance and general		87.4		79.6
Provincial grants and taxes		9.7		9.6
Depreciation and amortization		48.4		51.5
Regulated fuel adjustment mechanism and fixed cost deferrals		17.6		(7.2	)
Other fuel related costs		0.7		—
Electric margin	$	236.6	$	256.1

EMERA MAINE

Overview

Emera Maine is a transmission and distribution electric utility with assets of approximately $1.1 billion, serving 158,000 customers in the State of Maine in the United States.

Emera Maine’s electric revenue is comprised of distribution operations, local and regional transmission operations and stranded cost recoveries. The rates for each element are established in distinct regulatory proceedings.

• Emera Maine’s distribution rates are set on a 9.55 per cent ROE, with a common equity component of 49 per cent.

• For local transmission operations, the rate for the Bangor Hydro District is set on a 10.57 per cent ROE. For the Maine Public Service District, the rate is set on a 10.2 per cent ROE effective June 1 for wholesale and July 1 for retail customers. The Bangor Hydro District’s bulk transmission assets are managed by ISO-New England as part of a region-wide pool of assets and have a ROE range of 11.07 per cent to 11.74 per cent. The common equity component is based upon the average balances in the prior calendar year.

• For stranded cost recoveries, the rate for the Bangor Hydro District is set on a 5.9 per cent ROE, with a common equity component of 48 per cent and for the Maine Public Service District it is set on 6.75 per cent ROE with a common equity component of 48 per cent.

Emera Maine operates under a traditional cost-of-service regulatory structure. All amounts are reported in USD, unless otherwise stated.

20

Review of 2016

Emera Maine Net Income

For the	Three months ended March 31
millions of US dollars (except per share amounts)	2016		2015
Operating revenues – regulated	$	57.7	$	55.8
Operating revenues – non-regulated		0.2		—
Total operating revenues		57.9		55.8
Regulated fuel for generation and purchased power		7.8		7.7
Transmission pool expense (1)		6.3		6.1
Operating, maintenance and general		15.9		13.2
Provincial, state and municipal taxes		3.6		3.5
Depreciation and amortization		10.7		8.8
Total operating expenses		44.3		39.3
Income from operations		13.6		16.5
Other income (expenses), net		0.2		1.1
Interest expense, net		3.6		3.4
Income before provision for income taxes		10.2		14.2
Income tax expense (recovery)		3.4		4.9
Contribution to consolidated net income – USD	$	6.8	$	9.3
Contribution to consolidated net income – CAD	$	9.3	$	11.5
Contribution to consolidated earnings per common share – CAD	$	0.06	$	0.08
Net income weighted average foreign exchange rate – CAD/USD	$	1.37	$	1.24
EBITDA – USD	$	24.5	$	26.4
EBITDA – CAD	$	33.5	$	32.8

(1) Transmission pool expense is included in “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income.

Emera Maine’s USD contribution to consolidated net income in Q1 2016 decreased by $2.5 million to $6.8 million compared to $9.3 million in Q1 2015. Highlights of the USD net income changes are summarized in the following table:

For the	Three months ended
millions of US dollars	March 31
Contribution to consolidated net income – 2015	$	9.3
Increased operating revenues – (see Operating Revenues – Regulated Section below)		1.9
Increased OM&G primarily due to decreased capitalized construction overheads as a result of lower capital spending and storm costs		(2.7	)
Increased depreciation and amortization primarily due to higher plant in service		(1.9	)
Other		0.2
Contribution to consolidated net income – 2016	$	6.8

Emera Maine’s CAD contribution to consolidated net income decreased in Q1 2016 by $2.2 million to $9.3 million from $11.5 million in Q1 2015. The impact of a stronger USD, quarter-over-quarter, increased CAD earnings by $0.9 million for the three months ended March 31, 2016.

21

Operating Revenues – Regulated

Emera Maine’s operating revenues – regulated include sales of electricity and other services as summarized in the following table:

For the	Three months ended March 31
millions of US dollars	2016		2015
Electric revenues	$	41.7	$	40.0
Transmission pool revenues		11.6		12.2
Resale of purchased power		4.4		3.6
Operating revenues – regulated	$	57.7	$	55.8

Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population and weather.

Q1 Electric Sales Volumes
GWh	2016		2015		2014
Residential		218		235		232
Commercial		198		207		206
Industrial		81		101		105
Other		4		3		4
Total		501		546		547

Electric revenues are summarized in the following tables by customer class:

Q1 Electric Revenues millions of US dollars
	2016		2015		2014
Residential	$	20.7	$	21.6	$	20.7
Commercial		14.8		14.3		14.9
Industrial		3.2		3.3		4.1
Other (1)		3.0		0.8		2.7
Total	$	41.7	$	40.0	$	42.4

(1) Other revenue includes amounts recognized relating to FERC transmission rate refunds and other transmission revenue adjustments.

Electric revenues increased $1.7 million to $41.7 million in Q1 2016 compared to $40.0 million in Q1 2015. Highlights of the changes are summarized in the following table:

For the	Three months ended
millions of US dollars	March 31
Electric revenues – 2015	$	40.0
Increased due to rate changes		3.3
Decreased sales volume primarily due to weather		(3.4	)
Increased due to FERC transmission rate refund reserves		1.2
Amortization of transmission revenue adjustments		0.6
Electric revenues – 2016	$	41.7

Q1 Average Electric Revenue / MWh
US dollars	2016		2015		2014
Dollars per MWh	$	83	$	73	$	78

The change in average electric revenue per MWh in Q1 2016 compared to Q1 2015 reflects increased transmission rates and sales mix.

22

Transmission Pool Revenues and Expenses

Transmission pool revenues are recorded in “Operating revenues – regulated” and transmission pool expenses are recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income.

Transmission pool revenues and expenses are summarized in the following table:

For the	Three months ended
millions of US dollars	March 31
	2016		2015
Transmission pool revenues	$	11.6	$	12.2
Transmission pool expenses		6.3		6.1
Net transmission pool revenues	$	5.3	$	6.1

Emera Maine’s net transmission pool revenues decreased $0.8 million to $5.3 million in Q1 2016 compared to $6.1 million in Q1 2015 primarily due to changes in the level of investment in regionally funded transmission assets and the effect of weather.

EMERA CARIBBEAN

Overview

Emera Caribbean includes the following consolidated and non-consolidated investments:

Consolidated Investments

• 100.0 per cent (December 31, 2015 – 95.5 per cent) investment in ECI and its wholly owned subsidiary BLPC, a vertically integrated utility which is the provider of electricity on the island of Barbados. BLPC serves 126,000 customers and is regulated by the Fair Trading Commission, Barbados. BLPC’s approved regulated return on rate base for 2016 is 10.0 per cent. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. Emera completed the purchase of the remaining 4.5 per cent of common shares from minority shareholders of ECI in Q1 2016.

• 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited (“ICDU”)) in GBPC, which is a vertically integrated utility and a sole provider of electricity on Grand Bahama Island. GBPC serves 19,000 customers and is regulated by the GBPA. Effective February 1, 2016, the GBPA approved GBPC’s regulated return on rate base of 8.8 per cent applicable for the 2016 through 2018 period. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner.

• 51.9 per cent (December 31, 2015 – 49.6 per cent indirect controlling interest), through ECI, in Domlec, an integrated utility on the island of Dominica. Domlec serves 36,000 customers and is regulated by the IRC. Domlec’s approved allowable regulated return on rate base for 2016 is 15.0 per cent. A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely manner.

Equity Investment

• 19.1 per cent (December 31, 2015 – 18.2 per cent indirect interest), through ECI, in Lucelec, a vertically integrated regulated electric utility on the island of St. Lucia which is regulated by the Government of St. Lucia. The investment in Lucelec is accounted for on the equity basis.

23

Review of 2016

Emera Caribbean Net Income

For the	Three months ended March 31
millions of US dollars (except per share amounts)	2016		2015
Operating revenues – regulated	$	71.0	$	83.1
Operating revenues – non-regulated		—		1.9
Total operating revenues		71.0		85.0
Regulated fuel for generation and purchased power		26.7		39.1
Non-regulated direct costs		—		1.8
Operating, maintenance and general		21.6		22.8
Property taxes (1)		0.6		0.4
Depreciation and amortization		9.4		8.6
Total operating expenses		58.3		72.7
Income from operations		12.7		12.3
Income from equity investment		0.4		0.5
Other income (expenses), net		0.3		1.5
Interest expense, net		2.8		2.7
Income before provision for income taxes		10.6		11.6
Income tax expense (recovery)		1.0		1.0
Net income		9.6		10.6
Non-controlling interest in subsidiaries		1.2		2.2
Preferred stock dividends (2)		1.3		1.3
Contribution to consolidated net income – USD	$	7.1	$	7.1
Contribution to consolidated net income – CAD	$	9.8	$	8.8
Contribution to consolidated earnings per common share – CAD	$	0.07	$	0.06
Net income weighted average foreign exchange rate – CAD/USD	$	1.38	$	1.24
EBITDA – USD	$	22.8	$	22.9
EBITDA – CAD	$	31.5	$	28.3

(1) Included in “Provincial, state and municipal taxes” on the Consolidated Statements of Income.

(2) Preferred stock dividends are included in “Non-controlling interest in subsidiaries” on the Consolidated Statements of Income.

Emera Caribbean’s USD contribution to consolidated net income did not change in Q1 2016 compared to Q1 2015.

Emera Caribbean’s CAD contribution to consolidated net income increased by $1.0 million to $9.8 million in Q1 2016 compared to $8.8 million in Q1 2015 as a result of a stronger USD.

Operating Revenues – Regulated

Emera Caribbean’s operating revenues – regulated include sales of electricity and other services as summarized in the following table:

For the	Three months ended March 31
millions of US dollars	2016		2015
Electric revenues – base rates	$	44.0	$	43.6
Fuel charge		26.1		38.6
Total electric revenues		70.1		82.2
Other revenues		0.9		0.9
Operating revenues – regulated	$	71.0	$	83.1

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Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q3 being the strongest period, reflecting warmer weather.

Q1 Electric Sales Volumes
GWh
	2016		2015		2014
Residential		109		105		104
Commercial		179		179		177
Industrial		23		27		24
Other		6		6		7
Total		317		317		312

Electric revenues are summarized in the following tables by customer class:

Q1 Electric Revenues
millions of US dollars
	2016		2015		2014
Residential	$	22.5	$	25.9	$	31.2
Commercial		39.3		46.1		58.5
Industrial		6.8		8.6		8.4
Other		1.5		1.6		1.7
Total	$	70.1	$	82.2	$	99.8

Electric revenues decreased $12.1 million to $70.1 million in Q1 2016 compared to $82.2 million in Q1 2015. Highlights of the changes are summarized in the following table:

For the	Three months ended
millions of US dollars	March 31
Electric revenues – 2015	$	82.2
Decreased fuel charge primarily due to lower fuel prices		(12.5	)
Increased due to higher sales volumes at BLPC		0.4
Electric revenues – 2016	$	70.1

Q1 Average Electric Revenue/MWh
US dollars	2016		2015		2014
Dollars per MWh	$	221	$	259	$	320

The change in average electric revenues per MWh in Q1 2016 compared to Q1 2015 was the result of the decreased fuel charge primarily due to lower fuel prices.

Electric Margin

Emera Caribbean distinguishes revenues related to the recovery of fuel costs through the fuel charge from revenues related primarily to the recovery of non-fuel costs (“base rates”). Emera Caribbean’s electric margin and net income are influenced primarily by base rates, whereas the fuel charge and fuel costs do not have a material effect on electric margin or net income. Emera Caribbean’s customer classes contribute differently to the Company’s base rate revenue, with residential and commercial customers contributing more than industrial customers. Residential and commercial load is primarily affected by changes in weather and economic conditions, while industrial load is primarily affected by economic conditions.

25

Electric margin is summarized in the following table:

For the	Three months ended March 31
millions of US dollars	2016			2015
Operating revenues – regulated	$	71.0		$	83.1
Less: Other revenues		(0.9	)		(0.9	)
Total electric revenues	$	70.1		$	82.2

Total electric revenues are broken down as follows:

Electric revenues – base rate	$	44.0	$	43.6
Fuel charge		26.1		38.6
Total electric revenues		70.1		82.2
Regulated fuel for generation and purchased power		26.7		39.1
Regulatory amortization (1)		0.6		0.7
Electric margin	$	42.8	$	42.4

(1) Included in “Depreciation and amortization” on the Consolidated Statements of Income.

Q1 Average Electric Margin /MWh
US dollars	2016		2015		2014
Dollars per MWh	$	135	$	134	$	133

Electric margin and average electric margin/MWh is consistent quarter over quarter.

Regulated Fuel for Generation and Purchased Power

Q1 Production Volumes
GWh
	2016		2015		2014
Oil		337		335		330
Hydro		9		7		8
Total		346		342		338

Regulated fuel for generation and purchased power decreased $12.4 million to $26.7 million in Q1 2016 compared to $39.1 million in Q1 2015 primarily due to lower fuel prices.

Q1 Average Fuel Costs/MWh
US dollars	2016		2015		2014
Dollars per MWh	$	77	$	114	$	170

The change in average fuel costs in Q1 2016 compared to Q1 2015 was the result of lower fuel prices.

Non-GAAP Measure

Electric Margin Reconciliation

“Electric margin” is a non-GAAP financial measure used to show the amounts that BLPC, GBPC and Domlec retain to recover their non-fuel costs, as substantially all prudently incurred fuel costs are recovered from customers.

The companies’ electric margin may not be comparable to electric margin measures of other companies, but in management’s view appropriately reflects Emera’s specific condition. Management believes measuring electric margin shows the portion of revenues managed through fuel adjustment mechanism, which have a minimal impact on income. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance.

26

For the	Three months ended
millions of US dollars	March 31
	2016		2015
Income from operations	$	12.7	$	12.3
Less:
Operating revenues – non-regulated		—		1.9
Other revenue		0.9		0.9
Add back:
Non-regulated direct costs		—		1.8
Operating, maintenance and general		21.6		22.8
Property taxes		0.6		0.4
Depreciation and amortization (1)		8.8		7.9
Electric margin	$	42.8	$	42.4

(1) Depreciation and amortization excludes $0.6 million of regulatory amortization in Q1 2016 (2015 – $0.7 million).

27

PIPELINES

Overview

Pipelines is comprised of Emera’s wholly owned Brunswick Pipeline and the Company’s 12.9 per cent interest in the M&NP.

• Brunswick Pipeline is a 145-kilometre pipeline delivering re-gasified natural gas from the Canaport™ liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick, to markets in the northeastern United States for Repsol Energy Canada under a 25-year firm service agreement which expires in 2034. The NEB, which regulates Brunswick Pipeline, has classified it as a Group II pipeline. The agreement is accounted for as a direct financing lease.

• M&NP is a 1,400-kilometre transmission pipeline built to transport natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. The investment in M&NP is accounted for on the equity basis.

Mark-to-Market Adjustments

Pipelines’ “Interest expense, net” and “Income tax expense (recovery)” are affected by mark-to-market adjustments on an interest rate swap. Pipelines’ income table below shows these amounts net of mark-to-market adjustments and details the adjustments in the footnotes.

Review of 2016

Pipelines’ Adjusted Net Income

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2016			2015
Operating revenues – regulated	$	12.9		$	13.1
Operating maintenance and general		0.1			0.2
Accretion (1)		0.1			0.1
Income from equity investment		5.9			5.9
Other income (expenses), net		(0.2	)		0.7
Interest expense, net (2)		5.7			6.2
Adjusted Income before provision for income taxes		12.7			13.2
Income tax expense (recovery)		3.0			3.3
Adjusted contribution to consolidated net income	$	9.7		$	9.9
After-tax derivative mark-to-market gain (loss)		(0.3	)		—
Contribution to consolidated net income	$	9.4		$	9.9
Adjusted contribution to consolidated earnings per common share	$	0.07		$	0.07
Contribution to consolidated earnings per common share	$	0.06		$	0.07
Adjusted EBITDA	$	18.5		$	19.5

(1) Accretion related to the reclamation of the pipeline is included in “Depreciation and amortization” on the Consolidated Statements of Income.

(2) Interest expense, net excludes a pre-tax mark-to-market loss of $0.3 million in Q1 2016 compared to nil for the same period in 2015.

Pipelines’ contribution to consolidated net income in Q1 2016 is consistent with Q1 2015.

28

EMERA ENERGY

Overview

Emera Energy includes the following:

• Emera Energy Services (“EES”), a wholly owned physical energy marketing and trading business;

• Emera Energy Generation (“EEG”), a wholly owned portfolio of electricity generation facilities in New England and the Maritime provinces of Canada with 1,410 megawatts (“MW”) of total capacity;

• Equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

Wholly owned investments are consolidated. The investment in Bear Swamp is accounted for on an equity basis.

Mark-to-Market Adjustments

Emera Energy’s “Marketing and trading margin”, “Electricity sales”, “Non-regulated fuel for generation and purchased power”, “Income from equity investments” and “Income tax expense (recovery)” are affected by mark-to-market (“MTM”) adjustments. The Emera Energy income table shows these amounts net of mark-to-market adjustments and details these adjustments in footnotes to the income statement. Management believes excluding the effect of mark-to-market valuations, and changes thereto, from income until settlement better matches the financial effect of these contracts with the underlying cash flows.

Emera Energy has a number of Asset Management Agreements (“AMAs”) with counterparties, including local gas distribution utilities, power utilities, and natural gas producers in the northeast. The AMAs involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the counterparties’ gas transportation/storage capacity to Emera Energy. Mark-to-market adjustments on these AMA’s arise on the price differential between the point where gas is sourced and where it is delivered. At inception, the MTM adjustment is offset fully by the value of the corresponding gas transportation asset, which is amortized over the term of the AMA contract.

Subsequent changes in gas price differentials, to the extent they are not offset by the accounting amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM adjustments may be substantial during the term of the contract, specifically in the winter months of a contract when delivered volumes and market volatility are usually at peak levels. As a contract is realized, and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas transportation asset and the mark-to-market adjustment reduce to zero at the end of the contract term. As the business grows, and AMA volumes increase, MTM volatility resulting in gains and losses may also increase.

29

Review of 2016

Emera Energy Adjusted Contribution to Consolidated Net Income

For the	Three months ended March 31
millions of Canadian dollars (except per share amounts)	2016			2015
Marketing and trading margin (1)	$	46.9		$	38.8
Electricity sales (2)		180.1			250.9
Total operating revenues – non-regulated		227.0			289.7
Non-regulated fuel for generation and purchased power (3)		114.1			159.9
Operating, maintenance and general		25.3			20.1
Provincial, state and municipal taxes		0.9			1.4
Depreciation and amortization		10.9			9.3
Total operating expenses		151.2			190.7
Adjusted income (loss) from operations		75.8			99.0
Income from equity investments (4)		3.8			4.0
Other income (expenses), net		(2.6	)		22.2
Interest expense, net		6.2			1.0
Adjusted income (loss) before provision for income taxes		70.8			124.2
Income tax expense (recovery) (5)		22.9			47.8
Adjusted contribution to consolidated net income (loss)	$	47.9		$	76.4
After-tax derivative mark-to-market gain (loss)	$	45.5		$	(11.5	)
Contribution to consolidated net income	$	93.4		$	64.9
Adjusted contribution to consolidated earnings per common share – basic	$	0.32		$	0.53
Contribution to consolidated earnings per common share – basic	$	0.63		$	0.45
Adjusted EBITDA	$	87.9		$	134.5

(1) Marketing and trading margin excludes a pre-tax mark-to-market gain of $72.3 million for the quarter ended March 31, 2016 (2015 - $13.9 million gain).

(2) Electricity sales exclude a pre-tax mark-to-market loss of $8.3 million for the quarter ended March 31, 2016 (2015 - $45.8 million loss).

(3) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market gain of $2.8 million for the quarter ended March 31, 2016 (2015 - $7.0 million gain).

(4) Income from equity investments excludes a pre-tax mark-to-market loss of $2.4 million for the quarter ended March 31, 2016 (2015 - $3.4 million gain).

(5) Income tax expense (recovery) excludes an $18.9 million expense relating to mark-to-market gains for the quarter ended March 31, 2016 (2015 - $10.0 million recovery).

Emera Energy’s contribution to consolidated net income increased $28.5 million to $93.4 million in Q1 2016 compared to $64.9 million in Q1 2015. Highlights of the net income changes are summarized in the following table:

30

For the millions of Canadian dollars	Three months ended March 31
Contribution to consolidated net income – 2015	$	64.9
Increased marketing and trading margin – See Marketing and Trading Margin below		8.1
Decreased electricity sales primarily due to lower hedged and market power prices at the New England Gas Generating Facilities, lower market prices at Bayside Power, and decreased sales volumes at the New England Gas Generating Facilities driven by weather, partially offset by a stronger USD		(70.8	)
Decreased non-regulated fuel for generation and purchased power mainly due to lower hedged and market commodity prices at the New England Gas Generating Facilities, lower market commodity prices at Bayside Power, and decreased purchase volumes at the New England Gas Generating Facilities driven by weather, partially offset by a stronger USD		45.8
Increased OM&G primarily due to a stronger USD and increased performance-based compensation resulting from increased marketing and trading margin		(5.2	)
Decreased other income primarily due to a gain on the sale of NWP in 2015		(24.8	)
Increased interest expense, net primarily due to higher interest rates on internal financing		(5.2	)
Decreased income tax expense primarily due to decreased income before provision for income taxes, changes in the proportion of income earned in higher tax rate foreign jurisdictions and a stronger CAD		24.9
Increased mark-to-market, net of tax primarily due to the reversal of 2015 mark-to-market losses and changes in gas and power contract positions, partially offset by amortization of 2015 gas transportation assets		57.0
Other		(1.3	)
Contribution to consolidated net income – 2016	$	93.4

A portion of earnings are exposed to foreign exchange fluctuations, thereby impacting adjusted CAD contribution to net earnings. The impact of a stronger USD, quarter-over-quarter, increased CAD earnings by $5.3 million in Q1 2016 compared to Q1 2015.

Emera Energy Services

Adjusted EBITDA

Adjusted EBITDA for Emera Energy Services is summarized in the following table:

For the millions of Canadian dollars	Three months ended March 31
	2016			2015
Marketing and trading margin	$	46.9		$	38.8
OM&G		10.4			7.5
Other income (expenses), net		(3.7	)		3.5
Adjusted EBITDA	$	32.8		$	34.8

Marketing and Trading Margin

Marketing and trading margin increased $8.1 million to $46.9 million in Q1 2016 compared to $38.8 million in Q1 2015. This increase is primarily due to a stronger USD and growth in the volume of business, including investment in transportation capacity, which offset the impact of sustained low pricing and volatility in several of Emera Energy’s markets in Q1 2016, largely the result of weather.

Other Income

Other income decreased $7.2 million to $(3.7) million in Q1 2016 compared to $3.5 million in Q1 2015. This decrease is primarily due to foreign exchange losses recorded in 2016 as a result of the stronger CAD since December 31, 2015.

31

Emera Energy Generation

Adjusted EBITDA

Adjusted EBITDA for Emera Energy Generation is summarized in the following table:

	Three months ended March 31
For the	New England				Maritime Canada					Total
millions of Canadian dollars	2016		2015		2016		2015			2016		2015
Energy sales	$	139.3	$	201.3	$	28.3	$	39.0		$	167.6	$	240.3
Capacity and other		12.5		10.6		—		—			12.5		10.6
Electricity sales	$	151.8	$	211.9	$	28.3	$	39.0		$	180.1	$	250.9
Non-regulated fuel for generation and purchased power		94.1		133.4		18.3		28.6			112.4		162.0
Non-regulated electric margin	$	57.7	$	78.5	$	10.0	$	10.4		$	67.7	$	88.9
Provincial taxes		0.7		1.1		0.2		0.3			0.9		1.4
OM&G		9.0		7.3		5.5		4.5			14.5		11.8
Other income (expenses), net		—		1.3		1.1		(1.3	)		1.1		—
Adjusted EBITDA	$	48.0	$	71.4	$	5.4	$	4.3		$	53.4	$	75.7

Adjusted EBITDA decreased $22.3 million to $53.4 million in Q1 2016 from $75.7 million in Q1 2015 primarily due to lower margins realized in the New England Gas Generating Facilities, reflecting less favourable short-term economic hedges and fewer optimization opportunities driven by weather across the northeastern United States. This was partially offset by the stronger USD, which contributed $4.7 million.

Operating Statistics

For the	Three months ended March 31
	Sales Volumes (GWh) (1)				Plant Availability (%) (2)						Net Capacity Factor (%) (3)
	2016		2015		2016			2015			2016			2015
New England		1,299		1,410		96.1	%		98.0	%		54.6	%		60.8	%
Maritime Canada		518		483		95.8	%		99.2	%		75.9	%		70.0	%
Total		1,817		1,893		96.0	%		98.3	%		59.3	%		63.1	%

(1) Sales volumes represent the actual electricity output of the plants.

(2) Plant availability represents the percentage of time in the period that the plant was available to generate power regardless of whether it was running. Effectively, it represents 100% availability reduced by planned and unplanned outages.

(3) Net capacity factor is the ratio of the utilization of an asset as compared to its maximum capability, within a particular time frame. It is generally a function of plant availability and plant economic vis-à-vis the market.

Sales volumes and net capacity factor decreased quarter-over-quarter at the New England Gas Generating Facilities primarily due to the impact of weather across the northeastern United States.

The New England Gas Generating Facilities sell into price based competitive markets. The primary reason that the overall capacity factor is lower for New England Gas Generating Facilities as compared to the Maritime facilities is because the Rumford Plant, in particular, generally operates with a capacity factor of approximately 20 per cent, reflecting current electricity and gas supply price dynamics in its markets.

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Adjusted income from equity investments

Adjusted income from equity investments is summarized in the following table:

For the millions of Canadian dollars	Three months ended March 31
	2016		2015
Bear Swamp	$	3.8	$	2.1
NWP		—		1.9
Adjusted income from equity investments	$	3.8	$	4.0

Income from equity investments decreased $0.2 million to $3.8 million in Q1 2016 compared to $4.0 million in Q1 2015, largely due to the sale of NWP in Q1 2015 and higher interest costs at Bear Swamp as a result of its Q4 2015 refinancing, largely offset by favourable pricing at Bear Swamp and the effect of a stronger USD.

CORPORATE AND OTHER

Corporate

Corporate encompasses certain corporate-wide functions including executive management, strategic planning, treasury services, legal, financial reporting, tax planning, corporate business development, corporate governance, internal audit, investor relations, risk management, insurance, acquisition related costs and corporate human resource activities. It also includes interest revenue on intercompany financings recorded in “Intercompany revenue” in the table below, and costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Other

Other includes the following consolidated and non-consolidated investments:

Consolidated Investments

• Emera Utility Services is a utility services contractor primarily operating in Atlantic Canada (recorded in “Non-regulated operating revenue” in the table below).

• Emera Reinsurance Limited is a captive insurance company providing insurance and reinsurance to Emera and certain of its affiliates, to enable more cost efficient management of risk and deductible levels across Emera (recorded in “OM&G” and “Other income (expenses), net” in the table below).

Non-consolidated investments (recorded in “Income (loss) from equity investments” in the table below)

• Emera’s 19.4 per cent (December 31, 2015 – 19.6 per cent) investment in APUC. APUC is a diversified generation, transmission and distribution utility traded on the Toronto Stock Exchange (“TSX”) under the symbol “AQN”. The investment in APUC is accounted for on the equity basis. There is a one-quarter lag in reporting as APUC’s information is generally not publicly available at the time of Emera’s public release of its financial results. As at March 31, 2016, Emera owned 50.1 million common shares, 12.9 million outstanding subscription receipts and dividend equivalents, at an average conversion price of $9.19. The outstanding subscription receipts and dividend equivalents will automatically convert to common shares in Q4 2016, if an election is not made. If converted, Emera’s interest would increase to 23.2 per cent. The subscription receipts and dividend equivalents are included in “Investments subject to significant influence” on the Consolidated Balance Sheets.

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• Emera’s 100 per cent investment in ENL, which holds investments in the following:

• Emera’s 100 per cent investment in NSPML, a $1.56 billion transmission project, including two 170-kilometre subsea cables, between the island of Newfoundland and Nova Scotia. The investment in NSPML is accounted for on the equity basis with equity earnings equal to the return on equity component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017.

• Emera’s 59.0 per cent (December 31, 2015 - 55.1 per cent) investment in the partnership capital of LIL, a $3.1 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change based on the balance of capital investments required from Emera and Nalcor Energy to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 per cent of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is expected to go into service in 2017.

• Other investments.

Mark-to-Market Adjustments

Specific to the pending TECO Energy acquisition, Emera has recorded after-tax mark-to-market losses of $121.1 million for the three months ended March 31, 2016 (2015 – nil) related to the effect of USD-denominated currency and forward contracts put in place to hedge the anticipated proceeds from the second instalment of the Debenture Offering of the pending acquisition, expected to close mid-2016.

“Other income (expenses), net” and “Income tax expense (recovery)” are affected by the mark-to-market adjustments discussed above. Corporate and Other’s income table below shows these amounts net of mark-to-market adjustments and details the adjustments in the footnotes.

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Review of 2016

Corporate and Other

For the	Three months ended March 31
millions of Canadian dollars	2016			2015
Intercompany revenue (1)	$	9.9		$	5.3
Non-regulated operating revenue		8.4			8.8
Non-regulated direct costs		8.2			9.7
Operating, maintenance and general		13.7			12.7
Depreciation and amortization		0.7			0.3
Total operating expenses		22.6			22.7
Income (loss) from operations		(4.3	)		(8.6	)
Income (loss) from equity earnings		18.1			11.9
Other income (expenses), net (2)		3.6			(0.2	)
Interest expense		33.1			6.3
Adjusted income (loss) before provision for income taxes		(15.7	)		(3.2	)
Income tax expense (recovery) (3)		(13.7	)		(7.9	)
Preferred stock dividends		7.0			7.7
Adjusted contribution to consolidated net income	$	(9.0	)	$	(3.0	)
After-tax mark-to-market gain (loss)		(121.1	)		—
Contribution to consolidated net income		(130.1	)		(3.0	)
Adjusted contribution to consolidated earnings per common share – basic		(0.06	)		(0.02	)
Contribution to consolidated earnings per common share – basic	$	(0.87	)	$	(0.02	)
Adjusted EBITDA	$	18.1		$	3.4

(1) Intercompany revenue consists of interest from Brunswick Pipeline, M&NP and EEG.

(2) Other income (expenses) net, excludes a pre-tax mark-to-market loss of $139.5 million in Q1 2016 compared to nil for the same period in 2015.

(3) Income tax expense (recovery), excludes an $18.4 million recovery relating to mark-to-market losses in Q1 2016 compared to nil for the same period in 2015.

Corporate and Other’s contribution to consolidated net income decreased $127.1 million to $(130.1) million in Q1 2016 compared to $(3.0) million in Q1 2015. Highlights of the income changes are summarized in the following table:

For the	Three months ended
millions of Canadian dollars	March 31
Contribution to consolidated net income – 2015	$	(3.0	)
Increased intercompany revenue primarily due to the issuance of a loan to Emera Energy Generation		4.6
Income from equity investments - see table below for highlights		6.2
Increased interest expense primarily due to interest on the pending TECO Energy acquisition related convertible debentures represented by instalment receipts		(26.8	)
Increased income tax recovery primarily due to decreased income before provision for income taxes		5.8
After-tax mark-to-market gain (loss) - see After-Tax Mark-to-Market Gain (Loss) section below		(121.1	)
Other		4.2
Contribution to consolidated net income – 2016	$	(130.1	)

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Acquisition Related Costs

Highlights of the TECO Energy related acquisition costs summarized in the following table:

For the	Three months ended
millions of Canadian dollars	March 31
	2016			2015
Operating, maintenance, and general	$	0.1		$	—
Interest expense, net		25.5			—
Income tax expense (recovery)		(8.1	)		—
Acquisition related costs	$	17.5		$	—

After-Tax Mark-to-Market Gain (Loss)

The foreign currency earnings impact related to the translation from the convertible debenture USD cash balance and the mark-to-market adjustments from forward contracts from economically hedging the Debenture Offering are recorded as a mark-to-market adjustment. These pre-tax losses totaled $139.5 million in Q1 2016 and are recorded in “Other income (expenses), net” on the Consolidated Statements of Income ($121.1 million after-tax loss). These losses offset a pre-tax mark-to-market gain of $118.9 million ($100.5 million after-tax gain) recorded in Q4 2015. The after-tax mark-to-market gain (loss) is summarized in the following table:

For the	Three months ended
millions of Canadian dollars	March 31
	2016			2015
Foreign exchange on USD cash	$	(44.7	)	$	—
Mark-to-market adjustment on USD forward contracts		(94.8	)		—
Income tax (expense) recovery		18.4			—
After-tax mark-to-market gain (loss)	$	(121.1	)	$	—

Income from Equity Investments

Income from equity investments are summarized in the following table:

For the	Three months ended
millions of Canadian dollars	March 31
	2016		2015
APUC	$	9.0	$	6.6
NSPML		4.4		3.6
LIL		4.7		1.7
Income from equity investments	$	18.1	$	11.9

Income from equity investments increased $6.2 million to $18.1 million in Q1 2016 compared to $11.9 million in Q1 2015. Highlights of the changes are summarized in the following table:

For the	Three months ended
millions of Canadian dollars	March 31
Income from equity investments – 2015	$	11.9
APUC – Higher equity earnings and the reclassification of APUC subscription receipts		2.4
NSPML – AFUDC earnings as a result of increased investment		0.8
LIL – AFUDC earnings as a result of increased investment		3.0
Income from equity investments – 2016	$	18.1

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NSPML has invested $796.7 million as at March 31, 2016 of equity, debt and working capital, including $90.3 million of AFUDC, in the development of the Maritime Link Project. Project to date, Emera has invested a total of $206.4 million in equity, which is comprised of $169.3 million in equity contributed and $37.1 million of accumulated retained earnings, with the remaining costs being funded with working capital and debt. The debt has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9 per cent. Proceeds from the federally guaranteed debt financing completed in April 2014, were used to fund project costs until the Project’s target debt to equity ratio reached 70 per cent to 30 per cent respectively, in Q4 2015. From that point forward, project costs are being funded with debt and equity at a 70 per cent and 30 per cent ratio, with equity contributions of $14.4 million in Q1 2016.

Emera has invested $250.4 million in the LIL as at March 31, 2016, which is comprised of $224.5 million in equity contributed and $25.9 million of accumulated equity earnings. Equity earnings are being recorded based on an annual rate 8.8 per cent of the equity invested. The rate is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities.

LIQUIDITY AND CAPITAL RESOURCES

The Company generates cash primarily through its investments in various regulated and non-regulated energy related entities and investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include general economic downturns in markets served by Emera, the loss of one or more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets and changes in environmental legislation. Emera’s subsidiaries maintain solid credit metrics and are generally in a financial position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment.

Consolidated Cash Flow Highlights

Significant changes in the statements of cash flows between the three months ended March 31, 2016 and 2015 include:

millions of Canadian dollars	2016			2015			$ Change
Cash and cash equivalents, beginning of period	$	1,073.4		$	221.1		$	852.3
Provided by (used in):
Operating cash flow before change in working capital		232.4			257.5			(25.1	)
Change in working capital		(51.8	)		(137.9	)		86.1
Operating activities		180.6			119.6			61.0
Investing activities		(139.3	)		195.9			(335.2	)
Financing activities		(45.8	)		(259.3	)		213.5
Effect of exchange rate changes on cash and cash equivalents		(69.4	)		28.0			(97.4	)
Cash and cash equivalents, end of period	$	999.5		$	305.3		$	694.2

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Operating Cash Flows

Refer to Consolidated Income Statement and Operating Cash Flow Highlights for details.

Investing Cash Flows

Net cash used in investing activities increased $335.2 million to $139.3 million for the three months ended March 31, 2016 compared to net cash provided by investing activities of $195.9 million for the same period in 2015. The increase was primarily due to proceeds from the sale of NWP in 2015 and increased investments in NSPML and LIL in 2016.

Capital expenditures for the three months ended March 31, 2016, including AFUDC and net of proceeds from disposal of assets, were $87 million compared to $83 million during the same period in 2015. Details of the capital spend are shown below:

• $48 million at NSPI (2015 – $51 million);

• $9 million at Emera Maine (2015 – $19 million);

• $22 million at Emera Caribbean (2015 – $9 million);

• $6 million at Emera Energy (2015 – $2 million);

• $2 million in Corporate and Other (2015 – $2 million)

Financing Cash Flows

Net cash used in financing activities decreased $213.5 million to $45.8 million for the three months ended March 31, 2016 compared to $259.3 million for the same period in 2015. The decrease was primarily due to the repayment of debt in 2015, partially offset by the 2015 proceeds of the long-term debt issuance by Brunswick Pipeline.

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Contractual Obligations

As at March 31, 2016, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2016		2017		2018		2019		2020		Thereafter		Total
Long-term debt	$	268.8	$	49.5	$	23.8	$	610.1	$	748.5	$	2,301.2	$	4,001.9
Purchased power (1)		166.5		229.8		204.0		198.7		195.2		2,380.5		3,374.7
Solid fuel supply		114.5		75.7		12.0		—		—		—		202.2
DSM		22.1		34.0		34.9		—		—		—		91.0
Pension and post-retirement obligations (2)		11.1		19.2		19.8		20.2		20.9		716.7		807.9
Asset retirement obligations		5.1		4.0		4.3		4.2		1.7		317.2		336.5
Interest payment obligations (3)		140.0		177.4		175.1		167.7		138.8		2,244.7		3,043.7
Convertible debentures represented by instalment receipts (4)		727.6		—		—		—		—		—		727.6
Interest obligations on the first instalment of convertible debentures represented by instalment receipts (4)		54.1		—		—		—		—		—		54.1
Transportation (5)		188.9		118.6		78.2		43.2		41.1		86.3		556.3
Long-term service agreements (6)		48.6		49.6		34.4		47.1		20.4		202.1		402.2
Capital projects		69.2		5.6		—		—		—		—		74.8
Equity investment commitments (7)		356.0		183.0		—		—		—		—		539.0
Leases and other (8)		18.9		9.9		9.0		8.4		7.3		19.0		72.5
	$	2,191.4	$	956.3	$	595.5	$	1,099.6	$	1,173.9	$	8,267.7	$	14,284.4

(1) Annual requirement to purchase 20 to 100 per cent of electricity production from independent power producers over varying contract lengths up to 25 years.

(2) Defined benefit funding contractual obligations were determined based on funding requirements and assuming pension accruals cease as at December 31, 2015. Credited service and earnings are assumed to be crystallized as at December 31, 2015. The Company’s contractual obligations for post-retirement (non-pension) benefits assumes members must be age 55 or over as at December 31, 2015 to be eligible. As the defined benefit pension plans currently undergoes regular reviews to revise contribution requirements and members are still accruing service under the plans, actual future contributions to the plans will differ from the amounts shown.

(3) Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in effect at March 31, 2016, including any expected required payment under associated swap agreements.

(4) In 2015, to finance a portion of the pending acquisition of TECO Energy, Emera completed the sale of $2.185 billion aggregate principal amount of four per cent convertible unsecured subordinated debentures. The Debentures were sold on an instalment basis, with 1/3 paid on closing of the Debenture Offering, and the remaining payable on a date to be fixed following satisfaction of conditions precedent to the closing of the acquisition of TECO Energy.

(5) Purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines.

(6) Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

(7) Emera has a commitment in connection with the Federal Loan Guarantee (“FLG”) to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity. Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to change in both timing and amounts as the projects advance through construction.

(8) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

Other Contractual Obligations

On September 4, 2015, the Company announced a definitive agreement for Emera to acquire TECO Energy for $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.4 billion USD and includes the assumption of approximately $3.9 billion USD of debt. Further information on the pending acquisition of TECO Energy is discussed in the Developments section.

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Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $1.3 billion committed syndicated revolving bank lines of credit per the table below. NSPI has an active commercial paper program for up to $400 million, of which the full amount outstanding is backed by NSPI’s operating credit facility referred to below. The amount of commercial paper issued results in an equal amount of its operating credit facility being considered drawn and unavailable.

As at March 31, 2016, the Company’s total credit facilities, outstanding borrowings and available capacity were as follows:

millions of dollars	Maturity		Revolving Credit Facilities		Utilized		Undrawn and Available
Emera – Operating and acquisition credit facility		June 2020 – Revolver	$	700	$	276	$	424
NSPI – Operating credit facility		October 2020 – Revolver		500		386		114
Emera Maine – in USD – Operating credit facility		September 2019 – Revolver		80		21		59
Other – in USD – Operating credit facilities		Various		32		2		30

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements as at March 31, 2016.

For the purpose of bridge financing for the pending acquisition of TECO Energy, on September 4, 2015, the Company secured an aggregate of $6.5 billion USD non-revolving term credit facilities (“Acquisition Credit Facilities”) from a syndicate of banks. The non-revolving term credit facilities are comprised of a $4.3 billion USD debt bridge facility, repayable in full on the first anniversary following its advance, and a $2.2 billion USD equity bridge facility repayable in full on the first anniversary following its advance. On October 16, 2015, Emera permanently reduced the USD bridge facilities in the amount of $588.3 million USD with the proceeds of the first instalment of the convertible debentures and the proceeds from the Bear Swamp financing. The credit facilities table above does not include the Acquisition Credit Facilities.

Emera is required to effect reductions or make prepayments of the Acquisition Credit Facilities in an amount equal to the net cash proceeds from any common equity, preferred equity, bond or other debt offerings and any non-ordinary course asset sales by Emera and its subsidiaries, subject to certain prescribed exceptions and certain other prescribed transactions. Net proceeds from any such offerings, including the net proceeds of the final instalment under the Debenture Offering, or from any such non-ordinary course asset sales or transactions, will be applied to permanently reduce the commitments of the lenders under the Acquisition Credit Facilities or to repay the Acquisition Credit Facilities after they are drawn. Any prepayment under the Acquisition Credit Facilities may not be re-borrowed. The Acquisition Credit Agreements contain customary representations and warranties and affirmative and negative covenants of Emera that will closely resemble those in Emera’s existing revolving credit facility.

Emera’s future liquidity and capital needs, not including the capital needs to fund the pending TECO Energy acquisition, will be predominately for working capital requirements and capital expenditures in support of growth throughout the businesses, potential new acquisitions, dividends and debt servicing. These liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to capital markets.

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The cash purchase price of the pending TECO Energy acquisition and the acquisition related costs will be financed at the closing of the acquisition with one or more of the following sources: (i) net proceeds of the first instalment and second instalment under the Debenture Offering, (ii) net proceeds of any subsequently completed preferred equity or bond or other debt offerings, (iii) amounts drawn under the acquisition credit facilities and the revolving facility, and (iv) existing cash on hand and other sources available to the Company. Common equity and other available sources are expected to comprise $1.7 billion USD to $2.1 billion USD of the long-term financing for the acquisition, preferred equity offerings are expected to amount to $0.8 billion USD to $1.2 billion USD and bond or other debt offerings are expected to amount to $3.4 billion USD to $3.8 billion USD.

Emera and its subsidiaries recent financing activity is discussed further in the Developments section.

Guarantees and Letters of Credit

There were no changes in Emera’s standby letters of credit since its year end disclosure at December 31, 2015.

OUTLOOK

Energy markets across North America are affected by a number of trends that shape the environment in which energy and utility companies are operating. Some of these trends are short-term or cyclical, while others evolve to have a significant long-term impact on businesses and stakeholders across the sector.

Among the key trends influencing Emera’s long-term strategy is the increasing expectation by customers and policy-makers for a permanent reduction in the carbon-equivalent levels of electricity generation. This advocacy drive for cleaner, renewable sources of electricity has become a defining trend in the industry in recent years, not just in the markets Emera serves, but on a global basis. While it is still unclear whether economic volatility and lower fossil fuel prices will slow the pace of this transformation, its impact on the sector continues to be felt in the form of mandated and incented carbon reductions throughout eastern North America and in the Caribbean. As such, investment in wind and hydro generation, and natural gas infrastructure, is likely to continue across the sector.

This transformation in generation and fuel selection also has a significant impact on the requirement for new transmission infrastructure. Increasingly, in addition to the traditional issues of infrastructure life expectancy and changing technology, infrastructure renewal planning must now also take into account the changing energy landscape. Gas extraction from the Marcellus Shale region of the United States, major new hydro developments in Newfoundland and Labrador, and development of new wind farms in northern New England and Atlantic Canada (to name a few) require significant new transmission infrastructure to bring this energy to market.

The capital spending requirements related to this renewal underscore the intense focus placed by customers and regulators on electricity price and affordability that is required by our franchise agreements and basic rate regulation. Going forward, the ability of energy companies to achieve their growth objectives, environmental targets and other goals, will continue to be a key success factor.

As technology advances, so does the availability and demand for affordable new mechanisms that allow consumers to have more control over their energy usage and for utilities to introduce more efficient energy solutions for their customers. This includes grid modernization or ‘smart grid’ advances that, when combined with in-home products such as heat pumps and electric thermal storage units, have the potential to significantly increase energy efficiency for consumers while allowing utilities to better manage peak load demand. In addition, like wind turbine technology, advancements in solar technology have reduced solar generation costs significantly, bringing them more in line with the cost of fossil fuel generation in some higher-cost jurisdictions. This gives rise to customer expectations that they will be

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able to benefit from options such as distributed generation. Continued and advancing development of energy storage technology will further transform and support the efficient and practical utilization of renewables.

These and other trends create opportunities and challenges for businesses, regulators, investors and other stakeholders within the energy sector, and are expected to drive increased regional cooperation and interconnection within the energy industry. Whether it is the need to transport natural gas and electricity from disparate regions to markets on the eastern seaboard, or the need to gain efficiencies by coordinating electricity generation and dispatch across multiple jurisdictions, inter-regional cooperation has emerged as an important trend in itself.

Business Outlook

The pending TECO Energy acquisition will result in further acquisition costs in 2016. The transaction is expected to be accretive to EPS by approximately 5 per cent in the first full year following its completion (2017), growing to more than 10 per cent by the third full year (2019) assuming a USD/CAD exchange rate consistent with that at the time of announcement. Approximately 95 per cent of the expected foreign exchange exposure to close the pending acquisition has been effectively hedged.

Emera’s operations are affected by the US dollar relative to the Canadian dollar. With the disparity between the two currencies, the effect on Emera’s income is noteworthy, as approximately 50 per cent of Emera’s adjusted net income was derived from subsidiaries with a US functional currency. TECO Energy operations are conducted in US dollars and following the pending acquisition, Emera‘s consolidated net income and cash flows will be impacted to a greater extent by movements in the US dollar relative to the Canadian dollar.

NSPI

NSPI’s earnings are most directly impacted by the range of rate of return on equity and capital structure approved by the UARB; the prudent management and approved recovery of operating costs, load, the approved recovery of regulatory deferrals; and the timing and amount of capital expenditures.

While NSPI has experienced an unseasonably warm heating season with increased storm activity, NSPI anticipates earning within its allowed ROE range in 2016 and expects its earnings and rate base to be generally consistent with prior years.

Over the past several years, the requirement to reduce Nova Scotia’s reliance upon high carbon and greenhouse gas emitting sources of energy has resulted in NSPI making a significant investment in renewable energy sources and purchasing third party renewable energy. In December 2015, the Electricity Plan Act was enacted by the Province of Nova Scotia, with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period. In accordance with the Electricity Plan Act, NSPI filed a three-year rate plan with the UARB for Fuel Costs in Q1 2016, which requested average annual rate increases of 1.3 per cent for 2017 through 2019. NSPI also announced that it will not file a general rate application for non-fuel costs for the 2017 to 2019 period. This was a result of NSPI continuing to work towards rate stability for customers through a focused effort on operating costs, productivity levels and service improvements.

In 2015, NSPI filed an application with the UARB for the introduction of a regulatory framework to enable the purchase by retail customers of renewable low-impact electricity generated in Nova Scotia from retail suppliers licensed by the UARB. In Q1 2016, The UARB issued a decision affirming NSPI’s proposed framework subject to small revisions. It is expected the market implementation process will be completed by the end of 2016.

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Capital expenditures for 2016, including AFUDC are forecasted to be $282.5 million (2015 - $274.0 million actual).

Emera Maine

Emera Maine’s earnings are most directly impacted by the combined impacts of the range of rates of return on equity and rate base approved by its regulators, the prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures.

Emera Maine’s 2016 ROE and earnings are expected to be generally consistent with prior years. Its ongoing investment in transmission and distribution infrastructure is expected to result in modest growth in rate base.

Emera Maine has an agreement with Central Maine Power Company to pursue specific transmission opportunities in northern Maine that would relieve transmission congestion and more efficiently collect and deliver wind to southern New England markets. As part of this agreement, Emera Maine and Central Maine Power Company jointly responded in Q1 2016 to a request for proposals from Massachusetts, Connecticut and Rhode Island. The demand for new renewable energy, and the infrastructure to deliver that energy to market, is growing as a result of increasing renewable portfolio requirements of the southern New England states.

There are three outstanding pending complaints, with the FERC, to challenge the ISO-New England Open Access Transmission Tariff-allowed base ROE. On March 22, 2016, the Administrative Law Judge (“ALJ”) issued a recommended decision to the FERC with respect to the first two outstanding ROE complaints. The ALJ recommendation for the ENE Case was a 9.59 per cent base ROE, with a 10.42 per cent maximum ROE, and the recommendation for MA AG II Case was a 10.90 per cent base ROE, with a 12.19 per cent maximum ROE. A reserve was calculated on a 10.57 per cent base and represents Emera Maine’s best estimate of the probable outcome for the two outstanding complaints, and no update was made to the reserve based on the ALJ recommendation, as it is pending approval by the FERC and considered uncertain until that time. On April 29, 2016, an additional complaint was filed with FERC challenging the ROE under the ISO-NE transmission tariff. The complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”), a collection of thirteen municipal light departments, seeking to reduce the base transmission ROE to a maximum of 8.93 per cent and the maximum ROE of 11.24 per cent. No reserve has been made as a result of this complaint, as the outcome is considered uncertain.

In 2016, Emera Maine expects to invest approximately $89.5 million (2015 - $66 million actual), including approximately $42.9 million for transmission projects.

Emera Caribbean

Earnings from Emera Caribbean are most directly impacted by the combined impacts of the range of rates of return on rate base approved by their regulators, capital structure, prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures. Earnings are also affected by the investment returns of Emera’s interest in BLPC’s self-insurance fund.

The Barbados economy is forecasted to grow modestly in 2016. With oil being the predominant fuel source for generation of electricity in the Caribbean, reduced oil prices may result in an economic benefit on the island in decreased cost of electricity to ratepayers.

The economy of Grand Bahama is highly correlated to the United States economy. In 2015, the economy of Grand Bahama exhibited signs of improving with economic growth in the industrial sector and weather related growth in the residential sector. 2016 sales are expected to be flat compared to 2015.

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Overall, Emera Caribbean earnings and rate base are expected to be generally consistent with prior years. GBPC’s 2016 earnings will reflect its 8.8 per cent allowable return on rate base.

Emera Caribbean plans to invest approximately $125.2 million in capital programs in 2016 (2015 - $44.0 million actual). This increase is due to spending on a new solar facility in Barbados.

Pipelines

The timing of the income from Pipelines is predominately a result of capital lease accounting treatment of the Emera Brunswick Pipeline, which yields declining earnings over the life of the asset.

Pipelines’ 2016 earnings are expected to be lower than 2015 as a result of less favourable foreign exchange exposure and higher OM&G costs.

Emera Energy

Emera Energy Services

Emera Energy Services, Emera Energy’s marketing and trading business, is generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply/demand factors, can provide higher levels of margin opportunity.

In addition to capitalizing on volatility-driven market opportunities, Emera Energy Services expects to continue to grow organically building market share through superior customer service and expanding its geographic reach to adjacent markets, including the Marcellus Shale region.

Planned investment by the industry in gas transportation infrastructure within the northeast United States over the next few years could reduce the degree of volatility recently experienced in the market, all other things being equal. This could negatively affect profitability during certain periods.

Emera Energy Generation

Earnings from Emera Energy Generation’s assets are largely dependent on market conditions, in particular, the relative pricing of electricity and natural gas and capacity pricing for the New England Gas Generation Facilities. Efficient operations of the fleet to ensure unit availability, cost management and effective commercial performance are key success factors.

2016 adjusted earnings from Emera Energy generating assets are expected to be lower than 2015, reflecting lower hedged and expected margins as compared to 2015.

In addition to energy margins and ancillary revenue, the New England Gas Generating Facilities and Bear Swamp earn revenue from capacity payments through the forward capacity market (“FCM”), the annual reconfiguration capacity market and the monthly reconfiguration capacity market. Prices for the FCM, the larger of the two components, are determined through an auction process held annually, three years in advance, providing revenue visibility to 2020, presuming the facilities continue to be available to support their capacity obligations. Details of pricing and estimated revenues are outlined in the table below for the New England Gas Generating facilities, and Emera Energy’s 50 per cent interest in Bear Swamp.

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Forward Capacity Auction (“FCA”) Year	Clearing Price in $/kW-month (in USD)	Approximate Estimated Annual Capacity Revenue (in USD) (1)
FCA6 (June 2015 to May 2016)	$3.43	$40 million
FCA7 (June 2016 to May 2017)	$3.15	$40 million
FCA8 (June 2017 to May 2018)	$7.025	$100 million
FCA9 (June 2018 to May 2019)	$9.55 and $11.08 (2)	$145 million
FCA 10 (June 2019 to May 2020)	$7.03	$106 million

(1) Includes Emera’s 50 per cent share of Bear Swamp’s capacity revenue

(2) $11.08 was awarded for the Southeast Massachusetts/Rhode Island zone only and, as such, applies only to Tiverton

Bear Swamp’s adjusted earnings will be lower in 2016 and the first half of 2017 primarily due to higher interest costs as a result of its Q4 2015 refinancing. Beginning Q3 2017, these interest costs are expected to be offset by higher capacity revenues.

In 2016, Emera Energy expects to invest approximately $41.0 million (2015 – $42.0 million actual) in capital projects related to its generating assets in order to further improve reliability and increase plant capacity.

Corporate and Other

Corporate and Other is dependent, in part, on business development and acquisition related initiatives, which in 2016 will include further costs related to the pending TECO Energy acquisition, AFUDC earnings as a result of equity investments in the Maritime Link Project and the Labrador-Island Link, project-based construction services activity by Emera Utility Services, growth in APUC earnings (which Emera accounts one quarter after APUC reports such earnings), corporate financing costs and other corporate activities.

Corporate’s contribution to consolidated net income in 2016 is expected to be lower than 2015 primarily due to further acquisition costs and associated financing initiatives related to the pending TECO Energy acquisition. These costs will include a non-cash accounting charge for the difference between Emera’s closing share price on the issuance date of the convertible debentures and their exercise price. This will be recognized once contingencies surrounding regulatory and other approvals are resolved.

On February 9, 2016, APUC announced its intention to acquire The Empire District Electric Company in a $3.4 billion transaction, which is expected to close in Q1 2017. The closing of this transaction and its related financing will reduce Emera’s percentage ownership interest in APUC.

In 2016, Corporate and Other expects to invest approximately $8.0 million (2015 - $10.0 million actual).

ENL

NSP Maritime Link Inc. (“NSPML”)

Through its subsidiary, NSP Maritime Link Inc., ENL had invested at March 31, 2016, approximately $796.7 million of equity, debt and working capital, including $90.3 million of AFUDC, in the development of the Maritime Link Project. Project to date, ENL has invested $206.4 million in equity, comprised of $169.3 million in equity contributed and $37.1 million of accumulated retained earnings, with the remaining costs being funded with working capital and debt. The debt has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9 per cent.

ENL’s future earnings contribution from the Maritime Link Project will be affected by the amount and timing of capital expenditures for design and construction activities, which will determine the component of costs to be funded by equity. Proceeds from the federally guaranteed debt financing completed in 2014 were used to fund project costs until the Project’s debt to equity ratio reached 70 per cent to 30 per cent respectively in Q4 2015. From that point forward, project costs are being funded with debt and equity at a 70 per cent to 30 per cent ratio, with equity contributions of $14.4 million in Q1 2016.

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Maritime Link Project forecasted equity contributions for 2016 and 2017 are $160 million and $156 million respectively, with total equity for the Project estimated to be $470.9 million.

Labrador Island Link (“LIL”)

ENL is a limited partner with Nalcor Energy in LIL, currently estimated at approximately $3.1 billion. As at March 31, 2016, ENL has invested $250.4 million, comprised of $224.5 million in equity contributed and $25.9 million of accumulated equity earnings in LIL. Equity earnings are recorded based on an annual rate of 8.8 per cent of the equity invested. The return on ROE is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”). There is currently an application filed by another regulated electrical utility in Newfoundland and Labrador, being heard by the NLPUB, which includes a review of ROE. The NLPUB’s decision on ROE, expected in Q2 2016, will be applicable for all regulated electrical utilities in Newfoundland and Labrador and become the ROE applicable to ENL’s investment in LIL. Future earnings are dependent on the amount and timing of additional equity investments and the approved ROE. Total equity contributions for Q1 2016 for LIL were $38.4 million.

LIL forecasted equity contributions for 2016 and 2017 are $196.0 million and $27.0 million respectively, with total equity investment, by Emera, in the Project estimated to be $409.1 million.

Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s consolidated balance sheets.

TRANSACTIONS WITH RELATED PARTIES

In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues, with an offset to property, plant and equipment, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction. Below are transactions between Emera and its associated companies reported in the Consolidated Statements of Income:

For the			Three months ended
millions of Canadian dollars			March 31
			2016			2015
	Nature of Service	Presentation
Sales to:
APUC subsidiary	Net sale of natural gas and transportation	Operating revenue – non-regulated	$	2.0		$	1.6
Purchases from:
M&NP	Natural gas transportation capacity	Regulated fuel for generation and purchased power		0.3		$	0.2
M&NP	Natural gas transportation capacity	Operating revenue – non-regulated	$	(8.1	)		(6.3	)

Operating revenue – non-regulated includes intercompany profit relating to the sale of natural gas, sale of power, construction, operations management and engineering services, and hedging services to rate-regulated subsidiaries of Emera totaling $0.3 million for the three months ended March 31, 2016 (2015 – $(0.2) million).

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Amounts reported on Emera’s Consolidated Balance Sheets due (to) from its equity investments are summarized in the following table:

As at	March 31		December 31
millions of Canadian dollars	2016		2015
Due from related parties:
NSPML – current	$	1.2	$	1.6
Subsidiary of APUC – current		0.3		0.7
M&NP – loan receivable – long-term		2.5		2.5
Due to related parties:
M&NP – current		2.3		2.1
Net due from (to) related parties	$	1.7	$	2.7

All amounts are under normal interest and credit terms, except for a loan receivable from M&NP bearing interest at 1 per cent per annum maturing on November 30, 2019.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Emera’s risk management profile and practices have not changed materially from December 31, 2015.

Hedging Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:

As at	March 31			December 31
millions of Canadian dollars	2016			2015
Derivative instrument assets (current and other assets)	$	11.7		$	19.8
Derivative instrument liabilities (current and long-term liabilities)		(28.5	)		(46.2	)
Net derivative instrument assets (liabilities)	$	(16.8	)	$	(26.4	)

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Hedging Impact Recognized in Net Income

The Company recognized gains (losses) related to the effective portion of hedging relationships under the following categories:

For the	Three months ended March 31
millions of Canadian dollars	2016			2015
Operating revenues – regulated	$	(3.2	)	$	(2.1	)
Non-regulated fuel for generation and purchased power		4.2			5.6
Income from equity investments		(0.3	)		(0.2	)
Effective net gains (losses)	$	0.7		$	3.3

The effectiveness gains (losses) reflected in the above table would be offset in net income by the hedged item realized in the period.

The Company recognized in net income the following gains (losses) related to the ineffective portion of hedging relationships under the following categories:

For the	Three months ended March 31
millions of Canadian dollars	2016			2015
Non-regulated fuel for generation and purchased power	$	(1.0	)	$	(0.6	)
Ineffective gains (losses)	$	(1.0	)	$	(0.6	)

Regulatory Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:

As at	March 31			December 31
millions of Canadian dollars	2016			2015
Derivative instrument assets (current and other assets)	$	131.3		$	209.9
Regulatory assets (current and other assets)		51.5			64.3
Derivative instrument liabilities (current and long-term liabilities)		(49.8	)		(64.3	)
Regulatory liabilities (current and long-term liabilities)		(131.3	)		(209.9	)
Net asset (liability)	$	1.7		$	—

Regulatory Impact Recognized in Net Income

The Company recognized the following net gains (losses) related to derivatives receiving regulatory deferral as follows:

For the	Three months ended March 31
millions of Canadian dollars	2016		2015
Regulated fuel for generation and purchased power (1)	$	3.0	$	(1.1	)
Net gains (losses)	$	3.0	$	(1.1	)

(1) Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

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Held-for-trading Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to HFT derivatives:

As at	March 31			December 31
millions of Canadian dollars	2016			2015
Derivative instruments assets (current and other assets)	$	33.7		$	95.3
Derivative instruments liabilities (current and long-term liabilities)		(141.8	)		(331.9	)
Net derivative instrument assets (liabilities)	$	(108.1	)	$	(236.6	)

Held-for-trading Items Recognized in Net Income

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in net income:

For the	Three months ended March 31
millions of Canadian dollars	2016			2015
Operating revenues – non-regulated	$	221.6		$	94.0
Non-regulated fuel for generation and purchased power		(0.7	)		0.2
Net gains (losses)	$	220.9		$	94.2

Other Derivatives Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to other derivatives:

As at	March 31			December 31
millions of Canadian dollars	2016			2015
Derivative instrument assets (current and other assets)	$	1.1		$	92.1
Derivative instrument liabilities (current and long-term liabilities)		(7.0	)		(2.9	)
Net derivative instrument assets (liabilities)	$	(5.9	)	$	89.2

Other Derivatives Recognized in Net Income

The Company recognized in net income the following gains (losses) related to other derivatives:

For the	Three months ended
millions of Canadian dollars	March 31
	2016			2015
Other income (expense)	$	(94.8	)	$	—
Interest expense, net		(0.3	)		—
Total gains (losses)	$	(95.1	)	$	—

DISCLOSURE AND INTERNAL CONTROLS

The Company, under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, has designed as at March 31, 2016 disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”). These terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”).

There have been no changes in Emera or its consolidated subsidiaries’ ICFR for the three months ended on March 31, 2016, which has materially affected, or is reasonably likely to materially affect the Company’s ICFR.

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CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made. Significant areas requiring the use of management estimates relate to rate-regulated assets and liabilities, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill impairment assessments, income taxes, including deferred taxes, asset retirement obligations, capitalized overhead and valuation of derivative instruments. Actual results may differ significantly from these estimates.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

The new US GAAP accounting policies that are applicable to, and were adopted by Emera, effective during 2016, are described as follows:

Income Statement – Extraordinary and Unusual Items, Accounting Standard Update (“ASU”) 2015-01

In January 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items, which simplifies the income statement presentation requirements by eliminating the concept of extraordinary items. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Consolidation, ASU 2015-02

In February 2015, the FASB issued ASU 2015-02, Consolidation, which changes the analysis a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Some of the more notable amendments are (1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the variable interest entity (“VIE”) characteristics for a limited partnership or similar entity and (3) the primary beneficiary determination. All legal entities are subject to re-evaluation under the revised consolidation model. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Interest – Imputation of Interest, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented on the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected. The Company has adopted this standard effective Q1 2016 and December 31, 2015 balances have been retrospectively restated. This change resulted in $62.3 million of deferred financing costs, as at December 31, 2015, previously presented as other assets, being reclassified as a deduction from the carrying amount of the related long-term debt and convertible debentures represented by instalment receipts on the Consolidated Balance Sheets.

In accordance with ASU 2015-15 Interest: Imputation of Interest, the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments in other long-term assets on its Consolidated Balance Sheets.

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Compensation – Retirement Benefits, ASU 2015-04

In April 2015, the FASB issued ASU 2015-04, Compensation – Retirement Benefits, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard provides certain practical expedients for defined benefit pension or other post-retirement benefit plan measurement dates. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Intangibles – Goodwill and Other – Internal-Use Software, ASU 2015-05

In April 2015, the FASB issued ASU 2015-05, Intangibles – Goodwill and Other – Internal-Use Software, which provides guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer would account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer would account for the arrangement as a service contract. The guidance does not change GAAP for a customer’s accounting for service contracts. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Technical Corrections and Improvements, ASU 2015-10

In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Improvements, covering a wide range of topics in the codification to correct unintended application of guidance, or make minor improvements to the Codification. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Inventory – Simplifying the Measurement of Inventory, ASU 2015-11

In July 2015, the FASB issued ASU 2015-11, Inventory – Simplifying the Measurement of Inventory. The amendments require an entity to measure inventory at the lower of cost or net realizable value, whereas previously, inventory was measured at the lower of cost or market. ASU 2015-11 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016. Early adoption is permitted for any interim or annual financial statements that have not yet been issued. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships, ASU 2016-05

In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships. The standard clarifies that a change in the counterparty to a derivative contract, in and of itself, does not require the de-designation of a hedging relationship provided that all other hedge accounting criteria continue to be met. ASU 2016-05 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and early adoption is permitted. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

Investments – Equity Method and Joint Ventures, ASU 2016-07

In March 2016, the FASB issued ASU 2016-07, Investments – Equity Method and Joint Ventures, which is part of FASB’s initiative to reduce complexity in accounting standards. This standard eliminates the requirements of an investor to retroactively account for an investment under the equity method when an investment qualifies for equity method accounting. ASU 2016-07 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016, with early adoption permitted. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements.

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Future Accounting Pronouncements

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework and a new topic in the Accounting Standards Codification (“ASC”), Topic 606. ASC 606 also changes the basis for determining when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific aspects of revenue recognition and expands revenue disclosures. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers: Principal versus Agent Considerations. The amendments are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU 2016-10 Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing. The guidance will be effective beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The Company is continuing to evaluate the impact of adoption of these standards on its consolidated financial statements.

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities, ASU 2016-01

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. ASU 2016-01 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

Leases (Topic 842), ASU 2016-02

In February 2016, the FASB issued ASU 2016-02, Leases. The standard increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for lease terms of more than 12 months. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. ASU 2016-02 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and will be applied using a modified retrospective approach. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements.

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SUMMARY OF QUARTERLY RESULTS

For the quarter ended
millions of dollars	Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2
(except per share amounts)	2016		2015		2015		2015		2015		2014		2014		2014
Operating revenues	$	877.0	$	731.6	$	642.3	$	526.9	$	888.5	$	782.7	$	539.0	$	566.6
Net income attributable to common shareholders		44.3		192.1		35.0		10.0		160.1		151.2		28.2		24.5
Adjusted net income attributable to common shareholders		120.2		87.1		23.3		48.0		171.6		78.5		49.9		44.2
Earnings per common share – basic		0.30		1.31		0.24		0.07		1.10		1.05		0.20		0.17
Earnings per common share – diluted		0.30		1.30		0.24		0.07		1.09		1.02		0.20		0.17
Adjusted earnings per common share – basic		0.81		0.59		0.16		0.33		1.18		0.54		0.35		0.31

Quarterly operating revenues and net income attributable to common shareholders are affected by seasonality. The first quarter is generally the strongest because a significant portion of the Company’s operations are in northeastern North America, where winter is the peak electricity season. As the energy industry is seasonal in nature for companies like Emera, seasonal and other weather patterns, as well as the number and severity of storms, can affect the demand for energy and the cost of service. Quarterly results could be affected by items outlined in the Significant Items section and mark-to-market adjustments.

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EX-4.6

Exhibit 4.6

Emera

Incorporated

Notice of Annual and Special Meeting of Common Shareholders

Tuesday, May 17, 2016 and Management Information Circular

Dear Fellow Shareholders:

We invite you to attend the annual and special meeting of the common shareholders of Emera Incorporated, which will be held at the Design Exchange, 234 Bay St., Toronto, Ontario, on Tuesday, May 17, 2016 at 2:00 p.m. (Eastern Time).

The Board of Directors and the executive team look forward to meeting with you to present our analysis of our 2015 financial results and outline our plans for the future.

Please take time to read this document. The Management Information Circular contains important information about the business to be conducted at the annual meeting, about the Directors nominated for election, how we compensate our executive officers and Directors and about our corporate governance practices. If you cannot attend the annual meeting, please use the proxy or voting instruction form provided to you in order to submit your vote prior to the meeting. It is important to us that your shares be counted.

Live coverage of the annual meeting will be available on our website at www.emera.com/investors.

A recording of the meeting will be available on the site for several weeks following the meeting.

We hope you can join us.

Sincerely,

Jackie Sheppard

Chair of the Board

Christopher Huskilson

President and Chief Executive Officer

Table of Contents

Notice of Annual and Special Meeting	1
Management Information Circular	2
Business of the Meeting	4
Director Nominees	7
Skills and Experience	8
Statement of Corporate Governance Practices	24
Letter from the Management Resources and Compensation Committee to Shareholders	36
Statement of Executive Compensation	39
Compensation Discussion and Analysis	43
Performance Graph	54
NEO Summary Compensation Table	56
Appendix “A” – Board of Directors Charter	66
Appendix “B” – Amended Articles of Association	68

Notice of Annual and Special Meeting

Tuesday, May 17, 2016	Design Exchange	Record Date
2:00 p.m. Eastern Time	234 Bay Street	Close of business
	Toronto, Ontario	March 28, 2016

Items of Business

1. Electing Directors to serve until the next annual meeting of shareholders;

2. Appointing Auditors;

3. Authorizing the Directors to establish the Auditors’ fee;

4. To consider an advisory resolution on the Company’s approach to executive compensation;

5. Approving amendments to the Company’s Articles of Association; and

6. Transacting such other business as may properly come before the meeting.

As a shareholder, it is important that you vote. Common shareholders are encouraged to return their proxy or voting instruction form as soon as possible. A postage-paid, pre-addressed envelope is provided. As an alternative, shareholders may choose to vote by telephone or on Internet as provided for on the proxy or voting instruction form. Proxies must be received prior to 5:00 p.m. Eastern time on Monday, May 16, 2016, or if the meeting is adjourned, at least 48 hours (not including Saturdays, Sundays, or statutory holidays in Nova Scotia) prior to the reconvened meeting.

Should you have questions or comments, you may contact Emera Incorporated by writing to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, Nova Scotia B3J 2W5, by calling 1-800-358-1995 from anywhere in North America or (902) 428-6060 within the Halifax-Dartmouth area.

Stephen D. Aftanas

Corporate Secretary

Emera Inc. — Management Information Circular 2016          1

MANAGEMENT INFORMATION CIRCULAR

Information as of March 17, 2016

(unless otherwise noted)

Meeting Materials and Notice and Access

Canadian securities rules (“Notice and Access”) permit Emera Incorporated (the “Company” or “Emera”) to provide you with electronic access to this Management Information Circular (the “Circular”) and the 2015 Annual Report (the “Meeting materials”) for the annual and special meeting of common shareholders (“Shareholders”) instead of sending you a paper copy. This year, Emera is sending Meeting materials to registered holders and beneficial owners using Notice and Access. It is more environmentally friendly as it helps reduce paper use. The notice you received includes instructions on how to access and review an electronic copy of the Meeting materials or how to request a paper copy. The notice also provides instructions on voting by proxy at the meeting. If you would like to receive a paper copy of the Meeting materials, please follow the instructions in the notice.

For those Shareholders who have previously provided instructions to receive paper copies of Meeting materials, we sent you a paper copy in addition to the notice regarding their electronic availability.

Solicitation of Proxies

This Circular is furnished in connection with the solicitation of proxies by the Board of Directors and management of Emera for use at the annual and special meeting (“Meeting”) of Shareholders of the Company to be held on Tuesday, May 17, 2016, as set forth in the Notice of Annual and Special Meeting (the “Notice”).

You have received a proxy or voting instruction form. The solicitation of proxies will be primarily by mail although proxies may also be solicited by telephone, facsimile, in writing, or in person, by Directors, Officers, or other employees or agents of the Company.

The Company wishes to have as many Shareholders vote as possible and has retained D.F. King Canada as the proxy solicitation agent to assist with the solicitation of votes from Shareholders. The proxy solicitation agent will monitor the number of Shareholders voting and will contact Shareholders in order to increase participation in voting. The cost of this solicitation will be borne by the Company and is not expected to exceed $50,000.

Record Date and Voting of Shares

The date for determining which Shareholders are entitled to receive the Notice is Monday, March 28, 2016. This is called the “Record Date”. Only Shareholders of record at the close of business on the Record Date will be entitled to vote. Each common share owned as of the Record Date entitles the holder to one vote.

To the knowledge of the Directors and Officers, as of the date of this Circular, no person owned or exercised control over more than 10 per cent of the outstanding common shares of the Company and the only outstanding voting shares were 148,327,777 common shares.

Beneficial (or Non-Registered) Owners

The voting process is different depending on whether you are a registered Shareholder, Non-Objecting Beneficial Owner or Objecting Beneficial Owner.

If you have shares registered in your own name, you are a registered Shareholder. If you do not hold shares in your own name, you are a beneficial or non-registered owner. If your shares are listed in an account statement provided to you by a broker, then it is likely that those shares will not be registered in your name, but under the broker’s name or under the name of an agent of the broker such as CDS Clearing and Depository Services Inc., the nominee for many Canadian brokerage firms, or its nominee.

There are two kinds of beneficial owners: (i) Objecting Beneficial Owners – those who object to their name being made known to the issuers of shares which they own and (ii) Non-Objecting Beneficial Owners – those who do not object to their name being made known to the issuers of the shares which they own. Non-Objecting Beneficial Owners will receive a voting instruction form from Emera’s registrar and transfer agent, CST Trust Company (“CST”). This is to be completed and returned to CST in the envelope provided. In addition, CST provides both telephone voting and Internet voting as described on the voting instruction form.

Securities regulation requires brokers or agents to seek voting instructions from Objecting Beneficial Owners in advance of the Meeting. Objecting Beneficial Owners should be aware that brokers or agents can only vote shares if instructed to do so by the Objecting Beneficial Owner. Your broker or agent (or their agent Broadridge) will have provided you with a voting instruction form or form of proxy for the purpose of obtaining your voting instructions. Every broker has its own mailing procedures and provides instructions for voting. You must follow those instructions carefully to ensure your shares are voted at the Meeting.

If you are an Objecting Beneficial Owner receiving a voting instruction form or proxy from a broker or agent, you cannot use that proxy to vote in person at the Meeting. To vote your shares at the Meeting, the voting instruction form or proxy must be returned to the broker well in advance of the Meeting. If you wish to attend and vote your shares in person at the Meeting, follow the instructions for doing so provided by your broker or agent.

2          Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Shareholder Proxy Materials

These security holder materials are being sent to both registered and non-registered owners of the securities. If you are a non-registered owner, and the issuer or its agent has sent these materials directly to you, your name, address, and information about your holdings of securities, have been obtained in accordance with applicable securities regulatory requirements from the intermediary holding on your behalf. Emera has arranged for its registrar and transfer agent, CST, to send materials directly to Non-Objecting Beneficial Owners. Emera will bear the cost of delivering shareholder proxy materials to registered Shareholders, Non-Objecting Beneficial Owners and Objecting Beneficial Owners.

By choosing to send these materials to you directly, Emera (and not the intermediary holding on your behalf) has assumed responsibility for (i) delivering these materials to Non-Objecting Beneficial Owners, and (ii) executing their proper voting instructions. Please return voting instructions as specified in the voting instruction form or form of proxy.

Appointment and Revocation of Proxies

The persons named in the enclosed proxy are Jackie Sheppard, Chair of the Board, and Christopher Huskilson, President and Chief Executive Officer, both of whom are Directors of the Company, and Stephen Aftanas, who is Corporate Secretary of the Company.

In order for a vote by proxy or voting instruction form to be counted, it should be received prior to 5:00 p.m. (Eastern Time) on Monday, May 16, 2016. The Company reserves the right to accept late proxies and to waive the proxy cut-off with or without notice, but is under no obligation to accept or reject any particular late proxy. For Canadian residents, a postage-paid, pre-addressed envelope is provided for this purpose. In order for your vote to be counted, you may vote by proxy or voting instruction form via mail, the Internet or telephone. If you are a registered Shareholder or a Non-Objecting Beneficial Owner, you may attend the Meeting in person and submit your completed proxy or vote by ballot.

Completion of a proxy gives discretionary authority to the proxyholder to vote as he or she sees fit in respect of amendments to matters identified in the Notice, and other matters that may properly come before the Meeting or any adjournment thereof, whether or not the amendment or other matter that comes before the Meeting is or is not routine, and whether or not the amendment or other matter that comes before the Meeting is contested. Management of the Company is not aware of any amendments or other matters to be presented for action at the Meeting.

If you appoint Ms. Sheppard, Mr. Huskilson or Mr. Aftanas as your proxyholder, they will vote, or withhold from voting, in accordance with your directions. If you do not specify how you want your shares voted, they will vote “For” the:

• election of Directors named in this Circular;

• appointment of Ernst & Young LLP as Auditors;

• authorization of the Directors to establish the Auditors’ fee;

• advisory resolution on the Company’s approach to executive compensation; and

• approval of the amendments to the Company’s Articles of Association.

They will vote in accordance with their best judgment if any other matters are properly brought before the Meeting.

You may appoint any other person (who need not be a Shareholder) to represent you at the Meeting by inserting that person’s name in the space provided on the accompanying proxy. That person is your proxyholder and must attend and vote at the Meeting in order for your vote to count.

You may revoke your proxy by providing new voting instructions in a new proxy or voting instructions form with a later date, or at a later time if you are voting on Internet or by telephone. Any new voting instructions, however, will only take effect if received prior to 5:00 p.m. (Eastern Time) on Monday, May 16, 2016 or if the meeting is adjourned, at least 48 hours (not including Saturdays, Sundays or statutory holidays in Nova Scotia) prior to the reconvened meeting. You may also revoke your proxy without providing new voting instructions by giving written notification addressed to Mr. Stephen Aftanas, Corporate Secretary, P.O. Box 910, Halifax, Nova Scotia, B3J 2W5, no later than the last business day preceding the day of the Meeting or any postponement or adjournment thereof or with the Chair of the Meeting on the day of the Meeting or any postponement or adjournment thereof or in any other manner permitted by law. Registered shareholders may attend the Meeting and vote in person and, if they do so, any voting instructions previously given by such persons for such shares will be revoked.

Restrictions on Share Ownership and Voting

Under Nova Scotia legislation, no Emera Shareholder may own or control, directly or indirectly, more than 15 per cent of the outstanding voting shares. Shareholders who are not residents of Canada may not hold, in the aggregate, more than 25 per cent of the outstanding voting shares.

These restrictions may be enforced by limiting non-complying Shareholders’ voting rights, dividend rights and transfer rights. Shareholders may be required, at any time, to furnish a statutory declaration to verify the number of shares held and/or residency in order to ensure compliance with these restrictions.

If you have any questions about share ownership and voting restrictions, please contact the Corporate Secretary using the contact information contained in the Notice above.

Emera Inc. — Management Information Circular 2016          3

Business of the Meeting

1. Election of the Board of Directors: The 12 nominees proposed for election as Directors at the 2016 Meeting are identified under Director Nominees in this Circular. For more information about the process for nominating Directors, see Nomination of Directors in the Statement of Corporate Governance Practices.

All nominees are currently Directors of the Company. Each nominee has indicated his or her willingness to serve as a Director. Each Director elected at the Meeting will hold office until the next Annual Meeting of Shareholders.

Ms. Sheppard, Mr. Huskilson and Mr. Aftanas intend to vote “For” the 12 nominees unless instructed otherwise by Shareholders in their proxy.

2. Appointment of Auditors: The Audit Committee has reviewed the performance of Ernst & Young LLP, including its independence relating to the audit and recommends the re-appointment of Ernst & Young LLP as Auditors. Ernst & Young LLP have been Auditors of the Company since its inception in 1998, and before that were Auditors of the Company’s subsidiary, Nova Scotia Power Inc. (NSPI), since 1991.

Ms. Sheppard, Mr. Huskilson and Mr. Aftanas intend to vote “For” the re-appointment of Ernst & Young LLP as Auditors of the Company, to hold office until the close of the next Annual Meeting of Shareholders, unless a Shareholder specifies their shares be withheld from voting.

3. Auditors’ Fee: The Company is incorporated under the Nova Scotia Companies Act. Shareholder approval of the authorization of Directors to establish the Auditors’ fee is required pursuant to the Companies Act. The aggregate fees billed by Ernst & Young LLP, during the last two fiscal years ended December 31, 2014 and December 31, 2015, were as follows:

Service Fee	2015 ($)		2014 ($)
Audit Fees		1,167,187		1,074,859
Audit-Related Fees		242,568		342,664
Tax Fees		544,615		298,531
All Other Fees		125,000		Nil
Total		2,079,370		1,716,054

Ms. Sheppard, Mr. Huskilson and Mr. Aftanas intend to vote “For” the authorization of Directors to establish the Auditors’ fee, unless a Shareholder instructs otherwise in their proxy.

4. Advisory Vote on Executive Compensation: You will be asked to consider and approve, on an advisory basis, a resolution on Emera’s approach to executive compensation as disclosed in this Circular.

Our executive compensation programs are designed to attract, retain, motivate and reward high-calibre leaders to deliver strong performance in alignment with Emera’s corporate strategy and to create and sustain shareholder value. Programs are designed to reflect a blend of short- and long-term incentive plans to reflect our pay-for-performance philosophy and to provide for a significant portion of an executive’s compensation to be at risk, while aligning the structure of programs and payouts with sound risk management and good governance principles.

The Board, through the MRCC, has directed and reviewed the contents of the Statement of Executive Compensation in this Circular and has unanimously approved it as part of the Committee’s report to you.

As our shareholder, on an advisory basis, you have the opportunity to vote “For” or “Against” our approach to executive compensation through the following resolution:

“BE IT RESOLVED, on an advisory basis, and not to diminish the role and responsibilities of the Board of Directors, that the shareholders accept the approach to executive compensation disclosed in the Company’s information circular delivered in advance of the 2016 annual and special meeting of shareholders.”

Since your vote is advisory, it will not be binding on the Board, however, the Board and, in particular the MRCC, will seriously consider the outcome of the vote as part of its ongoing review of executive compensation.

Unless otherwise instructed, Ms. Sheppard, Mr. Huskilson and Mr. Aftanas intend to vote “For” the advisory resolution on executive compensation.

4           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

5. Approval of the Amendments to the Company’s Articles of Association:

Background

The Articles of Association of Emera (the “Articles”) adopted on incorporation were repealed and replaced in 1998 to comply with the Nova Scotia Power Reorganization (1998) Act. They were further amended in 2001 (to adopt a retirement age for Directors) and 2007 (to reduce from 10 the minimum size of the Board to eight Directors).

In the fall of 2015, the Company conducted a thorough review of the Articles and proposes that they be amended and restated. The primary intent of the substantive amendments proposed is to modernize aspects of the Articles to reflect developments in technology, business practice, governing law and the regulatory environment. There are a broad range of amendments proposed and the significant amendments include such matters as: the adoption of a requirement for advance notice of director nominations, an increase in the quorum for shareholder meetings, a simplification of the description of the committee structure, and provision for electronic voting to take advantage of future developments from time to time in law, voting technology and practices. Other amendments are also included to update the Articles to reflect changes in the law, and to effect housekeeping and drafting cleanup changes.

In drafting these proposed amendments, the Company sought external legal counsel and other third party advice in order that the amendments were reviewed from a shareholder’s perspective to confirm they do not impede shareholder rights, or derogate from the existing rights. On the basis of those consultations, we believe the amendments respect and in some cases, enhance shareholders’ interest.

The Board of Directors, on the recommendation of the Nominating and Corporate Governance Committee, approved the amendments as shown in detail in a redlined version of the Articles attached to the Circular as Appendix B, which you will be asked to approve. The major amendments are summarized below:

Proposed Amendments	New Article Numbers
Interpretation Provision Addition of an interpretive paragraph intended to ensure that the Articles are not read narrowly in the face of technological developments, whether or not yet known, which are not expressly contemplated by the Articles. For example, references to meetings occurring at a particular place should not in the future be read to preclude telephonic meetings.	2
Record Date and Other Dates Amendments to conform the timeframe for setting record dates and other dates to securities rules and, subject to applicable law, to provide for more flexibility in calling meetings and otherwise fixing dates.	51, 67, 70, 178
Advance Notice Provision Amendments requiring advance notice of director nominations and confirming that business to be brought by shareholders before the meeting is limited to the items specified in the notice of meeting or shareholder proposal submitted pursuant to the Companies Act. Advance notice of director nominations generally must be provided for general meetings at least 30 days prior to the meeting date. But if there is less than 50 days between the date of announcement of the meeting date and the meeting date, the deadline is 10 days after the meeting date is announced. For special meetings involving director elections, the deadline is 15 days following the announcement of the special meeting date. The notice must contain specific information about: (i) the proposed nominee, including name, age, addresses, occupation, and holdings of the Company’s shares; (ii) the nominating shareholder, including holdings of the Company’s shares; and (iii) the proposed nominee’s independence. The chair of the meeting is given the power to determine whether a nomination was made in accordance with the procedures. The Board may in its discretion waive any of the advance notice requirements for director nominations.	68, 69
Electronic Voting Changes in meeting procedures and voting procedures reflect modern technology. The changes allow the board to authorize and adopt procedures for shareholders and proxyholders not physically present at a meeting of shareholders to participate and vote in the meeting by means of a telephonic, electronic or other communication facility, and permit ‘virtual’ shareholder meetings.	73, 81
Board Meetings The changes clarify the ability of directors to attend and participate and vote at Board meetings by means of a telephonic, electronic or other communication facility. Certain other procedural matters are clarified.	115, 116, 119, 121, 122
Quorum and General Meeting Procedures Amendments to increase shareholder quorum requirements to 25 per cent, and update and clarify rules for proceedings at general meetings, including clarifying that the Board Chair does not have a second or casting vote.	70, 71, 75, 76, 78, 79, 82, 83, 85, 109

Emera Inc. — Management Information Circular 2016          5

Proposed Amendments (continued)	New Article Numbers
Proxy Voting Amendments to provide greater specifics dealing with proxy voting consistent with accepted practice.	89, 90, 92, 93, 94
Committees Amendments streamlining rules dealing with Board committees to give further discretion to directors to establish and regulate committees for better governance.	99, 105, 108, 123–130
Indemnity Provision Amendments modernizing director and officer indemnity provisions.	172, 173
Dividends, Financial Statements, and other changes in Law Amendments to address changes in Nova Scotia corporate law applicable to the Company, including in respect of the declaration and payment of dividends, the keeping of registers, borrowing, and financial statements, or to make the Articles more consistent with existing corporate law.	50, 56, 57, 60, 107, 131, 132, 134, 142, 155, 157, 159, 160, 161
Alteration of Capital Amendments in respect of alteration and reduction of capital. Notably, probably due to the provisions of the Nova Scotia Power Privatization Act, the Articles as initially prepared did not include language enabling future creation or redemption of classes of shares. For clarity, the alteration and reduction of capital pursuant to these amendments in each case requires shareholder approval.	52, 53, 54, 55
Further Amendments Housekeeping and drafting clean-up amendments which include:
(a)    Adding and amending definitions (i) to define capitalized terms used in the Articles which were not previously defined and other terms which do not have particular meaning at law; (ii) to make clear that certain inconsistent terms used in the Articles have the same meaning.	1
(b)    Modernizing language to reflect current standard practice (for example, references to “monies” are now to “funds” or “amounts”, terms like “debenture stock” are deleted).	8, 21, 25, 26, 143, 147, 148, 152
(c)    Changes made for internal consistency (for example consistent use of defined terms and consistent capitalization).	6, 17, 20, 30, 38, 47, 64, 65, 66, 74, 86, 95, 100, 117, 136, 157, 163, 164, 166, 181
(d)    Other changes for language clarity.	58, 97, 101, 102, 114, 119, 136, 137, 140, 165
(e)    Providing for officers of the Company other than those expressly listed.	112, 113
(f)    In respect of share certificates and share transfers, allowing the board to provide for direct registration and uncertificated shares when applicable and to adopt other modern practices.	14, 15, 18, 40, 182
(g)    Changes to address typographical errors and other apparent errors in and omissions from the earlier Articles.	46
(h)    Provisions modernizing the notice requirements.	162, 167, 169, 170
(i)    Deleting provision which is no longer applicable.	former Article 5

Shareholders are being asked to approve the amendments to and restatement of the Articles. At the Meeting, Shareholders will be asked to consider and, if deemed appropriate, to pass, with or without variation, a special resolution (meaning that a majority of not less than three-fourths of Shareholders entitled to vote as are present in person or by proxy must vote in favour of the resolution), in the form set out below, subject to such amendments, variations or additions as may be approved at the Meeting, approving the amendment and restatement to the Articles.

6           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Resolution Approving the Amendments to the Articles

The text of the resolution approving the amendments to the Articles to be put before shareholders at the Meeting is as follows:

“BE IT RESOLVED as a special resolution of the Company that:

1. the Articles of Association of the Company be repealed and new Articles of Association in the form attached hereto as Appendix B be and are hereby adopted;

2. the amendments provided for hereby shall not in any way prejudice or affect any acts, matters or things done or performed by the shareholders, directors, officers or agents of the Company pursuant to existing Memorandum of Association and Articles of Association of the Company; and

3. any officer or director of the Company be and is hereby authorized and directed to do all things and execute all documents, under the corporate seal where required, necessary or desirable to give effect to the foregoing.”

The new Articles of Association referred to in the above resolution are those attached as Appendix B to this Circular, except that Appendix B includes markings to show changes to the current Articles, which markings are not part of the new Articles of Association.

Where text is underlined in Appendix B that text is being added in the new Articles of Association. Where text is struck-through in Appendix B it is being deleted in the new Articles of Association. Text which is neither underlined nor struck-through is not being changed.

Board’s Recommendation

For the reason indicated above, the Board and Management of the Company unanimously recommend that Shareholders vote for the Amendments to the Articles. Unless the Amendments to the Articles are approved by three-fourths of the votes cast at the Meeting by shareholders voting in person or by proxy, it will not come into force or effect.

Unless otherwise instructed, Ms. Sheppard, Mr. Huskilson and Mr. Aftanas intend to vote “For” the resolution approving the amendment to and restatement of the Articles.

Director Nominees

The following pages set out the names of the nominees proposed for election as Directors of Emera. Biographical information about the Director nominees is also provided, including, age, municipality and country of residence, year first elected or appointed as a Director, principal occupation, education, skills and experience. The information about each Director nominee includes Committee memberships and meeting attendance. Their membership on other public company boards in the last five years is also described.

There is information about the common shares and Deferred Share Units (DSUs) of Emera held by each Director nominee for the past three years. The estimated value of each Director nominee’s common shares and DSUs holdings is based on the following:

Year-end	Closing price of Emera common shares ($)
December 31, 2013	30.57
December 31, 2014	38.64
December 31, 2015	43.23

All Director nominees are required to meet share ownership guidelines. The information below details their status under those guidelines. For further information on the share ownership guidelines for Directors, see Director Share Ownership Guidelines in the Statement of Corporate Governance Practices later in this Circular. For further information on the share ownership guidelines for the Company’s executive officers, including Mr. Huskilson, President and Chief Executive Officer, see Executive Share Ownership Requirements in the Statement of Executive Compensation.

All Director nominees, except Mr. Huskilson, are considered by the Board to be independent. For more information about the Company’s definition of independence, see Director Independence in the Statement of Corporate Governance Practices later in the Circular.

Emera Inc. — Management Information Circular 2016          7

Skills and Experience Total

The above bar-chart shows eight categories of skills and experience important to the Company’s business and governance (along the vertical axis), and that number of the 12 Director nominees who possess those skills and experience (along the horizontal axis). The details of each Director nominee’s skills and experience are contained in their biographies later in this Circular.

The voting results for those Directors who were nominees for election in the 2015 annual meeting of shareholders are shown in the two rows below.

Percentage of votes cast “For” each Director (%)		99.58		96.4		98.88		99.06		98.95		99.59		99.69		98.94		97.44		99.03		99.46		98.36
Percentage of votes cast “Withheld” (%)		0.42		3.6		1.12		0.94		1.05		0.41		0.31		1.06		2.56		0.97		0.54		1.64

8           Emera Inc. — Management Information Circular 2016

Sylvia Chrominska

Age: 64

Toronto, Ontario

Canada

Director Since: 2010

Independent

Skills and Experience

• CEO/Senior Executive

• Customer/Stakeholder

• M&A/Growth Strategy

• Governance/Other Directorship

• Financial

• Compensation and Human Resources

• Legal and Regulatory

MANAGEMENT INFORMATION CIRCULAR

Ms. Chrominska has been a Director since September 2010. She has been a member of the Management Resources and Compensation Committee since November 2010, and was a member of the Nominating and Corporate Governance Committee from June 2012 to September 2014. She was Chair of the ad hoc Pension Governance Committee from its inception in November 2013 until its termination in May 2014.

Ms. Chrominska is the former Group Head of Global Human Resources and Communications for The Bank of Nova Scotia, where she had global responsibility for human resources, corporate communications, government relations, public policy and corporate social responsibility of the Scotiabank Group. Ms. Chrominska is former Chair of the Board of Scotia Group Jamaica Limited. She is also former Chair of the Board of Scotiabank Trinidad and Tobago Limited. Ms. Chrominska is also a director of Wajax Corporation.

Ms. Chrominska graduated from the University of Western Ontario with an Honours Degree in Business Administration. She also serves on the Dean’s Advisory Board at the Richard Ivey School of Business. She was appointed to the Board of Governors of the University of Western Ontario in November 2015.

Ms. Chrominska’s 30-year career in the banking sector has provided her with valuable skills and knowledge in financial and credit matters. In particular, the experience she has gained through her senior executive leadership roles, with responsibilities encompassing a broad spectrum of areas within a complex, global business organization, is a distinct asset.

Board/Committee Membership	Attendance	Total	Public company board membership during the last five years
•    Board Member •    Management Resources and Compensation Committee Member	11 of 11     4 of 4	100%     100%	•    Wajax Corporation (May 2015 to present) •    Scotia Group Jamaica Limited (2009 to March 2016) •    Scotiabank Trinidad and Tobago Limited (January 2013 to March 2015)

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
136,875	N/A	136,875

DSUs Awarded and Held
2015 share-based     awards ($)	Total 2015 increase in value     of all DSUs held ($)	Market value of total     DSUs holdings ($)
118,906	221,970	756,439

Instalment Receipts (1)
Number of Instalment Receipts Held	30

Securities Held
Year	Common   Shares	DSUs	Value of shares   and DSUs ($)	Status under share ownership guidelines
2015   2014   2013	1,813   1,813   1,813	17,498   13,832   9,645	834,815   604,523   350,271	Ms. Chrominska owns shares and DSUs valued at 192% of the requirement under the Share Ownership Guidelines; therefore, the Guidelines are met.

(1) Convertible debentures were sold by Emera on an instalment basis at a price of $1,000 per debenture, with the first instalment of $333 payable on the closing of the offering. Instalment receipts represent the first instalment payment. See the definition of “Instalment Receipts” and the description of convertible debentures for more information in the section later in this Circular entitled “Convertible Debentures”.

Emera Inc. — Management Information Circular 2016          9

Henry Demone

Age: 61

Lunenburg, Nova Scotia

Canada

Director Since: 2014

Independent

Skills and Experience

• CEO/Senior Executive

• Customer/Stakeholder

• M&A/Growth Strategy

• Governance/Other Directorship

• Compensation and Human Resources

Mr. Demone joined the Emera Board of Directors in September 2014. He also became a member of the Management Resources and Compensation Committee at that time.

He is the Chairman of High Liner Foods of Lunenburg, Nova Scotia, the leading North American processor and marketer of value-added frozen seafood. He was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 until May 2015.

Mr. Demone currently sits on the Board of Saputo Inc. He is past-Chair of the Fisheries Council of Canada and The Groundfish Forum, a global trade association representing industry leaders. He has served on the Boards of Dover Industries Ltd. and Maritime Tel & Tel (Aliant). Mr. Demone was also the first non-US citizen to be named Chair of the National Fisheries Institute, a US national trade association.

Mr. Demone received his Bachelor of Science in Mathematics with honours from Acadia University.

In both public and private entities, Mr. Demone has extensive experience in strategic planning, global markets, mergers and acquisitions. As a long-time business leader in Atlantic Canada, Mr. Demone’s robust business relationships and his solid reputation make him a valuable member of Emera’s Board of Directors.

Board/Committee Membership	Attendance	Total	Public company board membership during the last five years
•    Board Member •    Management Resources and Compensation Committee	11 of 11     3 of 4	100%     75%	•    High Liner Foods Inc. (1989 to present) •    Saputo Inc. (2012 to present)

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
134,250	N/A	134,250

DSUs Awarded and Held
2015 share-based     awards ($)	Total 2015 increase in value     of all DSUs held ($)	Market value of total     DSUs holdings ($)
134,250	158,307	194,319

Instalment Receipts
Number of Instalment Receipts Held	170

Securities Held
Year	Common   Shares	DSUs	Value of shares   and DSUs ($)	Status under share ownership guidelines
2015   2014	5,000   Nil	4,495   932	410,469   36,012	Mr. Demone owns shares and DSUs valued at 94% of the requirement under the Share Ownership Guidelines. He has until January 2021 to meet the Guidelines.

10          Emera Inc. — Management Information Circular 2016

Allan Edgeworth

Age: 65

Calgary, Alberta

Canada

Director Since: 2005

Independent

Skills and Experience

• CEO/Senior Executive

• Customer/Stakeholder

• M&A/Growth Strategy

• Governance/Other Directorship

• Financial

• Energy Sector

• Compensation and Human Resources

• Legal and Regulatory

MANAGEMENT INFORMATION CIRCULAR

Mr. Edgeworth has been a Director since November 2005. He has been a member of the Management Resources and Compensation Committee since February 2006 and has been serving as Committee Chair since May 2010.

Mr. Edgeworth was a member of the Audit Committee from April 2008 to May 2013. From May 2007 to April 2008, Mr. Edgeworth was a member of the Nominating and Corporate Governance Committee. He also served as a Director of Nova Scotia Power Inc. from November 2005 to October 2006.

Mr. Edgeworth is former President of ALE Energy Inc. and is also a Director of AltaGas Ltd. Previously he was the President and Chief Executive Officer of Alliance Pipeline. Until March 31, 2012, he was a Commission Member and Director of the Alberta Securities Commission. He is also a former Director of Pembina Pipeline Corporation. Mr. Edgeworth has also served on the Boards of the Interstate National Gas Association of America and the Canadian Gas Association. He is past Chair of the Canadian Energy Pipeline Association.

Mr. Edgeworth holds a Bachelor of Applied Science from the University of British Columbia in Geological Engineering and is a graduate of the Queen’s Executive Program. His extensive experience as a senior leader in the energy sector combined with his expertise in corporate governance makes Mr. Edgeworth a valuable member of the Board.

Board/Committee Membership	Attendance	Total	Public company board membership during the last five years
•    Board Member •    Management Resources and Compensation Committee Chair	11 of 11     4 of 4	100%     100%	•    AltaGas Ltd. (previously AltaGas Income Trust) (March 2005 to present) •    Pembina Pipeline Corporation (July 2006 to May 2014)

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
154,500	N/A	154,500

DSUs Awarded and Held
2015 share-based     awards ($)	Total 2015 increase in value     of all DSUs held ($)	Market value of total     DSUs holdings ($)
109,750	332,011	1,606,513

Instalment Receipts
Number of Instalment Receipts Held	60

Securities Held
Year	Common   Shares	DSUs	Value of shares   and DSUs ($)	Status under share ownership guidelines
2015   2014   2013	1,000   1,000   1,000	37,162   32,984   28,547	1,649,743   1,313,142   903,252	Mr. Edgeworth owns shares and DSUs valued at 379% of the requirement under the Share Ownership Guidelines; therefore, the Guidelines are met.

Emera Inc. — Management Information Circular 2016          11

James Eisenhauer, FCPA, FCA

Age: 64

Lunenberg, Nova Scotia

Canada

Director Since: 2011

Independent

Skills and Experience

• CEO/Senior Executive

• Customer/Stakeholder

• Governance/Other Directorship

• Financial

Mr. Eisenhauer has been a Director of the Company since May 2011. He is Chairman of the Board of Directors of Emera’s subsidiary, Nova Scotia Power Inc., having served on its Board since 2008.

He is President and Chief Executive Officer of ABCO Group Limited, which has holdings in manufacturing and distribution. He is a Professional Engineer and a Fellow of the Chartered Professional Accountants of Nova Scotia. Mr. Eisenhauer was a member of the Board of Nova Scotia Business Inc. from 2005 to January 2013, serving as Chair from November 2010 to October 2012. He has also been a member of the Board Stelia Aerospace North America Inc. since 2014 (and its predecessors Composites Atlantic Limited since 1993 and Cellpack Aerospace Limited since 1987). He is also on the Advisory Board of Atlantic Industries Limited and is Chair of its Advisory Audit Committee.

Mr. Eisenhauer holds a Bachelor of Science from Dalhousie University and a Bachelor of Engineering (with distinction) from the Technical University of Nova Scotia.

Mr. Eisenhauer’s professional knowledge and experience combined with his executive leadership in manufacturing and distribution businesses are valuable assets. His leadership role in the Nova Scotia business community provides him with valuable stakeholder and governance skills and experience.

Board/Committee Membership	Attendance	Total	Public company board membership     during the last five years
•    Board Member	10 of 11	91%	Nova Scotia Power Inc. (September 2008 to present)

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
N/A	166,500	166,500

DSUs Awarded and Held
2015 share-based     awards ($)	Total 2015 increase in value     of all DSUs held ($)	Market value of total     DSUs holdings ($)
166,500	354,661	1,372,207

Instalment Receipts
Number of Instalment Receipts Held	100

Securities Held
Year	Common   Shares	DSUs	Value of shares   and DSUs ($)	Status under share ownership guidelines
2015   2014   2013	Nil   Nil   Nil	31,742   26,334   20,310	1,372,207   1,017,546   620,877	Mr. Eisenhauer owns DSUs valued at 315% of the requirement under the Share Ownership Guidelines; therefore,  the Guidelines are met.

12          Emera Inc. — Management Information Circular 2016

Christopher Huskilson

Age: 58

Wellington, Nova Scotia

Canada

Director Since: 2004

Not Independent

President and Chief Executive Officer of Emera

Skills and Experience

• CEO/Senior Executive

• Customer/Stakeholder

• M&A/Growth Strategy

• Governance/Other Directorship

• Financial

• Energy Sector

• Compensation and Human Resources

• Legal and Regulatory

MANAGEMENT INFORMATION CIRCULAR

Mr. Huskilson has been a Director and the President and Chief Executive Officer of Emera since November 2004.

He is a Director of NSPI and serves as the Chair or as a Director of a number of other Emera affiliated companies. He has been a Director of Algonquin Power & Utilities Corp. since 2009. He has held a number of positions within Nova Scotia Power Inc. and its predecessor, Nova Scotia Power Corporation, since June 1980.

Mr. Huskilson holds a Bachelor of Science in Engineering and a Master of Science in Engineering from the University of New Brunswick.

Mr. Huskilson’s decades of experience and extensive knowledge of various roles within Emera and Nova Scotia Power Inc. allow him to provide leadership within the Company, and in the broader electricity industry, regionally, nationally and internationally.

Board/Committee Membership	Attendance	Total	Public company board membership during the last five years
•    Board Member	11 of 11	100%	•    Emera (Caribbean) Incorporated (formerly Light & Power Holdings Limited) (June 2010 to present) (1) •    Nova Scotia Power Inc. (November 2004 to present) (1) •    ICD Utilities Limited (September 2008 to present) (1) •    Algonquin Power and Utilities Corp. (July 2009 to present)

DSUs Awarded and Held
2015 share-based     awards ($)	Total 2015 increase in value     of all DSUs held ($)	Market value of total     DSUs holdings ($)
0	1,272,432	9,078,214

Instalment Receipts
Number of Instalment Receipts Held	750

Securities Held
Year	Common   Shares	DSUs	Value of shares   and DSUs ($)	Status under share ownership guidelines
2015   2014   2013	25,537   25,523   25,516	209,998   202,013   193,580	10,182,178   8,791,991   6,697,765	Mr. Huskilson is subject to Executive Share Ownership Requirements, which require that he own shares and/or DSUs valued at four times his salary.He exceeds this requirement.

(1) Emera (Caribbean) Inc., Nova Scotia Power Inc. and ICD Utilities Limited are subsidiaries of Emera.

Emera Inc. — Management Information Circular 2016          13

Wayne Leonard

Age: 65

New Orleans, Louisiana

USA

Director Since: 2014

Independent

Skills and Experience

• CEO/Senior Executive

• M&A/Growth Strategy

• Governance/Other Directorship

• Energy Sector

• Legal and Regulatory

Mr. Leonard joined the Emera Board of Directors in September 2014. He also became a member of the Audit Committee at that time.

Mr. Leonard is the former Chairman and Chief Executive Officer of Entergy Corporation, an integrated electricity producer and retail distributor. He joined Entergy Corporation as President and Chief Operating Officer in 1998, becoming CEO in 1999. Previously, he was President of Cinergy Corporation’s Energy Commodities Strategic Business Unit and Capital & Trading Group from 1996 to 1997, and before that its Group Vice President and Chief Financial Officer. Mr. Leonard also held various senior management roles with PSI Energy Inc., including Senior Vice President and Chief Financial Officer from 1987 to 1994. He has served as an expert witness in numerous utility regulatory proceedings on various policies and financial issues, including, cost of capital and incentive regulation.

Mr. Leonard has been a member of the Board of Tidewater Inc. since 2003. Previously, he served on the Boards of the Edison Electric Institute and the Center for Climate and Energy Solutions. He is past Chairman of the New Orleans United Way Board of Trustees, the Mississippi River Delta Business LINC (appointed in 2000 by former President Bill Clinton), the Business Council of New Orleans, the National D-Day Museum Foundation Board of Trustees, and the Ball State University College of Business Advisory Board.

A Certified Public Accountant (CPA), Mr. Leonard received his Bachelor of Science, Accounting and Political Science from Ball State University and his MBA from Indiana University. He was awarded an Honorary Doctorate of Law Degree from Ball State University in 2004.

With his considerable experience in regulated and non-regulated utilities and capital markets, Mr. Leonard is a valuable member of the Emera Board.

Board/Committee Membership	Attendance	Total	Public company board membership during the last five years
•    Board Member •    Audit Committee Member	8 of 11     6 of 6	72%(1)   100%	•    Tidewater Inc. (2003 to present) •    Entergy Corporation (1999 to 2013)

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
135,250	N/A	135,250

DSUs Awarded and Held
2015 share-based     awards ($)	Total 2015 increase in value     of all DSUs held ($)	Market value of total     DSUs holdings ($)
135,250	161,310	208,412

Instalment Receipts
Number of Instalment Receipts Held	Nil (2)

Securities Held
Year	Common   Shares	DSUs	Value of shares   and DSUs ($)	Status under share ownership guidelines
2015   2014	Nil   Nil	4,821   1,219	208,412   47,102	Mr. Leonard owns shares and DSUs valued at 48% of the requirement under the Share Ownership Guidelines. He has until January 2021 to meet the Guidelines.

(1) Mr. Leonard was unable to participate in three Board meetings in 2015; in one instance due to an unavoidable travel commitment, and in two instances due to medical commitments.

(2) The instalment receipts were not offered or sold in the United States, therefore, Mr. Leonard as a U.S. resident was unable to participate in the offering.

14          Emera Inc. — Management Information Circular 2016

Lynn Loewen, FCPA, FCA

Age: 54

Westmount, Quebec

Canada

Director Since: 2013

Independent

Skills and Experience

• CEO/Senior Executive

• Governance/Other Directorships

• Customer/Stakeholder

• Financial

MANAGEMENT INFORMATION CIRCULAR

Ms. Loewen has been a Director of the Company since February 2013 and a member of the Audit Committee since May 2013.

Ms. Loewen is currently President of Minogue Medical Inc. She was President of Expertech Network Installation Inc. from 2008 to 2011. She held key positions with Bell Canada Enterprises, as Vice President of Finance Operations from 2005 to 2008, and as Vice President of Financial Controls from 2003 to 2005. Prior to that, she was Vice President of Corporate Services and Chief Financial Officer of Air Canada Jazz, where she held positions of increasing responsibility since 1988.

Ms. Loewen was a member of the Public Sector Pension Investment Board from 2001 to 2007, where she served on the Audit Committee from 2003 to 2007 and as Audit Committee Chair from 2006 to 2007. She was Chair of the Governance Committee from 2003 to 2006.

Ms. Loewen holds a Bachelor of Commerce from Mount Allison University and obtained her Chartered Accountant designation in 1986. She served on the Mount Allison University Board of Regents from 1998 to 2008 and as Chair from 2007 to 2008. She also served as a member of the Advisory Board of the Ron Joyce Centre for Business Studies from 2009 to 2011.

Ms. Loewen’s financial expertise and business acumen gained as a senior executive in the telecom and airline sectors are valuable assets for Emera’s Board.

Board/Committee Membership	Attendance		Total		Public company board membership during the last five years
•  Board Member		11 of 11		100%	None
•  Audit Committee Member		6 of 6		100%

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
139,625	N/A	139,625
DSUs Awarded and Held
2015 share-based   awards ($)	Total 2015 increase in value   of all DSUs held ($)	Market value of total DSUs holdings ($)
139,625	202,259	471,077

Instalment Receipts
Number of Instalment Receipts Held	100

Securities Held
Year	Common Shares		DSUs		Value of shares and DSUs ($)		Status under share ownership guidelines
2015  2014  2013		1,134 1,090 1,044		10,897 6,957 2,800		520,100 310,936 115,511	Ms. Loewen owns shares and DSUs valued at 120% of the requirement under the Share Ownership Guidelines; therefore, the Guidelines are met.

Emera Inc. — Management Information Circular 2016          15

John McLennan

Age: 70

Mahone Bay, Nova Scotia

Canada

Director Since: 2005

Independent

Skills and Experience

• CEO/Senior Executive

• Customer/Stakeholder

• M&A/Growth Strategy

• Governance/Other Directorship

• Financial

• Compensation and Human Resources

• Legal and Regulatory

Mr. McLennan has been a Director since April 2005 and was Chair of the Board from May 2009 to May 2014. He has been a member of the Nominating and Corporate Governance Committee since September 2014. He was a member of the Management Resources and Compensation Committee and the Nominating and Corporate Governance Committee from April 2005 to May 2009 when he became Chair of the Board. He was Chair of the ad hoc Board Chair Succession Committee. He was also a Director of Nova Scotia Power Inc. from April 2005 to November 2013, and was the Chair of that Board from May 2006 to May 2009.

Mr. McLennan is the former Vice Chair and Chief Executive Officer of Allstream Inc. (formerly AT&T Canada). He served as President and Chief Executive Officer of Bell Canada and Bell Mobility from 1990 to 1997. He is the former Chief Executive Officer of Cantel Inc. He is a former Board member of Chorus Aviation Inc. from January 2006 to May 2014. He currently sits on the Board of Amdocs Ltd.

Mr. McLennan holds a Bachelor of Science, Master of Science and Honorary Doctorate of Science degrees from Clarkson University in New York. From 1996 to 2006, he was Chancellor of Cape Breton University where he also received an Honorary Doctorate.

Mr. McLennan’s extensive chief executive officer experience with complex organizations across a variety of industries provides him with valuable strategic insight and leadership capabilities. Through his membership on several public company boards, he has gained extensive governance skills and business acumen.

Board/Committee Membership	Attendance		Total		Public company board membership during the last five years
•  Board Member •  Nominating and Corporate Governance Committee Member		11 of 11 4 of 4		100%   100%	•  Amdocs Limited (November 1999 to present) •  Chorus Aviation Inc. (and its predecessor Jazz Air Holding G.P. Inc.) (January 2006 to May 2014) •  Nova Scotia Power Inc. (April 2005 to November 2013)

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
134,250	N/A	134,250
DSUs Awarded and Held
2015 share-based   awards ($)	Total 2015 increase in value   of all DSUs held ($)	Market value of total DSUs holdings ($)
134,250	549,358	2,988,663

Instalment Receipts
Number of Instalment Receipts Held	500

Securities Held
Year	Common Shares		DSUs		Value of shares and DSUs ($)		Status under share ownership guidelines
2015  2014  2013		5,000 5,000 5,000		69,134 63,129 55,956		3,204,813 2,632,505 1,863,456	Mr. McLennan owns shares and DSUs valued at 737% of the requirement under the Share Ownership Guidelines; therefore, the Guidelines are met.

16          Emera Inc. — Management Information Circular 2016

Donald Pether

Age: 67

Dundas, Ontario

Canada

Director Since: 2008

Independent

Skills and Experience

• CEO/Senior Executive

• Customer/Stakeholder

• M&A/Growth Strategy

• Governance/Other Directorship

• Financial

• Compensation and Human Resources

• Legal and Regulatory

MANAGEMENT INFORMATION CIRCULAR

Mr. Pether has been a Director since November 2008. He has been a member of the Nominating and Corporate Governance Committee since May 2009, and was appointed Chair of the Committee in April 2012. He became a member of the Audit Committee in November 2014 and was a member of the Management Resources and Compensation Committee from May 2009 to September 2014.

Mr. Pether is the former Chair of the Board and Chief Executive Officer of ArcelorMittal Dofasco Inc., a Canadian steel producer. He is a past-Chair of the Board of the Hamilton Health Sciences Foundation, the McMaster Innovation Park and McMaster University. He currently sits on the Board of the Manning Innovation Awards Foundation and the Council of Governors for the Art Gallery of Hamilton. He is a Director of Samuel, Son & Co. Ltd and Schlegel Health Care Inc.

Mr. Pether has a Bachelor of Science in Metallurgical Engineering from the University of Alberta and holds a Doctor of Laws (Hon) from McMaster University.

Mr. Pether’s experience as a chief executive officer of a steel producer owning assets in the mining and automotive parts industry, and with employees in the U.S., Mexico and Canada, provides him with valuable business and stakeholder skills. Mr. Pether’s experience throughout his career with employee and labour relations, as well as with innovative manufacturing and maintenance processes, are of significant benefit to the Board.

Board/Committee Membership	Attendance		Total		Public company board membership during the last five years
•  Board Member •  Nominating and Corporate Governance Committee Chair		10 of 11 4 of 4		91%   100%	•  Primary Energy Recycling Corporation (April 2010 to December 2014)
•  Audit Committee Member		6 of 6		100%

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
154,875	N/A	154,875
DSUs Awarded and Held
2015 share-based   awards ($)	Total 2015 increase in value   of all DSUs held ($)	Market value of total DSUs holdings ($)
154,875	322,241	1,221,896

Instalment Receipts
Number of Instalment Receipts Held	50

Securities Held
Year	Common Shares		DSUs		Value of shares and DSUs ($)		Status under share ownership guidelines
2015  2014  2013		Nil Nil Nil		28,265 23,283 17,902		1,221,853 899,655 547,234	Mr. Pether owns DSUs valued at 281% of the requirement under the Share Ownership Guidelines; therefore, the Guidelines are met.

Emera Inc. — Management Information Circular 2016          17

Andrea Rosen

Age: 61

Toronto, Ontario

Canada

Director Since: 2007

Independent

Skills and Experience

• CEO/Senior Executive

• M&A/Growth Strategy

• Governance/Other Directorships

• Financial

Ms. Rosen has been a Director since January 2007 and a member of Emera’s Audit Committee since May 2007. She was appointed Audit Committee Chair in April 2008. She was a member of the ad hoc Committee formed by the Board in August 2015 to oversee certain aspects of the financing related to the TECO Energy, Inc. transaction.

Ms. Rosen was Vice Chair of TD Bank Financial Group and President of TD Canada Trust from 2002 to 2005.

Prior to this, she was Executive Vice President of TD Commercial Banking and Vice Chair of TD Securities. Previously, Ms. Rosen also served as Vice President of Varity Corporation from 1991 to 1994. Between 1981 and 1990, she held a variety of roles at Wood Gundy Inc. (later CIBC Wood Gundy) eventually becoming Vice President and Director. Ms. Rosen is also a Director of the Alberta Investment Management Corporation and Manulife Financial Corporation.

Ms. Rosen received her Bachelor of Laws degree from Osgoode Hall Law School and a Masters of Business Administration from the Schulich School of Business at York University. She earned a Bachelor of Arts degree from Yale University.

Ms. Rosen has spent over 20 years in the corporate finance field and is an experienced senior executive. Her career in the investment and commercial banking industry has given her extensive financial and investment knowledge. Her expertise is of significant value to the Board.

Board/Committee Membership	Attendance		Total		Public company board membership during the last five years
•  Board Member •  Audit Committee Chair		10 of 11 6 of 6		91%   100%	•  Manulife Financial Corporation (August 2011 to present) •  Hiscox Ltd. (October 2006 to October 2015)
•  Ad Hoc Committee Member (1)		3 of 3		100%

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
157,125	N/A	157,125
DSUs Awarded and Held
2015 share-based   awards ($)	Total 2015 increase in value   of all DSUs held ($)	Market value of total DSUs holdings ($)
157,125	382,170	1,634,570

Instalment Receipts
Number of Instalment Receipts Held	600

Securities Held
Year	Common Shares		DSUs		Value of shares and DSUs ($)		Status under share ownership guidelines
2015  2014  2013		Nil Nil Nil		37,811 32,412 26,886		1,634,570 1,252,400 821,874	Ms. Rosen owns DSUs valued at 376% of the requirement under the Share Ownership Guidelines; therefore, the Guidelines are met.

(1) This Ad Hoc Committee oversaw aspects of the financing related to the TECO Energy, Inc. transaction.

18          Emera Inc. — Management Information Circular 2016

Richard Sergel

Age: 66

Wellesley, Massachusetts

USA

Director Since: 2010

Independent

Skills and Experience

• CEO/Senior Executive

• Customer/Stakeholder

• M&A/Growth Strategy

• Governance/Other Directorship

• Financial

• Energy Sector

• Compensation and Human Resources

• Legal and Regulatory

MANAGEMENT INFORMATION CIRCULAR

Mr. Sergel has been a Director since September 2010. He has been a member of the Nominating and Corporate Governance Committee since November 2012, and a member of the Management Resources and Compensation Committee since September 2014. He was a member of the ad hoc Pension Governance Committee from November 2013 to May 2014, and was a member of the ad hoc Committee formed by the Board in August 2015 to oversee certain aspects of the financing related to the TECO Energy, Inc. transaction. Mr. Sergel is also a member of the Board of the Company’s subsidiary Emera U.S. Holdings Inc.

Mr. Sergel is the former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC). He served as President and Chief Executive Officer of National Grid USA, and its predecessor New England Electric System, from 1998 to 2004.

Mr. Sergel is presently a director of State Street Corporation. He also served on the boards of the Edison Electric Institute, the Consortium for Energy Efficiency, and the United Way of the Merrimac Valley.

Mr. Sergel holds a Bachelor of Science in Mathematics from Florida State University, a Master of Science in Applied Mathematics from North Carolina State University, and a Master of Business Administration from the University of Miami.

Mr. Sergel’s extensive career in the United States electricity sector has provided him with valuable industry and business skills and experience. His regulatory background is a distinct asset.

Board/Committee Membership	Attendance	Total	Public company board membership during the last five years
•    Board Member •    Nominating and Corporate Governance Committee Member	11 of 11   4 of 4	100%   100%	State Street Corporation (September 1999 to present)
•    Management Resources and Compensation Committee	4 of 4	100%
•    Ad Hoc Committee Member (1)	3 of 3	100%

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
154,500	17,479	171,979

DSUs Awarded and Held
2015 share-based   awards ($)	Total 2015 increase in value   of all DSUs held ($)	Market value of total   DSUs holdings ($)
65,000	109,162	326,473

Instalment Receipts
Number of Instalment Receipts Held	Nil (2)

Securities Held
Year	Common   Shares	DSUs	Value of shares   and DSUs ($)	Status under share ownership guidelines
2015 2014 2013	4,000   4,000   4,000	7,552   5,624   3,640	499,393   371,871   233,555	Mr. Sergel owns shares and DSUs valued at 115% of the requirement under the Share Ownership Guidelines; therefore, the Guidelines are met.

(1) This Ad Hoc Committee oversaw aspects of the financing related to the TECO Energy, Inc. transaction.

(2) The instalment receipts were not offered or sold in the United States, therefore, Mr. Sergel as a U.S. resident was unable to participate in the offering.

Emera Inc. — Management Information Circular 2016          19

Jackie Sheppard

Age: 60

Calgary, Alberta

Canada

Director Since: 2009

Independent

Skills and Experience

• CEO/Senior Executive

• Customer/Stakeholder

• M&A/Growth Strategy

• Governance/Other Directorship

• Financial

• Energy Sector

• Compensation and Human Resources

• Legal and Regulatory

Ms. Sheppard has been an Emera Director since February 2009, and became Chair of the Board in May 2014. She was a member of the Audit Committee from May 2009 to October 2014, and a member of the Management Resources and Compensation Committee from May 2009 to May 2014. She was Chair of the ad hoc Committee formed by the Board in August 2015 to oversee certain aspects of the financing related to the TECO Energy, Inc. transaction. Ms. Sheppard is also a Director of the Company’s subsidiary, Emera Newfoundland & Labrador Holdings Inc.

Ms. Sheppard is the former Executive Vice President, Corporate and Legal of Talisman Energy Inc. She served as Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a Provincial Crown Corporation, until June 2014. She is founder and Lead Director of Black Swan Energy Inc., an Alberta upstream energy company that is private equity financed. Ms. Sheppard is founder and former Director of Marsa Energy Inc., an oil and gas corporation. She is a Director of Cairn Energy PLC, a publicly traded UK-based international oil and gas producer, and a Director of the general partner of Pacific NorthWest LNG LP, which was formed for the purpose of constructing, owning and operating an LNG facility in British Columbia.

Ms. Sheppard is a Rhodes Scholar, having received an Honors Jurisprudence, Bachelor of Arts and Master of Arts from Oxford University in 1979. She earned a Bachelor of Laws degree (Honours) from McGill University in 1981, and a Bachelor of Arts degree from Memorial University of Newfoundland in 1977.

With her extensive roles as an executive in the oil and gas industry, and as a director of public, private and crown corporations, Ms. Sheppard’s experience in strategic planning, business development, public markets and governance are the foundation for her leadership of the Board.

Board/Committee Membership	Attendance	Total	Public company board membership during the last five years
•    Board Member •    Ad Hoc Committee Chair (1)	11 of 11   3 of 3	100%   100%	•    Cairn Energy PLC (May 2010 to present) •    NWest Energy Corp. (July 2008 to July 2012)

Total Compensation
Fees earned in 2015 ($)	All other compensation ($)	Total ($)
245,000	N/A	245,000

DSUs Awarded and Held
2015 share-based   awards ($)	Total 2015 increase in value   of all DSUs held ($)	Market value of total   DSUs holdings ($)
245,000	453,589	1,531,336

Instalment Receipts
Number of Instalment Receipts Held	500

Securities Held
Year	Common   Shares	DSUs	Value of shares   and DSUs ($)	Status under share ownership guidelines
2015	Nil	35,423	1,531,336	Ms. Sheppard owns DSUs valued at 352% of the requirement under the Share Ownership Guidelines; therefore, the Guidelines are met.
2014	Nil	27,893	1,077,747
2013	Nil	20,404	623,750

(1) This Ad Hoc Committee oversaw aspects of the financing related to the TECO Energy, Inc. transaction.

20          Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Compensation of Directors in 2015

Purpose of Director Compensation

The compensation of Directors is designed to:

• attract and retain highly skilled and experienced individuals to serve on Emera’s Board;

• ensure alignment with long-term Shareholders’ interest; and

• recognize the substantial time commitment required to oversee management of the Company.

For more information about the process of determining Director compensation, see Director Compensation in the Statement of Corporate Governance Practices later in the Circular.

Deferred Share Units (DSUs)

Directors have the ability to elect to receive some or all of their cash compensation in the form of DSUs. In 2015, the annual retainer for each Director was $105,000, of which $65,000 was payable in DSUs. More information about the Directors’ DSUs Plan is provided later in this section of the Circular. The Company does not offer option-based awards, non-equity incentive plan participation, or participation in a Company pension plan to its Directors.

Board Chair’s All-Inclusive Retainer

The annual Chair’s Retainer is an all-inclusive fee, meaning the Board Chair receives no meeting fees or any other retainer for serving as Emera’s Board Chair. The all-inclusive annual retainer of the Board Chair in 2015 was $245,000. This was comprised of $115,000 in DSUs, and the remainder in cash.

Compensation Rates for Directors

Listed below are the annual compensation rates for independent Directors in 2015. These rates are not applicable to:

• Mr. Huskilson, who is an employee of the Company,

• Mr. Eisenhauer, who received an annual all-inclusive annual retainer from NSPI as the Chair of the NSPI Board.

Annual retainers and meeting fees for Directors in 2015	Cash Amount ($)		DSUs ($)		Total ($)
Annual Chair’s retainer		130,000		115,000		245,000
Annual Director’s retainer		40,000		65,000		105,000
In-person meeting fee (1)						1,750
Telephone meeting fee (1)						1,250
Travel fee (if one-way travel is 5 hours or more)						1,750
Travel fee (if one-way travel is at least 3 hours but less than 5 hours)						875
Annual Audit Committee Chair’s retainer						20,000
Annual Audit Committee member’s retainer						5,000
Annual Management Resources and Compensation Committee Chair’s retainer						15,000
Annual Management Resources and Compensation Committee member’s retainer						3,000
Annual Nominating and Corporate Governance Committee Chair’s retainer						10,000
Annual Nominating and Corporate Governance Committee member’s retainer						3,000

(1) Members of ad hoc Committees received meeting fees for their participation in each Committee meeting. They received no annual retainer for being a member of an ad hoc Committee.

Total Director Compensation in 2015

The following table sets out the total compensation earned by the Directors who served on Emera’s Board during 2015. Compensation is made up of applicable retainers and fees for attendance at Board and Committee meetings for which a Director attended as a member or guest, briefing meetings, education sessions, and travel fees. Mr. Huskilson is not included in the table as his compensation for service as Emera’s President and CEO is disclosed in the Statement of Executive Compensation. He does not receive any additional compensation for his services as a member of the Board of Emera or as a member of the Board of any of Emera’s subsidiaries or investments.

Emera Inc. — Management Information Circular 2016          21

The table below entitled “Total Compensation” shows the compensation earned by Emera Directors in 2015 for serving on the Company’s Board of Directors. It includes compensation earned by Emera Directors who served on the Boards of Emera subsidiaries. See Compensation of Emera Directors on Subsidiary Boards for more information about Emera’s Directors who served on the Boards of its subsidiaries.

In the table below, the three columns under the heading “DSUs Awarded and Held” show detailed information about DSUs received by Directors as compensation.

Total Compensation

						DSUs Awarded and Held
Director	Fees earned in 2015 ($)	(1)	All other compensation ($)		Total ($)		2015 share-based awards ($)	(2)	Total 2015 increase in value of all DSUs held ($)	(3)	Market value of total DSU holdings ($)	(4)
Sylvia Chrominska	136,875				136,875		118,906		221,970		756,439
Henry Demone	134,250				134,250		134,250		158,307		194,319
Allan Edgeworth	154,500				154,500		109,750		332,011		1,606,513
James Eisenhauer (5)	N/A		166,500		166,500		166,500		354,661		1,372,207
Wayne Leonard	135,250				135,250		135,250		161,310		208,412
Lynn Loewen	139,625				139,625		139,625		202,259		471,077
John McLennan	134,250				134,250		134,250		549,358		2,988,663
Don Pether	154,875				154,875		154,875		322,241		1,221,896
Andrea Rosen	157,125				157,125		157,125		382,170		1,634,570
Richard Sergel	154,500		17,479	(6)	171,979		65,000		109,162		326,473
Jackie Sheppard	245,000				245,000		245,000		453,589		1,531,336

(1) The “Fees Earned In 2015” column is the amount of Directors’ fees, and includes the dollar value of that portion of their retainer paid in DSUs. All fees are in Canadian dollars.

(2) This column shows the portion of Directors’ fees earned in 2015 that was allocated to DSUs. DSUs granted in 2015 are based on the value of the Emera common share closing price on December 31, 2014 ($38.64).

(3) This column shows (i) the increase in value in 2015 of all DSUs held by each Director at the beginning of the year, plus (ii) the value of all DSUs received in 2015, including dividends earned on the DSUs (in the form of additional DSUs), multiplied by the December 31, 2015 closing Emera common share price of $43.23.

(4) This column shows the value of all DSUs held by each Director at the end of 2015 based on the December 31, 2015 closing Emera common share price of $43.23.

(5) $25,000 of the compensation earned by Mr. Eisenhauer is paid in the form of DSUs.

(6) Mr. Sergel received compensation for serving as a Director of Emera Energy Generation II LLC, Rumford Power Inc., Tiverton Power LLC, Bridgeport Energy LLC, Emera CNG Holdings Inc., and Emera CNG LLC until his retirement as a Director of those companies on September 30, 2015. Mr. Sergel also received compensation for serving as a Director of Emera US Holdings Inc. effective October 1, 2015.

Compensation of Emera Directors on Subsidiary Boards

The Emera Board of Directors, on the recommendation of the Nominating and Corporate Governance Committee, determines the compensation to be received by Emera Directors who serve on the boards of Emera’s subsidiaries. Such compensation received by each Emera Director that serves as a Director on the board of an Emera subsidiary is reported under “All Other Compensation” and “Total” in the Total Compensation table above.

Mr. Eisenhauer is Chair of the Board of Directors of NSPI. The NSPI Board Chair’s retainer is an annual all-inclusive fee paid by NSPI, meaning the NSPI Board Chair receives no meeting fees or other retainer. As of December 31, 2015, the all-inclusive annual retainer of the NSPI Board Chair was $166,500, of which at least $25,000 is payable in DSUs.

Emera Newfoundland & Labrador Holdings Inc. (“ENL”) is a wholly-owned subsidiary of Emera and the parent company of NSP Maritime Link Inc. and ENL Island Link Inc. Ms. Sheppard is a member of the ENL Board. As Emera Board Chair, Ms. Sheppard receives the Chair’s all-inclusive retainer and does not receive any additional compensation for her service on the ENL Board.

Mr. Sergel was a member of the Board of Directors (or in the case of limited liability companies, Board of Managers) of Emera CNG Holdings Inc. and Emera CNG LLC, for which he received a combined annual retainer of $10,000. Mr. Sergel was also on the Boards of Emera Energy Generation II LLC, Rumford Power Inc., Tiverton Power LLC and Bridgeport Energy LLC, for which he also received a combined annual retainer of $10,000. On September 30, 2015, he resigned from the Boards of Emera CNG Holdings Inc., Emera CNG LLC, Emera Energy Generation II LLC, Rumford Power Inc., Tiverton Power LLC and Bridgeport Energy LLC. On October 1, 2015, Mr. Sergel joined the Board of Emera US Holdings Inc., a United States holding company which is a direct subsidiary of Emera and holds certain US based investments of Emera, including the above subsidiaries, the boards from which he resigned on September 30, 2015. He receives an annual retainer of US $10,000 for serving on the Emera US Holdings Inc. Board, plus US $1,000 for any Board meetings.

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Directors’ Share Ownership Guidelines

In order to align the interests of Directors and Shareholders, the Directors are subject to share ownership guidelines that require them to own common shares and/or DSUs with a value of not less than three times the annual Director’s Retainer within a specified timeframe. For the status of each Director nominee under the Director Share Ownership Guidelines, see their biographies earlier in this Circular. For more information about the Director Share Ownership Guidelines, see Director Share Ownership Guidelines in the Statement of Corporate Governance Practices.

Convertible Debentures

Directors purchased 2,860 instalment receipts (“Instalment Receipts”) in connection with the offering of convertible debentures issued by Emera in September 2015 in respect of the financing of the Company’s acquisition of TECO Energy, Inc. Convertible debentures were sold by Emera on an instalment basis at a price of $1,000 per debenture, with the first instalment of $333 payable on the closing of the offering. The final instalment of $667 is payable following notification to holders that certain approval conditions have been fulfilled or waived as set out in the agreement and plan of merger dated September 4, 2015 among Emera, Emera US Inc. and TECO Energy, Inc. At the option of the holder, on payment of the final instalment, each debenture will be convertible into common shares of Emera at a conversion price of $41.85 per common share, being a conversion rate of 23.8949 common shares per $1,000 principal amount of debentures.

Directors’ DSU Plan

Under the Directors’ Deferred Share Unit Plan (the “Directors’ DSU Plan”), independent Directors may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each quarterly payment, the applicable amount is converted to DSUs. The number of DSUs to be credited is determined by dividing (a) the quarterly portion of the Director’s annual fee that the Director elected to be paid in DSUs by (b) the fair market value on the last trading day of the preceding calendar year, with fractions computed to three decimal places.

A DSU is a unit that has a value based upon the value of one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs computed by dividing: (a) the amount obtained by multiplying the amount of the dividend declared and paid per common share by the number of DSUs recorded in the Director’s account on the record date for the payment of such dividend, by (b) the market price of a common share as of the dividend payment date.

DSUs cannot be redeemed for cash until the Director leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption. DSUs are not shares, cannot be converted to shares, and do not carry voting rights. DSUs received by Directors in lieu of cash compensation and held by them represent an at-risk investment in Emera. The value of DSUs is based on the value of the common shares of Emera, and therefore is not guaranteed. See Director Compensation in the Statement of Corporate Governance Practices in this Circular for more information about the compensation of Directors. Independent Directors are not entitled to participate in any other compensation plan of the Company or in Emera’s Employee Common Share Purchase Plan.

Committees of the Board of Directors

The Board of Directors has three standing Committees to assist it in carrying out its duties. They are the:

• Audit Committee;

• Management Resources and Compensation Committee (MRCC); and

• Nominating and Corporate Governance Committee (NCGC).

From time to time the Board may establish ad hoc committees to assist the Board on specific matters of a temporary nature. Most recently, such an ad hoc committee was formed in August 2015 to oversee certain aspects of the financing related to the TECO Energy, Inc. transaction. Its membership consisted of Jackie Sheppard, as Committee chair, with Andrea Rosen and Richard Sergel as members, and it met three times in September 2015. In terms of compensation, members of ad hoc committees receive meeting fees for their participation in each committee meeting, but typically receive no annual retainer for being a member of an ad hoc committee because of the nature of the committee’s existence, having generally been established for a specific purpose and a temporary period of time. For further information on the Company’s Committees, see Committees of the Board of Directors in the Statement of Corporate Governance Practices later in this Circular.

Certain Proceedings

To the knowledge of the Company, none of the proposed nominees for election as Directors of the Company:

(a) are, as at the date of this Circular, or have been, within 10 years before the date of this Circular, a director, chief executive officer or chief financial officer of any company that:

(i) was subject to a cease trade order, an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation that was in effect for a period of more than 30 consecutive days (an “Order”) that was issued while the proposed nominee was acting in the capacity as director, chief executive officer or chief financial officer; or

Emera Inc. — Management Information Circular 2016          23

(ii) was subject to an Order that was issued after the proposed nominee ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer;

(b) are, as at the date of this Circular, or have been within 10 years before the date of this Circular, a director or executive officer of a company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or

(c) have, within the 10 years before the date of this Circular, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the proposed nominee.

Statement of Corporate Governance Practices

Corporate Governance at a Glance
Emera’s Board of Directors annually reviews its approach to corporate governance. It monitors best practices of leading corporations with a view to enhancing governance to create and preserve long-term Shareholder value. Details of Emera’s corporate governance practices may be found in this Statement of Corporate Governance Practices.
Governance Highlights	For details see
All Emera Directors are independent from management except the President and Chief Executive Officer.	Board of Directors page 25
The Board oversees the Company’s strategy, which includes reviewing the strategic planning process and annually approving the strategic plan, taking into account, among other things, the opportunities and risks of the business.	Board of Directors page 25
The Board oversees the Company’s risk management.	Board of Directors page 25
The Chair of the Board Charter and position descriptions for each of the Committee Chairs describe the roles and responsibilities for these leadership positions.	Position Descriptions page 27
Directors receive an orientation when they become Board members and receive support for continuing education to familiarize them with the business, investments and key Company personnel.	Orientation of New Directors and Continuing Education page 27
Creating a culture of integrity begins with the tone at the top. Directors, Officers and employees are required to annually acknowledge that they have reviewed and understand the Emera Group of Companies Standards for Business Conduct.	Ethical Business Conduct page 28
New Directors are recruited on the basis that they will make a strong contribution and have background, skills and experience needed by the Board in view of the Company’s strategy.	Nomination of Directors page 29
The Company maintains compensation for Directors designed to recognize the substantial time commitment required to oversee management of the Company and to align Directors’ interests with the long-term interest of Shareholders.	Director Compensation page 31
Three standing Committees assist the Board in carrying out its responsibilities: the Audit Committee; the Management Resources and Compensation Committee; and the Nominating and Corporate Governance Committee.	Committees of the Board of Directors page 33
The Board annually assesses its performance in order to find ways to improve its effectiveness and the performance of the Chair, individual Directors and the Board Committees.	Board and Director Performance Assessments page 32
Please read Emera’s entire Statement of Corporate Governance Practices below for more important details about the Company’s governance practices.

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Board of Directors

Director Independence

All Emera Directors are independent from management, except Mr. Huskilson, who is the President and CEO of the Company. Use of the term “independent” in relation to a Director in this Circular means a Director is independent as defined under applicable Canadian securities laws and, in particular, is free of any direct or indirect material relationship, which could, in the view of the Board of Directors, be reasonably expected to interfere with the Director’s independent judgment.

None of the independent Directors receive remuneration from Emera other than Directors’ retainers, fees or retainers for service as Chair of the Board or Chair of a Committee. Mr. Eisenhauer, who is Chair of the Board of Emera’s subsidiary, NSPI receives an all-inclusive annual retainer from NSPI. Ms. Sheppard receives an all-inclusive annual retainer as Chair of the Board of Emera. Mr. Sergel received a retainer for being a member of the boards of Emera’s subsidiaries, Emera CNG Holdings Inc., Emera CNG LLC, Emera Energy Generation II LLC, Rumford Power Inc., Tiverton Power LLC and Bridgeport Energy LLC and Emera US Holdings Inc.

The Company’s Articles of Association provide that no more than two Directors may be employees of the Company or of a subsidiary or affiliate of the Company. Mr. Huskilson, as President and CEO of the Company, is the only Director employed by the Company.

Board of Directors Charter

The Board of Directors believes that clear accountabilities lead to the best governance and, therefore, maintains a Charter for the Board. The Board of Directors Charter is attached to this Circular as Appendix A. Under the Charter, the Board is responsible for overseeing the management of the business of the Company and for providing stewardship and governance to ensure the viability and growth of its business. The Charter describes the duties and responsibilities of the Board in matters of independence and integrity, strategic planning, risk responsibility, leadership and succession, financial reporting, corporate communications, public disclosure, and corporate governance. We encourage you to carefully review the Charter for more detail about the obligations of the Board in these areas.

Strategic Planning

The President and CEO, in collaboration with executive officers and the Board of Directors, develop a strategic plan, which is presented to the Directors at a Board retreat. Under the Board of Directors Charter, oversight and guidance on the Company’s strategy is one of the primary roles of the Board. Directors participate in the development of the corporate strategy, which determines the annual and longer-term objectives for the Company. The Directors devote significant time at regular Board meetings to evaluate progress made in executing the Company’s strategy.

Risk Management

The Board of Directors is responsible for overseeing risk. Under the Board of Directors Charter, the Board is responsible for overseeing the implementation by management of appropriate systems to identify, report and manage the principal risks of Emera’s business. The Charter requires the Board to consider Emera’s risk profile and to oversee Emera’s risk management by reviewing:

(a) the annual identification and assessment of the principal risks of Emera;

(b) the process for ongoing monitoring and reporting of the principal risks of Emera;

(c) the effectiveness of Emera’s mitigation response to its principal risks; and

(d) the alignment of risk management with Emera’s risk profile, its strategy, and its organizational objectives, including capital and resources allocation.

The Board is also responsible for reviewing Emera’s annual insurance program, its uninsured exposure, and its business continuity and disaster recovery plans. The Board receives regular updates on the status of risk management activities and initiatives.

Directors Meet without Management

There were 28 Emera Board and Committee meetings during 2015. Each Board and Committee has adopted the practice of meeting in an in-camera session, during which management is excluded, at every Board and Committee meeting. The Board implemented this practice and held an in-camera session at each Board meeting, which excluded management, including the President and CEO.

The Board also holds an evening session before the day of a regularly scheduled Board meeting and prior to the Board’s annual strategy meeting. As a governance practice, and at least once a year, the independent Directors conduct such an evening session to the exclusion of all management, including the President and CEO. See Board Dinner Sessions for more information.

Emera Inc. — Management Information Circular 2016          25

Independent Chair

Ms. Sheppard, the Chair of the Board, is an independent Director. The Articles of Association of the Company require that the Chair of the Board and the President and CEO be separate individuals.

Chair of the Board of Directors Charter

The Chair provides leadership to the Board, in order that it may fulfill its duties effectively, efficiently and independent of management. The Chair’s role is to see that the Board and Shareholder meetings function effectively. The Chair provides advice and counsel to Directors and the President and CEO. The Chair participates in the recruitment of Directors and the assessment of their performance.

Directors’ Membership on Other Public Company Boards

Public company board membership for each Director during the last five years is set forth in their biographies earlier in the section of this Circular, entitled Director Nominees. The effectiveness of the Board, each Director and the Board Chair is annually evaluated through the Board and Director Performance Assessment process described in more detail below in Board and Director Performance Assessments.

Common Memberships on Boards of Public Companies

Except for the membership of Mr. Huskilson and Mr. Eisenhauer on the Board of Emera’s subsidiary NSPI, there are currently no common memberships on boards of public companies among Emera’s Directors.

Board Size

The Articles of Association provide that the number of Directors on the Company’s Board must not be less than eight and not more than 15. 12 Director nominees are being proposed for election at the 2016 Annual and Special Meeting.

Majority Voting for Election of Directors

The confidence of Shareholders in the actions of the Board and management are important. In order to provide a mechanism for Shareholders to express that confidence in each Director, the Board has adopted a Majority Voting Policy for Directors. The Policy states:

Should a director nominee, in an uncontested election at a meeting of shareholders of Emera Inc. at which directors are to be elected, receive a majority of “withheld” votes from his or her election as a director (a “Majority Withheld Vote”), the individual shall submit his or her resignation to the Board for consideration immediately following such shareholders’ meeting.

The votes determining a Majority Withheld Vote shall be the total votes cast by ballot by shareholders and proxyholders at, or if a ballot vote was not conducted, shall be the total votes represented by proxies validly deposited prior to, the shareholders’ meeting.

The directors who received a majority “for” vote at the shareholders’ meeting shall consider whether or not to accept the resignation. If there are less than three such directors, the entire Board shall consider whether or not to accept the resignation. The resignation of a director who received a Majority Withheld Vote shall be accepted absent exceptional circumstances and is effective when accepted by the directors. The determination shall be made within 90 days following the date of the shareholders’ meeting and a news release disclosing such determination shall be issued promptly following such determination. If the resignation is rejected, the news release shall include the reasons for rejecting the resignation. A copy of the press release shall be provided to the Toronto Stock Exchange.

Since the adoption of the Majority Voting Policy in 2008, all Director nominees have received a majority “For” vote at the Company’s meetings of Shareholders.

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Position Descriptions

Chair of the Board

The Chair of the Board of Directors Charter describes the fundamental responsibility of the Chair of the Board of Directors of the Company. This Charter confirms that the Chair of the Board is to lead the Board to fulfill its duties effectively, efficiently and independent of Management. For the full text of the Chair of the Board of Directors Charter, visit www.emera.com/governance.

Committee Chairs

The Board has adopted position descriptions for each Committee Chair, which detail the duties of the Committee Chairs. Each Committee Chair is required to provide leadership to the Committee members and support the Committee’s effective operation in order to fulfill its mandate. For the full text of the position description for Committee Chairs, visit www.emera.com/governance.

President and Chief Executive Officer

The roles and responsibilities of the President and CEO are contained in his employment contract, which provides that he is chief executive of the Company. The President and CEO’s employment contract is reviewed by the Chair of the Board of Directors and the MRCC, and it is approved by the Board of Directors.

Orientation of Directors and Continuing Education

For each new Director to be effective in their roles, they must be knowledgeable about the Company, its strategy, strengths and challenges. In order to best bring their skills and experience to the operation of the Board, new Directors receive an in-depth orientation to the Company’s executive leaders, business, strategy, financial information and governance practices. This allows them to effectively integrate with the operation of the Board. The Board and management have built and continue to expand a long term program of training for Directors to enhance their effectiveness and reinforce a collegial working relationship among members of the Board.

Orientation sessions are attended by the President and CEO, the CFO and other executive officers or leaders of key subsidiaries. The Chair also attends the orientation meetings with a new Director. A reference manual is provided in advance of the session that includes the following:

(a) Recent annual and interim MD&A and financials, Management Information Circular and Annual Information Form;

(b) Board and Committee Charters;

(c) Strategic Plan and Business Plan;

(d) Guide to the Company’s management structure;

(e) Insider trading guidelines;

(f) Emera Group of Companies Standards for Business Conduct; and

(g) Minutes of previous Board meetings.

Continuing Education for Directors

The oversight function of Directors is enhanced when they are well informed about the Company’s business and its industry. Management regularly seeks opportunities to update, educate and inform the Directors in areas they request or that management determines are relevant to issues facing the Company.

The Board and Committees receive regular presentations from senior management updating Directors about market and industry conditions and trends that may impact the Company’s business and influence its strategy. The Board is also provided with opportunities to make site visits to operational facilities to assist Directors to more fully understand the business. From time to time, the Board receives specialized presentations on various matters of significance to the Company.

Directors participated in education sessions and received education materials about specific topics in 2015 as follows on the next page.

Emera Inc. — Management Information Circular 2016          27

Education Presentations	Date	Participants
Site visit to West Sunrise Generation Plant, Freeport, Grand Bahama	February 6, 2015	All Board members
Regulatory Accounting Session – Utility Finance and Accounting Seminar	February 26, 2015	H. Demone, A. Edgeworth and J. Eisenhauer
Annual Environmental Oversight Education	May 21, 2015	All Board members
Maritime Provinces’ Natural Gas Infrastructure presentation	May 21, 2015	All Board members
Presentation of Smart Grid technologies	May 21, 2015	All Board members
New England Clean Energy Transformation presentation	June 24, 2015	All Board members
Cape Sharp Tidal Venture – Multi Phase Development of Demonstration Array in the Bay of Fundy presentation and tour of manufacturing site	September 24, 2015	All Board members except W. Leonard
Regulatory Accounting Education Session	September 25, 2015	All Board members except W. Leonard
U.S. Federal Energy Regulatory Commission Training – written presentation only	September 25, 2015	All Board members except W. Leonard
U.S. Environmental Protection Agency’s Proposed Clean Power Plan Presentation	November 12, 2015	All Board members except W. Leonard
Presentation entitled Canada and the Road to Paris respecting the 2015 United Nations Climate Change Conference of the Parties (COPS) Implications for North America	November 12, 2015	All Board members except W. Leonard
Presentation by external compensation consultant about governance trends and regulatory updates, guidelines of proxy advisory firms in Canada and governance principles applicable to compensation	September 24, 2015	All MRCC members were present
Presentation on best practices in corporate governance	September 24, 2015	All NCGC members were present

The Board of Directors encourages, and the Company pays for, Directors to pursue education sessions provided by third parties that are directly related to the business of the Company and the performance of their duties as a Director of the Company.

Board Dinner Sessions

Board dinner sessions are scheduled the evening prior to regularly scheduled Board meetings. Board dinners are treated as an opportunity to accomplish a number of important governance objectives, including:

• Meeting as independent directors in an atmosphere that is not a Board meeting. The Board’s practice is to have one dinner each year at which only the independent directors attend;

• Meeting in a less formal atmosphere with the CEO and other senior officers;

• Holding educational sessions on important topics for the Company’s business and strategic direction;

• Meeting high-potential employees in order to advance the succession planning for the Company; and

• Strengthening Directors’ collegial working relationship.

Ethical Business Conduct

The Board is committed to sustaining a culture of integrity and ethical business practices throughout the Company.

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Standards for Business Conduct

The Board has adopted written Standards for Business Conduct (Standards for Business Conduct) that apply to everyone at Emera and its subsidiaries. Directors, Officers and employees are required to annually acknowledge that they have reviewed and understand the Standards for Business Conduct. These Standards for Business Conduct are available on Emera’s website at www.emera.com, or a copy may be obtained by contacting the Chief Human Resources Officer, Emera Inc., P.O. Box 910, Halifax, Nova Scotia B3J 2W5.

The Board regularly reviews the Standards for Business Conduct, and makes revisions in order to update the content in keeping with best practices.

Whistleblowers Policy

The Company has a whistleblowers policy entitled “Procedures for the Reporting of Irregularities and Dishonesty”. These Procedures establish a method for dealing appropriately with any complaints made by employees of irregular or dishonest accounting, internal accounting control, auditing matters, or fraudulent or illegal activity by any employee or employees. Any employee who in good faith reports such activity will be protected from threats of retaliation, or discrimination because of the report. Any employee who retaliates against another employee who reports such activity, could face disciplinary action under the Procedures. If an employee believes that retaliation has occurred, the employee may submit a complaint in writing to the Director, Internal Audit.

Reports under the Standards for Business Conduct and Procedures for the Reporting of Irregularities and Dishonesty are addressed by the Company, and on a quarterly basis the Internal Audit department informs the Audit Committee of all reports and their status.

Ethics Hotline

The Company has established a confidential business conduct helpline, called “The Ethics Hotline”, hosted by an external service provider. The Ethics Hotline is available to employees to report allegations of conduct not in compliance with the Standards for Business Conduct or the Procedures for the Reporting of Irregularities and Dishonesty. The Board monitors compliance with the Standards for Business Conduct and the Procedures for the Reporting of Irregularities and Dishonesty. There have been no instances of any waiver of compliance with the Standards or the Procedures for any Director or Officer.

Corporate Disclosure Policy

The Board has approved a Disclosure Policy to ensure that communications to investors and potential investors are timely, factual and accurate, and that the information is disseminated in accordance with all applicable legal and regulatory requirements to the investing public, analysts and the media.

Conflicts of Interest

Directors are required to declare any conflict of interest which they may have in a matter before the Board. In any matter requiring approval of the Board, a Director is prohibited by the Company’s Articles of Association from voting in respect of the matter in which the Director is interested.

Director’s Occupation

The Directors have also instituted a policy, which requires them to submit their resignation as a Director if there is a significant change in their principal occupation. The resignation is then reviewed by the Board to determine if the circumstances warrant acceptance of the resignation, whether due to a conflict of interest arising by virtue of a new principal occupation or otherwise.

Nomination of Directors

The NCGC is responsible for providing the Company with a list of nominees for election as Directors at the Company’s annual meeting of Shareholders. The NCGC creates and reviews the criteria for selecting Directors by assessing the personal qualities, business experience and qualifications of current Directors. It also assesses the Company’s ongoing needs and circumstances, geographical representation and the overall experience of the Board. In recruiting new Directors, the NCGC considers the background, skills and experience desired for Directors in view of the Company’s strategy and activities. It develops a plan for the recruitment of additional director nominees who can provide those characteristics.

Director nominees must, in the opinion of the members of the NCGC, be able to contribute to the broad range of issues which come before the Board for consideration. They must be able to devote the time necessary to prepare for and attend meetings of the Board and Committees of the Board to which they may be appointed.

The NCGC regularly evaluates the expected turnover of Directors in advance of their retirement from the Board and develops an effective succession plan.

Emera Inc. — Management Information Circular 2016          29

Mechanism for Board Renewal

While Emera has no term limits for its Directors, the Board of Directors oversees processes for renewal of the Board, which balance a number of factors, and have as their ultimate objective the fulfillment of the fundamental responsibility of the Board to provide stewardship and good governance for the Company. Those processes primarily include:

• A robust Director recruitment process;

• An age limit for Directors; and

• Governance practices which provide for renewal in a deliberate manner.

Director Recruitment Process

In developing a list of nominees for election as Directors at Emera’s annual meeting of Shareholders, the Board’s NCGC evaluates the size of the Board and the mix of skills and experience of its Directors, and the level of representation of women on the Board. The NCGC will consider the likely potential tenure of a director candidate before making a selection. This is factored into the selection decision having regard to the current make-up of the Board, what skills and experience the candidate offers as a Director, and keeping in mind the age limit for Directors.

The average tenure of all of Emera’s 12 Director nominees is approximately six and a half years. The longest serving independent Directors have served on the Board for about 11 years; the shortest serving nominees have served about a year and a half. This represents an appropriate mix of longer-serving Directors with a history on the Emera Board, and Directors that are newer to Emera, who bring fresh perspective and approach to the Company’s Board table.

Age Limit

Director nominees must be under 70 years of age at the time of the Company’s annual meeting in order to qualify for nomination. In certain exceptional circumstances, the Committee may determine and recommend that an individual be permitted to serve as a member of the Board beyond age 70 because of the individual’s contribution and skills. Such determination is made annually. All Director nominees for the Company’s 2016 Shareholders’ meeting are under 70 years of age, except John McLennan.

Mr. McLennan will be age 71 at the time of the Shareholders’ meeting on May 17, 2016. The Committee has recommended to the Board of Directors that Mr. McLennan continue to serve as a Director because of his extensive experience with the Company, and because of the support and continuity he provides to the Board Chair in light of recent Board membership changes and the growth of the Company. The Emera Board of Directors accepted the recommendation of the NCGC. As a result, Mr. McLennan has been included in the list of nominee Directors for election at the Meeting.

Governance Practices

Emera’s governance practices prescribe that planned departures of Board members in any one year will not exceed two Directors. This practice contributes to Board renewal in a deliberate manner.

Board Renewal Ongoing

The Board does not have term limits, but it does have an age limit. The age limit does not replace the rigorous annual performance assessment process that takes place under the leadership of the Board Chair with support from the NCGC, see Board and Director Performance Assessments below. The annual performance assessment in combination with its current age limit for Directors – which the NCGC has the discretion to extend in exceptional circumstances – are the current mechanisms the Board possesses to provide for Board renewal and will continue to serve the Company’s best interests, providing for appropriate renewal of the membership on the Board.

Board Diversity

To ensure that there are a significant number of women on the Company’s Board of Directors, the Company recruits Board members under a long-standing corporate governance practice, which requires that no fewer than 25 per cent of the members of the Board of Directors are women. Emera has achieved and, in fact, exceeded this requirement. Emera’s Board of Directors has four women, or 33 per cent of the total members of the Board. The list of Director nominees for the Meeting on May 17, 2016, includes four women out of twelve Director nominees, or 33 per cent.

The NCGC reviews the criteria for selecting director nominees in light of this governance practice. This governance practice reflects the Board’s view that gender diversity is an important part of fostering diversity of perspective and experience around the Board table, leading to improved overall performance of the Board and its Committees.

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Representation of Women in Executive Officer Appointments

While Emera does not have targets regarding women in executive officer appointments, management is of the view that gender diversity among the senior executive team within the Emera group of companies serves the best interests of the Company in the following ways:

• It is important that Emera’s executive ranks reflect our diverse customer base.

• Gender diversity will help the Company better understand the needs of its customer base.

• The available workforce is increasingly made up of women. As baby boomers retire and as a competitive labour market is anticipated, Emera needs to access talent from the broadest recruitment pool.

• Leadership in diversity will make the Company an employer of choice and help us to recruit, retain, and engage high-performing employees.

• It is demonstrable that business performance improves with greater gender diversity; it is good for business.

Among the executive officers of Emera Inc. and its major subsidiary, Nova Scotia Power Inc., nine are female, representing 33 per cent. Emera monitors the progression of women into leadership positions within Emera and its subsidiary companies. The increase in 2015 in the number of female executive officers relative to the prior year reflects the promotion of women employees to such positions during the year.

With a view to fostering diversity within Emera, the Company’s management does not believe that targets are the right approach. Rather it is reviewing the adoption of a diversity strategy in order to address emerging trends in the business climate, including access to diverse talent, to increase employee engagement, to foster innovation and fresh perspectives and to serve the needs of diverse customers, with the intended result of broadening the diversity of Emera’s entire employee population.

One of Emera’s subsidiaries, Emera Newfoundland & Labrador (ENL), is demonstrating leadership within the Company in the area of diversity. ENL has entered into a Benefits Agreement with the Provinces of Newfoundland & Labrador and Nova Scotia in respect of the construction of the Maritime Link Transmission Project (the “Maritime Link Project”). The Benefits Agreement requires ENL to develop and implement a Diversity Plan. Under the Maritime Link Project’s Diversity Plan, gender equity, diversity and inclusiveness must be considered in each contract, procurement and employment decision.

Compensation

Executive Compensation

On the recommendation of the MRCC, the Board of Directors determines the compensation for the Company’s senior executives and other officers of the Company. See Compensation Discussion and Analysis with respect to compensation of the Company’s Named Executive Officers.

Director Compensation

The Board of Directors determines the compensation for the Company’s Directors on the recommendation of the NCGC. The compensation of Directors is designed to recognize the substantial time commitments required to oversee management of the Company. It is intended to attract and retain highly skilled and experienced individuals to serve on Emera’s Board, and to ensure alignment with Shareholders’ long-term interests. Appropriate compensation for Directors, independently determined, is also intended to support their independence of management.

The annual retainer for Directors in 2015 was $105,000 per annum, payable as follows:

• $40,000 cash; and

• $65,000 in DSUs.

For more details on total compensation received by Emera Directors in 2015, see Compensation of Directors.

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Annual Review and 2015 Increase

The NCGC annually reviews the compensation of the Directors to ensure it is appropriate. The NCGC reviews the compensation practices of Canadian publicly traded companies similar to Emera’s operations and size and determines whether the Directors are appropriately compensated for the responsibilities and risks involved in being a member of the Company’s Board. The review is based upon publicly available information concerning Directors’ compensation, public surveys and comparison of compensation of Directors of publicly traded companies in Canada.

As previously disclosed, the NCGC has adopted the 50th percentile as a target for Director compensation, and has determined it would be appropriate for Emera to continue to position total compensation of Directors at approximately the median of the peer group.

Based on this approach and on such annual review, in November 2015, the Board of Directors approved an NCGC recommendation to increase the annual retainer for Emera Directors by $40,000 per annum, $5,000 payable in cash and $35,000 payable in DSUs, for a total annual retainer of $145,000 effective January 1, 2016. The Board also approved an NCGC recommendation to increase the annual retainer for the Chair of the Board by $35,000 to $280,000, $20,000 payable in cash and $15,000 payable in DSUs, effective January 1, 2016.

Further, to address the negative impact of changes in the Canadian and U.S. foreign exchange rate, the cash portion of retainers for U.S.-domiciled Board members will be paid in U.S. dollars using a one to one conversion rate to the Canadian dollar, effective January 1, 2016.

Director Share Ownership Guidelines

Under guidelines established by the Board of Directors, within a prescribed timeframe, each Director must own Emera common shares and DSUs with a market value of three times the annual Board retainer. Based on the increased annual retainer for Emera Directors noted above, under these guidelines, each Director must own Emera shares or DSUs, or a combination of the two, worth $435,000, within five years following their appointment date or within five years of any change to the Director’s compensation, whichever is the later date.

Details of each Director’s share and DSU ownership, and status under the Share Ownership Guidelines, is shown in each Director nominee biography earlier in this Circular. All of Emera’s Director nominees are in compliance with these Guidelines.

Directors are Increasing Their Share/DSU Ownership over Time

By virtue of this increase in compensation payable in DSUs, more than 60 per cent of the annual retainer for Emera Directors will be paid in DSUs, which mirror the value of Emera common shares. The Directors increase their DSU ownership by at least $100,000 per annum, and in many cases, Directors have elected to receive DSUs in lieu of all cash compensation they would otherwise be entitled to as Emera Directors. Members of Emera’s Board of Directors support Directors’ ownership of shares and DSUs, believing that it contributes to the alignment of the interests of Directors with those of Emera Shareholders.

Board and Director Performance Assessments

The Board regularly assesses its effectiveness in order to find ways to improve its performance.

Assessment Process

Each year, the NCGC, in consultation with the Board Chair, determines the process by which assessments of the Board, Directors and its Committees will be conducted. The process has included the use of questionnaires and one-on-one interviews with Directors by the Board Chair. A written report on the assessment is provided to the NCGC and the Board of Directors, and a dinner and in-camera Board session are also held to consider the report. Issues arising from the assessment are identified, an action plan is developed and progress is monitored by the NCGC.

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2014 Assessment Findings and Action Plans to Address Findings

The 2014 Board and Director Performance Assessment resulted in several priority actions for 2015. With the assistance of the NCGC, the Board Chair reviewed progress made to address those priorities. This progress was reported to the Board, with significant areas including:

(a) Strategy and Business Plan: Strategy has been and will continue to be incorporated into the agendas of Board meetings, and throughout the year the Company has examined several strategic merger and acquisition opportunities;

(b) Organizational Structure and Capacity: Regular Board dialogue and feedback on organizational structure and capacity has focused plans to engage senior leaders and, in response to the Board’s feedback, led to new senior management positions and focused development plans for leaders;

(c) Corporate Governance: Action taken in response to Directors’ feedback through the Board assessment process has demonstrated the importance of that feedback, and the commitment of the Board to the Assessment process. An example of action taken includes the review of the governance structure for subsidiary boards. Directors emphasized that sound corporate governance for subsidiary boards is important to each business. They directed that management take a flexible approach to looking at the structure of each of Emera’s subsidiary boards with a view to continuing with the practice of keeping a connection to the communities with external directors and local boards, maximizing the benefit from, and effectiveness of, subsidiary boards, and ensuring a disciplined approach to the governance of the subsidiary is maintained.

2015 Board Director/Board Chair Performance Assessment

The Chair of the Board interviewed each external Director as part of the 2015 Board and Director Performance Assessment. A series of questions was sent to each Director for advance consideration. The questions pertained to a number of themes, including:

• Emera’s strategy and business;

• Organizational structure and capacity;

• The effectiveness of the operation of the Board and Committees;

• Corporate governance;

• An assessment of their own performance as Directors, including what might make them more effective as Directors; and

• An assessment of their peer Directors on the Board.

The assessment of the Chair of the Board was conducted in a meeting of all Directors that excluded the Board Chair, and was led by the Chair of the NCGC. Directors were asked to provide feedback directly to, and were given an opportunity to discuss the assessment of the Chair of the Board in a one-on-one format with, the Chair of the NCGC.

2015 Assessment Findings

The 2015 Board and Director Performance Assessment findings involved major themes, such as Emera’s strategy, its organizational structure and capacity, and its corporate governance. In the area of strategy, Directors acknowledged that significant work had been done to define the Company’s strategy for Shareholders, including defined dividend growth strategy (eight per cent per annum) and desired mix of 75 to 85 per cent regulated assets. Focus will remain on the delivery pursuant to that strategy. In connection with organizational structure and capacity, it was found that leadership development and succession planning had progressed. A high priority will be placed on planning for the anticipated closing of the acquisition of TECO Energy, Inc.

With support from the NCGC, the Chair of the Board will develop the action plan based on the 2015 Board and Director Performance Assessment findings, and progress on the action plan will continue to be reported to the Board. Recognizing that in person board meetings are limited and important opportunities for dialogue and engagement, the Board Chair will be working with management to enhance dialogue and reporting at Board meetings in order to focus upon those matters that are critical to, and foster the delivery of, the Company’s business plan and its long term strategy, with a view to creating shareholder value over the longer term.

Committees of the Board of Directors

The Board is committed to effectively and efficiently carrying out its oversight responsibilities. As such, it strongly supports the work of its three standing Committees, to which certain functions are delegated as set forth in the written charters. The Board Committees are:

• the Audit Committee

• the MRCC

• the NCGC

From time to time the Board may establish ad hoc committees.

In consultation with the Chair of the Board, the Board and its Committees may retain outside advisors as they deem necessary.

Emera Inc. — Management Information Circular 2016          33

Audit Committee

The Audit Committee is comprised of:

Chair: Ms. Rosen

Members: Ms. Loewen, Mr. Leonard, Mr. Pether

The Audit Committee assists the Board in discharging its oversight responsibilities concerning the integrity of Emera’s financial statements, its internal control systems, the internal audit and assurance process, the external audit process and its compliance with legal and regulatory requirements.

The Committee consists of independent Directors only, who each have a high degree of financial acumen. The Committee is responsible for reviewing and recommending to the Board the annual and interim financial statements and all related management discussion and analysis.

The Committee evaluates and recommends to the Board the appointment of the external auditor and the compensation of such external auditor. Once appointed, the external auditor reports directly to the Committee, and the Committee oversees the work of the external auditor concerning the preparation or issuance of the auditor’s report or the performance of other audit, review or attest services for Emera. The Committee reviews management controls and processes concerning the administration of investment activities, financial reporting, and financial performance and funding of the pension plans.

The Company’s internal auditor also reports directly to the Audit Committee, and the Committee oversees the appointment, replacement or termination of the internal auditor.

For the full text of the Audit Committee Charter, visit www.emera.com/governance.

Nominating and Corporate Governance Committee (NCGC)

The NCGC is comprised of:

Chair: Mr. Pether

Members: Mr. McLennan, Mr. Sergel

The NCGC assists the Board with a variety of matters relating to corporate governance. These duties include responsibility for providing the Company with a list of nominees for election as Directors to be included in the Company’s Management Information Circular prior to each annual meeting of Shareholders of the Company. For more information about the nomination of Directors, see Nomination of Directors, earlier in this Statement. The Committee consists of independent Directors only, selected by the Board. The Articles of Association of the Company provide that the Chair of the Board may not be a member of the Committee.

The NCGC is responsible for developing and communicating the Company’s approach to corporate governance issues, and reviews and approves Emera’s disclosure of corporate governance practices, including this Statement of Corporate Governance Practices. The Committee keeps abreast of best governance practices benchmarks and regularly evaluates the governance practices of Emera. It reviews any disclosure of the Company’s corporate governance practices in accordance with applicable rules and regulations.

The NCGC oversees the orientation of new Directors. This orientation program for new Directors is reviewed each time that a new Director joins the Board and is updated as required.

The Committee is responsible for assisting the Board of Directors in determining the proper and effective allocation of risk oversight responsibilities.

Other duties and responsibilities of the Committee include:

(a) assisting the Board and its Committees in determining Committee composition, as well as reviewing and updating the mandate of each Committee, for submission to the Board;

(b) making recommendations to the Board on all components of non-employee Director compensation, including the Board Chair and Committee Chairs;

(c) ensuring procedures are in place to assist the Board in obtaining information necessary to carry out its duties and ensuring the Board has access to executive management; and

(d) reviewing and updating the Company’s Standards for Business Conduct.

For the full text of the NCGC Charter, visit www.emera.com/governance.

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Management Resources and Compensation Committee (MRCC)

The MRCC is comprised of:

Chair: Mr. Edgeworth ⁽¹⁾

Members: Ms. Chrominska, Mr. Demone, Mr. Sergel

The MRCC consists of independent Directors only. The Committee reviews overall compensation, including salary and benefits policies and recommends such policies to the Board of Directors for approval.

The MRCC supports the Chair of the Board in conducting a review of corporate goals and objectives relevant to the President and CEO’s compensation and supports the Chair of the Board in recommending such goals and objectives for the current year to the Board of Directors. The Committee ensures that an assessment of the President and CEO’s performance in relation to these goals and objectives is completed. It makes recommendations to the Board of Directors relating to the President and CEO’s total compensation, including participation in incentive-compensation and equity-based plans. It also makes recommendations about senior management total compensation and incentive compensation plans and equity-based plans. It approves grants of stock options, Performance Share Units (PSUs) and DSUs in accordance with the provisions of the respective plans. It reviews executive compensation disclosure prior to the Company releasing such information to the public.

The Committee recommends executive officer appointments to the Board of Directors for approval. It supports and contributes to the Board’s succession planning process in respect of the President and CEO of the Company. It annually reviews the succession planning process for senior management and other potential senior management candidates, including for Emera’s subsidiaries, and oversees and contributes to that process. It reviews share ownership guidelines for executive officers. It satisfies itself that there are appropriate labour relations strategies in place and it regularly reviews management’s direction and decisions made in support of labour and employee relations. It also reviews the design of pension plans for the Company’s employees.

The MRCC is responsible for evaluating the compensation programs to determine that they do not reward executive officers for taking inappropriate risks that may harm the interests of the Company and its Shareholders. Under its Charter, the Committee must conduct a compensation risk review annually to ensure that the compensation policies are designed to take account of, and mitigate:

(a) incentive opportunities that inadvertently encourage excessive and unnecessary risk taking;

(b) pay structures that inadvertently encourage behaviour that negatively impacts long-term value;

(c) misalignment of pay and performance; and

(d) payouts which are not aligned with Emera’s business strategy.

For the full text of the MRCC Charter, visit www.emera.com/governance.

Communication with Directors

The Directors are always interested in receiving Shareholders’ views about the Company, its governance and its operation. The Board oversees systems for receiving feedback from Shareholders and it monitors feedback received by the Company.

Shareholders may communicate with the Chair of the Board or other independent Directors by mailing (by regular mail or other means of delivery) to the corporate head office at:

Attention: Chair of the Board, P.O. Box 910, Halifax, Nova Scotia B3J 2W5

In a sealed envelope marked “Private and Confidential – Attention, Chair of the Board of Directors of Emera Incorporated”

Additional Information

Additional information relating to the Company may be found at System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com. The Company’s financial information is contained in its comparative financial statements and management’s discussion and analysis for the financial year ended December 31, 2015.

For copies of the Company’s financial statements and management’s discussion and analysis, you may also contact the Office of the Corporate Secretary at:

Corporate Secretary

P.O. Box 910, Halifax, Nova Scotia B3J 2W5

Telephone: (902) 428-6096; Facsimile: (902) 428-6171; email: stephen.aftanas@emera.com

(1) Effective May 17, 2016, Mr. Edgeworth will step down as MRCC Chair, and Ms. Chrominska will become Committee Chair. Mr. Edgeworth will remain a member of the Committee.

Emera Inc. — Management Information Circular 2016          35

A Letter from the Management Resources and Compensation Committee to Our Shareholders

Dear Fellow Shareholders:

Emera is committed to creating sustainable value for all shareholders of the Company, which is significantly influenced by the quality of our executive team and their ability to lead and motivate all employees to act in the best interests of shareholders and customers. A fundamental principle of the Company’s compensation philosophy is that our compensation programs should align pay with performance, so that a significant portion of the compensation we pay our executives is directly linked to the achievement of objectives that measure whether shareholders are experiencing strong value for their investment. Moreover, we believe that aligning the interests of our executives with those of our shareholders is of utmost importance when making compensation decisions, which is why we require executives to hold significant equity in the Company. Our share ownership guidelines formalize our belief that executives must also be shareholders and maintain a material personal financial stake in the Company.

The Management Resources and Compensation Committee (MRCC or the Committee) is the steward of the Company’s compensation programs and oversees all aspects of executive compensation as part of our ongoing efforts to meet the expectations of our shareholders, customers, and regulators. The MRCC carefully determines how performance measures and targets are set. These measures and targets reflect the Company’s core values and short and long term strategic priorities. The targets must be achieved within the principles of prudent risk management, good corporate governance, and compliance with relevant standards and regulations. It is in light of these principles that the MRCC diligently oversees the establishment of the Company’s performance goals and assesses our executive compensation programs, while continuously seeking to improve our practices and standards.

We are pleased to provide you with an overview of our approach to executive compensation, the Board’s assessment of Emera’s 2015 performance, and our decisions relating to executive compensation.

Shareholder Engagement

In keeping with our ongoing commitment to strong corporate governance practices, we had our first “Say on Pay” advisory vote at our 2015 Annual General Meeting that allowed shareholders to indicate whether they were in agreement with Emera’s compensation practices and policies. Of the votes cast, 97.7 per cent were in favour of our approach to executive compensation and we will once again be presenting a “Say on Pay” non-binding advisory resolution at this year’s AGM. As part of our continued commitment to shareholder engagement, it is important for us to receive direct feedback from our shareholders and have constructive dialogue about our compensation decisions and other governance matters.

2015 Compensation Decisions

Our compensation philosophy targets the median level of compensation in the market, which is based primarily on companies in the utility and energy sector whose operations are of a similar size and nature as Emera. In recognition of the sustained leadership of Emera’s President and CEO in driving consistent top-quartile results, we position his target total compensation between the 50th and 75th percentile of the comparator group. At the end of 2014, the Committee reviewed benchmarking analyses from both management’s external compensation advisor, Mercer (Canada) Ltd., and the Committee’s independent compensation advisor, Hugessen Consulting Inc. The reviews indicated that the compensation of our named executive officers was below the targeted percentiles when compared against companies in our comparator group, particularly with respect to long-term incentive levels.

In light of our comparative compensation positioning to market, and to recognize the significant achievements of the named executive officers, the Committee adjusted the target compensation levels of our named executive officers in 2015 to bring them closer to the prevailing market levels. The average increase in base salaries was 2.7 per cent and the average increase in total target compensation (which consists of base salary, short-term incentive and long-term incentive) was 14.5 per cent. Based on the market data and in keeping with our pay-for-performance approach, the increases focused primarily on long-term incentive levels, which link compensation to performance metrics that measure long-term shareholder value. As a result of the changes, the variable or ‘at risk’ component of our named executive officers’ compensation increased from an average of 60 per cent to 64 per cent.

The Committee also made some adjustments to the stock option component of the Company’s long-term incentive plan in 2015. Each year, the Committee uses the Black-Scholes valuation methodology to value our stock options. After a review of the initial valuation in 2015, which would have led to a significant increase in the number of options granted in 2015 compared to 2014, the Committee instead opted to use an average of the previous three years’ Black-Scholes valuations to value the options, which led to fewer options being granted. The Committee believes the use of the three-year average was a prudent step to better reflect prevailing market conditions.

To further address the valuation of stock options, the Committee, with the assistance of its compensation advisor, Hugessen Consulting Inc., undertook a thorough review of market practices. The review concluded that while Black-Scholes remained an appropriate valuation methodology, the adoption of a ‘floor’ valuation ratio of 10 per cent (as a percentage of the share price) was reasonable. Accordingly, for the 2016 stock option grant, the Committee adopted the floor, which will apply when the Black-Scholes methodology leads to a valuation of less than 10 per cent of the share price. This will result in fewer stock options being granted, while maintaining options as a part of the long-term incentive plan.

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As in previous years, with the assistance of Mercer (Canada) Ltd., the Committee conducted a risk assessment intended to identify any potential risks associated with Emera’s current compensation design and policies, including any risks associated with the changes noted above. The assessment did not identify any material risks, but notwithstanding this positive result, we will continue to diligently monitor our programs so that we maintain our high governance standards.

Rewarding Results

2015 was a year of significant achievements for the Company, the most noteworthy of which was the announcement of the pending acquisition of TECO Energy, Inc. for $10.4 billion USD, one of the largest acquisitions in recent Canadian history. The addition of TECO Energy, Inc. is expected to be significantly accretive and will make Emera one of the 20 largest North American utilities, with more geographic, regulatory and business mix diversification. Some of the Company’s other key accomplishments in 2015 include:

• Emera announced two increases totaling 22.6 per cent in its annualized common share dividend rate, bringing the annual dividend to $1.90. The annual dividend growth target increased to eight per cent through 2019;

• Operating revenues (excluding mark-to-market impacts) increased to $2.83 billion in 2015 compared to $2.78 billion in 2014;

• Earnings before interest, income taxes, depreciation and amortization (EBITDA), excluding mark-to-market impacts, reached $1.03 billion, an 8.9 per cent increase over 2014 ($946.5 million);

• Adjusted net income increased to $330 million in 2015; adjusted net income, also excluding the costs associated with the pending acquisition of TECO Energy, Inc. was $382.8 million, compared to $319.2 million in 2014;

• Adjusted earnings per share (EPS) increased to $2.26 in 2015; adjusted EPS, also excluding the costs associated with the pending acquisition of TECO Energy, Inc. was $2.63, compared to $2.23 in 2014;

• Emera’s total assets increased 21.9 per cent to $12 billion in 2015 compared to $9.85 billion in 2014;

• The Company completed a $2.185 billion debenture offering, including an over-allotment of $285 million, to help fund the acquisition of TECO Energy, Inc.

The significant achievements noted above have led to Emera’s total shareholder return (TSR) considerably exceeding most of our market comparators, both over the past year as well as on an annualized basis over the past five years, as shown in the following table:

Total Shareholder Return

Emera Inc. — Management Information Circular 2016          37

Emera’s TSR exceeded the S&P/TSX Capped Utilities Index by 19.9 per cent in 2015 and by 7.6 per cent on an annualized basis over five years. Our TSR also exceeded the S&P/TSX Composite Index by 24.7 per cent over the past year and by 8.8 per cent on an annualized basis over the past five years.

Recognizing Emera’s strong performance against objectives established for the 2015 Corporate Balanced Scorecard, the Board approved an annual short-term incentive plan payout of 144.18 per cent of target. This short-term incentive plan ensures executives are rewarded for the achievement of key objectives linked to the Company’s corporate strategy. A full description of the 2015 Scorecard’s metrics and results is provided in 2015 Short-Term Incentive Results.

Our long-term incentive plan, which consists of Performance Share Units (PSUs) and stock options, is aligned closely with our performance objectives. PSUs are linked to performance metrics that are measured over a three-year period. The 2013 PSU Grant, which had a performance period from January 1, 2013 to December 31, 2015, used two equally-weighted metrics: (1) Emera’s TSR relative to the total return of the S&P/ TSX Capped Utilities index, and (2) the average growth in Emera’s earnings per share. Based on our strong performance against those two key metrics, the performance factor applied to the 2013 PSU Grant was 1.5, which is the maximum allowable under the PSU Plan. As a governance measure to help ensure payouts are not excessive, the PSU Plan caps each participant’s payout at two-times the initial grant value (when factoring in share price appreciation, notional dividend reinvestment, and the performance factor). The cap applied to the 2013 PSU payouts, thereby reducing the payouts from 212 per cent of the initial grant value to 200 per cent. More details are provided in the Performance Share Unit Plan section.

In addition, Emera’s strong performance led to an 11.9 per cent increase in our common share price, going from $38.64 as at December 31, 2014 to $43.23 as at December 31, 2015, which positively affected the value of the stock options we granted to our senior executives.

The Committee carefully reviews the metrics chosen for our incentive plans each year to ensure they continue to reflect the Company’s key strategic objectives.

The Committee also engaged Hugessen Consulting Inc. to update the Pay-for-Performance analysis of the compensation paid to the President and CEO, which is an annual review the Committee undertakes. The review looked at the compensation paid to Mr. Huskilson over his full tenure as President and CEO (from January 2005 to December 2015), and compared the investment returns experienced by shareholders over that same period. The analysis included both realized pay (consisting of amounts actually paid) and realizable pay (which consists of changes in the value of any outstanding equity-based awards). Once again, the analysis concluded that there was a close alignment between the President and CEO’s realized/realizable pay and the shareholders’ investment return experience over the long-term. Please see Total Shareholder Return vs. Named Executive Officer Compensation for more information on the analysis.

Based on the Company’s performance in 2015, we remain confident that our incentive plans and resulting payouts are closely aligned with the interests of our shareholders, so that both our shareholders and our executives benefit when the Company achieves strong results.

Sustaining Shareholder Value

Emera continues to grow and diversify its businesses, as evidenced by our strong financial results, with all of Emera’s operations throughout North America and the Caribbean playing an important role in the Company’s overall success. The significant accomplishments, both financial and non-financial, referenced in this Circular demonstrate the strength of our team of leaders and employees who will help ensure the Company is well positioned for the exciting period of growth and opportunity that lies ahead of us. We were pleased to see Emera receive an exceptional result in The Globe and Mail’s 2015 ‘Board Games’, an annual corporate governance rating compiled by the Report on Business.

We remain confident that our executive compensation programs appropriately incent and reward strong performance, and we will continue to monitor our practices and industry trends and adjust our practices accordingly. We welcome your review of our compensation programs and results, which are described in more detail in the Statement of Executive Compensation that follows. We encourage you to take part in our “Say on Pay” vote and, as always, we welcome your questions and feedback which can be provided by contacting the Corporate Secretary’s Office.

Allan Edgeworth	Sylvia Chrominska	Richard Sergel	Henry Demone
Director and Chair of the	Director and Member of the	Director and Member of the	Director and Member of the
Management Resources and	Management Resources and	Management Resources and	Management Resources and
Compensation Committee	Compensation Committee	Compensation Committee	Compensation Committee

Note: Operating revenues (excluding mark-to-market impacts), EBITDA (excluding mark-to-market impacts), adjusted net income and adjusted EPS are non-GAAP measures and do not have a standardized meaning. These non-GAAP measures are disclosed more fully in Emera’s 2015 Annual Report, which includes a reconciliation of non-GAAP measures to GAAP measures.

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Statement of Executive Compensation

Compensation Philosophy

The purpose of Emera’s executive compensation program is to:

• reward Emera’s executives for sustained increases in shareholder value;

• attract, retain and motivate highly qualified and high-performing executives; and

• align the interests of executives with the interests of Emera’s shareholders and customers.

Programs are designed to reflect a blend of short- and long-term incentive plans to reflect the Company’s pay-for-performance philosophy and to provide for a significant portion of an executive’s compensation to be at risk, while aligning the structure of programs and payouts with sound risk management and good governance principles.

Market Competitiveness

Emera’s executive compensation program is designed to generally provide total target compensation at the median or 50th percentile of compensation paid by companies in the utility and energy sector whose operations are of a similar size and nature as Emera. Pay positioning, in some specific cases, can be above or below the median based on experience, uniqueness of responsibilities, and performance. “Total target compensation” for senior management, including the named executive officers (NEOs), is comprised of base salary, target short-term incentive, and target long-term incentives linked to total shareholder value.

Pay-for-Performance

A central tenet of Emera’s executive compensation philosophy is that a significant portion of executive compensation must be at risk and linked to the achievement of objectives that measure whether shareholders are experiencing strong value for their investment. The at-risk components include both short- and long-term incentives, which establish measurable financial, customer, asset, employee and/or safety objectives that, if achieved, add value to the Company.

The incentive compensation plans are designed to pay larger amounts for superior performance and smaller amounts if target performance is not achieved. In addition, the Company must achieve a threshold level of performance for any payment against a particular objective, failing which there is no payment against that objective. Executives’ performance against those objectives are measured and rated by the President and CEO with a recommendation to the MRCC which, in turn, recommends to the Board of Directors for approval. The President and CEO’s performance is assessed by the Board Chair in collaboration with the MRCC.

Generally, the at-risk compensation component of total compensation increases based on the individual executive’s level of responsibility. Management considers many factors when developing the incentive plans, including current compensation trends, plan costs at payout including maximum payout values, expected value to be delivered to participants and analysis of threshold, target and stretch payouts. Both short- and long-term incentive plan designs are modelled using historical and prospective performance scenarios. This stress testing provides the MRCC with reasonable assurance that the plan payouts will be appropriate and aligned with shareholder and Company objectives. Analysis is done every year to determine how actual payouts compare to expected payouts and whether the plan components require any changes.

The MRCC reserves the right to exercise discretion in recommending that the Board adjust compensation payouts to align with Company results.

Emera Inc. — Management Information Circular 2016          39

Compensation Program

Emera’s compensation program includes the following components, which are discussed further in the pages noted:

Base Salary (page 48): Salaries are benchmarked against companies of similar size and scope as Emera and are set to reflect the degree of special skills and knowledge required for the position, and the performance and contribution of the individual.

Annual Short-Term Incentive (page 48): Short-term incentive objectives are set forth in annual scorecards and consist of key objectives linked to the Company’s corporate strategy. These scorecards establish measurable financial, customer, asset, employee and health and safety objectives that, if achieved, are designed to add value to the Company.

Long-Term Incentive (page 50): Consists of Performance Share Units (“PSUs”) and stock options. Levels are determined based on competitive benchmarking data and the degree of responsibility within the Company. They are intended to align executive performance with a long-term focus on creating and preserving shareholder value.

Pension (page 58): The Pension Plan consists of both defined benefit and defined contribution components, and a supplemental employee retirement plan, all of which are governed by a pension oversight governance framework.

Other Benefits (page 62): As an important part of competitive compensation, the Company also offers market competitive non-cash compensation components such as group benefits, vacation, car allowances, and wellness incentives.

Management Resources and Compensation Committee

The Board has assigned responsibility to the MRCC to determine the compensation for Emera’s executive officers, and to review, recommend and oversee the administration of all of the Company’s executive compensation plans and programs. Current members of the MRCC are:

• Mr. Edgeworth (Chair),

• Ms. Chrominska,

• Mr. Sergel, and

• Mr. Demone.

All members of the MRCC are independent Directors. Each member of the MRCC has experience with human resources issues and compensation matters. More detailed information is contained in Director Nominees.

The MRCC considers best practices in determining and monitoring Executive Compensation as discussed in this Circular:

The MRCC’s Letter to Shareholders outlines the Company’s approach to executive compensation.

The Company provides shareholders with the opportunity to vote on a “Say on Pay” resolution at its Annual General Meeting, which allows shareholders to indicate whether they are in agreement with Emera’s compensation practices and policies (97.7 per cent of votes cast last year were in favour of the Company’s approach).

The Company’s compensation programs are aligned with Emera’s corporate strategy through the use of performance metrics that support both short- and long-term strategic goals.

The MRCC has the discretion to reduce or withhold payouts under the short-term and equity-based incentive plans for results below expectations.

Compensation awards are tested for appropriate alignment between pay and performance under a number of scenarios.

Detailed information is provided on those companies used in the Company’s comparator group for benchmarking purposes.

Executive pay is aligned with shareholders’ interests by having a significant component at risk and tied to both short- and long-term performance.

Share ownership requirements are in place for designated executive officers.

A substantial portion of long-term incentives for the majority of the senior executives and other employees whose actions may have a material impact on the Company’s risk profile is deferred to discourage leaders from taking short-term or excessive risks.

A pension oversight governance framework is in place for pension benefits.

The Company monitors the ratio of its NEOs’ total compensation to the average employees’ total compensation.

The Company has a clawback policy that allows the Company to recoup short- and long-term incentive payments made to senior executives.

40           Emera Inc. — Management Information Circular 2016

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Committee Governance

The MRCC is responsible for reviewing the alignment of Emera’s compensation programs, including incentive pay programs, with Emera’s strategic plans, performance and risk management principles. The Committee annually reviews compensation for the President and CEO and senior management of the Company. The MRCC oversees the administration of the incentive plans providing for the award of short-term incentives, stock options, PSUs and deferred share units (DSUs) in accordance with the provisions of the respective plans.

The Committee reviews, and recommends to the Board of Directors, compensation policies and processes, any new incentive and equity compensation plans and any changes to such plans.

The Board Chair collaborates with the MRCC in assessing the performance of the President and CEO on an annual basis.

Risk Management and Compensation

As part of the Board and MRCC’s oversight responsibilities for the design and administration of the Company’s executive compensation programs, the MRCC identifies and discusses design features or processes that may potentially represent conflicts of interest and/or inducements for unnecessary or excessive risk-taking by senior executives.

The MRCC also regularly monitors industry trends with respect to risk management and conducts an annual risk assessment. Emera’s compensation programs and policies are designed to incorporate the Company’s view on appropriate risk, as demonstrated by the elements shown below, which are discussed in greater detail in the sections that follow:

The Company regularly reviews its executive compensation programs with third party compensation advisors to confirm the programs continue to support shareholder interests and regulatory compliance, and are aligned with sound principles of risk management and governance. The MRCC retains an independent compensation advisor that does not provide any services directly to management.

The Company has a pay-for-performance philosophy and the mix of short- and long-term programs assist in mitigating excessive risk taking.

Caps on payouts, vesting requirements, stress-testing potential payouts, clawback provisions and share ownership requirements are part of the Company’s overall plan design.

The Company’s compensation governance structure involves the Board, the MRCC, the MRCC’s external compensation advisor, management and management’s external compensation advisors.

All members of the MRCC are knowledgeable individuals who have the necessary background and expertise in human resources issues and compensation matters to fulfil their obligations to the Board and to shareholders.

Emera Inc. — Management Information Circular 2016          41

Risk Assessment

In 2015, the MRCC conducted its annual compensation risk review of its executive compensation programs and policies. Mercer (Canada) Ltd. (“Mercer”) was engaged to review the previous year’s comprehensive risk assessment that it conducted for any material changes over the course of the year. Mercer once again concluded that Emera has risk mitigation policies in place that are aligned with market best practices and did not identify any material risks arising from Emera’s compensation policies and practices. Based on this assessment, the MRCC determined that:

• Total compensation is appropriately balanced between short-term and long-term horizons and the mix of base salary and short- and long-term incentives does not create an inducement to take inappropriate risk to the detriment of the Company’s shareholders;

• The existence of multiple performance measures in the incentive plans (including non-financial measures) helps to avoid undue focus on any one particular metric;

• The short-term incentive plan focuses on growth of annual earnings and cash flow, but caps incentive payouts in a manner consistent with market practice, thereby reducing risk;

• Risks associated with the Long-term Incentive Plan are mitigated by annual grants (versus front-loading grants) of PSUs and stock options, and also by caps on payouts in the case of grants under the PSU Plan;

• The MRCC’s discretion to reduce or withhold payment under the short-term and equity-based incentive plans for results below expectations decreases any risks associated with those plans;

• Emera’s executive share ownership requirements decrease risk in the compensation program by encouraging alignment between the interests of senior officers and shareholders. In addition, the Company’s anti-hedging policy helps to maintain that alignment by prohibiting senior officers from hedging, pledging, monetizing or otherwise reducing or limiting their economic risk with respect to any Emera securities they hold. The ownership requirement includes a one-year hold period post-retirement for the President and CEO;

• The vesting conditions on retirement are an important retention tool for designated executives of the Company;

• The clawback policy also contributes to the Company’s risk mitigation efforts (the clawback policy allows the Company to recoup short- and long-term incentive payments made to senior executives in cases where: (a) such payments were based upon reported financial results that were subsequently corrected or restated as a result (or partial result) of the executive’s gross negligence, misconduct, or fraud and the reward received would have been lower had the financial results been properly reported; or (b) where the executive commits a serious breach of the Company’s Standards for Business Conduct; and

• The inclusion of double trigger provisions in employment contracts for senior officers and the absence of enhanced benefits for change of control mitigates the risk arising from termination.

Accordingly, based on the governance practices in place and the results of the risk assessment, the MRCC concluded that Emera’s compensation programs did not create inordinate risk to shareholders because an appropriate system of checks and balances is in place to mitigate the level of risk undertaken by management. The MRCC satisfies itself as to the adequacy of the information it receives regarding risk, the independence of the risk assessment and reviews, and the reporting of financial results on which certain important compensation decisions (e.g., the amount of short-term incentive to be paid) are based.

The MRCC and Board will continue to review the relationship between enterprise risk and the Company’s executive compensation plans and policies to confirm they continue to be optimally aligned with shareholder interests while maintaining an acceptable level of risk exposure.

Succession Planning and Leadership Development

The MRCC has responsibility for overseeing the succession planning process for senior management of the Company and its affiliates, and reviews this process on an annual basis. The Board has responsibility for the development of succession plans and the approval of all executive appointments. At Emera, succession planning is a dynamic, ongoing process of systematically identifying, assessing and developing leadership competencies and business skills. The purpose is to confirm the Company’s capacity to meet future strategic objectives and to replenish critical organizational roles over time.

As part of the comprehensive succession planning process at Emera, the President and CEO annually provides a list of potential successors for his position to the MRCC. In addition, the President and CEO identifies internal successors for each of the NEOs and senior management positions throughout the Company and its affiliates. The Committee oversees the management succession planning process and developmental strategy.

Emera is committed to developing leaders at all levels and has a comprehensive annual assessment process and framework to coordinate leadership development across the Company. This assessment process identifies areas of development for individuals as well as the overall leadership team with regards to identified core leadership capabilities. Personal development plans and overall Company leadership development programs are in place for both existing and potential leaders. The Company focuses on ensuring challenging work assignments are offered, secondments to affiliates occur where appropriate, regular leadership development training occurs and mentors are assigned where beneficial.

Emera will continue these focused efforts to build leadership capacity throughout the organization in support of its long-term growth strategy.

42           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Compensation Advisors

The MRCC retains the services of independent compensation advisors to assist in discharging its duties, including determining the compensation payable to the President and CEO and other senior officers.

Since 2007, the MRCC has engaged Hugessen Consulting Inc. (“Hugessen”) as its principal advisor to provide independent advice, compensation analysis and other information for compensation recommendations. Hugessen provides advice on the competitiveness and appropriateness of compensation practices and comparator groups for Emera and its affiliates. In addition, Hugessen provides advice to the MRCC on policy recommendations made by management, and also reviews and provides commentary on the Company’s Statement of Executive Compensation. As independent advisors to the MRCC, Hugessen does not provide any professional services to management.

The MRCC has adopted a number of practices with regard to its executive compensation advisor:

• The MRCC annually reviews its advisor’s performance and fees.

• With input from Company management and the advisor, the MRCC annually, or on an as-needed basis, determines the specific work to be undertaken by the advisor and the fees associated with this work.

• All services provided by the MRCC’s advisor beyond its role in supporting the requirements of the MRCC require written pre-approval by the MRCC Chair, outlining the scope of work and related fees.

• The MRCC does not approve any such work that, in its view, could compromise the advisor’s independence in serving the MRCC.

In addition to the MRCC’s compensation advisor, in 2015, Emera engaged the services of Mercer and Morneau Shepell to assist in executive compensation matters.

In making its decisions on the compensation program, the MRCC reviews information and recommendations provided by Hugessen, Mercer, and Morneau Shepell, but all decisions remain the responsibility of the MRCC and the Board.

The table below summarizes the fees paid to all external compensation advisors in 2014 and 2015.

			2015				2014
Advisor	MRCC work ($)		Other work ($)		MRCC work ($)		Other work ($)
Hugessen Consulting Inc.		188,177		Nil		90,025		Nil
Morneau Shepell		Nil		56,654		Nil		67,628
Mercer (Canada) Ltd.		Nil		60,761		Nil		38,501

Compensation Discussion and Analysis

Named Executive Officer Compensation

For the purposes of compensation disclosure, the individuals disclosed in this Compensation Discussion and Analysis are the President and CEO, the CFO, and the next three most highly compensated executive officers of the Company, or its subsidiaries, as defined by Canadian securities legislation (the “Named Executive Officers” or “NEOs”):

• Christopher Huskilson, President and Chief Executive Officer, Emera Inc. (“President and CEO”);

• Scott Balfour, Chief Financial Officer and Chief Operating Officer, Northeast and Caribbean, Emera Inc. (“CFO”);

• Nancy Tower, Chief Corporate Development Officer, Emera Inc.;

• Robert Bennett, President and Chief Executive Officer, Emera U.S. Inc.; and

• Robert Hanf, President and Chief Executive Officer, Nova Scotia Power Inc. (“NSPI President and CEO”).

Christopher Huskilson, President and Chief Executive Officer, Emera Inc.

The strong performance of Emera in 2015 was led by the President and CEO. Under Mr. Huskilson’s leadership, Emera posted strong financial results in 2015 and achieved a number of important strategic milestones across the business. The Company strengthened earnings year over year, raised the dividend by 22.6 per cent and was among the leaders in the sector in value creation. This past September, Emera announced the acquisition of TECO Energy, Inc., a significantly accretive transaction that will make Emera one of the 20 largest electric utilities in North America.

The Company made substantial progress against its strategy to deliver cleaner and more affordable energy for its customers. Renewable energy projects under development include the Maritime Link, Cape Sharp Tidal and a utility-scale solar generating facility in Barbados.

Scott Balfour, Chief Financial Officer and Chief Operating Officer, Northeast and Caribbean, Emera Inc.

Mr. Balfour took on an expanded role in 2015 as Chief Operating Officer for Emera’s existing businesses in the US and Caribbean. He played a central role in the planning and financing for $2.6 billion of capital market financings, including the $2.2 billion convertible debenture financing for TECO Energy, Inc. He also led key aspects of Emera’s strategy work and the further shaping of Emera’s capital market positioning. This included the enhancement of Emera’s dividend strategy by increasing the annual dividend growth target to eight per cent through 2019.

Emera Inc. — Management Information Circular 2016          43

Nancy Tower, Chief Corporate Development Officer, Emera Inc.

Ms. Tower has responsibility for overall business development opportunities across Emera and all affiliates to ensure alignment with the Company’s long-term strategy. She led the comprehensive effort to analyze and propose the acquisition of TECO Energy, Inc., which is a key and transformational accomplishment in 2015. She continues to be focused on the important task of closing the transaction in 2016.

Robert Bennett, President and Chief Executive Officer, Emera U.S. Inc.

Mr. Bennett took on the new role of President and CEO, Emera U.S. Inc. in late 2015 in which he will lead the planning and integration of TECO Energy, Inc. Prior to this role, he held the position of Chief Operating Officer, Eastern Canada with Emera Inc. where he was responsible for governance and oversight of Canadian affiliates. This included supporting leadership development and aligning opportunities for regional synergies within Nova Scotia Power Inc., Emera Maine, Emera New Brunswick and Emera Utility Services.

Robert Hanf, President and Chief Executive Officer, Nova Scotia Power Inc.

Mr. Hanf completed his third year as President and CEO of Nova Scotia Power Inc., delivering strong results, which included the establishment of a rate stability plan and fuel cost reductions. He remained focused on an improved business model, service delivery to Nova Scotia Power Inc.’s customers and capital planning.

The total target compensation for each NEO in 2015 is outlined below:

Name	Base salary ($)		Short-term incentive at target (% of salary)		Short-term incentive at target ($)		Long-term incentive at target (% of salary)		Long-term incentive at target ($)		Total target compensation ($)
Christopher Huskilson		875,000		90		787,500		240		2,100,000		3,762,500
Scott Balfour		475,000		70		332,500		125		593,750		1,401,250
Nancy Tower		475,000		60		285,000		100		475,000		1,235,000
Robert Bennett		475,000		60		285,000		100		475,000		1,235,000
Robert Hanf		400,000		50		200,000		60		240,000		840,000

The following table shows the percentage weighting of each component of the total target compensation for the NEOs. In keeping with the Company’s pay-for-performance philosophy, the 2015 compensation plan design resulted in at least 50 per cent of each NEO’s total target compensation being at risk, with the average for the five NEOs being 64 per cent.

Name	Base salary (%)		Annual incentive at target (%)		Long-term incentive at target (%)		Total pay at risk (%)
Christopher Huskilson		23		21		56		77
Scott Balfour		34		24		42		66
Nancy Tower		38		24		38		62
Robert Bennett		38		24		38		62
Robert Hanf		48		24		28		52

44           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Compensation Process

Benchmarking Data

The MRCC is responsible for annually reviewing the composition and use of comparator groups to assist in determining the compensation recommendations for the Company’s senior officers, including its President and CEO, which are then brought to the Board for approval. The MRCC undertakes periodic reviews of compensation design and total compensation opportunities for the senior management team, including the NEOs. This practice ensures the programs are current and that they fairly compare for particular roles, recognizing varying responsibility and scope of executive positions within Emera and its affiliates.

Emera management engages the services of Mercer, an independent compensation advisor, to compile market information on senior management compensation relating to base salary, short-term and long-term incentives. A complete benchmarking review takes place every two years and the scope of services includes: competitive market reviews of senior executive compensation levels; review and observations of current executive compensation philosophy, policies and practices; and a review of pay and performance comparators. Mercer conducted a compensation benchmarking review of the executive team for 2015 and, with the assistance of Hugessen, the MRCC undertook a review of the competitiveness and appropriateness of compensation programs specifically for the President and CEO and the CFO.

The MRCC reviews compensation data based on a comparator group of companies, primarily regulated utilities and other energy industry enterprises that are of a similar size and scope as Emera. The rationale for incorporating the energy industry is that senior talent can migrate between similar organizations (i.e. industry, scale, complexity) and the fact that Emera’s strategic objectives include expansion into various energy-related sectors.

In 2015, with the assistance of both Mercer and Hugessen, the MRCC also conducted a thorough review of the comparator companies to confirm they continued to be appropriate in terms of size and scope. The review focused on companies in the Canadian utility and energy sectors that are of comparable size to Emera, which was generally viewed as being within the range of half to twice the size of Emera in terms of total enterprise value and total asset size. Based on that review, the Committee updated the comparator group to the following 13 organizations:

Pay Benchmarking Comparator Group (Applicable to Emera NEOs)

Utilities Industry Comparables
ATCO Ltd.	Fortis Inc.
Capital Power Corporation	TransAlta Corporation
EPCOR Utilities Inc.	Hydro One
Energy Industry Comparables
AltaGas Ltd.	Inter Pipeline Ltd.
ARC Resources Ltd.	Pembina Pipeline Corporation
Canadian Oil Sands Ltd.	Tourmaline Oil Corp.
Crescent Point Energy Corp.

Emera Inc. — Management Information Circular 2016          45

The following table shows where Emera is positioned compared to the companies in the peer group identified above, based on selected key financial metrics. Emera is generally positioned around the median of the comparator group metrics.

Emera vs. Pay Benchmarking Comparator Group

(1) As at most recent comparator screening (as of September 2, 2015). Market Capitalization is calculated based on the number common voting shares multiplied by the closing share price. Total Enterprise Value is calculated on Market Capitalization plus net debt.

(2) Reported assets, as at most recent fiscal quarter end (as of June 30, 2015).

(3) Last twelve months as at most recent fiscal quarter end (as of June 30, 2015).

Note: The above table was prepared by Hugessen Consulting using data from S&P Capital IQ.

With the expected acquisition of TECO Energy, Inc. in 2016, the MRCC expects to reevaluate the comparator group in light of the significant increase in size of Emera and the broader geographic scope and complexity. In late 2015, the MRCC worked with Hugessen to begin deliberations on the appropriate market comparators for the Company on a post-acquisition basis. Any changes to the comparator group that the MRCC approves in 2016 will be reported in next year’s Management Information Circular.

A different comparator group is used to benchmark the NSPI President and CEO, which reflects the size, scope and nature of Nova Scotia Power Inc.’s operations. Concurrent with the Emera comparator group review, the MRCC and the NSPI Human Resources and Governance Committee conducted a review of the comparator group for NSPI. The review focused on companies in the Canadian utility sector that are of comparable size to NSPI, which was generally viewed as being within the range of half to twice NSPI’s revenue and total asset size. Based on that review, the NSPI comparator was updated to the following group:

   Pay Benchmarking Comparator Group (Applicable to NSPI President and CEO)

Utilities Industry Comparables – Publicly Available Disclosure
Alberta Electric System Operator	FortisBC
ENMAX Corporation	Northland Power Inc.
EPCOR Utilities	Toronto Hydro
Fortis Alberta

The NSPI Human Resources and Governance Committee and MRCC will continue to regularly review the composition of NSPI’s comparator group to ensure it continues to reflect NSPI’s characteristics.

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In addition to using publicly disclosed compensation data referenced above, the MRCC also uses Mercer’s Total Compensation Survey for the Energy Sector to benchmark executive compensation using data from energy and services companies with similar revenues to Emera. To provide sufficient data in some cases, the Mercer Benchmark Database Survey (which is a general industry database) is also used to expand the survey scope to include Canadian general industry companies of similar size to Emera.

Annual Compensation Review Process

For each executive position, a range for base salary, target short-term incentive, and target long-term incentive is established annually, using the benchmarking data referenced above along with other information on industry trends for positions of similar scope and responsibility.

The President and CEO conducts annual performance assessments on members of the senior management team, including each of the NEOs, which shape the annual salary adjustment recommendations. Based on the performance assessments and the benchmarking data, the President and CEO then recommends total target compensation for each senior leader, including the NEOs (but excluding himself) to the MRCC for review and approval. With respect to the President and CEO, the MRCC reviews benchmark data and other information regarding industry trends for positions of similar scope.

Following this process, the MRCC makes recommendations for total target compensation for all of the senior management team including the NEOs and the President and CEO, to the Board of Directors. As part of the annual compensation review process, the MRCC reviews emerging best practices and risk considerations.

At the end of 2014, the Company’s external compensation advisors, Mercer and Hugessen provided the results of their benchmarking reviews, which indicated that the compensation of the NEOs was below the targeted percentiles when compared against companies in the Company’s comparator group, particularly with respect to long-term incentive levels. In light of the comparative compensation positioning to market, and to recognize the significant achievements of the named executive officers, the MRCC recommended adjustments to the target compensation levels of the NEOs in 2015 to bring them closer to the prevailing market rates, which were approved by the Board of Directors.

The compensation changes from 2014 to 2015 are summarized below:

		Short-Term	Long-Term	Total Target
		Incentive Target	Incentive Target	Compensation
	Base Salary	(% of base salary)	(% of base salary)	(% increase)	Compensation at Risk
Christopher Huskilson	No change	No change	Increase from 220 to 240	4.9	Increase from 76 per cent to 77 per cent
Scott Balfour	Increase from $473,800 to $475,000	Increase from 60 to 70	Increase from 80 to 125	23.2	Increase from 58 per cent to 66 per cent
Nancy Tower	Increase from $460,000 to $475,000	No change	Increase from 70 to 100	16.7	Increase from 57 per cent to 62 per cent
Robert Bennett	Increase from $460,000 to $475,000	No change	Increase from 70 to 100	16.7	Increase from 57 per cent to 62 per cent
Robert Hanf	Increase from $360,000 to $400,000	No change	No change	11.1	No change (52 per cent)

Based on the market data and in keeping with the Company’s pay-for-performance approach, the increases focused primarily on long-term incentive levels, which link compensation to performance metrics that measure long-term shareholder value. The average increase to base salaries was 2.7 per cent, while the average increase in target total compensation (which consists of base salary, short-term incentive and long- term incentive) was 14.5 per cent. As a result of the changes, the variable or ‘at risk’ component of the NEOs’ compensation increased from an average of 60 per cent to an average of 64 per cent.

The changes made to the compensation of the respective NEOs in 2015 are also reflected in the NEO Summary Compensation Table.

Emera Inc. — Management Information Circular 2016          47

Elements of Compensation

Base Salary

As noted in Benchmarking Data, the MRCC is responsible for annually reviewing the composition of the compensation the Company pays its executives, including base salary. While the MRCC focuses on total compensation as a whole, base salary remains an important part of the overall compensation package the Company offers its executives.

Short–Term Incentive Program

The compensation awarded under the Short-Term Incentive Program is intended to link a portion of an executive’s compensation to the achievement of predetermined levels of performance in support of corporate and business unit objectives. These objectives are designed to focus on short-term goals (typically on an annual basis) that are intended to deliver value to customers and contribute to increased shareholder value in the longer term. Emera has adopted the scorecard approach to translate corporate strategies into measurable incentive plan goals. Target payouts under the scorecards are generally set as a percentage of salary and are benchmarked against the median for positions with similar responsibilities in comparator companies.

On the recommendation of the MRCC, the Board of Directors of Emera approves scorecards that set forth corporate objectives and related threshold, target and stretch performance levels to be achieved each year. For NEOs who participate in the NSPI Scorecard instead of the Emera Scorecard, the Board of Directors of NSPI approves the respective corporate objectives and performance levels. Short-term incentive payouts for the majority of senior management, including the NEOs, are based on scorecard results with potential payouts ranging from 0 to 200 per cent of target.

All NEOs have their short-term incentive payout calculated based on results achieved through scorecard results.

2015 Short-Term Incentive Results

2015 Emera Corporate Scorecard

The scorecard for Emera (“Emera Corporate Scorecard”) was developed by management and approved by the Emera Board of Directors, on the recommendation of the MRCC, at the beginning of 2015. It was used to determine the short-term incentive payout for Emera’s President and CEO, the CFO, the Chief Corporate Development Officer, and the President and Chief Executive Officer, Emera U.S. Inc.

The Emera Corporate Scorecard objectives were based on the Company’s Business Plan for the year and established threshold, target, and stretch performance standards for each objective.

The following table shows the elements and results of the Emera Corporate Scorecard for 2015.

					Actual	Percentage
Emera Corporate Objective	Weighting (%)	Threshold ($)	Target ($)	Stretch ($)	Result ($)	Payout (%) (1)
Cash From Operations (2)	50	539.4M	674.2M	809.0M	725.9M	69.18
Earnings Per Share (2)	30	2.07	2.27	2.47	2.63	60.00
Continued Development of Leaders	10	90% of Emera’s senior leadership team participate in a training session on two of the following areas of focus: strategy, communication and/or goal alignment PLUS improvement in results of the Future Vision Index on the Employee Survey over 2014 results.			Target Achieved	10.00
Safety & Environment	10	Increase number of proactive incident reports to total recordable injuries across Emera to a ratio of 40:1 AND Environmental Audit Program completed with no findings of major risk PLUS All Injury Frequency Rate of 1.30 or less AND all Environmental critical targets are 100% complete PLUS Move safety culture forward with results of 86% or greater in the safety section of the Employee Engagement Survey.			Threshold   Achieved	5.00
	100					Total: 144.18

(1) Percentage payouts, below or above target for financial measures, are prorated on a scale between each level of performance (50 per cent for threshold, 100 per cent for target and capped at 200 per cent for stretch).

(2) Cash from operations and EPS for compensation purposes are non-GAAP measures. See footnotes 3, 4 and 5 in the table following for information on the calculation of these measures.

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As a result of two safety incidents at Emera’s affiliate companies in 2015, management made a recommendation to the MRCC to reduce the ‘Safety & Environment’ metric result to the threshold level. The MRCC and the Board agreed with the recommendation and adjusted the Scorecard accordingly, leading to an overall result of 144.18 per cent.

The table below shows how Emera’s EPS and cash from operations has trended from 2010 to 2015 (the amounts shown are as at December 31 of each year).

	2010	(1)	2011	(1)(2)	2012	(2)	2013	(2)	2014	(2)	2015	(3)(4)
Earnings Per Share ($) (5)	1.76		1.77		1.85		1.96		2.23		2.63
Cash From Operations ($) (5)	419.2M		399.5M		397.6M		564.2M		762.5M		725.9M

(1) EPS for compensation purposes in 2010 and 2011 reflected reported EPS, excluding mark-to-market gains and losses and Light & Power Holdings, Ltd. acquisition gains.

(2) EPS for compensation purposes in 2011, 2012, 2013 and 2014 reflected EPS-basic adjusted for the income effect of Emera’s held-for-trading derivative instruments and the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp Power Company LLC (“BSPC”) and Northeast Wind Partners II, LLC (“NWP”), as well as the amortization of transportation capacity recognized as a result of certain trading and market transactions.

(3) EPS for compensation purposes in 2015 reflected EPS-basic adjusted for the income effect of Emera’s held-for-trading derivative instruments and the mark-to-market adjustments included in Emera’s equity income related to the business activities of BSPC and NWP, until NWP’s sale on January 29, 2015, the amortization of transportation capacity recognized as a result of certain trading and market transactions, the mark-to-market adjustment related to an interest rate swap in Brunswick Pipeline as well as the mark-to-market adjustments included in Emera’s other income related to the effect of USD denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from Emera’s Debenture Offering and acquisition costs including legal, advisory, and financing costs related to Emera’s pending acquisition of TECO Energy, Inc.

(4) Cash from operations for compensation purposes in 2015 reflected net cash provided by operating activities adjusted for the cash flow effect of acquisition costs including legal, advisory, and financing costs related to the pending TECO Energy, Inc. acquisition. Cash from operations for compensation purposes is a non-GAAP measure and is disclosed more fully in Emera’s 2015 Annual Report.

(5) Cash from operations and EPS for compensation purposes are non-GAAP measures and are disclosed more fully in Emera’s Annual Report for the applicable year.

Scorecard payouts on average over the last five years have been 39 per cent over target. EPS performance has trended upwards over the same period, increasing 49 per cent over the period from 2010 to 2015.

2015 Nova Scotia Power Incorporated (NSPI) Corporate Scorecard

The 2015 NSPI Scorecard set out corporate objectives and related threshold, target and stretch performance levels for 2015. It was used to determine the short-term incentive payout for the NSPI President and CEO.

The NSPI Scorecard is developed and recommended by NSPI management for approval by the NSPI Human Resources and Governance Committee and Board, which in turn recommends the NSPI Scorecard for final approval at the beginning of each year by the Emera MRCC.

On the recommendation of the NSPI Human Resources and Governance Committee, the Emera MRCC approved the 2015 NSPI scorecard to be paid out at 115.36 per cent of target, which was used to calculate the payout for the NSPI President and CEO.

The table on the following page shows the elements and results of the NSPI Scorecard for 2015.

Emera Inc. — Management Information Circular 2016          49

				Percentage
NSPI Corporate Objective	Target	Weighting (%)	Actual Result	Payout (%)
Safety Build and sustain continual improvement toward World Class Safety performance	95% of senior management team complete two critical task reviews; PLUS 80% of employees complete Safe Start education session; PLUS 10% increase in Proactive Incident reporting over 2014 actuals; PLUS 10% reduction in controllable vehicle Incidents in 2015	7.5	Below   Threshold	0
People Enhance Employee Engagement	95% of senior management team develop and implement leadership action plans from the 2014 Annual Employee Survey; PLUS 75% of senior management team execute one team building activity focusing on engaging employees and connecting with the community; PLUS achieve 3% points improvement on the Employee Engagement Index, PLUS 3% points improvement on employee survey follow-up	12.5	Target	12.50
Customer Build reputation for service and reliability	Continue to improve system reliability, as represented by System Average Interruption Frequency Index (SAIFI) x System Average Interruption Duration Index (SAIDI) (including extreme events) < 26%; PLUS Customer Satisfaction Score > 71%	25	Between Target   and Stretch	27.50
Asset Management Transition the generation resources in a cost effective and sustainable manner for our customers	Projects >$1.5M are executed in 2015 with total spending within plus 2.5% or minus 10% of total project budget; PLUS adoption of a Generation Unit Utilization & Investment Plan and T&D Asset Management strategy; PLUS achieve an average DAFOR =<3% on generating units with capacity factors over 70%	15	Between Target   and Stretch	22.50
Financial - Earnings and Cost Structure (1)	$130M of earnings or regulated ROE of 9.25% AND an incremental $5M reduction of the current non-fuel deferrals AND OM&G spend (excluding pension and storms) of $202.5M	20	Stretch	30.00
Financial – Cash Flow (1)	$370M and average working capital as a % of revenue of 22.2%	20	Between Target   and Stretch	22.86
		100		Total: 115.36

(1) The financial measures are prorated on a scale between each level of performance. Percentage payouts in between threshold and target, and in between target and stretch, are prorated on a scale between each level of performance (50 per cent for threshold, 100 per cent for target and 150 per cent to 200 per cent for stretch). The threshold level for Earnings was $129 million and an OM&G spend (excluding pension and storms) of $212.5 million, while the stretch level was $130 million or regulated ROE of 9.25 per cent, an incremental $5 million reduction of the non-fuel deferrals, and an OM&G spend (excluding pension and storms) of $202.5 million. The cash flow objective at threshold was $355M and average working capital of 24.3 per cent of revenue; the stretch level was cash flow from operations of $385M and average working capital of 20.4 per cent of revenue.

As a result of a safety incident at Nova Scotia Power Inc. in 2015, management made a recommendation to the Nova Scotia Power Inc. Human Resources and Governance Committee and the MRCC to reduce the ‘Safety’ metric result to zero. The Nova Scotia Power Inc. Human Resources and Governance Committee, the MRCC and the Board agreed with the recommendation and adjusted the overall Scorecard accordingly, leading to an overall result of 115.36 per cent.

Long-Term Incentive Program

There are two primary components of long-term incentive compensation for senior management, including the NEOs: the Performance Share Unit Plan (the “PSU Plan”) and the Senior Management Stock Option Plan (the “Stock Option Plan”). The MRCC is responsible for granting PSUs and stock options.

The number of PSUs and stock options granted to senior management is determined after considering competitive benchmarking data and the individual’s level of responsibility within the Company. Grants are calculated each year based on each executive’s long-term incentive target percentage and base salary and, generally, the grant amount increases with the level of responsibility. The value of PSUs and stock options increase or decrease over the term of a particular grant based on increases or decreases in Emera’s common share price.

The MRCC takes into account previous grants and looks at a three-year history of total compensation each year before approving any new stock option and PSU grants for senior management (including the NEOs). This helps to ensure grants remain reasonable in light of market data and the performance of both the Company and the individual.

50           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

In 2015, 50 per cent of the target long-term incentive compensatory value for the President and CEO consisted of PSUs and 50 per cent consisted of stock options. For all other NEOs, PSUs made up 75 per cent of the target long-term incentive compensatory value and stock options made up the remaining 25 per cent. More details about the PSU Plan and the Stock Option Plan are set forth below.

Performance Share Unit Plan

The PSU Plan is designed to retain and incent employee participants by allowing senior management and key employees in specific roles to participate in the long-term success of the Company. A PSU is a notional share unit that is based on the value of an Emera common share – the value of a PSU changes directly in correlation to the value of an Emera share. PSUs also attract dividends similar to Emera shares; when a dividend is paid on Emera’s common shares, each participant is allocated additional PSUs based on the dividend paid on an equivalent number of Emera common shares.

Each year, designated senior leaders are awarded PSUs based on a pre-determined target of their base salary and the average 50 trading-day Emera common share price immediately preceding the effective grant date (the average is used to smooth out any short-term fluctuations in the share price). Each PSU grant has a three-year performance period. In addition to being affected by fluctuations in the Emera share price, the value of a PSU is also dependent on the achievement of financial objectives that help measure the increase in shareholder value. The MRCC establishes these financial objectives at the beginning of the performance period. By linking the value of the PSUs to Emera’s financial performance, the plan aligns the interests of senior leaders with the interests of Emera’s shareholders and helps ensure that both shareholders and plan participants benefit when the Company achieves strong results. All PSU grants and payouts must be approved by the MRCC.

At the end of the performance period, a performance factor is applied to the PSU grant based on the achievement of the financial objectives. If the Company fails to meet the performance objectives for a particular PSU grant, the Plan may pay out at less than target, or may not pay out any amounts at all. If targets are exceeded, payouts may be as much as, but not more than, two times the initial grant value.

Accordingly, the amount payable to participants, including NEOs, at the end of the three-year performance period is determined by:

    PSU Payout           =     Original Grant + Notional Dividends     x         Performance Factor         x         Closing Share Price    

Similar to the methodology on grant, the payout is based on the average 50-day closing price for Emera common shares at the end of the three-year performance period to smooth out short-term price fluctuations.

The metrics for the 2013 PSU Grant, which had a performance period of January 1, 2013 to December 31, 2015, are shown below.

Performance Factor 1

The first performance factor was based on Emera’s average three-year total shareholder return (TSR) relative to the average three-year TSR of the S&P/TSX Capped Utilities Index as illustrated in the table below.

Relative annual return to S&P/TSX Capped Utilities Index	Performance factor
Less than –5%		0
–5%		0.5
0%		1.0
5% or more		1.5

Performance Factor 2

The second performance factor was based on Emera’s average annual growth in EPS:

Emera average three-year Earnings Per Share growth	Performance factor
Less than 4%		0
4%		0.5
6%		1.0
8% or more		1.5

In addition, dividends had to be maintained at or higher than the December 31, 2012 levels; if dividends were reduced, the second performance factor would be deemed to be zero regardless of the EPS growth.

Each performance factor was weighted equally at 50 per cent and the value of each performance factor was interpolated on the basis of the actual relative returns. All annual average returns or percentages over the three-year performance period were determined on a compounded basis.

Emera Inc. — Management Information Circular 2016          51

The following table shows the performance factor results for the three-year period from January 1, 2013 to December 31, 2015:

	Factor 1:
	Relative Total Shareholder Return (TSR)				Factor 2:
			S&P/TSX Capped		Earnings per		Overall Performance
	Emera TSR		Utilities Index TSR		Share Growth		Factor
Year – 2013		–8.3%		–4.4%		5.9%
Year – 2014		31.9%		16.1%		13.8%
Year – 2015		16.4%		–3.5%		17.5%
Average Annual Compounded Return		12.1%		2.3%		12.3%
Emera’s Relative TSR				9.8%
Resulting Performance Factor				1.5 (Weighted at 50%)		1.5   (Weighted at 50%)		1.5

The overall performance factor applied to the 2013 PSU Grant was 1.5 (the maximum performance factor), based on Emera’s TSR exceeding the TSR of the S&P/TSX Capped Utilities Index by 9.8 per cent and average annual EPS growth being 12.3 per cent.

To ensure that PSU payouts are not excessive, the PSU Plan caps the maximum payout to participants at twice the participant’s grant value. The cap factors in share price appreciation, notional dividend reinvestment, and the performance factor. Based on the average share price (during the last 50 trading days of 2015) of $42.95, the performance factor of 1.50, and the dividend reinvestment over the performance period, the payout for the 2013 PSU grant would have been 212 per cent of the grant value for each participant. Accordingly, the cap was triggered and the payouts were reduced to 200 per cent of the grant value for each participant. The MRCC considers the PSU Plan payout cap to be an important element of the Company’s risk mitigation practices (as noted in Mercer’s compensation risk assessment) and maintains the important balance between linking pay to performance while ensuring incentive plan payouts are reasonable.

The total payout for all PSU Plan participants in respect of the 2013 PSU Grant was approximately $9.3M.

2015 PSU Grant Performance Metrics

The performance period for PSUs granted in 2015 is from January 1, 2015 to December 31, 2017 and the performance metrics are the same as the 2013 grant noted above, with the exception that dividends must be maintained at or higher than the December 31, 2014 and the levels for the EPS metric have been adjusted to the following:

Emera average three-year Earnings Per Share growth	Performance factor
Less than 2%		0
2%		0.5
6%		1.0
10% or more		1.5

The performance targets for the PSU awards are used for compensation purposes only and are not suitable for any other purpose. There is no assurance that any performance level will be met. The targets may also constitute forward-looking information. Forward-looking statements are based upon a number of assumptions and are subject to a number of known and unknown risks and uncertainties, any of which are beyond Emera’s control, which could cause actual results to differ materially from the performance targets. Please see the cautionary statement in Emera’s 2015 Annual Report respecting risks and assumptions relevant to Emera’s determination of performance targets for compensation purposes.

52           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Senior Management Stock Option Plan

The Board of Directors has delegated the administration of the Senior Management Stock Option Plan (the “Stock Option Plan”) to the MRCC. The MRCC is responsible for designating, based on management’s recommendation, which employees of the Company and its affiliates will be eligible to participate in the Stock Option Plan.

Stock options are designed to deliver a percentage of the long-term incentive opportunity for senior management, including the NEOs, and have been retained to recognize their importance as a component of competitive executive compensation in preserving a long-term focus. Grants are calculated each year based on each executive’s long-term incentive target percentage and base salary and, generally, the grant amount increases with the level of responsibility. The Company considers stock options to be in alignment with long-term shareholder interests and the MRCC continues to review the use of options annually. All NEOs participate in the Stock Option Plan and have received stock options in 2015 as a part of their long-term incentive.

Stock options are valued based on the Black-Scholes valuation methodology. The value of the stock options granted to the NEOs in 2015 was determined to be equal to 8.6 per cent of the February 11, 2015 closing share price of $42.71, or $3.67 per option (the value of each stock option is determined by multiplying the share price by the option value ratio). The value ratio of 8.6 per cent was calculated using the three-year average of Emera’s value ratio for the 2012, 2013, and 2014 grants (9.2 per cent, 8.2 per cent and 8.4 per cent, respectively), which were also calculated using the Black-Scholes methodology. The initial valuation of the 2015 stock options resulted in a value ratio of 5.5 per cent. Because the initial Black-Scholes valuation would have led to a significant increase in the number of options granted in 2015 compared to 2014, the MRCC instead opted to use the average of the previous three years’ Black-Scholes value ratios to value the options, which resulted in fewer options being granted (all other factors being equal, the use of a higher value ratio leads to fewer options).

Following the 2015 stock option grant, which occurred in February 2015, and to address the valuation of stock options, the Committee engaged Hugessen to assist in reviewing market practices regarding valuation methodologies. The review concluded that Black-Scholes remained an appropriate valuation methodology and that the adoption of a ‘floor’ value ratio of 10 per cent was appropriate. Accordingly, for the 2016 stock option grant, the Committee adopted the floor and, where the Black-Scholes methodology leads to a value ratio that is less than 10 per cent, the floor of 10 per cent will apply.

The Committee considers both the use of the three-year average to value the options in 2015 and the adoption of a 10 per cent floor going forward to be a prudent step to maintaining stock options as a part of the long-term incentive plan, while reflecting prevailing market conditions.

Unless a stock option has expired, vested options may be exercised within the 24 months following the option holder’s date of retirement or termination for other than just cause, and within six months following the date of termination for just cause, resignation, or death. If stock options are not exercised within such time, they expire. However, certain senior executives (including the NEOs) are entitled to an enhanced retirement vesting provision, which allows unvested stock options to continue to vest and be exercised for two years post-retirement.

The maximum percentage of shares under all security-based compensation arrangements (including the Stock Option Plan) issuable to insiders of the Company at any time is 10 per cent of the issued and outstanding shares of the Company. The maximum number of shares to be optioned to any one person under the Stock Option Plan is five per cent of the issued and outstanding shares of the Company at the date of the grant of the option. The number of shares issued to insiders, within any one-year period, under all security-based compensation arrangements, will not exceed 10 per cent of the issued and outstanding shares of the Company.

Under the Stock Option Plan, options may be granted in respect of authorized and unissued common shares of the Company to a maximum of 11.7 million shares, or approximately 7.89 per cent of the total issued and outstanding common shares of the Company (all figures in this section are as of March 16, 2016, unless otherwise noted).

There have been 4,931,640 common shares issued under the Stock Option Plan since its inception, which represents approximately 3.32 per cent of the total issued and outstanding common shares of the Company. There are 3,198,968 common shares issuable under actual grants of options which represent approximately 2.16 per cent of the total issued and outstanding common shares of the Company and, of that amount, 1,733,881 are vested and 1,465,087 are unvested.

The Board of Directors of the Company may amend or discontinue the Stock Option Plan by resolution at any time; provided, however, that shareholder approval is required for any amendment that:

• increases the number of Common Shares reserved for issuance, except an increase made in proportion to an increase in the number of common shares outstanding due to a stock dividend, stock split, amalgamation, reorganization, merger or similar event;

• extends eligibility to participate to non-employee directors;

• permits rights under the Stock Option Plan to be transferred other than for normal estate settlement purposes;

• permits awards to be granted under the Stock Option Plan in addition to options;

• increases either of the 10 per cent insider participation limits;

• reduces the option price of an option except for the purpose of maintaining option value in connection with a change of control or pursuant to the provisions in the Stock Option Plan, which permit equitable adjustments to be made to the option price in connection with a stock dividend, stock split, share reclassification, amalgamation, reorganization, merger or similar event;

• extends the term of a stock option beyond the original expiry date;

• permits the expiry of a stock option to be beyond ten years from its date of grant; or,

• deletes or reduces the range of amendments, which require shareholder approval under this paragraph.

Emera Inc. — Management Information Circular 2016          53

The table below summarizes certain ratios regarding the Stock Option Plan, namely dilution, burn rate and overhang as defined in the table and measured as a percentage of the total number of shares outstanding as of December 31, 2015, 2014, and 2013.

	December 31, 2015 (%)		December 31, 2014 (%)	December 31, 2013 (%)
Dilution (total number of options outstanding, divided by total number of shares outstanding)		1.99	1.69	1.56
Burn Rate (total number of options granted in a fiscal year, minus expired options, divided by the total number of shares outstanding)		0.40	0.43	0.45
Overhang (total shares available for issuance, plus options outstanding, divided by the total number of shares outstanding)		4.94	5.11	1.96

The stock options issued under the Stock Option Plan are non-assignable, though the Plan permits transfers from the estate of a deceased option holder to the ultimate beneficiaries. The option can then be exercised by such beneficiaries.

In 2015, the Company provided no financial assistance to participants under the Stock Option Plan to facilitate the purchase of shares under the Plan.

Performance Graph

The following performance graph compares Emera’s cumulative total shareholder return or “TSR” (assuming an investment of $100 and reinvestment of dividends) for its common shares with that of the S&P/TSX Capped Utilities Index and the S&P/TSX Composite Index.

Cumulative Total Return on $100 Investment – December 31, 2010 to December 31, 2015

As at December 31	2010 ($)		2011 ($)		2012 ($)		2013 ($)		2014 ($)		2015 ($)
Emera		100.00		109.76		120.07		110.12		145.27		169.02
S&P TSX Utilities		100.00		106.47		110.71		105.79		122.77		118.50
S&P TSX Composite		100.00		91.29		97.85		110.56		122.23		112.06

As indicated in the chart, Emera has created significant value for its shareholders over the last five years. Emera’s cumulative TSR for the five-year period from December 31, 2010 to December 31, 2015, was 69 per cent, which was significantly higher than the 18.5 per cent return of the S&P/TSX Capped Utilities Index and the 12 per cent return of the S&P/TSX Composite Index.

The chart above also shows the significant growth of Emera’s TSR in 2015, during which Emera’s TSR increased 16.4 per cent, compared to the decrease in the return of the S&P/TSX Capped Utilities Index by 3.5 per cent and a decrease in the return of the S&P/TSX Composite Index by 8.3 per cent. In relative terms, Emera’s TSR was 19.8 percentage points higher than the S&P/TSX Capped Utilities Index and 24.7 percentage points higher than the S&P/TSX Composite Index.

54           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Total Shareholder Return vs. Named Executive Officer Compensation

As noted in the Letter from the Management Resources and Compensation Committee to Our Shareholders, a fundamental principle of Emera’s compensation philosophy is to align pay with performance, by linking a significant portion of the compensation the Company pays its executives to the achievement of objectives measuring whether shareholders are experiencing strong value for their investment.

In light of this principle, at the end of 2015, the Company undertook its annual analysis of the alignment between the President and CEO’s compensation and the experience of shareholders. The analysis reviewed the President and CEO’s compensation over a number of timeframes and compared the results to the shareholder experience, as measured by TSR, over the same periods. The review included both realized pay (which consists of amounts actually paid out for a particular performance year) and realizable pay (which consists of changes in the value of any outstanding equity-based awards year-over-year).

The analysis looked at the shareholders’ experience using 11 different measurement periods, recognizing that shareholders have acquired their shares at different times. Each period had the same end point (December 31, 2015) but started at a different beginning period, going from January 1, 2005 to January 1, 2015. The analysis measured the dollar return per $100 of investment over each period as compared to the President and CEO’s economic experience, measured by the dollar realized and realizable per $100 of target compensation awarded over the same periods. The average return for shareholders over the 11 periods was $223, while the average realized/realizable compensation relative to target for the President and CEO was $212, indicating a close alignment between President and CEO’s compensation and the shareholders’ experience. Accordingly, the analysis concluded that Emera’s compensation framework provided a very close alignment between the President and CEO’s compensation and the shareholder experience over the long-term.

In keeping with Emera’s compensation philosophy, a significant component of NEO compensation consists of long-term incentives (PSUs and stock options), which are designed to focus executives on the long-term success of the Company. These long-term incentives are directly affected by changes in Emera’s common share price and Emera’s TSR relative to the S&P/TSX Capped Utilities Index. This helps create a direct correlation between the shareholder experience and the compensation the Company pays its senior executives.

As described in Performance Share Unit Plan, each PSU grant is subject to the achievement of financial objectives and, at the end of the performance period, a performance factor is applied, which is determined based on the extent to which the Company has met those objectives. The performance factors for the PSU Plan, expressed in terms of a percentage, for the past five years were 149 per cent (the performance year ended in 2011), 126 per cent (2012), 57 per cent (2013), 150 per cent (2014), and 150 per cent (2015). The general trend shows performance factors at or above 100 per cent in years where Emera outperforms the S&P/TSX Capped Utilities Index, and below 100 per cent when the Company underperforms the Index, indicating an alignment between executive and shareholder interests.

The total annual salary, short-term incentive and long-term PSU payouts earned in 2015 for the NEOs totalled $9.0 million, which represents 2.3 per cent of the Company’s net earnings applicable to common shares of $397.2 million for the period ended December 31, 2015.

NSPI Ratepayers

No portion of the compensation paid to Emera’s President and CEO, the CFO, the Chief Corporate Development Officer, or the President or the Chief Executive Officer, Emera U.S. Inc. in 2015 was paid by NSPI or NSPI ratepayers.

Emera Inc. — Management Information Circular 2016          55

NEO Summary Compensation Table

								Non-equity
								incentive plan
								compensation
Name and principal position	Year	Salary ($)	(1)	Share-based awards ($)	(2)(3)	Option-based awards ($)	(4)		Annual incentive plans ($)	(5)	Pension value ($)	(6)	All other compensation ($)	(7)	Total compensation ($)
Christopher Huskilson
President and	2015	875,000		1,050,018		1,049,987			1,135,418		179,000		25,472		4,314,895
Chief Executive	2014	875,000		962,380		962,608			1,237,399		550,000		31,817		4,619,204
Officer	2013	871,635		962,542		962,445			1,358,438		579,000		32,120		4,766,180
Scott Balfour
Chief Financial Officer and Chief Operating Officer,	2015 2014 2013	474,958 473,376 460,000		445,498 284,376 241,624		148,268 94,656 80,370			479,399 926,308 601,100		128,000 90,000 122,000		23,864 25,940 29,216		1,699,987 1,894,656 1,534,310
Northeast and Caribbean
Nancy Tower
Chief Corporate	2015	474,481		356,086		118,908			410,913		214,000		26,226		1,600,614
Development Officer	2014 2013	460,000 458,385		241,482 241,624		80,512 80,370			433,679 601,100		194,000 388,000		26,724 24,106		1,436,397 1,793,585
Robert Bennett
President and	2015	474,481		356,086		118,908			410,913		239,000		23,664		1,623,052
Chief Executive Officer, Emera US Inc.	2014 2013	460,000 458,923		241,482 241,624		80,512 80,370			433,679 476,100		342,000 499,000		26,190 18,845		1,583,863 1,774,862
Robert Hanf (8)
President and	2015	398,615		380,194		59,821			230,800		275,000		22,686		1,367,116
Chief Executive Officer, Nova Scotia Power Inc.	2014 2013	360,000 364,483		161,860 134,981		54,128 45,030			185,310 252,000		128,000 361,000		25,195 73,736		914,493 1,231,230

(1) The figure shown represents actual base earnings paid in 2015.

(2) Includes PSU grants and special DSU grants, but does not reflect DSUs received in lieu of cash bonuses, as their value is already reflected in the ‘Annual incentive plans’ column—see Deferred Share Unit Plan for further details. The grant value of PSUs granted in 2015 was based on the average 50 trading-day closing share price up to December 31, 2014 ($38.08). The 50-day share price average is used for PSU and DSU grants to smooth out any short-term fluctuations in share price immediately preceding the grant date. The value of PSUs on payout is subject to the achievement of specific performance objectives over the three-year performance period from January 1, 2015, to December 31, 2017. If those objectives are not met, payouts may be less than the initial value of the grant noted above and if performance objectives are exceeded, the payout may be higher than the amount noted above.

(3) The value shown for Mr. Hanf includes a special grant of 5,010 DSUs, valued at $200,000, which occurred on February 16, 2015 based on the average 50 trading-day closing share price immediately preceding the grant ($39.92). The special grant was to acknowledge Mr. Hanf’s leadership in transforming the cost structure of Nova Scotia Power Inc. to provide rate stabilization and avoid a general rate application in 2016. No portion of the cost of the special DSU grant will be borne by ratepayers.

(4) Stock options are valued based on the Black-Scholes valuation methodology. The value of the stock options granted to the NEOs in 2015 was determined to be equal to 8.6 per cent of the February 11, 2015 closing share price of $42.71 or $3.67 per option. The valuation ratio of 8.6 per cent was calculated using the three-year average of Emera’s value ratio (for the 2012, 2013 and 2014 grants, which were also calculated using the Black-Scholes methodology). The initial valuation of the 2015 stock options was based on a value ratio of 5.5 per cent, which was determined using the following assumptions: an estimated volatility of 13.6 per cent (based on daily historical share price for the four-year period ending on December 31, 2014), estimated dividend yield of 4.3 per cent, and a risk-free interest rate of 1.79 per cent. Because the initial Black-Scholes valuation of 5.5 per cent would have led to a significant increase in the number of options granted in 2015 compared to 2014, the MRCC instead opted to use the average of the previous three years’ Black-Scholes valuations to value the options (the use of a higher value ratio leads to fewer options being granted).

(5) In 2015, Mr. Huskilson, Mr. Balfour, Ms. Tower, and Mr. Bennett participated in the Emera Corporate Scorecard and Mr. Hanf participated in the NSPI Corporate Scorecard. The payouts to the NEOs participating in the Emera Corporate Scorecard were based on a scorecard result of 144.18 per cent and the payout to Mr. Hanf was based on the NSPI Scorecard result of 115.36 per cent. The Short-Term Incentive Plan and the 2015 results are described in greater detail in Short-Term Incentive Plan. The figures shown reflect amounts earned in the 2015 performance year and paid in 2016. Mr. Balfour elected to receive 50 per cent of his short-term incentive in the form of DSUs and Mr. Hanf elected to receive 25 per cent of his short-term incentive in the form of DSUs.

(6) Further information concerning pension values can be found in Pension Plan Benefits.

(7) All other compensation in 2015 includes: (a) a car allowance for each NEO in the following amounts: $18,000 for Mr. Huskilson; $13,200 for Mr. Balfour; $12,000 for Ms. Tower; $13,200 for Mr. Bennett; and $14,400 for Mr. Hanf; and (b) other taxable benefits.

(8) All compensation paid to Mr. Hanf was paid by NSPI, though only a portion his salary ($205,792) and $26,753 of his other compensation and benefits was included in NSPI rates, in accordance with the Public Utilities Act and Nova Scotia Power Incorporated Regulations. None of the compensation paid to Mr. Huskilson, Mr. Balfour, Ms. Tower or Mr. Bennett was included in NSPI rates.

56           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Outstanding Share-based Awards and Option-based Awards

The following table describes all option-based and share-based awards outstanding as of December 31, 2015 for each NEO:

Option-based awards (1) (stock options)						Share-based awards (performance share units (PSUs) and deferred share units (DSUs))
Name	Number of securities underlying unexercised option (#)	Option exercise price ($)	Option expiration date	Value of unexercised in-the-money options ($)	(2)		Number of shares or unit of shares that have not vested (#)	(3)	Market or payout value of share-based awards that have not vested ($)	(4)	Market or payout value of vested share-based awards that have not been paid out ($)	(5)
Christopher	168,100	21.99	12-Feb-2019	3,570,444			63,372		2,721,808		9,019,424
Huskilson	147,000	23.94	16-Feb-2020	2,835,630
	26,400	24.63	5-Jun-2020	491,040
	72,500	32.06	15-Feb-2021	809,825
	97,700	33.35	14-Feb-2022	965,276
	337,700	34.80	12-Feb-2023	2,846,811
	353,900	32.35	11-Feb-2024	3,850,432
	286,100	42.71	11-Feb-2025	148,772
Scott Balfour	100,000	33.73	15-Apr-2022	950,000			22,417		962,822		1,261,189
	28,200	34.80	12-Feb-2023	237,726
	34,800	32.35	11-Feb-2024	378,624
	40,400	42.71	11-Feb-2025	21,008
Nancy Tower	16,900	21.58	14-Feb-2018	365,885			18,430		791,548		2,544,819
	21,600	21.99	12-Feb-2019	458,784
	21,300	23.94	16-Feb-2020	410,877
	16,900	32.06	15-Feb-2021	188,773
	22,800	33.35	14-Feb-2022	225,264
	28,200	34.80	12-Feb-2023	237,726
	29,600	32.35	11-Feb-2024	322,048
	32,400	42.71	11-Feb-2025	16,848
Robert Bennett	2,500	21.58	14-Feb-2018	54,125			18,430		791,548		1,885,545
	9,700	21.99	12-Feb-2019	206,028
	13,725	23.94	16-Feb-2020	264,755
	14,500	32.06	15-Feb-2021	161,965
	28,943	33.35	14-Feb-2022	285,957
	28,200	34.80	12-Feb-2023	237,726
	29,600	32.35	11-Feb-2024	322,048
	32,400	42.71	11-Feb-2025	16,848
Robert Hanf	5,025	32.06	15-Feb-2021	56,129			10,756		461,989		1,087,679
	12,200	33.35	14-Feb-2022	120,536
	15,800	34.80	12-Feb-2023	133,194
	19,900	32.35	11-Feb-2024	216,512
	16,300	42.71	11-Feb-2025	8,476

(1) Option-based awards include both vested and unvested options.

(2) The value of all unexercised option-based awards was calculated using a December 31, 2015 closing share price of $43.23.

(3) Unvested share-based awards include PSU and unvested special DSU grants, and any additional PSUs and DSUs from dividend reinvestment relating to such grants as of December 31, 2015.

(4) The market or payout value of share-based awards was calculated based on an assumed performance factor of 1.0 and the average closing share price for the last 50 trading days of 2015 ($42.95).

(5) These figures represent only vested DSUs, as PSUs are paid out upon vesting, and are based on the average closing share price for the last 50 trading days of 2015 ($42.95).

Emera Inc. — Management Information Circular 2016          57

Incentive Plan Awards – Value Vested or Earned During the Year

The following table describes all option-based awards, share-based awards and non-equity incentives that vested, or were earned, during 2015 for each NEO:

Name	Option-based awards value vested during 2014 ($)	(1)	Share-based awards (Performance Share Units (PSUs) and Deferred Share Units (DSUs)) value vested during 2015 ($)	(2) (3)	Non-equity incentive plan compensation - value earned during the 2015 ($)	(4)
Christopher Huskilson	1,912,057		2,223,643		1,135,418
Scott Balfour	331,808		483,248		479,399
Nancy Tower	219,230		515,070		410,913
Robert Bennett	226,666		517,877		410,913
Robert Hanf	127,025		491,617		230,800

(1) Represents the aggregate dollar value that would have been realized if stock options had been exercised on the applicable vesting (eligibility) date in 2015.

(2) The value of PSUs vested in 2015 is based on the 2013 PSU grant, which had a three-year performance period from January 1, 2013 to December 31, 2015. The payout is calculated based on the original grant with accumulated dividends, multiplied by the performance factor, multiplied by the average closing share price for the last 50 trading days of 2015 ($42.95). The performance factor for the 2013 PSU grant was based on Emera’s total shareholder return relative to the S&P/TSX Capped Utilities Index and Emera’s average annual growth in EPS – the overall performance factor result was 1.5 and the payout was capped at two-times the grant date value, as per the terms of the PSU Plan. More details on the PSU Plan and results can be found in Performance Share Unit Plan.

(3) This dollar amount includes the value of DSUs from special grants that vested in 2015, including additional DSUs from dividend equivalents on such grants, and calculated using a closing share price for the last 50 trading days of 2015 ($42.95). This amount equalled $298,560 for Mr. Huskilson, $31,822 for Ms. Tower, $34,629 for Mr. Bennett, and $221,655 for Mr. Hanf.

(4) This amount represents the 2015 incentive payouts as disclosed in the NEO Summary Compensation Table.

Aggregate Option Exercise during 2015 and 2015 Option Values

The following table summarizes the number of common shares, if any, each NEO acquired pursuant to the exercise of stock options in 2015, the aggregate value realized upon exercise, and the number of common shares covered by unexercised options under the Stock Option Plan as at December 31, 2015. The aggregate value realized upon exercise is the difference between the fair market value of the common shares on the exercise date and the exercise price of the option. The value of unexercised in-the-money options at year-end is the difference between the exercise price of the options and the fair market value of the common shares on December 31, 2015, which was $43.23.

							Unexercised options at December 31, 2015		Value of unexercised in-the-money options at December 31, 2015
Name	Securities acquired on exercise (#)		Aggregate value realized ($)		Exercisable (#)		Unexercisable (#)		Exercisable ($)		Unexercisable ($)
Christopher Huskilson		0		0		744,600		744,800		10,816,910		4,701,321
Scott Balfour		0		0		97,800		105,600		926,019		661,339
Nancy Tower		4,600		99,130		115,300		74,400		1,792,642		433,563
Robert Bennett		0		0		83,632		75,936		1,100,713		448,739
Robert Hanf		6,100		76,070		27,050		42,175		267,256		267,591

Pension Plan Benefits

The NEOs are members of the corporate pension plan (Pension Plan) and participate on either a defined benefit basis or a defined contribution basis. For 2015, all NEOs participated in the defined benefit component of the Pension Plan.

58           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Defined Benefit

The following table shows years of credited service, estimated pension amounts, and changes to accrued obligations from January 1, 2015 to December 31, 2015 for the NEOs who participated in the Pension Plan on a defined benefit basis.

		Annual benefits payable
Name	Number of years credited service (#)		At year-end    ($) (1)	At age 65 ($)	Accrued obligation at start of year ($)	Compensatory    change ($) (2)	Non-    compensatory    change ($) (2)	Accrued obligation at year-end ($)
Christopher Huskilson (3)	35.0		650,000	650,000	15,377,000	179,000	235,000	15,791,000
Scott Balfour	3.7		42,000	197,000	362,000	128,000	37,000	527,000
Nancy Tower	18.3		200,000	290,000	3,934,000	214,000	182,000	4,330,000
Robert Bennett	27.7		295,000	373,000	6,440,000	239,000	231,000	6,910,000
Robert Hanf	13.5		105,000	198,000	1,953,000	275,000	52,000	2,280,000

(1) With the exception of Mr. Huskilson and Ms. Tower, the NEOs are not eligible for an immediate pension at year-end. The amount shown is the accrued pension starting at the NEO’s unreduced retirement date if the NEO terminated employment at December 31, 2015.

(2) The compensatory and non-compensatory changes are described in more detail below.

(3) Mr. Huskilson’s pension is capped, which is described in further detail below.

The accrued obligation of a pension entitlement is the present value of the expected future annual benefits payable taking into account service accrued to date and the expected salaries used to determine the annual benefit payable at retirement. Each year the value of the accrued obligation changes as a result of compensatory changes and non-compensatory changes, which are shown in the table above.

Compensatory changes are caused by changes in the annual benefit payable and result primarily from three factors: (i) new accrued service (the employer current service cost); (ii) the impact of salary increases greater than expected on past benefits (estimated increases are already built into the accrued benefit obligation), and; (iii) plan changes impacting, for example, accrued service or when benefits are payable. There were no Pension Plan changes that materially affected the above figures in 2015.

Non-compensatory changes are caused by interest on the accrued obligation and current service cost, employee required contributions and changes in the assumptions used to calculate the present value of the future annual benefit payment stream. These assumptions include the mortality table, salary scale, retirement assumption and the inflation assumption used for calculating indexing and the discount rate. The non-compensatory changes in 2015 were driven largely by interest on the accrued obligation and current service cost as there were no material changes in assumptions.

The defined benefit component of the Pension Plan entitles members to pension benefits based on two per cent of the average of the member’s five highest years of pensionable earnings, multiplied by each year of credited service to a maximum of 35 years credited service. For the NEOs, pensionable earnings include base salary plus up to 50 per cent of their target short-term incentive. Upon reaching age 65, pension benefits under the Pension Plan are reduced by an amount approximately equal to the amount payable under the Canada Pension Plan. For members who retire from active service, the pension is payable on an unreduced basis upon the earlier of age 60 or age 55, provided that age and years of service add to at least 85. For members who joined the Pension Plan on or after July 1, 2004, the age 60 unreduced retirement age condition is replaced by age 62 with 15 years of service. A member may also retire on a reduced formula if the member has attained age 55, but does not qualify for the rule of 85. Spousal benefits are paid on the death of a member at the rate of 60 per cent of regular pension benefits. Pensions are indexed to the consumer price index to a maximum of six per cent per annum.

For 2015, members of the defined benefit component of the plan contributed 7.4 per cent of eligible earnings up to the year’s maximum pensionable earnings (“YMPE”) under the Canada Pension Plan, and 9.5 per cent of earnings between the YMPE and the amount on which pension benefits may be earned under a registered pension plan as permitted by the Income Tax Act (Canada).

Due to Canada Revenue Agency’s limitations on the maximum pension benefit that may be paid under the Pension Plan, a portion of the pension the NEOs earned after January 1, 1992 is provided under the terms of a Supplementary Retirement Plan, which is unfunded but secured by a letter of credit deposited in a retirement compensation trust. The Supplementary Retirement Plan is non-contributory.

In 2011, Mr. Huskilson’s pension amount payable under the Pension Plan and Supplementary Retirement Plan was capped. The limit at future potential retirement dates was determined based on the pension formula and an assumed increase in pensionable earnings of approximately four per cent per year from the 2010 pensionable earnings levels. This limit is expected to reduce the amount that would otherwise be payable under the normal Pension Plan terms. As a result, year-over-year changes of more than four per cent to Mr. Huskilson’s earnings have no impact on his compensatory change component.

The accrued pension obligation is calculated following the method prescribed under US GAAP (section 715 of FASB) and by the Canadian Institute of Chartered Accountants and is based on management’s best estimate of future events that affect the cost of pensions, including assumptions about future salary adjustments and short-term incentive awards.

The defined benefit component of the Pension Plan was closed to new non-union employees hired after January 8, 2013 and to new union employees hired after October 31, 2014.

Emera Inc. — Management Information Circular 2016          59

Defined Contribution

Under the defined contribution component of the plan, the Company contributes a base amount to the participant’s account each pay period. The amount is expressed as a percentage of eligible earnings. Plan participants can also make contributions to the defined contribution component, with the Company matching a portion of these contributions. Canada Revenue Agency limits apply.

Upon ending active employment with the Company at any age between 55 and 65, plan participants may start receiving retirement income through the purchase of a life annuity or by converting their account to a Life Income Fund.

The defined contribution component of the plan is administered on behalf of the Company by a major Canadian insurance company, which acts in accordance with the provisions of the defined contribution component of the plan, the Income Tax Act, and the Nova Scotia Pension Benefits Act.

Since all the NEOs participate in the pension plan on a defined benefit basis, they have not accrued any amounts under the defined contribution component of the plan.

Deferred Share Unit Plan (“DSU Plan”)

The Deferred Share Unit (DSU) Plan is another component of Emera’s long-term incentive program for senior leaders. A DSU is a notional share unit that is based on the value of an Emera common share – the value of a DSU changes directly in correlation to an Emera share and earns dividend equivalents in the form of additional DSUs. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs based on the dividend paid on an equivalent number of Emera common shares. DSUs are not paid out until such time as the participant is no longer employed by the Company or any of its affiliates. When redeemed, the value of a participant’s DSUs is equivalent to the fair market value of an equal number of common shares of the Company.

The DSU Plan is intended to facilitate achievement of share ownership guidelines (discussed in Executive Share Ownership Requirements) without diluting the shareholder base. Prior to the start of each performance year, each plan participant may elect to defer some or all of the short-term incentive payout associated with that performance year in the form of DSUs. When the short-term incentive is paid to the NEOs, the portion elected is allocated to DSUs rather than paid in cash. Since DSUs are principally an income deferral mechanism, there are no performance metrics attributable to DSUs.

Following a participant’s departure from the Company and on a date selected by the participant not later than December 15 of the next calendar year after departure, the value of the participant’s DSUs is calculated by multiplying the number of DSUs in the participant’s account by the average closing Emera common share price for the 50 trading days preceding the payout date (the 50-day average is used to smooth out any short-term price fluctuations). The after-tax amount is paid to the participant. If a participant is a U.S. taxpayer, payment is made six months following the termination date.

In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to recognize singular achievements or the achievement of certain corporate objectives. In 2015, Mr. Hanf was awarded a special grant of 5,010 DSUs, valued at $200,000 based on the average 50 trading-day closing share price immediately preceding the grant ($39.92). The special grant was to recognize Mr. Hanf’s leadership in transforming the cost structure of Nova Scotia Power Inc. to provide rate stabilization and avoid a general rate application in 2016.

2015 DSU Plan Allocations

The table below identifies how much of the short-term incentive for 2015 that each NEO elected to allocate to DSUs:

Name	Percentage of 2015 annual incentive elected to deferred share units (%)		Dollar amount of 2015 annual incentive elected to deferred share units ($)
Christopher Huskilson		0		0
Scott Balfour		50		239,700
Nancy Tower		0		0
Robert Bennett		0		0
Robert Hanf		25		57,700

60           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

Executive Share Ownership Requirements

To align the interests of senior management with the interests of shareholders, share ownership guidelines were introduced for designated executive officers in 2003. The MRCC amended the guidelines in 2015 to apply to the top three levels of executives across all affiliates (regardless of whether they are officers of Emera Inc. or an affiliate). Mr. Huskilson is required to hold shares equal to at least four-times his base salary and all other executives subject to the guidelines (including Mr. Balfour, Ms. Tower, Mr. Bennett and Mr. Hanf) are required to hold shares equal to at least hold two-times their respective base salaries.

Share ownership is calculated based on: (1) the number of Emera shares an executive owns; and (2) DSUs acquired pursuant to the DSU Plan, which are considered share equivalents. PSUs do not count for purposes of the share ownership guidelines. Executives have five years to reach the required ownership level and are required to allocate a portion of their short-term incentive into DSUs until their target share ownership is met.

All executives are subject to an anti-hedging policy prohibiting them from hedging, pledging, monetizing, or otherwise reducing or limiting their economic risk with respect to any Emera securities they hold (including DSUs, PSUs and stock options). Mr. Huskilson is required to maintain his share ownership target for at least one year post-retirement.

The share ownership levels for the NEOs are set out below. The value shown is based on the closing price of Emera’s common shares on December 31, 2015 of $43.23.

Name	Required ownership level as a multiple of base salary		Shares/share equivalents (#)		Estimated value ($)		Multiple of base salary		Target achieved
Christopher Huskilson		4.0		235,535		10,182,179		11.6		Yes
Scott Balfour		2.0		50,942		2,202,212		4.6		Yes
Nancy Tower		2.0		65,996		2,853,005		6.0		Yes
Robert Bennett		2.0		45,435		1,964,166		4.1		Yes
Robert Hanf		2.0		29,556		1,277,707		3.2		Yes

The above table does not include instalment receipts representing convertible unsecured subordinated debentures of Emera Inc., which were sold in relation to the pending acquisition of TECO Energy, Inc. Mr. Huskilson purchased 750 instalment receipts (valued at $750,000), Mr. Balfour purchased 250 (valued at $250,000), Ms. Tower purchased 450 (valued at $450,000), Mr. Bennett purchased 100 (valued at $100,000) and Mr. Hanf purchased 100 (valued at $100,000). The instalment receipts are convertible to Emera common shares following the closing of the TECO Energy, Inc. acquisition.

The total share and share equivalent ownership for Mr. Huskilson, when factoring in PSUs and the above-noted installment receipts as of December 31, 2015, is illustrated below:

Shares ($)	DSUs ($)		PSUs ($)		Instalment receipts for convertible unsecured subordinated debentures ($) (1)		Total share and share equivalent ownership ($)		Total shares and share equivalents as a multiple of base salary
1,103,965		9,078,214		2,739,552		750,000		13,671,731		15.6

(1) All debentures sold through Emera’s Bought Deal Offering were purchased on an instalment basis at a price of $1,000 per Debenture, of which $333 is payable on the closing of the Offering and the remaining $667 is payable on a date to be fixed by the Company following satisfaction of all conditions precedent to the closing of Emera’s acquisition of TECO Energy, Inc.

Emera Inc. — Management Information Circular 2016          61

Other Executive Benefits

The Company provides executives with additional benefits in accordance with the compensation program objectives. As part of their compensation and consistent with market practice, executives, including the NEOs, are eligible to receive:

• annual income tax return preparation;

• monthly parking;

• monthly car allowance plus mileage, as applicable; and

• annual wellness/fitness allowance.

Executives are also eligible to participate in the Employee Common Share Purchase Plan, which allows employees of Emera and its affiliates to purchase Emera common shares through regular payroll deductions or lump-sum payments. Participants can contribute up to $8,000 per year and the Company will match 20 per cent of the first $3,000 in contributions, and 10 per cent of any contributions between $3,000 and $8,000.

These benefits are considered taxable benefits and are reported in the Summary Compensation Table for the NEOs.

Termination and Change of Control Benefits

The following table provides the estimated amounts of incremental payments, payables and benefits to which each NEO would be entitled based on differing departure scenarios – resignation, termination for cause, termination without cause, separation from the Company in circumstances of a change of control, and retirement, assuming the triggering event took place on December 31, 2015.

Name	Departure scenario (1)	Cash severance ($)	Short-term incentive ($)	PSUs ($)	(2)	Stock options ($)	(3)	Continuation of benefits (present value) ($)	(4)	Total ($)
Christopher Huskilson	Resignation	—	—	—		—		—		—
	Termination for Cause	—	—	—		—		—		—
	Termination without Cause	1,750,000	1,575,000	—		—		45,413		3,370,413
	Control Change	1,750,000	1,575,000	—		—		45,413		3,370,413
	Retirement	—	—	2,721,808		3,664,327				6,386,135
Scott Balfour	Resignation	—	—	—		—		—		—
	Termination for Cause	—	—	—		—		—		—
	Termination without Cause	475,000	332,500	962,822		—		5,519		1,775,841
	Control Change	475,000	332,500	962,822		—		5,519		1,775,841
	Retirement	—	—	467,770		—				467,770
Nancy Tower	Resignation	—	—	—		—		—		—
	Termination for Cause	—	—	—		—		—		—
	Termination without Cause	475,000	285,000	388,532		—		18,718		1,167,250
	Control Change	475,000	285,000	791,548		—				1,551,548
	Retirement	—	—	791,548		344,627				1,136,175
Robert Bennett	Resignation	—	—	—		—		—		—
	Termination for Cause	—	—	—		—		—		—
	Termination without Cause	475,000	285,000	388,532		—		5,519		1,154,051
	Control Change	475,000	285,000	791,548		—				1,551,548
	Retirement			791,548		359,800				1,151,348
Robert Hanf	Resignation	—	—	—		—		—		—
	Termination for Cause	—	—	—		—		—		—
	Termination without Cause	400,000	200,000	237,568		—		18,141		855,709
	Control Change	400,000	200,000	237,568		—		18,141		855,709
	Retirement	—	—	461,989		209,225				671,214

(1) Please see the tables following for a description of the entitlements of each NEO under the various departure scenarios.

(2) Payouts for PSUs assume a performance factor of 1.0 and are valued using the average closing share price for the last 50 trading days of 2015 ($42.95).

(3) Payouts for stock options on retirement represent the value of stock options that are unvested as of December 31, 2015 (the assumed retirement date) that would vest within 24 months from the assumed retirement date, using the closing share price as of December 31, 2015 ($43.23).

(4) Continuation of benefits may reflect amounts for car allowance, health and dental benefits and insurance benefits, pursuant to the terms of the NEOs’ employment contracts, as applicable.

62           Emera Inc. — Management Information Circular 2016

MANAGEMENT INFORMATION CIRCULAR

The following is a summary of the entitlements on departure afforded to each NEO under his or her employment contract or the applicable plans as of December 31, 2015.

Christopher Huskilson
Resignation	All unvested PSUs and stock options are forfeited.
Terminated for cause	All unvested PSUs and stock options are forfeited.
Terminated without cause	Entitled to 24 months’ compensation based upon annual salary, short-term incentive at target and car allowance. Health, dental and other such benefits will be continued for up to 12 months. Unvested PSUs and stock options are forfeited.
Change in control	If there is a change of control of the ownership of the Company, such that any one party acquires 50 per cent or more of voting securities and there is a substantial reduction in responsibilities or scope of authority, Mr. Huskilson may elect within three months following such substantial reduction in responsibilities or scope of authority, to terminate employment and receive 24 months’ compensation based upon annual salary, short-term incentive at target, and car allowance. Health, dental and other such benefits will be continued for up to 12 months. Unvested PSUs and stock options are forfeited.
Retirement	Mr. Huskilson was eligible to retire with an unreduced pension as of June 30, 2012. He has agreed to advise the Company at least 12 months in advance of any proposed retirement. Information regarding pension entitlement is contained in Pension Plan Benefits. PSUs continue to be eligible to vest in accordance with the applicable performance criteria and will be paid out upon vesting. Unvested stock options continue to be eligible to vest for two years past retirement. Any stock options that have not vested within two years of retirement are forfeited. All vested stock options must be exercised by the earlier of (a) two years from the date of retirement, and (b) 10 years from the original grant date.

Scott Balfour
Resignation	All unvested PSUs and stock options are forfeited.
Terminated for cause	All unvested PSUs and stock options are forfeited.
Terminated without cause	Entitled to a lump sum equal to 12 months’ compensation based upon annual salary and short-term incentive at target. Health, dental and other such benefits will be continued for up to 12 months. Unvested PSUs are deemed to vest on the termination date. Unvested stock options are forfeited.
Change in control	If there is a change of control of the ownership of the Company, such that any one party acquires 50 per cent or more of voting securities and there is a substantial reduction in responsibilities or scope of authority, Mr. Balfour may elect, within three months following such substantial reduction in responsibilities or scope of authority, to terminate employment and receive 12 months’ compensation based upon annual salary and short-term incentive at target. Health, dental and other such benefits will be continued for up to 12 months. Unvested PSUs are deemed to vest on the termination date. Unvested stock options are forfeited.
Retirement	Mr. Balfour becomes eligible to retire with an unreduced pension as of April 30, 2027. Information regarding pension entitlement is contained in Pension Plan Benefits. PSUs continue to be eligible to vest in accordance with the applicable performance criteria and will be paid out on a prorated basis upon vesting. Unvested stock options are forfeited.
Other	If Mr. Balfour’s employment is terminated without cause, he is entitled to a relocation program for reimbursement of reasonable relocation costs back to Ontario to a maximum of $200,000, which is payable up to 12 months after the termination date.

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Nancy Tower
Resignation	All unvested PSUs and stock options are forfeited.
Terminated for cause	All unvested PSUs and stock options are forfeited.
Terminated without cause	Entitled to a lump sum equal to 12 months’ compensation based upon annual salary, short-term incentive at target and car allowance. Health, dental and other such benefits will be continued for up to 12 months. Unvested PSUs are prorated to the date of termination and paid out based on an estimated future value. Unvested stock options are forfeited.
Change in control	If there is a change of control of the ownership of the Company, such that any one party acquires 50 per cent or more of voting securities and there is a substantial reduction in responsibilities or scope of authority, Ms. Tower may elect, within three months following such substantial reduction in responsibilities or scope of authority, to terminate employment and receive 12 months’ compensation calculated on the basis of her annual salary and short-term incentive at target. Unvested PSUs are deemed to vest on the termination date. Unvested stock options are forfeited.
Retirement	Ms. Tower becomes eligible to retire with an unreduced pension as of March 31, 2019. Information regarding pension entitlement is contained in Pension Plan Benefits. PSUs continue to be eligible to vest for two years following retirement in accordance with the applicable performance criteria. Unvested stock options continue to be eligible to vest for two years past retirement. Any stock options that have not vested within two years of retirement are forfeited. All vested stock options must be exercised by the earlier of (a) two years from the date of retirement; and (b) 10 years from the original grant date.

Robert Bennett
Resignation	All unvested PSUs and stock options are forfeited.
Terminated for cause	All unvested PSUs and stock options are forfeited.
Terminated without cause	Entitled to a lump sum equal to 12 months’ compensation based upon annual salary and short-term incentive at target. Health, dental and other such benefits will be continued for up to 12 months. Unvested PSUs are prorated to the date of termination and paid out based on an estimated future value. Unvested stock options are forfeited.
Change in control	If there is a change of control of the ownership of the Company, such that any one party acquires 50 per cent or more of voting securities and there is a substantial reduction in responsibilities or scope of authority, Mr. Bennett may elect, within three months following such substantial reduction in responsibilities or scope or authority, to terminate employment and receive 12 months’ compensation calculated on the basis of his annual salary and short-term incentive at target. Unvested PSUs are deemed to vest on the termination date. Unvested stock options are forfeited.
Retirement	Mr. Bennett becomes eligible to retire with an unreduced pension as of October 31, 2017. Information regarding pension entitlement is contained in Pension Plan Benefits. PSUs continue to be eligible to vest for two years following retirement in accordance with the applicable performance criteria. Unvested stock options continue to be eligible to vest for two years past retirement. Any stock options that have not vested within two years of retirement are forfeited. All vested stock options must be exercised by the earlier of (a) two years from the date of retirement; and (b) 10 years from the original grant date.
Other	In a termination without cause scenario, Mr. Bennett is entitled to receive his pension on his earliest retirement eligibility date, to be calculated based on his earliest retirement eligibility date in 2017 and, in accordance with his supplemental pension agreement, the pension would be calculated using his salary and annual target bonus in effect at the time of termination.

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Robert Hanf
Resignation	All unvested PSUs and stock options are forfeited.
Terminated for cause	All unvested PSUs and stock options are forfeited.
Terminated without cause	Entitled to a lump sum equal to 12 months’ compensation based upon annual salary, short-term incentive at target and car allowance. Health, dental and other such benefits will be continued for up to 12 months. Unvested PSUs are prorated to the date of termination and paid out based on an estimated future value. Unvested stock options are forfeited.
Change in control	If there is a change of control of the ownership of the Company, such that any one party acquires 50 per cent or more of voting securities and there is a substantial reduction in responsibilities or scope of authority, Mr. Hanf may elect, within three months following such substantial reduction in responsibilities or scope or authority, to terminate employment and receive 12 months’ compensation calculated on the basis of his annual salary, short-term incentive at target and car allowance. Health, dental and other such benefits will be continued for up to 12 months. Unvested PSUs are prorated to the date of termination and paid out based on an estimated future value. Unvested stock options are forfeited.
Retirement	Mr. Hanf becomes eligible to retire with an unreduced pension as of November 30, 2022. Information regarding pension entitlement is contained in Pension Plan Benefits. PSUs continue to be eligible to vest for two years following retirement in accordance with the applicable performance criteria. Unvested stock options continue to be eligible to vest for two years past retirement. Any stock options that have not vested within two years of retirement are forfeited. All vested stock options must be exercised by the earlier of (a) two years from the date of retirement; and (b) 10 years from the original grant date.

Shares Authorized for Issuance under Equity-based Compensation Plans

The following table shows shares authorized for issuance under the Stock Option Plan and the Employee Common Share Purchase Plan as of December 31, 2015. There are no equity-based compensation plans that were not approved by Shareholders.

	(A)		(B)		(C)
Plan Category	Number of shares to be issued upon exercise of outstanding options		Weighted-average exercise price of outstanding options ($)		Number of shares available for future issuance under equity compensation plans (excluding column (A))
Equity-based compensation plans approved by Shareholders
•  Senior Management Stock Option Plan		2,927,068		33.07		4,339,210
•  Employee Common Share Purchase Plan		N/A		N/A		1,620,410
Total		2,927,068		33.07		5,959,620

Loans to Directors and Officers

No current or former directors, officers, or employees of Emera, or any of its subsidiaries, had any loans with Emera or any of its subsidiaries at any time in 2015, other than routine indebtedness previously outstanding as defined under Canadian securities laws.

Material Transactions

During the most recently completed financial year, insiders of the Company and its affiliates, including Directors, executive officers, proposed nominee Directors or their associates or corporations they controlled, did not have any material interest, direct or indirect, in any transaction or in any proposed transaction that has materially affected or will materially affect the Company.

Management Contracts

There are no functions of management that are performed by a person or company other than the Directors, executive officers or other employees of the Company.

Audit Committee Information

For information regarding Emera’s Audit Committee, including its Charter, composition, relevant education and experience of its members, Audit Committee oversight, policies and procedures for the approval of non-audit services and Auditors’ service fees, please refer to Emera’s Annual Information Form, available on SEDAR at www.sedar.com, or by contacting the Corporate Secretary of the Company.

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Appendix A

Emera Incorporated Board of Directors Charter

The fundamental responsibility of the Board of Directors (the “Board”) is to provide stewardship and governance to Emera Incorporated (“Emera”) to ensure the viability of the Company by overseeing management of the business.

In addition to the powers set out in Emera’s Articles of Association, the Board shall have the following duties and responsibilities.

Independence and Integrity

The Board shall be comprised of a majority of “Independent Directors” as defined from time to time under applicable legislation and the rules of any stock exchange on which Emera’s securities are listed for trading.

The Chair shall be an “Independent Director” as defined above.

The Board shall review and approve standards for ethical business conduct for employees, Officers and Directors of Emera and its subsidiaries and affiliates and a procedure for monitoring compliance with such code throughout the Company.

The Board shall satisfy itself as to the integrity of the Chief Executive Officer and executive officers and the creation of an integrity-based culture throughout the Company.

The Board shall, through its oversight of management, continue to foster an organization which operates in an environmentally responsible manner.

Strategic Planning

The Board shall provide oversight and guidance on the strategic issues facing Emera.

The Board shall oversee a strategic planning process resulting in a strategic plan which shall be approved on an annual basis and will take into account, among other things, the opportunities and risks of the business.

The Board shall regularly consider Emera’s strategy, evaluate progress made in pursuing that strategy, and consider any adjustments to the strategy that may be required from time to time.

The Board shall review and approve the Company’s financial objectives, plans and actions, including significant capital allocations and expenditures.

The Board shall review and approve all material acquisitions, dispositions, projects, business plans and budgets.

Risk Responsibility

The Board shall oversee the implementation by management of appropriate systems to identify, report and manage the principal risks of Emera’s business. The Board will consider Emera’s risk profile and oversee Emera’s risk management by reviewing:

(a) the annual identification and assessment of the principal risks of Emera;

(b) the process for ongoing monitoring and reporting of the principal risks of Emera;

(c) the effectiveness of Emera’s mitigation response to its principal risks; and

(d) the alignment of risk management with Emera’s risk profile, its strategy and its organizational objectives, including capital and resources allocation.

The Board shall also review Emera’s annual insurance program and uninsured exposure, and Emera’s business continuity and disaster recovery plans.

The Board shall receive regular updates on the status of risk management activities and initiatives.

The Board shall approve and monitor processes that provide reasonable assurance of compliance with applicable legal and regulatory requirements.

Leadership Succession

The Board shall oversee policies and practices to enable the Company to attract, develop and retain the human resources required by the Company to meet its business objectives.

The Board shall appoint executive officers and delegate the necessary authority for the conduct of the business.

The Board shall establish annual performance expectations and corporate goals and objectives for the Chief Executive Officer and monitor progress against those expectations.

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The Board shall evaluate the performance and, following a review of recommendations from the Management Resources and Compensation Committee, approve compensation for executive officers.

The Board shall oversee the succession planning program for the Chief Executive Officer and other key executive positions from time to time.

Financial

The Board shall oversee the financial reporting and disclosure obligations imposed on the Company by laws, regulations, rules, policies and other applicable requirements.

The Board shall review the financial performance of the Company and declare dividends as appropriate.

The Board shall approve for release to the public as necessary the Company’s financial statements, management’s discussion and analysis (MD&A) and earnings releases prepared by management, and oversee the Company’s compliance with applicable audit, accounting and reporting requirements.

The Board shall review the quality and integrity of Emera’s internal controls and management information systems.

Corporate Communications and Public Disclosure

The Board shall review and approve a formal corporate disclosure policy and oversee policies and processes for accurate, timely and appropriate public disclosure.

The Board shall oversee systems for receiving feedback from stakeholders and monitor such feedback received by the Company.

Governance Responsibility

The Board is responsible for overseeing the Company’s corporate governance policies and practices and shall maintain a set of corporate governance practices that are specifically appropriate to the Company.

Pursuant to the Articles, the Directors shall appoint one of the Directors as Chair of the Board, and such Director shall not be an employee of Emera or any of its affiliates or subsidiaries.

The Board shall establish appropriate structures and procedures to allow the Board to function independently of management and in the interests of the Company and its Shareholders.

The Board, in carrying out its mandate, shall appoint Committees of the Board and delegate certain functions to those Committees, each of which shall have its own written charter. Notwithstanding such delegation, the Board retains its oversight function and ultimate responsibility for these delegated functions.

The Board shall oversee a process for the selection of qualified individuals for board nomination, and shall approve selection criteria for identifying Director candidates, taking into account the competencies and skills the Board as a whole should possess.

The Board shall undertake regular evaluation of the Board, the Chair of the Board, the Board Committees and individual Directors.

The Board shall undertake regular evaluation of Directors’ compensation.

The Board shall review this Charter annually to ensure it appropriately reflects the Board’s stewardship responsibilities.

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Appendix B

Emera Incorporated Amended Articles of Association

Amended Articles of Association of Emera Incorporated

Part A

Interpretation

1. In these Articles (including for greater certainty Part B hereof), unless there be something in the subject or context inconsistent therewith:

(a) “the “Act” means the Companies Act, R.S.N.S. 1989, c. 81 and all amendments thereto81, as amended and restated from time to time;

(b) “affiliate” for purposes of these Articles shall mean:

(i) one body corporate is affiliated with another body corporate if one of them is the subsidiary of the other or both are subsidiaries of the same body corporate or each of them is controlled by the same person; and

(ii) if two bodies corporate are affiliated with the same body corporate at the same time, they are deemed to be affiliated with each other.;

(c) “business day” means any day other than a Saturday or Sunday on which the banks in Halifax, Nova Scotia or the Company are generally open for business;

(d) (c) “the “Company” means NS Power HoldingsEmera Incorporated;

(e) (d) “the OfficeDirector” means the registered officea director of the Company for the time being of the Company; and “Board”, “board” and “Board of Directors” means the board of directors of the Company for the time being;

(f) a “meeting” shall, to the extent permitted by the Act and other applicable law, absent express provisions herein to the contrary, include a meeting held in whole or in part by telephonic, electronic or other means of communication contemplated by these Articles;

(g) the terms “member” (when not expressly referring to a member of another body, group or organization), “shareholder” and “Shareholder” each means a member of the Company, as that term is used in the Act in connection with a company limited by shares;

(h) the “Office” means the registered office for the time being of the Company;

(i) (e) “the “Register” means the register of members kept pursuant to Secion 42 ofthe Act and, where context permits, includes any branch register of members;

(j) (f) “the “Registrar” means the Registrar of Joint Stock Companies appointed under the Act and includes thea Deputy Registrar or any person authorized by the Governor in Council to perform the duties of the Registrar in the absence of the Registrar;

(k) (g) “month” means calendar month;

(l) (h) “in writing” and “written” includes printing, lithography and other modes of representing or reproducing words in visible form;

(m) “sent”, “given”, “delivered” and similar terms in relation to shareholders of the Company shall for greater certainty and without limitation include the “notice and access” method or any other manner of providing information permitted for any such purpose by the Act and applicable securities regulation;

(n) (i) “these Articles” and “these presents” include theseArticles” of Association“means these articles of association and all amendments thereto;

(o) (j) “reporting company” and “reporting issuer” shall havehas the meaningsmeaning as set out in Section 2 ofgiven thereto in the Act;

(p) (k) “Secretary” includes any person appointed to perform the duties of the Secretary temporarily;

(q) (l) “special resolution” means, in relation to the Company, notwithstanding the provisions of the Act, a resolution passed by a majority of not less thatthan three fourths of such members of the Company entitled to vote as are present in person or by proxy at a general meeting of the Company of which notice specifying the intention to propose the resolution as a special resolution has been duly given;

(r) (m) “subsidiary” for purposes of these Articles a body corporate is a “subsidiary” of another body corporate if;

(i) it is controlled by

(A) that other body corporate;

(B) that other body corporate and one or more bodies corporate each of which is controlled by that other body corporate,; or

(C) two or more bodies corporate each of which is controlled by that other body corporate; or

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(ii) it is a subsidiary of a body corporate that is a subsidiary of that other body corporate.

(s) (n) “proxyholder” includes an alternate proxyholder;

(t) (o) “Privatization Act” means the Nova Scotia Power Privatization Act, S.N.S., 1992, c.8 – and all amendments thereto;

(u) (p) “Reorganization Act” means the Nova Scotia Power Reorganization (1998) Act, S.N.S., 1998, c.19 – and all amendments thereto;

(v) “stated capital account” means a capital account maintained or deemed to be maintained by the Company for shares of a class or series pursuant to the Act;

(w) (q) words importing the singular number only include both the singular and the plural number and vice versaunless the context otherwise requires;

(x) (r) words importing the masculinegender onlyinclude the feminine genderall genders unless the context otherwise requires;

(y) (s) words importing persons include corporationsboth natural persons and bodies corporate and, where context permits, include partnerships and other entities.

2. These Articles have been prepared and adopted for use in an environment in which technology is evolving. Language used herein is not intended to limit the use of technology by the Company and its Directors, but rather is intended to facilitate the use of new technologies by the Company and its Directors wherever the objectives of these Articles can be well accomplished through the use of technology, subject to applicable law. These Articles are to be interpreted in the context of such intention, and terms used herein, including terms which suggest place, time or action, shall be interpreted to allow activities and processes to occur with the aid of technology by a means that may not be covered by the ordinary meanings of such terms. For greater certainty, the intention expressed here applies to technologies which existed at the time these Articles were originally prepared or most recently amended and any expressed or implied reference to the use of technology by the Company or the Directors in one provision of these Articles shall not preclude other provisions from being interpreted as applying to the use of other technologies by the Company and its Directors in light of such intention. The Board may make rules of interpretation from time to time which shall govern the interpretation of these Articles.

3. 2. The regulations appearing in Table A in the First Schedule to the Act shall not apply to the Company.

4. 3. The Directors may enter into and carry into effect or adopt and carry into effect any agreement or agreements made in connection with the reorganization of the Company pursuant to the Reorganization Act on behalf of the Company and shall have full power to agree to any modification in the terms of any such agreements, either before or after their execution.

5. 4. The Directors may, out of any moneys of the Company, pay all expenses incurred for the formation and reorganization of the Company.

5. The business of the Company may be commenced as soon as the Directors think fit.

6. The head office, registered officeOffice and principal executive offices of the Company shall be situated in the Province of Nova Scotia.

Shares

7. The Directors shall control the shares and, subject to the provisions of these Articles and the Reorganization Act, may allot or otherwise dispose of them to such persons at such times, on such terms and conditions, for such consideration and either at a premium or at par as they think fit.

8. The Directors may pay on behalf of the Company a reasonable commission to any person in consideration of that person subscribing or agreeing to subscribe (whether absolutely or conditionally) for any shares in the Company, or procuring or agreeing to procure subscriptions whether absolute or conditional) for any shares in the Company. TheSubject to the Act, the commission may be paid or satisfied in cash or in shares debentures or debenture stockother securities of the Company.

9. On the issue of shares the Company may arrange among the holders thereof differences in the calls to be paid and in the times for their payment.

10. If the whole or part of the allotment price of any shares is, by the conditions of their allotments, payable in instalments, every such instalment, shall, when due, be payable to the Company by the person who is at such time the registered holder of the shares. 11. Shares may be registered in the names of joint holders not exceeding three in number.

12. The joint holders of a share shall be severally as well as jointly liable for the payment of all instalments and calls due in respect of such share. On the death of one or more joint holders of shares the survivor or survivors of them shall alone be recognized by the Company as having title to the shares.

13. Save as herein otherwise provided, the Company shall be entitled to treat the registered holder of any share as the absolute owner thereof and accordingly shall not, except as ordered by a court of competent jurisdiction or required by statute, be bound to recognize any equitable or other claim to or interest in such share on the part of any other person.

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Certificates

14. Certificates of title to shares shall comply with the Act and be in such form as the Directors may from time to time approve. Nothing in these Articles shall require, should at any time the Act and applicable laws otherwise permit, that all or any shares issued by the Company be evidenced by certificates and, subject to applicable laws, the Directors may from time to time issue regulations, complying with the Act and other applicable laws, establishing book-based or other share ownership and transfer systems as they may see fit.

15. Certificates of title to shares shall be signed (i) by the President, a Vice-President or a Director, and (ii) by the Secretary, an Assistant Secretary or such other persons as the Directors may authorize and, (iii) if the Directors have appointed a transfer agent for the Company, (iii) by an authorized officer of such transfer agent. The signature of the President or a Vice-President or Director and, if a transfer agent has been appointed, of the Secretary or an Assistant Secretary or other authorized person signing in lieu of them, may be engraved, lithographed or printed upon the certificates or any one or more of them and all such certificates, when signed by the Secretary, an Assistant Secretary, such other person as the Directors authorize, or, if a transfer agent has been appointed, an authorized officer of such transfer agent, shall be valid and binding upon the Company. If the Company has appointed only one Director and officer, share certificates shall be signed by that Director alone as sole Director. If a certificate contains a printed or mechanically reproduced signature of a person, the Company may issue the certificate, notwithstanding that the person has ceased to be a Director or an officer of the Company and the certificate is as valid as if such person were a Director or an officer at the date of its issue. Any certificate representing shares of a class publicly traded on any stock exchange shall be valid and binding on the Company if it complies with the rules of such exchange whether or not it otherwise complies with this Article.

16. Subject to any regulations made at any time of the Directors, each shareholder may have title to the shares registered in the shareholder’s name evidenced by any number of certificates so long as the aggregate of the shares stipulated in such certificates equals the aggregate registered in the shareholder’s name.

17. Where shares are registered in the names of two or more persons, the Company shall not be bound to issue more than one certificate or one set of certificates, and such certificate or set of certificates shall be delivered to the person first named on the registerRegister.

18. AnySubject to any regulations issued by the Directors, any certificate that has become worn, damaged or defaced may, upon its surrender to the DirectorsCompany, be cancelled and replaced by a new certificate. AnySubject to any regulations issued by the Directors, any certificate that has become lost or destroyed may also be replaced by a new certificate upon proof of such loss or destruction to the satisfaction of the Directors and the furnishing to the Company of such undertakings of indemnity as the Directors deem adequate.

19. The sum of one dollar or such other sum as the Directors from time to time determine shall be paid to the Company for every certificate other than the first certificate issued to any holder in respect of any share or shares.

20. The Directors may cause one or more branch registers of membersRegisters to be kept in any place or places, whether inside or outside of the Province of Nova Scotia.

Calls

21. The Directors may from time to time make such calls as they think fit upon the shareholders in respect of all moniesamounts unpaid on the shares held by them respectively and not made payable at fixed times by the conditions on which such shares were allotted and each shareholder shall pay the amount of every call so made on him or her to the persons and at the times and places appointed by the Directors. A call may be made payable by instalments.

22. A call shall be deemed to have been made at the time when the resolution of the Directors authorizing such call was passed.

23. At least fourteen days’ notice of any call shall be given, and such notice shall specify the time and place at which and the person to whom such call shall be paid.

24. If the sum payable in respect of any call or instalment is not paid on or before the day appointed for the payment thereof, the holder for the time being of the share in respect of which the call has been made or the instalment is due shall pay interest on such call or instalment at the rate of fifteen per centumcent per annum from the day appointed for the payment thereof up to the time of actual payment.

25. At the trial or hearing of any action for the recovery of any moneyamount due for any call, it shall be sufficient to prove that the name of the shareholder sued is entered on the registerRegister as the holder or one of the holders of the share or shares in respect of which such debt accrued, that the resolution making the call is duly recorded in the minute book and that notice of such call was duly given to the shareholder sued in pursuance of these Articles. It shall not be necessary to prove the appointment of the Directors who made such call or any other matters whatsoever and the proof of the matters stipulated shall be conclusive evidence of the debt.

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26. The Directors may, if they think fit, receive from any shareholders willing to advance it all or any part of the moniesamounts due upon shares held by the shareholder beyond the sums actually called for; and upon the moniesamounts so paid or satisfied in advance or so much thereof as from time to time exceeds the amount of the calls then made upon the shares in respect of which such advance has been made the Company may pay interest at such rate, not exceeding fifteen per centumcent per annum, as the shareholder paying such sum in advance and the Directors agree upon or the Directors may agree with such shareholder that the shareholder may participate in profits upon the amount so paid or satisfied in advance.

Forfeiture of Shares

27. If any shareholder fails to pay any call or instalment on or before the day appointed for payment, the Directors may at any time thereafter while the call or instalment remains unpaid serve a notice on such shareholder requiring the shareholder to pay the call or instalment together with any interest that may have accrued and all expenses that may have been incurred by the Company by reason of such non-payment.

28. The notice shall name a day (not being less than fourteen days after the date of the notice) and a place or places on and at which such call or instalment and such interest and expenses are to be paid. The notice shall also state that, in the event of non-payment on or before the day and at the place or one of the places so named, the shares in respect of which the call was made or instalment is payable will be liable to be forfeited.

29. If the requirements of any such notice are not complied with, any shares in respect of which such notice has been given may at any time thereafter, before payment of all calls or instalments, interest and expenses due in respect thereof, be forfeited by a resolution of the Directors to that effect. Such forfeiture shall include all dividends declared in respect of the forfeited shares and not actually paid before the forfeiture.

30. When any share has been so forfeited, notice of the resolution shall be given to the shareholder in whose name it stood immediately prior to the forfeiture and an entry of the forfeiture shall be made in the register.Register.

31. Any share so forfeited shall be deemed the property of the Company and the Directors may sell, re-allot or otherwise dispose of it in such manner as they think fit.

32. Directors may at any time before any share so forfeited has been sold, re-allotted or otherwise disposed of, annul the forfeiture thereof upon such conditions as they think fit.

33. Any shareholder whose shares have been forfeited shall nevertheless be liable to pay and shall forthwith pay to the Company all calls, instalments, interest and expenses owing upon or in respect of such shares at the time of the forfeiture together with interest thereon at the rate of fifteen per cent per annum from the time of forfeiture until payment. The Directors may enforce such payment if they think fit, but are under no obligation to do so.

34. A certificate in writing under the hand of the Secretary stating that a share has been duly forfeited on a specified date in pursuance of these Articles and the time when it was forfeited shall be conclusive evidence of the facts therein stated as against all persons who would have been entitled to the share but for such forfeiture.

Lien on Shares

35. The Company shall have a first and paramount lien upon all shares (other than fully paid up shares) registered in the name of each shareholder (whether solely or jointly with others) and upon the proceeds from the sale thereof for the debts, liabilities and other engagements of the shareholder, solely or jointly with any other person, to or with the Company, whether or not the period for the payment, fulfilment or discharge thereof has actually arrived, and such lien shall extend to all dividends from time to time declared in respect of such shares. Unless otherwise agreed, the registration of a transfer of shares shall operate as a waiver of any lien of the Company on such shares.

36. For the purposes of enforcing such lien the Directors may sell the shares subject to the lien in such manner as they think fit; but no sale shall be made until the period for the payment, fulfilment or discharge of such debts, liabilities or other engagements has arrived, and until notice in writing of the intention to sell has been given to such shareholder, or to the shareholder’s executors or administrators and default has been made by the shareholder or the executors or administrators in such payment, fulfilment or discharge for seven days after such notice.

37. The net proceeds of any such sale after the payment of all costs shall be applied in or towards the satisfaction of such debts, liabilities or engagements and the residue, if any, paid to such shareholder or thesuch shareholder’s executors, administrators or assigns.

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Validity of Sales

38. Upon any sale after forfeiture or the enforcing of a lien in purported exercise of the powers given by these Articles the Directors may cause the purchaser’s name to be entered in the registerRegister in respect of shares sold, and the purchaser shall not be bound to see to the regularity of the proceedings or to the application of the purchase money, and after the purchaser’s name has been entered in the registerRegister in respect of such shares the validity of the sale shall not be impeached by any person and the remedy of any person aggrieved by the sale shall be in damages only and against the Company exclusively.

Transfer Of Shares

39. The instrument of transfer of any share in the Company shall be signed by the transferor. The transferor shall be deemed to remain the holder of such share until the name of the transferee is entered in the registerRegister in respect thereof and shall be entitled to receive any dividend declared thereon before the registration of the transfer.

40. The instrument of transfer of any share shall be in writing in the following form or as near thereto as circumstances will permitto the following effect or as may be otherwise approved by the Directors or the Company’s transfer agent from time to time:

For value received I (we) assign and transfer unto                                                                     

Please insert social insurance number or other tax identifying number of assignee                                                             

Please print name and address including postal code of assignee shares                 of the Company represented by this certificate.

Date                                                                                      

Signature                                                                              

SIGNATURE GUARANTEE: The signature must be guaranteed by a bank, trust company or a member of a recognized stock exchange whose signature is acceptable to the Transfer AgentCompany’s transfer agent.

41. The Directors may, without assigning any reason therefor, decline to register any transfer of shares not fully paid up or upon which the Company has a lien.

42. Every instrument of transfer shall be left at the officeOffice of the Company or the office of its transfer agent where the principal or a branch register of membersRegister is maintained for registration together with the certificate of the shares, if any, to be transferred and such other evidence as the Company may require to prove the title of the transferor or the right of the transferor to transfer the shares.

43. A fee not exceeding Five Dollars ($5.00) may be charged for each transfer and shall, if required by the Directors, be paid before its registration.

44. Every instrument of transfer shall, after its registration, remain in the custody of the Company.

45. Any instrument of transfer that the Directors decline to register shall, except in case of fraud, be returned to the person who deposited it.

Transmission of Shares

46. The executors or administrators of a deceased member (not being one of several joint holders) shall be the only persons recognized by the Company as having any title to the shares registered in the name of such member. When a share is registered in the names of two or more joint holders, the survivor or survivors or the executors or administrators of the deceased survivorlast surviving member, shall be the only persons recognized by the Company as having any title to, or interest in, such share.

47. Notwithstanding anything in these Articles, if the Company has only one member, not being one of several joint holders, and that member dies, the executors or administrators of such deceased member shall be entitled to register themselves in the register of membersRegister as the holders of such deceased member’s share whereupon they shall have all the rights given by these Articles and law to members.

48. AnySubject to the Reorganization Act, any person becoming entitled to shares in consequence of the death or bankruptcy of any member or any way other than by allotment or transfer upon producing such evidence of being entitled to act in the capacity claimed or of such person’s title to the shares as the Directors think sufficient, may, with the consent of Directors, (which they shall not be under any obligation to give) be registered as a member in respect of such shares, or may, without being registered, transfer such shares subject to the provisions of these Articles respecting the transfer of shares.

49. The Directors shall have the same right to refuse to register a person entitled by transmission to any shares, or that person’s nominee, as if the person were the transferee named in an ordinary transfer presented for registration.

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Stated Capital Accounts

50. Notwithstanding anything contained in the Act:

(a) The Company shall maintain a separate stated capital account, sometimes called a stated capital account, for each class and series of shares it issues; and, should it fail to do so will be deemed to maintain such account as contemplated by the Act.

(b) The Company shall add to the appropriate stated capital account the full amount of any consideration it receives for any shares it issues;.

(c) Notwithstanding paragraph (b) of this Article 50, where the Company issues shares in exchange for

(i) property of a person who immediately before the exchange or that, because of the exchange, did not deal with the Company at arm’s length within the meaning of that term in the Income Tax Act (Canada), or

(ii) shares of a body corporate that immediately before the exchange or that, because of the exchange, did not deal with the Company at arm’s length within the meaning of that term in the Income Tax Act (Canada),

the Company may, subject to paragraph (d) of this Article 50, add to the stated capital accounts maintained for the shares of the classes or series issued the whole or any part of the amount of the consideration it received in the exchange.

(d) On the issue of a share the Company shall not add to a stated capital account in respect of the share it issues an amount greater than the amount of the consideration it received for the share.

Record Dates

51. Notwithstanding anything contained in the Act:

(a) For the purpose of determining shareholders:

(i) entitled to receive payment of a dividend;

(ii) entitled to participate in a liquidation distribution; or

(iii) for any other purpose except the right to receive notice of or to vote at a meeting,

the Directors may fix in advance a date as the record date for such determination of shareholders but such record date shall not precede by more than fifty days the particular action to be taken by more than the longer of (A) sixty days, or (B) such longer period as is fixed from time to time by the Directors and complies with all applicable laws;

(b) For the purpose of determining shareholders entitled to receive notice of a meeting of shareholders, the Directors may fix in advance a date as the record date for such determination of shareholders, but, unless different periods complying with all applicable laws are fixed from time to time by the Directors, such record date shall not precede by more than fiftysixty days or be less than twenty-one days before the date on which the meeting is to be held;

(c) For the purpose of determining shareholders entitled to vote at a meeting of shareholders, the Directors may fix in advance a date as the record date for such determination of shareholders, but such record date shall not precede the date on which the meeting is to be held by more than longer of (A) sixty days, or (B) such longer period complying with all applicable laws as is fixed from time to time by the Directors;

(d) (c) If no record date is fixed,

(i) The record date for the determination of shareholders entitled to receive notice of a meeting of shareholders shall be

(A) at the close of business on the day immediately preceding the day on which the notice is given; or

(B) if no notice is given, the day on which the meeting is held; and

(ii) the record date for the determination of shareholders for any purpose other than to establish a shareholder’s right to receive notice of a meeting or a vote shall be at the close of business on the day on which the Directors pass the resolution relating thereto;

(e) (d) If a record date is fixed, unless notice of the record date is waived in writing by every holder of a share of the class or series affected whose name is set out in the Register at the close of business on the day the directorsDirectors fix the record date, notice thereof shall, not less than seven days before the date so fixed, be given

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(i) either (A) by advertisement in a newspaper published or distributed in the place where the corporationCompany has its registered officeOffice and in each place in Canada where it has a transfer agent or where a transfer of its shares may be recorded; or (B) as may be otherwise permitted under applicable securities law and the Act; and

(ii) by written notice to each stock exchange in Canada on which the shares of the Company are listed for trading.

ReductionAlteration of Capital

52. Subject to the the rights, if any, of the holders of shares of any class or series of shares to vote separately as a class or series thereon, the Company may, from time to time, by special resolution reduce its share capital and any capital redemption reserve fund in any way, and having done so shall in accordance with the Act seek an order of the Court confirming such reduction. Act, the Reorganization Act, the provisions of this Article and Part B of these Articles, and the rights, if any, under the Act or other applicable law, of the holders of shares of any class or series of shares to vote separately as a class or series thereon, the Company may by resolution of its shareholders, add, change or remove any provision of its Memorandum to increase its share capital by the creation of new shares of such amount as it thinks expedient and may by special resolution, add, change or remove any provision of its Memorandum to:

(a) increase its share capital to authorize a new class of shares without nominal or par value, either stating the maximum number of shares of such class that the Company is authorized to issue or, where there is no limit on the number of shares of such class, a statement to that effect;

(b) change the maximum number of shares of a class of shares without nominal or par value that the Company is authorized to issue, which may include a change to or from an unlimited number of shares of that class;

(c) consolidate and divide all or any of its share capital into shares of larger amounts than its existing shares;

(d) change the shares of any classes, whether issued or unissued, into a different number of shares of the same class or into the same or different number of shares of another class;

(e) convert all or any of its paid-up shares into stock and reconvert that stock into paid-up shares of any denomination or into shares without nominal or par value;

(f) subdivide its shares, or any of them, into shares of smaller amounts than is fixed by the Memorandum, so, however, that in the subdivision the proportion between the amount paid and the amount, if any, unpaid on each reduced share shall be the same as it was in the case of the share from which the reduced share is derived, and the special resolution whereby any share is subdivided may determine that as between the holders of the shares resulting from such subdivision, one or more of such shares shall have some preference or special advantage as regards dividend, capital, voting or otherwise, over, or as compared with, the others or other;

(g) exchange shares of one denomination for another, including shares without nominal or par value;

(h) convert any part of its issued or unissued share capital into preferred shares redeemable or purchasable by the Company;

(i) except in the case of preferred shares, convert all or any of its previously authorized unissued or issued and fully paid-up shares with nominal or par value into the same number of shares without any nominal or par value and reduce, maintain or increase accordingly its liability on any of its shares so converted, but the power to reduce its liability on any of its shares so converted where it results in a reduction of paid-up capital may only be exercised in accordance with any applicable restriction in the Act;

(j) convert all or any of its previously authorized, unissued or issued, fully paid-up shares without nominal or par value into the same or a different number of shares with nominal or par value, and for such purpose the shares issued without nominal or par value and replaced by shares with a nominal or par value shall be considered as fully paid, but their aggregate par value shall not exceed the value of the net assets of the Company as represented by the shares without par value issued before the conversion;

(k) change the designation of all or any of its shares and add, change or remove any rights, privileges, restrictions or conditions including rights to accrued dividends, in respect of all or any of the shares, whether issued or unissued; or

(l) make any change or do anything which is permitted by, or not restricted by, the Act

53. Subject to the Act, the Company may by resolution of its shareholders, add, change or remove any provision of its Memorandum to cancel shares that at the date of the passing of the resolution in that behalf, have not been taken or agreed to be taken by any person, and diminish the amount of its share capital by the amount of the shares so cancelled.

54. Where the shares of a class are issued in series, and any designation, rights, privileges, restrictions or conditions attaching to any series of such shares are set out in the Memorandum, all provisions of these Articles respecting the creation, amendment, exchange, cancellation or other change of shares of any class, apply thereto.

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55. Subject to the Act, the Reorganization Act, the provisions of this Article and Part B of these Articles, and the rights, if any, under the Act or other applicable law, of the holders of shares of any class or series of shares to vote separately as a class or series thereon and the restrictions on allotment and issuance in these Articles and the Memorandum, any shares authorized to be issued may be issued upon such terms and conditions and with such rights, privileges, limitations, restrictions and conditions attached thereto as the Company by resolution of its shareholders shall direct or, if no direction is given, as the Directors determine, and in particular such shares may be issued with a preferential or qualified right to dividends and in the distribution of assets of the Company, and with a special right, or without any right, of voting. Except as otherwise provided by the conditions of issue, or by these Articles, any capital raised by the creation of new shares shall be considered part of the original capital and shall be subject to the provisions herein contained with reference to payment of calls and instalments, transfer and transmission, forfeiture, surrender, lien and otherwise.

Redemption of Shares and Other Reductions of Capital

56. Subject to the Act, the Reorganization Act, the provisions of this Article and Part B of these Articles, and the rights, if any, under the Act or other applicable law, of the holders of shares of any class or series of shares to vote separately as a class or series thereon, the Company may reduce all or a portion of the paid-up capital on a class or series of shares, or certain shares of such class or series of shares, in any way and for any purpose. Where such reduction of paid-up capital is so authorized, the shareholders approving such reduction may in such authorizing resolution determine when the paid-up capital shall be reduced on the shares of the particular class or series of shares, or certain shares of such class or series of shares, the amount of paid-up capital to be reduced on each such share (where such does not necessarily follow from the determination of the amount reduced on the class or series as a whole) and the manner in which and purpose for which such reduction shall be effected. If the shareholders fail to determine any such matter in such resolution they may subsequently determine such matter by special resolution, failing which the Directors, or such persons as may be authorized by the shareholders by special resolution, may make any such determination or determinations not inconsistent with a prior determination of the shareholders as may be necessary or desirable from time to time. The manner in which or purpose for which the reduction shall be effected may include, without limitation, any of the following:

(a) reducing or extinguishing any liability of the holders of any shares of any class or series including, without limitation, extinguishing or reducing the liability on any of such shares not paid-up;

(b) either with or without extinguishing or reducing liability on shares of any class or series, paying or distributing to the holder of an issued share of any such class or series of shares an amount not exceeding the paid-up capital thereof;

(c) declaring its paid-up capital to be reduced, without payment or distribution, by an amount that is lost or unrepresented by realizable assets, or by such other amount as the Company may see fit;

(d) paying cash or transferring other property;

(e) issuing other securities, debentures, bonds, securities, promissory notes or other indebtedness;

(f) increasing any share premium, contributed surplus or other surplus account; or

(g) providing a sinking fund on any terms thought fit for the redemption, purchase or acquisition of shares of any class or series.

53. SubjectWithout limiting the foregoing but subject to the Act and any provisions of the Act from time to time in forceattached to such shares, the Company may redeem, purchase or otherwise acquire any of its shares issued by it. Theand the Directors may determine the manner and the terms for redeeming, purchasing or otherwise acquiring such shares and may from time to time provide a sinking fund on such terms as they think fit for the redemption, purchase or acquisition of such shares. Preference shares which by their provisions may be redeemed or purchased by the Company shall be redeemed subject to such provisions.shares of any class or series.

57. The amount of the reduction in the paid-up capital of the class or series of shares, or certain shares of such class or series of shares, including upon the purchase or redemption of any shares acquired by the Company, shall be recorded, or shall be deemed to have been recorded, in the accounts of the Company maintained or deemed to be maintained for such class or series of shares. Where the Company has issued more than one class or series of shares, the special resolution authorizing the reduction in paid-up capital must specify the capital account or accounts from which the paid-up capital returned, cancelled or otherwise extinguished will be deducted.

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Modification of Rights of Shareholders

58. 54. The rights, privileges, restrictions and conditions attached to a class or series of shares may be added to, changed or removed only with the prior approval of the holders of the issued shares of that class or series given as specified herein, in addition to any vote or authorization required by law. Any approval of the holders of the shares with respect to the modification of the rights, privileges, restrictions, and conditions attached to the shares may be given in such manner as may then be required by law, subject to a minimum requirement that such approval be given either (i) be given by resolution signed by all the holders of the issued and outstanding shares of the class or series, or (ii) passed by the affirmative vote of at least two-thirds of the votes cast by the holders of the shares who voted in respect of that resolution at a meeting of the holders of the shares duly called for that purpose at which the holders of at least fifty percent (50%) of the outstanding shares of that class or series are present in person or represented by proxy, or, if such quorum is not present at such meeting, at an adjournment thereof at which the holders of shares of that class or series then present in person or represented by proxy shall constitute a quorum for all purposes. The formalities to be observed with respect to proxies, the giving of notice, voting, and the conduct of any such meeting or any adjourned meeting shall be those from time to time prescribed by these articlesArticles or otherwise prescribed by law with respect to meetings of shareholders. Notwithstanding the foregoing, unless the rights, privileges, terms or conditions attached to a class or series of shares provide otherwise, the holders of shares of a class or of a series are not entitled to vote separately as a class or series and are not entitled to dissent, upon a proposal to amend the articlesMemorandum or these Articles to,

(a) increase or decrease any maximum number of authorized shares of such class or series, or increase any maximum number of authorized shares of a class or series having rights or privileges equal or superior to the shares of such class or series;

(b) effect an exchange, reclassification or cancellation of all or part of the shares of such class or series; or

(c) create a new class or series of shares equal or superior to such class or series.

This Article shall not be deemed by implication to limit, restrict or curtail the power of modification which the Company would have if this Article were omitted.

Surrender of Shares

59. 55. The Directors may accept the surrender of any share by way of compromise of any question as to the holder being properly registered in respect thereof. Any share so surrendered may be disposed of in the same manner as a forfeited share.

Borrowing Powers and Power of Guarantee

60. 56. The Directors on behalf of the Company may from time to time in their discretion:

(a) raise or borrow moneyfunds for any of the purposes of the Company or any of them;

(b) secure, subject to compliance with Section 102 of the Act, the repayment of moneysfunds so raised or borrowed in such manner and upon such terms and conditions in all respects as they think fit, and in particular by the execution and delivery of mortgages of the Company’s real or personal property, or by the issue of bonds, debentures or debenture stockother securities of the Company secured by mortgage or other charge upon all or any part of the property of the Company, both present and future, including its uncalled capital for the time being;

(c) sign or endorse bills, notes, acceptances, cheques, contracts, and other evidence of or securities for moneyfunds borrowed or to be borrowed for the purposes aforesaid; and

(d) pledge debentures as security for loans.

61. 57. Bonds, debentures and other securities may be made assignable, free from any equities between the Company and the person to whom such securities were issued.

62. 58. Any bonds, debentures and other securities may be issued at a discount, premium or otherwise and with special privileges as to redemption, surrender, drawings, allotments of shares, attending and voting at general meetings of the Company, appointment of Directors and other matters.

63. 59. The Directors may, from time to time and in their discretion:

(a) guarantee on behalf of the Company the performance of liabilities, contracts and loans of any kind whatsoever, and give any postponements required in connection with such a guarantee; and

(b) delegate authority to such officers and Directors of the Company and on such terms and conditions as they, in their sole discretion determine appropriate, to provide guarantees on behalf of the Company as set out in the preceding sub-paragraph including to give any postponements required in connection with such guarantees.

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Meetings

64. 60. OrdinaryAnnual general meetings of the Company shall be held at least once in every calendar year at such time and place as may be determined by the Directors and not later than fifteen months after the preceding ordinaryannual general meeting of the Company. All other meetings of the Company shall be called special general meetings. Annual or special general meetings may be held either within or without the Province of Nova Scotia.

65. 61. The Directors may whenever they think fit, convene a special general meeting and they shall, upon the requisition of members shareholders of the Company holding not less than five percent of the total voting rights of all the members having at the date of the deposit of the requisition a right to vote at general meetings of the Company andissued share capital of the Company in respect of whose shares all calls or other sums then due have been paid, or otherwise as provided in the Act, forthwith proceed to convene a special general meeting of the Company, to be held at such time and place as the Directors determine.

66. 62. The requisition shall state the objects of the meeting requested, be signed by the membersshareholders making it and deposited at the registered office of the CompanyOffice. It may consist of several documents in like form each signed by one or more of the requisitionists.

67. 63. If the Directors do not proceed to cause a meeting to be held within twenty-one days (21) days from the date that the requisition is so deposited, or within such longer period as may be permitted by applicable law, the requisitionists, or a majority of them in value, may themselves convene a meeting, provided it is held within three (3) months after the date of the deposit of the requisition.

68.

(a) No business may be transacted at an annual general meeting of shareholders, other than business that is either (i) specified in the Company’s notice of meeting (or any supplement thereto) given by or at the direction of the Board, (ii) otherwise properly brought before the annual general meeting by or at the direction of the Board or (iii) otherwise properly brought before the annual general meeting by any shareholder of the Company who complies with the proposal procedures set forth in this Article 68. For business to be properly brought before an annual general meeting by a shareholder of the Company, such shareholder must submit a proposal to the Company for inclusion in the Company’s management proxy circular; provided that any proposal that includes nominations for the election of Directors shall be submitted to the Company in accordance with the requirements set forth in Article 69.

(b) At a special general meeting of shareholders, only such business shall be conducted as shall have been brought before the meeting pursuant to the Company’s notice of meeting (or any supplement thereto) given by or at the direction of the Board. Nominations of persons for election to the Board of Directors may be made at a special general meeting of shareholders at which Directors are to be elected pursuant to the Company’s notice of meeting only pursuant to and in compliance with Article 69.

69.

(a) Only individuals who are nominated in accordance with the procedures set out in this Article 69 and who, at the discretion of the Board, satisfy the qualifications of a Director as set out in applicable law and these Articles shall be eligible for election as Directors of the Company at any general meeting of shareholders of the Company. Nominations of individuals for election to the Board of Directors of the Company may be made at any annual general meeting of shareholders, or at any special general meeting of shareholders if one of the purposes for which the special general meeting was called was the election of Directors:

(i) by or at the direction of the Board, including pursuant to a notice of meeting;

(ii) by or at the direction or request of one or more shareholders pursuant to a requisition of the shareholders made in accordance with the Act; or

(iii) by any person (a “Nominating Shareholder”) who

(A) at the close of business on the date of the giving of the notice provided for below in this Article 69 and on the record date for notice of such meeting, is a registered holder of shares carrying the right to vote at such meeting on the election of Directors; and

(B) complies with the notice procedures set forth in this Article 69.

(b) In addition to any other applicable requirements, for a nomination to be made by a Nominating Shareholder, the Nominating Shareholder must have given timely notice thereof and in proper written form to the Secretary of the Company at the Office.

(c) To be timely, a Nominating Shareholder’s notice to the Secretary must be made within the applicable period described below:

(i) in the case of an annual general meeting of shareholders, not less than 30 days prior to the date of the annual general meeting of shareholders; provided, however, that if the annual general meeting of shareholders is to be held on a date that is less than 50 days after the date (in this Article, the “Notice Date”) on which the first public announcement of the date of the annual general meeting was made, notice by the Nominating Shareholder may be made not later than the 10th day following the Notice Date; and

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(ii) in the case of a special general meeting (which is not also an annual general meeting) of shareholders called for the purpose of electing Directors (whether or not called for other purposes), not later than the 15th day following the day on which the first public announcement of the date of the special meeting of shareholders was made.

(d) To be in proper written form, a Nominating Shareholder’s notice to the Corporate Secretary must set forth

(i) as to each individual whom the Nominating Shareholder proposes to nominate for election as a Director

(A) the name, age, business address and residential address of the individual;

(B) the principal occupation or employment of the individual;

(C) the class or series and number of shares in the capital of the Company which are beneficially owned, or over which control or direction is exercised, directly or indirectly, by such individual as of the record date for the meeting of shareholders (if such date shall then have been made publicly available and shall have occurred) and as of the date of such notice; and

(D) any other information relating to the individual that would be required to be disclosed in a dissident’s proxy circular or other filings to be made in connection with solicitations of proxies for election of Directors pursuant to applicable laws, including applicable securities laws; and

(ii) as to the Nominating Shareholder and any beneficial owner respecting which the notice was given, the names of such person(s) and

(A) the class or series and number of shares in the capital of the Company which are controlled, or over which control or direction is exercised, directly or indirectly, by such person(s) and each person acting jointly or in concert with any of them (and for each such person any options or other rights to acquire shares in the capital of the Company, derivatives or other securities, instruments or arrangements for which the price or value or delivery, payment or settlement obligations are derived from, referenced to, or based on any such shares, hedging transactions, short positions and borrowing or lending arrangements relating to such shares) as of the record date for the meeting of shareholders (if such date shall then have been made publicly available and shall have occurred) and as of the date of such notice;

(B) any proxy, contract, agreement, arrangement, understanding or relationship pursuant to which such Nominating Shareholder or beneficial owner has a right to vote any shares in the capital of the Company on the election of Directors;

(C) in the case of a special general meeting of shareholders called for the purpose of electing Directors, a statement as to whether the Nominating Shareholder intends to send an information circular and form of proxy to any shareholders of the Company in connection with any individual’s nomination and (iv) any other information relating to such Nominating Shareholder or beneficial owner that would be required to be made in a dissident’s proxy circular or other filings to be made in connection with solicitations of proxies for election of Directors pursuant to the Act and applicable securities laws; and

(D) any other information relating to such Nominating Shareholder or beneficial owner that would be required to be made in a dissident’s proxy circular or other filings to be made in connection with solicitations of proxies for election of Directors pursuant to the Act and applicable securities laws.

(e) A Nominating Shareholder’s notice to the Corporate Secretary must also state whether

(i) in the opinion of the Nominating Shareholder and the proposed nominee, the proposed nominee would qualify to be an independent Director of the Company under Sections 1.4 and 1.5 of National Instrument 52-110 of the Canadian Securities Administrators (“NI 52-110”); and

(ii) with respect to the Company the proposed nominee has one or more of the relationships described in Sections 1.4(3), 1.4(8) and 1.5 of National NI 52-110 and, if so, which ones.

(f) The chair of the meeting shall have the power and duty to determine whether a nomination was made in accordance with the procedures set forth in the foregoing provisions and, if any proposed nomination is not in compliance with such foregoing provisions, to declare that such defective nomination shall be disregarded. A duly appointed proxy holder of a Nominating Shareholder shall be entitled to nominate at a meeting of shareholders the Directors nominated by the Nominating Shareholder, provided that all of the requirements of this Article 69 have been satisfied. If the Nominating Shareholder or its duly appointed proxy holder does not attend at the meeting of shareholders to present the nomination, the nomination shall be disregarded notwithstanding that proxies in respect of such nomination may have been received by the Company.

(g) In addition to the provisions of this Article 69, a Nominating Shareholder and any individual nominated by the Nominating Shareholder shall also comply with all of the applicable requirements of the Act, applicable securities laws and applicable stock exchange rules regarding the matters set forth herein.

(h) For purposes of this Article 69, “public announcement” shall mean disclosure in a news release reported by a national news service in Canada, or in a document publicly filed by the Company at such location determined by the Board of Directors from time to time (including any web site or other virtual location).

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(i) Notwithstanding any other provision of the Company’s Articles, notice given to the Secretary of the Company pursuant to this Article 69 may only be given by personal delivery (at the Office of the Company) or by electronic mail (at the e-mail address set out in the Company’s issuer profile on the System for Electronic Document Analysis and Retrieval at www.sedar.com or such other location as may be determined by the Board of Directors from time to time), and shall be deemed to have been given and made only at the time it is so served by personal delivery to the Corporate Secretary of the Company or sent by e-mail to such e-mail address (provided that receipt of confirmation of such transmission has been received); provided that if such delivery or electronic communication is made on a day which is a not a business day or later than 5:00 p.m. (Halifax Time) on a day which is a business day, then such delivery or electronic communication shall be deemed to have been made on the next following day that is a business day.

(j) Notwithstanding the foregoing, the board may, in its sole discretion, waive any requirement in this Article 69.

70. 64. At least twenty-one (21) days’ notice, or such shorter notice period as is fixed from time to time by the Directors and complies with all applicable laws, of every general meeting, specifying the place, day and hour of the meeting and, when special business is to be considered, the general nature of such business, shall be given to the membersshareholders entitled to be present at such meeting by notice given in accordance with the provisions of these Articles. Subject to any exemption authorized pursuant to the Act, when the Company is a reporting issuer, it shall, concurrently with or prior to sending notice of a meeting of the Company, send a form of proxy to each membershareholder who is entitled to receive notice of the meeting. With the consent in writing of all the membersshareholders entitled to vote at such meeting, a meeting may be convened by a shorter notice and in any manner theythe Directors think fit, or if all the membersshareholders are present at a meeting either in person or by proxy, notice of the time, place and purpose of the meeting may be waived. Any previously scheduled annual general meeting of shareholders may be postponed, and any shareholders’ meeting other than an annual general meeting of shareholders may be postponed or cancelled, by the Company by public notice given to the shareholders prior to the time previously scheduled for such meeting of shareholders.

71. 65. The accidental omission to give any such notice to any of the membersshareholders or the failure of any shareholder to receive such notice shall not invalidate any resolution passed at any suchgeneral meeting.

Proceedings at General Meetings

72. 66. The business of any ordinaryannual general meeting shall be to receive and consider the financial statements of the Company, and the reports of the Directors and Auditorsauditors thereon, to elect Directors in the place of those retiring, to appoint auditors, and to transact any other business which under these Articles ought to be transacted at an ordinaryannual general meeting.

73. If authorized by the Board in its sole discretion, and subject to any applicable law and such guidelines and procedures as the Board may adopt, shareholders and proxyholders not physically present at a meeting of shareholders may, by means of a telephonic, electronic or other communication facility that permits all participants to communicate adequately during the meeting, if the Company makes available such a communication facility: (a) participate in a meeting of shareholders; and (b) be deemed present in person at the meeting to the fullest extent permitted by law; and (c) vote at the meeting whether such meeting is to be held at a designated place or solely by means of a telephonic, electronic or other communication facility, provided that (i) the Company shall implement reasonable measures to verify that each person deemed present and permitted to vote at the meeting by means of a telephonic, electronic or other communication facility is a shareholder or proxyholder, (ii) the Company shall implement reasonable measures to provide such shareholders and proxyholders a reasonable opportunity to read or hear the proceedings of the meeting substantially concurrently with such proceedings and to vote on matters submitted to the shareholders, and (iii) if any shareholder or proxyholder votes or takes other action at the meeting by means of a telephonic, electronic or other communication facility, a record of such vote or other action shall be maintained by the Company.

74. 67. No business shall be transacted at any general meeting unless the quorum requisite is present at the commencement of the business. A corporationbody corporate that is a member of the Company and has a duly authorized agent or representative present at any such meeting shall for the purpose of this Article be deemed to be personally present at such meeting.

75. 68. Three members, where there are more than two members, personally present and entitled to vote shall be a quorum for a general meeting for the choice of a chair and the adjournment of the meeting. For all other purposes the quorum for a general meeting shall be three members personally present and entitled to vote and holding or representing by proxy not less than one tenth in numbertwenty-five per cent of such of the issued shares of the Company as confer upon the holders thereof the right to vote at such meeting.

76. 69. TheUnless otherwise determined by the Board, the Chair of the Board shall be entitled to take the chair at every general meeting or, if there be no Chair of the Board, or if the Chair of the Board is not present within fifteen minutes after the time appointed for holding the meeting, the President or declines to take the chair, the President, or if the President is not present within fifteen minutes after the time appointed for holding the meeting or declines to take the chair, a vice-president, shall be entitled to take the chair. If the Chair or the President or a vice-president is not present within fifteen minutes after the time appointed for holding the meeting or is present but declines to take the chair, the members present entitled to vote at the meeting shall choose another Director as Chairchair of the meeting and, if no Director is present or if all the Directors present decline to take the chair, then the members present entitled to vote shall choose one of their number to be Chair.chair of the meeting.

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77. 70. If within half an hour from the time appointed for the meeting a quorum is not present, the meeting, if it was convened pursuant to a requisition made pursuant to these Articles shall be dissolved; if it was convened in any other way, it shall stand adjourned to the same day, in the next week, at the same time and place. If at such adjourned meeting a quorum is not present, those members entitled to vote who are present shall be a quorum and may transact the business for which the meeting was called.

78. 71. AtSubject to the Act, at any general meeting a resolution put to the meeting may be decided by a show of hands if the vote is unanimous otherwise the resolution shall be decided by a poll of the members present in person or by proxy and entitled to vote at such meetingunless, either before or on the declaration of the result of the show of hands, a poll is demanded by the chair, a member or a proxyholder; and unless a poll is so demanded, a declaration by the chair of the meeting that the resolution has been carried, carried by a particular majority, lost or not carried by a particular majority and an entry to that effect in the Company’s book of proceedings shall be conclusive evidence of the fact without proof of the number or proportion of the votes recorded in favour or against such resolution.

79. 72. A poll shall be taken at the meeting in such manner as the chair of the meeting directs, and either at once or after an interval. The result of the poll shall be deemed to be the resolution of the meeting at which the poll was taken. The demand of a poll may be withdrawn. When any dispute occurs over the admission or rejection of a vote, it shall be resolved by the chair and such determination made in good faith shall be final and conclusive. The demand of a poll shall not prevent the continuance of a meeting for the transaction of any business other than the question on which a poll has been demanded.

80. 73. When on any motion there is an equality of votes, the motion shall fail.

81. Any person entitled to vote at a general meeting where the Company has made available a telephonic, electronic or other communication facility for the purposes of attending and voting at such meeting may vote by means of the telephonic, electronic or other communication facility that the Company has made available for that purpose. Subject to any applicable law and such guidelines and procedures as the Board may adopt, any vote referred to in these Articles may be held entirely by means of a telephonic, electronic or other communication facility if the Company makes available such a communication facility, provided, in each case, that the facility: (i) enables the votes to be gathered in a manner that permits their subsequent verification; and (ii) permits the tallied votes to be presented to the Company.

82. 74. The chair of a general meeting may, with the consent of a majority of the members presentand if so directed by the meeting must, adjourn the meeting from time to time and from place to place, but no business shall be transacted at any adjourned meeting other than the business left unfinished at the meeting that was adjourned.

Votes of Members

83. 75. Subject to the Reorganization Act and Part B of these Articles of Association and the provisions applicable to any shares issued under conditions limiting or excluding the rights of the holders thereof to vote at general meetings, every member present in person or by proxy (including members deemed to be present) shall have one vote for every share held by such member. In computing the majority on a poll reference shall be had to the number of votes to which each member is entitled by their shares or by these Articles.

84. 76. Any person entitled under Article 4648 to transfer any shares may vote at any general meeting in respect thereof in the same manner as if such person were the registered holder of such shares so long as the person, at least forty-eight hours before the time of holding the meeting or adjourned meeting at which the person proposes to vote, satisfies the Directors that such person has the right to transfer such shares.

85. 77. Where there are joint registered holders of any share, any one of such persons may vote such share at any meeting, either personally or by proxy, as if such person were solely entitled to it. If more than one of such joint holders is present and voting in person at any meeting, personally or by proxy, the one whose name stands first on the registerRegister in respect of such share shall alone be entitled to vote it. Several executors or administrators of a deceased member in whose name any share stands shall for the purpose of this Article be deemed joint holders thereof.

86. 78. Votes may be cast either personally or by proxy or, in the case of a corporationbody corporate, by a representative duly authorized under the Act.

87. 79. A member of unsound mind in respect of whom an order has been made by any court having jurisdiction may vote by such member’s guardian or other person in the nature of a guardian appointed by that court and any such guardian or other person may vote by proxy.

88. 80. Subject to the Act, no member shall be entitled to be present or to vote on any question, either personally or by proxy or as proxy for another member, at any meeting or be recognized for the purposes of a quorum while any call or other sum is due and payable to the Company in respect of any of the shares of such member.

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Proxies

89. 81. A proxy shall be in writing and executed in the manner provided in the Act. A proxy or other authority of a corporate shareholder does not require its seal. The provisions of the Act, and the regulations made thereunder, relating to proxies shall otherwise apply to the Company.

90. 82. No instrument appointing a proxy shall be valid after the expiration of twelve months from the date of its execution. The chair of any meeting of shareholders may, but need not, at his or her sole discretion, make determinations as to the acceptability of proxies deposited for use at the meeting, including the acceptability of proxies which may not strictly comply with the requirements of these Articles as to form, execution, accompanying documentation or otherwise, and any such determination made in good faith shall be final and conclusive. A proxy and the power of attorney or other authority, if any, under which it is signed or a notarially certified copy of that power or authority shall be deposited at the Office of the Company or at such other place as the Directors may direct. The Directors may, by resolution, fix a time not exceeding 48 hours excluding Saturdays and holidays preceding any meeting or adjourned meeting before which time proxies to be used at that meeting must be deposited with the Company at its Office or with an agent of the Company. Notice of the requirement for depositing proxies shall be given in the notice calling the meeting. The chair of the meeting shall determine all questions as to validity of proxies and other instruments of authority. No instrument appointing a proxy shall be valid after the expiration of twelve months from the date of its execution. Notwithstanding any specified time limits for the deposit of proxies by shareholders, the chair of any meeting or the Chair of the Board may, but need not, at his, her or their sole discretion, waive the time limits for the deposit of proxies by shareholders, including any deadline set out in the notice calling the meeting of shareholders or in any proxy circular and any such waiver made in good faith shall be final and conclusive.

91. 83. A vote given in accordance with the terms of an instrument of proxy shall be valid notwithstanding the previous death of the principal, the revocation of the proxy, or the transfer of the share in respect of which the vote is given, provided no intimation in writing of the death, revocation or transfer is received at the officeOffice of the Company before the meeting or by the chair of the meeting before the vote is given.

92. Subject to Articles 90 and 94, every proxy may be revoked by an instrument in writing that is received: (a) at the Office at any time up to and including the last business day before the day set for holding of the meeting at which the proxy is to be used; or (b) by the chair of the meeting, at the meeting, before any vote in respect of which the proxy is to be used shall have been taken.

93. An instrument referred to in Article 89 must be signed as follows: (a) if the shareholder for whom the proxy holder is appointed is an individual, the instrument must be signed by the shareholder or his or her legal personal representative; (b) if the shareholder for whom the proxy holder is appointed is a body corporate, the instrument must be signed by the body corporate or by a representative appointed for the body corporate.

94. 84. Every instrument of proxy, whether for a specified meeting or otherwise, shall be in such form as the Directors may from time to time determine and as required by law. Unless otherwise determined by the board in its sole discretion, no shareholder will be provided with access to any proxy materials relating to a meeting of shareholders prior to such meeting taking place. Upon the request of a shareholder not earlier than one day following a meeting of shareholders, the Company shall provide such shareholder with access to the proxies deposited with the Company in connection with such meeting.

Resolutions in Writing

95. 85. A resolution, including a special resolution, in writing and signed by every shareholder who would be entitled to vote on the resolution at a meeting is as valid as if it were passed by such shareholders at a meeting and satisfied all the requirements of the Act and these Articles respecting meetings of shareholders. A Resolution so passed shall be deemed to constitute a waiver of all notices required to have been given for that meeting. The signature of a member whoshareholder which is a body corporate shall be evidenced by the signature of an Officerofficer or Officersofficers, Directordirector or Directordirectors of such body corporate, or other person or persons authorized by the body corporate.

Directors

96. 86. Unless otherwise determined by general meeting, the number of Directors shall be determined by the Board of Directors but shall not be less than eight nor shall they be more than fifteen provided however that the number of the members of the Board of Directors of the Company who are employees of the Company or of a subsidiary or affiliate of the Company shall not exceed two. No director may appoint any other person to act as his or her alternate to attend or vote at meetings of directors or otherwise act as a director in his or her absence.

97. 87. The Directors shall have power to increase the number of Directors on the Board at any time and from time to time to appoint any one or more other personpersons as a DirectorDirectors so long as the total number of Directors does not at any time exceed the maximum number permitted. in Article 96. No such appointment shall be effective unless two-thirds of the Directors concur in it.

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98. 88. The Directors shall be paid out of the funds of the Company as remuneration for their service such sums, if any, as the Board may from time to time determine and such remuneration shall be divided among them in such proportions and in such manner as the Directors determine. Any remuneration so payable to a Director who is also an officer or employee of the Company or who is counsel or solicitor to the Company or otherwise serves it in a professional capacity may be in addition to the Director’s salary as an officer or professional fees as the case may be. In addition, the Board may by resolution from time to time award special remuneration out of the funds of the Company to any Director who performs or undertakes any special work or service for, or on behalf of, the Company outside the work or services ordinarily required of a Director of the Company. The Directors shall also be reimbursed for their out of pocket expenses incurred in attending Board, Committee or Shareholders’ meetings or otherwise in respect of the performance by them of their duties as the Board may from time to time determine. Notwithstanding Article 92,102, the Directors shall not be required to declare their interest in nor shall the Directors be prohibited from voting in respect of the determination of their remuneration in accordance with this Article.

99. 89. The continuing Directors may act notwithstanding any vacancy in their body, but if the number of Directors fallfalls below the minimum permitted under these Articles, the Directors shall not, except in emergencies or for the purpose of filling up vacancies, act so long as the number is below the minimum. If the number of Directors falls below the quorum requirement under these Articles, nominees shall be proposed by the Nominating Committeecontinuing Directors, or any committee established by them for the purpose, for election at a meeting of shareholders of the Company and called pursuant to the Companies Act.

100. 90. A Director may, in conjunction with the office of Director, and on such terms as to remuneration and otherwise as the Directors arrange or determine, hold any other office or position in the Company or in any companybody corporate in which thisthe Company is a shareholder or is otherwise interested.

101. 91. The office of a Director shall ipso facto be vacated:

(a) if such Director becomes bankrupt or makes an assignment or is petitioned in Bankrupcyfor the benefit of creditors; or

(b) if such Director is found by a court of competent jurisdiction to be mentally incompetent or of unsound mind; or

(c) if by notice in writing to the Company such Director resigns the office of Director; or

(d) if such Director is removed by special resolution of the Company or as otherwise provided by law.

Directors’ Interest in Contracts

102. 92. No Director shall be disqualified from contracting with the Company, either as vendor, purchaser, or otherwise, nor shall any such contract, or any contract or arrangement entered into or proposed to be entered into by or on behalf of the Company in which any Director is in any way interested, either directly or indirectly, be avoided, nor shall any Director so contracting or being so interested be liable to account to the Company for any profit realized by any such contract or arrangement by reason only of such Director holding office as a Director of the Company or of the fiduciary relation thereby established. However, the existence and nature of the Director’s interest must be declared by such Director at a meeting of the Directors of the Company unless the contract, arrangement or transaction is one involving the fixing of remuneration payable to the Directors in their capacitycapacities as Directors (herein referred to as an “Excluded Transaction”). In the case of a proposed contract or transaction, other than an Excluded Transaction, any Director with an interest in the contract or transaction shall declare the interest of such Director at the meeting of Directors at which the matter is first taken into consideration, or if the Director was not then interested, at the next meeting held after the Director became so interested. A general notice given to the Directors by a Director that the Director is a member, shareholder or directorDirector of any specified firm or company and is to be regarded as interested in any transaction or contract with such firm or company shall be deemed to be a sufficient declaration under this Article and no further or other notice shall be required. No Director shall as a Director vote in respect of any contract or arrangement in which the Director is so interested, and if the Director does so vote, the vote shall not be counted. This prohibition may at any time or times be suspended or relaxed to any extent by a general meeting and shall not apply to any Excluded Transaction or any contract or arrangement by or on behalf of the Company to give to the Directors or any of them any remuneration payable to the Directors as such, any security for advances or by way of indemnity.

Election Of Directors

103. 93. Subject to the next following Article, at the dissolution of every annual ordinary general meeting all the Directors shall retire from office and be succeeded by the Directors elected at such meeting. Retiring Directors shall be eligible for re-election at such meeting.

104. 94. If at any ordinaryannual general meeting at which an election of Directors ought to take place no such election takes place, or if no ordinaryannual general meeting is held in any year or period of years, the retiring Directors shall continue in office until their successors are elected and a general meeting for that purpose may on notice be held at any time.

105. The Directors, or a committee established by them for the purpose, may nominate, and provide to the annual general meeting, nominees to be elected or re-elected as Directors. The Directors or any such committee shall nominate individuals who, in the reasonable opinion of the Directors or such committee, shall have the ability to contribute to the broad range of issues with which the Directors must deal and who are able to devote the time necessary to prepare for and attend meetings of the Board and committees of the Board to which they may be appointed.

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106. 95. The Company in general meeting may from time to time increase or reduce the number of Directors and may determine or alter their qualification.

107. 96. The Company may, by special resolution or in any other manner permitted by law, remove any Director before the expiration of thetheir period of office and appoint another person in their stead. The person so appointed shall hold office during such time only as the Director in whose place the person is appointed would have held office if the Director had not been removed.

108. 97. If at any time, a vacancy occurs on the Board as a result of a Director ceasing to be a Director, the Board of Directors shall fill such vacancy, after receiving a recommendation from the nominating committee (if any has been established), by the appointment as a Director of an individual who meets the requirements of Article 123.105.

Chair of The Board

109. 98. At the first meeting of the Directors of the Company following each general election of Directors by the Shareholders of the Company at an annual general meeting of Shareholders, the Directors shall appoint a Chair of the Board from their number who provided that such Chair is not an employee of the Company or of any subsidiary or affiliate of the Company. The Chair of the Board shall perform such duties and receive such special remuneration as the Board may from time to time provide. At any meeting of Directors and at any meeting of shareholders, the Chair of the Board shall not have a casting vote in the event of an equality of votes.

President, Vice President and Vice PresidentOther Officers

99.

110. (a) The Directors shall elect from their number the President of the Company and may determine the period for which he or she is to hold office. The President shall be the Chief Executive Officer of the Company and shall have general supervision of the business of the Company and shall perform such duties as may be assigned to him or her from time to time by the Board.

111. (b) The Directors may also appoint Vice-Presidents and determine the periodperiods for which they are to hold office. A Vice-President need not be a Director and any Vice- President shall, at the request of the President or the Board and subject to the directions of the Board, perform the duties of the President during the absence, illness or incapacity of the President.

112. The Directors may appoint such other officer or officers of the Company, having such powers and duties, as they see fit.

113. If the Directors so decide, the same person may hold more than one of the offices provided for in these Articles.

Proceedings of Directors

114. 100. The Directors may meet together for the dispatch of business, and adjourn and otherwise regulate their meetings and proceedings as they think fit, provided that no business shall be transacted unless there is a quorum. A quorum for a meeting of the Board of Directors shall be a majority of the Directors in office at the commencement of the meeting.

115. 101. Meetings of Directors may be held either within or without the Province of Nova Scotia and the Directors may from time to time make arrangements relating to the time and place of holding Directors’ meetings, the notices to be given for such meetings and what meetings may be held without notice. Unless otherwise provided by such arrangements:

(1) A meeting of Directors may be held at the close of every ordinaryannual general meeting of the Company without notice.

(2) Notice of every other Directors’ meeting may be in writing and delivered by personal delivery, telex or facsimile transmission or electronic mail, or mailed, or may be given by telephone to each Director before the meeting is to take place. Such notice shall be delivered, transmitted, mailed or given by telephone at least forty-eight hours before the time fixed for the meeting.

(3) A meeting of Directors may be held without formal notice if all the Directors are present or if those absent have signified their assent to such meeting or their consent to the business transacted at such meeting.

(4) The accidental omission to give any such notice to any of the Directors or the failure of any directorDirector to receive such notice shall not invalidate any resolution passed at any such meeting.

116. 102. A Director may participate in meetings of the Board and in meetings of a Committee of the Board by means of such telephone or other communications facilities as permit all persons participating in such a meeting to hear each other and a Director participating by such means will be considereda telephonic, electronic or other communication facility that permits all participants to communicate adequately with each other during the meeting. For the avoidance of doubt, a meeting of the Board or of a committee of the Board may be held entirely by means of a telephonic, electronic or other communication facility. A director participating in a meeting by such means shall be deemed to be present at thethat meeting.

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117. 103. The President or any other Director may at any time, and the Secretary, upon the request of the President or any other Director, shall summon a meeting of the Directors to be held at the Registered Office of the Company. The Chair of the Board or a majority of the Board may at any time summon a meeting to be held elsewhere.

118. 104. Questions arising at any meeting of Directors shall be decided by a majority of votes and when, on any motion before the Board, there is an equality of votes, the motion shall fail.

119. 105. If no Chair of the Board is elected, or if at any meeting of Directors the Chair is not present within fifteen minutes after the time appointed for holding the meeting, or declines to take the chair, the President shall preside. If neither the Chair nor the President is present at such time and willing to take the chair, the Directors present shall choose some one of their number to chair the meeting.

120. 106. A meeting of the Directors at which a quorum is present shall be competent to exercise all or any of the authorities, powers and discretions for the time being vested in or exercisable by the Directors generally.

121. Any Director participating in a meeting by a telephonic, electronic or other communication facility may vote by any reasonable means (including verbal assent) given the nature of such telephonic, electronic or other communication facility.

122. A resolution in writing signed by all the Directors who would be entitled to vote thereon at a meeting of Directors shall be as valid and effectual as if it had been passed at a meeting of the Directors duly called and constituted. A resolution so effected shall be deemed to constitute a waiver of any notice required under these Articles or the Act to have been given for such a meeting.

Committees

123. 107. The Directors may delegate any of their powers to committees consisting of such number of members of their body as they think fit establish from time to time such committees, including without limitation, an Executive Committee, an Audit Committee, a Nominating and Corporate Governance Committee, and a Management Resources and Compensation Committee, as the Directors think fit and entrust to and confer upon any such committee established such powers exercisable under these Articles by the Directors as they think fit, and may confer such powers for such time, and to be exercised for such objects and purposes and upon such terms and conditions, and with such restrictions as they think expedient; and they may confer such powers either collaterally with, or to the exclusion of, and in substitution for, all or any of the powers of the Directors in that behalf; and may from time to time revoke, withdraw, alter or vary all or any of such powers. Any committee so formed shall in the exercise of the powers so delegatedentrusted upon them conform to any rules or regulations that may be imposed on them by the Directors or by these Articles. At least a majority of members of any committee of Directors appointed by the Board shall be Directors who are not employees of the Company or of any subsidiary or affiliate of the Company.

124. The Directors, when establishing any committee, shall determine the membership thereof, which membership may include persons who hold a particular office or other position with the Company, if a director, from time to time. Members of committees shall have such terms of office as the Directors may establish or may serve at pleasure. The Directors may at any time and from time to time change the membership of any committee.

125. At least a majority of members of any committee of Directors appointed by the Board shall be Directors who are not employees of the Company or of any subsidiary or affiliate of the Company. For greater certainty, unless expressly otherwise provided the provisions of this Article apply to committees named in these Articles.

126. 108. The meetings and proceedings of any such committee consisting of two or more membersDirectors shall be governed by the provisions contained in these Articles for regulating the meetings and proceedings of the Directors, including notice and quorum, insofar as they are applicable and are not superseded by any rules or regulations made by the Directors. The Directors may make any rules or regulations which they see fit to govern meetings and proceedings of any committee and shall not be limited by the provisions of these Articles.

127. 109. All acts done at any meeting of the Directors or of a committee of Directors or by any person acting as a Director shall, notwithstanding that it is afterwards discovered that there was some defect in the appointment of the Directors or persons so acting, or that they or any of them were disqualified, be as valid as if every such person had been duly appointed and was qualified to be a Director.

128. 110. A resolution in writing signed by all the Directorsmembers of any committee established hereunder shall be as valid and effectual as if it had been passed at a meeting of the Directorssuch committee duly called and constituted. A Resolution so effected shall be deemed to constitute a waiver of any notice required under these Articles or the Act to have been given for such a meeting.

111. The Board may establish an Executive Committee of not less than five Directors made up as follows:

(a) The chief executive officer of the Company, or, if no officer of the Company is designated as chief executive officer, the most senior executive officer of the Company as determined by the Directors; and

(b) The balance being Directors who are not employees of the Company or of a subsidiary or affiliate of the Company.

The Executive Committee shall generally perform such duties and exercise such powers as may be directed or delegated to such committee by the Board.

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112. At least three members of the Executive Committee shall be present at all meetings to constitute a quorum for the transaction of business.

113. Any member of the Executive Committee may be removed or replaced at any time by the Board and shall at any time cease to be a member of the Executive Committee upon ceasing to be a Director. Subject to the foregoing, each member of the Executive Committee shall hold office as such until the next annual meeting of shareholders after the member’s appointment to the committee.

114. The Executive Committee shall choose one of its own members to be its Chair and the Secretary of the Company shall be the Secretary of the Executive Committee.

115. The times of and places where meetings of the Executive Committee shall be held and the calling of and procedure at such meetings, shall be determined from time to time by the Executive Committee.

116. The Directors may from time to time entrust to and confer upon the Executive Committee such powers exercisable under these Articles by the Directors as they think fit, and may confer such powers for such time, and to be exercised for such objects and purposes and upon such terms and conditions, and with such restrictions as they think expedient; and they may confer such powers either collaterally with, or to the exclusion of, and in substitution for, all or any of the powers of the Directors in that behalf; and may from time to time revoke, withdraw, alter or vary all or any of such powers.

117. The Executive Committee shall keep regular minutes of its proceedings and report to the Board as required.

Audit Committee

118. (a) The Board shall appoint annually from among its members a committee to be known as the Audit Committee to be composed of not less than three directors, none of whom shall be employees of the Company or of any subsidiary or affiliate of the Company. Two members of the audit committee shall constitute a quorum.

        (b) Any member of the Audit Committee may be removed or replaced at any time by the Board and shall at any time cease to be a member of the Audit Committee upon ceasing to be a director. Subject to the foregoing, each member of the Audit Committee shall hold office as such until the next annual meeting of shareholders after the member’s appointment to the Committee.

119. The Audit Committee shall:

129. Subject to rules and regulations established by the Directors from time to time with respect to such committee or applying to committees generally:

(a) review the financial statements of the Company before the financial statements are approved by the Directors;Any committee shall choose one of its own members to be its Chair and the secretary.

(b) ensure that appropriate internal control procedures are in place;The times of and places where meetings of the committee shall be held and the calling of and procedure at such meetings, shall be determined from time to time by the committee.

(c) review such investments and transactions that could adversely affect the well- being of the Company as the auditor or any officer of the Company may bring to the attention of the committee;The committee shall keep regular minutes of its proceedings and report to the Board as required.

(d) meet with the auditor to discuss the financial statements and transactions referred to in this Article;

(e) meet with the chief internal auditor of the Company, or the officer or employee of the Company acting in a similar capacity, and with management of the Company, to discuss the effectiveness of the internal control procedures established for the Company; and

(f) generally perform such other duties and exercise such powers as may be directed or delegated to such committee by the Board.

130. 120. The members of theany Audit Committee shall have the right for the purpose of performing their duties of inspecting all the books and records of the Company and its affiliates and of discussing such accounts and records and any matters relating to the financial position of the Company with the officers and auditors of the Company and its affiliates.

121. The Audit Committee shall choose one of its own members to be its Chair and the Secretary of the Company shall be the Secretary of the Audit Committee.

122. (a) The times of and places where meetings of the Audit Committee shall be held and the calling of and procedure at such meetings shall be determined from time to time by the Audit Committee. The auditor of the Company shall be given notice of every meeting of the Audit Committee and shall be permitted to attend and be heard at the meeting on matters relating to the auditor’s duties as auditor.

        (b) The Audit Committee shall keep regular minutes of its proceedings and report to the Board as required.

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Nominating Committee

123. (a) The Board shall appoint annually from among its members, a Nominating Committee consisting of three Directors and each member of the Nominating Committee shall be neither an employee of the Company or of any subsidiary or affiliate of the Company nor the Chair of the Board.

        (b) Not later than sixty days prior to each annual meeting of shareholders of the Company, the Nominating Committee will provide the Company with a list of nominees for election as Directors to be included in the Company’s management proxy circular for that meeting.

        (c) The nominating committee will include in its list of nominees:

(i) The chief executive officer of the Company and may include one other senior executive of the Company as determined by the Nominating Committee; and

(ii) Individuals who in the reasonable opinion of the Nominating Committee:

(A) other than as expressly authorized by the preceding subparagraph (i), are not employees of the Company or of any subsidiary or affiliate of the Company;

(B) have not reached seventy (70) years of age, except as provided in (C) below;

(C) in certain exceptional circumstances, it may be appropriate for individuals to be able to serve on the Board beyond age 70 Should such circumstances occur, the Nominating and Corporate Governance Committee will determine and recommend that an individual be permitted to serve as a Director beyond age 70 because of the individual’s contribution and skills. Such determination will be made annually.

(D) A majority of the members of the Nominating Committee shall constitute a quorum.

(E) All of the nominees to be included in the Nominating Committee’s list of nominees referred to in Article 123(c) shall be individuals who, in the reasonable opinion of the Nominating Committee, shall have the ability to contribute to the broad range of issues with which the Directors must deal and who are able to devote the time necessary to prepare for and attend meetings of the Board and committees of the Board to which they may be appointed.

Management Resources And Compensation Committee

124. (a) The Board shall appoint annually from among its members a Management Resources and Compensation Committee composed of not less than three Directors to make recommendations from time to time to the Board of Directors with respect to the remuneration of senior management of the Company, any other matter with respect to senior management the Committee deems appropriate and such other matters as the Directors may decide. The Management Resources and Compensation Committee shall consist of Directors selected by the Board who are not employees of the Company or of any subsidiary or affiliate of the Company nor the Chair of the Board.

        (b) A majority of the members of the Management Resources and Compensation Committee shall constitute a quorum.

Registers

131. 125. The Directors shall cause to be kept a register of the shareholders of the Companyat the Office or as may otherwise be permitted in accordance with the Act, the Register, a register of holders of bonds, debentures and securities of the Company and a register of its Directors and may cause to be kept branch registers, including branch registers of the shareholders and holders of bonds, debentures and securities, either within or without the Province of Nova Scotia in accordance with the Act. The Directors may appoint one or more transfer agents to maintain the central registerRegister, and any other registers and branch registers of shareholders and holders of bonds, debentures and securities of the Company at any place within Canada.

132. 126. The Directors shall:

        (a) ensure that the Register and all other registers required by these Articles to be prepared and maintained are in a bound or loose-leaf form or in a photographic film form or entered or recorded by any system of mechanical or electronic data processing or other information storage device that is capable of reproducing in Nova Scotia any required information in intelligible written form within a reasonable time and, where applicable, conforms to the provisions of the Act; and

        (b) cause the Company or its transfer agent to maintain within Nova Scotia an office or other facility at which the transfer of shares, bonds, debentures and securities of the Company may be effected.

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Minutes

133. 127. The Directors shall cause minutes to be entered in books designated for the purpose:

        (a) of all appointments of officers;

        (b) of the names of the Directors present at each meeting of Directors and of any committees of Directors;

        (c) of all orders made by the Directors and committees of Directors;

        (d) of all resolutions and proceedings of meetings of the Shareholders and of the Directors.

134. 128. Any such minutes of any meeting of the Directors or of any committee of the Directors or of the Company, if purporting to be signed by the chair of such meeting or by the chair of the next succeeding meeting, shall be receivable as prima facie evidence of the matters stated in such minutes. The Directors shall cause the books containing the minutes of proceedings of any general meeting of the Company to be kept at the Company’s Office or at such other place or places as designated by the Directors as permitted by the Act.

135. 129. Any resolution of the Shareholders, the Directors, or a committee of the Directors, passed pursuant to the provisions of Articles 8595, 122 or 110 of these Articles,128, shall be receivable as prima facie evidence of the matters stated therein.

Power of Directors

136. 130. The management of the business of the Company shall be vested in the Directors who, in addition to the powers and authorities by these Articles or otherwise expressly conferred upon them, may exercise all such powers and do all such acts and things as may be exercised or done by the Company and are not hereby or by statute expressly directed or required to be exercised or done by the Company in general meeting, but subject nevertheless to the provisions of the statutesany statute in that behalf and of the Memorandum and these Articles and to any regulations from time to time made by the Company in general meeting; provided that no regulation so made or modification of the Memorandum or these Articles shall invalidate any prior act of the Directors that would have been valid if such regulation or modification had not been made.

137. 131. Without restricting the generality of the terms of the last preceding Article and without prejudice to the powers conferred thereby, and the other powers conferred by these Articles, the Directors shall have power:

        (a) (1) To take such steps as they think fit to carry out any agreement or contract made by or on behalf of the Company;

        (b) (2) To pay the costs, charges and expenses preliminary and incidental to the promotion, formation, establishment, and registration of the Company;

        (c) (3) To purchase or otherwise acquire for the Company any property, rights or privileges, stocks, bonds, debentures, or other securities (including shares in the capital stock of any other companybody corporate) that the Company is authorized to acquire, and at such price and generally on such terms and conditions as they think fit;

        (d) (4) At their discretion to pay for any property, rights, or privileges, stocks, bonds, debentures, or other securities (including shares in the capital stock of any other company) acquired by, or services rendered to the Company either wholly or partially in cash or in shares (fully paid up or otherwise), bonds, debentures or other securities of the Company, and any such shares may be issued either as fully paid up, or with such amount credited as paid up thereon as may be agreed upon;

        (e) (5) To secure the fulfilment of any contracts or engagements entered into by the Company by mortgaging or charging all or any of the property of the Company and its unpaid capital for the time being, or in such other manner as they think fit;

        (f) (6) To appoint, remove or suspend at their discretion such experts, managers, secretaries, treasurers, officers, clerks, agents and servants for permanent, temporary or special services, as they from time to time think fit, and to determine their powers and duties, and fix their salaries or emoluments and to require security in such instances and to such amounts as they think fit;

        (g) (7) To accept from any member insofar as the law permits and on such terms and conditions as may be agreed upon a surrender of the member’s shareshares or any part thereofof them;

        (h) (8) To appoint any person or persons (whether incorporated or not) to accept and hold in trust for the Company any property belonging to the Company, or in which it is interested, to execute and do all such deeds and things as may be requisite in relation to any such trust, and to provide for the remuneration of any such trustee or trustees;

        (i) (9) To institute, conduct, defend, compound or abandon any legal proceedings by and against the Company, its Directors or its officers or otherwise concerning the affairs of the Company, and also to compound and allow time for payment or satisfaction of any debts due and of any claims or demands by or against the Company;

        (j) (10) To refer any claims or demands by or against the Company to arbitration and observe and perform the awardsaward;

        (k) (11) To make and give receipts, releases and other discharges for moneyamounts payable to the Company and for claims and demands of the Company;

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(l) (12) To determine who shall be entitled to exercise the borrowing powers of the Company and sign on the Company’s behalf bonds, debentures or other securities, bills, notes, receipts, acceptances, assignments, transfers, hypothecations, pledges, endorsements, cheques, drafts, releases, contracts, agreements and all other instruments and documents;

(m) (13) To provide from time to time for the management of the affairs of the Company abroad in such manner as they think fit, and in particular to appoint any persons to be the attorneys or agents of the Company with such powers (including power to sub-delegate) and upon such terms as may be thought fit;

(n) (14) To invest and deal with any of the moneysfunds of the Company not immediately required for the purposes thereof in such securities and in such manner as they think fit; and from time to time to vary or realize such investments;

(o) (15) To execute in the name and on behalf of the Company in favour of any Director or other person who may incur or be about to incur any personal liability for the benefit of the Company such mortgages of the Company’s property, present and future, as they think fit, and any such mortgages may contain a power of sale and such other powers, covenants and provisions as are agreed on;

(p) (16) To give any officer or other person employed byemployee of the Company a commission on the profits of any particular business or transaction or a share in the general profits of the Company, and such commission or share of profits shall be treated as part of the working expenses of the Company;

(q) (17) To set aside out of the profits of the Company before declaring any dividend such sumsamounts as they think proper as a reserve fund to meet contingencies or provide for dividends, depreciation, repairing, improving and maintaining any of the property of the Company and such other purposes as the Directors may in their absolute discretion think conducive to the interests of the Company; and to invest the several sumsamounts set aside in such investments, other than shares of the Company, as they may think fit, and from time to time to deal with and vary such investments, and to dispose of all or any part of them for the benefit of the Company, and to divide the reserve fund into such special funds as they think fit, with full power to employ the assets constituting the reserve fund in the business of the Company without being bound to keep them separate from the other assets;

(r) (18) From time to time to make, vary and repeal rules for the regulation ofand regulations respecting the business of the Company, its officers and servantsemployees, the members of the Company or any section or class of them, and respecting any other matters contemplated by these Articles;

(s) (19) To enter into all such negotiations and contracts, rescind and vary all such contracts, and execute and do all such acts, deeds, and things in the name and on behalf of the Company as they may consider expedient for or in relation to any of the matters aforesaid or otherwise for the purposes of the Company;

(t) (20) From time to time to provide for the management of the affairs of the Company in such manner as they shall think fit;

(u) (21) Subject to the Act and the Company’s Memorandum of Association, to sell, lease or otherwise dispose of any property, real or personal, undertaking, franchises, business, assets, interests or effects which the Company is authorized to sell, lease or otherwise dispose of, for such price or consideration and generally and on such terms and conditions as the directorsDirectors may think fit, and in particular but without limitation for shares, debentures or other securities of any companybody corporate having objects altogether or in part similar to those of this Company;

(v) (22) To delegate any of the duties of the boardBoard to any standing or special committee, or to any manager or any other officer, attorney or agent, and to appoint any person to be the attorney or agent of the Company, with such powers, including the power to sub-delegate and upon such terms as they think fit.

Solicitors

138. 132. The Company may employ or retain a solicitor or solicitors and such solicitor may, at the request of the Board of Directors or on instructions of the Chair of the Board, or the President, attend meetings of the Directors or Shareholders, whether or not the solicitor is a member or a Director of the Company. If such solicitor is also a Director, the solicitor may nevertheless charge for services rendered to the Company as a solicitor.

Secretary

139. 133. The Directors shall appoint a Secretary of the Company to keep the minutes of the shareholders’ and Directors’ meetings and perform such other duties as may be assigned to the Secretary by the Board. The Directors may also appoint a temporary substitute for the Secretary who shall, for the purposes of these Articles, be deemed to be the Secretary.

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The Seal

140.

(a) 134. The Common Seal may be affixed to any instrument (i) in the presence of and contemporaneously with the attesting signatures of two persons who are officers and/or directorsDirectors of the Company, or (ii) in the presence of and contemporaneously with the attesting signature of any one personor more persons designated by and under the authority of a resolution of the Board of Directors or of a committee thereof. If the Company has only one Director and Officer the common sealCommon Seal may be affixed in the presence of and contemporaneously with the attesting signature of that Director and Officer. For the purpose of certifying documents or proceedings of the Company the Common Seal may be affixed by any one of the President, a Vice-President, the Secretary, an assistant secretary, any other officer of the Company or a Director.

(b) 135. (a) The Company may have facsimiles of the Common Seal which may be used interchangeably with the Common Seal.

(c) (b) The Company may have for use at any place outside Nova Scotia as to all matters to which the corporate existence and capacity of the Company extends an official seal that is a facsimile of the Common Seal of the Company with the addition on its face of the name of the place where it is to be used; and the Company may by writing under the seal of its Common Seal authorize any person to affix such official seal to any document at such place to which the Company is a party, and may prescribe and limit the type of documents to which the official seal may be affixed by such person.

Dividends

141. 136. The Directors may from time to time declare such dividend as they deem proper upon the shares of the Company according to the rights of the members and the respective classes thereof, and may determine the date upon which such dividend will be payable and that it will be payable to the persons registered as the holders of such shares at the close of business upon the record date determined in accordance with Article 51. No transfer of such shares made or registered after the record date so specified shall pass any right to the dividend so declared.

142. 137. The Company may declare or pay aan otherwise lawful dividend unless there are reasonable grounds for believing that:

(a) The Company is, or would after the payment be, unable to pay its liabilities as they become due; or

(b) The realizable value of the Company’s assets would thereby be less than the aggregate of its liabilities and stated capital of all classes.

138. , including without limitation from profits, retained earnings or other surplus account. The Directors may from time to time pay to the members such interim dividends as in their judgment the position of the Company justifies.

143. 139. The Directors may deduct from the dividends payable to any member all such sums of moneyamounts as may be due and payable by the member to the Company on account of calls, instalments or otherwise, and may apply the same in or towards satisfaction of such sums of moneyamounts so due and payable.

144. 140. The Directors may retain any dividends on which the Company has a lien, and may apply the same in or towards satisfaction of the debts, liabilities or engagements in respect of which the lien exists.

145. 141. The Directors may retain the dividends payable upon shares in respect of which any person is under Article 4648 entitled to become a member, or which any person under that clause is entitled to transfer, until such person has become a member in respect of or has duly transferred such shares.

146. 142. Any meeting declaring a dividend may make a call on the members for such amount as the meeting fixes so long as the call on each member does not exceed the dividend payable to him or her. The call shall be made payable at the same time as the dividend and the dividend may, if so arranged between the Company and the member, be set off against the call. The making of a call under this Article shall be deemed to be and be business of a meeting which declares such a dividend.

147. 143. Any meeting declaring a dividend may resolve that such dividend be paid wholly or in part by the distribution of specific assets, paid up shares, debentures, bonds or debenture stockother securities of the Company or paid up shares, debentures, bonds, or debenture stockother securities of any other Companybody corporate, or in any one or more of such ways.

148. 144.Any meeting may resolve that any moneyscash, investments or other assets forming part of the undivided profits of the Company standing to the credit of the reserve fund or in the hands of the Company and available for dividends or representing premiums received on the issue of shares and standing to the credit of share premium account, be capitalized and distributed to the shareholdersmembers who would be entitled to receive them if distributed by way of dividend and in the same proportions, that all or any part or such capitalized fund be applied on behalf of such shareholdersmembers in paying up in full, either at par or at such premium as the resolution may provide, any unissued shares or debentures or debenture stockother securities of the Company (which shall be distributed accordingly) or in or towards payment of the uncalled liability on any issued shares or debentures or debenture stockother securities, and that such distribution or payment shall be accepted by such shareholdersmembers in full satisfaction of their interest in such capitalized sum.

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149. 145. For the purpose of giving effect to any resolution under the two last preceding Articles, the Directors may settle any difficulty that may arise in regard to the distribution as they think expedient, and in particular may issue fractional certificates, may fix the value for distribution of any specific assets, may determine that cash payments will be made to any members upon the footing of the value so fixed or that fractions of less value than $5.00 may be disregarded in order to adjust the rights of all parties, and may vest any such cash or specific assets in trustees upon such trusts for the persons entitled to the dividend or capitalized fund as may seem expedient to the Directors.

150. 146. A transfer of shares shall not pass the right to any dividend declared thereon after such transfer and before the registration of the transfer.

151. 147. AnyoneAny one of several persons registered as the joint holder of any share may give effectual receipts for all dividends and payments on account of dividends in respect of such share.

152. 148. Unless otherwise determined by the Directors, any dividend may be paid by a cheque or warrant delivered to or sent through the postmail to the registered address of the member entitled, or, when there are joint holders, to the registered address of the one whose name stands first on the registerRegister for the shares jointly held. Every cheque or warrant so delivered or sent shall be made payable to the order of the person to whom it is delivered or sent.

153. 149. Notice of the declaration of any dividend, whether interim or otherwise, shall be given to the holders of registered shares in the manner hereinafter provided.

154. 150. All dividends unclaimed one year after having been declared may, until claimed, be invested or otherwise made use of by the Directors for the benefit of the Company.

Accounts

155. 151. The Directors shall cause proper books of account to be kept offor the business of the Company. The books of account shall be kept at the head office of the company or at such other place or places as the Directors may direct.

156. 152. The Directors shall from time to time determine whether and to what extent and at what times and places and under what conditions or regulations the accounts and books of the Company or any of them shall be open to inspection of the members, and no member shall have any right of inspecting any account or book or document of the Company except as conferred by statute or authorized by the Directors or a resolution of the Company in general meeting.

157. 153. At the ordinaryannual general meeting in every year the Directors shall lay before the Company the financial statements required by the Act, and the reportreports to the members of the auditor, if any, and, if the Company is a reporting issuer, the report of the Directors required by subsection 121(1) of the Act.

158. 154. The financial statements shall be approved by the Board and such approval shall be evidenced by the signatures on the balance sheet of two Directors or by the Director if there is only one.

159. 155. The Directors shall, not less than twenty-one (21) days before the date of the ordinaryannual general meeting or within such shorter period as is fixed from time to time by the Directors and complies with all applicable laws, send copies of the financial statements together with copies of the auditor’s report, if any, and the report of the Directors, if any, to all members holding voting securities or otherwise entitled to receive notices of general meetings of the Companymembers who have requested them and such persons as may be required to receive such financial statements and reports under the Act.

Auditors and Audit

160. 156. UnlessExcept in respect of a financial year for which the Company is exempt from the requirements of the Act regarding the appointment and duties of an auditor, an auditor shall be appointed and the auditor’s duties regulated in accordance with the Act. The Company may appoint as auditor any person, including a shareholder, not disqualified by the Act or other law. An auditor may be removed or replaced in the circumstances and in the manner specified in the Act. The Directors may fill any casual vacancy in the office of the auditor but while any such vacancy continues the surviving or continuing auditor or auditors, if any, may act.

161. 157. The auditors shall conduct such audit as may be required by the Act and their report, if any, shall be dealt with by the Company as required by the Act. Every account of the directorsDirectors, when audited and approved by a general meeting as required by the Act shall be conclusive, except as regards an error discovered therein within three months next after the approval thereof. Whenever any such error is discovered within the period, the account shall forthwith be corrected, and thenceforth shall be conclusive.

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Notices

162. 158. A notice may be(including any communication or document) shall be sufficiently given, delivered or served by the Company upon members personally or by sending it through the post in a prepaid envelope or wrapper addressed to such member at the member’s registered place ofa shareholder, Director, officer or auditor by personal delivery at such person’s registered address (or, in the case of a Director, officer or auditor, last known address) or by prepaid mail, telegraph, telex, facsimile machine or other electronic means of communication addressed to such person at such address.

163. 159. MembersShareholders who have no registered place of address shall not be entitled to receive any notice.

160. The holder of a share warrant shall not, unless otherwise expressed therein, be entitled in respect thereof to notice of any general meeting of the Company.

164. 161. Any notice required to be given by the Company to the membersshareholders, or any of them, and not expressly provided for by these Articles, shall be sufficiently given if given by advertisement.

165. 162. Any notice given by advertisement shall be advertised twice in a paper published in the place where the head office of the Company is situated, or if no paper is published there, then in any newspapersnewspaper published in the City of Halifax, Nova Scotia.

166. 163. All notices shall, with respect to any registered shares to which persons are jointly entitled, be given to whichever of such persons is named first in the registerRegister for such shares, and notice so given shall be sufficient notice to all the holders of such shares.

167. 164. Any notice sent by postmail shall be deemed to be given, delivered or served on the earlier of the day of actual receipt or the day following that upon which the letter, envelope or wrapper containing it is postedmailed, and in proving such service it shall be sufficient to prove that the letter, envelope or wrapper containing the notice was properly addressed and put into the post officemailed with the postage prepaid thereon. Any notice given by electronic means of communication shall be deemed to be given when entered into the appropriate transmitting device for transmission. A certificate in writing signed by any manager, secretary or other officialon behalf of the Company that the letter, envelope or wrapper containing the notice was so addressed and postedmailed shall be conclusive evidence thereof. The foregoing provisions of this clause shall not apply to a notice of a meeting of the Directors.

168. 165. Every person who by operation of law, transfer or other means whatsoever becomes entitled to any share shall be bound by every notice in respect of such share that prior to such person’s name and address being entered on the registerRegister was duly served in the manner hereinbefore provided upon the person from whom the person derived title to such share.

169. 166. Any notice or document so advertised or delivered, sent by post to or left ator otherwise transmitted to the registered address of any member in pursuance of thethese Articles, shall, notwithstanding that such member is then deceased and that the Company has notice of such death, be deemed to have been served in respect of any registered shares, whether held by such deceased member solely or jointly with other persons, until some other person is registered instead of such deceased member as the holder or joint holder thereof, and such service shall for all purposes of these Articles be deemed a sufficient service of such notice or document on the deceased member’s heirs, executors or administrators and all persons, if any, jointly interested with the deceased member in any such share.

170. 167. The signature to anyAny notice given by the Company may bemay bear the nameor signature, manual or reproduced, of the person giving the notice, written or printed.

171. 168. When a given number of days’ notice or notice extending over any other period is required to be given, the day of service and the day upon which such notice expires shall not, unless it is otherwise provided, be counted in such number of days or other period.

Indemnity

172.

(a) The Company shall indemnify each Director and officer, each former Director and officer and each other individual who acts or acted at the Company’s request as a Director or officer or in a similar capacity of an Other Entity and their respective heirs and legal representatives against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by any such person in respect of any civil, criminal, administrative, investigative, arbitration, mediation, or other proceeding or investigation to which he is made a party or involved in by reason of being or having been a Director or officer of the Company or such Other Entity at the request of the Company or in a similar capacity, provided that:

(i) the individual acted honestly and in good faith with a view to the best interests of the Company or, as the case may be, to the best interest of the Other Entity for which the individual acted as a Director or officer or in a similar capacity at the Company’s request; and

(ii) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, the individual had reasonable grounds to believe that his conduct was lawful.

(b) The Company shall, to the full extent permitted by law, advance funds to an individual referred to above for any costs, charges and expenses of a proceeding or investigation provided that such individual shall repay the funds advanced if the individual does not fulfill the conditions of indemnification set out in this Article.

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(c) The right of any person to indemnification granted hereunder is not exclusive of any other rights to which any person seeking indemnification may be entitled under any agreement, resolution or other vote of shareholders or Directors, at law or otherwise.

(d) 169. Every Director, Manager, Secretary and other officer or servant of the Company shall be indemnified by the Company against, and it shall be the duty of the Directors out of the funds of the Company to pay, all costs, losses and expenses that any such Director, Manager, Secretary or other officer or servant may incur or become liable to pay by reason of any contract entered into, or act or thing done by such person as such officer or servant or in any way in the discharge of such person’s duties including travelling expenses; and the amount for which suchThe amount for which any indemnity is proved shall immediately attach as a lien on the property of the Company and have priority as against the members over all other claims.

(e) For the purposes of this Article, the term “Other Entity” means any affiliate or subsidiary of the Company, and any other body corporate, corporation, limited liability company, partnership, joint venture, trust, unincorporated association, unincorporated organization, unincorporated syndicate or other enterprise in which the Company, directly or indirectly, now or in the future, holds an interest, whether in debt, equity or otherwise, for which the Director, officer or other individual serves or served as a Director or officer or in a capacity similar thereto at the request of the Company.

(f) The Company is authorized to enter into an agreement evidencing and setting out the terms and conditions of an indemnity in favour of any of the persons referred to in this Article.

173. 170. No Director or other officer of the Company shall, in the absence of any dishonesty on the part of such person, be liable for the acts, receipts, neglects or defaults of any other Director or officer, or for joining in any receipt or other act for conformity, or for any loss or expense happening to the Company through the insufficiency or deficiency of title to any property acquired by order of the Directors for or on behalf of the Company, or through the insufficiency or deficiency of any security in or upon which any of the moneysfunds of the Company are invested, or for any loss or damage arising from the bankruptcy, insolvency or tortious act of any person with whom any moneysfunds, securities or effects are deposited, or for any loss occasioned by error of judgment or oversight on the part of such person, or for any other loss, damage or misfortune whatsoever which happens in the execution of the duties of such person’s office or in relation thereto.

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Part B Ownership and Voting Restrictions

Interpretation

174. 171.

(a) In this Part “B”, all terms that are not defined have the meanings attributed to those terms in the Privatization Act and:

“directors’ determination” and similar expressions means a determination made by the directors of the Company in accordance with Article 182185;

“excess voting shares” means voting shares held, beneficially owned or controlled in contravention of the individual share constraint or the non-resident share constraint, as the case may be;

“individual share constraint” has the meaning set forth in Article 172175(a);

“non-resident share constraint” has the meaning set forth in Article 173176(a);

“non-resident voting constraint” has the meaning set forth in Article 174177;

“principal stock exchange” means, at any time, the stock exchange in Canada on which the highest volume of voting shares is generally traded at that time, as determined by the directors of the Company;

“sell-down notice” has the meaning set forth in Article 175178(a);

“shareholder default” has the meaning set forth in Article 175178(a)(iv);

“shareholder’s declaration” means a declaration made in accordance with Article 183186; and

“suspension” has the meaning set forth in Article 176179(a) and “suspend”, “suspended” and similar expressions have corresponding meanings.

(b) The provisions of subsections 8(3) and (8) of the Privatization Act are deemed to be incorporated in this Part “B”, with references therein to the “Company” deemed to be references to the Company. Any provision of this Part “B” that may be read in a manner that is inconsistent with the Privatization Act shall be read so as to be consistent therewith.

(c) For greater certainty, no person is presumed to be an associate of any other person for purposes of paragraph 8(5)(g) of the Privatization Act solely by reason that one of them has given the other the power to vote or direct the voting of voting shares of a class of voting shares at a meeting of the holders of that class pursuant to a revocable proxy where the proxy is solicited solely by means of an information circular issued in a public solicitation of proxies that is made in respect of all voting shares of that class and in accordance with applicable law.

(d) For the purposes of this Part “B”;

(i) where voting shares of the Company are held, beneficially owned or controlled by two or more persons jointly, the number of voting shares held, beneficially owned or controlled by each such person shall include the number of voting shares held, beneficially owned or controlled jointly with such other persons;

(ii) where one or more joint holders of, beneficial owners of or persons controlling voting shares is a non-resident, the voting shares are deemed to be held, beneficially owned or controlled, as the case may be, by such non-resident;

(iii) where a person who was not a non-resident becomes a non-resident on any day, the day of acquisition or registration in respect of the acquisition of the voting shares held, beneficially owned or controlled by such person shall be deemed to be the day that such person became a non-resident; and

(iv) references to shares “of” a person are to shares held, beneficially owned or controlled, directly or indirectly, otherwise than by way of security only, by that person.

(e) In this Part “B”, except where the context requires to the contrary, words importing the singular shall include the plural and vice versa and words importing gender shall include masculine, feminine and neuter genders.

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Individual Share Constraint

175. 172.

(a) No person, together with the associates of that person, shall hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, in the aggregate voting shares to which are attached more than 15 per cent of the votes that may ordinarily be cast to elect directors of the Company. (The foregoing prohibition is referred to in this Part “B” as the “individual share constraint”.)

(b) In the event that it appears from the register of members of the Company that any person, together with the associates of that person, is in contravention of the individual share constraint:

(i) the Company shall not accept any subscription for voting shares from that person or any associate of that person;

(ii) the Company shall not issue any voting shares to that person or any associate of that person; and

(iii) the Company shall not register or otherwise recognize the transfer of any voting shares to that person or any associate of that person.

(c) In the event of a directors’ determination that any person, together with the associates of that person, is in contravention of the individual share constraint:

(i) the Company shall not accept any subscription for voting shares from that person or any associate of that person;

(ii) the Company shall not Issue any voting shares to that person or any associate of that person;

(iii) the Company shall not register or otherwise recognize the transfer of any voting shares to that person or any associate of that person;

(iv) no person may, in person or by proxy, exercise the right to vote any of the voting shares of that person or of any associate of that person;

(v) subject to Article 181184(a), the Company shall not declare or pay any dividend, and or make any other distribution:

(A) on any of the excess voting shares of that person or of any associate of that person; or

(B) if the directors of the Company determine that the contravention of the individual ownership constraint was intentional and that it would not be inequitable to do so, on all of the voting shares of that person and of each associate of that person; and any entitlement to such dividend or other distribution shall be forfeited; and

(vi) the Company shall send a sell-down notice to the registered holder of the voting shares of that person and of each associate of that person.

(d) In the event that it appears from the register of members of the Company that, or in the event of a directors’ determination that, any person, together with the associates of that person, after any proposed subscription, issue or transfer of voting shares, would be in contravention of the individual share constraint, the Company shall not:

(i) accept the proposed subscription for voting shares from;

(ii) issue the proposed voting shares to; or

(iii) register or otherwise recognize the proposed transfer of any voting shares to; that person or any associate of that person.

(e) In the event of a directors’ determination that during any period any person, together with the associates of that person, was in contravention of the individual share constraint, the directors of the Company may also determine that:

(i) any votes cast, in person or by proxy, during that period in respect of the voting shares of that person or of any associate of that person shall be disqualified and deemed not to have been cast; and

(ii) subject to Article 181184(a), each of that person and the associates of that person is liable to the Company to restore to the Company the amount of any dividend paid or distribution received during that period on:

(A) the excess voting shares of that person and of each associate of that person; or

(B) if the directors of the Company determine that the contravention of the individual ownership constraint was intentional and that it would not be inequitable to do so, on all of the voting shares of that person and of each associate of that person.

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Non-Resident Share Constraint

176. 173.

(a) Non-residents shall not hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, in the aggregate voting shares to which are attached more than 25 per cent of the votes that may ordinarily be cast to elect directors of the Company. (The foregoing prohibition is referred to in this Part “B” as the “non-resident share constraint”.)

(b) In the event that it appears from the register of members of the Company that, or in the event of a directors’ determination that, there is a contravention of the non-resident share constraint:

(i) the Company shall make a public announcement, whether by press release, newspaper advertisements or otherwise, reasonably expected to inform the markets in which voting shares are traded of the contravention; and

(ii) the Company shall not:

(A) accept any subscription for voting shares from any non-resident;

(B) issue any voting shares to any non-resident; or

(C) register or otherwise recognize the transfer of any voting shares from any resident to any non-resident.

(c) In the event of a directors’ determination that there is a contravention of the non-resident share constraint and that to do so would be practicable and would not be unfairly prejudicial to, and would not unfairly disregard the interests of, persons holding, beneficially owning or controlling voting shares who are non-resident, the Company shall send a sell-down notice to the registered holders of such of those voting shares as shall be chosen on the basis of inverse order to the order of acquisition or registration of all non-residents, by lot or by such other method that is authorized by a directors’ determination.

(d) In the event that it appears from the register of members of the Company that, or in the event of a directors’ determination that, after any proposed subscription, issue or transfer of voting shares to a non-resident, there would be a contravention of the non-resident share constraint, the Company shall not:

(e)

(i)

(i) accept the proposed subscription for voting shares;

(ii) issue the proposed voting shares; or

(iii) register or otherwise recognize the proposed transfer.

Non-Resident Voting Constraint

177. 174. In the event of a directors’ determination that on any motion made at any meeting of shareholders of the Company more than 25 per cent of the votes cast, in person or by proxy, have been cast in respect of voting shares that are held, beneficially owned or controlled, directly or indirectly, by non-residents, all votes cast, in person or by proxy, in respect of such voting shares on that motion shall be proportionally adjusted so that such votes cast equal twenty-five percent of all votes cast. (The foregoing adjustment is referred to in this Part “B” as the “non-resident voting constraint”.)

Sell-Down Notice

178. 175.

(a) Any notice (a “sell-down notice”) required to be sent to a registered holder of voting shares pursuant to Article 172175(c)(vi) or Article 173176(c):

(i) shall specify in reasonable detail the nature of the contravention of the individual share constraint or the non-resident share constraint, as the case may be, the number of voting shares determined to be excess voting shares and the consequences of the contravention specified in Article 172175 or 173176, as the case may be;

(ii) shall request an initial or further shareholder’s declaration;

(iii) shall specify a date, which shall be not less than, in the case of a contravention of the individual share constraint, 45 days (or such shorter period as is fixed from time to time by the Directors and complies with all applicable laws), or, in the case of a contravention of the non-resident share constraint, 60 days (or such shorter period as is fixed from time to time by the Directors and complies with all applicable laws), after the date of the sell-down notice, by which the excess voting shares are to be sold or disposed of; and

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(iv) shall state that unless the registered holder either:

(A) sells or otherwise disposes of the excess voting shares by the date specified in the sell-down notice on a basis that does not result in any contravention of the individual share constraint or the non-resident share constraint and provides to the Company, in addition to the shareholder’s declaration requested pursuant to Article 175178(a)(ii), written evidence satisfactory to the Company of such sale or other disposition; or

(B) provides to the Company, in addition to the shareholder’s declaration requested pursuant to the Article 175178(a)(ii), written evidence satisfactory to the Company that no such sale or other disposition of excess voting shares is required;

such default (a “shareholder default”) shall result in the consequence of suspension pursuant to Article 176179 and may result in the consequence of sale in accordance with Article 177180 or redemption in accordance with Article 178,181, in each case without further notice to the registered holder, and shall specify in reasonable detail the nature and timing of those consequences.

(b) In the event that, following the sending of a sell-down notice, written evidence is submitted to the Company for purposes of Article 175178(a)(iv)(B), the Company shall assess the evidence as soon as is reasonably practicable and in any event shall give a second notice to the person submitting the evidence not later than 10 days after the receipt thereof stating whether the evidence has or has not satisfied the Company that no sale or other disposition of excess voting shares is required. If the evidence has so satisfied the Company, such sell-down notice shall be cancelled and such second notice shall so state. If the evidence has not so satisfied the Company, such second notice shall reiterate the statements required to be made in such sell-down notice pursuant to Articles. 175 178(a)(iii) and (iv). In either case, the 45 day or 60 day period, as the case may be,applicable periods referred to in Article 175178(a) (iii) shall be automatically extended to the end of the 10 day period referred to in this Article 175Article 178(b) if such 10 day period extends beyond such 45 day or 60 dayotherwise applicable period.

Suspension

179. 176.

(a) In the event of a shareholder default in respect of any registered holder of voting shares, then, without further notice to the registered holder:

(i) all of the voting shares of the registered holder shall be deemed to be struck from the register of members of the Company;

(ii) no person may, in person or by proxy, exercise the right to vote any of such voting shares;

(iii) subject to Article 181184(a), the Company shall not declare or pay any dividend, or make any other distribution, on any of such voting shares and any entitlement to such dividend or other distribution shall be forfeited;

(iv) the Company shall not send any form of proxy, information circular or financial statements of the Company or any other communication from the Company to any person in respect of such voting shares; and

(v) no person may exercise any other right or privilege ordinarily attached to such voting shares.

(All of the foregoing consequences of a shareholder default are referred to in this Part “B” as a “suspension”.) Notwithstanding the foregoing, a registered holder of suspended voting shares shall have the right to transfer such voting shares on any securities register of the Company on a basis that does not result in contravention of the individual share constraint or the non-resident share constraint.

(b) The Directors of the Company shall cancel any suspension of voting shares of a registered holder and reinstate the registered holder to the register of members of the Company for all purposes if they determine that, following the cancellation and reinstatement, none of such voting shares will be held, beneficially owned or controlled in contravention of the individual share constraint or the non-resident share constraint. For greater certainty, any such reinstatement shall permit, from and after the reinstatement, the exercise of all rights and privileges attached to the voting shares so reinstated but, subject to Article 181184(a), shall have no retroactive effect.

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Sale

180. 177.

(a) In the event of a shareholder default in respect of any registered holder of voting shares, the Company may elect by directors’ determination to sell, on behalf of the registered holder, the excess voting shares thereof, without further notice thereto, on the terms set forth in this Article 177180 and Article 179.182.

(b) The Company may sell any excess voting shares in accordance with this Article 177180:

(i) on the principal stock exchange; or

(ii) if there is no principal stock exchange, on such other stock exchange or organized market on which the voting shares are then listed or traded as the directors of the Company shall determine; or

(iii) if the voting shares are not then listed on any stock exchange or traded on any organized market, in such other manner as the directors of the Company shall determine.

(c) The net proceeds of sale of excess voting shares sold in accordance with this Article 177180 shall be the net proceeds after deduction of any commission, tax or other cost of sale.

(d) For all purposes of a sale of excess voting shares in accordance with this section, the Company is the agent and lawful attorney of the registered holder and the beneficial owner of the excess voting shares.

Redemption

181. 178.

(a) For the purposes of enforcing the ownership restrictions and constraints imposed pursuant to the foregoing articles and the Reorganization Act, in the event of a shareholder default in respect of any registered holder of voting shares and in the event that the Directors of the Company determine either that the Company has used reasonable efforts to sell excess voting shares in accordance with Article 177180 but that such sale is impracticable or that it is likely that such sale would have material adverse consequences to the Company or the holders of voting shares, the Company may, notwithstanding section 51 of the Companies Act, elect by directors’ determination, to redeem the excess voting shares thereof, without further notice thereto, on the terms set forth in this Article 178181 and Article 179.182.

(b) The redemption price paid the Company to redeem any excess voting shares in accordance with this Article 178181 shall be:

(i) the average of the closing prices per share of the voting shares on the principal stock exchange (or, if there is no principal stock exchange or if the requisite trading of voting shares has not occurred on the principal stock exchange, such other stock exchange or such other organized market on which such requisite trading has occurred as the directors of the Company shall determine) over the last 10 trading days on which at least one board lot of voting shares has traded on the principal stock exchange (or such other stock exchange or such other organized market) in the period ending on the trading day immediately preceding the redemption date; or

(ii) if the requisite trading of voting shares has not occurred on any stock exchange or other organized market, on such basis as the Directors of the Company shall determine.

Procedures Relating to Sale and Redemption

182. 179.

(a) In the event of any sale or redemption of excess voting shares in accordance with Article 177180 or Article 178,181, respectively, the Company shall deposit an amount equal to the amount of the net proceeds of sale or the redemption price, respectively, in a special account in any bank or trust company in Canada selected by it. The amount of the deposit, less the reasonable costs of administration of the special account, shall be payable to the registered holder of the excess voting shares sold or redeemed on presentation and surrender by the registered holder to that bank or trust company of the certificate or certificates, if any, representing the excess voting shares. Any interest earned on any amount so deposited shall accrue to the benefit of the Company.

(b) From and after any deposit made pursuant to Article 179182(a), the registered holder shall not be entitled to any of the remaining rights of a registered holder in respect of the excess voting shares sold or redeemed, other than the right to receive the funds so deposited on presentation and surrender of the certificate or certificates representing the excess voting shares sold or redeemed.

(c) If a part only of the voting shares represented by any certificate is sold or redeemed in accordance with Articles 177180 or 178,181, respectively, the Company shall, on presentation and surrender of such certificate and at the expense of the registered holder, and subject to any regulations made by the Directors, issue a new certificate representing the balance of the voting shares.

Emera Inc. — Management Information Circular 2016          97

(d) So soon as is reasonably practicable after, and, in any event, not later than 30 days (or such longer period as is fixed from time to time by the Directors and complies with all applicable laws) after, a deposit made pursuant to Article 179182(a), the Company shall send a notice to the registered holder of the excess voting shares sold or redeemed and the notice shall state:

(i) that a specified number of voting shares has been sold or redeemed, as the case maybe;

(ii) the amount of the net proceeds of sale or the redemption price, respectively;

(iii) the name and address of the bank or trust company at which the Company has made the deposit of the net proceeds of sale or the redemption price, respectively; and

(iv) all other relevant particular of the sale or redemption, respectively.

(e) For greater certainty, the Company may sell or redeem excess voting shares in accordance with Articles 177180 or 178181, respectively, despite the fact that the Company does not possess the certificate or certificates, if any, representing the excess voting shares at the time of the sale or redemption. If, in accordance with Article 177,180, the Company sells excess voting shares without possession of the certificate or certificates representing the excess voting shares, the Company shall, subject to any regulations made by the Directors, issue to the purchaser of such excess voting shares or its nominee a new certificate or certificates representing the excess voting shares sold. If, in accordance with Articles 177180 or 178,181, the Company sells or redeems excess voting shares without possession of the certificate or certificates representing the excess voting shares and, after the sale or redemption, a person establishes that it is a bona fide purchaser of the excess voting shares sold or redeemed, then, subject to applicable law:

(i) the excess voting shares held or beneficially owned by the bona fide purchaser are deemed to be, from the date of the sale or redemption by the Company, as the case may be, validly issued and outstanding voting shares in addition to the excess voting shares sold or redeemed; and

(ii) notwithstanding Article 179182(b), the Company is entitled to the deposit made pursuant to Article 179182(a) and, in the case of a sale in accordance with Article 177,180, shall add the amount of the deposit to the stated capital account for the class of voting shares issued.

Exceptions

183. 180.

(a) Notwithstanding Article 172175 or 173,176, neither the individual share constraint nor the non-resident share constraint applies in respect of voting shares of the Company that are held:

(i) (i) by one or more underwriters solely for the purpose of distributing the voting shares to the public; or

(ii) by any person who provides centralized facilities for the clearing of trades in securities and is acting in relation to trades in the voting shares solely as an intermediary in the payment of funds or the delivery of securities, or both.

(b) A person referred to in Article 180183(a)(ii) shall not exercise voting rights attached to the voting shares so held by that person.

Saving Provisions

184. 181.

(a) Notwithstanding any other provision of this Part “B”;

(i) (i) the Directors of the Company may determine to pay a dividend or to make any other distribution on voting shares that would otherwise be prohibited by any other provision of this Part “B” where the contravention of the individual share constraint or the non-resident share constraint that gave rise to the prohibition was inadvertent or of a technical nature or it would otherwise be inequitable not to pay the dividend or make the distribution; and

(ii) where a dividend has not been paid or any other distribution has not been made on voting shares as a result of a directors’ determination of a contravention of the individual share constraint or the non-resident share constraint, or where the amount of a dividend or any other distribution has been restored to the Company pursuant to Article 172175(e)(ii) as a result of a directors’ determination of a contravention of the individual share constraint, the Directors of the Company shall declare and pay the dividend, make the distribution, or refund the restored amount, respectively, if they subsequently determine that no such contravention occurred.

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(b) In the event that the Company suspends or redeems voting shares in accordance with Article 176179 or 178,181, respectively, or otherwise redeems, purchases for cancellation or otherwise acquires voting shares, and the result of such action is that any person and the associates of that person who, prior to such action, were not in contravention of the individual share constraint are, after such action, in contravention, then, notwithstanding any other provision of this Part “B” , the sole consequence of such action to that person and the associates of that person, in respect of the voting shares of that person and of the associates of that person held, beneficially owned or controlled at the time of such action, shall be that the number of votes attached to those voting shares shall be reduced to a number that is the largest whole number of votes that may be attached to the voting shares which that person and the associates of that person could hold, beneficially own or control from time to time in compliance with the individual share constraint.

(c) Notwithstanding any other provision of this Part “B”, a contravention of the individual share constraint or the non-resident share constraint shall have no consequences except those that are expressly provided for in this Part “B”. For greater certainty but without limiting the generality of the foregoing:

(i) no transfer, issue or ownership of, and no title to, voting shares;

(ii) no resolution of shareholders [(except to the extent that the result thereof is affected as a result of a directors’ determination under Article 172175(e)(i)]); and

(iii) no act of the Company, including any transfer of property to or by the Company;

shall be invalid or otherwise affected by any contravention of the individual share constraint or the non-resident share constraint or the failure to make the adjustment required pursuant to the non-resident voting constraint.

Directors’ Determinations

185. 182.

(a) The Directors of the Company shall have the sole right and authority to administer the provisions of this Part “B” and to make any determination required or contemplated hereunder. In so acting, the Directors of the Company shall enjoy, in addition to the powers set forth in this Part “B“, all of the powers necessary or desirable, in their opinion, to carry out the intent and purpose of this Part “B”. The Directors of the Company shall make on a timely basis all determinations necessary for the administration of the provisions of this Part “B” and, without limiting the generality of the foregoing, if the Directors of the Company consider that there are reasonable grounds for believing that a contravention of the individual ownership constraint or the non-resident ownership constraint has occurred or will occur, the Directors shall make a determination with respect to the matter. Any directors’ determination that is not inconsistent with the Reorganization Act, the Privatization Act and other applicable law shall be conclusive, final and binding except to the extent modified by any subsequent directors’ determination.

(b) The Directors of the Company shall make any directors’ determination contemplated by Article 172175 or 173176:

(i) after the relevant shareholder’s declaration have been requested and received by the Company, only:

(A) on a basis consistent with those shareholder’s declarations; or

(B) if the Directors of the Company are of the opinion that the shareholder’s declarations do not contain adequate or accurate information and they believe and have reasonable grounds for believing that they will not be provided with shareholder’s declarations that do contain adequate and accurate information; or

(ii) whether or not any shareholder’s declaration has been requested or received by the Company, only if the Directors of the Company believe and have reasonable grounds for believing that they have sufficient information to make the directors’ determination, that the consequences of the directors’ determination would not be inequitable to those affected by it and that it would be impractical, under all the circumstances, to request or to await the receipt of any shareholder’s declaration.

(c) In administering the provisions of this Part B, including, without limitation, in making any directors’ determination in accordance with Article 182185(b) or otherwise, the Directors of the Company may rely on any information on which the Directors consider it reasonable to rely in the circumstances. Without limiting the generality of the foregoing, the Directors of the Company may rely upon any shareholder’s declaration, the register of members of the Company, the knowledge of any Director, officer or employee of the Company or any advisor to the Company and the opinion of counsel to the Company.

(d) In administering the provisions of this Part B , including, without limitation, in making any directors’ determination, the Directors shall act honestly and in good faith. Provided that the Directors of the Company so act, they shall not be liable to the Company and neither they nor the Company shall be liable to any holder or beneficial owner of voting shares or any other person for, nor with respect to any matter arising from or related to, any act or omission to act in relation to this Part B.

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(e) Any directors’ determination required or contemplated by this Part B shall be expressed and conclusively evidenced by a resolution duly adopted.

(f) The Directors may delegate any of their powers and duties under this Article 182185 to any standing or special committee consisting of such members of the Board as the Directors may determine.

Shareholders’ Declarations

186. 183.

(a) For purposes of monitoring the compliance with and of enforcing the provisions of this Part B, the Directors of the Company may require that any registered holder or beneficial owner, or any other person of whom it is, in the circumstances, reasonable or make such request, file with the Company or its registrar and transfer agent a completed shareholder’s declaration. The Directors of the Company shall determine from time to time written guidelines with respect to the nature of the shareholder’s declaration to be requested, the times at which shareholder’s declarations are to be requested and any other relevant matters relating to shareholder’s declarations.

(b) A shareholder’s declaration shall be in the form from time to time determined by the directors of the Company pursuant to Article 183186(a) and, without limiting the generality of the foregoing may be required to be in the form of a simple declaration in writing or a statutory declaration under the Canada Evidence Act. Without limiting the generality of its contents, any shareholder’s declaration may be required to contain information with respect to:

(i) the name, address and residency of the shareholder (“Registered Shareholder”) and if the shareholder is an individual and not a Canadian citizen, such shareholder’s citizenship;

(ii) the name, address and residency of any person who beneficially owns or controls, directly or indirectly, otherwise than by way of security only, the Registered Shareholder’s shares (“Beneficial Shareholder”) and if such person is an individual and not a Canadian citizen, such person’s citizenship;

(iii) the name, address and residency of any person who is an associate of the Registered Shareholder or any Beneficial Shareholder (“Associate”), and if such person is an individual and not a Canadian citizen, such person’s citizenship;

(iv) the number of shares held by the Registered Shareholder, each Beneficial Shareholder and each Associate, including the dates such shares were acquired or proposed to be acquired; and

(v) if the Registered Shareholder, any Beneficial Shareholder or any Associate is a corporation, trust, partnership or unincorporated organization the name, address and residency of each person who is a controlling shareholder, trustee, partner or member of the corporation, trust, partnership or unincorporated organization, as the case may be, and if such person is an individual and not a Canadian citizen, such person’s citizenship.

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www.emera.com

EX-4.7

Exhibit 4.7

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

TECO ENERGY, INC.

Report of Independent Registered Certified Public Accounting Firm

To the Board of Directors and Shareholders of TECO Energy, Inc.:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of TECO Energy, Inc. and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting.  Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances.  We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 2 to the financial statements, the Company changed the manner in which it classifies deferred taxes in 2015.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Tampa, Florida

February 26, 2016

71

TECO ENERGY, INC.

Consolidated Balance Sheets

Assets	Dec. 31,			Dec. 31,
(millions)	2015			2014
Current assets
Cash and cash equivalents	$	23.8		$	25.4
Receivables, less allowance for uncollectibles of $2.1 and    $2.1 at Dec. 31, 2015 and 2014, respectively		280.7			299.8
Inventories, at average cost
Fuel		113.4			96.4
Materials and supplies		76.8			75.4
Regulatory assets		44.8			53.6
Deferred income taxes		0.0			72.8
Prepayments and other current assets		30.8			22.6
Assets held for sale		0.0			109.6
Total current assets		570.3			755.6
Property, plant and equipment
Utility plant in service
Electric		7,270.3			7,094.8
Gas		2,113.8			1,984.6
Construction work in progress		794.7			640.0
Other property		15.9			14.5
Property, plant and equipment, at original costs		10,194.7			9,733.9
Accumulated depreciation		(2,712.9	)		(2,645.7	)
Total property, plant and equipment, net		7,481.8			7,088.2
Other assets
Regulatory assets		395.2			348.5
Goodwill	408.4			408.3
Deferred charges and other assets		105.4			65.8
Assets held for sale		0.0			59.8
Total other assets		909.0			882.4
Total assets	$	8,961.1		$	8,726.2

The accompanying notes are an integral part of the consolidated financial statements.

72

TECO ENERGY, INC.

Consolidated Balance Sheets – continued

Liabilities and Capital	Dec. 31,			Dec. 31,
(millions)	2015			2014
Current liabilities
Long-term debt due within one year	$	333.3		$	274.5
Notes payable		247.0			139.0
Accounts payable		255.4			288.6
Customer deposits		182.1			176.2
Regulatory liabilities		84.8			57.0
Derivative liabilities		24.1			36.6
Interest accrued		36.2			39.9
Taxes accrued		13.2			29.9
Other		22.6			16.8
Liabilities associated with assets held for sale		0.0			39.4
Total current liabilities		1,198.7			1,097.9
Other liabilities
Deferred income taxes		570.7			519.2
Investment tax credits		10.5			9.0
Regulatory liabilities		715.8			729.0
Derivative liabilities		2.1			6.1
Deferred credits and other liabilities		387.4			370.9
Liabilities associated with assets held for sale		0.0			65.4
Long-term debt, less amount due within one year		3,516.9			3,354.0
Total other liabilities		5,203.4			5,053.6
Commitments and Contingencies (see Note 12)
Capital
Common equity (400.0 million shares authorized; par value $1;    235.3 million and 234.9 million shares outstanding at    Dec. 31, 2015 and 2014, respectively)		235.3			234.9
Additional paid in capital		1,894.5			1,875.9
Retained earnings		441.4			479.6
Accumulated other comprehensive loss		(12.2	)		(15.7	)
Total TECO Energy capital		2,559.0			2,574.7
Total liabilities and capital	$	8,961.1		$	8,726.2

The accompanying notes are an integral part of the consolidated financial statements.

73

TECO ENERGY, INC.

Consolidated Statements of Income

(millions, except per share amounts)
For the years ended Dec. 31,		2015			2014			2013
Revenues
Regulated electric		$	2,014.9		$	2,019.9		$	1,949.6
Regulated gas			716.8			537.4			392.9
Unregulated			11.8			9.1			12.6
Total revenues			2,743.5			2,566.4			2,355.1
Expenses
Regulated operations and maintenance
Fuel			638.6			692.3			680.2
Purchased power			78.9			71.4			64.7
Cost of natural gas sold			271.6			209.7			142.2
Other			613.2			547.8			524.4
Operation and maintenance other expense			22.7			29.5			12.5
Depreciation and amortization			349.0			315.3			291.8
Taxes, other than income			207.4			195.0			184.7
Total expenses			2,181.4			2,061.0			1,900.5
Income from operations			562.1			505.4			454.6
Other income (expense)
Allowance for other funds used during construction			17.4			10.5			6.3
Other income			3.4			0.5			1.8
Total other income			20.8			11.0			8.1
Interest charges
Interest expense		195.1			176.4				165.0
Allowance for borrowed funds used during construction			(8.7	)		(5.3	)		(3.6	)
Total interest charges			186.4			171.1			161.4
Income from continuing operations before provision    for income taxes			396.5			345.3			301.3
Provision for income taxes			155.3			138.9			112.6
Net income from continuing operations			241.2			206.4			188.7
Discontinued operations
Income (loss) from discontinued operations			(106.3	)		(125.4	)		5.2
Provision (benefit) for income taxes			(38.6	)		(49.4	)		(3.8	)
Income (loss) from discontinued operations, net			(67.7	)		(76.0	)		9.0
Net income		$	173.5		$	130.4		$	197.7
Average common shares outstanding	– Basic		233.1			223.1			215.0
	– Diluted		234.5			223.7			215.5
Earnings per share from continuing operations	– Basic	$	1.03		$	0.92		$	0.88
	– Diluted	$	1.03		$	0.92		$	0.88
Earnings per share from discontinued operations	– Basic	$	(0.29	)	$	(0.34	)	$	0.04
	– Diluted	$	(0.29	)	$	(0.34	)	$	0.04
Earnings per share	– Basic	$	0.74		$	0.58		$	0.92
	– Diluted	$	0.74		$	0.58		$	0.92
Dividends paid per common share outstanding		$	0.90		$	0.88		$	0.88

Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

The accompanying notes are an integral part of the consolidated financial statements.

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TECO ENERGY, INC.

Consolidated Statements of Comprehensive Income

(millions)
For the years ended Dec. 31,	2015			2014			2013
Net income	$	173.5		$	130.4		$	197.7
Other comprehensive income (loss), net of tax
Gain on cash flow hedges		3.5			0.7			1.4
Amortization of unrecognized benefit costs and other		2.1			(3.0	)		14.8
Change in benefit obligation due to valuation		(9.8	)		8.0			0.0
Increase in unrecognized postemployment costs		0.0			(8.2	)		0.0
Recognized benefit costs due to settlement		7.7			0.0			1.6
Other comprehensive income (loss), net of tax		3.5			(2.5	)		17.8
Comprehensive income	$	177.0		$	127.9		$	215.5

The accompanying notes are an integral part of the consolidated financial statements.

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TECO ENERGY, INC.

Consolidated Statements of Cash Flows

(millions)
For the years ended Dec. 31,	2015			2014			2013
Cash flows from operating activities
Net income	$	173.5		$	130.4		$	197.7
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		350.2			341.9			329.5
Deferred income taxes and investment tax credits		117.5			89.4			110.1
Allowance for other funds used during construction		(17.4	)		(10.5	)		(6.3	)
Non-cash stock compensation		13.1			12.7			13.5
Loss (gain) on disposals of business/assets		13.2			(0.2	)		(1.6	)
Deferred recovery clauses		26.4			(15.2	)		(6.2	)
Asset impairment		78.6			115.9			0.0
Receivables, less allowance for uncollectibles		36.0			(36.6	)		(4.5	)
Inventories		(22.6	)		12.8			1.1
Prepayments and other current assets		(8.0	)		2.8			(2.2	)
Taxes accrued		(15.9	)		1.1			1.4
Interest accrued		(3.6	)		7.3			(1.3	)
Accounts payable		(61.6	)		23.4			35.9
Other		(69.8	)		(10.4	)		(8.5	)
Cash flows from operating activities		609.6			664.8			658.6
Cash flows from investing activities
Capital expenditures		(739.7	)		(703.8	)		(526.1	)
Purchase of NMGI, net of cash acquired		0.0			(751.5	)		0.0
Net proceeds from sales of business/assets		0.0			0.2			4.3
Other investments		(0.3	)		(7.9	)		0.0
Cash flows used in investing activities		(740.0	)		(1,463.0	)		(521.8	)
Cash flows from financing activities
Dividends paid		(211.7	)		(199.2	)		(191.2	)
Proceeds from the sale of common stock		7.3			302.3			6.7
Proceeds from long-term debt issuance		499.7			563.6			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(274.5	)		(83.3	)		(51.6	)
Change in short-term debt		108.0			55.0			84.0
Cash flows from/(used in) financing activities		128.8			638.4			(152.1	)
Net decrease in cash and cash equivalents		(1.6	)		(159.8	)		(15.3	)
Cash and cash equivalents at beginning of the year		25.4			185.2			200.5
Cash and cash equivalents at end of the year	$	23.8		$	25.4		$	185.2
Supplemental disclosure of cash flow information
Cash paid during the year for:
Interest	$	179.6		$	161.3		$	161.0
Income taxes paid	$	14.5		$	2.9		$	1.8
Supplemental disclosure of non-cash activities
Debt assumed in NMGI acquisition	$	0.0		$	200.0		$	0.0
Change in accrued capital expenditures	$	8.0		$	13.3		$	4.7

The accompanying notes are an integral part of the consolidated financial statements.

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TECO ENERGY, INC.

Consolidated Statements of Capital

											Accumulated
					Additional						Other
			Common		Paid in			Retained			Comprehensive			Total
(millions)	Shares		Stock		Capital			Earnings			Income (Loss)			Capital
Balance, Dec. 31, 2012		216.6	$	216.6	$	1,564.5		$	541.7		$	(31.0	)	$	2,291.8
Net income									197.7						197.7
Other comprehensive income, after tax												17.8			17.8
Common stock issued		0.7		0.7		5.2									5.9
Cash dividends declared									(191.2	)					(191.2	)
Stock compensation expense						13.5									13.5
Restricted stock—dividends						1.0			0.1						1.1
Tax short fall—stock compensation						(2.9	)								(2.9	)
Balance, Dec. 31, 2013		217.3	$	217.3	$	1,581.3		$	548.3		$	(13.2	)	$	2,333.7
Net income									130.4						130.4
Other comprehensive income, after tax												(2.5	)		(2.5	)
Common stock issued		17.6		17.6		283.2									300.8
Cash dividends declared									(199.2	)					(199.2	)
Stock compensation expense						12.7									12.7
Restricted stock—dividends						1.1			0.1						1.2
Tax short fall—stock compensation						(2.4	)								(2.4	)
Balance, Dec. 31, 2014		234.9	$	234.9	$	1,875.9		$	479.6		$	(15.7	)	$	2,574.7
Net income									173.5						173.5
Other comprehensive loss, after tax												3.5			3.5
Common stock issued		0.4		0.4		4.6									5.0
Cash dividends declared									(211.7	)					(211.7	)
Stock compensation expense						13.1									13.1
Restricted stock—dividends						1.3									1.3
Tax short fall—stock compensation						(0.4	)								(0.4	)
Balance, Dec. 31, 2015		235.3	$	235.3	$	1,894.5		$	441.4		$	(12.2	)	$	2,559.0

The accompanying notes are an integral part of the consolidated financial statements.

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TECO ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies

Description of the Business

TECO Energy is a holding company for regulated utilities and other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiary, NMGI, owns NMGC.

TEC, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electricdivision provides retail electric services in West Central Florida, and PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida.

NMGC, a Delaware corporation and wholly owned subsidiary of NMGI, was acquired by the company on Sept. 2, 2014. NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in New Mexico.

On Sept. 21, 2015, TECO Diversified sold all of its ownership interest in TECO Coal.  TECO Coal, a Kentucky LLC, had subsidiaries which owned assets in Eastern Kentucky, Tennessee and Virginia. These entities owned mineral rights, owned or operated surface and underground mines and owned interests in coal processing and loading facilities. See Note 19 for further information.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 21 for further information.

The company’s significant accounting policies are as follows:

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of TECO Energy and its majority-owned subsidiaries.  Intercompany balances and intercompany transactions have been eliminated in consolidation.

The consolidated financial statements include NMGI and NMGC from the acquisition date of Sept. 2, 2014 through Dec. 31, 2015 (see Note 21). In addition, all periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent and TECO Diversified that directly related to TECO Coal and TECO Guatemala (see Note 19).

For entities that are determined to meet the definition of a VIE, the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a noncontrolling interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 18).

Through its centralized services company subsidiary, TSI, TECO Energy provides its operating subsidiaries with specialized services at cost, including information technology, procurement, human resources, legal, risk management, financial, and administrative services. TSI’s costs are directly charged or allocated to the applicable operating subsidiaries using cost-causative allocation methods. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of total operating revenues, total operating assets and net income as the basis of allocation. TSI has losses related to taxes which are not distributed to affiliate companies.  The results of TECO Energy’s corporate operations, consisting of TSI tax losses and non-allocable Parent costs, are included within the “Other” reportable segment (see Note 14).

Use of Estimates

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Property, Plant and Equipment

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Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Tampa Electric, PGS and NMGC, concurrent with a planned major maintenance outage or with new construction, capitalize the cost of adding or replacing retirement units-of-property in conformity with the regulations of FERC, FPSC and NMPRC, as applicable. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred.

In general, when regulated depreciable property is retired or disposed, its original cost less salvage is charged to accumulated depreciation. For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.

Depreciation

Tampa Electric, PGS and NMGC compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

● the group remaining life method, approved by the FPSC or NMPRC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

● the amortizable life method, approved by the FPSC or NMPRC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2015, 3.6% for 2014 and 3.7% for 2013. Construction work in progress is not depreciated until the asset is completed or placed in service.

On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric began using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

Other TECO Energy subsidiaries compute depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives:

Asset	Estimated Useful Lives
Building and improvements	40 years
Office equipment and furniture	4 - 7 years
Computer software	3 - 15 years

Total depreciation expense for the years ended Dec. 31, 2015, 2014 and 2013 was $339.1 million, $307.5 million and $285.6 million, respectively.

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate Tampa Electric’s AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. Tampa Electric’s rate was 8.16% for May 2009 through December 2013. In March 2014, the rate was revised to 6.46% effective Jan. 1, 2014. NMGC’s rate used to calculate its AFUDC in 2015 and 2014 was 4.41% and 4.92%, respectively. Total AFUDC for the years ended Dec. 31, 2015, 2014 and 2013 was $26.1 million, $15.8 million and $9.9 million, respectively.

Inventory

TEC and NMGC value materials, supplies and fossil fuel inventory (coal, oil or natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.

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Fuel Inventory	Dec. 31,		Dec.  31,
(millions)	2015		2014
TEC	$	105.6	$	85.2
NMGC		7.8		11.2
Total	$	113.4	$	96.4

TECO Coal inventories were stated at the lower of cost, computed on the first-in, first-out method, or net realizable value. Parts and supplies inventories were stated at the lower of cost or market on an average cost basis. TECO Coal’s inventory was classified within Assets held for sale at Dec. 31, 2014.

Regulatory Assets and Liabilities

Tampa Electric, PGS and NMGC are subject to accounting guidance for the effects of certain types of regulation (see Note 3 for additional details).

Deferred Income Taxes

TECO Energy uses the asset and liability method to determine deferred income taxes. Under the asset and liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax assets will not be realized. If management determines that it is likely that some or all of deferred tax assets will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized (see Note 4 for additional details).

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

Goodwill

Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated fair values of assets acquired and liabilities assumed at the acquisition date. Under the accounting guidance for goodwill, goodwill is subject to an annual assessment for impairment at the reporting unit level. See Note 20 for further detail.

Employee Postretirement Benefits

The company sponsors a defined benefit retirement plan and other postretirement benefits.  The measurement of the plans are based on several statistical and other factors, including those that attempt to anticipate future events.  See Note 5 for further detail.

Revenue Recognition

TECO Energy recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ retail businesses and the prices charged to customers are regulated by the FPSC or NMPRC, as applicable. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

Revenues for energy marketing operations at TECO EnergySource, Inc. are presented on a net basis in accordance with the accounting guidance for reporting revenue gross as a principal versus net as an agent and recognition and reporting of gains and losses on energy trading contracts to reflect the nature of the contractual relationships with customers and suppliers. Accordingly, for the years ended Dec. 31, 2015, 2014 and 2013, total costs of $3.1 million, $4.3 million and $23.1 million, respectively, consisting primarily of natural gas purchased, were netted against revenues in the “Revenues-Unregulated” caption on the Consolidated Statements of Income.

Revenues for TECO Coal shipments, both domestic and international, were recognized when title and risk of loss transfer to the customer. They were included in “Income (loss) from discontinued operations” on the Consolidated Statements of Income.

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Revenues and Cost Recovery

Revenues include amounts resulting from cost recovery clauses at the regulated utilities (Tampa Electric, PGS and NMGC) which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, gas storage, interstate pipeline capacity and conservation costs for PGS and NMGC. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide for a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2015 and 2014, unbilled revenues of $81.1 million and $86.6 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $78.9 million, $71.4 million and $64.7 million, for the years ended Dec. 31, 2015, 2014 and 2013, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.

Receivables and Allowance for Uncollectible Accounts

Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on the regulated utilities’ collection experience. Circumstances that could affect Tampa Electric’s, PGS’s and NMGC’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

TECO Coal’s receivables, which were classified within Assets held for sale at Dec. 31, 2014, consisted of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts was established based on TECO Coal’s collection experience. Circumstances that could have affected TECO Coal’s estimates of uncollectible receivables included customer credit issues and general economic conditions. Accounts were written off once they were determined to be uncollectible.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover certain costs on a dollar-for-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $116.9 million, $113.9 million and $108.5 million for the years ended Dec. 31, 2015, 2014 and 2013, respectively. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis.  Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statement of Income.

TECO Energy’s excise taxes were accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they were not specifically recovered through revenues. Excise taxes paid by the regulated utilities were not material and were expensed when incurred.

Deferred Charges and Other Assets

Deferred charges and other assets consist primarily of a contribution made by the company in order to fully fund its SERP obligation (see Note 5), unamortized debt issuance costs and assets related to NMGC’s ROW.

Debt issuance costs – The company capitalizes the external costs of obtaining debt financing and amortizes such costs over the life of the related debt on a straight-line basis that approximates the effective interest method. These amounts are reflected in “Interest expense” on TECO Energy’s Consolidated Statements of Income.

NMGC’s ROW- Gross assets related to NMGC’s ROW were $41 million at Dec. 31, 2015 and 2014. The related accumulated amortization was $9 million and $8 million at Dec. 31, 2015 and 2014, respectively. The company amortizes costs related to obtaining NMGC’s ROW to “Depreciation and amortization expense” on TECO Energy’s Consolidated Statements of Income.

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Deferred Credits and Other Liabilities

Deferred credits and other liabilities primarily include the accrued postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 12), and medical and general liability claims incurred but not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2015 and 2014 ranged from 2.92% to 4.00% and 2.71% to 4.00%, respectively.

Stock-Based Compensation

TECO Energy accounts for its stock-based compensation in accordance with the accounting guidance for share-based payment. Under the provisions of this guidance, stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments.

Cash Flows Related to Derivatives and Hedging Activities

The company classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. In the case of diesel fuel swaps, which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows are included in the operating section. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows.

Reclassifications

Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TECO Energy’s net income in any period.

2. New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers.  This guidance will be effective for the company beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance will be effective for the company beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Dec. 31, 2015, $27.7 million of debt issuance costs, which does not include costs for line-of-credit arrangements, are included in the “Deferred charges and other assets” line item on the company’s Consolidated Condensed Balance Sheet. The guidance will not affect the company’s results of operations or cash flows.

Disclosure of Investments Using Net Asset Value

In May 2015, the FASB issued guidance stating that investments for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies that a plan sponsor’s pension assets are eligible to be measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan has such investments as disclosed in Note 5. This standard will be required for the company beginning in 2016. As early adoption is permitted, the company adopted the standard for its 2015 fiscal year and applied the presentation on a retrospective basis for all periods presented

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in the pension plan assets fair value hierarchy. The guidance did not affect the company’s balance sheets, results of operations or cash flows.

Measurement Period Adjustments in Business Combinations

In September 2015, the FASB issued guidance requiring an acquirer in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to exceed one year. The guidance will be effective for the company beginning in 2016 and will be applied prospectively. The guidance will not affect the company’s current financial statements. However, the company will assess the potential impact of the guidance on future acquisitions.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. To simplify the presentation of deferred income taxes, the new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet rather than be classified as current or noncurrent under current guidance. The guidance will be required for the company beginning in 2017 and may be applied on a prospective or retrospective basis. As early adoption is permitted, the company adopted the standard in December 2015 and applied the balance sheet presentation on a prospective basis. Therefore, prior period balance sheets were not retrospectively adjusted. The guidance did not affect the company’s results of operations or cash flows.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. The company does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for the company beginning in 2018.

Leases

 In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The dual model for income statement classification is maintained under the new guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. This guidance will be effective for the company beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. The company is currently evaluating the impacts of the adoption of the guidance on its financial statements.

3. Regulatory

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC has jurisdiction over the regulatory matters related, directly and indirectly, to NMGC providing service to its customers, including, among other things, rates, accounting procedures, securities issuances, and standards of service. NMGC must follow certain accounting guidance that pertains specifically to entities that are subject to such regulation. Comparable to the FPSC, the NMPRC sets rates at a level that allows utilities such as NMGC to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

Base Rates-Tampa Electric

Tampa Electric’s results for the first ten months of 2013 reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

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Tampa Electric’s results for 2015, 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on Sept. 6, 2013, between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of Tampa Electric’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective no sooner than Jan. 1, 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Tampa Electric Storm Damage Cost Recovery

Prior to the above-mentioned stipulation and settlement agreement, Tampa Electric was accruing $8.0 million annually to a FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both Dec. 31, 2015 and 2014.  

Base Rates-PGS

PGS’s base rates were established in May 2009 and reflect an ROE of 10.75%, which is the middle of a range between 9.75% to 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of $560.8 million.

Base Rates-NMGC

In March 2011, NMGC filed an application with the NMPRC seeking authority to increase NMGC’s base rates by approximately $34.5 million on a normalized annual basis. In September 2011, the parties to the base rate proceeding entered into a settlement. The parties filed an unopposed stipulation reflecting the terms of that settlement with the NMPRC and the unopposed stipulation was approved by the NMPRC on Jan. 31, 2012, revising, among other things, base rates for all service provided on or after Feb. 1, 2012. The revised rates contained in the NMPRC-approved settlement increased NMGC’s base rate revenue by approximately $21.5 million on a normalized annual basis. The monthly residential customer access fee increased from $9.59 to $11.50, with the remaining rate increase reflected in changes to volumetric delivery charges. The parties stipulated that the NMPRC-approved revised rates would not increase again prior to July 31, 2013. Subsequently, as a condition of the August 2014 NMPRC order approving the TECO Energy acquisition of NMGC, the rates were frozen at the approved 2012 levels until the end of 2017, as reported in Note 21.

Regulatory Assets and Liabilities

Tampa Electric, PGS and NMGC apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

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Details of the regulatory assets and liabilities as of Dec. 31, 2015 and 2014 are presented in the following table:

	Dec. 31,		Dec. 31,
(millions)	2015		2014
Regulatory assets:
Regulatory tax asset (1)	$	74.7	$	69.2
Cost-recovery clauses - deferred balances (2)	5.5		1.9
Cost-recovery clauses - offsets to derivative liabilities (2)		26.5		43.2
Environmental remediation (3)		54.0		53.1
Postretirement benefits (4)		240.6		194.0
Deferred bond refinancing costs (5)		6.5		7.2
Debt basis adjustment (6)		17.5		20.9
Competitive rate adjustment (2)		2.6		2.8
Other		12.1		9.8
Total regulatory assets		440.0		402.1
Less: Current portion		44.8		53.6
Long-term regulatory assets	$	395.2	$	348.5
Regulatory liabilities:
Regulatory tax liability	$	7.9	$	6.9
Cost-recovery clauses (2)		55.9		25.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve—cost of removal (7)		679.9		695.2
Other		0.8		1.9
Total regulatory liabilities		800.6		786.0
Less: Current portion		84.8		57.0
Long-term regulatory liabilities	$	715.8	$	729.0

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.  

(2) These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument.

(7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

4. Income Taxes

Income Tax Expense

In 2015, 2014 and 2013, TECO Energy recorded net tax provisions from continuing operations of $155.3 million, $138.9 million and $112.6 million, respectively. A majority of this provision is non-cash. TECO Energy has net operating losses that are being utilized to reduce its taxable income. As such, cash taxes paid for income taxes as required for the alternative minimum tax, state income taxes and prior year audits in 2015, 2014 and 2013 were $14.5 million, $2.9 million and $1.8 million, respectively.

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Income tax expense consists of the following:

Income Tax Expense (Benefit)

(millions)
For the year ended Dec. 31,	2015			2014			2013
Continuing Operations
Current income taxes
Federal	$	(0.5	)	$	0.5		$	2.2
State		0.0			0.0			0.0
Deferred income taxes
Federal		133.2			111.0			98.8
State		21.1			27.7			11.9
Amortization of investment tax credits		1.5			(0.3	)		(0.3	)
Income tax expense from continuing operations		155.3			138.9			112.6
Discontinued Operations
Current income taxes
Federal		0.0			0.0			0.0
State		(0.3	)		(0.4	)		(3.5	)
Deferred income taxes
Federal		(34.7	)		(44.0	)		(0.3	)
State		(3.6	)		(5.0	)		0.0
Income tax expense from discontinued operations		(38.6	)		(49.4	)		(3.8	)
Total income tax expense	$	116.7		$	89.5		$	108.8

During 2015, 2014 and 2013, TECO Energy increased its net operating loss carryforward.

The reconciliation of the federal statutory rate to the company’s effective income tax rate is as follows:

Effective Income Tax Rate

(millions)
For the year ended Dec. 31,	2015			2014			2013
Income tax expense at the federal statutory rate of 35%	$	138.8		$	120.9		$	105.5
Increase (decrease) due to:
State income tax, net of federal income tax		13.6			17.0			7.5
Valuation allowance		0.1			0.9			0.0
Other		2.8			0.1			(0.4	)
Total income tax expense from continuing operations	$	155.3		$	138.9		$	112.6
Income tax expense as a percent of income from continuing operations,    before income taxes		39.2	%		40.2	%		37.4	%

For the three years presented, the overall effective tax rate on continuing operations was higher than the 35% U.S. federal statutory rate primarily due to state income taxes. For 2015, the effective tax rate decreased as a result of a lower state consolidated tax adjustment, offset by a tax expense related to stock-based compensation.

As discussed in Note 1, TECO Energy uses the asset and liability method to determine deferred income taxes. Based primarily on the reversal of deferred income tax liabilities and future earnings of the company’s utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2015 will be realized in future periods.

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Deferred Income Taxes

The major components of the company’s deferred tax assets and liabilities recognized are as follows:

(millions)
As of Dec. 31,	2015			2014
Deferred tax liabilities (1)
Property related	$	1,519.3		$	1,391.3
Pension		86.6			62.3
Total deferred tax liabilities		1,605.9			1,453.6
Deferred tax assets (1)
Alternative minimum tax credit carryforward		213.5			214.0
Loss and credit carryforwards (2)		637.5			566.7
Other postretirement benefits		69.5			71.5
Other		117.5			159.6
Total deferred tax assets		1,038.0			1,011.8
Valuation allowance (3)		(2.0	)		(4.6	)
Total deferred tax assets, net of valuation allowance		1,036.0			1,007.2
Total deferred tax liability, net		569.9			446.4
Less: Current portion of deferred tax asset		0.0			(72.8	)
Less: Long term portion of deferred tax asset		(0.8	)		0.0
Long-term portion of deferred tax liability, net	$	570.7		$	519.2

(1) Certain property related assets and liabilities have been netted.

(2) As a result of certain realization requirements of accounting guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2015 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s equity will be increased by $2.6 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized.

(3) During 2015, the valuation allowance related to discontinued operations decreased from $3.6 million to $1.0 million.

At Dec. 31, 2015, the company had cumulative unused federal, Florida and New Mexico NOLs for income tax purposes of $1,728.6 million, $675.2 million and $85.8 million, respectively, expiring at various times between 2025 and 2034, with the majority expiring in 2025. The federal NOL includes $121.6 million of NOLs due to the 2014 acquisition of NMGI. In addition, the company has unused general business credits of $5.8 million expiring between 2026 and 2034. During 2015, the company’s available AMT credit carryforward decreased from $214.0 million to $213.5 million. The AMT credit may be used indefinitely to reduce federal income taxes.

The company’s consolidated balance sheet reflects loss carryforwards excluding amounts resulting from excess stock-based compensation. Accordingly, such losses from excess stock-based compensation tax deductions are accounted for as an increase to additional paid-in capital if and when realized through a reduction in income taxes payable.

The company establishes valuation allowances on its deferred tax assets, including losses and tax credits, when the amount of expected future taxable income is not likely to support the use of the deduction or credit. At Dec. 31, 2014, a $4.6 million valuation allowance had been established for state NOL carryforwards and state deferred tax assets, net of federal tax. During 2015, the valuation allowance decreased by $2.6 million.  As a result of the company’s sale of its 100% interest in TECO Coal, the company released a $3.6 million valuation allowance previously recorded in 2014 related to state NOL carryforwards and deferred tax assets, net of federal tax, with a corresponding write off of the gross deferred tax assets since the likelihood that the company will ever utilize those carryforwards is remote.  The TECO Coal sale also generated a federal capital loss carryforward deferred tax asset of $1.0 million for which a full valuation allowance has been established due to the uncertainty of recognizing the benefit from this loss, before it expires in 2020.        

Unrecognized Tax Benefits

The company accounts for uncertain tax positions in accordance with FASB guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, the company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

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A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

(millions)	2015		2014		2013
Balance at Jan. 1,	$	0.0	$	0.0	$	2.9
Decreases due to expiration of statute of limitations		0.0		0.0		(2.9	)
Balance at Dec. 31	$	0.0	$	0.0	$	0.0

The company recognizes interest accruals related to uncertain tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance other expense” in the Consolidated Statements of Income. In 2015, 2014 and 2013, the company recognized $0.0 million, $0.0 million and $(0.9) million, respectively, of pretax charges (benefits) for interest only. Additionally, the company did not have any accrued interest at Dec. 31, 2015 and 2014. No amounts have been recorded for penalties.

The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. U.S. state and foreign jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by taxing authorities in major state jurisdictions and foreign jurisdictions include 2005 and forward. The company does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

5. Employee Postretirement Benefits

Pension Benefits

TECO Energy has a qualified, non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings.

Amounts disclosed for pension benefits in the following tables and discussion also include the fully-funded obligations for the SERP. The SERP is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.

TECO Coal participants ceased earning pension benefits on Sept. 21, 2015, the date of TECO Energy’s sale of TECO Coal. As a result of the sale, a curtailment loss in the Retirement Plan was recognized in the fourth quarter of 2014. See curtailment-related line items in tables below.

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits (Other Benefits or Other Postretirement Benefit Plan) for most employees retiring after age 50 meeting certain service requirements. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.

MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.

The FASB issued accounting guidance and disclosure requirements related to MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset in 2010 and recorded a true up in 2013. TEC is amortizing the regulatory asset over the remaining average service life at the time of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

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Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts, which are greater than the subsidy payments previously received by the company under Medicare Part D for its post-65 retiree prescription drug plan.

NMGC has a separate, partially-funded other postretirement benefit plan. It is not presented separately; rather, it is presented with TECO Energy’s plan in the tables and discussion below. Since NMGC is allowed to recover its other postretirement benefit costs through rates, the regulated asset established prior to the acquisition for pre-acquisition-related prior service cost, actuarial loss, and transition obligation was maintained after the acquisition. This regulated asset will be amortized. See “unrecognized costs in regulated asset acquired in business combination” line item in the “Amounts recognized in accumulated other comprehensive income, pretax, and regulatory assets” table below.

Effective Jan. 1, 2015, the TECO Coal participants were terminated from the Other Postretirement Benefit Plan. As a result, the other postretirement benefit obligation for TECO Coal was eliminated as of Dec. 31, 2014. See curtailment-related line items in tables below.

Obligations and Funded Status

TECO Energy recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in the benefit liabilities and AOCI in the case of the unregulated companies, or the benefit liabilities and regulatory assets in the case of TEC and NMGC. The results of operations are not impacted.

The following table provides a detail of the change in benefit obligations and change in plan assets for combined pension plans (pension benefits) and combined other postretirement benefit plans (other benefits).

Obligations and Plan Assets	Pension Benefits						Other Benefits
(millions)	2015			2014			2015			2014
Change in benefit obligation
Net benefit obligation at beginning of year	$	728.9		$	666.0		$	201.5		$	208.1
Service cost		20.9			18.3			2.2			2.5
Interest cost		30.3			32.0			8.2			10.8
Plan participants’ contributions		0.0			0.0			2.0			2.8
Plan amendments		0.0			0.0			(3.7	)		(23.2	)
Actuarial loss (gain)		5.8			48.3			(0.4	)		1.5
Benefits paid		(53.0	)		(39.9	)		(14.6	)		(16.0	)
Transfer in due to the effect of business combination		0.0			0.0			0.0			26.7
Plan curtailment		0.0			4.0			0.0			(11.7	)
Special termination benefit		0.0			0.2			0.0			0.0
Net benefit obligation at end of year	$	732.9		$	728.9		$	195.2		$	201.5

Change in plan assets
Fair value of plan assets at beginning of year	$	648.0		$	593.0		$	18.8		$	0.0
Actual return on plan assets		(25.5	)		46.4			(0.6	)		0.1
Employer contributions		55.0			47.5			1.5			(1.0	)
Employer direct benefit payments		0.9			1.0			13.5			16.0
Plan participants’ contributions		0.0			0.0			2.0			2.8
Transfer in due to acquisition		0.0			0.0			0.0			16.9
Benefits paid		(53.0	)		(39.9	)		(14.6	)		(16.0	)
Fair value of plan assets at end of year (1)	$	625.4		$	648.0		$	20.6			18.8

 (1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

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At Dec. 31, the aggregate financial position for pension plans and other postretirement plans with benefit obligations in excess of plan assets was as follows:

Funded Status	Pension Benefits						Other Benefits
(millions)	2015			2014			2015			2014
Benefit obligation (PBO/APBO)	$	732.9		$	728.9		$	195.2		$	201.5
Less: Fair value of plan assets		625.4			648.0			20.6			18.8
Funded status at end of year	$	(107.5	)	$	(80.9	)	$	(174.6	)	$	(182.7	)

The accumulated benefit obligation for all defined benefit pension plans was $686.9 million at Dec. 31, 2015 and $685.0 million at Dec. 31, 2014.  

The amounts recognized in the Consolidated Balance Sheets for pension and other postretirement benefit obligations, plan assets, and unrecognized costs at Dec. 31 were as follows:

Amounts recognized in balance sheet	Pension Benefits						Other Benefits
(millions)	2015			2014			2015			2014
Regulatory assets	$	208.2		$	167.4		$	32.4		$	26.6
Accrued benefit costs and other current liabilities		(10.5	)		(4.9	)		(10.7	)		(10.7	)
Deferred credits and other liabilities		(97.0	)		(76.0	)		(163.9	)		(172.0	)
Accumulated other comprehensive loss (income), pretax		55.7			36.3			(41.6	)		(34.6	)
Net amount recognized at end of year	$	156.4		$	122.8		$	(183.8	)	$	(190.7	)

Unrecognized gains and losses and prior service credits and costs are recorded in accumulated other comprehensive income for the non-regulated companies and regulatory assets for the regulated companies. The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.

Amounts recognized in accumulated other comprehensive income, pretax, and regulatory assets	Pension Benefits				Other Benefits
(millions)	2015		2014		2015			2014
Net actuarial loss	$	263.6	$	203.7	$	10.9		$	9.6
Prior service cost (credit)		0.3		0.0		(25.0	)		(23.6	)
Unrecognized costs in regulated asset acquired in business combination		0.0		0.0		4.9			6.0
Amount recognized, pretax	$	263.9	$	203.7	$	(9.2	)	$	(8.0	)

Assumptions used to determine benefit obligations at Dec. 31:

	Pension Benefits						Other Benefits
	2015			2014			2015			2014
Discount rate		4.688	%		4.258	%		4.669	%		4.211	%
Rate of compensation increase—weighted		3.87	%		3.87	%		2.50	%		3.86	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				7.05	%		7.09	%
Ultimate rate	n/a			n/a				4.50	%		4.57	%
Year rate reaches ultimate	n/a			n/a			2038			2025

A one-percentage-point change in assumed health care cost trend rates would have the following effect on the benefit obligation:

		1%		1%
(millions)	Increase		Decrease
Effect on postretirement benefit obligation	$	9.0	$	(7.7	)

The discount rate assumption used to determine the Dec. 31, 2015 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

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Amounts recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets

(millions)	Pension Benefits									Other Benefits
	2015			2014			2013			2015			2014			2013
Service cost	$	20.9		$	18.3		$	18.2		$	2.2		$	2.5		$	2.5
Interest cost		30.3			32.0			28.9			8.2			10.8			9.3
Expected return on plan assets		(43.3	)		(41.8	)		(38.4	)		(1.1	)		(0.3	)		0.0
Amortization of:
Actuarial loss		15.1			13.5			20.5			0.0			0.2			1.0
Prior service (benefit) cost		(0.2	)		(0.4	)		(0.4	)		(2.4	)		(0.2	)		(0.4	)
Curtailment loss (gain)		0.0			3.9			0.0			0.0			(0.2	)		0.0
Special termination benefit		0.0			0.2			0.0			0.0			0.0			0.0
Settlement loss		0.0			0.0			1.0			0.0			0.0			0.0
Net periodic benefit cost	$	22.8		$	25.7		$	29.8		$	6.9		$	12.8		$	12.4

New prior service cost	$	0.0		$	0.0		$	0.0		$	(3.7	)	$	(23.6	)	$	0.0
Net loss (gain) arising during the year		74.5			44.1			(75.7	)		1.3			(9.9	)		(15.6	)
Unrecognized costs in regulated asset acquired in business combination		0.0			0.0			0.0			0.0			6.4			0.0
Amounts recognized as component of net periodic benefit cost:
Amortization of actuarial gain (loss)		(15.1	)		(13.5	)		(21.5	)		0.0			(0.2	)		(1.0	)
Amortization of prior service (benefit) cost		0.2		0.4				0.4			2.4			0.2			0.3
Total recognized in OCI and regulatory assets	$	59.6		$	31.0		$	(96.8	)	$	0.0		$	(27.1	)	$	(16.3	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	82.4		$	56.7		$	(67.0	)	$	6.9		$	(14.3	)	$	(3.9	)

A curtailment loss and special termination benefits were recognized in 2014 for the Retirement Plan due to the expected sale of TECO Coal. The sale was completed in 2015. Additionally, a curtailment gain was recognized for the OPEB plan due to the termination of the TECO Coal plan effective Jan. 1, 2015.

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $3.5 million and $0.1 million, respectively. The estimated prior service cost for the other postretirement benefit plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year is $0.5 million.

In addition, the estimated net loss for the defined benefit pension plans that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year are $9.8 million. There will be an estimated $2.1 million prior service cost that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year for the other postretirement benefit plan. Additionally, $1.1 million of NMGC’s pre-acquisition regulated asset will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year.

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

	Pension Benefits									Other Benefits
	2015			2014 (1)			2013			2015			2014			2013
Discount rate		4.258	%	5.118%/4.277%/4.331%				4.196	%		4.211	%		5.096	%		4.180	%
Expected long-term return on plan assets		7.00	%	7.25%/7.00%/7.00%				7.50	%		5.75			5.75		n/a
Rate of compensation increase		3.87	%		3.73	%		3.76	%		3.86	%		3.71	%		3.74	%
Healthcare cost trend rate
Initial rate	n/a			n/a			n/a				7.09	%		7.25	%		7.50	%
Ultimate rate	n/a			n/a			n/a				4.57	%		4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			n/a			2025			2025			2025

(1) TECO Energy performed a valuation as of Jan. 1, 2014. TECO remeasured its Retirement Plan on Sept. 2, 2014 for the acquisition of NMGC and on Oct. 31, 2014 for the expected curtailment of TECO Coal, resulting in the respective updated discount rates and EROAs.

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The discount rate assumption used to determine the 2015 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation at the measurement date. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2015, TECO Energy’s pension plan assets decreased approximately 3.5%.

The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on expense:

		1%		1%
(millions)	Increase		Decrease
Effect on periodic cost	$	0.4	$	(0.3	)

Pension Plan Assets

Pension plan assets (plan assets) are primarily invested in a mix of equity and fixed income securities. The company’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

	Target  Allocation			Actual  Allocation, End of Year
Asset Category				2015			2014
Equity securities	47%-53%				53	%		50	%
Fixed income securities	47%-53%				47	%		50	%
Total		100	%		100	%		100	%

The company reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. The company will continue to monitor the matching of plan assets with plan liabilities.

The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). Investments are valued using quoted market prices on an exchange when available. Such investments are classified Level 1. In some cases where a market exchange price is available but the investments are traded in a secondary market, acceptable practical expedients are used to calculate fair value.

If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2015 and 2014.

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(millions)	At Fair Value as of Dec. 31, 2015
	Level 1			Level 2			Level  3		Using NAV (1)		Total
Net cash
Cash	$	1.9		$	0.0		$	0.0	$	0.0	$	1.9
Accounts receivable		14.3			0.0			0.0		0.0		14.3
Accounts payable		(27.2	)		0.0			0.0		0.0		(27.2	)
Total net cash		(11.0	)		0.0			0.0		0.0		(11.0	)
Cash equivalents
Money markets		0.0			0.2			0.0		0.0		0.2
Discounted notes		0.0			0.7			0.0		0.0		0.7
Short-term investment funds (STIFs) (1)		0.0			0.0			0.0		12.4		12.4
Total cash equivalents		0.0			0.9			0.0		12.4		13.3
Equity securities
Common stocks		90.9			0.0			0.0		0.0		90.9
American depository receipts (ADRs)		5.7			0.0			0.0		0.0		5.7
Real estate investment trusts (REITs)		4.8			0.0			0.0		0.0		4.8
Commingled fund		0.0			53.7			0.0		0.0		53.7
Mutual funds (1)		0.0			0.0			0.0		175.6		175.6
Total equity securities		101.4			53.7			0.0		175.6		330.7
Fixed income securities
Municipal bonds		0.0			5.0			0.0		0.0		5.0
Government bonds		0.0			56.2			0.0		0.0		56.2
Corporate bonds		0.0			32.2			0.0		0.0		32.2
Asset backed securities (ABS)		0.0			0.3			0.0		0.0		0.3
Mortgage-backed securities (MBS), net short sales		0.0			8.7			0.0		0.0		8.7
Collateralized mortgage obligations (CMOs)		0.0			1.5			0.0		0.0		1.5
Commingled fund (1)		0.0			0.0			0.0		117.9		117.9
Mutual fund (1)		0.0			0.0			0.0		71.3		71.3
Total fixed income securities		0.0			103.9			0.0		189.2		293.1
Derivatives
Swaps		0.0			(0.9	)		0.0		0.0		(0.9	)
Purchased options (swaptions)		0.0			1.1			0.0		0.0		1.1
Written options (swaptions)		0.0			(1.0	)		0.0		0.0		(1.0	)
Total derivatives		0.0			(0.8	)		0.0		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.0		0.1
Total	$	90.4		$	157.8		$	0.0	$	377.2	$	625.4

(1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet.

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(millions)	At Fair Value as of Dec. 31, 2014
	Level 1			Level 2			Level  3		Using NAV (1)		Total
Net cash
Cash	$	0.4		$	0.0		$	0.0	$	0.0	$	0.4
Accounts receivable		1.4			0.0			0.0		0.0		1.4
Accounts payable		(5.3	)		0.0			0.0		0.0		(5.3	)
Total net cash		(3.5	)		0.0			0.0		0.0		(3.5	)
Cash equivalents
Treasury bills (T bills)		0.0			0.2			0.0		0.0		0.2
Discounted notes		0.0			8.8			0.0		0.0		8.8
Short-term investment funds (STIFs) (1)		0.0			0.0			0.0		7.6		7.6
Total cash equivalents		0.0			9.0			0.0		7.6		16.6
Equity securities
Common stocks		98.0			0.0			0.0		0.0		98.0
American depository receipts (ADRs)		1.3			0.0			0.0		0.0		1.3
Real estate investment trusts (REITs)		2.5			0.0			0.0		0.0		2.5
Preferred stock		0.8			0.0			0.0		0.0		0.8
Commingled fund		0.0			45.6			0.0		0.0		45.6
Mutual funds (1)		0.0			0.0			0.0		171.3		171.3
Total equity securities		102.6			45.6			0.0		171.3		319.5
Fixed income securities
Municipal bonds		0.0			6.1			0.0		0.0		6.1
Government bonds		0.0			47.9			0.0		0.0		47.9
Corporate bonds		0.0			22.0			0.0		0.0		22.0
Asset backed securities (ABS)		0.0			0.3			0.0		0.0		0.3
Mortgage-backed securities (MBS), net short sales		0.0			9.6			0.0		0.0		9.6
Collateralized mortgage obligations (CMOs)		0.0			2.0			0.0		0.0		2.0
Commingled fund (1)		0.0			0.0			0.0		129.2		129.2
Mutual fund (1)		0.0			0.0			0.0		98.6		98.6
Total fixed income securities		0.0			87.9			0.0		227.8		315.7
Derivatives
Short futures		0.0			(0.3	)		0.0		0.0		(0.3	)
Purchased options (swaptions)		0.0			0.7			0.0		0.0		0.7
Written options (swaptions)		0.0			(0.8	)		0.0		0.0		(0.8	)
Total derivatives		0.0			(0.4	)		0.0		0.0		(0.4	)
Miscellaneous		0.0			0.1			0.0		0.0		0.1
Total	$	99.1		$	142.2		$	0.0	$	406.7	$	648.0

(1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet.

The following list details the pricing inputs and methodologies used to value the investments in the pension plan:

● The primary pricing inputs in determining the fair value of the Level 1 assets are closing quoted prices in active markets.

● The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes sourced by State Street Custody System.  The fund holds primarily international equity securities that are actively traded in over-the-counter markets. The fund honors subscription and redemption activity on an “as of” basis.

● The money markets are valued at cost due to their short-term nature. Discounted notes are valued at amortized cost.

● The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMO are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information.

● Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

● Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

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● Options are valued using the bid-ask spread and the last price.

● The STIF is valued at NAV as determined by JP Morgan. The funds are open-end investments. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV.

● The primary pricing inputs in determining the equity mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV.

● The primary pricing input in determining the fair value of the fixed asset mutual fund is its NAV. It is an unregistered open-ended mutual fund.

● The fixed income commingled fund is a private fund valued at NAV. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15^th calendar day of the month. Redemptions are honored on the 15^th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.

Additionally, the unqualified SERP had $43.5 million and $0.9 million of assets as of Dec. 31, 2015 and 2014, respectively. Since the plan is unqualified, its assets are included in the “Deferred charges and other assets” line item in TECO Energy’s Consolidated Balance Sheets rather than being netted with the related liability. The fund holds investments in a money market fund, which is valued at cost due to its short-term nature, making this a level 2 asset. The SERP was fully funded as of Dec. 31, 2015.

Other Postretirement Benefit Plan Assets

NMGC’s other postretirement benefits plan had $20.6 million and $18.8 million of assets as of Dec. 31, 2015 and 2014, respectively. The majority of the assets are valued at the cash surrender value of NMGC participant life insurance policies and are considered Level 2 assets. In accordance with NMPRC requirements, NMGC must fund to a trust, on an annual basis, an amount equal to the other postretirement expense allowed in its last base rate case.

Contributions

The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.

WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions were based on a percentage of the funding target until 2013, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In August 2014, the President signed into law HAFTA, which modified MAP-21. HAFTA and MAP-21 provide funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The company expects the required minimum pension contributions to be lower than the levels previously projected; however, the company plans on funding at levels above the required minimum pension contributions under HAFTA and MAP-21. In November 2015, the President signed into law the Bipartisan Budget Act of 2015, which extended pension funding relief of MAP-21 and HAFTA through 2022.

The qualified pension plan’s actuarial value of assets, including credit balance, was 120.1% of the Pension Protection Act funded target as of Jan. 1, 2015 and is estimated at 114.1% of the Pension Protection Act funded target as of Jan. 1, 2016.

The company’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. The company made $55.0 million and $47.5 million of contributions to this plan in 2015 and 2014, respectively, which met the minimum funding requirements for both 2015 and 2014. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. The company estimates its contribution in 2016 to be $37.4 million and expects to make contributions from 2017 to 2020 in the range of $12.2 to $44.6 million per year based on current assumptions. These contributions are in excess of the minimum required contribution under ERISA guidelines.

The company made contributions of $43.4 million and $1.2 million to the SERP in 2015 and 2014, respectively. The company’s contribution in October 2015 to the SERP’s trust was made in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded

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amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current participants. Since the SERP is fully funded, the company does not expect to make significant contributions to this plan in 2016.

The company funds its other postretirement benefits periodically to meet benefit obligations. The company’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. The company’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2016, the company expects to make contributions of about $14.3 million. This includes $3.6 million that NMGC is required to fund to its trust in accordance with NMPRC requirements. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments

(including projected service and net of employee contributions)

			Other
	Pension		Postretirement
(millions)	Benefits		Benefits
2016	$	77.8	$	11.5
2017		49.5		11.9
2018		52.7		12.5
2019		59.2		13.0
2020		54.9		13.3
2021-2025		299.1		68.6

Defined Contribution Plan

The company has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. The company and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective Jan. 1, 2015, employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals. During the period from April 2013 to December 2014, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions, with an additional incentive match of up to 40%. For the years ended Dec. 31, 2015, 2014 and 2013, the company and its subsidiaries recognized expense totaling $11.1 million, $13.1 million and $11.3 million, respectively, related to the matching contributions made to this plan.

6. Short-Term Debt

At Dec. 31, 2015 and Dec. 31, 2014, the following credit facilities and related borrowings existed:

Credit Facilities

	Dec. 31, 2015						Dec. 31, 2014
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding  (1)		Outstanding		Facilities		Outstanding  (1)		Outstanding
Tampa Electric  Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	12.0	$	0.6
3-year accounts receivable facility (3)		150.0		61.0		0.0		150.0		46.0		0.0
TECO Energy/TECO  Finance:
5-year facility (2)(4)		300.0		163.0		0.0		300.0		50.0		0.0
New Mexico Gas Company:
5-year facility (2)		125.0		23.0		1.7		125.0		31.0		1.7
Total	$	900.0	$	247.0	$	2.2	$	900.0	$	139.0	$	2.3

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(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Dec. 17, 2018.

(3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.

(4) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.

At Dec. 31, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at Dec. 31, 2015 and 2014 was 1.29% and 1.16%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Pursuant to the Loan Agreement, TRC will pay program and liquidity fees, which total 65 basis points as of Dec. 31, 2015. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either the BTMU’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank deposit rate (if available) plus a margin. In addition, under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of Dec. 31, 2015, TEC and TRC were in compliance with the requirements of the Loan Agreement.

TECO Energy Credit Agreement Assigned to and Assumed by NMGC

On Dec. 17, 2013, TECO Energy entered into a $125 million bank credit facility, pursuant to which it was the initial party to the Credit Agreement (the NMGC Credit Agreement). TECO Energy had no rights or obligations to borrow under the NMGC Credit Agreement, which was entered into solely with the intent of it being assigned to, and assumed by, NMGC upon the closing of the Acquisition. Pursuant to the terms of the NMGC Credit Agreement, on Sept. 2, 2014, TECO Energy designated NMGC as the borrower under the NMGC Credit Agreement by delivering a Joinder and Release Agreement duly executed by TECO Energy and NMGC, whereupon (i) NMGC became the borrower for all purposes of the NMGC Credit Agreement and the other credit facility documents under the NMGC Credit Agreement, and (ii) TECO Energy ceased to be a party to the NMGC Credit Agreement and any further rights or obligations thereunder. The NMGC Credit Agreement (i) has a maturity date of Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) allows NMGC to borrow funds at a rate equal to the one-month London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows NMGC to borrow funds at an interest rate equal to a margin plus the higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows NMGC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (v) allows NMGC to request the lenders to increase their commitments under the credit facility by up to $75 million in the aggregate; and (vi) includes a $40 million letter of credit facility.

On Sept. 30, 2014, NMGC entered into an amendment of the NMGC Credit Agreement, which reallocated commitments among the lenders and made certain other technical changes.

Amendment of Tampa Electric Company Credit Facility

On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continued to allow TEC, as borrower, to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

On Sept. 30, 2014, TEC entered into an amendment of its $325 million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes.

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Amendments of TECO Energy/TECO Finance Credit Facility

On Dec. 17, 2013, TECO Energy amended and restated its $200 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement (the TECO Credit Facility).  The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues with TECO Energy as guarantor and its wholly-owned subsidiary, TECO Finance, as borrower; (iii) allows TECO Finance to borrow funds at an interest rate equal to the London interbank deposit rate plus a margin; (iv) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (v) allows TECO Finance to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans;  (vi) allows TECO Finance to request the lenders to increase their commitments under the credit facility by $100 million in the aggregate; (vii) continues to include a $200 million letter of credit facility; and (viii) made other technical changes. 

The Fourth Amended and Restated Credit Agreement includes the changes made in Amendment No. 1 dated June 24, 2013 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011. Amendment No. 1 was entered into to accommodate the acquisition of NMGI, as described in Note 21 herein, by (i) temporarily changing the total debt to total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closed, TECO Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the previous capitalization ratio of 0.65 to 1.00 and (ii) changed the definition of Permitted Liens to permit the acquisition of a significant subsidiary that has outstanding secured debt and made other changes matching the corresponding covenant in the Bridge Facility. TECO Energy and TECO Finance entered into a $1.075 billion senior unsecured bridge credit agreement on June 24, 2013, among TECO Energy as guarantor, TECO Finance as borrower, Morgan Stanley Senior Funding, Inc. (Morgan Stanley) as administrative agent, sole lead arranger and sole book runner, and Morgan Stanley together with nine other banks as lenders in the Bridge Facility.

On Sept. 30, 2014, the TECO Credit Facility was amended to increase total commitments to $300 million and to reallocate commitments among the lenders.

7. Long-Term Debt

At Dec. 31, 2015, total long-term debt had a carrying amount of $3,850.2 million and an estimated fair market value of $4,061.6 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $3,628.5 million and an estimated fair market value of $3,987.8 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

TECO Finance is a wholly owned subsidiary of TECO Energy. TECO Finance’s sole purpose is to raise capital for TECO Energy’s diversified businesses. TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s securities.

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.

TECO Energy’s gross maturities and annual sinking fund requirements of long-term debt for 2016 through 2020 and thereafter are as follows:

Long-Term Debt Maturities

													Total
As of Dec. 31, 2015													Long-Term
(millions)	2016		2017		2018		2019		2020		Thereafter		Debt
TECO Finance	$	250.0	$	300.0	$	250.0	$	0.0	$	300.0	$	0.0	$	1,100.0
Tampa Electric		83.3		0.0		254.2		0.0		0.0		1,666.7		2,004.2
PGS		0.0		0.0		50.0		0.0		0.0		211.7		261.7
NMGC		0.0		0.0		0.0		0.0		0.0		270.0		270.0
NMGI		0.0		0.0		0.0		50.0		0.0		150.0		200.0
Total long-term debt maturities	$	333.3	$	300.0	$	554.2	$	50.0	$	300.0	$	2,298.4	$	3,835.9

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Issuance of TECO Finance Floating Rate Notes due 2018

On Apr. 10, 2015, TECO Finance completed an offering of $250 million aggregate principal amount of floating rate notes due 2018 (the 2018 Notes), which are guaranteed by TECO Energy. The 2018 Notes were sold at par and mature on Apr. 10, 2018. The 2018 Notes bear interest at a floating rate that is reset quarterly based on the three-month LIBOR plus 60 basis points. The 2018 Notes are not  subject to redemption prior to maturity. The 2018 Notes are effectively subordinated to existing and future liabilities of TECO Energy’s subsidiaries to their respective creditors, and also are effectively subordinated to any secured debt that TECO Finance and TECO Energy incur to the extent of the value of the assets securing that indebtedness.

The offering resulted in net proceeds to TECO Finance (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $248.6 million. TECO Finance used these net proceeds to repay borrowings under the TECO Finance credit facility and to fund a portion of the payment of $191 million of TECO Finance notes that matured in May 2015.

Issuance of Tampa Electric Company 4.20% Notes due 2045

On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the TEC 2015 Notes).  The TEC 2015 Notes were sold at 99.814% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any part of the TEC 2015 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2015 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the TEC 2015 Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the TEC 2015 Notes, in whole or in part, at 100% of the principal amount of the TEC 2015 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Issuance of Tampa Electric Company 4.35% Notes due 2044

On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the TEC 2014 Notes). The TEC 2014 Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the TEC 2014 Notes at its option at any time and from time to time before Nov. 15, 2043 at a redemption price equal to the greater of (i) 100% of the principal amount of TEC 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the TEC 2014 Notes, in whole or in part, at 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Issuance of New Mexico Gas Intermediate Senior Unsecured Notes

On Sept. 2, 2014, NMGI completed an offering of $50 million aggregate principal amount of 2.71% Series A Senior Unsecured Notes due July 30, 2019 (the NMGI Series A 2014 Notes) and $150 million aggregate principal amount of 3.64% Series B Senior Unsecured Notes due July 30, 2024 (the NMGI Series B 2014 Notes and, with the NMGI Series A 2014 Notes, the NMGI 2014 Notes). The NMGI 2014 Notes were sold at 100% of par. The offering resulted in net proceeds to NMGI (after deducting underwriting discounts, commissions and estimated offering expenses) of approximately $198.4 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGI may redeem all or any part of the NMGI 2014 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of NMGI 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the NMGI notes to be redeemed, discounted at an applicable reinvestment yield (as defined in the note purchase agreement), plus 50 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. The NMGI 2014 Notes were issued in a private placement that was not subject to the registration requirements of the Securities Act of 1933.

Issuance of New Mexico Gas Company Senior Unsecured 3.54 % Notes due 2026

On Sept. 2, 2014, NMGC completed an offering of $70 million aggregate principal amount of 3.54% Senior Unsecured Notes due July 30, 2026 (the NMGC 2014 Notes). The NMGC 2014 Notes were sold at 100% of par. The offering resulted in net proceeds to NMGC (after deducting underwriting discounts, commissions and estimated offering expenses) of approximately $69.3 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGC may redeem all or any part of the NMGC 2014 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the

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principal amount of NMGC 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the notes to be redeemed, discounted at an applicable reinvestment yield (as defined in the note purchase agreement), plus 50 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. The NMGC 2014 Notes were issued in a private placement that was exempt from the registration requirements of the Securities Act of 1933.

Amendment of New Mexico Gas Company 4.87 % Notes due 2021

On Feb. 8, 2011, NMGC issued secured notes in an aggregate principal amount of $200 million (NMGC 2011 Notes), maturing Feb. 8, 2021. The NMGC 2011 Notes were issued in a private placement that was exempt from the registration requirements of the Securities Act of 1933.

On July 16, 2014, NMGC received approvals from the noteholders of the NMGC 2011 Notes to release the collateral securing the NMGC 2011 Notes by amending the existing note purchase agreement. The amendments to the note purchase agreement were subject to the approval of the NMPRC, and on Oct. 22, 2014, NMGC received the required NMPRC approval of the amendments. On Oct. 30, 2014, the amendments became effective, the collateral securing the NMGC 2011 Notes was released and other technical changes were made to the NMGC 2011 Notes.

Purchase in Lieu of Redemption of Revenue Refunding Bonds

On Mar. 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds). On Mar. 19, 2008, the HCIDA had remarketed the Series 2006 HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from Mar. 19, 2008 to Mar. 15, 2012. TEC is responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.

On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from Mar. 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.

As of Dec. 31, 2015, $232.6 million of bonds purchased in lieu of redemption were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

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At Dec. 31, 2015 and 2014, TECO Energy had the following long-term debt outstanding:

Long-Term Debt
(millions)		Due	2015		2014
TECO Finance	Notes (1)(2) : 6.75% (3)	2015	$	0.0	$	191.2
	4.00% (3)	2016		250.0		250.0
	6.57% (3)	2017		300.0		300.0
	Floating rate notes	2018		250.0		0.0
	5.15% (3)	2020		300.0		300.0
	Total long-term debt of TECO Finance			1,100.0		1,041.2
Tampa Electric	Installment contracts payable (4) :
	5.65% Refunding  bonds	2018		54.2		54.2
	Variable rate  bonds repurchased in 2008 (5)	2020		0.0		0.0
	5.15% Refunding bonds repurchased in 2013 (6)	2025		0.0		0.0
	1.5% Term rate bonds repurchased in 2011 (7)	2030		0.0		0.0
	5.0% Refunding bonds repurchased in 2012 (8)	2034		0.0		0.0
	Notes (1)(2) : 6.25%	2015-2016		83.3		166.7
	6.10%	2018		200.0		200.0
	5.40%	2021		231.7		231.7
	2.60%	2022		225.0		225.0
	6.55%	2036		250.0		250.0
	6.15%	2037		190.0		190.0
	4.10%	2042		250.0		250.0
	4.35%	2044		290.0		290.0
	4.20%	2045		230.0		0.0
	Total long-term debt of Tampa Electric			2,004.2		1,857.6
PGS	Notes (2)(3) : 6.10%	2018		50.0		50.0
	5.40%	2021		46.7		46.7
	2.60%	2022		25.0		25.0
	6.15%	2037		60.0		60.0
	4.10%	2042		50.0		50.0
	4.35%	2044		10.0		10.0
	4.20%	2045		20.0		0.0
	Total long-term debt of PGS			261.7		241.7
NMGI	Notes (2)(3) : 2.71%	2019		50.0		50.0
	3.64%	2024		150.0		150.0
	Total long-term debt of NMGI			200.0		200.0
NMGC	Notes (2)(3) : 4.87%	2021		200.0		200.0
	3.54%	2026		70.0		70.0
	Total long-term debt of NMGC			270.0		270.0
	Total long-term debt of TECO Energy			3,835.9		3,610.5
Unamortized debt discount, net				14.3		18.0
Total carrying amount of long-term debt				3,850.2		3,628.5
Less amount due within one year				333.3		274.5
Total long-term debt			$	3,516.9	$	3,354.0

(1) Guaranteed by TECO Energy.

(2) These long-term debt agreements contain various restrictive financial covenants.

(3) These securities are subject to redemption in whole or in part, at any time, at the option of the issuer.

(4) Tax-exempt securities.

(5) In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC.  These held variable rate bonds have a par amount of $20.0 million due in 2020.

(6) In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC.  These held term rate bonds have a par amount of $51.6 million due in 2025.

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(7) In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC.  These held term rate bonds have a par amount of $75.0 million due in 2030.

(8) In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC.  These held term rate bonds have a par amount of $86.0 million due in 2034.

8. Preferred Stock

Preferred stock of TECO Energy – $1 par

10 million shares authorized, none outstanding.

Preference stock (subordinated preferred stock) of Tampa Electric – no par

2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – no par

2.5 million shares authorized, none outstanding.

Preferred stock of Tampa Electric – $100 par

1.5 million shares authorized, none outstanding.

9. Common Stock

Pending Merger with Emera

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest.

The Merger Agreement with Emera restricts TECO Energy and its subsidiaries, without Emera’s prior written consent, from issuing equity or equity equivalents and from paying quarterly cash dividends in excess of levels agreed upon in the Merger Agreement until the Merger occurs or the Merger Agreement is terminated.  

See Note 21 for additional information regarding the pending Merger.

Public Offering of 15.5 million in Common Shares

On July 1, 2014, the company entered into an underwriting agreement with Morgan Stanley & Co. LLC, as representative of the several underwriters named therein, pursuant to which the company agreed to offer and sell 15.5 million shares of its common stock in an underwritten public offering at a public offering price of $18.10 per share. The company received approximately $271 million in net proceeds from the offering after underwriting fees and offering expenses. The shares were delivered to the underwriters on July 8, 2014.

Pursuant to the terms of the underwriting agreement, the company granted the underwriters a 30-day option to purchase up to an additional 2.3 million shares. The company received approximately $21 million of net proceeds when the underwriters exercised this option for an additional 1.2 million shares.

The company used the net proceeds from the offering to fund, in part, the acquisition of NMGI and for general corporate purposes.

Stock-Based Compensation

On May 5, 2010, the shareholders approved the 2010 Equity Incentive Plan (2010 Plan) as an amendment and restatement of both the company’s 2004 Equity Incentive Plan (2004 Plan) and the 1997 Director Equity Plan (1997 Plan, and together with the 2004 Plan, the Old Plans). The 2010 Plan superseded the Old Plans and no additional grants will be made under the Old Plans. The rights of the holders of outstanding options, unvested restricted stock or other outstanding awards under the Old Plans were not affected. The purpose of the 2010 Plan is to attract and retain key employees and non-employee directors, to enable the company to provide equity-based incentives relating to achieving long-range performance goals and to enable award recipients to participate in the long-term growth of the company. The 2010 Plan is administered by the Compensation Committee of the Board of Directors (Committee), which may grant awards to any employee of the company who is capable of contributing significantly to the successful performance of the company. Only the Board of Directors may grant awards to any non-employee members of the Board of Directors.

The 2010 Plan amended the 2004 Plan. The amendment reduced the number of shares of common stock subject to grants to 4.0 million shares (a reduction of 3.0 million shares), removed the cap on shares available for stock grant, placed various limitations

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on the terms of awards granted under the 2010 Plan, removed the ability to make awards to consultants of the company and reapproved the business criteria upon which objective performance goals may be established by the Committee to continue to permit the company to take federal tax deductions for performance-based awards made to certain senior officers under Section 162(m) of the tax code.

The types of awards that can be granted under the 2010 Plan include stock options, stock grants and stock equivalents. Stock options were last awarded in 2006 under the Old Plans. Stock grants and time-vested restricted stock are valued at the fair market value on the date of grant, with expense recognized over the vesting period, which is normally three years. Time-vested restricted stock granted to directors vest in one year. Performance-based restricted stock has been granted to officers and employees, with shares potentially vesting after three years. The total awards for performance-based restricted stock vest based on the total return of TECO Energy common stock compared to a peer group of utility stocks. The performance-based grants can vest in amounts ranging between 0% and 150% of the original grant. Beginning in 2015, the total awards for performance-based restricted stock vest based on achievement of earnings growth, with the ability to earn more shares based on total return of TECO Energy common stock compared to a peer group of utility stocks. The 2015 performance-based grants can vest in amounts ranging between 0% and 200% of the original grant. Dividends are paid on all time-vested stock grants during the vesting period. Dividends are accrued during the vesting period on all performance stock granted and paid at vesting date on the shares that vest. The value of time-vested restricted stock and stock grants are based on the fair market value of TECO Energy common stock at the time of grant. The Merger Agreement with Emera contains provisions regarding the vesting of outstanding grants which would apply upon closing of the Merger.

The fair market value of stock options is determined using the Black-Scholes valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of options granted is based on accounting guidance for the simplified method of averaging the vesting term and the original contractual term; the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the option); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant.

The fair market value of performance-based restricted stock awards is determined using the Monte-Carlo valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of the awards is based on the performance measurement period (which is generally three years); the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the award); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant, with continuous compounding.

Assumptions	2015			2014			2013
Assumptions applicable to performance-based restricted stock
Risk-free interest rate		0.83	%		0.68	%		0.41	%
Expected lives (in years)		3			3			3
Expected stock volatility		14.78	%		17.36	%		19.04	%
Dividend yield		3.98	%		5.13	%		4.83	%

In 2015, 2014 and 2013, 0.7 million, 0.8 million and 0.7 million shares of restricted stock were granted, respectively, with weighted-average fair value per share of $22.96, $14.69 and $17.21, respectively. The total fair market value of awards vesting during 2015, 2014 and 2013 was $7.5 million, $3.6 million and $3.5 million, respectively, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Dec. 31, 2015, there was $13.2 million of unrecognized compensation cost related to all non-vested awards that is expected to be recognized over a weighted-average period of two years.

The following table provides additional information on compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards.

(millions)	2015		2014		2013
Compensation costs (1)	$	13.1	$	12.7	$	13.5
Income tax benefits (1)		5.1		4.9		5.2
Excess tax benefits (2)		0.0		0.4		0.0

(1) Reflected on the Consolidated Statements of Income.

(2) Reflected as financing activities on the Consolidated Statements of Cash Flows.

The aggregate intrinsic value of stock options exercised was $2.9 million, $2.7 million and $2.4 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively. Cash received from option exercises under all share-based payment arrangements was $9.4 million, $10.8 million and $6.7 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively. The income tax benefit

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realized from stock option exercises was $1.1 million, $1.0 million and $0.8 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively.

A summary of non-vested shares of restricted stock is shown as follows:

Nonvested Restricted Stock

	Time-Based Restricted					Performance-Based
	Stock (1)					Restricted Stock (1)
				Weighted -					Weighted-
				Avg. Grant					Avg. Grant
	Number of			Date		Number of			Date
	Shares			Fair Value		Shares			Fair Value
	(thousands)			(per  share)		(thousands)			(per  share)
Nonvested balance at Dec. 31, 2014		668		$	17.56		1,515		$	15.44
Granted		213		$	21.34		445		$	23.72
Vested		(273	)	$	17.96		(626	)	$	15.94
Forfeited		(19	)	$	17.78		(43	)	$	16.05
Nonvested balance at Dec. 31, 2015		589		$	18.74		1,291		$	18.06

(1) The weighted-average remaining contractual term of restricted stock is two years.

Stock option transactions are summarized as follows:

Stock Options

						Weighted-Avg.		Aggregate
	Number of			Weighted-Avg.		Remaining		Intrinsic
	Shares			Option Price		Contractual		Value
	(thousands)			(per share)		Term (years)		(millions)
Outstanding balance at Dec. 31, 2014		840		$	16.32
Granted		0		$	0.00
Exercised		(580	)	$	16.30
Cancelled		(6	)	$	18.87
Outstanding balance at Dec. 31, 2015 (1)		254		$	16.30		1	$	2.6
Exercisable at Dec. 31, 2015 (1)		254		$	16.30		1	$	2.6
Available for future grant at Dec. 31, 2015		2,429

(1) Option prices are $16.30 per share.

Direct Stock Purchase and Dividend Reinvestment Plan

In September 2014, the Direct Stock Purchase and Dividend Plan amended and restated the 1992 Dividend Reinvestment and Common Stock Purchase Plan. TECO Energy purchased shares on the open market for this plan in 2015, 2014 and 2013, resulting in no increase in shares outstanding.

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10. Other Comprehensive Income

TECO Energy reported the following OCI (loss) for the years ended Dec. 31, 2015, 2014 and 2013, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s benefit plans:

(millions)	Gross			Tax			Net
2015
Unrealized gain (loss) on cash flow hedges	$	4.3		$	(1.5	)	$	2.8
Reclassification from AOCI to net income (1)		1.4			(0.7	)		0.7
Gain (Loss) on cash flow hedges		5.7			(2.2	)		3.5
Amortization of unrecognized benefit costs and other (2)		3.4			(1.3	)		2.1
Change in benefit obligation due to valuation (3)		(15.5	)		5.7			(9.8	)
Recognized cost due to settlement (4)		12.1			(4.4	)		7.7
Total other comprehensive income (loss)	$	5.7		$	(2.2	)	$	3.5
2014
Unrealized gain (loss) on cash flow hedges	$	(0.5	)	$	0.2		$	(0.3	)
Reclassification from AOCI to net income (1)		1.6			(0.6	)		1.0
Gain (Loss) on cash flow hedges		1.1			(0.4	)		0.7
Amortization of unrecognized benefit costs and other (2)		(4.8	)		1.8			(3.0	)
Increase in unrecognized postemployment costs (5)		(12.9	)		4.7			(8.2	)
Change in benefit obligation due to valuation (6)		12.6			(4.6	)		8.0
Total other comprehensive income (loss)	$	(4.0	)	$	1.5		$	(2.5	)
2013
Unrealized gain (loss) on cash flow hedges	$	1.0		$	(0.4	)	$	0.6
Reclassification from AOCI to net income (1)		1.3			(0.5	)		0.8
Gain (Loss) on cash flow hedges		2.3			(0.9	)		1.4
Amortization of unrecognized benefit costs and other (2)		23.6			(8.8	)		14.8
Recognized costs due to settlement		2.6			(1.0	)		1.6
Total other comprehensive income (loss)	$	28.5		$	(10.7	)	$	17.8

(1) Related to interest rate contracts in Interest expense and commodity contracts recognized in Income (loss) from discontinued operations.

(2) Related to postretirement and postemployment benefits.  See Note 5 for additional information.

(3) Related to the transfer of employees and their associated postretirement benefits from TEC to TSI, the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas TSI recognized them in AOCI.

(4) Related to the settlement of the TECO Coal black lung obligation at the closing of the sale. See Note 19 for additional information.

(5) Amounts reflect an out-of-period adjustment related to TECO Coal’s unfunded black lung liability.

(6) Includes an adjustment to eliminate TECO Coal’s OPEB liability.  See Note 5 for additional information.

Accumulated Other Comprehensive Loss

(millions) Dec. 31,	2015			2014
Unamortized pension losses and prior service credits (1)	$	(34.2	)	$	(22.5	)
Unamortized other benefit gains, prior service costs and transition obligations (2)		25.6			13.9
Net unrealized losses from cash flow hedges (3)		(3.6	)		(7.1	)
Total accumulated other comprehensive loss	$	(12.2	)	$	(15.7	)

(1) Net of tax benefit of $21.5 million and $13.8 million as of Dec. 31, 2015 and 2014, respectively.

(2) Net of tax expense of $16.1 million and $8.3 million as of Dec. 31, 2015 and 2014, respectively. The Dec. 31, 2014 balance included a $7.7 million loss related to TECO Coal’s unfunded black lung liability that was reclassified from AOCI to net income from discontinued operations upon the settlement of the black lung obligation at the sale date. See Note 5.

(3) Net of tax benefit of $2.3 million and $4.5 million as of Dec. 31, 2015 and 2014, respectively.

11. Earnings Per Share

In accordance with accounting standards for the calculation of EPS, TECO Energy follows the two-class method for computing EPS. These standards define share-based payment awards that participate in dividends prior to vesting as participating securities that should be included in the earnings allocation in computing EPS under the two-class method.

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The two-class method of calculating EPS requires TECO Energy to calculate EPS for its common stock and its participating securities (time-vested restricted stock and performance-based restricted stock) based on dividends declared and the pro-rata share each has to undistributed earnings. The application of the two-class method did not have a material effect on TECO Energy’s EPS calculations.

(millions, except per share amounts)	2015			2014			2013 (1)
Basic earnings per share
Net income from continuing operations	$	241.2		$	206.4		$	188.7
Amount allocated to nonvested participating shareholders		(0.7	)		(0.7	)		(0.6	)
Income before discontinued operations available to     common shareholders—Basic	$	240.5		$	205.7		$	188.1
Income (loss) from discontinued operations	$	(67.7	)	$	(76.0	)	$	9.0
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0
Income (loss) from discontinued operations —Basic	$	(67.7	)	$	(76.0	)	$	9.0
Net income	$	173.5		$	130.4		$	197.7
Amount allocated to nonvested participating shareholders		(0.7	)		(0.7	)		(0.6	)
Net income available to common shareholders—Basic	$	172.8		$	129.7		$	197.1
Average common shares outstanding—Basic		233.1			223.1			215.0
Earnings per share from continuing operations available to    common shareholders—Basic	$	1.03		$	0.92		$	0.88
Earnings per share from discontinued operations available to common    shareholders—Basic		(0.29	)		(0.34	)		0.04
Earnings per share attributable to TECO Energy available     to common shareholders—Basic	$	0.74		$	0.58		$	0.92
Diluted earnings per share
Net income from continuing operations	$	241.2		$	206.4		$	188.7
Amount allocated to nonvested participating shareholders		(0.7	)		(0.7	)		(0.6	)
Income before discontinued operations available to    common shareholders—Diluted	$	240.5		$	205.7		$	188.1
Income (loss) from discontinued operations	$	(67.7	)	$	(76.0	)	$	9.0
Amount allocated to nonvested participating shareholders		0.0			0.0			0.0
Income (loss) from discontinued operations available to common    shareholders—Diluted	$	(67.7	)	$	(76.0	)	$	9.0
Net income	$	173.5		$	130.4		$	197.7
Amount allocated to nonvested participating shareholders		(0.7	)		(0.7	)		(0.6	)
Net income available to common shareholders—Diluted	$	172.8		$	129.7		$	197.1
Unadjusted average common shares outstanding—Diluted		233.1			223.1			215.0
Assumed conversion of stock options, unvested restricted    stock and contingent performance shares, net		1.4			0.6			0.5
Average common shares outstanding—Diluted		234.5			223.7			215.5
Earnings per share from continuing operations available to    common shareholders—Diluted	$	1.03		$	0.92		$	0.88
Earnings per share from discontinued operations available to common    shareholders—Diluted		(0.29	)		(0.34	)		0.04
Earnings per share available to common shareholders—Diluted	$	0.74		$	0.58		$	0.92
Anti-dilutive shares		0.0			0.0			0.0

(1) All prior periods presented reflect the classification of TECO Coal as discontinued operations (see Note 19).

12. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does

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not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

Tampa Electric Legal Proceedings

A 36-year-old man died from mesothelioma in March 2014. His estate and his family sued Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and 14 other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to the company’s financial position as of Dec. 31, 2015.

A 33-year-old man made contact with a primary line in June 2013, suffering severe burns. He and his wife sued Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence.  Plaintiffs' case against Tampa Electric alleged, among other things, negligence and loss of consortium. Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to the company’s financial position as of Dec. 31, 2015.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in late 2016.

New Mexico Gas Company Legal Proceedings

In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).  

In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.”  

In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to the company’s financial position as of Dec. 31, 2015.

In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary judgement in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgement.  

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration.

On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.

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Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding.

While the duration of the annulment proceedings is uncertain, a hearing was held in October 2015, with a decision by the ad hoc committee expected in mid- to late-2016. Pending the outcome of annulment proceedings, results to date do not reflect any benefit of this decision.

Proceedings in connection with the Pending Merger with Emera

Twelve securities class action lawsuits were filed against the company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction.  Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida.  They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger.  In addition, several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order.  Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose.  The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

The company also received two separate shareholder demand letters from purported shareholders of the company.  Both of these letters demanded that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices.  One of the letters also demanded that the company refrain from consummating the transaction with Emera. Both of these demand letters have subsequently been withdrawn.  

In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger.  As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement.  Per the terms of the Memorandum of Understanding, the parties will negotiate a settlement agreement and submit it to the court for approval after the Merger is complete.  There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.

PGS Compliance Matter
          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. PGS is continuing to work with the OPC and FPSC staff to resolve the issues.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2015, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

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Long-Term Commitments

TECO Energy has commitments for capacity payments and long-term leases, primarily for building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations and maintenance – Other”, “Operation & maintenance other expense – Other” and “Discontinued Operations” on the Consolidated Statements of Income for the years ended Dec. 31, 2015, 2014 and 2013 totaled $15.3 million, $13.7 million and $7.6 million, respectively.  In addition, the company has other purchase obligations, including Tampa Electric’s outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines.  The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year, capacity payments under PPAs, and other net purchase obligations/commitments at Dec. 31, 2015:

	Capacity		Operating		Net Purchase
(millions)	Payments		Leases(1)		Obligations/Commitments (1)		Total
Year ended Dec. 31:
2016	$	14.6	$	7.7	$	222.5	$	244.8
2017		9.9		7.1		21.5		38.5
2018		10.1		6.4		9.6		26.1
2019		0.0		5.7		9.7		15.4
2020		0.0		5.4		4.7		10.1
Thereafter		0.0		18.6		20.0		38.6
Total future minimum payments	$	34.6	$	50.9	$	288.0	$	373.5

(1) Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. The table above excludes payment obligations under contractual agreements of Tampa Electric, PGS and NMGC for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses.

Guarantees and Letters of Credit

TECO Energy accounts for guarantees in accordance with the applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:

● Initial recognition and initial measurement of a liability, and/or

● Disclosure of specific details of the guarantee.

Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.

Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Dec. 31, 2015 are as follows:

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(millions)	Year of Expiration						Maximum
					After (1)		Theoretical		Liabilities  Recognized
Guarantees for the Benefit of:	2016		2017-2020		2020		Obligation		at Dec. 31, 2015
TECO Energy
Fuel sales and transportation (2)	$	0.0	$	0.0	$	92.9	$	92.9	$	0.0
Letters of indemnity - coal mining permits (3)		90.0		0.0		0.0		90.0		0.0
	$	90.0	$	0.0	$	92.9	$	182.9	$	0.0

(millions)	Year of Expiration						Maximum
					After (1)		Theoretical		Liabilities  Recognized
Letter of Credit for the Benefit of:	2016		2017-2020		2020		Obligation		at Dec. 31, 2015 (4)
TEC	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
NMGC	$	0.0	$	0.0	$	1.7	$	1.7	$	0.0
(1)     These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2)     The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Dec. 31, 2015. See Note 16 for additional information.
(3)     These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations.  Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 19, TECO Coal was sold on Sept. 21, 2015 to Cambrian.  Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities.  Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective. At the date of sale in September 2015, the letters of indemnity guaranteed $93.8 million. The company is working with Cambrian on the process to replace the bonds and expects the process to be completed in 2016. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained.
(4)     The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Dec. 31, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

Financial Covenants

In order to utilize their respective bank credit facilities, TECO Energy and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2015, TECO Energy and its subsidiaries were in compliance with all required financial covenants.

13. Related Party Transactions

The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. The company paid legal fees of $1.7 million for the year ended Dec. 31, 2013 to Ausley McMullen, P.A. of which Mr. DuBose Ausley (who was a director of TECO Energy, until his retirement from the Board in May 2013) was an employee. Other transactions were not material for the years ended Dec. 31, 2015, 2014 and 2013. No material balances were payable as of Dec. 31, 2015 or 2014.

14. Segment Information

TECO Energy is primarily an electric and gas utility holding company. Its diversified activities have been classified as discontinued operations. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each segment’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related

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information. All significant intercompany transactions are eliminated in the Consolidated Financial Statements of TECO Energy, but are included in determining reportable segments.

Tampa Electric provides retail electric utility services to almost 719,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for approximately 361,000 residential, commercial, industrial and electric power generation customers in the State of Florida. NMGC is engaged in the purchase and distribution of natural gas for more than 516,000 residential, commercial, industrial customers in the State of New Mexico.

	Tampa						TECO											TECO
(millions)	Electric		PGS		NMGC (4)		Coal (2)				Other (4),(5)			Eliminations (5)				Energy
2015
Revenues—external	$	2,014.9	$	401.5	$	316.5	$	0.0			$	10.6		$	0.0			$	2,743.5
Sales to affiliates		3.4		6.0		0.0		0.0				0.1			(9.5	)			0.0
Total revenues		2,018.3		407.5		316.5		0.0				10.7			(9.5	)			2,743.5
Depreciation and amortization		256.7		56.8		33.8		0.0				1.7			0.0				349.0
Total interest charges (1)		95.1		14.5		13.0		0.0				65.1			(1.3	)			186.4
Internally allocated interest (1)		0.0		0.0		0.0		0.0				1.3			(1.3	)			0.0
Provision for income taxes		143.6		21.9		15.4		0.0				(25.6	)		0.0				155.3
Net income from continuing operations		241.0		35.3		24.1		0.0				(59.2	)		0.0				241.2
Discontinued operations, net of tax		0.0		0.0		0.0		(69.6	)			1.9			0.0				(67.7	)
Net income		241.0		35.3		24.1		(69.6	)			(57.3	)		0.0				173.5
Goodwill		0.0		0.0		408.4		0.0				0.0			0.0				408.4
Total assets		7,020.7		1,137.4		1,231.3		0.0		(3)		1,947.9			(2,376.2	)	(6)		8,961.1
Capital expenditures		592.6		94.0		48.7		3.7				0.7			0.0				739.7
2014
Revenues—external	$	2,019.9	$	398.5	$	137.5	$	0.0			$	10.5		$	0.0			$	2,566.4
Sales to affiliates		1.1		1.1		0.0		0.0				0.2			(2.4	)			0.0
Total revenues		2,021.0		399.6		137.5		0.0				10.7			(2.4	)			2,566.4
Depreciation and amortization		248.6		54.0		11.0		0.0				1.7			0.0				315.3
Total interest charges (1)		92.8		13.8		4.2		0.0				66.1			(5.8	)			171.1
Internally allocated interest (1)		0.0		0.0		0.0		0.0				5.8			(5.8	)			0.0
Provision for income taxes		133.2		22.7		7.1		0.0				(24.1	)		0.0				138.9
Net income from continuing operations		224.5		35.8		10.5		0.0				(64.4	)		0.0				206.4
Discontinued operations, net of tax		0.0		0.0		0.0		(82.0	)			6.0			0.0				(76.0	)
Net income		224.5		35.8		10.5		(82.0	)			(58.4	)		0.0				130.4
Goodwill		0.0		0.0		408.3		0.0				0.0			0.0				408.3
Total assets		6,565.4		1,082.8		1,237.2		227.7		(3)		1,611.6			(1,998.5	)	(6)		8,726.2
Capital expenditures		582.1		88.9		18.2		14.6				0.0			0.0				703.8
2013
Revenues—external	$	1,949.6	$	392.7	$	0.0	$	0.0			$	12.8		$	0.0			$	2,355.1
Sales to affiliates		0.9		0.8		0.0		0.0				0.5			(2.2	)			0.0
Total revenues		1,950.5		393.5		0.0		0.0				13.3			(2.2	)			2,355.1
Depreciation and amortization		238.8		51.5		0.0		0.0				1.5			0.0				291.8
Total interest charges (1)		91.8		13.5		0.0		0.0				63.9			(7.8	)			161.4
Internally allocated interest (1)		0.0		0.0		0.0		0.0				7.8			(7.8	)			0.0
Provision for income taxes		116.9		21.9		0.0		0.0				(26.2	)		0.0				112.6
Net income from continuing operations		190.9		34.7		0.0		0.0				(36.9	)		0.0				188.7
Discontinued operations, net of tax		0.0		0.0		0.0		9.0				0.0			0.0				9.0
Net income		190.9		34.7		0.0		9.0				(36.9	)		0.0				197.7
Total assets		6,126.9		1,021.2		0.0		316.3		(3)		1,739.2			(1,755.6	)	(6)		7,448.0
Capital expenditures		422.3		79.0		0.0		22.4				2.4			0.0				526.1

(1) Segment net income is reported on a basis that includes internally allocated financing costs. Total interest charges include internally allocated interest costs that for 2015, 2014 and 2013 were at a pretax rate of 6.00%, based on an average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure.

(2) All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Other, including Parent and TECO Diversified, that directly relate to TECO Coal or TECO Guatemala. See Note 19.

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(3) The carrying value of mineral rights as of Dec. 31, 2015, 2014 and 2013 was $0.0 million, $10.9 million and $12.1 million, respectively.

(4) NMGI is included in the Other segment.

(5) Certain prior year amounts have been reclassified to conform to current year presentation.

(6) Amounts primarily relate to consolidated tax eliminations.

15. Asset Retirement Obligations

TECO Energy accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.

Prior to the sale of TECO Coal on Sept. 21, 2015, TECO Energy had recognized AROs for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities at TECO Coal. The majority of obligations were related to environmental remediation and restoration activities for coal-related operations. At Dec. 31, 2014, these obligations totaled $22.5 million and were classified as Liabilities Associated with Assets Held for Sale on TECO Energy’s Consolidated Balance Sheet.

TECO Energy’s regulated utilities must file depreciation and dismantlement studies periodically and receive approval from the FPSC or NMPRC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

For Tampa Electric, PGS and NMGC, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. At Dec. 31, 2015 and 2014, these obligations totaled $6.8 million and $6.1 million, respectively.

Reconciliation of beginning and ending carrying amount of asset retirement obligations:

	Dec. 31,
(millions)	2015			2014
Beginning balance	$	6.1		$	28.6
Additional liabilities		0.9			0.1
Revisions to estimated cash flows		(0.5	)		0.2
Acquisition of NMGC		0.0			0.8
Reclassification to liabilities associated with assets held for sale		0.0			(22.5	)
Other (1)		0.3			(1.1	)
Ending balance	$	6.8		$	6.1

(1) 2015 includes $0.3 million accretion recorded as a deferred regulatory asset. 2014 includes $(1.3) million of activity associated with TECO Coal and classified as discontinued operations and $0.2 million accretion recorded as a deferred regulatory asset.

16. Accounting for Derivative Instruments and Hedging Activities

From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes:

· To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric, PGS and NMGC; and

· To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates.

TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

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The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.

The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 17). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC and NMPRC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

The company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Dec. 31, 2015, all of the company’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Dec. 31, 2015 and 2014 are reflected on the company’s Consolidated Balance Sheets and classified accordingly as current and long term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.2 and $0.0 million as of Dec. 31, 2015 and 2014, respectively, and are included in “Prepayments and other current assets” on the Consolidated Balance Sheet. Derivative liabilities totaled $26.2 million and $42.7 million as of Dec. 31, 2015 and 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties.

All of the derivative asset and liabilities at Dec. 31, 2015 and 2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Balance Sheets as current and long term regulatory assets and liabilities. Based on the fair value of the instruments at Dec. 31, 2015, net pretax losses of $23.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

The Dec. 31, 2015 and 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 10.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the years ended Dec. 31, 2015, 2014 and 2013, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the years ended Dec. 31, 2015, 2014 and 2013 is presented in Note 10. These gains and losses were the result of interest rate contracts for TEC and diesel fuel derivatives related to TECO Coal operations. The locations of the reclassifications to income were reflected in “Interest expense” for TEC and “Income (loss) from discontinued operations” for TECO Coal.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Nov. 30, 2017 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Dec. 31, 2015, are expected to settle during the 2016 and 2017 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		38.4
2017		0.0		5.1
Total		0.0		43.5

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The company is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Dec. 31, 2015, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

The company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments.

17. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1: Observable inputs, such as quoted prices in active markets;

Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

(A) Market approach: Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities;

(B) Cost approach: Amount that would be required to replace the service capacity of an asset (replacement cost); and

(C) Income approach: Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models).

The fair value of financial instruments is determined by using various market data and other valuation techniques.

The following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Dec. 31, 2015 and 2014. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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Recurring Fair Value Measures

	As of Dec. 31, 2015
(millions)	Level  1		Level  2		Level  3		Total
Assets
Natural gas derivatives	$	0.0	$	0.2	$	0.0	$	0.2
Liabilities
Natural gas derivatives	$	0.0	$	26.2	$	0.0	$	26.2
	As of Dec. 31, 2014
(millions)	Level  1		Level  2		Level  3		Total
Liabilities
Natural gas derivatives	$	0.0	$	42.7	$	0.0	$	42.7

The natural gas derivatives are OTC swap and option instruments.  Fair values of swaps and options are estimated utilizing the market and income approach, respectively.  The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. The price of options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to NYMEX. The resulting prices are applied to the notional quantities of active swap and option positions to determine the fair value (see Note 16). 

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Dec. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

See Notes 5, 7 and 19 for information regarding the fair value of the company’s pension plan investments, long-term debt, and asset impairment charge, respectively.

18. Variable Interest Entities

The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 157 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric is not required to consolidate any of these entities. Tampa Electric purchased $33.6 million, $25.7 million and $22.1 million, under these PPAs for the three years ended Dec. 31, 2015, 2014 and 2013, respectively.

The company does not provide any material financial or other support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. In the normal course of business, the company’s involvement with these VIEs does not affect its Consolidated Balance Sheets, Statements of Income or Cash Flows.

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19. Discontinued Operations, Assets Held for Sale and Asset Impairments

TECO Coal

In 2013, TECO Coal temporarily idled some of its mines due to the softened coal market. As a result, the company performed impairment analyses in the fourth quarter of 2013 on the mining complexes with closed mines and the coal reserves. The company used an undiscounted cash flows approach in determining the recoverability amount of the assets in accordance with applicable accounting guidance. All assets were determined to have carrying values that were recoverable; therefore, no impairment charge was deemed necessary in 2013. Additionally, the company performed sensitivity analyses for the effects of inflation and noted that if inflation affected costs more than revenues by one percent each year, all assets would still be recoverable.

In September 2014, the Board of Directors of TECO Energy authorized management to actively pursue the sale of TECO Coal. As a result of this and other factors, the TECO Coal segment was accounted for as an asset held for sale and reported as a discontinued operation beginning in the third quarter of 2014. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly relate to the sale of TECO Coal.

In 2014, the company recorded impairment charges totaling $115.9 million pretax to write down the held-for-sale TECO Coal assets to their implied fair value based on the price specified in an agreement of sale entered into in October 2014, which agreement had conditions to closing that were not satisfied, less estimated costs of the transaction. In the second quarter of 2015, based on management’s assessment of current market conditions and discussions with interested parties, an additional impairment charge of $78.6 million pretax was recorded, which included the estimated selling costs associated with the transaction completed in September 2015. The fair value measurements were considered Level 2 measurements since the market is not active as defined by accounting standards (i.e. transactions for these assets are too infrequent to provide pricing information on an ongoing basis). None of these impairments had cash flow impacts. The asset impairment charges are recorded in the “Income (loss) from discontinued operations” line item in the Consolidated Statements of Income and the “Asset impairment” line item in the Consolidated Statements of Cash Flows for the years ended Dec. 31, 2014 and 2015.  

On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into the SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian.  The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction.  The retained liabilities included pension liability, which was fully funded at Sept. 30, 2015, and severance agreements, which were accrued at June 30, 2015 and paid in the third quarter of 2015. Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees in Note 12).  The company recorded a loss on sale of $10.0 million pretax, which is reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income, primarily to write off an after-tax settlement charge of $7.7 million related to the unfunded black lung obligations previously recorded in AOCI. Transaction-related costs of $12.3 million pretax, comprised of $2.5 million of legal and other consultant costs and $9.8 million of severance and other employee costs, were accrued at June 30, 2015 and reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income. The transaction-related costs were paid in 2015, with the exception of a minor amount of severance payments.

Since the closing of the sale, TECO Energy has not and will not have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.

The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items:

Assets held for sale
(millions)	Dec. 31, 2014
Current assets	$	109.6
Property, plant and equipment, net and other long-term assets		59.8
Total assets held for sale	$	169.4
Liabilities associated with assets held for sale
(millions)
Current liabilities	$	39.4
Long-term liabilities		65.4
Total liabilities associated with assets held for sale	$	104.8

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TECO Guatemala

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala (see Note 12). The 2015 charges shown in the table below are legal costs associated with that claim.  Additionally, in March 2014, an indemnification provision for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to a favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.

Combined components of income from discontinued operations

The following table provides selected components of discontinued operations related to TECO Coal and TECO Guatemala:

Components of income from discontinued operations
(millions)	2015			2014			2013
Revenues—TECO Coal	$	200.4		$	443.6		$	496.2
Income (loss) from operations—TECO Coal		(16.9	)		(13.9	)		5.4
Income (loss) from operations—TECO Guatemala		(0.8	)		4.4			(0.2	)
Loss on impairment—TECO Coal		(78.6	)		(115.9	)		0.0
Loss on sale—TECO Coal		(10.0	)		0.0			0.0
Income (loss) from discontinued operations—TECO Coal		(105.5	)		(129.8	)		5.4
Income (loss) from discontinued operations—TECO Guatemala		(0.8	)		4.4			(0.2	)
Income (loss) from discontinued operations		(106.3	)		(125.4	)		5.2
Provision (benefit) for income taxes		(38.6	)		(49.4	)		(3.8	)
Income (loss) from discontinued operations, net	$	(67.7	)	$	(76.0	)	$	9.0

20. Goodwill

The following table presents the changes in the carrying amount of goodwill for the years ended Dec. 31, 2015, 2014 and 2013.

(millions)	NMGC		Total
Balance as of Dec. 31, 2013	$	0.0	$	0.0
Acquisition of NMGC		408.3		408.3
Balance as of Dec. 31, 2014		408.3		408.3
Measurement period adjustments (1)		0.1		0.1
Balance as of Dec. 31, 2015	$	408.4	$	408.4

(1) Due to immateriality, the measurement period adjustment was not applied retrospectively to the opening balance sheet.

The goodwill on the company’s balance sheet related to the NMGC segment was recorded upon acquisition of NMGI on Sept. 2, 2014 (see Note 21). Under the accounting guidance for goodwill, goodwill is not subject to amortization. Rather, goodwill is subject to an annual assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill. Since NMGC is the lowest level of identifiable cash flows, this is the level at which goodwill is tested. Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity bypasses the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accounting guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. TECO Energy reviews recorded goodwill at least annually (during the fourth quarter) for each reporting unit.

The fair value for NMGC was determined in the fourth quarter using a weighted combination of a discounted cash flow analysis, a market multiple analysis, and a comparable transactions analysis. The discounted cash flow analysis relies on management’s best estimate of NMGC’s projected cash flows. It includes an estimate of NMGC’s terminal value based on these expected cash flows using the Gordon Growth Formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash

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flows. The discount rate is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to EBITDA of comparable public companies in estimating fair value. The comparable transaction analysis identified comparable company acquisitions within the industry and calculates the implied EBITDA multiple from the transaction, which is then applied to the last-twelve-months EBITDA of the subject company. Significant assumptions used in estimating the fair value include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows and the calculation of the terminal value.

The company determined the fair value of NMGC exceeds the book value and related goodwill carrying amounts at Dec. 31, 2015 and 2014, resulting in no impairment charge. Adverse changes in assumptions described above could result in a future material impairment of NMGC’s goodwill.

21. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt.

The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC, was obtained on Jan. 20, 2016) (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

The Merger Agreement contains customary representations, warranties and covenants of TECO Energy, Emera and Merger Sub. The Merger Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the execution of the Merger Agreement and the closing of the Merger and (ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera, among others, that Emera will use its reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals.

In addition, the Merger Agreement requires Emera (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.

The Merger Agreement contains certain termination rights for both TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

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During the year ended Dec. 31, 2015, TECO Energy incurred approximately $17.0 million pretax of incremental transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.

Acquisition of New Mexico Gas Company

Description of Transaction

On Sept. 2, 2014, the company completed the acquisition of NMGI contemplated by the acquisition agreement dated May 25, 2013 by and among the company, NMGI and Continental Energy Systems LLC. As a result of that acquisition, the company acquired all of the capital stock of NMGI. NMGI is the parent company of NMGC. The aggregate purchase price was $950 million, which included the assumption of $200 million of senior secured notes at NMGC, plus certain working capital adjustments.

Description of NMGC

On the acquisition date, NMGC, with approximately 720 employees, served more than 513,000 customers, predominately residential, in New Mexico with the majority located in the Central Rio Grande Corridor region, which is one of the fastest growing regions in the state. The company served approximately 60 percent of the state’s population with customers in 23 of New Mexico’s 33 counties. Customers are served through a combination of approximately 1,600 miles of transmission pipeline and 10,000 miles of distribution lines.

Strategic Rationale for Acquisition

· A transformative transaction that immediately added more than 513,000 customers in a single state.

· Provides an opportunity for TECO Energy’s experienced management team to share marketing expertise to a new and growing service territory, and for both companies to share best practices to support growth.

· Diversifies TECO Energy’s operating footprint.

· Provides immediate to near-term shareholder and customer benefits through organic growth opportunities.

Acquisition-Related Regulatory Matters

NMGC is a rate-regulated natural gas utility subject to the regulation of the NMPRC, including with respect to its rates, service standards, accounting, securities issuances, construction of major new transmission and distribution facilities and other matters affecting, directly or indirectly, the provision of natural gas sales and transportation services to NMGC’s customers.

In May 2014, TECO Energy reached a settlement with the New Mexico Industrial Energy Consumers (which represents large customers), the New Mexico Attorney General’s office (which represents the New Mexico residential and small business customers) and the U.S. Department of Energy. As part of this settlement of the application for approval of the acquisition by the NMPRC, TECO Energy agreed, among other things, to:

· freeze rates for NMGC customers until the end of 2017,

· credit NMGC customers with a $2 million rate credit to customer bills in 2015, increasing to $4 million per year in 2016 and each year after 2016 until NMGC’s next rate case,

· cap job losses in New Mexico at 99 over three years, many of which will be through attrition,

· maintain the NMGC name and headquarters in Albuquerque,

· support new economic development opportunities designed to attract new businesses to New Mexico through maintaining good service and reasonable customer rates,

· maintain or increase NMGC’s current level of community involvement and support, and

· own NMGC for at least 10 years.

On Aug. 13, 2014, the NMPRC approved the acquisition with the conditions set forth in the settlement agreements described above. The transaction closed on Sept. 2, 2014.

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Purchase Price

The total consideration in the acquisition was as follows:

Consideration Transferred

(millions)
Cash paid to seller	$	530.1
Cash paid to settle long-term debt, including accrued interest and fees		219.9
Long-term debt assumed		200.0
Total consideration transferred, excluding cash and working capital adjustments	$	950.0

Purchase Price Allocation

The majority of NMGI’s assets acquired and liabilities assumed relate to deferred income taxes associated with its NOL. These were recorded in accordance with the applicable accounting guidance. Additionally, the company paid off the existing outstanding debt at NMGI and issued $200 million of new NMGI debt at closing. Since the refinancing took place at closing, face value approximated fair value.

The majority of NMGC’s operations are subject to the rate-setting authority of the NMPRC and are accounted for pursuant to U.S. GAAP, including the accounting guidance for regulated operations. Rate-setting and cost recovery provisions currently in place for NMGC’s regulated operations provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. Except for long-term debt, the ARO, derivatives, OPEB plans, and deferred taxes, fair values of tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values. Accordingly, assets acquired and liabilities assumed and pro-forma financial information do not reflect any net adjustments related to these amounts. The difference between fair value and pre-merger carrying amounts for long-term debt, derivatives, and the OPEB plan for regulated operations were recorded as regulatory assets or liabilities.

The excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid primarily for opportunities for growth, synergies and an improved risk profile. Goodwill resulting from the acquisition was allocated entirely to the NMGC segment. Goodwill of $146.1 million related to the formation of NMGC in 2009 is tax deductible. The incremental goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes were recorded related to this portion of the goodwill.

The final purchase price allocation of the acquisition of NMGI and NMGC was as follows:

Purchase Price Allocation
(millions)
Current assets (1)	$	48.7
Property, plant and equipment		616.4
OPEB regulatory asset		6.4
Debt-related regulatory asset		23.9
Goodwill		408.4
Deferred tax assets		52.8
Other assets		29.3
Total assets	$	1,185.9
Current liabilities	$	(38.2	)
Long-term debt fair value adjustment and interest assumed		(22.7	)
Cost of removal regulatory liability		(100.6	)
Deferred tax liabilities		(60.8	)
OPEB liability		(9.8	)
Deferred credits and other liabilities		(3.8	)
Total liabilities	$	(235.9	)
Total purchase price allocation, excluding cash and working    capital adjustments	$	950.0

120

(1) Includes accounts receivables with fair value of $18.9 million, gross contract value of $19.6 million, and $0.7 million of contractual receivables not expected to be collected.

Impact of Acquisition

The impact of NMGI and NMGC on the company’s revenues in the Consolidated Statements of Operations for the years ended Dec. 31, 2015 and 2014 was an increase of $316.5 million and $137.5 million, respectively. The impact of NMGI and NMGC on the company’s net income in the Consolidated Statements of Operations for the years ended Dec. 31, 2015 and 2014 was an increase of $19.6 million and $8.2 million, respectively.

Pro Forma Impact of the Acquisition

The following unaudited pro forma financial information reflects the consolidated results of operations of the company and reflects the amortization of purchase accounting adjustments assuming the acquisition had taken place on Jan. 1, 2013. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the company.

Pro forma earnings presented below include adjustments related to non-recurring acquisition consummation, integration and other costs incurred by the company during the period. After-tax non-recurring acquisition consummation, integration and other costs incurred by the company were $8.6 million and $6.2 million for the years ended Dec. 31, 2014 and 2013, respectively.

Pro Forma Impact of Acquisition	For the year ended Dec. 31,
(millions, except per share amounts)	2014		2013
Revenues	$	2,806.6	$	2,704.0
Net income from continuing operations		223.8		216.8
Basic and diluted EPS from continuing operations		0.96		0.93

Transaction and Integration Costs

The following after-tax transaction and integration charges were recognized in connection with the acquisition and are included in the TECO Energy Consolidated Statement of Income for the years ended Dec. 31, 2015 and 2014.

Transaction and Integration Costs	For the year ended Dec. 31,
(millions)	2015		2014
Legal and other consultants	$	0.5	$	8.0
Bridge loan costs		0.0		3.3
Severance and relocation costs		1.0		2.8
Other costs and tax benefit		0.4		(5.5	)
Total accounting charges	$	1.9	$	8.6

The company has an ongoing severance plan under which, in general, the longer a terminated employee worked prior to termination, the greater the amount of severance benefits. The company records a liability and expense for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the company measures the obligation and records the expense at its fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.

In conjunction with the acquisition, in September 2014, TECO Energy and NMGC each offered a severance plan to certain eligible employees. Severance costs incurred were recorded primarily within Operation and maintenance other expense in the Consolidated Condensed Statements of Income. Cash payments under the severance plan began in the third quarter of 2014, and substantially all cash payments under the plan are expected to be made by the end of 2017 resulting in the substantial completion of the acquisition integration plan. As of Dec. 31, 2015 and 2014, the obligations associated with the severance benefits costs were $0.7 million and $2.6 million, respectively.

121

22. Quarterly Data (unaudited)

Financial data by quarter is as follows:

(millions, except per share amounts)
Quarter ended	Dec.  31		Sept. 30		June 30		Mar. 31
2015
Revenues	$	676.1	$	693.8	$	680.6	$	693.0
Income from operations		126.0		146.6		143.3		146.2
Net income from continuing operations		51.0		64.9		61.5		63.8
Net income		50.5		53.2		11.8		58.0
EPS—Basic
Net income from continuing operations	$	0.22	$	0.28	$	0.26	$	0.27
Net income		0.21		0.23		0.05		0.25
EPS—Diluted
Net income from continuing operations	$	0.22	$	0.28	$	0.26	$	0.27
Net income		0.21		0.23		0.05		0.25
Dividends paid per common share outstanding	$	0.225	$	0.225	$	0.225	$	0.225
Quarter ended	Dec.  31		Sept. 30		June 30		Mar. 31
2014
Revenues	$	695.5	$	687.2	$	605.7	$	578.0
Income from operations		112.1		145.7		132.0		115.6
Net income from continuing operations		27.4		73.0		57.6		48.4
Net income		10.8		11.1		58.4		50.1
EPS—Basic
Net income from continuing operations	$	0.11	$	0.32	$	0.27	$	0.22
Net income		0.04		0.04		0.27		0.23
EPS—Diluted
Net income from continuing operations	$	0.11	$	0.32	$	0.27	$	0.22
Net income		0.04		0.04		0.27		0.23
Dividends paid per common share outstanding	$	0.220	$	0.220	$	0.220	$	0.220

Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 19.

23. Subsequent Events

Amendment of TECO Energy/TECO Finance Credit Facility

On Feb. 24, 2016, TECO Energy and TECO Finance entered into Amendment No. 3 to its Fourth Amended and Restated Credit Agreement (the TECO Credit Facility) with JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders named therein.  The amendment provides that the closing of the Merger will not constitute an event of default under the TECO Credit Facility. 

TECO Energy/TECO Finance One-Year Term Loan Facility

In February 2016, TECO Energy (as guarantor) and TECO Finance (as borrower) secured commitments for a $400 million one-year term loan facility, the terms of which provide for closing and funding on Mar. 14, 2016.  The proceeds of the facility are to be used to repay at maturity the $250 million aggregate principal amount of TECO Finance 4.00% Notes due Mar. 15, 2016, repay a portion of the drawings under the TECO Credit Facility and for general corporate purposes.

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123

TAMPA ELECTRIC COMPANY

Report of Independent Registered Certified Public Accounting Firm

To the Board of Directors and Shareholder of Tampa Electric Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Tampa Electric Company and its subsidiariesat December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  These financial statements and the financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the financial statements, the Company changed the manner in which it classifies deferred taxes in 2015.

/s/ PricewaterhouseCoopers LLP

Tampa, Florida

February 26, 2016

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TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets

Assets	Dec. 31,			Dec. 31,
(millions)	2015			2014
Property, plant and equipment
Utility plant in service
Electric	$	7,270.3		$	7,094.8
Gas		1,398.6			1,308.9
Construction work in progress		771.1			624.2
Utility plant in service, at original costs		9,440.0			9,027.9
Accumulated depreciation		(2,676.8	)		(2,633.8	)
Utility plant in service, net		6,763.2			6,394.1
Other property		9.7			8.6
Total property, plant and equipment, net		6,772.9			6,402.7
Current assets
Cash and cash equivalents		9.1			10.4
Receivables, less allowance for uncollectibles of $1.5 and $1.4 at Dec. 31, 2015 and 2014, respectively		230.2			227.2
Inventories, at average cost
Fuel		105.6			85.2
Materials and supplies		73.1			72.2
Regulatory assets		44.3			52.1
Taxes receivable from affiliate		61.3			43.3
Deferred income taxes		0.0			24.8
Prepayments and other current assets		21.5			17.4
Total current assets		545.1			532.6
Deferred debits
Unamortized debt expense		18.1			16.8
Regulatory assets		373.8			319.6
Other		16.8			2.6
Total deferred debits		408.7			339.0
Total assets	$	7,726.7		$	7,274.3

The accompanying notes are an integral part of the consolidated financial statements.

125

TAMPA ELECTRIC COMPANY

Consolidated Balance Sheets—continued

Liabilities and Capital	Dec. 31,			Dec. 31,
(millions)	2015			2014
Capitalization
Common stock	$	2,305.4		$	2,130.4
Accumulated other comprehensive loss		(3.6	)		(7.1	)
Retained earnings		313.7			305.8
Total capital		2,615.5			2,429.1
Long-term debt, less amount due within one year		2,179.8			2,013.8
Total capital		4,795.3			4,442.9
Current liabilities
Long-term debt due within one year		83.3			83.3
Notes payable		61.0			58.0
Accounts payable		221.6			242.3
Customer deposits		176.3			170.4
Regulatory liabilities		83.2			54.7
Derivative liabilities		24.1			36.6
Interest accrued		16.9			17.0
Taxes accrued		13.2			12.4
Other		10.2			10.0
Total current liabilities		689.8			684.7
Deferred credits
Deferred income taxes		1,308.8			1,209.1
Investment tax credits		10.5			9.0
Derivative liabilities		2.1			6.1
Regulatory liabilities		603.5			623.4
Deferred credits and other liabilities		316.7			299.1
Total deferred credits		2,241.6			2,146.7
Commitments and Contingencies (see Note 9)
Total liabilities and capital	$	7,726.7		$	7,274.3

The accompanying notes are an integral part of the consolidated financial statements.

126

TAMPA ELECTRIC COMPANY

Consolidated Statements of Income and Comprehensive Income

(millions)
For the years ended Dec. 31,	2015			2014			2013
Revenues
Electric	$	2,017.7		$	2,020.5		$	1,950.1
Gas		401.5			398.5			392.7
Total revenues		2,419.2			2,419.0			2,342.8
Expenses
Regulated operations & maintenance
Fuel		638.6			692.3			680.2
Purchased power		78.9			71.4			64.7
Cost of natural gas sold		135.5			137.0			142.6
Other		528.9			518.4			523.6
Depreciation and amortization		313.5			302.6			290.3
Taxes, other than income		192.0			189.8			183.1
Total expenses		1,887.4			1,911.5			1,884.5
Income from operations		531.8			507.5			458.3
Other income
Allowance for other funds used during construction		17.2			10.5			6.3
Other income, net		2.4			4.8			5.1
Total other income		19.6			15.3			11.4
Interest charges
Interest expense		117.9			111.7			108.9
Allowance for borrowed funds used during construction		(8.3	)		(5.1	)		(3.6	)
Total interest charges		109.6			106.6			105.3
Income before provision for income taxes		441.8			416.2			364.4
Provision for income taxes		165.5			155.9			138.8
Net income		276.3			260.3			225.6
Other comprehensive income, net of tax
Gain on cash flow hedges		3.5			0.7			0.9
Total other comprehensive income,  net of tax		3.5			0.7			0.9
Comprehensive income	$	279.8		$	261.0		$	226.5

The accompanying notes are an integral part of the consolidated financial statements.

127

TAMPA ELECTRIC COMPANY

Consolidated Statements of Cash Flows

(millions)
For the years ended Dec. 31,	2015			2014			2013
Cash flows from operating activities
Net income	$	276.3		$	260.3		$	225.6
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		313.5			302.6			290.3
Deferred income taxes and investment tax credits		118.9			92.2			118.1
Allowance for other funds used during construction		(17.2	)		(10.5	)		(6.3	)
Loss on disposal of assets, pretax		3.1			0.0			0.0
Deferred recovery clauses		26.5			(16.2	)		(6.2	)
Receivables, less allowance for uncollectibles		(3.0	)		0.4			(13.8	)
Inventories		(21.3	)		13.1			(9.0	)
Prepayments and other deposits		(4.0	)		1.5			0.0
Taxes accrued		(17.2	)		11.8			(34.3	)
Interest accrued		(0.1	)		0.6			(0.9	)
Accounts payable		(26.8	)		5.9			34.8
Other		(40.8	)		(14.5	)		(2.8	)
Cash flows from operating activities		607.9			647.2			595.5
Cash flows from investing activities
Capital expenditures		(686.6	)		(671.0	)		(501.3	)
Net proceeds from sale of assets		0.0			0.0			0.1
Cash flows used in investing activities		(686.6	)		(671.0	)		(501.2	)
Cash flows from financing activities
Common stock		175.0			100.0			60.0
Proceeds from long-term debt issuance		251.1			296.3			0.0
Repayment of long-term debt/Purchase in lieu of redemption		(83.3	)		(83.3	)		(51.6	)
Net change in short-term debt		3.0			(26.0	)		84.0
Dividends paid		(268.4	)		(262.6	)		(222.1	)
Cash flows from/(used in) financing activities		77.4			24.4			(129.7	)
Net increase (decrease) in cash and cash equivalents		(1.3	)		0.6			(35.4	)
Cash and cash equivalents at beginning of the year		10.4			9.8			45.2
Cash and cash equivalents at end of the year	$	9.1		$	10.4		$	9.8
Supplemental disclosure of cash flow information
Cash paid (received) during the year for:
Interest	$	106.2		$	102.5		$	102.4
Income taxes	$	63.7		$	52.6		$	56.4
Supplemental disclosure of cash flow information
Change in accrued capital expenditures	$	6.9		$	14.3		$	4.7

The accompanying notes are an integral part of the consolidated financial statements.

128

TAMPA ELECTRIC COMPANY

Consolidated Statements of Retained Earnings

(millions)
For the years ended Dec. 31,	2015		2014		2013
Balance, beginning of year	$	305.8	$	308.1	$	304.6
Add: Net income		276.3		260.3		225.6
		582.1		568.4		530.2
Deduct: Cash dividends on capital stock—common		268.4		262.6		222.1
Balance, end of year	$	313.7	$	305.8	$	308.1

The accompanying notes are an integral part of the consolidated financial statements.

129

TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization

		Capital  Stock Outstanding			Cash  Dividends
	Current	Dec.  31,			Paid (1)
	Redemption				Per
(millions, except share amounts)	Price	Shares	Amount		Share			Amount
Common stock - without par value
25 million shares authorized
2015 (3)	N/A	10	$	2,305.4		(2	)	$	268.4
2014 (3)	N/A	10	$	2,130.4		(2	)	$	262.6

Preferred stock – $100 par value

1.5 million shares authorized, none outstanding.

Preferred stock – no par

2.5 million shares authorized, none outstanding.

Preference stock – no par

2.5 million shares authorized, none outstanding.

(1) Quarterly dividends paid on Mar. 2, May 28, Aug. 28 and Nov. 30 during 2015.

Quarterly dividends paid on Feb. 28, May 28, Aug. 28 and Nov. 28 during 2014.

(2) Not meaningful.

(3) TECO Energy made equity contributions to TEC of $175.0 million in 2015 and $100.0 million in 2014.

The accompanying notes are an integral part of the consolidated financial statements.

130

TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization – continued

At Dec. 31, 2015 and 2014, TEC had the following long-term debt outstanding:

Long-Term Debt
(millions)		Due	2015			2014
Tampa Electric	Installment contracts payable (1) :
	5.65% Refunding  bonds	2018	$	54.2		$	54.2
	Variable rate bonds repurchased in 2008 (2)	2020		0.0			0.0
	5.15% Refunding bonds repurchased in 2013 (3)	2025		0.0			0.0
	1.5% Term rate bonds repurchased in 2011 (4)	2030		0.0			0.0
	5.0% Refunding bonds repurchased in 2012 (5)	2034		0.0			0.0
	Notes (6)(7) : 6.25%	2015-2016		83.3			166.7
	6.10%	2018		200.0			200.0
	5.40%	2021		231.7			231.7
	2.60%	2022		225.0			225.0
	6.55%	2036		250.0			250.0
	6.15%	2037		190.0			190.0
	4.10%	2042		250.0			250.0
	4.35%	2044		290.0			290.0
	4.20%	2045		230.0			0.0
	Total long-term debt of Tampa Electric			2,004.2			1,857.6
PGS	Notes (6)(7) : 6.10%	2018		50.0			50.0
	5.40%	2021		46.7			46.7
	2.60%	2022		25.0			25.0
	6.15%	2037		60.0			60.0
	4.10%	2042		50.0			50.0
	4.35%	2044		10.0			10.0
	4.20%	2045		20.0			0.0
	Total long-term debt of PGS			261.7			241.7
Total long-term debt of TEC				2,265.9			2,099.3
Unamortized debt discount, net				(2.8	)		(2.2	)
Total carrying amount of long-term debt				2,263.1			2,097.1
Less amount due within one year				83.3			83.3
Total long-term debt			$	2,179.8		$	2,013.8

(1) Tax-exempt securities.

(2) In March 2008 these bonds, which were in auction rate mode, were purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020.  

(3) In September 2013 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025.

(4) In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030.

(5) In March 2012 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034.

(6) These securities are subject to redemption in whole or in part, at any time, at the option of the issuer.

(7) These long-term debt agreements contain various restrictive covenants.

The accompanying notes are an integral part of the consolidated financial statements.

131

TAMPA ELECTRIC COMPANY

Consolidated Statements of Capitalization—continued

At Dec. 31, 2015, total long-term debt had a carrying amount of $2,263.1 million and an estimated fair market value of $2,433.3 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $2,097.1 million and an estimated fair market value of $2,372.2 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments.

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time. Gross maturities and annual sinking fund requirements of long-term debt for the years 2016 through 2020 and thereafter are as follows:

Long-Term Debt Maturities

													Total
As of Dec. 31, 2015													Long-Term
(millions)	2016		2017		2018		2019		2020		Thereafter		Debt
Tampa Electric	$	83.3	$	0.0		254.2	$	0.0	$	0.0	$	1,666.7	$	2,004.2
PGS		0.0		0.0		50.0		0.0		0.0		211.7		261.7
Total long-term debt maturities	$	83.3	$	0.0	$	304.2	$	0.0	$	0.0	$	1,878.4	$	2,265.9

The accompanying notes are an integral part of the consolidated financial statements.

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Significant Accounting Policies

TEC has two business segments. Its Tampa Electricdivision provides retail electric services in West Central Florida, and PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in Florida. TEC’s significant accounting policies are as follows:

Basis of Accounting

TEC maintains its accounts in accordance with recognized policies prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects.

The impact of the accounting guidance for the effects of certain types of regulation has been minimal in the company’s experience, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with this guidance (see Note 3 for additional details).

TEC’s retail and wholesale businesses are regulated by the FPSC and FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.

Principles of Consolidation

TEC is a wholly-owned subsidiary of TECO Energy, Inc., and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, PGS. Intercompany balances and intercompany transactions have been eliminated in consolidation. The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates.

For entities that are determined to meet the definition of a VIE, TEC obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If TEC is determined to be the primary beneficiary, then the VIE is consolidated and a noncontrolling interest is recognized for any other third-party interests. If TEC is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 15).

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned subsidiary of Emera. See Note 16 for further information.

Cash Equivalents

Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.

Property, Plant and Equipment

           Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Concurrent with a planned major maintenance outage or with new construction, the cost of adding or replacing retirement units-of-property is capitalized in conformity with the regulations of FERC and FPSC. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred.

In general, when regulated depreciable property is retired or disposed, its original cost less salvage is charged to accumulated depreciation. For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.

133

Depreciation

Tampa Electric and PGS compute depreciation and amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods:

· the group remaining life method, approved by the FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property;

· the amortizable life method, approved by the FPSC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above.

The provision for total regulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.7% for 2015, 2014 and 2013. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years ended Dec. 31, 2015, 2014 and 2013 was $306.0 million, $295.8 million and $284.2 million, respectively.

On Sept. 11, 2013, the FPSC unanimously voted to approve a stipulation and settlement agreement between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric began using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

Allowance for Funds Used During Construction

AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. In March 2014, the rate was revised to 6.46% effective Jan. 1, 2014. Total AFUDC for the years ended Dec. 31, 2015, 2014 and 2013 was $25.5 million, $15.6 million and $9.9 million, respectively.

Inventory

TEC values materials, supplies and fossil fuel inventory (coal, oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered with a normal profit upon sale in the ordinary course of business.

Deferred Income Taxes

TEC uses the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.

Investment Tax Credits

ITCs have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.

Revenue Recognition

TEC recognizes revenues consistent with accounting standards for revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.

The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company.

Revenues and Cost Recovery

Revenues include amounts resulting from cost-recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline

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capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets.

Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide for a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2015 and 2014, unbilled revenues of $53.7 million and $49.3 million, respectively, are included in the “Receivables” line item on TEC’s Consolidated Balance Sheets.

Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $78.9 million, $71.4 million and $64.7 million, for the years ended Dec. 31, 2015, 2014 and 2013, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause.

Receivables and Allowance for Uncollectible Accounts

Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on TEC’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Accounting for Excise Taxes, Franchise Fees and Gross Receipts

TEC is allowed to recover certain costs on a dollar-for-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $116.9 million, $113.9 million and $108.5 million for the years ended Dec. 31, 2015, 2014 and 2013, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred.

Deferred Credits and Other Liabilities

Other deferred credits primarily include the accrued postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 9), and medical and general liability claims incurred but not reported. TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2015 and 2014 ranged from 2.92% to 4.00% and 2.71% to 4.00%, respectively.

Cash Flows Related to Derivatives and Hedging Activities

TEC classifies cash inflows and outflows related to derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows.

Reclassifications

Certain reclassifications were made to prior year amounts to conform to current period presentation. None of the reclassifications affected TEC’s net income in any period.

2. New Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will

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require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers. This guidance will be effective for TEC beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. TEC expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods andthe impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance will be effective for TEC beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Dec. 31, 2015, $18.1 million of debt issuance costs, which does not include costs for line-of-credit arrangements, are included in “Deferred debits” on TEC’s Consolidated Condensed Balance Sheet. The guidance will not affect TEC’s results of operations or cash flows.

Disclosure of Investments Using Net Asset Value

In May 2015, the FASB issued guidance stating that investments for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies that a plan sponsor’s pension assets are eligible to be measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan, in which TEC participates, has such investments as disclosed in Note 5. This standard will be required for TEC beginning in 2016. As early adoption is permitted, TEC adopted the standard for its 2015 fiscal year and applied the presentation on a retrospective basis for all periods presented in the pension plan assets fair value hierarchy. The guidance did not affect TEC’s balance sheets, results of operations or cash flows.

Measurement Period Adjustments in Business Combinations

In September 2015, the FASB issued guidance requiring an acquirer in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to exceed one year. The guidance will be effective for TEC beginning in 2016 and will be applied prospectively. The guidance will not affect TEC’s current financial statements. However, TEC will assess the potential impact of the guidance on future acquisitions.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued guidance regarding the classification of deferred taxes on the balance sheet. To simplify the presentation of deferred income taxes, the new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet rather than be classified as current or noncurrent under current guidance. The guidance will be required for TEC beginning in 2017 and may be applied on a prospective or retrospective basis. As early adoption is permitted, TEC adopted the standard in December 2015 and applied the balance sheet presentation on a prospective basis. Therefore, prior period balance sheets were not retrospectively adjusted. The guidance did not affect TEC’s results of operations or cash flows.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. TEC does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for TEC beginning in 2018.

Leases

 In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The dual model for income statement classification is maintained under the new guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. This guidance will be effective for TEC beginning in 2019, with early adoption

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permitted, and will be applied using a modified retrospective approach. TEC is currently evaluating the impacts of the adoption of the guidance on its financial statements.

3. Regulatory

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus a reasonable return on invested capital.

Base Rates-Tampa Electric

Tampa Electric’s results for the first ten months of 2013 reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.

Tampa Electric’s results for 2015, 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on Sept. 6, 2013, between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases: $57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of Tampa Electric’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to 10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective no sooner than Jan. 1, 2018), unless its earned ROE were to fall below 9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than Tampa Electric could seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software retroactive to Jan. 1, 2013.

Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices.

Storm Damage Cost Recovery

Prior to the above-mentioned stipulation and settlement agreement, Tampa Electric was accruing $8.0 million annually to a FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve remained $56.1 million at both Dec. 31, 2015 and 2014.

Base Rates-PGS

PGS’s base rates were established in May 2009 and reflect an ROE of 10.75%, which is the middle of a range between 9.75% to 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of $560.8 million.

Regulatory Assets and Liabilities

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer

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than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

Details of the regulatory assets and liabilities as of Dec. 31, 2015 and 2014 are presented in the following table:

Regulatory Assets and Liabilities

	Dec.  31,		Dec.  31,
(millions)	2015		2014
Regulatory assets:
Regulatory tax asset (1)	$	74.6	$	69.2
Cost-recovery clauses - deferred balances (2)	5.2		0.9
Cost-recovery clauses - offsets to derivative liabilities (2)		26.2		42.7
Environmental remediation (3)		54.0		53.1
Postretirement benefits (4)		238.3		187.8
Deferred bond refinancing costs (5)		6.5		7.2
Competitive rate adjustment (2)		2.6		2.8
Other		10.7		8.0
Total regulatory assets		418.1		371.7
Less: Current portion		44.3		52.1
Long-term regulatory assets	$	373.8	$	319.6
Regulatory liabilities:
Regulatory tax liability	$	5.7	$	5.1
Cost-recovery clauses (2)		54.2		23.5
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve—cost of removal (6)		570.0		591.5
Other		0.7		1.9
Total regulatory liabilities		686.7		678.1
Less: Current portion		83.2		54.7
Long-term regulatory liabilities	$	603.5	$	623.4

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.  

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

4. Income Taxes

Income Tax Expense

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. For the three years presented, TEC’s effective tax rate differs from the statutory rate principally due to state income taxes.

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Income tax expense consists of the following components:

Income Tax Expense (Benefit)

(millions)
For the year ending Dec. 31,	2015		2014			2013
Current income taxes
Federal	$	38.2	$	54.8		$	19.4
State		8.4		8.9			1.3
Deferred income taxes
Federal		102.9		79.0			99.8
State		14.5		13.5			18.6
Amortization of investment tax credits		1.5		(0.3	)		(0.3	)
Total income tax expense	$	165.5	$	155.9		$	138.8

The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes as follows:

Effective Income Tax Rate

(millions)
For the years ended Dec. 31,	2015			2014			2013
Income tax expense at the federal statutory rate of 35%	$	154.6		$	145.7		$	127.5
Increase (decrease) due to
State income tax, net of federal income tax		14.8			14.5			13.0
Other		(3.9	)		(4.3	)		(1.7	)
Total income tax expense on consolidated statements of income	$	165.5		$	155.9		$	138.8
Income tax expense as a percent of income from continuing operations,    before income taxes		37.5	%		37.5	%		38.1	%

Deferred Income Taxes

Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows:

(millions)
As of Dec. 31,	2015		2014
Deferred tax liabilities (1)
Property related	$	1,431.9	$	1,328.8
Pension and postretirement benefits		92.0		72.5
Pension		71.1		51.8
Total deferred tax liabilities		1,595.0		1,453.1
Deferred tax assets (1)
Loss and credit carryforwards		80.0		77.7
Medical benefits		47.7		51.0
Insurance reserves		27.6		29.0
Pension and postretirement benefits		92.0		72.5
Capitalized energy conservation assistance costs		21.4		20.3
Other		17.5		18.3
Total deferred tax assets		286.2		268.8
Total deferred tax liability, net		1,308.8		1,184.3
Less: Current portion of deferred tax asset		0.0		(24.8	)
Long-term portion of deferred tax liability, net	$	1,308.8	$	1,209.1

(1) Certain property related assets and liabilities have been netted.

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At Dec. 31, 2015, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $194.1 million and $268.5 million, respectively, expiring in 2033. In addition, TEC has unused general business credits of $1.9 million, expiring between 2028 and 2035.

Unrecognized Tax Benefits

TEC accounts for uncertain tax positions as required by FASB accounting guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, TEC may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures.

As of Dec. 31, 2015 and 2014, TEC does not have a liability for unrecognized tax benefits. Based on current information, TEC does not anticipate that this will change materially in 2016. As of Dec. 31, 2015 and 2014, TEC does not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

The IRS concluded its examination of TECO Energy’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and onward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized. TEC does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months.

5. Employee Postretirement Benefits

Pension Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy, including a qualified, non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on the employees’ age, years of service and final average earnings. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans.

Amounts disclosed for pension benefits in the following tables and discussion also include the fully-funded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits (Other Benefits) for most employees retiring after age 50 meeting certain service requirements. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy postretirement health care and life insurance plans. Postretirement benefit levels are substantially unrelated to salary. TECO Energy reserves the right to terminate or modify the plans in whole or in part at any time.

MMA added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.

The FASB issued accounting guidance and disclosure requirements related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.

In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TEC reduced its deferred tax asset and recorded a corresponding regulatory asset in 2010. This amount was trued up in 2013. TEC is amortizing the regulatory asset over the remaining average service life at the time of 12 years.

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Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.

Effective Jan. 1, 2013, the company implemented an EGWP for its post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts, which are greater than the subsidy payments previously received by the company under Medicare Part D for its post-65 retiree prescription drug plan.

Obligations and Funded Status

TEC recognizes in its statement of financial position the over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted.

The following table provides a detail of the change in TECO Energy’s benefit obligations and change in plan assets for combined pension plans (pension benefits) and combined other postretirement benefit plans (other benefits). 

TECO Energy	Pension Benefits						Other Benefits
Obligations and Funded Status
(millions)	2015			2014			2015			2014
Change in benefit obligation
Net benefit obligation at beginning of year	$	728.9		$	666.0		$	201.5		$	208.1
Service cost		20.9			18.3			2.2			2.5
Interest cost		30.3			32.0			8.2			10.8
Plan participants’ contributions		0.0			0.0			2.0			2.8
Plan amendments		0.0			0.0			(3.7	)		(23.2	)
Actuarial loss (gain)		5.8			48.3			(0.4	)		1.5
Benefits paid		(53.0	)		(39.9	)		(14.6	)		(16.0	)
Transfer in due to the effect of business combination		0.0			0.0			0.0			26.7
Plan curtailment		0.0			4.0			0.0			(11.7	)
Special termination benefit		0.0			0.2			0.0			0.0
Net benefit obligation at end of year	$	732.9		$	728.9		$	195.2		$	201.5

Change in plan assets
Fair value of plan assets at beginning of year	$	648.0		$	593.0		$	18.8		$	0.0
Actual return on plan assets		(25.5	)		46.4			(0.6	)		0.1
Employer contributions		55.0			47.5			1.5			(1.0	)
Employer direct benefit payments		0.9			1.0			13.5			16.0
Plan participants’ contributions		0.0			0.0			2.0			2.8
Transfer in due to acquisition		0.0			0.0			0.0			16.9
Benefits paid		(53.0	)		(39.9	)		(14.6	)		(16.0	)
Fair value of plan assets at end of year (1)	$	625.4		$	648.0		$	20.6			18.8

(1) The MRV of plan assets is used as the basis for calculating the EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.

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At Dec. 31, the aggregate financial position for TECO Energy pension plans and other postretirement plans with benefit obligations in excess of plan assets was as follows:

Funded Status	Pension Benefits						Other Benefits
(millions)	2015			2014			2015			2014
Benefit obligation (PBO/APBO)	$	732.9		$	728.9		$	195.2		$	201.5
Less: Fair value of plan assets		625.4			648.0			20.6			18.8
Funded status at end of year	$	(107.5	)	$	(80.9	)	$	(174.6	)	$	(182.7	)

The accumulated benefit obligation for TECO Energy consolidated defined benefit pension plans was $686.9 million at Dec. 31, 2015 and $685.0 million at Dec. 31, 2014.

The amounts recognized in TEC’s Consolidated Balance Sheets for pension and other postretirement benefit obligations, plan assets, and unrecognized costs at Dec. 31 were as follows:

Tampa Electric Company	Pension Benefits						Other Benefits
Amounts recognized in balance sheet
(millions)	2015			2014			2015			2014
Regulatory assets	$	208.2		$	167.4		$	30.2		$	20.4
Accrued benefit costs and other current liabilities		(0.6	)		(0.6	)		(9.2	)		(9.1	)
Deferred credits and other liabilities		(69.3	)		(53.5	)		(142.3	)		(137.1	)
	$	138.3		$	113.3		$	(121.3	)	$	(125.8	)

Unrecognized gains and losses and prior service credits and costs are recorded in regulatory assets for TEC. The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.

Amounts recognized in regulatory assets	Pension Benefits					Other Benefits
(millions)	2015		2014			2015			2014
Net actuarial loss (gain)	$	208.2	$	167.7		$	47.2		$	39.5
Prior service cost (credit)		0.0		(0.3	)		(17.0	)		(19.1	)
Amount recognized	$	208.2	$	167.4		$	30.2		$	20.4

Assumptions used to determine benefit obligations at Dec. 31:

	Pension Benefits						Other Benefits
	2015			2014			2015			2014
Discount rate		4.688	%		4.258	%		4.669	%		4.211	%
Rate of compensation increase-weighted average		3.87	%		3.87	%		2.50	%		3.86	%
Healthcare cost trend rate
Immediate rate	n/a			n/a				7.05	%		7.09	%
Ultimate rate	n/a			n/a				4.50	%		4.57	%
Year rate reaches ultimate	n/a			n/a			2038			2025

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s benefit obligation:

(millions)	1%  Increase		1 %  Decrease
Effect on postretirement benefit obligation	$	6.1	$	(5.2	)

The discount rate assumption used to determine the Dec. 31, 2015 benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

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Amounts recognized in Net Periodic Benefit Cost, OCI, and Regulatory Assets

TECO Energy	Pension Benefits									Other Benefits
	2015			2014			2013			2015			2014			2013
(millions)
Service cost	$	20.9		$	18.3		$	18.2		$	2.2		$	2.5		$	2.5
Interest cost		30.3			32.0			28.9			8.2			10.8			9.3
Expected return on plan assets		(43.3	)		(41.8	)		(38.4	)		(1.1	)		(0.3	)		0.0
Amortization of:
Actuarial loss		15.1			13.5			20.5			0.0			0.2			1.0
Prior service (benefit) cost		(0.2	)		(0.4	)		(0.4	)		(2.4	)		(0.2	)		(0.4	)
Curtailment loss (gain)		0.0			3.9			0.0			0.0			(0.2	)		0.0
Special termination benefit		0.0			0.2			0.0			0.0			0.0			0.0
Settlement loss		0.0			0.0			1.0			0.0			0.0			0.0
Net periodic benefit cost	$	22.8		$	25.7		$	29.8		$	6.9		$	12.8		$	12.4

New prior service cost	$	0.0		$	0.0		$	0.0		$	(3.7	)	$	(23.6	)	$	0.0
Net loss (gain) arising during the year		74.5			44.1			(75.7	)		1.3			(9.9	)		(15.6	)
Unrecognized costs in regulated asset acquired in business combination		0.0			0.0			0.0			0.0			6.4			0.0
Amounts recognized as component of net periodic benefit cost:
Amortization of actuarial gain (loss)		(15.1	)		(13.5	)		(21.5	)		0.0			(0.2	)		(1.0	)
Amortization of prior service (benefit) cost		0.2		0.4				0.4			2.4			0.2			0.3
Total recognized in OCI and regulatory assets	$	59.6		$	31.0		$	(96.8	)	$	0.0		$	(27.1	)	$	(16.3	)
Total recognized in net periodic benefit cost, OCI and regulatory assets	$	82.4		$	56.7		$	(67.0	)	$	6.9		$	(14.3	)	$	(3.9	)

TEC’s portion of the net periodic benefit costs for pension benefits was $13.5 million, $14.8 million and $21.7 million for 2015, 2014 and 2013, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $5.7 million, $10.4 million and $10.0 million for 2015, 2014 and 2013, respectively.

The estimated net loss for the defined benefit pension plans that will be amortized by TEC from regulatory assets into net periodic benefit cost over the next fiscal year are $9.8 million. There will be an estimated $1.9 million prior service credit that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year for the other postretirement benefit plan.

Assumptions used to determine net periodic benefit cost for years ended Dec. 31:

	Pension Benefits									Other Benefits
	2015			2014 (1)			2013			2015			2014			2013
Discount rate		4.258	%	5.118%/4.277%/4.331%				4.196	%		4.211	%		5.096	%		4.180	%
Expected long-term return on plan assets		7.00	%	7.25%/7.00%/7.00%				7.50	%		5.75			5.75		n/a
Rate of compensation increase		3.87	%		3.73	%		3.76	%		3.86	%		3.71	%		3.74	%
Healthcare cost trend rate
Initial rate	n/a			n/a			n/a				7.09	%		7.25	%		7.50	%
Ultimate rate	n/a			n/a			n/a				4.57	%		4.50	%		4.50	%
Year rate reaches ultimate	n/a			n/a			n/a			2025			2025			2025
(1)TECO Energy performed a valuation as of Jan. 1, 2014. TECO remeasured its Retirement Plan on Sept. 2, 2014 for the acquisition of NMGC and on Oct. 31, 2014 for the expected curtailment of TECO Coal, resulting in the respective updated discount rates and EROAs.

The discount rate assumption used to determine the 2015 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate.

The expected return on assets assumption was based on historical returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets.

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Additionally, expectations of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2015, TECO Energy’s pension plan’s assets decreased approximately 3.5%.

The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases.

A one-percentage-point change in assumed health care cost trend rates would have the following effect on TEC’s expense:

(millions)	1%  Increase		1%  Decrease
Effect on periodic cost	$	0.2	$	(0.2	)

Pension Plan Assets

Pension plan assets (plan assets) are invested in a mix of equity and fixed income securities. TECO Energy’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. TECO Energy’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.

	Target  Allocation		ActualAllocation, End of Year
Asset Category			2015			2014
Equity securities	47%-53%			53	%		50	%
Fixed income securities	47%-53%			47	%		50	%
Total		100%		100	%		100	%

TECO Energy reviews the plan’s asset allocation periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. TECO Energy, Inc. expects to take additional steps to more closely match plan assets with plan liabilities.

The plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). Investments are valued using quoted market prices on an exchange when available. Such investments are classified Level 1. In some cases where a market exchange price is available but the investments are traded in a secondary market, acceptable practical expedients are used to calculate fair value.

If observable transactions and other market data are not available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable.

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As required by the fair value accounting standards, the investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2015 and 2014.

Pension Plan Investments

(millions)	At Fair Value as of Dec. 31, 2015
	Level 1			Level 2			Level  3		Using NAV (1)		Total
Net cash
Cash	$	1.9		$	0.0		$	0.0	$	0.0	$	1.9
Accounts receivable		14.3			0.0			0.0		0.0		14.3
Accounts payable		(27.2	)		0.0			0.0		0.0		(27.2	)
Total net cash		(11.0	)		0.0			0.0		0.0		(11.0	)
Cash equivalents
Money markets		0.0			0.2			0.0		0.0		0.2
Discounted notes		0.0			0.7			0.0		0.0		0.7
Short-term investment funds (STIFs) (1)		0.0			0.0			0.0		12.4		12.4
Total cash equivalents		0.0			0.9			0.0		12.4		13.3
Equity securities
Common stocks		90.9			0.0			0.0		0.0		90.9
American depository receipts (ADRs)		5.7			0.0			0.0		0.0		5.7
Real estate investment trusts (REITs)		4.8			0.0			0.0		0.0		4.8
Commingled fund		0.0			53.7			0.0		0.0		53.7
Mutual funds (1)		0.0			0.0			0.0		175.6		175.6
Total equity securities		101.4			53.7			0.0		175.6		330.7
Fixed income securities
Municipal bonds		0.0			5.0			0.0		0.0		5.0
Government bonds		0.0			56.2			0.0		0.0		56.2
Corporate bonds		0.0			32.2			0.0		0.0		32.2
Asset backed securities (ABS)		0.0			0.3			0.0		0.0		0.3
Mortgage-backed securities (MBS), net short sales		0.0			8.7			0.0		0.0		8.7
Collateralized mortgage obligations (CMOs)		0.0			1.5			0.0		0.0		1.5
Commingled fund (1)		0.0			0.0			0.0		117.9		117.9
Mutual fund (1)		0.0			0.0			0.0		71.3		71.3
Total fixed income securities		0.0			103.9			0.0		189.2		293.1
Derivatives
Swaps		0.0			(0.9	)		0.0		0.0		(0.9	)
Purchased options (swaptions)		0.0			1.1			0.0		0.0		1.1
Written options (swaptions)		0.0			(1.0	)		0.0		0.0		(1.0	)
Total derivatives		0.0			(0.8	)		0.0		0.0		(0.8	)
Miscellaneous		0.0			0.1			0.0		0.0		0.1
Total	$	90.4		$	157.8		$	0.0	$	377.2	$	625.4

(1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet.

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(millions)	At Fair Value as of Dec. 31, 2014
	Level 1			Level 2			Level  3		Using NAV (1)		Total
Net cash
Cash	$	0.4		$	0.0		$	0.0	$	0.0	$	0.4
Accounts receivable		1.4			0.0			0.0		0.0		1.4
Accounts payable		(5.3	)		0.0			0.0		0.0		(5.3	)
Total net cash		(3.5	)		0.0			0.0		0.0		(3.5	)
Cash equivalents
Treasury bills (T bills)		0.0			0.2			0.0		0.0		0.2
Discounted notes		0.0			8.8			0.0		0.0		8.8
Short-term investment funds (STIFs) (1)		0.0			0.0			0.0		7.6		7.6
Total cash equivalents		0.0			9.0			0.0		7.6		16.6
Equity securities
Common stocks		98.0			0.0			0.0		0.0		98.0
American depository receipts (ADRs)		1.3			0.0			0.0		0.0		1.3
Real estate investment trusts (REITs)		2.5			0.0			0.0		0.0		2.5
Preferred stock		0.8			0.0			0.0		0.0		0.8
Commingled fund		0.0			45.6			0.0		0.0		45.6
Mutual funds (1)		0.0			0.0			0.0		171.3		171.3
Total equity securities		102.6			45.6			0.0		171.3		319.5
Fixed income securities
Municipal bonds		0.0			6.1			0.0		0.0		6.1
Government bonds		0.0			47.9			0.0		0.0		47.9
Corporate bonds		0.0			22.0			0.0		0.0		22.0
Asset backed securities (ABS)		0.0			0.3			0.0		0.0		0.3
Mortgage-backed securities (MBS), net short sales		0.0			9.6			0.0		0.0		9.6
Collateralized mortgage obligations (CMOs)		0.0			2.0			0.0		0.0		2.0
Commingled fund (1)		0.0			0.0			0.0		129.20		129.2
Mutual fund (1)		0.0			0.0			0.0		98.6		98.6
Total fixed income securities		0.0			87.9			0.0		227.8		315.7
Derivatives
Short futures		0.0			(0.3	)		0.0		0.0		(0.3	)
Purchased options (swaptions)		0.0			0.7			0.0		0.0		0.7
Written options (swaptions)		0.0			(0.8	)		0.0		0.0		(0.8	)
Total derivatives		0.0			(0.4	)		0.0		0.0		(0.4	)
Miscellaneous		0.0			0.1			0.0		0.0		0.1
Total	$	99.1		$	142.2		$	0.0	$	406.7	$	648.0

(1) In accordance with accounting standards, certain investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy to amounts presented in the Consolidated Balance Sheet.

The following list details the pricing inputs and methodologies used to value the investments in the pension plan:

● The primary pricing inputs in determining the fair value of the Level 1 assets are closing quoted prices in active markets.

● The methodology and inputs used to value the investment in the equity commingled fund are broker dealer quotes sourced by State Street Custody System.  The fund holds primarily international equity securities that are actively traded in over-the-counter markets. The fund honors subscription and redemption activity on an “as of” basis.

● The money markets are valued at cost due to their short-term nature. Discounted notes are valued at amortized cost.

● The primary pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMO are priced using TBA prices, treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information.

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● Futures are valued using futures data, cash rate data, swap rates, and cash flow analyses.

● Swaps are valued using benchmark yields, swap curves, and cash flow analyses.

● Options are valued using the bid-ask spread and the last price.

● The STIF is valued at NAV as determined by JP Morgan. The funds are open-end investments. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV.

● The primary pricing inputs in determining the equity mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV.

● The primary pricing input in determining the fair value of the fixed asset mutual fund is its NAV. It is an unregistered open-ended mutual fund.

● The fixed income commingled fund is a private fund valued at NAV. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15^th calendar day of the month. Redemptions are honored on the 15^th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date.

Additionally, the unqualified SERP had $43.5 million and $0.9 million of assets as of Dec. 31, 2015 and 2014, respectively. Since the plan is unqualified, its assets are included in the “Deferred charges and other assets” line item in TECO Energy’s Consolidated Balance Sheets rather than being netted with the related liability. The fund holds investments in a money market fund, which is valued at cost due to its short-term nature, making this a level 2 asset. The SERP was fully funded as of Dec. 31, 2015.

Other Postretirement Benefit Plan Assets

There are no assets associated with TECO Energy’s other postretirement benefits plan. Asset amounts shown in the tables above relate to a separate NMGC other postretirement benefit plan.

Contributions

The Pension Protection Act became effective Jan. 1, 2008 and requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional plan disclosures in regulatory filings and to plan participants.

WRERA was signed into law on Dec. 23, 2008. WRERA grants plan sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2013, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In August 2014, the President signed into law HAFTA, which modified MAP-21. HAFTA and MAP-21 provide funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. TECO Energy expects the required minimum pension contributions to be lower than the levels previously projected; however, TECO Energy plans on funding at levels above the required minimum pension contributions under HAFTA and MAP-21. In November 2015, the President signed into law the Bipartisan Budget Act of 2015, which extended pension funding relief of MAP-21 and HAFTA through 2022.

The qualified pension plan’s actuarial value of assets, including credit balance, was 120.1% of the Pension Protection Act funded target as of Jan. 1, 2015 and is estimated at 114.1% of the Pension Protection Act funded target as of Jan. 1, 2016.

TECO Energy’s policy is to fund the qualified pension plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TECO Energy made $55.0 million of contributions to this plan in 2015 and $47.5 million in 2014, which met the minimum funding requirements for both 2015 and 2014. TEC’s portion of the contribution in 2015 was $43.9 million and in 2014 was $38.2 million. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. TECO Energy estimates its contribution in 2016 to be $37.4 million, with TEC’s portion being $30.9 million. TECO Energy estimates it will make annual contributions from 2017 to 2020 ranging from $12.2 to $44.6 million per year based on current assumptions, with TEC’s portion to range from $8.0 million to $35.0 million. These amounts are in excess of the minimum funding required under ERISA guidelines.

TECO Energy made contributions of $43.4 million and $1.2 million to the SERP in 2015 and 2014, respectively. TEC’s portion of the contributions in 2015 and 2014 were $14.9 million and $0.8 million, respectively. TECO Energy’s contribution in October 2015 to the SERP’s trust was made in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera.

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The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current participants. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2016.

The other postretirement benefits are funded annually to meet benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. TECO Energy’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2016, TECO Energy expects to make a contribution of about $14.3 million. TEC’s portion of the expected contribution is $9.3 million. Postretirement benefit levels are substantially unrelated to salary.

Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

Expected Benefit Payments—TECO Energy

(including projected service and net of employee contributions)			Other
	Pension		Postretirement
(millions)	Benefits		Benefits
2016	$	77.8	$	11.5
2017		49.5		11.9
2018		52.7		12.5
2019		59.2		13.0
2020		54.9		13.3
2021-2025		299.1		68.6

Defined Contribution Plan

TECO Energy has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match up to 6% of the participant’s payroll savings deductions. Effective Jan. 1, 2015, the employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain operating company financial goals. During the period from April 2013 to December 2014, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions with additional incentive match of up to 40%. For the years ended Dec. 31, 2015, 2014 and 2013, TECO Energy and its subsidiaries recognized expense totaling $11.1 million, $13.1 million and $11.3 million, respectively, related to the matching contributions made to this plan. TEC’s portion of expense totaled $7.5 million, $10.2 million and $9.1 million for 2015, 2014 and 2013, respectively.

6. Short-Term Debt

At Dec. 31, 2015 and 2014, the following credit facilities and related borrowings existed:

Credit Facilities

	Dec. 31,  2015						Dec. 31,  2014
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	12.0	$	0.6
3-year accounts receivable facility (3)		150.0		61.0		0.0		150.0		46.0		0.0
Total	$	475.0	$	61.0	$	0.5	$	475.0	$	58.0	$	0.6

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Dec. 17, 2018.

(3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.

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At Dec. 31, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at Dec. 31, 2015 and 2014 was 0.89% and 0.7%, respectively.

Tampa Electric Company Accounts Receivable Facility

On Mar. 24, 2015, TEC and TRC amended and restated their $150 million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and (iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Pursuant to the Loan Agreement, TRC will pay program and liquidity fees, which total 65 basis points as of Dec. 31, 2015. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s option, either the BTMU’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank deposit rate (if available) plus a margin.  In addition, under the terms of the Loan Agreement, TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of Dec. 31, 2015, TEC and TRC were in compliance with the requirements of the Loan Agreement.  

Amendment of Tampa Electric Company Credit Facility

On Dec. 17, 2013, TEC amended and restated its $325 million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further extension with the consent of each lender); (ii) continues to allow TEC, as borrower, to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

On Sept. 30, 2014, TEC entered into an amendment of its $325 million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes.

7. Long-Term Debt  

A substantial part of Tampa Electric’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time.

Issuance of Tampa Electric Company 4.20% Notes due 2045

On May 20, 2015, TEC completed an offering of $250 million aggregate principal amount of 4.20% Notes due May 15, 2045 (the TEC 2015 Notes).  The TEC 2015 Notes were sold at 99.814% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any part of the TEC 2015 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2015 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the TEC 2015 Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.  At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the TEC 2015 Notes, in whole or in part, at 100% of the principal amount of the TEC 2015 Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Issuance of Tampa Electric Company 4.35% Notes due 2044

On May 15, 2014, TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the TEC 2014 Notes). The TEC 2014 Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting

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underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the TEC 2014 Notes at its option at any time and from time to time before Nov. 15, 2043 at a redemption price equal to the greater of (i) 100% of the principal amount of TEC 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the TEC 2014 Notes, in whole or in part, at 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.

Purchase in Lieu of Redemption of Revenue Refunding Bonds

On Mar. 15, 2012, TEC purchased in lieu of redemption $86.0 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds). On Mar. 19, 2008, the HCIDA had remarketed the Series 2006 HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from Mar. 19, 2008 to Mar. 15, 2012. TEC is responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.

On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from Mar. 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.

As of Dec. 31, 2015, $232.6 million of bonds purchased in lieu of redemption were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

8. Other Comprehensive Income

TEC reported the following OCI (loss) for the years ended Dec. 31, 2015, 2014 and 2013, related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges:

Other Comprehensive Income

(millions)	Gross		Tax			Net
2015
Unrealized gain (loss) on cash flow hedges	$	4.3	$	(1.5	)	$	2.8
Reclassification from AOCI to net income		1.4		(0.7	)		0.7
Gain (Loss) on cash flow hedges		5.7		(2.2	)		3.5
Total other comprehensive income (loss)	$	5.7	$	(2.2	)	$	3.5
2014
Unrealized gain (loss) on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		1.1		(0.4	)		0.7
Gain (Loss) on cash flow hedges		1.1		(0.4	)		0.7
Total other comprehensive income (loss)	$	1.1	$	(0.4	)	$	0.7
2013
Unrealized gain (loss) on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		1.4		(0.5	)		0.9
Gain (Loss) on cash flow hedges		1.4		(0.5	)		0.9
Total other comprehensive income (loss)	$	1.4	$	(0.5	)	$	0.9

Accumulated Other Comprehensive Loss

(millions) As of Dec. 31,	2015			2014
Net unrealized losses from cash flow hedges (1)	$	(3.6	)	$	(7.1	)
Total accumulated other comprehensive loss	$	(3.6	)	$	(7.1	)

(1) Net of tax benefit of $2.3 million and $4.5 million as of Dec. 31, 2015 and 2014, respectively.

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9. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. TEC is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the TEC’s results of operations, financial condition or cash flows.

Tampa Electric Legal Proceedings

A 36-year-old man died from mesothelioma in March 2014. His estate and his family sued Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and 14 other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to TEC’s financial position as of Dec. 31, 2015.

A 33-year-old man made contact with a primary line in June 2013, suffering severe burns. He and his wife sued Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence.  Plaintiffs' case against Tampa Electric alleged, among other things, negligence and loss of consortium.  Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to TEC’s financial position as of Dec. 31, 2015.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in late 2016.

PGS Compliance Matter
          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. PGS is continuing to work with the OPC and FPSC staff to resolve the issues.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2015, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

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In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

Long-Term Commitments

TEC has commitments for capacity payments and long-term leases, primarily for building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations & maintenance – Other” on the Consolidated Statements of Income for the years ended Dec. 31, 2015, 2014 and 2013, totaled $3.8 million, $4.1 million and $2.3 million, respectively. In addition, Tampa Electric has other purchase obligations, including its outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines.   The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year, capacity payments under PPAs, and other net purchase obligations/commitments at Dec. 31, 2015:

	Capacity		Operating		Net Purchase
(millions)	Payments		Leases(1)		Obligations/Commitments (1)		Total
Year ended Dec. 31:
2016	$	14.6	$	5.7	$	218.3	$	238.6
2017		9.9		5.2		21.5		36.6
2018		10.1		4.7		9.6		24.4
2019		0.0		4.4		9.7		14.1
2020		0.0		4.1		4.7		8.8
Thereafter		0.0		14.5		20.0		34.5
Total future minimum payments	$	34.6	$	38.6	$	283.8	$	357.0

(1) Excludes payment obligations under contractual agreements of Tampa Electric and PGS for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses approved by the FPSC annually.

Guarantees and Letters of Credit

At Dec. 31, 2015, TEC was not obligated under guarantees, but had the following letters of credit outstanding.

(millions)	Year of Expiration						Maximum
					After (1)		Theoretical		Liabilities  Recognized
Letter of Credit for the Benefit of:	2016		2017-2020		2020		Obligation		at Dec. 31, 2015 (2)
TEC	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1

(1) These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020.

(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Dec. 31, 2015. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

Financial Covenants

In order to utilize their respective bank credit facilities, TEC must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2015, TEC was in compliance with all required financial covenants.

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10. Related Party Transactions

A summary of activities between TEC and its affiliates follows:

Net transactions with affiliates:

(millions)	2015		2014		2013
Natural gas sales, net	$	0.8	$	0.3	$	18.3
Administrative and general, net(1)	$	69.4	$	22.5	$	27.2

(1) The 2015 increase in transactions with affiliates is attributable to shared services being provided to TEC from TSI, TECO Energy’s centralized services company subsidiary, beginning in Jan. 1, 2015.

Amounts due from or to affiliates at Dec. 31,

(millions)	2015		2014
Accounts receivable(1)	$	2.3	$	2.4
Accounts payable(1)		15.9		9.7
Taxes receivable(2)		61.3		43.3
Taxes payable(2)		1.0		0.0

(1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.

(2) Taxes receivable are due from, and taxes payable are due to, TECO Energy.

TEC had certain transactions, in the ordinary course of business, with entities in which directors of TEC had interests. TEC paid legal fees of $1.7 million for the year ended Dec. 31, 2013 to Ausley McMullen, P.A. of which Mr. Ausley (who was a director of TEC, until his retirement from the Board in May 2013) was an employee.

11. Segment Information

TEC is a public utility operating within the State of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to almost 719,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and marketing of natural gas for approximately 361,000 residential, commercial, industrial and electric power generation customers in the State of Florida.

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	Tampa
(millions)	Electric		PGS		Eliminations			TEC
2015
Revenues - external	$	2,017.7	$	401.5	$	0.0		$	2,419.2
Sales to affiliates		0.6		6.0		(6.6	)		0.0
Total revenues		2,018.3		407.5		(6.6	)		2,419.2
Depreciation and amortization		256.7		56.8		0.0			313.5
Total interest charges		95.1		14.5		0.0			109.6
Provision for income taxes		143.6		21.9		0.0			165.5
Net income		241.0		35.3		0.0			276.3
Total assets		6,637.1		1,099.0		(9.4	)		7,726.7
Capital expenditures		592.6		94.0		0.0			686.6
2014
Revenues - external	$	2,020.5	$	398.5	$	0.0		$	2,419.0
Sales to affiliates		0.5		1.1		(1.6	)		0.0
Total revenues		2,021.0		399.6		(1.6	)		2,419.0
Depreciation and amortization		248.6		54.0		0.0			302.6
Total interest charges		92.8		13.8		0.0			106.6
Provision for income taxes		133.2		22.7		0.0			155.9
Net income		224.5		35.8		0.0			260.3
Total assets		6,234.4		1,047.0		(7.1	)		7,274.3
Capital expenditures		582.1		88.9		0.0			671.0
2013
Revenues - external	$	1,950.1	$	392.7	$	0.0		$	2,342.8
Sales to affiliates		0.4		0.8		(1.2	)		0.0
Total revenues		1,950.5		393.5		(1.2	)		2,342.8
Depreciation and amortization		238.8		51.5		0.0			290.3
Total interest charges		91.8		13.5		0.0			105.3
Provision for income taxes		116.9		21.9		0.0			138.8
Net income		190.9		34.7		0.0			225.6
Total assets		5,895.4		989.3		(8.9	)		6,875.8
Capital expenditures		422.3		79.0		0.0			501.3

12. Asset Retirement Obligations

TEC accounts for AROs under the applicable accounting standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.

When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.

As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.

For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.

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Reconciliation of beginning and ending carrying amount of asset retirement obligations:

	Dec. 31,
(millions)	2015			2014
Beginning balance	$	5.3		$	4.8
Additional liabilities		0.9			0.1
Revisions to estimated cash flows		(0.5	)		0.2
Other (1)		0.3			0.2
Ending balance	$	6.0		$	5.3

(1) Accretion recorded as a deferred regulatory asset.

13. Accounting for Derivative Instruments and Hedging Activities

From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes:

· To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and

· To limit the exposure to interest rate fluctuations on debt securities.

TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by TEC provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.

TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 14). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

TEC applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Dec. 31, 2015, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Dec. 31, 2015 and 2014 are reflected on TEC’s Consolidated Balance Sheets and classified accordingly as current and long term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were no derivative assets as of Dec. 31, 2015 and 2014. Derivative liabilities totaled $26.2 million and $42.7 million as of Dec. 31, 2015 and 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties.

All of the derivative asset and liabilities at Dec. 31, 2015 and 2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Balance Sheets as current and long term regulatory assets and liabilities. Based on the fair value of the instruments at Dec. 31, 2015, net pretax losses of $24.1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months.

The Dec. 31, 2015 and 2014 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 8.

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For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the years ended Dec. 31, 2015, 2014 and 2013, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the years ended Dec. 31, 2015, 2014 and 2013 is presented in Note 8. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in Interest expense.

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Nov. 30, 2017 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Dec. 31, 2015, are expected to settle during the 2016 and 2017 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		27.6
2017		0.0		5.0
Total		0.0		32.6

TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of Dec. 31, 2015, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.  

14. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1: Observable inputs, such as quoted prices in active markets;

Level 2: Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

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Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

(A) Market approach: Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities;

(B) Cost approach: Amount that would be required to replace the service capacity of an asset (replacement cost); and

(C) Income approach: Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models).

The fair value of financial instruments is determined by using various market data and other valuation techniques.

The following table sets forth by level within the fair value hierarchy TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Dec. 31, 2015 and 2014. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  

Recurring Derivative Fair Value Measures

	As of Dec. 31, 2015
(millions)	Level  1		Level  2		Level  3		Total
Liabilities
Natural gas swaps	$	0.0	$	26.2	$	0.0	$	26.2
	As of Dec. 31, 2014
(millions)	Level  1		Level  2		Level  3		Total
Liabilities
Natural gas swaps	$	0.0	$	42.7	$	0.0	$	42.7

Natural gas swaps are OTC swap instruments. The fair value of the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the reported fair value (see Note 13).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At Dec. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

15. Variable Interest Entities

The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 157 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric is not required to consolidate any of these entities. Tampa Electric purchased $33.6 million, $25.7 million and $22.1 million, under these PPAs for the three years ended Dec. 31, 2015, 2014 and 2013, respectively.

TEC does not provide any material financial or other support to any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. In the normal course of business, TEC’s involvement with these VIEs does not affect its Consolidated Balance Sheets, Statements of Income or Cash Flows.

157

16. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt (of which TEC’s portion of debt was $2.3 billion).

The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC, was obtained on Jan. 20, 2016), (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.

The Merger Agreement contains certain termination rights for both TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

158

EX-4.8

Exhibit 4.8

Item 9A. CONTROLS AND PROCEDURES.

TECO Energy, Inc.

Conclusions Regarding Effectiveness of Disclosure Controls and Procedures.

TECO Energy’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of TECO Energy’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this annual report, Dec. 31, 2015 (Evaluation Date). Based on such evaluation, TECO Energy’s principal executive officer and principal financial officer have concluded that, as of the Evaluation Date, TECO Energy’s disclosure controls and procedures are effective.

Management’s Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. We conducted an evaluation of the effectiveness of TECO Energy, Inc.’s internal control over financial reporting as of Dec. 31, 2015 based on the 2013 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that TECO Energy, Inc.’s internal control over financial reporting was effective as of Dec. 31, 2015.

TECO Energy’s internal control over financial reporting as of Dec. 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered certified public accounting firm, as stated in their report which appears herein.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. A control system, no matter how well designed and operated, can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting.

There were no changes in TECO Energy’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of TECO Energy’s internal controls that occurred during TECO Energy’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

Tampa Electric Company

Conclusions Regarding Effectiveness of Disclosure Controls and Procedures.

TEC’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of TEC’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this annual report, Dec. 31, 2015 (Evaluation Date). Based on such evaluation, TEC’s principal executive officer and principal financial officer have concluded that, as of the Evaluation Date, TEC’s disclosure controls and procedures are effective.

159

Management’s Report on Internal Control over Financial Reporting.

TEC’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. We conducted an evaluation of the effectiveness of TEC’s internal control over financial reporting as of Dec. 31, 2015 based on the 2013 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that TEC’s internal control over financial reporting was effective as of Dec. 31, 2015.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. A control system, no matter how well designed and operated, can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting.

There was no change in Tampa Electric Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of Tampa Electric Company’s internal controls that occurred during Tampa Electric Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.

160

EX-4.9

Exhibit 4.9

PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

4

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets

Unaudited

Assets	Mar. 31,			Dec. 31,
(millions)	2016			2015
Current assets
Cash and cash equivalents	$	46.1		$	23.8
Receivables, less allowance for uncollectibles of $2.1 and $2.1    at Mar. 31, 2016 and Dec. 31, 2015, respectively		240.1			280.7
Inventories, at average cost
Fuel	118.3			113.4
Materials and supplies		77.1			76.8
Regulatory assets		40.2			44.8
Prepayments and other current assets		25.4			30.8
Total current assets		547.2			570.3
Property, plant and equipment
Utility plant in service
Electric		7,328.3			7,270.3
Gas		2,154.1			2,113.8
Construction work in progress		816.9			794.7
Other property		16.1			15.9
Property, plant and equipment, at original costs		10,315.4			10,194.7
Accumulated depreciation		(2,762.4	)		(2,712.9	)
Total property, plant and equipment, net		7,553.0			7,481.8
Other assets
Regulatory assets		393.4			395.2
Goodwill		408.4			408.4
Deferred charges and other assets		79.1			77.8
Total other assets		880.9			881.4
Total assets	$	8,981.1		$	8,933.5

The accompanying notes are an integral part of the consolidated condensed financial statements.

5

TECO ENERGY, INC.

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capital	Mar. 31,			Dec. 31,
(millions)	2016			2015
Current liabilities
Long-term debt due within one year	$	83.3		$	333.3
Notes payable		513.0			247.0
Accounts payable		189.5			255.4
Customer deposits		176.7			182.1
Regulatory liabilities		108.4			84.8
Derivative liabilities		22.3			24.1
Interest accrued		54.0			36.2
Taxes accrued		28.2			13.2
Other		25.2			22.6
Total current liabilities		1,200.6			1,198.7
Other liabilities
Deferred income taxes		607.0			570.7
Investment tax credits		10.4			10.5
Regulatory liabilities		709.4			715.8
Derivative liabilities		0.8			2.1
Deferred credits and other liabilities		380.9			387.5
Long-term debt, less amount due within one year		3,489.7			3,489.2
Total other liabilities		5,198.2			5,175.8
Commitments and contingencies (see Note 10)
Capital
Common equity (400.0 million shares authorized; par value $1; 235.5 million    and 235.3 million shares outstanding at Mar. 31, 2016 and Dec. 31, 2015,    respectively)		235.5			235.3
Additional paid in capital		1,894.8			1,894.5
Retained earnings		463.5			441.4
Accumulated other comprehensive loss		(11.5	)		(12.2	)
Total capital		2,582.3			2,559.0
Total liabilities and capital	$	8,981.1		$	8,933.5

The accompanying notes are an integral part of the consolidated condensed financial statements.

6

TECO ENERGY, INC.

Consolidated Condensed Statements of Income

Unaudited

		Three months ended Mar. 31,
(millions, except per share amounts)		2016			2015
Revenues
Regulated electric		$	423.4		$	449.7
Regulated gas			232.9			240.2
Unregulated			3.2			3.1
Total revenues			659.5			693.0
Expenses
Regulated operations and maintenance
Fuel			115.2			144.1
Purchased power			14.4			17.1
Cost of natural gas sold			96.8			103.0
Other			142.3			143.7
Operation and maintenance other expense			0.0			1.6
Depreciation and amortization			89.8			85.5
Taxes, other than income			52.9			51.8
Total expenses			511.4			546.8
Income from operations			148.1			146.2
Other income
Allowance for other funds used during construction			5.7			3.8
Other income, net			1.5			1.6
Total other income			7.2			5.4
Interest charges
Interest expense			48.9			49.8
Allowance for borrowed funds used during construction			(3.0	)		(1.9	)
Total interest charges			45.9			47.9
Income from continuing operations before provision for    income taxes			109.4			103.7
Provision for income taxes			35.7			39.9
Net income from continuing operations			73.7			63.8
Discontinued operations
Income (loss) from discontinued operations			0.2			(9.6	)
Provision (benefit) from income taxes			0.1			(3.8	)
Income (loss) from discontinued operations, net			0.1			(5.8	)
Net income		$	73.8		$	58.0
Average common shares outstanding	– Basic		234.0			232.8
	– Diluted		235.2			233.5
Earnings per share from continuing operations	– Basic	$	0.31		$	0.27
	– Diluted	$	0.31		$	0.27
Earnings per share from discontinued operations	– Basic	$	0.00		$	(0.02	)
	– Diluted	$	0.00		$	(0.02	)
Earnings per share	– Basic	$	0.31		$	0.25
	– Diluted	$	0.31		$	0.25
Dividends paid per common share outstanding		$	0.230		$	0.225

The accompanying notes are an integral part of the consolidated condensed financial statements.

7

TECO ENERGY, INC.

Consolidated Condensed Statements of Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2016		2015
Net income	$	73.8	$	58.0
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2		0.3
Amortization of unrecognized benefit costs		0.5		0.6
Other comprehensive income, net of tax		0.7		0.9
Comprehensive income	$	74.5	$	58.9

The accompanying notes are an integral part of the consolidated condensed financial statements.

8

TECO ENERGY, INC.

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2016			2015
Cash flows from operating activities
Net income	$	73.8		$	58.0
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		89.8			85.9
Deferred income taxes and investment tax credits		36.1			36.0
Allowance for other funds used during construction		(5.7	)		(3.8	)
Non-cash stock compensation		3.0			3.9
Deferred recovery clauses		26.4			(5.7	)
Receivables, less allowance for uncollectibles		40.6			51.0
Inventories		(5.2	)		(15.7	)
Prepayments and other current assets		2.8			(10.9	)
Taxes accrued		18.1			1.7
Interest accrued		17.8			17.8
Accounts payable		(59.1	)		(63.5	)
Other		(6.8	)		(7.7	)
Cash flows from operating activities		231.6			147.0
Cash flows from investing activities
Capital expenditures		(168.0	)		(156.2	)
Other investing activities		(0.2	)		(0.2	)
Cash flows used in investing activities		(168.2	)		(156.4	)
Cash flows from financing activities
Dividends and dividend equivalents		(54.3	)		(53.0	)
Proceeds from the sale of common stock		3.9			2.8
Repayment of long-term debt/purchase in lieu of redemption		(250.0	)		0.0
Net increase (decrease) in short-term debt (maturities of 90 days or less)		(134.0	)		67.0
Proceeds from other short-term debt (maturities over 90 days)		400.0			0.0
Other financing activities		(6.7	)		0.0
Cash flows from (used in) financing activities		(41.1	)		16.8
Net increase in cash and cash equivalents		22.3			7.4
Cash and cash equivalents at beginning of the period		23.8			25.4
Cash and cash equivalents at end of the period	$	46.1		$	32.8
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(6.0	)	$	11.5

The accompanying notes are an integral part of the consolidated condensed financial statements.

9

TECO ENERGY, INC.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TECO Energy, Inc.’s 2015 Annual Report on Form 10-K for a complete discussion of the company’s accounting policies. The significant accounting policies for all utility and diversified operations include:

Principles of Consolidation and Basis of Presentation

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and its subsidiaries as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 16 for further information.

Revenues

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $67.3 million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipt Taxes

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million for the three months ended Mar. 31, 2016 and 2015, respectively.

NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line-item impact on the Consolidated Condensed Statements of Income.

2. New Accounting Pronouncements

Change in Accounting Policy

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for the company beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, the company classified $26.4 million and $27.7 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified in the “Deferred charges and other assets” line item). The guidance did not affect the company’s results of operations or cash flows.

Stock Compensation

In March 2016, the FASB issued guidance regarding employee share-based payment accounting. The guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, accounting for forfeitures, classification of awards as either equity or liability, and presentation on the statement of cash flows. This guidance will be required for the company beginning in 2017. As early adoption is permitted, the company adopted the standard as of Jan. 1, 2016. Each aspect has an accounting impact and was implemented as follows:

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· Income tax consequences – Under the new guidance, the company will no longer recognize excess tax benefits and certain tax deficiencies in additional paid in capital. Instead, the company will recognize all excess tax benefits and tax deficiencies as income tax expense or benefit on the income statement. In addition, the guidance eliminates the requirement that excess tax benefits be realized before the company can recognize them. Accordingly, the company recorded a $2.6 million cumulative adjustment to retained earnings as of Jan. 1, 2016 for excess tax benefits related to prior periods. In accordance with the new guidance, the company will no longer include excess tax benefits and tax deficiencies in the dilutive EPS calculation on a prospective basis.

· Accounting for forfeitures – The company’s policy is to estimate the number of awards expected to be forfeited, which is consistent with prior periods.

· Classification of awards - The company had no share-based payments classified as liability awards as of Mar. 31, 2016 or Dec. 31, 2015.  

· Presentation on the statement of cash flows – Excess tax benefits are required to be presented as an operating activity on the statement of cash flows rather than as a financing activity. The change may be applied retrospectively or prospectively. The company elected to apply it prospectively, and prior periods were not retrospectively adjusted. Additionally, employee taxes paid by an employer to a tax authority when shares are withheld for tax-withholding purposes are required to be presented as a financing activity on a retrospective basis for all periods presented. Previously, the company presented it as an operating activity. There was an immaterial amount of activity that did not result in an adjustment to the statement of cash flows for the three months ended Mar. 31, 2015.

Future Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers.  This guidance will be effective for the company beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The company expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. The company does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for the company beginning in 2018.

Leases

In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. Recognition of expenses for both operating and finance leases will be similar to existing guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. This guidance will be effective for the company beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. The company is currently evaluating the impacts of the adoption of the guidance on its financial statements.

Derivative Contract Novations

In March 2016, the FASB issued guidance clarifying that a change in the counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The guidance is effective for the company beginning in 2017, with early adoption permitted, and may be applied on a prospective or modified retrospective basis. The guidance will not affect the company’s current financial statements. However, the company will assess the impact of this guidance on future derivative contract novations, if any.

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3. Regulatory

Tampa Electric’s retail business and PGS are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC has jurisdiction over the regulatory matters related, directly and indirectly, to NMGC providing service to its customers, including, among other things, rates, accounting procedures, securities issuances, and standards of service. NMGC must follow certain accounting guidance that pertains specifically to entities that are subject to such regulation. Comparable to the FPSC, the NMPRC sets rates at a level that allows utilities such as NMGC to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

Regulatory Assets and Liabilities

Tampa Electric, PGS and NMGC apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

Details of the regulatory assets and liabilities as of Mar. 31, 2016 and Dec. 31, 2015 are presented in the following table:

Regulatory Assets and Liabilities
(millions)	Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	77.1	$	74.7
Cost-recovery clauses - deferred balances (2)		0.1		5.5
Cost-recovery clauses - offsets to derivative liabilities (2)		26.0		26.5
Environmental remediation (3)		54.4		54.0
Postretirement benefits (4)		238.5		240.6
Deferred bond refinancing costs (5)		6.2		6.5
Debt basis adjustment (6)		16.7		17.5
Competitive rate adjustment (2)		2.5		2.6
Other		12.1		12.1
Total regulatory assets		433.6		440.0
Less: Current portion		40.2		44.8
Long-term regulatory assets	$	393.4	$	395.2
Regulatory liabilities:
Regulatory tax liability	$	7.6	$	7.9
Cost-recovery clauses (2)		80.0		55.9
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (7)		673.6		679.9
Other		0.5		0.8
Total regulatory liabilities		817.8		800.6
Less: Current portion		108.4		84.8
Long-term regulatory liabilities	$	709.4	$	715.8

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.

(2) These assets and liabilities are related to FPSC and NMPRC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

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(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This asset represents the difference between the fair value and pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt instrument.

(7) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

4. Income Taxes

The effective tax rate decreased to 32.63% for the three months ended Mar. 31, 2016 from 38.48% for the same period in 2015 primarily due to the tax benefit related to long-term incentive compensation share vestings (see Note 2 for further description).

The company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. U.S. state jurisdictions have statutes of limitations generally ranging from three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by taxing authorities in major state jurisdictions and foreign jurisdictions include 2005 and forward. TECO Energy does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016.

5. Employee Postretirement Benefits

Included in the table below is the periodic expense for pension and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP.

Pension Expense
(millions)	Pension Benefits						Other Postretirement Benefits
Three months ended Mar. 31,	2016			2015			2016			2015
Components of net periodic benefit expense
Service cost	$	4.4		$	4.5		$	0.5		$	0.6
Interest cost		8.1			7.4			2.2			2.0
Expected return on assets		(11.3	)		(10.8	)		(0.3	)		(0.3	)
Amortization of:
Prior service (benefit) cost		0.0			(0.1	)		(0.6	)		(0.6	)
Actuarial loss		3.4			3.4			0.0			0.0
Regulatory asset		0.0			0.0			0.2			0.3
Net pension expense recognized in the    TECO Energy Consolidated Condensed Statements of Income	$	4.6		$	4.4		$	2.0		$	2.0

For the fiscal 2016 plan year, TECO Energy is using an assumed long-term EROA of 7.00% and a discount rate of 4.685% for pension benefits under its qualified pension plan. For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.667% for the Florida-based plan and 4.687% for the NMGC plan. Additionally, TECO Energy made contributions of $4.7 million and $14.9 million to its pension plan for the three months ended Mar. 31, 2016 and 2015, respectively.

For the three months ended Mar. 31, 2016 and 2015, TECO Energy and its subsidiaries reclassified $0.8 million of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended Mar. 31, 2016 and 2015, the regulated companies reclassified $2.2 million of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense.

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6. Short-Term Debt

At Mar. 31, 2016 and Dec. 31, 2015, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts    receivable facility (3)		150.0		0.0		0.0		150.0		61.0		0.0
TECO Energy/TECO Finance:
5-year facility (2)(4)		300.0		113.0		0.0		300.0		163.0		0.0
1-year term facility (4)(5)		400.0		400.0		0.0		0.0		0.0		0.0
New Mexico Gas Company:
5-year facility (2)		125.0		0.0		1.7		125.0		23.0		1.7
Total	$	1,300.0	$	513.0	$	2.2	$	900.0	$	247.0	$	2.2
(1)            Borrowings outstanding are reported as notes payable.
(2)            This 5-year facility matures Dec. 17, 2018.
(3)            Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.
(4)            TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
(5)            This 1-year facility matures Mar. 14, 2017.

At Mar. 31, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2016 and Dec. 31, 2015 was 1.44% and 1.29%, respectively.  

TECO Energy/TECO Finance Credit Facility

On Mar. 14, 2016, TECO Finance entered into a one-year, $400 million credit agreement. The credit agreement (i) has a maturity date of Mar. 14, 2017; (ii) contains customary representations and warranties, events of default, and financial and other covenants; and (iii) provides for interest to accrue at variable rates based on the London interbank deposit rate plus a margin, or, as an alternative to such interest rate, at an interest rate equal to a margin plus the higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the one-month London interbank deposit rate plus 1.00%.

7. Long-Term Debt

Fair Value of Long-Term Debt

At Mar. 31, 2016, total long-term debt had a carrying amount of $3,573.0 million and an estimated fair market value of $3,879.1 million. At Dec. 31, 2015, total long-term debt had a carrying amount of $3,822.5 million and an estimated fair market value of $4,061.6 million. The company uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments (see Note 13 for information regarding the fair value hierarchy).

Purchase in Lieu of Redemption of Revenue Refunding Bonds

On Mar. 19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds) in a term rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds.  The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from Mar. 19, 2008 to Mar. 15, 2012.  On Mar. 15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016.  On Mar. 15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. TEC is responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.

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As of Mar. 31, 2016, $232.6 million of bonds purchased in lieu of redemption, including the Series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended Mar. 31, 2016 and 2015 related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans:

Other Comprehensive Income
	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income (1)		0.3		(0.1	)		0.2
Gain on cash flow hedges		0.3		(0.1	)		0.2
Amortization of unrecognized benefit costs (2)		0.8		(0.3	)		0.5
Total other comprehensive income	$	1.1	$	(0.4	)	$	0.7
2015
Unrealized gain on cash flow hedges	$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income (1)		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.7		(0.4	)		0.3
Amortization of unrecognized benefit costs (2)		0.9		(0.3	)		0.6
Total other comprehensive income	$	1.6	$	(0.7	)	$	0.9
(1)  Related to interest rate contracts recognized in Interest expense.
(2)  Related to postretirement and postemployment benefits. See Note 5 for additional information.

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2016			Dec. 31, 2015
Unamortized pension loss and prior service credit (1)	$	(33.6	)	$	(34.2	)
Unamortized other benefit gains, prior service costs and    transition obligations (2)		25.5			25.6
Net unrealized losses from cash flow hedges (3)		(3.4	)		(3.6	)
Total accumulated other comprehensive loss	$	(11.5	)	$	(12.2	)
(1)  Net of tax benefit of $21.1 million and $21.5 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(2)  Net of tax expense of $16.0 million and $16.1 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
(3)  Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.

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9. Earnings Per Share

	For the three months ended Mar. 31,
(millions, except per share amounts)	2016			2015
Basic earnings per share
Net income from continuing operations	$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to    common shareholders - Basic	$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0
Income (loss) from discontinued operations available to    common shareholders - Basic	$	0.1		$	(5.8	)
Net income	$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income available to common shareholders - Basic	$	73.7		$	57.8
Average common shares outstanding - Basic		234.0			232.8
Earnings per share from continuing operations available to    common shareholders - Basic	$	0.31		$	0.27
Earnings per share from discontinued operations available to    common shareholders - Basic		0.0		$	(0.02	)
Earnings per share available to common shareholders - Basic	$	0.31		$	0.25
Diluted earnings per share
Net income from continuing operations	$	73.7		$	63.8
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Income before discontinued operations available to    common shareholders - Diluted	$	73.6		$	63.6
Income (loss) from discontinued operations, net	$	0.1		$	(5.8	)
Amount allocated to nonvested participating shareholders		0.0			0.0
Income (loss) from discontinued operations available to    common shareholders - Diluted	$	0.1		$	(5.8	)
Net income	$	73.8		$	58.0
Amount allocated to nonvested participating shareholders		(0.1	)		(0.2	)
Net income available to common shareholders - Diluted	$	73.7		$	57.8
Unadjusted average common shares outstanding - Diluted		234.0			232.8
Assumed conversion of stock options, unvested restricted stock,    unvested RSUs and contingent performance shares, net		1.2			0.7
Average common shares outstanding - Diluted		235.2			233.5
Earnings per share from continuing operations available to    common shareholders - Diluted	$	0.31		$	0.27
Earnings per share from discontinued operations available to    common shareholders - Diluted		0.0		$	(0.02	)
Earnings per share available to common shareholders - Diluted	$	0.31		$	0.25
Anti-dilutive shares		0.2			0.1

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10. Commitments and Contingencies

Legal Contingencies

From time to time, TECO Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in October 2016.

New Mexico Gas Company Legal Proceedings

In February 2011, NMGC experienced gas shortages due to weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).  

In March 2011, a customer purporting to represent a class consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico, purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC, four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico private businesses and enterprises.”

In September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to the company’s financial position as of Mar. 31, 2016.

In addition to the two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary judgment in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgment, which is pending.  

Proceedings in connection with the Pending Merger with Emera

Twelve securities class action lawsuits were filed against the company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction.  Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida.  They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger.  In addition, several of these suits alleged that one or more of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order.  Since the consolidation, two of the complaints have been amended. One of those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose.  The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

The company also received two separate shareholder demand letters from purported shareholders of the company.  Both of these letters demanded that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection devices.  One of the letters also demanded that the company refrain from consummating the transaction with Emera. Both of these demand letters have subsequently been withdrawn.  

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In November 2015, the parties to the lawsuits entered into a Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger.  As a result of the Memorandum of Understanding, the company made additional disclosures related to the proposed Merger in a proxy supplement.  Per the terms of the Memorandum of Understanding, the parties will negotiate a settlement agreement and submit it to the court for approval after the Merger is complete.  There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.

Claim in connection with the Sale of TECO Coal

As discussed in Note 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian. On Mar. 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified asserting breach of certain representations, and fraud and willful misconduct in connection therewith, of the SPA.  

TECO Guatemala Holdings, LLC v. The Republic of Guatemala

On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs that it incurred in pursuing the arbitration.

On Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules.

Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the amount of TGH’s damages.

On Apr. 5, 2016, an ICSID ad hoc Committee issued a decision in favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala’s application for annulment of the award and upheld the original $21.1 million award, plus interest. In addition, the ad hoc Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to pay certain costs relating to the annulment proceedings. Because the Tribunal’s award of costs to TGH in its original arbitration was based on the Tribunal’s assessment that TGH had prevailed on liability and Guatemala had partially prevailed on damages, and the latter finding was annulled by the ad hoc Committee, the Committee also annulled the Tribunal’s award of costs to TGH.  As a result, TGH has the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21.1 million), as well as additional interest on the $21.1 million, and its full costs relating to the original arbitration and the new arbitration proceeding. Results to date do not reflect any benefit of this decision.

PGS Compliance Matter
          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Mar. 31, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

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In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

Guarantees and Letters of Credit

A summary of the face amount or maximum theoretical obligation and the year of expiration under letters of credit and guarantees as of Mar. 31, 2016 is as follows:

(millions)							Maximum
					After (1)		Theoretical		Liabilities Recognized
Guarantees for the Benefit of:	2016		2017-2020		2020		Obligation		at Mar. 31, 2016
TECO Energy
Fuel sales and transportation (2)	$	0.0	$	0.0	$	92.9	$	92.9	$	0.0
Letters of indemnity - coal mining permits (3)		89.4		0.0		0.0		89.4		0.0
	$	89.4	$	0.0	$	92.9	$	182.3	$	0.0
							Maximum
(millions)					After (1)		Theoretical		Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Obligation		at Mar. 31, 2016 (4)
TEC	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
NMGC		0.0		0.0		1.7		1.7		0.0
	$	0.0	$	0.0	$	2.2	$	2.2	$	0.1
(1)     These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2)     The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies. Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Mar. 31, 2016. See Note 12 for additional information.
(3)     These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations.  Payments to the surety companies would be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies. As discussed in Note 15, TECO Coal was sold on Sept. 21, 2015 to Cambrian.  Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of control with the appropriate governmental entities.  Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective. At the date of sale in September 2015, the letters of indemnity guaranteed $93.8 million. The company is working with Cambrian on the process to replace the bonds and expects the process to be completed in 2016. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained.
(4)     The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

Financial Covenants

In order to utilize their respective bank facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive

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covenants in specific agreements and debt instruments. At Mar. 31, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants.

11. Segment Information

TECO Energy is an electric and gas utility holding company with diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. Intercompany transactions are eliminated in the Consolidated Condensed Financial Statements of TECO Energy, but are included in determining reportable segments.  

Three months ended Mar. 31,	Tampa Electric		PGS		NMGC (2)		TECO Coal (1)			Other (2) (3)			Eliminations (3)				TECO Energy
2016
Revenues - external	$	423.4	$	126.8	$	106.6	$	0.0		$	2.7		$	0.0			$	659.5
Sales to affiliates		1.1		4.4		0.0		0.0			0.0			(5.5	)			0.0
Total revenues		424.5		131.2		106.6		0.0			2.7			(5.5	)			659.5
Depreciation and amortization		66.1		14.8		8.4		0.0			0.5			0.0				89.8
Total interest charges		23.8		3.7		3.0		0.0			15.6			(0.2	)			45.9
Internally allocated interest		0.0		0.0		0.0		0.0			0.2			(0.2	)			0.0
Provision (benefit) for income taxes		27.8		8.9		9.7		0.0			(10.7	)		0.0				35.7
Net income (loss) from continuing operations		50.2		13.1		15.2		0.0			(4.8	)		0.0				73.7
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0		0.0			0.1			0.0				0.1
Net income (loss)	$	50.2	$	13.1	$	15.2	$	0.0		$	(4.7	)	$	0.0			$	73.8
2015
Revenues - external	$	449.8	$	121.7	$	119.0	$	0.0		$	2.5		$	0.0			$	693.0
Sales to affiliates		0.8		1.2		0.0		0.0			0.0			(2.0	)			0.0
Total revenues		450.6		122.9		119.0		0.0			2.5			(2.0	)			693.0
Depreciation and amortization		62.9		13.9		8.4		0.0			0.3			0.0				85.5
Total interest charges		23.5		3.5		3.3		0.0			17.9			(0.3	)			47.9
Internally allocated interest		0.0		0.0		0.0		0.0			0.3			(0.3	)			0.0
Provision (benefit) for income taxes		27.4		9.2		9.0		0.0			(5.7	)		0.0				39.9
Net income (loss) from continuing operations		48.2		14.6		13.9		0.0			(12.9	)		0.0				63.8
Income (loss) from discontinued operations, net (1)		0.0		0.0		0.0		(6.0	)		0.2			0.0				(5.8	)
Net income (loss)	$	48.2	$	14.6	$	13.9	$	(6.0	)	$	(12.7	)	$	0.0			$	58.0
At Mar. 31, 2016
Total assets	$	6,988.2	$	1,147.0	$	1,210.9	$	0.0		$	1,982.1		$	(2,347.1	)	(4)	$	8,981.1
At Dec. 31, 2015
Total assets (3)	$	7,003.8	$	1,136.1	$	1,229.7	$	0.0		$	1,945.1		$	(2,381.2	)	(4)		8,933.5
(1)     All periods have been adjusted to reflect the results from operations to discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15.
(2)    NMGI is included in the Other segment.
(3)    Certain prior year amounts have been reclassified to conform to current year presentation.
(4)    Amounts primarily relate to intercompany advances and consolidated tax eliminations.

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12. Accounting for Derivative Instruments and Hedging Activities

From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes:

· To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric, PGS and NMGC;

· To optimize the utilization of NMGC’s physical natural gas storage capacity, and

· To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates.

TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The regulated utilities’ primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.

The company applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 13). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

The company applies the accounting standards for regulated operations to financial instruments used to hedge the purchase and sale of natural gas for the benefit of its regulated companies’ ratepayers. These standards, in accordance with the FPSC and NMPRC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

The company’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Mar. 31, 2016, all of the company’s physical contracts qualify for the NPNS exception with the exception of a minor amount of forward purchases and sales entered into by NMGC to optimize its gas storage capacity.

The derivatives that are designated as cash flow hedges at Mar. 31, 2016 and Dec. 31, 2015 are reflected on the company’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. Derivative assets totaled $0.0 million and $0.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively, and are included in “Prepayments and other current assets” on the Condensed Consolidated Balance Sheets. Derivative liabilities totaled $23.1 million and $26.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Mar. 31, 2016 and Dec. 31, 2015 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Mar. 31, 2016, net pretax losses of $22.3 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Mar. 31, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 8.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Mar. 31, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the

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threemonths ended Mar. 31, 2016 and 2015 is presented in Note 8. These gains and losses were the result of interest rate contracts for TEC. The location of the reclassification to income was reflected in “Interest expense” for TEC.

The maximum length of time over which the company is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

Derivative Volumes	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		25.1
2017		0.0		9.9
2018		0.0		0.7
Total		0.0		35.7

The company is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Mar. 31, 2016, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that are not rated.

The company has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

The company has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as the company uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TECO Energy derivative instruments contain provisions that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings, including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The company has no other contingent risk features associated with any derivative instruments.

13. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

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(A)  Market approach:  Prices and other relevant information generated by market transactions involving

identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).  

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

The following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2016 and Dec. 31, 2015. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.     

Recurring Fair Value Measures
	As of Mar. 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas derivatives	$	0.0	$	23.1	$	0.0	$	23.1
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Assets
Natural gas derivatives	$	0.0	$	0.2	$	0.0	$	0.2
Liabilities
Natural gas derivatives	$	0.0	$	26.2	$	0.0	$	26.2

The natural gas derivatives are OTC swap, forward and option instruments. Fair values of swaps and forwards are estimated utilizing the market approach. The price of swaps and forwards are calculated using observable NYMEX quoted closing prices of exchange-traded futures. Fair values of options are estimated utilizing the income approach. The price of options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to NYMEX. The resulting prices are applied to the notional quantities of active swap, forward and option positions to determine the fair value (see Note 12). 

The company considered the impact of nonperformance risk in determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the company transacts have experienced dislocation. At Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

14. Variable Interest Entities

The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $12.6 million and $5.4 million under these PPAs for the three months ended Mar. 31, 2016 and 2015, respectively.

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The company does not provide any material financial or other support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. In the normal course of business, the company’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

15. Discontinued Operations and Asset Impairments

TECO Coal

On Sept. 21, 2015, TECO Energy’s subsidiary, TECO Diversified, entered into an SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian.  The SPA did not provide for an up-front purchase payment, but provides for future contingent consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the transaction.  Letters of indemnity related to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees in Note 10). The SPA contained customary representations, warranties and covenants (see Note 10 for description of a claim related to the SPA). The income shown for the first quarter of 2016 in the table below reflects a refund of prepaid costs.

Since the closing of the sale, TECO Energy does not have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.

TECO Guatemala

In 2012, TECO Guatemala completed the sale of its interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim filed against the Republic of Guatemala (see Note 10). The charges shown in the table below are legal costs associated with that claim.  

Combined Components of Discontinued Operations

The following table provides selected components of discontinued operations related to the sales of TECO Coal and TECO Guatemala:

Components of income from discontinued operations	Three months ended
	Mar. 31,
(millions)	2016		2015
Revenues—TECO Coal	$	0.0	$	72.7
Loss from operations—TECO Coal		0.0		(9.5	)
Loss from operations—TECO Guatemala		0.0		(0.1	)
Income (loss) from discontinued operations—TECO Coal		0.2		(9.5	)
Loss from discontinued operations—TECO Guatemala		0.0		(0.1	)
Income (loss) from discontinued operations		0.2		(9.6	)
Provision (benefit) for income taxes		0.1		(3.8	)
Income (loss) from discontinued operations, net	$	0.1	$	(5.8	)

16. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt.

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The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC and the Committee on Foreign Investment in the United States, was obtained on Jan. 20, 2016 and Mar. 23, 2016, respectively), (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the transaction.  In the stipulation, the parties state that they believe the settlement is in the public interest and have recommended approval to the NMPRC. Amongst other elements, the stipulation includes Emera’s agreement to maintain the commitments made by TECO Energy in its 2014 case relating to its acquisition of NMGC, invest in the expansion of the natural gas system to underserved communities and the Mexican border, and provide resources to support certain economic growth projects and programs.  The stipulation is subject to review and approval by the NMPRC. The NMPRC hearing to consider the acquisition is scheduled to begin in May 2016.

The Merger Agreement contains customary representations, warranties and covenants of TECO Energy, Emera and Merger Sub. The Merger Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the execution of the Merger Agreement and the closing of the Merger and (ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera, among others, that Emera will use its reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals.

In addition, the Merger Agreement requires Emera (i) to maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida, (iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than, and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.

Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals) or (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final. If the Merger Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

During the three months ended Mar. 31, 2016, TECO Energy incurred approximately $0.1 million pretax of incremental transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets

Unaudited

Assets	Mar. 31,			Dec. 31,
(millions)	2016			2015
Property, plant and equipment
Utility plant in service
Electric	$	7,328.3		$	7,270.3
Gas		1,419.3			1,398.6
Construction work in progress		797.0			771.1
Utility plant in service, at original costs		9,544.6			9,440.0
Accumulated depreciation		(2,720.3	)		(2,676.8	)
Utility plant in service, net		6,824.3			6,763.2
Other property		9.9			9.7
Total property, plant and equipment, net		6,834.2			6,772.9
Current assets
Cash and cash equivalents		28.2			9.1
Receivables, less allowance for uncollectibles of $1.6 and $1.5 at Mar. 31, 2016    and Dec. 31, 2015, respectively		205.5			230.2
Inventories, at average cost
Fuel		115.4			105.6
Materials and supplies		73.6			73.1
Regulatory assets		39.9			44.3
Taxes receivable from affiliate		0.0			61.3
Prepayments and other current assets		17.0			21.5
Total current assets		479.6			545.1
Deferred debits
Regulatory assets		373.1			373.8
Other		17.9			16.8
Total deferred debits		391.0			390.6
Total assets	$	7,704.8		$	7,708.6

The accompanying notes are an integral part of the consolidated condensed financial statements.

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Balance Sheets - continued

Unaudited

Liabilities and Capitalization	Mar. 31,			Dec. 31,
(millions)	2016			2015
Capitalization
Common stock	$	2,330.4		$	2,305.4
Accumulated other comprehensive loss		(3.4	)		(3.6	)
Retained earnings		314.4			313.7
Total capital		2,641.4			2,615.5
Long-term debt		2,162.0			2,161.7
Total capitalization		4,803.4			4,777.2
Current liabilities
Long-term debt due within one year		83.3			83.3
Notes payable		0.0			61.0
Accounts payable		174.6			221.6
Customer deposits		170.9			176.3
Regulatory liabilities		104.5			83.2
Derivative liabilities		22.2			24.1
Interest accrued		41.2			16.9
Taxes accrued		33.6			13.2
Other		10.1			10.2
Total current liabilities		640.4			689.8
Deferred credits
Deferred income taxes		1,342.0			1,308.8
Investment tax credits		10.4			10.5
Derivative liabilities		0.8			2.1
Regulatory liabilities		595.5			603.5
Deferred credits and other liabilities		312.3			316.7
Total deferred credits		2,261.0			2,241.6
Commitments and Contingencies (see Note 8)
Total liabilities and capitalization	$	7,704.8		$	7,708.6

The accompanying notes are an integral part of the consolidated condensed financial statements.

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Income and Comprehensive Income

Unaudited

	Three months ended Mar. 31,
(millions)	2016			2015
Revenues
Electric	$	424.2		$	450.4
Gas		126.8			121.7
Total revenues		551.0			572.1
Expenses
Regulated operations and maintenance
Fuel		115.1			144.1
Purchased power		14.4			17.1
Cost of natural gas sold		50.3			43.3
Other		121.2			121.8
Depreciation and amortization		80.9			76.8
Taxes, other than income		48.5			47.6
Total expenses		430.4			450.7
Income from operations		120.6			121.4
Other income
Allowance for other funds used during construction		5.6			3.8
Other income, net		1.3			1.2
Total other income		6.9			5.0
Interest charges
Interest on long-term debt		29.0			27.7
Interest expense		1.2			1.1
Allowance for borrowed funds used during construction		(2.7	)		(1.8	)
Total interest charges		27.5			27.0
Income before provision for income taxes		100.0			99.4
Provision for income taxes		36.7			36.6
Net income		63.3			62.8
Other comprehensive income, net of tax
Gain on cash flow hedges		0.2			0.3
Total other comprehensive income, net of tax		0.2			0.3
Comprehensive income	$	63.5		$	63.1

The accompanying notes are an integral part of the consolidated condensed financial statements.

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TAMPA ELECTRIC COMPANY

Consolidated Condensed Statements of Cash Flows

Unaudited

	Three months ended Mar. 31,
(millions)	2016			2015
Cash flows from operating activities
Net income	$	63.3		$	62.8
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		80.9			76.8
Deferred income taxes and investment tax credits		30.4			21.2
Allowance for funds used during construction		(5.6	)		(3.8	)
Deferred recovery clauses		27.0			(4.7	)
Receivables, less allowance for uncollectibles		24.7			13.5
Inventories		(10.3	)		(21.1	)
Prepayments		4.6			(5.0	)
Taxes accrued		81.7			72.7
Interest accrued		24.3			22.9
Accounts payable		(41.2	)		(28.3	)
Other		(11.6	)		(6.9	)
Cash flows from operating activities		268.2			200.1
Cash flows from investing activities
Capital expenditures		(150.5	)		(148.8	)
Cash flows used in investing activities		(150.5	)		(148.8	)
Cash flows from financing activities
Common stock		25.0			20.0
Net decrease in short-term debt		(61.0	)		(11.0	)
Dividends		(62.6	)		(55.7	)
Cash flows used in financing activities		(98.6	)		(46.7	)
Net increase in cash and cash equivalents		19.1			4.6
Cash and cash equivalents at beginning of period		9.1			10.4
Cash and cash equivalents at end of period	$	28.2		$	15.0
Supplemental disclosure of non-cash activities
Change in accrued capital expenditures	$	(4.8	)	$	11.4

The accompanying notes are an integral part of the consolidated condensed financial statements.

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TAMPA ELECTRIC COMPANY

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

UNAUDITED

1. Summary of Significant Accounting Policies

See TEC’s 2015 Annual Report on Form 10-K for a complete discussion of accounting policies. The significant accounting policies for TEC include:

Principles of Consolidation and Basis of Presentation

TEC is a wholly owned subsidiary of TECO Energy. For the purposes of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary beneficiary. For the periods presented, no VIEs have been consolidated (see Note 13).

Intercompany balances and intercompany transactions have been eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of the results that can be expected for the entire fiscal year ending Dec. 31, 2016.

The use of estimates is inherent in the preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 14 for further information.

Revenues

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $56.8 million and $53.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets.

Accounting for Franchise Fees and Gross Receipts

Tampa Electric and PGS are allowed to recover certain costs from customers on a dollar-per-dollar basis through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Condensed Statements of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million for the three months ended Mar. 31, 2016 and 2015, respectively.

2. New Accounting Pronouncements

Change in Accounting Policy

Presentation of Debt Issuance Costs

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset, regardless of whether a balance is outstanding. This guidance became effective for TEC beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, TEC classified $17.9 million and $18.1 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s Consolidated Condensed Balance Sheet (previously classified as an asset in the “Unamortized debt expense” line item). The guidance did not affect TEC’s results of operations or cash flows.

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Future Accounting Pronouncements

Revenue from Contracts with Customers

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers. This guidance will be effective for TEC beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. TEC expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued guidance related to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial instruments. TEC does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for TEC beginning in 2018.

Leases

In February 2016, the FASB issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. Recognition of expenses for both operating and finance leases will be similar to existing guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. This guidance will be effective for TEC beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. TEC is currently evaluating the impacts of the adoption of the guidance on its financial statements.

Derivative Contract Novations

In March 2016, the FASB issued guidance clarifying that a change in the counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The guidance is effective for TEC beginning in 2017, with early adoption permitted, and may be applied on a prospective or modified retrospective basis. The guidance will not affect TEC’s current financial statements. However, TEC will assess the impact of this guidance on future derivative contract novations, if any.

3. Regulatory

Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital.

Regulatory Assets and Liabilities

Tampa Electric and PGS apply the accounting standards for regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them when cost recovery is ordered over a period longer than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process.

Details of the regulatory assets and liabilities as of Mar. 31, 2016 and Dec. 31, 2015 are presented in the following table:

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Regulatory Assets and Liabilities
(millions)	Mar. 31, 2016		Dec. 31, 2015
Regulatory assets:
Regulatory tax asset (1)	$	77.0	$	74.6
Cost-recovery clauses - deferred balances (2)		0.0		5.2
Cost-recovery clauses - offsets to derivative liabilities (2)		25.9		26.2
Environmental remediation (3)		54.4		54.0
Postretirement benefits (4)		236.4		238.3
Deferred bond refinancing costs (5)		6.2		6.5
Competitive rate adjustment (2)		2.5		2.6
Other		10.6		10.7
Total regulatory assets		413.0		418.1
Less: Current portion		39.9		44.3
Long-term regulatory assets	$	373.1	$	373.8
Regulatory liabilities:
Regulatory tax liability	$	5.6	$	5.7
Cost-recovery clauses (2)		76.1		54.2
Transmission and delivery storm reserve		56.1		56.1
Accumulated reserve - cost of removal (6)		561.7		570.0
Other		0.5		0.7
Total regulatory liabilities		700.0		686.7
Less: Current portion		104.5		83.2
Long-term regulatory liabilities	$	595.5	$	603.5

(1) The regulatory tax asset is primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered over the expected life of the related assets.

(2) These assets and liabilities are related to FPSC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following the settlement of the derivative position.

(3) This asset is related to costs associated with environmental remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the expenditures related to remediation.

(4) This asset is related to the deferred costs of postretirement benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants.

(5) This asset represents the past costs associated with refinancing debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.

(6) This item represents the non-ARO cost of removal in the accumulated reserve for depreciation.

4. Income Taxes

TEC is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. TEC’s effective tax rates for the three months ended Mar. 31, 2016 and 2015 differ from the statutory rate principally due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

The IRS concluded its examination of TECO Energy’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized. TEC does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016.

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5. Employee Postretirement Benefits

TEC is a participant in the comprehensive retirement plans of TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended Mar. 31, 2016 and 2015, respectively, was $2.9 million and $2.6 million for pension benefits, and $1.5 million and $1.4 million for other postretirement benefits.

For the fiscal 2016 plan year, TECO Energy assumed a long-term EROA of 7.00% and a discount rate of 4.685%.  For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.667%. Additionally, TECO Energy made contributions of $4.7 million and $14.9 million to its pension plan in the three months ended Mar. 31, 2016 and 2015, respectively. TEC’s portion of the contributions was $3.9 million and $11.0 million, respectively.

Included in the benefit expenses discussed above, for the three months ended Mar. 31, 2016 and 2015, TEC reclassified $2.0 million and $1.9 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income.

6. Short-Term Debt

At Mar. 31, 2016 and Dec. 31, 2015, the following credit facilities and related borrowings existed:

Credit Facilities
	Mar. 31, 2016						Dec. 31, 2015
					Letters						Letters
	Credit		Borrowings		of Credit		Credit		Borrowings		of Credit
(millions)	Facilities		Outstanding (1)		Outstanding		Facilities		Outstanding (1)		Outstanding
Tampa Electric Company:
5-year facility (2)	$	325.0	$	0.0	$	0.5	$	325.0	$	0.0	$	0.5
3-year accounts    receivable facility (3)		150.0		0.0		0.0		150.0		61.0		0.0
Total	$	475.0	$	0.0	$	0.5	$	475.0	$	61.0	$	0.5

(1) Borrowings outstanding are reported as notes payable.

(2) This 5-year facility matures Dec. 17, 2018.

(3) Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year facility matures Mar. 23, 2018.

At Mar. 31, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2016 and Dec. 31, 2015 was 1.0% and 0.89%, respectively.

7. Long-Term Debt

Fair Value of Long-Term Debt

At Mar. 31, 2016, TEC’s total long-term debt had a carrying amount of $2,245.3 million and an estimated fair market value of $2,483.1 million. At Dec. 31, 2015, TEC’s total long-term debt had a carrying amount of $2,245.0 million and an estimated fair market value of $2,433.3 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments (see Note 11 for information regarding the fair value hierarchy).

Purchase in Lieu of Redemption of Revenue Refunding Bonds

On Mar.  19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds) in a term-rate mode pursuant to the terms of the Loan and Trust agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from Mar. 19, 2008 to Mar. 15, 2012. On Mar.  15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016. On Mar.  15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar.  15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. TEC is

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responsible for payment of the interest and principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation.

As of Mar. 31, 2016, $232.6 million of bonds purchased in lieu of redemption, including the series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

8. Commitments and Contingencies

Legal Contingencies

From time to time, TEC and its subsidiaries are involved in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows.

Peoples Gas Legal Proceedings

In November 2010, heavy equipment operated at a road construction site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014, the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in October 2016.

PGS Compliance Matter

          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and Peoples Gas divisions, is a PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Mar. 31, 2016, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates.

The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.

In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs.

Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from

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the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.

Letters of Credit

A summary of the face amount or maximum theoretical obligation under TEC’s letters of credit as of Mar. 31, 2016 is as follows:

Letters of Credit - Tampa Electric Company
(millions)					After (1)				Liabilities Recognized
Letters of Credit for the Benefit of:	2016		2017-2020		2020		Total		at Mar. 31, 2016
TEC (2)	$	0.0	$	0.0	$	0.5	$	0.5	$	0.1
(1)These letters of credit renew annually and are shown on the basis that they will continue to renew beyond 2020.
(2)     The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Mar. 31, 2016. The obligations under these letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.

Financial Covenants

In order to utilize its bank credit facilities, TEC must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2016, TEC was in compliance with all applicable financial covenants.

9. Segment Information

(millions)	Tampa							Tampa Electric
Three months ended Mar. 31,	Electric		PGS		Eliminations			Company
2016
Revenues - external	$	424.2	$	126.8	$	0.0		$	551.0
Intracompany sales		0.3		4.4		(4.7	)		0.0
Total revenues		424.5		131.2		(4.7	)		551.0
Depreciation and amortization		66.1		14.8		0.0			80.9
Total interest charges		23.8		3.7		0.0			27.5
Provision for income taxes		27.8		8.9		0.0			36.7
Net income	$	50.2	$	13.1	$	0.0		$	63.3
2015
Revenues - external	$	450.4	$	121.7	$	0.0		$	572.1
Intracompany sales		0.2		1.2		(1.4	)		0.0
Total revenues		450.6		122.9		(1.4	)		572.1
Depreciation and amortization		62.9		13.9		0.0			76.8
Total interest charges		23.5		3.5		0.0			27.0
Provision for income taxes		27.4		9.2		0.0			36.6
Net income	$	48.2	$	14.6	$	0.0		$	62.8
Total assets at Mar. 31, 2016	$	6,600.4	$	1,109.6	$	(5.2	)	$	7,704.8
Total assets at Dec. 31, 2015 (1)		6,620.2		1,097.7		(9.3	)		7,708.6

(1) Certain prior year amounts have been reclassified to conform to current year presentation.

10. Accounting for Derivative Instruments and Hedging Activities

From time to time, TEC enters into futures, forwards, swaps and option contracts for the following purposes:

· To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations, and

· To limit the exposure to interest rate fluctuations on debt securities.

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TEC uses derivatives only to reduce normal operating and market risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.

The risk management policies adopted by TEC provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies.

TEC applies the accounting standards for derivative instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 11). The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction.

TEC applies the accounting standards for regulated operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3).

TEC’s physical contracts qualify for the NPNS exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Mar. 31, 2016, all of TEC’s physical contracts qualify for the NPNS exception.

The derivatives that are designated as cash flow hedges at Mar. 31, 2016 and Dec. 31, 2015 are reflected on TEC’s Consolidated Condensed Balance Sheets and classified accordingly as current and long-term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were no derivative assets as of Mar. 31, 2016 and Dec. 31, 2015. Derivative liabilities totaled $23.0 million and $26.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties.

All of the derivative assets and liabilities at Mar. 31, 2016 and Dec. 31, 2015 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Condensed Balance Sheets as current and long-term regulatory assets and liabilities. Based on the fair value of the instruments at Mar. 31, 2016, net pretax losses of $22.2 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next twelve months.

The Mar. 31, 2016 and Dec. 31, 2015 balance in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12.

For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the three months ended Mar. 31, 2016 and 2015, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the three months ended Mar. 31, 2016 and 2015 is presented in Note 12. Gains and losses were the result of interest rate contracts and the reclassification to income was reflected in “Interest expense”.

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The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

	Natural Gas Contracts
(millions)	(MMBTUs)
Year	Physical		Financial
2016		0.0		25.1
2017		0.0		9.9
2018		0.0		0.7
Total		0.0		35.7

TEC is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of Mar. 31, 2016, substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated.

TEC has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. TEC generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights relating to creditworthiness, collateral and termination.

TEC has implemented procedures to monitor the creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential impact of nonperformance risk to derivative positions.

Certain TEC derivative instruments contain provisions that require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.

11. Fair Value Measurements

Items Measured at Fair Value on a Recurring Basis

Accounting guidance governing fair value measurements and disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1:  Observable inputs, such as quoted prices in active markets;

Level 2:  Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and

Level 3: Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques noted under accounting guidance:

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(A)  Market approach:  Prices and other relevant information generated by market transactions involving

identical or comparable assets or liabilities;

(B)  Cost approach:  Amount that would be required to replace the service capacity of an asset (replacement

cost); and

(C)  Income approach:  Techniques to convert future amounts to a single present amount based upon market

expectations (including present value techniques, option-pricing and excess earnings models).

The fair value of financial instruments is determined by using various market data and other valuation techniques.  

The following tables set forth by level within the fair value hierarchy, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2016 and Dec. 31, 2015. As required by accounting standards for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  

Recurring Derivative Fair Value Measures
	As of Mar. 31, 2016
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	23.0	$	0.0	$	23.0
	As of Dec. 31, 2015
(millions)	Level 1		Level 2		Level 3		Total
Liabilities
Natural gas swaps	$	0.0	$	26.2	$	0.0	$	26.2

Natural gas swaps are OTC swap instruments. The fair value of the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the reported fair value (see Note 10).

TEC considered the impact of nonperformance risk in determining the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have experienced dislocation. At Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

12. Other Comprehensive Income

Other Comprehensive Income	Three months ended Mar. 31,
(millions)	Gross		Tax			Net
2016
Unrealized gain on cash flow hedges	$	0.0	$	0.0		$	0.0
Reclassification from AOCI to net income		0.3		(0.1	)		0.2
Gain on cash flow hedges		0.3		(0.1	)		0.2
Total other comprehensive income	$	0.3	$	(0.1	)	$	0.2
2015
Unrealized gain on cash flow hedges	$	0.3	$	(0.2	)	$	0.1
Reclassification from AOCI to net income		0.4		(0.2	)		0.2
Gain on cash flow hedges		0.7		(0.4	)		0.3
Total other comprehensive income	$	0.7	$	(0.4	)	$	0.3

Accumulated Other Comprehensive Loss
(millions)	Mar. 31, 2016			Dec. 31, 2015
Net unrealized losses from cash flow hedges (1)	$	(3.4	)	$	(3.6	)
Total accumulated other comprehensive loss	$	(3.4	)	$	(3.6	)

38

(1) Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.  

13. Variable Interest Entities

The determination of a VIE’s primary beneficiary is the enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

Tampa Electric has entered into multiple PPAs with wholesale energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 250 MW of available capacity, are with similar entities and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include: operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate any of these entities. Tampa Electric purchased $12.6 million and $5.4 million under these PPAs for the three months ended Mar. 31, 2016 and 2015, respectively.

TEC does not provide any material financial or other support to any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. In the normal course of business, TEC’s involvement with these VIEs does not affect its Consolidated Condensed Balance Sheets, Statements of Income or Cash Flows.

14. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera.

Upon the terms and subject to the conditions set forth in the Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation.

Pursuant to the Merger Agreement, upon the closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt (of which TEC’s portion of debt was $2.3 billion).

The closing of the Merger is subject to certain conditions, including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015), (ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign Investment in the United States (which, with respect to the FERC and the Committee on Foreign Investment in the United States, was obtained on Jan. 20, 2016 and Mar. 23, 2016, respectively), (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement.

On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the transaction. The stipulation is subject to review and approval by the NMPRC. The NMPRC hearing to consider the acquisition is scheduled to begin in May 2016.

TECO Energy is also subject to a “no shop” restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties.

Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals) or (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final. If the Merger Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

39

EX-4.10

Exhibit 4.10

Osler, Hoskin & Harcourt LLP Box 50, 1 First Canadian Place Toronto, Ontario, Canada M5X 1B8 416.362.2111 MAIN 416.862.6666 FACSIMILE

Toronto   Montréal   Ottawa   Calgary   New York   June 8, 2016   TO:  Nova Scotia Securities Commission, as Principal Regulator   Dear Sirs/Mesdames:   Emera Incorporated (the “Company”)   We refer you to the final short form base shelf prospectus of the Company dated June 8, 2016 (the “Prospectus”). In the Prospectus, reference is made to this firm under the headings “Documents Filed as Part of the Registration Statement”, “Legal Matters”, “Interests of Experts” and “Enforcement of Civil Liabilities” and to the opinion of this firm under the heading “Certain Canadian Federal Income Tax Considerations”. We hereby consent to being named in the Prospectus and to the use of our opinion.   We also confirm that we have read the Prospectus and that we have no reason to believe that there are any misrepresentations (as defined in Canadian securities legislation) in the information contained in it that are: (i) derived from our opinions referred to above, or (ii) within our knowledge as a result of the services we have performed in connection with our opinion referred to above.   This is a consent contemplated by Section 4.2(a)(vii) of National Instrument 44-101, and to the extent permitted by law we disclaim any liability beyond the statutory liability provisions of Canadian securities legislation applicable to the Prospectus.   Yours very truly,   “Osler, Hoskin and Harcourt LLP”  

EX-5.1

Exhibit 5.1

CONSENT OF INDEPENDENT REGISTERED CERTIFIED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in this amendment no. 1 to the Registration Statement on Form F-10 of Emera Inc. of our report dated February 26, 2016 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in TECO Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2015. We also consent to the reference to us as experts under the heading “Independent Registered Public Accounting Firm” in such Registration Statement.

/s/ PricewaterhouseCoopers LLP

Tampa, FL

June 8, 2016

EX-5.2

Exhibit 5.2

Consent of Independent Registered Public Accounting Firm

We consent to the reference to our firm under the caption “Independent Registered Accounting Firms” and to the incorporation by reference of our report dated February 12, 2016 in the prospectus included in the amendment no. 1 to the Registration Statement on Form F-10 of Emera Incorporated for the registration of unsecured, subordinated notes and first preferred shares.

Halifax, Canada	/s/ Ernst & Young LLP
June 8, 2016	Chartered Accountants

EX-5.3

Exhibit 5.3

Osler, Hoskin & Harcourt LLP Box 50, 1 First Canadian Place Toronto, Ontario, Canada M5X 1B8 416.362.2111 MAIN 416.862.6666 FACSIMILE

Toronto   Montréal   Ottawa   Calgary   New York   June 8, 2016   Emera Incorporated 5151 Terminal Road Halifax, Nova Scotia B3J 1A1   Ladies and Gentleman:   We refer to the prospectus included as part of the amendment no. 1 to the registration statement on Form F-10 of Emera Incorporated (the “Prospectus”) filed with the U.S. Securities and Exchange Commission on the date hereof.   We hereby consent to the references to our name under the captions “Legal Matters”, “Documents Filed as Part of the Registration Statement”, “Interests of Experts” and “Enforcement of Civil Liabilities” in the Prospectus and to the use of our opinion under the caption “Certain Canadian Federal Income Tax Considerations”.   Very truly yours,   /s/ OSLER, HOSKIN & HARCOURT LLP   Osler, Hoskin & Harcourt LLP  

EX-5.4

Exhibit 5.4

		New York Menlo Park Washington DC London Paris	Madrid Tokyo Beijing Hong Kong São Paulo
Davis Polk & Wardwell LLP 450 Lexington Avenue New York, NY 10017	212 450 4000 tel 212 701 5800 fax

June 8, 2016

Emera Incorporated

5151 Terminal Road

Halifax, Nova Scotia B3J 1A1

Ladies and Gentlemen:

We refer to the prospectus included as part of the amendment no. 1 to the registration statement on Form F-10 of Emera Incorporated (the “Prospectus”) filed with the U.S. Securities and Exchange Commission on the date hereof.

We hereby consent to the references to our name under the captions “Legal Matters” and “Documents Filed as Part of the Registration Statement” in the Prospectus. In giving this consent, we do not admit that we are in the category of persons whose consent is required under Section 7 of the Securities Act.

Very truly yours,

/s/ DAVIS POLK & WARDWELL LLP

    Davis Polk & Wardwell LLP

EX-7.1

Exhibit 7.1

EMERA INCORPORATED

as Issuer

- and -

AMERICAN STOCK TRANSFER & TRUST COMPANY, LLC

as the U.S. trustee, the U.S. registrar and the U.S. paying agent

- and -

CST TRUST COMPANY

as the Canadian trustee and the Canadian registrar

TRUST INDENTURE

PROVIDING FOR THE ISSUE OF NOTES

Dated as of ●, 2016

TABLE OF CONTENTS

		Page
ARTICLE 1 INTERPRETATION			2
1.1	Definitions		2
1.2	Meaning of “outstanding” for Certain Purposes		5
1.3	Interpretation Not Affected By Headings, etc.		5
1.4	Statute References		6
1.5	Monetary References		6
1.6	Day Not a Business Day		6
1.7	Invalidity of Provisions		6
1.8	Governing Law		6
1.9	Notes and Supplemental Indentures		6
1.10	Additional Parties		6
ARTICLE 2 THE NOTES			7
2.1	Limitation on Issue and Designation		7
2.2	Issuance in Series		7
2.3	Differences in Notes of any Series		7
2.4	Issuance of Notes as Part of Series Previously Issued		7
2.5	Issuance of Notes		7
2.6	Execution of Notes		8
2.7	Certification		8
2.8	Concerning Interest		8
2.9	Rank of Notes		9
2.10	Registration of Notes		9
2.11	Book-Entry System		10
2.12	Payment of Principal and Interest in Respect of Notes		12
2.13	Ownership of Notes		13
2.14	Exchange of Notes		13
2.15	Replacement of Notes		14
2.16	Interim Notes		14
2.17	Option of Holder as to Place of Payment		15
2.18	Payment Agreements for Notes		15
2.19	ERISA Matters		15
ARTICLE 3 REDEMPTION AND PURCHASE FOR CANCELLATION OF NOTES			17
3.1	Redemption of Notes		17
3.2	Partial Redemption of Notes		17
3.3	Notice of Redemption		18
3.4	Notes Due on Redemption Dates		18
3.5	Deposit of Redemption Moneys		18
3.6	Failure to Surrender Notes Called for Redemption		18
3.7	Surrender of Notes for Cancellation		19
3.8	Purchase of Notes for Cancellation		19
3.9	Cancellation of Notes		19

- i -

TABLE OF CONTENTS

(continued)

		Page
ARTICLE 4 SUBORDINATION OF NOTES			19
4.1	Notes Subordinated to Senior Indebtedness		19
4.2	Disputes with Holders of Certain Senior Indebtedness		20
4.3	Subrogation		21
4.4	Obligation of Issuer Unconditional		21
4.5	Payments on Notes Permitted		22
4.6	Effectuation of Subordination by Trustee		22
4.7	Knowledge of Trustee		22
4.8	Trustee May Hold Senior Indebtedness		22
4.9	Rights of Holders of Senior Indebtedness Not Impaired		22
4.10	Article Applicable to Paying Agents		23
4.11	Trustee; Compensation Not Prejudiced		23
ARTICLE 5 COVENANTS OF THE ISSUER			23
5.1	General Covenants		23
5.2	Not to Extend Time for Payment of Interest or Principal		23
5.3	To Provide Annual Certificate of Compliance		24
5.4	To Pay Trustee’s Remuneration		24
5.5	Trustee may Perform Covenants		24
ARTICLE 6 DEFAULT AND ENFORCEMENT			25
6.1	Events of Default		25
6.2	Notice of Events of Default		25
6.3	Acceleration on Default		25
6.4	Waiver of Default		26
6.5	Enforcement by the Trustee		26
6.6	Holders May Not Sue		27
6.7	Application of Moneys		27
6.8	Distribution of Moneys		28
6.9	Persons Dealing with Trustee		29
6.10	Trustee Appointed Attorney		29
6.11	Remedies Cumulative		29
6.12	Immunity of Shareholders, Directors, and Others		29
6.13	Judgment Against the Issuer		29
6.14	Unconditional Right of Holders to Principal, Premium or Make-Whole Amount, if any, Interest and Additional Amounts		29
ARTICLE 7 SATISFACTION AND DISCHARGE			30
7.1	Cancellation and Destruction		30
7.2	Non-Presentation of Notes		30
7.3	Repayment of Unclaimed Moneys		30
7.4	Discharge		31
ARTICLE 8 CONSOLIDATION, AMALGAMATION, MERGER, CONVEYANCE, TRANSFER OR LEASE			31
8.1	Issuer May Consolidate, Etc., Only on Certain Terms		31
8.2	Successor Substituted		31

- ii -

TABLE OF CONTENTS

(continued)

		Page
ARTICLE 9 MEETINGS OF HOLDERS			32
9.1	Right to Convene Meetings		32
9.2	Serial Meetings		32
9.3	Notice of Meetings		32
9.4	Chairperson		32
9.5	Quorum		32
9.6	Power to Adjourn		33
9.7	Show of Hands		33
9.8	Poll		33
9.9	Voting		33
9.10	Regulations		34
9.11	Issuer and Trustee May Be Represented		34
9.12	Powers Exercisable by Extraordinary Resolution		34
9.13	Meaning of “Extraordinary Resolution”		36
9.14	Powers Cumulative		37
9.15	Minutes		37
9.16	Signed Instruments		37
9.17	Binding Effect of Resolutions		38
9.18	Evidence of Rights of Holders		38
ARTICLE 10 NOTICES			38
10.1	Notice to the Issuer		38
10.2	Notice to Holders		38
10.3	Notice to the Trustee		39
10.4	Notice to a Clearing Agency		39
10.5	Mail Service Interruption		39
ARTICLE 11 CONCERNING THE TRUSTEE			40
11.1	Trust Indenture Legislation		40
11.2	No Conflict of Interest		40
11.3	Qualifications of Trustee		40
11.4	Rights and Duties of Trustee		41
11.5	Evidence, Experts and Advisers		42
11.6	Trustee May Deal in Notes		42
11.7	Trustee Not Required to Give Security		43
11.8	Protection of Trustee		43
11.9	Investment of Trust Moneys		44
11.10	Action by Trustee to Protect Rights		45
11.11	Replacement of Trustee		45
11.12	Acceptance of Trusts		46
11.13	Appointment of Authenticating Agent		46
11.14	Joint Trustees		47
11.15	Compliance with Privacy Legislation		48
11.16	Compliance with Anti-Money Laundering Legislation		48
ARTICLE 12 SUPPLEMENTAL INDENTURES			48
12.1	Supplemental Indentures		48

- iii -

TABLE OF CONTENTS

(continued)

		Page
ARTICLE 13 MISCELLANEOUS			49
13.1	Counterparts		49
13.2	Language of Indenture		50
13.3	Benefit of Indenture		50
13.4	Assignment		50

- iv -

TRUST INDENTURE dated as of ●, 2016

BETWEEN:

EMERA INCORPORATED, a company existing under the laws

of the Province of Nova Scotia;

(hereinafter called the “Issuer”)

OF THE FIRST PART

        - and –

AMERICAN STOCK TRANSFER & TRUST COMPANY,

LLC, a New York limited liability trust company, as the U.S. trustee, the U.S.

registrar and the U.S. paying agent;

(hereinafter called the “U.S. Trustee”)

OF THE SECOND PART

        - and –

CST TRUST COMPANY, a trust company existing under the

federal laws of Canada and having an office in the City of ● in the

Province of ●, as the Canadian trustee and the Canadian registrar;

(hereinafter called the “Canadian Trustee” and, together with the “U.S.

Trustee, the “Trustee”)

OF THE THIRD PART

A. The Issuer has duly authorized the execution and delivery of this Trust Indenture to provide for the issuance of subordinated notes of the Issuer from time to time (the “Notes”), the terms of which will be set out in such notes or in one or more indentures supplemental hereto;

B. All necessary action has been taken by the Issuer to make the Notes, when certified by the Trustee and issued as provided in this Trust Indenture, valid, binding and legal obligations of the Issuer with the benefits and subject to the terms of this Trust Indenture and to make this Trust Indenture a valid and binding agreement of the Issuer, in accordance with its terms; and

C. The foregoing recitals are made as representations and statements of fact by the Issuer and not by the Trustee;

NOW THEREFORE THIS INDENTURE WITNESSETH and it is hereby covenanted, agreed and declared as follows:

ARTICLE 1

INTERPRETATION

1.1 Definitions

In this Trust Indenture, unless otherwise expressly provided or unless there is something in the subject matter or context inconsistent therewith:

1.1.1. “Affiliate” means, in respect of any Person, any other Person which, directly or indirectly, is in control of, is controlled by or is under common control with such Person;

1.1.2. “Authorized Investments” means (i) short term interest bearing or discount debt obligations issued or guaranteed by the Government of Canada or a Province or a Canadian chartered bank (which may include an Affiliate or related party of the Trustee) provided that each such obligation is rated at least R1 (middle) by DBRS Limited, or any equivalent rating by Standard & Poor’s Rating Services, a division of The McGraw-Hill Companies (Canada) Corporation or Moody’s Investors Service, Inc.; and (ii) each other investment as may be authorized as such in a supplemental indenture with respect to a Series;

1.1.3. “Authorized Officer” means any director or officer of the Issuer, or a designated representative of the Issuer designated in writing by any director or officer of the Issuer;

1.1.4. “Book-Entry System” means, with respect to a Series, a securities transfer, clearing, settlement and/or pledge system selected by the Issuer with respect to such Series administered by a Clearing Agency in accordance with the operating rules and procedures of the Clearing Agency, in force from time to time and any successor system thereof;

1.1.5. “Business Day” means, subject to the terms of the Notes of a Series or an applicable supplemental indenture with respect to a Series, a day on which the Issuer and the Trustee are open for business other than a Saturday, Sunday or any statutory or civic holiday in the City of Halifax, Nova Scotia or the City of New York, New York;

1.1.6. “Canadian Trustee” means CST Trust Company, unless a successor Canadian Trustee shall have become such pursuant to the applicable provisions of this Indenture, and thereafter “Canadian Trustee” shall mean such person who is then the Canadian Trustee hereunder;

1.1.7. “Clearing Agency” means DTC or, if otherwise specified in the Notes of a Series or an applicable supplemental indenture for a Series, any other or additional organization that performs securities transfer, settlement, clearing and/or pledge services;

1.1.8. “Code” means the U.S. Internal Revenue Code of 1986, as amended;

1.1.9. “Counsel” means a barrister or solicitor or firm of barristers and solicitors retained by the Trustee or retained by the Issuer and acceptable to the Trustee;

- 2 -

1.1.10. “DTC” means the Depository Trust Company and its nominees or any successors approved by the Issuer and the Trustees;

1.1.11. “ERISA” means the U.S. Employee Retirement Income Security Act of 1974, as amended;

1.1.12. “Event of Default” has the meaning attributed to such term in Section 6.1.1;

1.1.13. “Extraordinary Resolution” has the meaning attributed to such term in Sections 9.13 and 9.16;

1.1.14. “Generally Accepted Accounting Principles” means at any time, any of (a) generally accepted accounting principles in Canada in the effect from time to time, including International Financial Reporting Standards approved by the Canadian Institute of Chartered Accountants or any successor body, (b) generally accepted accounting principles in the United States of America in effect from time to time, approved by the Financial Accounting Standards Board or any successor body, or (c) International Financial Reporting Standards in effect from time to time, approved by the International Accounting Standards Board or any successor body, as consistently applied by the Issuer in the consolidated financial statements of the Issuer in respect of the applicable period;

1.1.15. “Holders” means the registered holders, from time to time, of Notes or, where the context requires, all of such holders, except that for purposes of any withholding tax, “Holders” shall mean the beneficial owners, from time to time, of Notes;

1.1.16. “Holders’ Request” means an instrument signed in one or more counterparts by the Holders of not less than 25% of the principal amount of the outstanding Notes of any Series requesting the Trustee to take the action or proceeding specified therein in respect of such Series;

1.1.17. “Indenture Legislation” has the meaning attributed to such term in Section 11.1;

1.1.18. “Interim Notes” has the meaning attributed to such term in Section 2.16.1;

1.1.19. “Issuer” includes any successor entity to or of the party of the first part which shall have complied with the provisions of Article 8;

1.1.20. “Notes” means any notes, debentures or other instruments of indebtedness, which shall in each case constitute subordinated indebtedness of the Issuer, issued or to be issued under this Indenture for the time being outstanding and entitled to the benefits of this Indenture;

1.1.21. “Officer’s Certificate” means a certificate signed by any one of the Authorized Officers, and may consist of one or more instruments so executed;

- 3 -

1.1.22. “Ordinary Resolution” means a resolution proposed to be passed by the Holders of not less than a majority of the principal amount of the Notes then outstanding who voted in respect of that resolution or signed by the Holders of not less than a majority of the principal amount of the Notes then outstanding entitled to vote on that resolution;

1.1.23. “Participant” means a broker, dealer, bank or other financial institution or other participant in an applicable Clearing Agency or Book-Entry System;

1.1.24. “Paying Agent” means any Person authorized by the Issuer to make payments of principal, interest or redemption price, if any, on Notes, together with any other amounts payable with respect thereto on behalf of the Issuer;

1.1.25. “Person” is to be broadly interpreted and includes an individual, a corporation, a limited liability company, an unlimited liability company, a limited or general partnership, a trust, an unincorporated organization, a joint venture and any other organization, whether or not a legal entity, a government of a country or any political subdivision of a country or any agency or department of any such government and the executors, administrators or other legal representatives of a Person in such capacity;

1.1.26. “Selection Date” has the meaning attributed to such term in Section 3.2;

1.1.27. “Senior Indebtedness” means obligations (other than non-recourse obligations, the Notes or any other obligations specifically designated as being subordinate in right of payment to Senior Indebtedness) of, or guaranteed or assumed by, the Issuer for borrowed money or evidenced by bonds, debentures or notes or obligations of the Issuer for or in respect of bankers’ acceptances (including the face amount thereof), letters of credit and letters of guarantee (including all reimbursement obligations in respect of each of the foregoing) or other similar instruments, and amendments, renewals, extensions, modifications and refundings of any such indebtedness or obligation;

1.1.28. “Series” means a series of Notes;

1.1.29. “Successor Entity” has the meaning attributed to such term in Section 8.1.1;

1.1.30. “this Indenture”, “this Trust Indenture”, “hereto”, “hereby”, “hereunder”, “hereof”, “herein” and similar expressions refer to this indenture and not to any particular Article, Section, subdivision or other portion hereof, and include any and every supplemental indenture; and “supplemental indenture” and “indenture supplemental hereto” include any and every instrument supplemental or ancillary hereto or in implement hereof;

1.1.31. “Trustee” means the party of the second part and the party of the third part and their respective successors for the time being in the trusts hereby created; and

1.1.32. “U.S. Trustee” means American Stock Transfer & Trust Company, LLC, unless a successor U.S. Trustee shall have become such pursuant to the applicable provisions of this Indenture, and thereafter “U.S. Trustee” shall mean such Person who is then the U.S. Trustee hereunder;

- 4 -

1.1.33. “Written Order of the Issuer” and “Written Request of the Issuer” mean, respectively, an order or a request signed by any one of the Authorized Officers, and may consist of one or more instruments so executed.

Words importing the singular include the plural and vice versa and words importing the masculine gender include the feminine gender and vice versa.

1.2 Meaning of “outstanding” for Certain Purposes

Except as otherwise provided in the Notes of a Series or a supplemental indenture for a Series, every Note certified and delivered by the Trustee hereunder shall be deemed to be outstanding until it shall be cancelled or delivered to the Trustee for cancellation, or a new Note shall be issued in substitution therefor under Section 2.15, or moneys for the payment thereof shall be set aside under Article 7, provided that:

1.2.1. where a new Note has been issued in substitution for a Note which has been lost, stolen or destroyed, only one of such Notes shall be counted for the purpose of determining the aggregate principal amount of Notes outstanding;

1.2.2. Notes that have been partially redeemed shall be deemed to be outstanding only to the extent of the unredeemed part of the principal amount thereof; and

1.2.3. for the purpose of any provision of this Indenture entitling Holders of outstanding Notes to vote, sign consents, requests or other instruments or take other action under this Indenture, Notes owned directly or indirectly, legally or equitably, by the Issuer or any Affiliate of the Issuer shall be disregarded, except that:

1.2.3.1 for the purpose of determining whether the Trustee shall be protected in relying on any such vote, consent, request or other instrument or other action, only the Notes of which the Trustee has notice in writing that they are so owned shall be so disregarded;

1.2.3.2 Notes so owned which have been pledged in good faith other than to the Issuer or an Affiliate of the Issuer shall not be so disregarded if the pledgee shall establish to the satisfaction of the Trustee the pledgee’s right to vote such Notes in the pledgee’s discretion free from the control of the Issuer or an Affiliate of the Issuer; and

1.2.3.3 where the Issuer and its Affiliates own 100% of the outstanding Notes, such Notes shall not be so disregarded.

1.3 Interpretation Not Affected By Headings, etc.

The division of this Indenture into Articles and Sections, the provision of a table of contents and the insertion of headings are for convenience of reference only and shall not affect the construction or interpretation of this Indenture.

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1.4 Statute References

Any reference in this Indenture to a statute shall be deemed to be a reference to such statute as amended, re-enacted or replaced from time to time.

1.5 Monetary References

Except as otherwise specified in this Indenture or the Notes of a Series or a supplemental indenture with respect to a Series, any reference in this Indenture to “Dollars”, “dollars” or the sign “$” shall be deemed to be a reference to lawful money of the United States.

1.6 Day Not a Business Day

In the event that any day on or before which any action is required to be taken hereunder is not a Business Day, then such action shall be required to be taken on or before the requisite time on the first Business Day thereafter.

1.7 Invalidity of Provisions

Each of the provisions contained in this Indenture or the Notes is distinct and severable and a declaration of invalidity or unenforceability of any such provision or part thereof by a court of competent jurisdiction shall not affect the validity or enforceability of any other provision hereof. To the extent permitted by applicable law, the parties waive any provision of law which renders any provision of this Indenture or the Notes invalid or unenforceable in any respect.

1.8 Governing Law

This Indenture, any supplemental indenture and the Notes shall be governed by and construed in accordance with the laws of the Province of Nova Scotia and the federal laws of Canada applicable therein, other than such provisions of the Indenture which govern the U.S. Trustee’s rights and obligations to holders of the Notes and the Issuer, which will be governed by the laws of the State of New York.

1.9 Notes and Supplemental Indentures

For greater certainty, the Notes of a Series and/or any supplemental indenture for a Series may amend, modify, render inapplicable or supersede any provision of this Indenture that would otherwise be applicable to such Series, including the subordination provisions of Article 4.

1.10 Additional Parties

Other Persons, in addition to the Issuer and the Trustee, may execute a supplemental indenture and become a party thereto and to this Indenture with respect to the applicable Series for the purposes, and with the rights and obligations, set forth therein.

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ARTICLE 2

THE NOTES

2.1 Limitation on Issue and Designation

The aggregate principal amount of Notes that may be issued under this Indenture is unlimited but Notes may be issued hereunder only upon the terms and subject to the conditions herein provided.

2.2 Issuance in Series

The Notes may be issued in one or more Series subject to the conditions hereinafter set forth. The Notes of each Series shall bear such date or dates and mature on such date or dates, shall bear interest at such rate or rates, may be issued in such denominations, may be redeemable before maturity in such manner and subject to payment of such premium, or without premium, may be payable as to principal, interest and premium, if any, at such place or places, may be payable in such currency or currencies, may be guaranteed by other Persons, may provide for such sinking fund, conversion rights or obligations, exchange rights or obligations and share purchase rights or obligations, if any, may contain such provisions for the interchange or transfer of Notes of different denominations and forms and may contain such other provisions, not inconsistent with the provisions of this Indenture, as may be expressed in an indenture supplemental hereto providing for the issuance of the Notes of such Series or in the Notes of such Series.

2.3 Differences in Notes of any Series

The Notes of any Series may be of different denominations and forms and may contain such variations of tenor and effect as are incidental to such differences of denomination and form including variations in the provisions for the interchange of Notes of different denominations or forms and in the provisions for the registration or transfer of Notes and any Series may consist of Notes having different dates of issue, different dates of maturity, different rates of interest, different redemption prices, if any, and different sinking fund provisions, if any, and partly of Notes carrying the benefit of a sinking fund and partly of Notes with no sinking fund.

2.4 Issuance of Notes as Part of Series Previously Issued

Subject to the foregoing provisions, any of the Notes may be issued as part of any Series previously issued, in which case they shall bear the same designation and designating letters as have been applied to such similar prior issue and shall be numbered consecutively upwards in respect of each denomination of Notes in like manner and following the numbers of the Notes of such prior issue.

2.5 Issuance of Notes

The Notes may be issued in such amounts, to such persons, on such terms, not inconsistent with the provisions of this Indenture, and at par or at a discount or at a premium. Each Note as soon as issued or negotiated shall, subject to the terms hereof, be equally and proportionately entitled to the benefits of this Indenture as if all of the Notes had been issued and negotiated simultaneously. Notes may, subject to the provisions of this Indenture and to such

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restrictions as may be set forth in any Series, and subject as hereinafter provided, from time to time be executed by the Issuer and delivered to the Trustee and shall be certified by the Trustee and delivered to, or to the order of the Issuer, pursuant to a Written Order of the Issuer, without the Trustee receiving any consideration therefor.

2.6 Execution of Notes

The Notes may be signed on behalf of the Issuer by any two of the Authorized Officers. A facsimile signature upon any of the Notes shall for all purposes of this Indenture be deemed to be the signature of the individual whose signature it purports to be and to have been signed at the time such facsimile signature is reproduced. Notwithstanding that any individual whose signature (either manual or in facsimile) may appear on the Notes is not, at the date of this Indenture or at the date of the Notes or at the date of the certifying and delivery thereof, any one of the Authorized Officers, such Notes shall be valid and binding upon the Issuer and entitled to the benefits of this Indenture.

2.7 Certification

No Notes shall be issued or, if issued, shall be obligatory or shall entitle the Holder thereof to the benefits of this Indenture until it has been certified by or on behalf of the Trustee substantially in the form set out in the applicable supplemental indenture hereto or in some other form approved by the Trustee, whose approval shall be conclusively evidenced by the certification thereof. Such certificate on any Notes shall be conclusive evidence as against the Issuer that such Notes are duly issued and is a valid obligation of the Issuer.

The certificate of the Trustee on any Notes shall not be construed as a representation or warranty by the Trustee as to the validity of this Indenture or of the Notes (except the due certification thereof) and the Trustee shall in no respect be liable or answerable for the use made of the Notes or any of them or the proceeds thereof.

2.8 Concerning Interest

2.8.1. Unless otherwise provided in a supplemental indenture for a Series:

2.8.1.1 Every Note, whether issued originally or in exchange for other Notes, shall bear interest from and including its date of issue or from and including the last interest payment date to which interest shall have been paid or made available for payment on such Notes, whichever shall be later.

2.8.1.2 Interest on each Note shall cease to accrue from the earliest of: (i) the maturity date; or (ii) if such Note is called for redemption, the date fixed for redemption, unless upon due presentation and surrender thereof for payment on or after the maturity date or the date fixed for redemption, as the case may be, such payment is improperly withheld or refused.

2.8.1.3 Wherever in this Indenture or the Notes there is mention, in any context, of the payment of interest, such mention shall be deemed to include the payment of interest on amounts in default to the extent that, in such context, such interest is, was or would be payable pursuant to this Indenture or the Notes, and

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express mention of interest on amounts in default in any of the provisions of this Indenture or the Notes shall not be construed as excluding such interest in those provisions where such express mention is not made.

2.8.1.4 If an interest payment date falls on a day that is not a Business Day, the interest payment date will be postponed to the next Business Day, and no further interest or other sums will accrue in respect of such postponement.

2.9 Rank of Notes

All Notes created and issued under this Indenture shall be in all respects entitled, equally and rateably with all other Notes created and issued under this Indenture, to the benefits hereof without preference, priority or distinction on account of the actual time or times of certification and delivery, all in accordance with the terms and provisions of this Indenture. The Notes shall be direct, subordinated obligations of the Issuer, ranking equally and rateably with all other subordinated indebtedness of the Issuer from time to time issued and outstanding, except for indebtedness that, by its terms, ranks subordinate to the Notes.

2.10 Registration of Notes

2.10.1. Subject to Section 2.11, the Issuer shall cause to be kept by and at the principal office of the Trustee in the City of ●, ● or such other location as it may designate from time to time, a central register of Holders, and at such other place or places or by such other registrar or registrars as the Issuer may designate or appoint, with the approval of the Trustee, branch registers, in which shall be entered the names and latest known addresses of the Holders of Notes, and the other particulars, as prescribed by law, of the Notes held by them respectively and of all transfers of Notes. Such registration shall be noted on the Notes by the Trustee or other registrar. Subject to Section 2.11, no transfer of Notes shall be effective as against the Issuer unless made on one of the appropriate registers by the Holder of the Notes or the Holder’s executors or administrators or other legal representatives or the Holder’s attorney duly appointed by an instrument in form and execution satisfactory to the Trustee and upon compliance with such requirements as the Trustee or other registrar may prescribe, and unless such transfer shall have been duly noted on such Notes by the Trustee or other registrar.

2.10.2. The registers referred to in this Section shall be open during regular business hours for inspection by the Issuer, the Trustee and any Holder.

2.10.3. Subject to Section 2.11, the Holder of Notes may, at any time and from time to time, have such Notes transferred at any of the places at which a register is kept pursuant to the provisions of this Section 2.10 and in accordance with such reasonable regulations as the Trustee may prescribe. The Holder of Notes may at any time and from time to time have the registration of such Notes transferred from the register in which the registration thereof appears to another register maintained in another place authorized for that purpose under the provisions of this Indenture. No service charge shall be made to a Holder for any registration of transfer of Notes, but the Issuer or the Trustee may require payment of a sum sufficient to cover any tax, assessment or other governmental charge that may be imposed in connection with any registration of transfer of Notes.

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2.10.4. None of the Issuer, the Trustee or any registrar shall be required:

2.10.4.1 to transfer or exchange any Notes on any interest payment date or during the 10 Business Days immediately preceding any interest payment date; or

2.10.4.2 to transfer or exchange any Notes from the Selection Date to the date that notice of redemption is mailed.

2.10.5. None of the Issuer, the Trustee or any registrar for any of the Notes shall be charged with notice of or be bound to see to the execution of any trust, whether express, implied or constructive, in respect of any Notes and may transfer any Notes on the direction of a Holder thereof, whether named as trustee or otherwise, as though that Person were the beneficial owner thereof.

2.10.6. The Issuer shall have power at any time to close any branch register and in that event it shall transfer the records thereof to an existing register or to a new register and thereafter such Notes shall be deemed to be registered on such existing or new register, as the case may be. In the event that the register in any place is closed and the records transferred to a register in another place, notice of such change shall be given to the Holders of the Notes registered in the register so closed and the particulars of such change shall be recorded in the central register required to be kept in the City of ●, ●.

2.10.7. Every registrar shall, when requested to do so by the Issuer or the Trustee, furnish the Issuer or the Trustee, as the case may be, with a list of the names and addresses of the Holders of the Notes showing the Series, principal amounts and serial numbers of such Notes held by each Holder.

2.11 Book-Entry System

2.11.1. Notwithstanding any other provision of this Indenture, the Issuer may elect to have the Notes of a Series issued hereunder represented in the form of one or more typewritten, English language, fully registered global certificates held by, or on behalf of, a Clearing Agency (or its nominee) as depository of the global certificate (for its Participants) and registered on the register maintained by the Trustee pursuant to Section 2.10 in the name of the Clearing Agency (or its nominee). It is expressly acknowledged that any such registrations of ownership and transfers of such Notes, or interests of Participants therein, will be made by the Clearing Agency only through the applicable Book-Entry System in accordance with policies and procedures of the Clearing Agency. Subject to this Section 2.11, the rights of the holder of any beneficial interest in the Notes of a Series represented by a global certificate (including the right to receive a certificate or other instrument evidencing an ownership interest in such Notes) shall be limited to those established by any agreement (including a book-entry securities services agreement or letter of representations of the Issuer to the Clearing Agency) between the Issuer and the Clearing Agency, by applicable law and agreements between the Clearing Agency and its Participants and between such Participants and the holder of such beneficial interest. Accordingly, except as provided herein, neither the Issuer nor the Trustee shall be under any obligation to deliver, nor shall the holder of such interest have any right to require the delivery of, a certificate evidencing Notes of a Series to the holder of the interest in such Notes. In the event of any conflict between this Indenture and any such agreement between the Issuer and a Clearing Agency, the terms of any such agreement shall prevail, subject to Section 2.11.2.

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2.11.2. Notwithstanding Section 2.11.1, after the occurrence of an Event of Default or a breach of any of the covenants of the Issuer provided for in this Indenture which breach shall have continued unremedied for a period of 60 days after the Issuer has received notice of such breach, unless the Trustee (having regard to the subject matter of the breach) shall have agreed to a longer period and, in such event, within the period agreed to by the Trustee, the Holders of Notes of a Series may at any time determine (which determination shall, for greater certainty, require an Ordinary Resolution and not an Extraordinary Resolution) that the continuation of the holding of the Notes by only global certificates under the Book-Entry System is no longer in the best interests of such Holders.

2.11.3. Upon any determination made pursuant to Section 2.11.2, or if required to do so by law, or if the applicable Book-Entry System ceases to exist, or if the Issuer determines that the applicable Clearing Agency is no longer willing or able to discharge properly its responsibilities as depository and the Issuer is unable to locate a qualified successor, or if the Issuer at its option elects or is required by applicable law or rules of any securities exchange to terminate the applicable Book-Entry System for any reason,

2.11.3.1 the Trustee shall notify the applicable Clearing Agency and shall request such Clearing Agency to notify the Participants of the availability of definitive fully registered certificates representing Notes;

2.11.3.2 the Trustee shall request the Clearing Agency to deliver the global certificate representing Notes to the Trustee and the Trustee shall thereupon reduce the holdings of such Clearing Agency on the register maintained hereunder to nil in respect of the Notes represented by such global certificate;

2.11.3.3 the Issuer shall issue or cause to be issued, in accordance with and subject to the provisions of this Indenture, in exchange for such global certificate, Notes of a Series in definitive form in an aggregate amount equal to the amount of such global certificate registered in the names of the Participants as advised by the Clearing Agency in accordance with their proportionate interest in such global certificate as recorded in the records maintained by such Clearing Agency as at the date of the issue of the Notes in definitive form; and

2.11.3.4 after such replacement of such global certificate by definitive Notes, all payments in respect of such Notes in definitive form shall be made to the registered holders thereof in accordance with the terms and conditions of such Notes in definitive form and the provisions of this Indenture and in all other respects such registered holders shall be the holders thereof for all purposes hereunder.

2.11.4. All expenses of the Trustee and any applicable Clearing Agency relating to this Section 2.11 shall be paid by the Issuer.

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2.11.5. Any notice required or permitted to be given to any beneficial holder of Notes while such Notes are represented by a global certificate held by, or on behalf of, an applicable Clearing Agency as part of the Book-Entry System, shall be provided to or as directed by such Clearing Agency.

2.11.6. It is hereby acknowledged that in making the determination as to the percentage interest of a Participant in a global certificate, the Trustee shall be entitled to rely solely upon the records therefor maintained by any applicable Clearing Agency and confirmed in writing to the Trustee by such Clearing Agency.

2.11.7. The Issuer shall not be responsible for any actions, inactions or omissions on the part of any Clearing Agency and/or the Participants under this Indenture or under any agreements, service rules or procedures entered into between an applicable Clearing Agency and each Participant and shall not be liable to registered holders for any such actions, inactions or omissions by any Clearing Agency and/or the Participants which adversely affect a Person’s beneficial interest in Notes.

2.12 Payment of Principal and Interest in Respect of Notes

2.12.1. Subject to Section 2.12.4 and the specific terms applicable to a Series of Notes, payment of the principal of the Notes will be made by cheque or electronic transfer of funds to the respective Holders thereof in lawful money of the United States against surrender thereof by the respective Holders thereof at the principal office of the Trustee in ●, ●.

2.12.2. Subject to Sections 2.12.3 and 2.12.4 and the specific terms applicable to a Series of Notes, as the interest on Notes becomes due (except interest payable on the maturity date which may be paid upon presentation and surrender of such Notes for payment), the Issuer shall, on each date on which interest on such Notes becomes due, effect an electronic transfer or forward, or cause to be forwarded, a cheque by first class mail, postage prepaid (or in the event of a mail service interruption by such other means as the Trustee and the Issuer shall determine to be appropriate), for such interest (less any tax required or permitted by law and the specific terms applicable to a Series of Notes to be deducted) to such Holder and payable to such Holder and negotiable at par at each of the places at which interest upon such Notes is payable. Any electronic transfer instructions received by the Trustee shall remain in effect until revoked by the Holder. The forwarding of such cheque or electronic funds shall satisfy and discharge the liability for the interest on such Notes to the extent of the sum represented thereby (plus the amount of any tax deducted as aforesaid) unless such cheque is not paid on presentation or is lost or destroyed or such electronic funds are not received on or prior to the applicable payment date. In the event of the non-receipt of any such cheque by a Holder, or the loss or destruction thereof, the Issuer, upon being furnished with evidence of such non-receipt, loss or destruction and indemnity reasonably satisfactory to it, shall issue or cause to be issued to such Holder a replacement cheque for the amount of such cheque. In the event of the non-receipt of any electronic funds by a Holder, the Issuer, upon being furnished with evidence of such non- receipt and indemnity reasonably satisfactory to it, shall forward or cause to be forwarded to such Holder a replacement electronic transfer for the amount initially transferred and not received.

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2.12.3. Where Notes are registered in more than one name, the principal and interest from time to time payable in respect thereof shall be paid by cheque or electronic transfer of funds payable to the order of all such Holders, unless the Issuer has received written instructions from them to the contrary, and the receipt of any one of such Holders therefor shall be a valid discharge to the Trustee, any registrar of Notes, the Issuer and any Paying Agent.

2.12.4. If Notes of a Series are registered in the name of a Clearing Agency or its nominee, the principal and interest from time to time payable (subject to any amounts withheld in accordance with customary practices and procedures of the Trustee or the Clearing Agency) in respect thereof shall be paid by delivery of a cheque or electronic transfer of funds payable to the order of the Clearing Agency or its nominee, as the case may be, and the receipt of the Clearing Agency or its nominee, as the case may be, therefor shall be a valid discharge to the Trustee, any registrar of Notes, the Issuer and any Paying Agent, who shall be entitled to rely upon the Clearing Agency and the Participants to ensure that funds are advanced to beneficial holders of Notes.

2.13 Ownership of Notes

2.13.1. The Person in whose name any Notes are registered shall be deemed to be the owner thereof for all purposes of this Indenture, except for purposes of any withholding tax in which case the beneficial owner of the Notes will be deemed to be the owner, and payment of or on account of the principal of, and interest on, such Notes shall be made only to or upon the order in writing of the registered holder thereof and such payment shall be a complete discharge to the Trustee, any registrar of Notes, the Issuer and any Paying Agent for the amounts so paid.

2.13.2. The Holder for the time being of any Notes shall be entitled to the principal and interest evidenced by such Notes, free from all equities or rights of set-off or counterclaim between the Issuer and the original or any intermediate Holder thereof (except any equities of which the Issuer is required to take notice by law or any rights of set-off or counterclaim which may be specifically set out in the terms of any Series of Notes) and all Persons may act accordingly and a transferee of a Note shall, after the appropriate form of transfer is lodged with the Trustee or other registrar of Notes and upon compliance with all other conditions in that behalf required by this Indenture or by any conditions contained in such Notes or by law, be entitled to be entered on the appropriate register or on any one of the appropriate registers as the owner of such Notes free from all equities or rights of set-off or counterclaim between the Issuer and such Holder’s transferor or any previous Holder thereof, save in respect of equities of which the Issuer is required to take notice by statute or by order of a court of competent jurisdiction.

2.14 Exchange of Notes

2.14.1. In the event that the Notes of a Series are not held in the Book-Entry System, Notes of any denomination may be exchanged for Notes of any other authorized denomination or denominations, any such exchange to be for an equivalent aggregate principal amount and Series. Exchanges of Notes may only be made at the principal office of the Trustee in the City of ●, ●. Any Notes tendered for exchange shall be surrendered to the Trustee and shall be cancelled. The Issuer shall execute, and the Trustee shall certify, all Notes necessary to carry out such exchanges.

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2.14.2. Except as otherwise provided herein, upon any exchange of Notes of any denomination for Notes of any other authorized denominations and upon any transfer of Notes, the Trustee or other registrar of Notes may make a sufficient charge to reimburse it for any stamp tax, security transfer tax or other governmental charge required to be paid, and payment of such charges shall be made by the party requesting such exchange or transfer as a condition precedent thereto.

2.14.3. Notwithstanding the foregoing, no charge to the Holder (other than for insurance on any Notes forwarded by mail) shall be made by the Trustee, any registrar of Notes or the Issuer

2.14.3.1 for any exchange, registration or transfer of any Notes applied for within a period of 30 days from the date of issue thereof; or

2.14.3.2 for any exchange, after such period, of Notes for Notes of the same Series in lesser denominations;

provided that the Notes surrendered for exchange shall not have been issued as a result of any previous exchange, other than an exchange pursuant to Section 2.14.3.1 or 3.8.

2.14.4. None of the Issuer, the Trustee or any other registrar of Notes shall be required to make exchanges of Notes on any interest payment date, during the 10 Business Days immediately preceding any interest payment date or from the Selection Date to the date that notice of redemption is mailed.

2.15 Replacement of Notes

If any of the Notes of a Series shall become mutilated or be lost, stolen or destroyed and in the absence of notice that such Notes have been acquired by a bona fide purchaser, the Issuer shall issue, and thereupon the Trustee shall certify and deliver, new Notes of the same Series upon surrender and cancellation of the mutilated Notes, or, in the case of lost, stolen or destroyed Notes, in lieu of and in substitution for the same, and the substituted Notes shall be in a form approved by the Trustee and shall, subject to the terms of the applicable Series, be entitled to the benefits of this Indenture equally with all other Notes issued or to be issued hereunder. In case of loss, theft or destruction, the applicant for new Notes shall furnish to the Issuer and to the Trustee such evidence of such loss, theft or destruction as shall be satisfactory to them in their discretion and shall also furnish an indemnity in amount and form satisfactory to them in their discretion and any other documents that may be required. The applicant shall pay all expenses incidental to the issuance of any such new Notes.

2.16 Interim Notes

2.16.1. Pending delivery to the Trustee of definitive Notes, the Issuer may execute in lieu thereof (but subject to the same provisions, conditions and limitations as herein set forth), and the Trustee may certify, interim printed, mimeographed or typewritten Notes

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of a Series (“Interim Notes”), in such form and in such denominations as may be approved by the Trustee and by any one of the Authorized Officers (whose certification or signature, either manual or in facsimile, as the case may be, on any such Interim Notes shall be conclusive evidence of such approval) entitling the Holders thereof to definitive Notes of the same Series in any authorized denominations when the same are ready for delivery, without expense to such Holders, but the total amount of Interim Notes so issued shall not exceed the aggregate principal amount of Notes of such Series authorized to be issued hereunder. Forthwith after the issuance of any such Interim Notes, the Issuer shall cause to be prepared the appropriate definitive Notes of such Series for delivery to the Holders of such Interim Notes.

2.16.2. Interim Notes which have been duly issued shall, until exchanged for definitive Notes, entitle the Holders thereof to rank for all purposes as Holders, and otherwise in respect of this Indenture to the same extent and in the same manner as though such exchange had actually been made. When exchanged for definitive Notes, such Interim Notes shall forthwith be cancelled by the Trustee. Any interest paid upon Interim Notes shall be noted thereon by the Paying Agent at the time of payment unless paid by cheque to the Holders thereof.

2.17 Option of Holder as to Place of Payment

Except as otherwise provided herein, all sums which may at any time become payable, whether on the maturity date, on redemption or on a declaration by the Trustee pursuant to Section 6.3 or otherwise, on account of any Notes or any interest shall be payable at the option of the Holder at any of the places at which the principal of and interest on such Notes are payable.

2.18 Payment Agreements for Notes

Notwithstanding anything contained herein, the Issuer may enter into an agreement with a Holder of Notes or with the Person for whom such Holder is acting as nominee providing for the payment to such Holder of the principal, interest, redemption price, if any, on such Notes, together with any other amounts payable with respect thereto, at a place or places other than the place or places specified herein and in such Notes as the place or places for such payment. Any payment of the principal, interest, redemption price, if any, on any such Notes, together with any other amounts payable with respect thereto, at such other place or places pursuant to such agreement shall, notwithstanding any other provision of this Indenture, be valid and binding on the Issuer, the Trustee and such Holder of Notes. The Issuer shall provide written notice to the Trustee of the existence and terms of any payment agreement between the Issuer and any Holder.

2.19 ERISA Matters

2.19.1. Subject to the restrictions in this Section 2.19, the Notes may be held by (i) plans that are subject to the fiduciary responsibility provisions of ERISA or the provisions of Section 4975 of the Code and entities deemed to hold plan assets of the foregoing (such plans and entities, “Plans”) and (ii) plans that are subject to provisions under federal, state or other laws (“Similar Law”) that are substantially similar to the fiduciary responsibility provisions of ERISA or the prohibited transaction provisions of ERISA and/or Section 4975 of the Code (such plans, “Similar Law Plans”). A fiduciary of any Plan or Similar Law Plan shall determine that the purchase, holding, redemption or

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exchange of the Notes or an interest therein is consistent with its fiduciary duties and will not constitute or result in a non-exempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Code, or a violation under any applicable Similar Law. Section 406 of ERISA and Section 4975 of the Code prohibit certain transactions involving the assets of Plans (as well as those plans that are not subject to ERISA but which are subject to Section 4975 of the Code) and certain persons (“parties in interest” or “disqualified persons”) having certain relationships to such Plans, unless a statutory or administrative exemption is applicable to the transaction. There can be no assurance that any administrative or statutory exemption will be available with respect to any particular transaction involving the Notes. A party in interest or disqualified person who engages in a prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and Section 4975 of the Code.

2.19.2. Under a regulation issued by the U.S. Department of Labor, 29 CFR Section 2510.3-101 (as effectively modified by Section 3(42) of ERISA) (the “Regulation”), the assets of the Issuer would be treated as plan assets of a Plan for the purposes of ERISA and the Code only if the Plan acquired an “equity interest” in the Issuer and none of the exceptions to “plan assets” contained in the Regulation was applicable. An equity interest is defined under the Regulation as an interest other than an instrument which is treated as indebtedness under applicable local law and which has no substantial equity features. The Issuer believes that as of the date hereof, the Notes should be treated as indebtedness of the Issuer without substantial equity features for purposes of the Regulation, but there is no certainty that the U.S. Department of Labor or a court would agree with that position. This determination is based upon the traditional debt features of the Notes, including the reasonable expectation of purchasers of the Notes that the Notes will be repaid when due. The purchasers and subsequent transferees of the Notes or any interest therein will be deemed to have acknowledged by its purchase, holding, redemption or exchange thereof that the debt treatment of the Notes for ERISA purposes could change subsequent to the date hereof if the Issuer incurs losses. In the event of a withdrawal or downgrade to below investment grade of the rating of the Notes or a characterization of the Notes as other than indebtedness under applicable local law, the transfer and subsequent acquisition of the Notes or interest therein by a Plan is prohibited.

2.19.3. Unless a statutory or administrative exemption is applicable, the purchase and, in certain cases, the holding of securities by a Plan with respect to which (i) the Issuer or any of its affiliates or (ii) any underwriter, dealer or agent selling the securities or any of their affiliates is a party in interest or disqualified person could constitute a prohibited transaction. Accordingly, each purchaser and subsequent transferee of the Notes or any interest therein will be deemed to have represented by its purchase, holding, redemption or exchange thereof that either (i) it is not, and is not acting on behalf of, any Plan or Similar Law Plan or (ii) its purchase, holding, redemption or exchange of the Notes or any interest therein will not constitute or result in a nonexempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Code because such purchaser and subsequent transferee relied on an available prohibited transaction exemption, all of the conditions of which are satisfied, or is not in violation of any applicable Similar Law. Each purchaser and subsequent transferee of the Notes or any interest therein will be deemed to have acknowledged by its purchase, holding,

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redemption or exchange thereof that neither Plans nor Similar Law Plans may acquire the Notes at any time that the ratings on the Notes are below investment grade or the Notes have been characterized as other than indebtedness for applicable local law purposes.

2.19.4. The purchasers and subsequent transferees of the Notes or any interest therein will be deemed to have acknowledged by its purchase, holding, redemption or exchange thereof that the sale of any securities to a Plan or Similar Law Plan is in no respect a representation by the Issuer, or by any underwriter, dealer or agent selling the securities, that such an investment meets all of the legal requirements with respect to investments by any particular Plan or Similar Law Plan or that such an investment is appropriate for any particular Plan or Similar Law Plan.

2.19.5. References to holder, purchaser or transferee of Notes in this Section 2.19 include reference to a beneficial holder, owner, purchaser or transferee of Notes.

ARTICLE 3

REDEMPTION AND PURCHASE FOR CANCELLATION OF NOTES

3.1 Redemption of Notes

3.1.1. The Issuer shall have the right at its option to redeem either in whole at any time or in part from time to time prior to maturity Notes issued hereunder of any Series which by their terms are made so redeemable (subject, however, to any applicable law restricting the redemption of Notes of such Series) at such rates of premium, if any, and at such date or dates as shall have been determined at the time of the issue of such Notes and as shall be expressed in such Notes and/or supplemental indenture providing for the issue thereof.

3.1.2. The Issuer may be required to redeem, in whole, prior to maturity Notes issued hereunder of any Series which by their terms are made so redeemable (subject, however, to any applicable law restricting the redemption of Notes of such Series) at such rates of premium, if any, at such date or dates as shall have been determined at the time of the issue of such Notes and in such circumstances as shall be expressed in such Notes and/or supplemental indenture providing for the issue thereof.

3.2 Partial Redemption of Notes

If less than all the Notes of a Series are to be redeemed pursuant to Section 3.1, the Issuer shall, at least 15 days prior to the date that notice of redemption is given, notify the Trustee of its intention to redeem the aggregate principal amount of such Series to be redeemed. The Notes to be redeemed shall be selected by the Trustee in such manner as may be described in the applicable Series of Notes and/or any supplemental indenture, or in such other manner as the Trustee may consider equitable. The day the Trustee makes such selection shall be referred to for the purpose of Sections 2.10.4.2 and 2.14 as the “Selection Date”. For this purpose, the Trustee may make, and from time to time amend, regulations with regard to the manner in which such Notes may be so selected and regulations so made shall be valid and binding upon all Holders of Notes notwithstanding the fact that, as a result thereof, one or more of such Notes become subject to redemption in part only.

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3.3 Notice of Redemption

Notice of any intention to redeem any Notes of a Series shall be given by or on behalf of the Issuer to the Holders of such Series in accordance with the terms contained in such Series or any supplemental indenture in respect thereof.

3.4 Notes Due on Redemption Dates

3.4.1. Upon notice having been given as aforesaid, the Notes so called for redemption shall thereupon become due and payable at the applicable redemption price and on the redemption date specified in such notice, in the same manner and with the same effect as if it were the maturity date specified in such Notes, notwithstanding anything contained therein or herein to the contrary, and from and after such redemption date, if the moneys necessary to redeem such Notes shall have been deposited as hereinafter provided and an Officer’s Certificate, affidavit or other proof satisfactory to the Trustee as to the mailing of such notices shall have been delivered to the Trustee, such Notes shall no longer be considered outstanding hereunder and interest upon such Notes shall cease to accrue after such date.

3.4.2. If any question shall arise as to whether notice of redemption or deposit of the redemption moneys has been given or made as provided above, such question shall be decided by the Trustee whose decision shall be final and binding upon all parties in interest.

3.5 Deposit of Redemption Moneys

Upon Notes having been called for redemption, the Issuer shall deposit with the Trustee, on or before the redemption date fixed in the relevant notice of redemption, such sums as may be sufficient to pay the redemption price of the Notes to be redeemed, together with accrued interest, if any, and the estimated charges and expenses to be incurred in connection with such redemption. From the sums so deposited, the Trustee shall pay or cause to be paid to the Holders of the Notes called for redemption, upon surrender of such Notes, the applicable redemption price and interest, (less any applicable withholding taxes, to the extent required or permitted by law and the specific terms applicable to a Series of Notes) to which they are respectively entitled on redemption.

3.6 Failure to Surrender Notes Called for Redemption

If the Holder of any Notes called for redemption shall, within 30 days from the date fixed for redemption, fail to surrender any of such Notes or shall not within such time accept payment of the redemption price payable in respect thereof or give such receipt therefor, if any, as the Trustee may require, such redemption price shall be set aside by the Trustee in trust for such Holder in a bank account and such setting aside shall for all purposes be deemed a payment to the Holder of the sum so set aside, and to that extent the Holder shall have no right except to receive payment out of the moneys so paid and deposited, upon surrender of his Notes, of the redemption price of such Notes without interest thereon.

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3.7 Surrender of Notes for Cancellation

If the principal moneys due upon any Notes shall become payable by redemption or otherwise before the maturity date, the Person presenting such Notes for payment must surrender the same for cancellation, the Issuer nevertheless paying or causing to be paid the interest accrued and unpaid thereon in accordance with the terms of such Notes (computed on a per diem basis if the date fixed for payment is not a scheduled interest payment date).

3.8 Purchase of Notes for Cancellation

Subject to such restrictions on purchase as may be set forth in any Notes of a Series or in any supplemental indenture under which Notes of a Series may be issued, at any time when the Issuer is not in default hereunder, the Issuer may purchase Notes in the market or by private contract at any price.

3.9 Cancellation of Notes

All Notes redeemed and all Notes purchased under this Article 3 shall forthwith be delivered to the Trustee and shall be cancelled by it and will not be reissued or resold, and except as may be provided in the Notes or any supplemental indenture in respect thereof, no Notes shall be issued in substitution therefor.

ARTICLE 4

SUBORDINATION OF NOTES

4.1 Notes Subordinated to Senior Indebtedness

4.1.1. The Issuer covenants and agrees, and each Holder of Notes, by the acceptance thereof, likewise covenants and agrees, that the indebtedness represented by the Notes and the payment of the principal of and interest on each and all of the Notes is hereby expressly subordinated, to the extent and in the manner hereinafter set forth, in right of payment to the prior payment in full of Senior Indebtedness.

4.1.2. In the event (a) of any insolvency or bankruptcy proceedings or any receivership, liquidation, reorganization or other similar proceedings in respect of the Issuer or a substantial part of its property, or of any proceedings for liquidation, dissolution or other winding up of the Issuer, whether or not involving insolvency or bankruptcy, or (b) subject to the provisions of Section 4.2 that (i) a default shall have occurred with respect to the payment of principal of or interest on or other monetary amounts due and payable on any Senior Indebtedness, or (ii) there shall have occurred an event of default (other than a default in the payment of principal or interest or other monetary amounts due and payable) in respect of any Senior Indebtedness, as defined therein or in the instrument under which the same is outstanding, permitting the holder or holders thereof to accelerate the maturity thereof (with notice or lapse of time, or both), and such event of default shall have continued beyond the period of grace, if any, in respect thereof, and, in the cases of subclauses (i) and (ii) of this clause (b), such default or event of default shall not have been cured or waived or shall not have ceased to exist, or (c) that the principal of and accrued interest on the Notes of any Series shall have been declared due and payable pursuant to Section 6.3 and such declaration shall not have been rescinded and annulled as provided in Section 6.4, then:

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4.1.2.1 the holders of all Senior Indebtedness shall first be entitled to receive payment of the full amount due thereon, or provision shall be made for such payment in money or money’s worth, before the Holders of any of the Notes are entitled to receive a payment on account of the principal of or interest on the indebtedness evidenced by the Notes, including, without limitation, any payments made pursuant to Article 3;

4.1.2.2 any payment by, or distribution of assets of, the Issuer of any kind or character, whether in cash, property or securities, to which the Holders of any of the Notes or the Trustee would be entitled except for the provisions of this Article shall be paid or delivered by the person making such payment or distribution, whether a trustee in bankruptcy, a receiver, receiver and manager or liquidating trustee or otherwise, directly to the holders of such Senior Indebtedness or their representative or representatives or to the trustee or trustees under any indenture under which any instruments evidencing any of such Senior Indebtedness may have been issued, ratably according to the aggregate amounts remaining unpaid on account of such Senior Indebtedness held or represented by each, to the extent necessary to make payment in full of all Senior Indebtedness remaining unpaid after giving effect to any concurrent payment or distribution (or provision therefor) to the holders of such Senior Indebtedness, before any payment or distribution is made to the holders of the indebtedness evidenced by the Notes or to the Trustee under this instrument; and

4.1.2.3 in the event that, notwithstanding the foregoing, any payment by, or distribution of assets of, the Issuer of any kind or character, whether in cash, property or securities, in respect of principal of or interest on the Notes or in connection with any repurchase by the Issuer of the Notes, shall be received by the Trustee or the Holders of any of the Notes before all Senior Indebtedness is paid in full, or provision made for such payment in money or money’s worth, such payment or distribution in respect of principal of or interest on the Notes or in connection with any repurchase by the Issuer of the Notes shall be paid over to the holders of such Senior Indebtedness or their representative or representatives or to the trustee or trustees under any indenture under which any instruments evidencing any such Senior Indebtedness may have been issued, ratably as aforesaid, for application to the payment of all Senior Indebtedness remaining unpaid until all such Senior Indebtedness shall have been paid in full, after giving effect to any concurrent payment or distribution (or provision therefor) to the holders of such Senior Indebtedness.

4.2 Disputes with Holders of Certain Senior Indebtedness

Any failure by the Issuer to make any payment on or perform any other obligation under Senior Indebtedness, other than any indebtedness incurred by the Issuer or assumed or guaranteed, directly or indirectly, by the Issuer for money borrowed (or any deferral, renewal, extension or refunding thereof) or any indebtedness or obligation as to which the provisions of this Section shall have been waived by the Issuer in the instrument or instruments by which the Issuer

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incurred, assumed, guaranteed or otherwise created such indebtedness or obligation, shall not be deemed a default or event of default under Section 4.1.2(b) if (a) the Issuer shall be disputing its obligation to make such payment or perform such obligation and (b) either (i) no final judgment relating to such dispute shall have been issued against the Issuer which is in full force and effect and is not subject to further review, including a judgment that has become final by reason of the expiration of the time within which a party may seek further appeal or review, and (ii) in the event of a judgment that is subject to further review or appeal has been issued, the Issuer shall in good faith be prosecuting an appeal or other proceeding for review and a stay of execution shall have been obtained pending such appeal or review.

4.3 Subrogation

Subject to the payment in full of all Senior Indebtedness, the Holders of the Notes shall be subrogated (equally and ratably with the holders of all obligations of the Issuer which by their express terms are subordinated to Senior Indebtedness of the Issuer to the same extent as the Notes are subordinated and which are entitled to like rights of subrogation) to the rights of the holders of Senior Indebtedness to receive payments or distributions of cash, property or securities of the Issuer applicable to the Senior Indebtedness until all amounts owing on the Notes shall be paid in full, and as between the Issuer, its creditors other than holders of such Senior Indebtedness and the Holders, no such payment or distribution made to the holders of Senior Indebtedness by virtue of this Article that otherwise would have been made to the Holders shall be deemed to be a payment by the Issuer on account of such Senior Indebtedness, it being understood that the provisions of this Article are and are intended solely for the purpose of defining the relative rights of the Holders, on the one hand, and the holders of Senior Indebtedness, on the other hand.

4.4 Obligation of Issuer Unconditional

4.4.1. Nothing contained in this Article or elsewhere in this Indenture or in the Notes is intended to or shall impair, as among the Issuer, its creditors other than the holders of Senior Indebtedness and the Holders, the obligation of the Issuer, which is absolute and unconditional, to pay to the Holders the principal of and interest on the Notes as and when the same shall become due and payable in accordance with their terms, or is intended to or shall affect the relative rights of the Holders and creditors of the Issuer other than the holders of Senior Indebtedness, nor shall anything herein or therein prevent the Trustee or any Holder from exercising all remedies otherwise permitted by applicable law upon default under this Indenture, subject to the rights, if any, under this Article of the holders of Senior Indebtedness in respect of cash, property or securities of the Issuer received upon the exercise of any such remedy.

4.4.2. Upon payment or distribution of assets of the Issuer referred to in this Article, the Trustee and the Holders shall be entitled to rely upon any order or decree made by any court of competent jurisdiction in which any such dissolution, winding up, liquidation or reorganization proceeding affecting the affairs of the Issuer is pending or upon a certificate of the trustee in bankruptcy, receiver, receiver and manager, assignee for the benefit of creditors, liquidating trustee or agent or other person making any payment or distribution, delivered to the Trustee or to the Holders, for the purpose of ascertaining the persons entitled to participate in such payment or distribution, the holders of the Senior Indebtedness and other indebtedness of the Issuer, the amount thereof or payable thereon, the amount paid or distributed thereon and all other facts pertinent thereto or to this Article.

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4.5 Payments on Notes Permitted

Nothing contained in this Article or elsewhere in this Indenture or in the Notes shall affect the obligations of the Issuer to make, or prevent the Issuer from making, payment of the principal of or interest on the Notes in accordance with the provisions hereof and thereof, except as otherwise provided in this Article.

4.6 Effectuation of Subordination by Trustee

Each holder of Notes, by its acceptance thereof, authorizes and directs the Trustee on its behalf to take such action as may be necessary or appropriate to effectuate the subordination provided in this Article and appoints the Trustee his attorney-in-fact for any and all such purposes.

4.7 Knowledge of Trustee

Notwithstanding the provisions of this Article or any other provisions of this Indenture, the Trustee shall not be charged with knowledge of the existence of any facts that would prohibit the making of any payment of moneys to or by the Trustee, or the taking of any other action by the Trustee, unless and until the Trustee shall have received written notice thereof mailed or delivered to the Trustee from the Issuer, any Holder, any paying agent or the holder or representative of any class of Senior Indebtedness; provided that if at least three Business Days prior to the date upon which by the terms hereof any such moneys may become payable for any purpose (including, without limitation, the payment of the principal or interest on any Note) the Trustee shall not have received with respect to such moneys the notice provided for in this Section, then, anything herein contained to the contrary notwithstanding, the Trustee shall have full power and authority to receive such moneys and to apply the same to the purpose for which they were received and shall not be affected by any notice to the contrary that may be received by it within three Business Days prior to or on or after such date.

4.8 Trustee May Hold Senior Indebtedness

The Trustee shall be entitled to all the rights set forth in this Article with respect to any Senior Indebtedness at the time held by it, to the same extent as any other holder of Senior Indebtedness, and nothing in Section 11.6 or elsewhere in this Indenture shall deprive the Trustee of any of its rights as such holder.

4.9 Rights of Holders of Senior Indebtedness Not Impaired

4.9.1. No right of any present or future holder of any Senior Indebtedness to enforce the subordination herein shall at any time or in any way be prejudiced or impaired by any act or failure to act on the part of the Issuer or by any noncompliance by the Issuer with the terms, provisions and covenants of this Indenture, regardless of any knowledge thereof any such holder may have or be otherwise charged with.

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4.9.2. With respect to the holders of Senior Indebtedness, (i) the duties and obligations of the Trustee shall be determined solely by the express provisions of this Indenture, (ii) the Trustee shall not be liable except for the performance of such duties and obligations as are specifically set forth in this Indenture, (iii) no implied covenants or obligations shall be read into this Indenture against the Trustee and (iv) the Trustee shall not be deemed to be a fiduciary as to such holders.

4.10 Article Applicable to Paying Agents

In case at any time any paying agent other than the Trustee shall have been appointed by the Issuer and be then acting hereunder, the term “Trustee” as used in this Article shall in such case (unless the context shall require not otherwise) be construed as extending to and including such paying agent within its meaning as fully for all intents and purposes as if such paying agent were named in this Article in addition to or in place of the Trustee; provided, however, that Sections 4.7 and 4.8 shall not apply to the Issuer if it acts as its own paying agent.

4.11 Trustee; Compensation Not Prejudiced

Nothing in this Article shall apply to claims of, or payments to, the Trustee pursuant to Section 5.4 or 11.8.

ARTICLE 5

COVENANTS OF THE ISSUER

5.1 General Covenants

5.1.1. The Issuer will duly and punctually pay or cause to be paid to Holders the principal, interest and redemption price, if any, on the Notes, together with any other amounts payable with respect thereto (including, in the case of default, interest on the amount in default) on the dates, at the places, in the money, and in the manner mentioned herein and in the Notes.

5.1.2. Except as herein otherwise expressly provided, the Issuer will at all times maintain its existence and the Issuer will carry on and conduct its business in a proper and efficient manner and will keep or cause to be kept proper books of account and make or cause to be made therein true and accurate entries of all its dealings and transactions in relation to its business, all in accordance with Generally Accepted Accounting Principles, and at all reasonable times it will furnish or cause to be furnished to the Trustee or its duly authorized agent or attorney such information relating to its business as the Trustee may reasonably require, and such books of account shall during regular business hours be open for inspection by the Trustee or such agent or attorney.

5.1.3. The Issuer will duly and punctually perform and carry out all of the acts or things to be done by it as provided in this Trust Indenture.

5.2 Not to Extend Time for Payment of Interest or Principal

The Issuer covenants that, in order to prevent any accumulation after maturity of unpaid interest or of unpaid Notes, the Issuer will not directly or indirectly extend or assent to the

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extension of time for payment of any interest upon any Notes or of any principal payable in respect of any Notes and that it will not directly or indirectly be or become a party to or approve any such arrangement by purchasing or funding any interest on the Notes or any principal thereof or in any other manner and that the Issuer will deliver to the Trustee all Notes when paid as evidence of such payment.

5.3 To Provide Annual Certificate of Compliance

The Issuer covenants that, on or before March 31, 2017 and on or before March 31 in each subsequent year and at any other time if requested by the Trustee, it will furnish to the Trustee an Officer’s Certificate stating that the Issuer has complied with all covenants, conditions and other requirements contained in this Indenture during the preceding fiscal year, non-compliance with which would, with the giving of notice, lapse of time or otherwise, constitute an Event of Default hereunder or, if such is not the case, specifying the covenant, condition or other requirement which has not respectively been complied with and giving particulars of such non-compliance and the action, if any, the Issuer proposes to take with respect thereto.

5.4 To Pay Trustee’s Remuneration

5.4.1. The Issuer covenants that it will pay to the Trustee reasonable remuneration for its services as Trustee hereunder and will pay all costs, charges and expenses properly incurred by the Trustee in connection with the trusts hereof (including reasonable legal fees and disbursements), on demand by the Trustee.

5.4.2. Any amount due under this Section 5.4 and unpaid 30 days after demand for such payment shall bear interest at the rate normally charged by the Trustee. After default, all amounts so payable and the interest thereon shall be payable out of any funds coming into possession of the Trustee in priority to any payment of the principal of and interest on the Notes.

5.5 Trustee may Perform Covenants

If the Issuer shall fail to perform any of its covenants contained herein, the Trustee may in its discretion, but (subject to Section 6.2) need not, notify the Holders of such failure or may itself perform any of such covenants capable of being performed by it and, if any such covenant requires the payment of money, it may make such payment with its own funds, or with money borrowed by it for such purpose, but shall be under no obligation to do so; and all sums so paid shall be payable by the Issuer in accordance with the provisions of Section 5.4. No such performance by the Trustee of any covenant contained herein or payment by the Issuer of any sums advanced or borrowed by the Trustee pursuant to the foregoing provisions shall be deemed to relieve the Issuer from any default hereunder.

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ARTICLE 6

DEFAULT AND ENFORCEMENT

6.1 Events of Default

6.1.1. Each of the following events is an “Event of Default” in respect of the Notes of any Series:

6.1.1.1 if the Issuer defaults on the payment of principal or premium, if any, when due and payable; or

6.1.1.2 if the Issuer defaults on the payment of interest when due and payable and such default continues for thirty days (subject to the Issuer’s right, at its sole option, to defer interest payments as shall be expressed in the Notes of any Series and/or supplemental indenture providing for the issue thereof).

6.2 Notice of Events of Default

6.2.1. If an Event of Default occurs and is continuing the Trustee shall, within 30 days after it becomes aware of the occurrence of such Event of Default, give notice thereof to the Holders, provided that, notwithstanding the foregoing, the Trustee shall not be required to give such notice if the Trustee in good faith shall have decided that the withholding of such notice is in the best interests of such Holders and shall have so advised the Issuer in writing.

6.2.2. Where notice of the occurrence of an Event of Default has been given pursuant to Section 6.2.1 and the Event of Default is thereafter cured or waived, notice that the Event of Default is no longer continuing shall be given by the Trustee to the Holders within 30 days after the Trustee becomes aware that the Event of Default has been cured or waived.

6.3 Acceleration on Default

If any Event of Default has occurred and is continuing, the Trustee may in its discretion and shall upon receipt of a Holders’ Request, subject to Section 6.4, by notice in writing to the Issuer, declare the principal of, and interest on, the Notes of any Series then outstanding and any other moneys payable hereunder to be due and payable and the same shall forthwith become immediately due and payable to the Trustee, notwithstanding anything contained therein or herein to the contrary, and the Issuer shall pay forthwith to the Trustee for the benefit of the Holders of such Series the principal of, and accrued and unpaid interest (including interest on amounts in default) on, such Notes and all other moneys payable hereunder, together with subsequent interest thereon at the rate borne by such Notes from the date of such declaration until payment is received by the Trustee. Such payment when made shall be deemed to have been made in discharge of the Issuer’s obligations hereunder and any moneys so received by the Trustee shall be applied as provided in Section 6.7.

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6.4 Waiver of Default

If an Event of Default shall have occurred:

6.4.1. other than with respect to a covenant or provision which cannot be modified, amended or waived without the consent of each of the Holders of Notes affected, the Holders of not less than a majority of the aggregate principal amount of the Notes shall have the power (in addition to the powers exercisable by Extraordinary Resolution as hereinafter provided) by instrument signed by such Holders to instruct the Trustee to waive any default or Event of Default hereunder or compliance with any provision hereunder or under the Notes and/or to cancel any declaration made by the Trustee pursuant to Section 6.3 and the Trustee shall thereupon waive the default or Event of Default or compliance and/or cancel such declaration upon such terms and conditions as such Holders shall prescribe; and

6.4.2. the Trustee, so long as it has not become bound to institute any proceedings hereunder, shall have the power to waive any Event of Default hereunder if, in the Trustee’s opinion, relying on the opinion of Counsel, the same shall have been cured or adequate satisfaction made therefor, and in such event to cancel any such declaration theretofore made by the Trustee in the exercise of its discretion, upon such terms and conditions as the Trustee may consider advisable; provided that no delay or omission of the Trustee or of the Holders to exercise any right or power accruing upon any Event of Default shall impair any such right or power or shall be construed to be a waiver of any such Event of Default or acquiescence therein and provided further that no act or omission either of the Trustee or of the Holders shall extend to or be taken in any manner whatsoever to affect any subsequent Event of Default hereunder or the rights resulting therefrom.

6.5 Enforcement by the Trustee

If an Event of Default shall have occurred, but subject to Section 6.4 and to the provisions of any Extraordinary Resolution that may be passed by the Holders as hereinafter provided:

6.5.1. the Trustee may in its discretion proceed to enforce the rights of the Trustee and of such Holders by any action, suit, remedy or proceeding authorized or permitted by this Indenture or by law or equity; and may file such proofs of claim and other papers or documents as may be necessary or advisable in order to have the claims of the Trustee and of the Holders filed in any bankruptcy, insolvency, winding-up or other judicial proceedings relating to the Issuer;

6.5.2. no such remedy for the enforcement of the rights of the Trustee or such Holders shall be exclusive of or dependent on any other such remedy, but any one or more of such remedies may from time to time be exercised independently or in combination;

6.5.3. all rights of action hereunder may be enforced by the Trustee without the possession of any of the Notes or the production thereof on the trial or other proceedings relating thereto; and

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6.5.4. upon the receipt of an instrument signed in one or more counterparts by the Holders of not less than a majority of the principal amount of the outstanding Notes of any Series requesting the Trustee to take the action or proceeding specified therein in respect of such Series and upon being funded and indemnified to its satisfaction as provided in Section 11.4.2, the Trustee shall exercise or take one or more of such remedies as such instrument may direct or, if such instrument contains no direction, as the Trustee may consider expedient, provided that if any such instrument directs the Trustee to take proceedings out of court, the Trustee may in its discretion take judicial proceedings in lieu thereof.

6.6 Holders May Not Sue

No Holder of Notes shall have the right to institute any action, suit or proceeding or to exercise any other remedy authorized or permitted by this Indenture or by law or by equity for the purpose of enforcing payment of interest owing on such Notes, together with any other amounts payable with respect thereto, or for the execution of any trust or power hereunder, unless:

6.6.1. such Holder shall previously have given to the Trustee written notice of the occurrence of an Event of Default;

6.6.2. the Holders, by Extraordinary Resolution, shall have made a request to the Trustee to take action hereunder or the instrument referred to in Section 6.5.4 shall have been delivered to the Trustee, and the Trustee shall have been offered a reasonable opportunity either itself to proceed to exercise the powers hereinbefore granted or to institute an action, suit or proceeding in its name for such purpose;

6.6.3. the Holders or any of them shall have furnished to the Trustee, when requested by the Trustee, sufficient funds and an indemnity in accordance with Section 11.4.2; and

6.6.4. the Trustee shall have failed to act within a reasonable time thereafter.

In such event but not otherwise, any Holder, acting on behalf of such Holder and all other Holders, shall be entitled to take proceedings in any court of competent jurisdiction, including proceedings to seek enforcement of their rights against the Issuer in an Event of Default, such as the Trustee might have taken under Section 6.5, but in no event shall any Holder or combination of Holders have any right to take any other remedy or proceedings out of court; it being understood and intended that no one or more Holders of Notes shall have any right in any manner whatsoever to enforce any right hereunder or under any Notes except subject to the conditions and in the manner herein provided, and that all powers and trusts hereunder shall be exercised and all proceedings at law shall be instituted, had and maintained by the Trustee, except only as herein provided, and in any event for the equal benefit of all Holders of outstanding Notes.

6.7 Application of Moneys

Except as otherwise provided herein, any moneys arising from any enforcement hereof, whether by the Trustee or any Holder of Notes, shall be held by the Trustee and applied by it, together with any moneys then or thereafter in the hands of the Trustee available for the purpose, as follows:

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6.7.1. first, in payment or reimbursement to the Trustee of the remuneration, expenses, disbursements and advances of the Trustee earned, incurred or made in the administration or execution of the trusts hereunder or otherwise in relation to this Indenture with interest thereon as herein provided;

6.7.2. second, in or towards payment of the principal of all of the Notes then outstanding, and thereafter in or towards payment of the accrued and unpaid interest and interest on overdue interest on such Notes (or if the Holders by (i) Ordinary Resolution, by signed instrument only, provided that notice of any Ordinary Resolution passed by signed instrument shall be given by the Trustee to the Holders of Notes within 30 days of the date on which such resolution was passed or (ii) Extraordinary Resolution, shall have directed payments to be made in accordance with any other order of priority, or without priority as between principal and interest, then such moneys shall be applied in accordance with such direction); and

6.7.3. third, the surplus (if any) of such moneys shall be paid to the Issuer or as it may direct; provided, however, that no payments shall be made in respect of the principal or interest of any Notes held, directly or indirectly, by or for the benefit of the Issuer or any Affiliate (other than any Notes pledged for value and in good faith to a Person other than the Issuer or an Affiliate, but only to the extent of such Person’s interest therein), except subject to the prior payment in full of the principal, interest, redemption price, if any, or any other amount payable on indebtedness evidenced by the Notes or interest on overdue amounts thereof which are not so held.

6.8 Distribution of Moneys

Payments to Holders of Notes pursuant to Section 6.7.2 shall be made as follows:

6.8.1. at least 21 days’ notice of every such payment shall be given in the manner provided in Article 10 specifying the date and time when and the place or places where such payments are to be made and the amount of the payment and the application thereof as between principal and interest;

6.8.2. payment in respect of any Notes shall be made upon presentation thereof at any one of the places specified in such notice and any such Notes thereby paid in full shall be surrendered, otherwise a notation of such payment shall be endorsed thereon; but the Trustee may in its discretion dispense with presentation and surrender or endorsement in any special case upon receipt by it of such indemnity as it shall consider sufficient;

6.8.3. from and after the date of payment specified in the notice, interest shall accrue only on the amount owing on the Notes after giving credit for the amount of the payment specified in such notice unless the Notes in respect of which such amount is owing is duly presented on or after the date so specified and payment of such amount is not made; and

6.8.4. the Trustee shall not be required to make any partial or interim payment to Holders unless the moneys in its hands, after reserving therefrom such amount as the Trustee may think necessary to provide for the payments mentioned in Section 6.7.1, exceed 5% of the aggregate principal amount of the outstanding Notes, but it may retain

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the moneys so received by it and deal with the same as provided in Section 11.9 until the money or investments representing the same, with the income derived therefrom, together with any other moneys for the time being under its control, shall be sufficient for such purpose or until it shall consider it advisable to apply the same in the manner hereinbefore set forth.

6.9 Persons Dealing with Trustee

No Person dealing with the Trustee or any of its agents shall be concerned to enquire whether an Event of Default has occurred, or whether the powers which the Trustee is purporting to exercise have become exercisable, or whether any moneys remain due under this Indenture or on the Notes, or to see to the application of any moneys paid to the Trustee; and in the absence of fraud on the part of such Person, such dealing shall be deemed to be within the powers hereby conferred and to be valid and effective accordingly.

6.10 Trustee Appointed Attorney

The Issuer irrevocably appoints the Trustee to be the attorney of the Issuer in the name and on behalf of the Issuer to execute any instruments and do any things which the Issuer ought to execute and do, and has not executed or done, under the covenants and provisions contained in this Indenture and generally to use the name of the Issuer in the exercise of all or any of the powers hereby conferred on the Trustee with full powers of substitution and revocation.

6.11 Remedies Cumulative

No remedy herein conferred upon or reserved to the Trustee or the Holders of Notes is intended to be exclusive of any other remedy, but each and every such remedy shall be cumulative and shall be in addition to every other remedy given hereunder or now or hereafter existing by law or by statute.

6.12 Immunity of Shareholders, Directors, and Others

The Holders and the Trustee waive and release any right, cause of action or remedy now or hereafter existing in any jurisdiction against any past, present or future incorporator, shareholder, director or officer of the Issuer or of any Successor Entity for the payment of the principal of or interest on any of the Notes or on any covenant, agreement, representation or warranty by the Issuer contained herein or in the Notes.

6.13 Judgment Against the Issuer

In the case of any judicial or other proceedings to obtain judgment for the principal of or interest on the Notes, judgment may be rendered against the Issuer in favour of the Holders or in favour of the Trustee, as trustee for the Holders, for any amount which may remain due in respect of the Notes.

6.14 Unconditional Right of Holders to Principal, Premium or Make-Whole Amount, if any, Interest and Additional Amounts

Notwithstanding any other provision in this Indenture, the Holder of any Notes shall have the right which is absolute and unconditional to payment of the principal of (and premium, if

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any) and interest on such Notes on the respective due dates expressed in such Notes as provided therein and to institute suit for the enforcement of any such payment, and such rights shall not be impaired without the consent of the Holder.

ARTICLE 7

SATISFACTION AND DISCHARGE

7.1 Cancellation and Destruction

All matured Notes shall forthwith after payment thereof be delivered to the Trustee and cancelled by it. All Notes which are cancelled or required to be cancelled under this or any other provision of this Indenture shall be destroyed by the Trustee and, if required by the Issuer, the Trustee shall furnish to it a destruction certificate setting out the designating numbers and denominations of the Notes so destroyed.

7.2 Non-Presentation of Notes

If the Holder of any Notes shall fail to present the same for payment on the date on which the principal thereof and the interest thereon or represented thereby becomes payable either at maturity or otherwise or shall not accept payment on account thereof and give such receipt therefor (if any) as the Trustee may require:

7.2.1. the Issuer shall be entitled to pay to the Trustee and direct it to set aside; or

7.2.2. in respect of moneys in the hands of the Trustee which may or should be applied to the payment of the Notes, the Issuer shall be entitled to direct the Trustee to set aside;

the principal moneys, and the interest, as the case may be, in trust to be paid to the Holder of such Notes upon due presentation and surrender thereof in accordance with the provisions of this Indenture; and thereupon the principal moneys, and/or the interest payable on or represented by each Notes in respect whereof such moneys have been set aside shall be deemed to have been paid and thereafter such Notes shall not be considered as outstanding hereunder and the Holders thereof shall thereafter have no right in respect thereof except that of receiving payment of the moneys so set aside by the Trustee (without interest thereon) upon due presentation and surrender thereof, subject always to the provisions of Section 7.3. Any money so set aside may, and, if remaining unclaimed for 60 days, shall be set aside by the Trustee in trust for such Holders in a bank account.

7.3 Repayment of Unclaimed Moneys

Any moneys set aside under Section 7.2 and not claimed by and paid to Holders of Notes within six years after the date of such setting aside shall, subject to applicable law, be repaid to the Issuer by the Trustee on demand and thereupon the Trustee shall be released from all further liability with respect to such moneys and thereafter the Holders in respect of which such moneys were so repaid to the Issuer shall have no rights in respect thereof except to obtain payment of such moneys without interest thereon from the Issuer.

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7.4 Discharge

Upon proof being given to the reasonable satisfaction of the Trustee that all the Notes and interest (including interest on amounts in default) thereon have been paid or satisfied or that, all the outstanding Notes having matured, such payment has been duly provided for by payment to the Trustee or otherwise, and upon payment of all costs, charges and expenses properly incurred by the Trustee in relation to this Indenture and all interest thereon and the remuneration of the Trustee, or upon provision satisfactory to the Trustee being made therefor, the Trustee shall, at the Written Request of the Issuer and at the expense of the Issuer, execute and deliver to the Issuer such deeds or other instruments as shall be necessary to evidence the satisfaction and discharge of this Indenture and to release the Issuer from its covenants contained herein except those relating to the indemnification of the Trustee.

ARTICLE 8

CONSOLIDATION, AMALGAMATION, MERGER, CONVEYANCE, TRANSFER OR LEASE

8.1 Issuer May Consolidate, Etc., Only on Certain Terms

The Issuer shall not merge, amalgamate, consolidate or otherwise combine with any other Person or convey, transfer or lease all or substantially all of its assets to any Person, unless:

8.1.1. in case the Issuer shall consolidate or amalgamate with or merge into another Person or convey, transfer or lease all or substantially all of its assets to any Person, the Person formed by, or resulting from, such consolidation or amalgamation or into which the Issuer, as the case may be, is merged or the Person that acquires by conveyance or transfer, or which leases, all or substantially all of the assets of the Issuer (the “Successor Entity”) shall be a corporation, partnership or trust, organized and validly existing and shall expressly assume and be legally responsible for the Notes and to perform all obligations of the Issuer under this Indenture, by supplemental indenture satisfactory to the Trustee executed and delivered to the Trustee by such Person;

8.1.2. immediately after such consolidation, amalgamation, merger, conveyance, transfer or lease the Successor Entity must not be in default in the performance of the covenants and conditions of this Indenture to be performed by the Issuer; and

8.1.3. the Issuer has delivered to the Trustee an Officers’ Certificate and an opinion of Counsel, each stating that such consolidation, amalgamation, merger, conveyance, transfer or lease and any applicable supplemental indenture comply with this Article and that all conditions precedent herein provided for relating to such transaction have been complied with.

8.2 Successor Substituted

Upon any consolidation or amalgamation of the Issuer with, or merger of the Issuer into, any other Person or any conveyance, transfer or lease of all or substantially all of the assets of the Issuer in accordance with Section 8.1, the Successor Entity shall succeed to, and be substituted for, and may exercise every right and power of the Issuer under this Indenture with the same effect as if such Successor Entity had been named as the Issuer herein, and thereafter, except in the case of a lease, the predecessor Person shall be relieved of all obligations and covenants under this Indenture and the Notes.

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ARTICLE 9

MEETINGS OF HOLDERS

9.1 Right to Convene Meetings

The Trustee may at any time and from time to time and shall, on receipt of a Written Request of the Issuer or a Holders’ Request and upon being indemnified to its reasonable satisfaction by the Issuer or by the Holders signing such Holders’ Request against the costs which may be incurred in connection with the calling and holding of such meeting, convene a meeting of the Holders or the Holders of any Series, depending on who made the request. If the Trustee fails within 30 days after receipt of such Written Request or Holders’ Request and such indemnity to give notice convening a meeting, the Issuer or the Holders, as the case may be, may convene such meeting. Every such meeting shall be held in the city of Halifax, Nova Scotia or at such other place as may be approved or determined by the Trustee.

9.2 Serial Meetings

If the business to be transacted at any meeting by resolution, extraordinary or otherwise, especially affects the rights of the Holders of any Series or part of a Series of Notes in a manner or to an extent substantially differing from that in or to which the rights of the Holders of any other Series or part thereof are affected, then reference to such fact indicating each Series or part of a Series so especially affected shall be made in the notice of the meeting and the meeting shall be and be deemed to be and is herein referred to as a serial meeting.

9.3 Notice of Meetings

At least 21 days’ notice of any meeting of the Holders of Notes will be given to Holders and a copy thereof shall be sent to the Trustee unless the meeting has been called by the Trustee and to the Issuer unless the meeting has been called by the Issuer. Such notice shall state the time when and the place where the meeting is to be held and shall state briefly the general nature of the business to be transacted thereat, but it shall not be necessary for any such notice to set out the terms of any resolution to be proposed at the meeting or any of the provisions of this Section 9.3.

9.4 Chairperson

An individual, who need not be a Holder, nominated in writing by the Trustee shall be chairperson of the meeting and if no individual is so nominated or the individual so nominated is unable or unwilling to act or if the individual so nominated is not present within 15 minutes from the time fixed for the holding of the meeting, the Holders present in person or by proxy shall choose an individual present to be chairperson.

9.5 Quorum

At any meeting of the Holders of Notes other than a meeting convened for the purpose of considering a resolution proposed to be passed as an Extraordinary Resolution as to which the

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provisions of Section 9.13 shall be applicable, a quorum shall consist of one or more Holders present in person or by proxy and representing at least a majority in principal amount of the outstanding Notes. If, however, the meeting is a serial meeting, a quorum shall consist of one or more Holders present in person or by proxy representing at least a majority in principal amount of the outstanding Notes of each Series or part thereof especially affected as aforesaid. If a quorum shall not be present within 30 minutes from the time fixed for holding any such meeting, the meeting, if convened by the Holders or pursuant to a Holder’s Request, shall be dissolved; but in any other case, the meeting shall be adjourned to the same day in the next week (unless such day is not a Business Day, in which case it shall be adjourned to the next following Business Day) at the same time and place. At the adjourned meeting, the Holders present in person or by proxy shall form a quorum and may transact the business for which the meeting was originally convened notwithstanding that they may not represent a majority of the principal amount of the outstanding Notes or the outstanding Notes of each Series, as the case may be.

9.6 Power to Adjourn

The chairperson of any meeting at which a quorum is present may, with the consent of the Holders of a majority in principal amount of the outstanding Notes represented thereat, adjourn any such meeting and no notice of such adjournment need be given except such notice, if any, as the meeting may prescribe.

9.7 Show of Hands

Every question submitted to a meeting of Holders of Notes shall be decided in the first place by a majority of the votes given on a show of hands, except that votes on Extraordinary Resolutions shall be given in the manner hereinafter provided. At such meeting, unless a poll is duly demanded as herein provided, a declaration by the chairperson that a resolution has been carried or carried unanimously or by a particular majority or lost or not carried by a particular majority shall be conclusive evidence of the fact.

9.8 Poll

On every Extraordinary Resolution, and on any other question submitted to a meeting, when demanded by the chairperson or by one or more Holders and/or proxies for Holders holding at least 5% of the principal amount of the Notes represented thereat, a poll shall be taken in such manner and either at once or after an adjournment as the chairperson shall direct. Questions other than Extraordinary Resolutions shall, if a poll is taken, be decided by the votes of the Holders of a majority in principal amount of the Notes represented at the meeting and voted on the poll.

9.9 Voting

On a show of hands, every Person who is present and entitled to vote, whether as a Holder or as proxy, shall have one vote. On a poll, each Holder present in person or represented by a duly appointed proxy shall be entitled to one vote in respect of each $1,000 principal amount of Notes of which he shall then be the Holder. A proxy need not be a Holder. In the case of joint registered Holders of Notes, any one of them present in person or by proxy at the meeting may vote in the absence of the other or others; but in case more than one of them are present in person or by proxy, they shall vote together in respect of the Notes of which they are

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joint registered Holders. At a serial meeting no Ordinary Resolution shall be deemed to have been validly passed or adopted unless there shall have been given in favour thereof not less than a majority of the votes given respectively by the Holders of each Series of Notes or part thereof especially affected as aforesaid.

9.10 Regulations

The Trustee or the Issuer, with the approval of the Trustee, may from time to time make and from time to time vary such regulations as it shall from time to time think fit providing for:

9.10.1. voting by proxy and the form of the instrument appointing a proxy (which shall be in writing) and the manner in which the same shall be executed and for the production of the authority of any Person signing on behalf of a Holder;

9.10.2. the deposit of instruments appointing proxies at such place as the Trustee, the Issuer or the Holders convening the meeting, as the case may be, may in the notice convening the meeting direct and the time, if any, before the holding of the meeting or any adjournment thereof by which the same shall be deposited;

9.10.3. the deposit of instruments appointing proxies at some approved place or places other than the place at which the meeting is to be held and enabling particulars of instruments appointing proxies to be mailed, cabled, telegraphed, telecopied or sent by telex before the meeting to the Issuer or to the Trustee at the place where the same is to be held and for the voting of proxies so deposited as though the instruments themselves were produced at the meeting; and

9.10.4. the calling of a meeting of Holders of Notes and the conduct of business thereat.

Any regulations so made shall be binding and effective on the Holders of Notes and the votes given in accordance therewith shall be valid and shall be counted. Save as such regulations may provide, the only Persons who shall be recognized at any meeting as the Holders of any Notes, or as entitled to vote or (other than as set forth in Section 9.11 below) be present at the meeting in respect thereof, shall be Holders of Notes and persons whom such Holders have duly appointed as their proxies.

9.11 Issuer and Trustee May Be Represented

The Issuer and the Trustee, by their respective officers, directors, employees, and legal advisers, may attend any meeting of the Holders, but shall have no vote as such.

9.12 Powers Exercisable by Extraordinary Resolution

In addition to the powers conferred upon them by any other provisions of this Indenture or by law, a meeting of the Holders of Notes shall have the following powers exercisable from time to time by Extraordinary Resolution, provided that, without the consent of each Holder, affected thereby, the Issuer and the Trustee may not (a) extend the stated maturity of the principal of the Notes, (b) reduce the principal amount thereof or reduce the rate or extend the time of payment of interest thereon, (c) reduce any amount payable on redemption thereof, (d)

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change the place at which or currency in which principal and interest payments are to be made, (e) reduce the amount of any original issue discount security payable upon acceleration or provable in bankruptcy or impair the right to institute suit for the enforcement of any payment on any of the Notes when due, or (f) reduce the aforesaid percentage in principal amount of the Notes:

9.12.1. power to approve any change whatsoever in any of the provisions of this Indenture or the Notes and any modification, abrogation, alteration, compromise or arrangement of the rights of the Holders and/or the Trustee (subject to the consent of the Trustee) against the Issuer or against their undertaking, property and assets or any part thereof, whether such rights arise under this Indenture or the Notes or otherwise;

9.12.2. power to approve any scheme for the reconstruction or reorganization of the Issuer or for the consolidation, amalgamation or merger of the Issuer with any other corporation or for any transfer, sale or lease, in each case whereby all or substantially all of the undertaking, property and assets of the Issuer would become the property of another Person or, in the case of any such amalgamation, of the continuing corporation resulting therefrom, provided that no such approval shall be necessary in respect of any such transaction if the provisions of Article 8 shall have been complied with;

9.12.3. power to direct or authorize the Trustee to exercise any power, right, remedy or authority given to it by this Indenture or the Notes in any manner specified in such Extraordinary Resolution or to refrain from exercising any such power, right, remedy or authority;

9.12.4. power to waive and direct the Trustee to waive any default or Event of Default and/or cancel any declaration made by the Trustee pursuant to Section 6.3 either unconditionally or upon any conditions specified in such Extraordinary Resolution;

9.12.5. power to restrain any Holder from taking or instituting any suit, action or proceeding for the purpose of enforcing payment of the principal, interest or redemption price, if any, of any Notes, together with any other amounts payable with respect thereto, or for the execution of any trust or power hereunder or for any other remedy hereunder;

9.12.6. power to direct any Holder who, as such, has brought any action, suit or proceeding to stay or discontinue or otherwise deal with the same in the manner directed by such Extraordinary Resolution upon payment, if the taking of such action, suit or proceeding shall have been permitted by Section 6.6, of the costs, charges and expenses reasonably and properly incurred by such Holder in connection therewith;

9.12.7. power to appoint a committee to consult with the Trustee (and to remove any committee so appointed) and to delegate to such committee (subject to such limitations, if any, as may be prescribed in such Extraordinary Resolution) all or any of the powers which the Holders may exercise by Extraordinary Resolution under this Section 9.12; the Extraordinary Resolution making such appointment may provide for payment of the expenses and disbursements of and compensation to such committee; such committee shall consist of such number of individuals (who need not be Holders) as shall be prescribed in the Extraordinary Resolution appointing it; subject to the Extraordinary Resolution appointing it, every such committee may elect its chairman and

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may make regulations respecting its quorum, the calling of its meetings, the filling of vacancies occurring in its number, the manner in which it may act and its procedure generally and such regulations may provide that the committee may act at a meeting at which a quorum is present or may act by resolution signed in one or more counterparts by a majority of the members thereof or the number of members thereof necessary to constitute a quorum, whichever is the greater; all acts of any such committee within the authority delegated to it shall be binding upon all Holders of such Notes;

9.12.8. power to agree to any compromise or arrangement with any creditor or creditors or any class or classes of creditors, whether secured or otherwise, and with holders of any securities of the Issuer;

9.12.9. power to authorize the distribution in specie of any shares, bonds, debentures or other securities or obligations and/or cash or other consideration received or the use or disposition of the whole or any part of such shares, bonds, debentures or other securities or obligations and/or cash or other consideration in such manner and for such purpose as may be considered advisable and specified in such Extraordinary Resolution;

9.12.10. power to approve the exchange of the Notes for or the conversion thereof into bonds, debentures or other securities or obligations of the Issuer or of any Person formed or to be formed;

9.12.11. power to remove the Trustee from office and to appoint a new Trustee or Trustees; and

9.12.12. power to amend, alter or repeal any Extraordinary Resolution previously passed or approved by the Holders or by any committee appointed pursuant to Section 9.12.7.

9.13 Meaning of “Extraordinary Resolution”

9.13.1. The expression “Extraordinary Resolution” when used in this Indenture means, subject as hereinafter provided in this Section 9.13, either (i) the written consent of Holders of not less than a majority of the aggregate principal amount of the Notes, or the applicable Series of Notes, or (ii) a resolution proposed to be passed as an Extraordinary Resolution at a meeting of Holders of Notes duly convened for the purpose and held in accordance with the provisions of this Section 9.13 at which the Holders of not less than a majority of the aggregate principal amount of the Notes, or of each applicable Series of Notes if a serial meeting, then outstanding are present in person or by proxy and passed by the favourable votes of the Holders of not less than 66 ²⁄₃% of the principal amount of Notes represented at the meeting and voted on a poll upon such resolution. At a serial meeting such resolution must receive the affirmative vote upon a poll of not less than 66 ²⁄₃% of the votes given by the Holders of each Series of Notes or part thereof especially affected thereby.

9.13.2. If at any such meeting the Holders of not less than a majority of the principal amount of the Notes, or Notes of each Series, as the case may be, then outstanding are not present in person or by proxy within 30 minutes after the time

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appointed for the meeting, then the meeting, if convened by the Holders or pursuant to a Holder’s Request, shall be dissolved; but in any other case, it shall be adjourned to such date, being not less than 21 nor more than 60 days later, and to such place and time as may be appointed by the chairman. Not less than 10 days’ notice shall be given of the time and place of such adjourned meeting in the manner provided in Article 10. Such notice shall state that at the adjourned meeting the Holders present in person or by proxy shall form a quorum, but it shall not be necessary to set forth the purposes for which the meeting was originally called or any other particulars. At the adjourned meeting, the Holders present in person or by proxy shall form a quorum and may transact the business for which the meeting was originally convened and a resolution proposed at such adjourned meeting and passed in accordance with Section 9.13.1 shall be an Extraordinary Resolution within the meaning of this Indenture, notwithstanding that the Holders of not less than a majority of the aggregate principal amount of the Notes then outstanding are not present in person or by proxy at such adjourned meeting.

9.13.3. Votes on an Extraordinary Resolution shall always be given on a poll and no demand for a poll on an Extraordinary Resolution shall be necessary.

9.14 Powers Cumulative

It is hereby declared and agreed that any one or more of the powers and/or any combination of the powers in this Indenture stated to be exercisable by the Holders by Extraordinary Resolution or otherwise may be exercised from time to time and the exercise of any one or more of such powers or any combination of powers from time to time shall not be deemed to exhaust the right of the Holders to exercise the same or any other such power or powers or combination of powers thereafter from time to time.

9.15 Minutes

Minutes of all resolutions and proceedings at every meeting of Holders shall be made and duly entered in books to be provided for that purpose by the Trustee at the expense of the Issuer, and any such minutes, if signed by the chairperson of the meeting at which such resolutions were passed or proceedings had, or by the chairperson of the next succeeding meeting of the Holders, shall be prima facie evidence of the matters therein stated and, until the contrary is proved, every such meeting, in respect of the proceedings of which minutes shall have been made, shall be deemed to have been duly held and convened, and all resolutions passed or proceedings had thereat, to have been duly passed and had.

9.16 Signed Instruments

Any action which may be taken and any power which may be exercised by the Holders at a meeting held as hereinbefore in this Article provided may also be taken and exercised by the Holders of not less than a majority of the principal amount of the outstanding Notes, or the applicable Series of Notes, by signed instrument and the expression “Extraordinary Resolution” when used in this Indenture shall include an instrument so signed. Notice of any Extraordinary Resolution passed in accordance with this Section 9.16 shall be given by the Trustee to the Holders of Notes within 30 days of the date on which such Extraordinary Resolution was passed.

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9.17 Binding Effect of Resolutions

Every Ordinary Resolution and every Extraordinary Resolution passed in accordance with the provisions of this Article 9 at a meeting of Holders of Notes shall be binding upon all the Holders of Notes to which such resolution relates, whether present at or absent from such meeting, and every instrument signed by Holders of Notes in accordance with Section 9.16 shall be binding upon all the Holders of Notes to which such resolution relates, whether signatories thereto or not, and each and every Holder and the Trustee (subject to the provisions for its indemnity herein contained) shall be bound to give effect to every such Ordinary Resolution, Extraordinary Resolution and instrument.

9.18 Evidence of Rights of Holders

Any request, direction, notice, consent or other instrument which this Indenture may require or permit to be signed or executed by the Holders may be in any number of concurrent instruments of similar tenor and may be signed or executed by such Holders in person or by attorney duly appointed in writing. Proof of the execution of any such request, direction, notice, consent or other instrument or of a writing appointing any such attorney shall be sufficient for any purpose of this Indenture if made in the following manner, namely, the fact and date of the execution by any Person of such request, direction, notice, consent or other instrument or writing may be proved by the certificate of any notary public, or other officer authorized to take acknowledgements of deeds to be recorded at the place where such certificate is made, that the Person signing such request, direction, notice, consent or other instrument or writing acknowledged to him the execution thereof, or by an affidavit of a witness of such execution or in any other manner which the Trustee may consider adequate.

The Trustee may, nevertheless, in its discretion require further proof in cases where it considers further proof necessary or desirable or may accept such other proof as it shall consider proper.

ARTICLE 10

NOTICES

10.1 Notice to the Issuer

Any notice to the Issuer under the provisions of this Indenture shall be valid and effective if delivered personally to, by facsimile to or, subject to Section 10.5, if given by first class mail, postage prepaid, addressed to, the Issuer, at 5151 Terminal Road, Halifax, Nova Scotia B3J 1A1, Attention: Corporate Secretary, facsimile: (902) 428-6171, and shall be deemed to have been given on the date of delivery, the Business Day immediately following the date such notice has been sent by facsimile or on the third Business Day after such letter has been mailed, as the case may be. The Issuer may from time to time notify the Trustee of a change in address which thereafter, until changed by further notice, shall be the address of the Issuer for all purposes of this Indenture.

10.2 Notice to Holders

Except as otherwise expressly provided herein, all notices to be given hereunder with respect to the Notes shall be valid and effective if such notice is delivered personally or, subject

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to Section 10.5, is sent by first class mail, postage prepaid, addressed to the Holders of the Notes at their post office addresses appearing in any of the registers hereinbefore mentioned or, if the Holder is a Clearing Agency, in accordance with Section 10.4. For greater certainty, in the event that a Clearing Agency is the Holder, notice to Holders shall be valid and effective if such notice is delivered only to the Clearing Agency. Any notice so delivered or sent by mail shall be deemed to have been given on the day upon which it is delivered or mailed, as the case may be. Any accidental error, omission or failure in giving or in delivering or mailing any such notice or the non-receipt of any such notice by any Holder shall not invalidate or otherwise prejudicially affect any action or proceeding founded thereon.

10.3 Notice to the Trustee

Any notice to the Trustee under the provisions of this Indenture shall be valid and effective if delivered personally to, by facsimile to or, subject to Section 10.5, if given by first class mail, postage prepaid, addressed to, ●, at ●, Attention: ● (Facsimile: ●) and shall be deemed to have been given on the date of delivery, the Business Day immediately following the date such notice has been sent by facsimile or on the third Business Day after such letter has been mailed, as the case may be. The Trustee may from time to time notify the Issuer of a change in address which thereafter, until changed by further notice, shall be the address of the Trustee for all purposes of this Indenture.

10.4 Notice to a Clearing Agency

Any notice to a Clearing Agency under the provisions of this Indenture shall be valid and effective if delivered personally to, by facsimile to or, subject to Section 10.5, if given by registered mail, postage prepaid, addressed to the Clearing Agency at its address as listed on the register maintained by the Trustee or as otherwise provided to the Issuer and shall be deemed to have been given on the date of delivery, the Business Day immediately following the date such notice has been sent by facsimile or on the third Business Day after such letter has been mailed, as the case may be. A Clearing Agency may from time to time notify the Issuer of a change in address which thereafter, until changed by further notice, shall be the address of the Clearing Agency for all purposes of this Indenture.

10.5 Mail Service Interruption

If the Trustee determines that mail service is or is threatened to be interrupted at the time when the Trustee is required or elects to give any notice to the Holders hereunder, the Trustee shall, notwithstanding the provisions hereof, give such notice by means of publication in The Globe and Mail, national edition, or any other English language daily newspaper or newspapers of general circulation in Canada and, if Notes were initially distributed in the United States, in the Wall Street Journal or another financial newspaper of general circulation in New York, New York, once in each of two successive weeks, and notice so published shall be deemed to have been given on the latest date on which the first publication has taken place.

If, by reason of any actual or threatened interruption of mail service due to strike, lock-out or otherwise, any notice to be given to the Trustee or to the Issuer would be unlikely to reach its destination in a timely manner, such notice shall be valid and effective only if delivered personally in accordance with Section 10.1 or 10.3, as the case may be.

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ARTICLE 11

CONCERNING THE TRUSTEE

11.1 Trust Indenture Legislation

11.1.1. In this Article 11, the term “Indenture Legislation” means the provisions, if any, of the Companies Act (Nova Scotia) and any other statute of Canada or a province thereof, the U.S. Trust Indenture Act of 1939, as amended, and of the regulations under any such statutes, relating to trust indentures providing for the issue or guarantee of debt obligations by corporations and to the rights, duties and obligations of trustees under such trust indentures and of corporations issuing or guaranteeing debt obligations under trust indentures, to the extent that such provisions are at the time in force and applicable to this Indenture or the Issuer.

11.1.2. If and to the extent that any provision of this Indenture limits, qualifies or conflicts with a mandatory requirement of Indenture Legislation, such mandatory requirement shall prevail.

11.2 At all times in relation to this Indenture and any action to be taken hereunder, the Issuer and the Trustee each shall observe and comply with Indenture Legislation and the Issuer, the Trustee and each Holder shall be entitled to the benefits of Indenture Legislation.No Conflict of Interest

The Trustee is trustee in respect of the Notes. The Trustee represents to the Issuer that, at the date of the execution and delivery of this Indenture, there exists no material conflict of interest in the role of the Trustee as a fiduciary hereunder. If at any time a material conflict of interest exists in the Trustee’s role as a fiduciary hereunder, the Trustee shall, within 90 days after ascertaining that such a material conflict of interest exists, either eliminate the same or else resign from the trusts hereunder by giving notice in writing to the Issuer at least 21 days prior to such resignation and shall thereupon be discharged from all further duties and liabilities hereunder. If the Trustee has a material conflict of interest, the validity and enforceability of this Indenture, any supplemental indenture and any Notes will not be affected in any manner by reason only of the existence of such material conflict of interest.

11.3 Qualifications of Trustee

11.3.1. There shall at all times be a U.S. Trustee hereunder for the Notes which shall be (i) a corporation, limited liability company, trust company, association or company organized and doing business under the laws of the United States of America, any State thereof or the District of Columbia, authorized under such laws to exercise corporate trust powers and subject to supervision or examination by United States federal or State authority, or (ii) a corporation, or other Person organized and doing business under the laws of any other government which is permitted to act as Trustee pursuant to any rule, regulation or order of the SEC, authorized under such laws to exercise corporate trust powers and subject to supervision or examination by an authority of such government, or a political subdivision thereof, substantially equivalent to the supervision or examination applicable to an institution described in clause (i) above, in each case under clauses (i) and (ii) having (together with its parent) a combined capital and surplus of at least US$50,000,000 and its corporate trust office in New York, New York. If such corporation or other Person publishes reports of condition at least annually, pursuant to law or to the

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requirements of said supervising or examining authority, then for the purposes of this Section the combined capital and surplus of such corporation or other Person shall be deemed to be its combined capital and surplus as set forth in its most recent report of condition so published.

11.3.2. For so long as required by any Indenture Legislation, there shall be a Canadian Trustee hereunder for the Notes. The Canadian Trustee shall at all times be a corporation organized under the laws of Canada or any province thereof and authorized to carry on trust business therein.

11.3.3. No Person will be eligible to be appointed as Canadian Trustee hereunder, or to continue to act as Canadian Trustee at any time, other than a company incorporated under the laws of Canada or of a province or territory of Canada that, at such time, is resident in Canada for purposes of the Income Tax Act (Canada) and is authorized and qualified to carry on the business of a trust company under the laws of Nova Scotia and every other jurisdiction where such authorization or qualification is necessary to enable it to act as a trustee hereunder.

11.3.4. Neither the Issuer nor any Person directly or indirectly controlling, controlled by or under common control with the Issuer shall serve as a Trustee. For purposes of the preceding sentence, the term “control” shall mean the power to direct the management and policies of a Person directly or through one or more intermediaries, whether through the ownership of voting securities, by contract, or otherwise, and the terms “controlling” and “controlled” shall have meanings correlative to the foregoing.

11.3.5. If at any time a Trustee shall cease to be eligible in accordance with the provisions of this Section 11.3.5, such Trustee shall resign immediately in the manner and with the effect hereinafter specified in this Article 11.

11.4 Rights and Duties of Trustee

11.4.1. In the exercise of the rights and duties prescribed or conferred by the terms of this Indenture, the Trustee shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

11.4.2. The obligation of the Trustee to commence or continue any act, action or proceeding for the purpose of enforcing any rights of the Trustee or the Holders hereunder shall be conditional upon the Holders furnishing, when required by notice in writing by the Trustee, sufficient funds and indemnity to commence or continue such act, action or proceeding and indemnity reasonably satisfactory to the Trustee to protect and hold harmless the Trustee against the costs, charges and expenses and liabilities to be incurred thereby and any loss and damage it may suffer by reason thereof. None of the provisions contained in this Indenture shall require the Trustee to expend or risk its own funds or otherwise incur financial liability in the performance of any of its duties or in the exercise of any of its rights or powers.

11.4.3. The Trustee may, before commencing or at any time during the continuance of any such act, action or proceeding, require the Holders at whose instance it is acting to deposit with the Trustee the Notes held by them, for which Notes the Trustee shall issue receipts.

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11.4.4. Every provision of this Indenture that by its terms relieves the Trustee of liability or entitles it to rely upon any evidence submitted to it is subject to the provisions of Indenture Legislation, this Section 11.4 and Section 11.5.

11.5 Evidence, Experts and Advisers

11.5.1. In addition to the reports, certificates, opinions, statutory declarations and other evidence required by this Indenture, the Issuer shall furnish to the Trustee such additional evidence of compliance with any provisions hereof, and in such form, as may be prescribed by Indenture Legislation or as the Trustee may reasonably require by written notice to the Issuer.

11.5.2. In the exercise of its rights, duties and obligations, the Trustee may act and rely on the truth of the statements and the accuracy of the opinions expressed therein and upon statutory declarations, opinions, reports, certificates or other evidence referred to in Section 11.5.1, provided that the Trustee examines the same and determines that such evidence complies with the applicable requirements of this Indenture and of Indenture Legislation. The Trustee shall be entitled to act and rely on the genuineness and authenticity of any such writing submitted to it. It shall not be necessary for the Trustee to ascertain whether or not the persons who have executed, signed or otherwise issued the documents have authority to do so or that they are the same persons named therein.

11.5.3. The Trustee may employ or retain such Counsel, auditors, accountants, appraisers or other experts or advisers, whose qualifications give authority to any opinion or report made by them, as it may reasonably require for the purpose of determining or discharging its duties hereunder, may pay their reasonable fees and disbursements without taxation of costs of any counsel and shall not be responsible for any misconduct on the part of any of them. Any remuneration so paid by the Trustee shall be repaid in accordance with Section 5.4.

11.5.4. The Trustee may act and rely and shall be protected in acting and relying in good faith on the opinion or advice or information obtained from any counsel, auditors, accountants, appraisers or other expert or advisers, whether retained or employed by the Trustee in accordance with Section 11.5.3 or by the Issuer, in relation to any manner arising in the performance of its duties under the Trust Indenture.

11.5.5. Proof of execution of any document or instrument in writing, including a Holders’ Request, may be satisfied by a certificate of a notary public or other officer with similar powers certifying that the person signing such instrument acknowledged to him the execution thereof or by an affidavit of a witness to such execution or any other manner the Trustee considers adequate.

11.6 Trustee May Deal in Notes

The Trustee may buy, sell, lend upon and deal in the Notes or other securities of the Issuer, either with the Issuer or otherwise, and generally contract and enter into financial transactions with the Issuer or otherwise, without being liable to account for any profits made thereby.

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11.7 Trustee Not Required to Give Security

The Trustee shall not be required to give any bond or security in respect of the execution of the trusts and powers of this Indenture or otherwise in respect of this Indenture.

11.8 Protection of Trustee

By way of supplement to the provisions of any law for the time being relating to trustees, it is expressly declared and agreed as follows:

11.8.1. the Trustee shall not be liable for or by reason of any statements of fact or recitals in this Indenture or in the Notes (except the representation contained in Section 11.2 and in the certificate of the Trustee on the Notes) or required to verify the same, but all such statements or recitals are and shall be deemed to be made by the Issuer;

11.8.2. nothing herein contained shall impose any obligation on the Trustee to see to or to require evidence of the registration or filing (or renewal thereof) of this Indenture or any instrument ancillary or supplemental hereto;

11.8.3. the Trustee shall not be:

11.8.3.1 bound to give any notice or do or take any act, action or proceeding by virtue of the powers conferred on it hereby unless and until it shall have been required to do so under the terms hereof; or

11.8.3.2 required to take notice of any default hereunder, unless and until notified in writing of such default, which notice shall distinctly specify the default desired to be brought to the attention of the Trustee and in the absence of any such notice, the Trustee may conclusively assume that no default has occurred in the observance and performance of any of the representations, warranties, covenants, agreements or conditions contained in this Indenture, and any such notice shall in no way limit any discretion herein given to the Trustee to determine whether or not the Trustee shall take action with respect to any default;

11.8.4. the Trustee shall not incur any liability or responsibility whatever or be in any way responsible for the consequence of any breach on the part of the Issuer of any of the covenants herein contained or of any acts of the agents of the Issuer;

11.8.5. the Trustee shall not be liable for any action taken or omitted by it, or any action suffered by it except through its own gross negligence or willful misconduct;

11.8.6. the Issuer shall indemnify and save harmless the Trustee and its officers, directors, employees, representatives and agents from and against any and all liability, losses, costs, claims, actions or demands whatsoever brought against the Trustee which it may suffer or incur as a result of or arising out of the performance of its duties and obligations under this Indenture, including any and all legal fees and disbursements of whatever kind or nature, save only in the event of the gross negligent action, the gross negligent failure to act or the willful misconduct of the Trustee or any of its officers, directors, employees, representatives or agents; and it is understood and agreed that this indemnity will survive the termination or discharge of this Indenture and the resignation or removal of the Trustee;

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11.8.7. the Trustee will not be responsible for any error made or act done by it resulting from reliance upon the signature of any Person on behalf of any Person on whose signature the Trustee may be called upon or entitled to act or refrain from acting under this Indenture nor shall the Trustee be responsible for relying on the accuracy of the information contained in any such document provided it honestly and in good faith believes such information to be correct.

11.8.8. the Trustee shall not be required to give security for the execution of the trusts or its conduct or administration under this Indenture;

11.8.9. the Trustee will not be required to disburse monies according to this Indenture except to the extent that monies have been deposited with it;

11.8.10. none of the provisions contained in this Indenture shall require the Trustee to expend or risk its own funds or otherwise incur financial liability in the performance of any of its duties or in the exercise of any of its rights or powers unless indemnified as aforesaid and provided with sufficient funds or to give any bond or security in respect of the trust and powers of this Indenture;

11.8.11. the Trustee shall retain the right not to act and shall not be held liable for refusing to act unless it receives clear and reasonable documentation which complies with the terms of this Indenture. Such documentation must not require the exercise of any discretion or independent judgment, except as otherwise provided herein;

11.8.12. the Issuer shall provide to the Trustee an incumbency certificate setting out the names and sample signatures of persons authorized to give instructions to the Trustee hereunder. The Trustee shall be entitled to rely on such certificate until a revised certificate is provided to it hereunder. The Trustee shall be entitled to refuse to act upon any instructions given by a party which are signed by any person other than a person described in the incumbency certificate provided to it pursuant to this Section; and

11.8.13. the Trustee shall be entitled to rely, and act upon, on any direction, order, instruction, notice or other communication provided to it hereunder which is sent to it by facsimile or electronic transmission.

11.9 Investment of Trust Moneys

11.9.1. Unless otherwise provided in this Indenture, any moneys held by the Trustee, which under the trusts of this Indenture may or ought to be invested or which may be on deposit with the Trustee or which may be in the hands of the Trustee, may be invested and reinvested in the name or under the control of the Trustee, upon the written direction of the Issuer, in Authorized Investments.

11.9.2. Upon receipt of a direction from the Issuer, the Trustee shall invest any moneys held by it in Authorized Investments in its name in accordance with such direction. Any direction from the Issuer to the Trustee shall be in writing and shall be

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provided to the Trustee no later than 9:00 a.m. (● time) on the day on which the investment is to be made. Any such direction received by the Trustee after 9:00 a.m. (● time) or received on a non-Business Day shall be deemed to have been given prior to 9:00 a.m. (● time) on the next Business Day.

11.9.3. In the event that the Trustee does not receive a direction or only a partial direction, the Trustee may hold cash balances constituting part or all of the funds and may, but need not, invest same in the deposit department of a Canadian chartered bank; but the Trustee and its Affiliates, or a Canadian chartered bank shall not be liable to account for any profit to any parties to this Indenture or to any person or entity other than at a rate, if any, established from time to time by the Trustee which rate shall not exceed 0.5% per annum.

11.9.4. The Trustee shall not be liable for any loss or losses realized on such investments, negligence, willful acts or defaults only excepted.

11.10 Action by Trustee to Protect Rights

The Trustee shall have the power to institute and maintain all and any such actions, suits or proceedings as it may consider necessary or expedient to preserve, protect or enforce its rights and the rights of the Holders of the Notes.

11.11 Replacement of Trustee

The Trustee may resign its trust and thereupon be discharged from all further duties and liabilities hereunder by giving to the Issuer 90 days’ notice in writing or such shorter notice as the Issuer may accept as sufficient. The Holders by Extraordinary Resolution shall have power at any time to remove the Trustee and to appoint a new trustee hereunder. In the event of the Trustee resigning or being removed as aforesaid or being dissolved, becoming bankrupt, going into liquidation, ceasing to be a resident of Canada for purposes of the Income Tax Act (Canada) or otherwise becoming incapable of acting hereunder, the Issuer shall forthwith appoint a new trustee hereunder unless a new trustee has already been appointed by the Holders; failing such appointment by the Issuer, the retiring trustee hereunder at the expense of the Issuer or any Holder may apply to a Judge of the Superior Court of Justice of Ontario, on such notice as such Judge may direct, for the appointment of a new trustee hereunder; but any trustee so appointed by the Issuer or by the Court shall be subject to removal as aforesaid by the Holders. Any new trustee hereunder appointed under any provision of this Section 11.11 shall be a company that meets the requirements of Section 11.2 and shall certify that it will not have any material conflict of interest upon becoming trustee hereunder and the Canadian Trustee shall certify that it is a resident of Canada for the purposes of the Income Tax Act (Canada).

11.11.1. On any new appointment, the new Trustee shall be vested with the same powers, rights, duties and responsibilities as if it had been originally named herein as Trustee without further assurance, conveyance, act or deed; but there will be immediately executed, at the expense of the Issuer, all such conveyances or other instruments as may, in the opinion of Counsel, be necessary or advisable for the purpose of assuring such powers, rights, duties and responsibilities of the new Trustee, provided that any resignation or removal of the Trustee and appointment of a successor Trustee shall have been evidenced by the execution of an appropriate instrument and, at the request of the

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Issuer, the predecessor Trustee, upon payment of its outstanding remuneration and expenses, shall execute and deliver to the successor Trustee an appropriate instrument transferring to such successor Trustee all rights and powers of the Trustee hereunder.

11.11.2. On any new appointment, the Issuer shall promptly give notice thereof to the Holders.

11.11.3. Any corporation into which the Trustee may be merged or with which it may be consolidated or amalgamated, or any corporation resulting from any merger, consolidation or amalgamation to which the Trustee shall be a party or any corporation to which the Trustee has transferred substantially all of its corporate trust business, shall be the successor Trustee under this Indenture without the necessity of the execution of any instrument or any further act.

11.11.1. If a Canadian Trustee under this Indenture is no longer required by any Indenture Legislation, then the Issuer may remove the Canadian Trustee.

11.12 Acceptance of Trusts

The Trustee accepts the trusts in this Indenture declared and provided for and agrees to perform the same upon the terms and conditions herein set forth and in trust for the various Persons who shall from time to time be Holders, subject to the terms and conditions herein set forth.

11.13 Appointment of Authenticating Agent

Any Trustee may appoint one or more Authenticating Agents with respect to the Notes which shall be authorized to act on behalf of, and subject to the direction of, such Trustee to authenticate the Notes, including Notes issued upon original issue, exchange, registration of transfer or partial redemption thereof or pursuant to Section 2.15; and Notes so authenticated shall be entitled to the benefits of this Indenture and shall be valid and obligatory for all purposes as though authenticated by such Trustee. Wherever reference is made in this Indenture to the authentication and delivery of the Notes by a Trustee or to a Trustee’s certificate of authentication, such reference shall be deemed to include authentication and delivery on behalf of such Trustee by any Authenticating Agent of such Trustee and a certificate of authentication executed on behalf of such Trustee by such Authenticating Agent. Each Authenticating Agent shall be acceptable to the Issuer and shall at all times be either (i) a corporation, limited liability company, association or company organized and doing business under the laws of the United States of America, any State thereof or the District of Columbia, authorized under such laws to act as Authenticating Agent, having (together with its parent) a combined capital and surplus of not less than US$50,000,000 and subject to supervision or examination by federal or state authority or (ii) a corporation or other Person organized and doing business under the laws of Canada or any province thereof, authorized under such laws to act as Authenticating Agent, having (together with its parent) a combined capital and surplus of not less than US$50,000,000 (or the equivalent in other currencies) and subject to supervision or examination by governmental authority of its jurisdiction of incorporation and organization. If such Authenticating Agent publishes reports of condition at least annually, pursuant to law or to the requirements of said supervising or examining authority, then for the purposes of this Section the combined capital and surplus of such Authenticating Agent shall be deemed to be its combined

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capital and surplus as set forth in its most recent report of condition so published. If at any time an Authenticating Agent shall cease to be eligible in accordance with the provisions of this Section, such Authenticating Agent shall resign immediately in the manner and with the effect specified in this Section.

The Canadian Trustee hereby appoints and authorizes the U.S. Trustee to act as its Authenticating Agent with respect to the Notes.

Any corporation or other Person into which an Authenticating Agent may be merged or converted or with which it may be consolidated or amalgamated, or any corporation or other Person resulting from any merger, conversion, consolidation or amalgamation to which such Authenticating Agent shall be a party, or any corporation or other Person succeeding to all or substantially all of the corporate agency or corporate trust business of any Authenticating Agent, shall be the successor to such Authenticating Agent, provided such corporation shall be otherwise eligible under this Section, without the execution or filing of any paper or any further act on the part of the Trustee or such Authenticating Agent.

Any Authenticating Agent may resign at any time by giving written notice thereof to the Trustees and to the Issuer. A Trustee may at any time terminate the appointment of any Authenticating Agent of such Trustee by giving written notice thereof to such Authenticating Agent and to the Issuer and each other Trustee then in office. Upon receiving such notice of resignation or upon such termination, or in case at any time such Authenticating Agent shall cease to be eligible in accordance with the provisions of this Section, the respective Trustee may appoint a successor Authenticating Agent which shall be acceptable to the Issuer and each other Trustee then in office and shall, at the expense of the Issuer, provide notice of such appointment to all Holders of the Securities and to each other Trustee then in office. Any successor Authenticating Agent, upon acceptance of its appointment hereunder, shall become vested with all the rights, powers and duties of its predecessor hereunder, with like effect as though originally named as an Authenticating Agent. No successor Authenticating Agent shall be appointed unless eligible under the provisions of this Section.

The Corporation agrees to pay to each Authenticating Agent from time to time reasonable compensation for its services hereunder.

11.14 Joint Trustees

The rights, powers, duties and obligations conferred and imposed upon the Trustees are conferred and imposed upon and shall be exercised and performed by the U.S. Trustee and the Canadian Trustee either jointly or severally, except to the extent otherwise provided herein or, in the case of the Canadian Trustee, otherwise required by any Indenture Legislation, and, except to the extent that under any Indenture Legislation the Canadian Trustee shall be incompetent or unqualified to perform such act, in which event such rights, powers, duties and obligations shall be exercised and performed by a Trustee which is not so incompetent or unqualified to the extent it can do so under applicable law, and except that neither Trustee shall be liable or responsible for the acts or omissions of the other Trustee. If the Trustees are unable to agree jointly to act or refrain from acting with respect to any right, power, duty or obligation conferred jointly upon the Trustees hereunder, the U.S. Trustee shall be entitled to act without the Canadian Trustee, and any action by the U.S. Trustee, or decision of the U.S. Trustee to act or refrain from acting, shall be binding upon the Canadian Trustee and each other Person as if the Canadian Trustee so acted or refrained from acting.

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11.15 Compliance with Privacy Legislation

The parties acknowledge that federal provincial and/or state legislation in Canada and the United States that address the protection of individuals’ personal information (collectively, “Privacy Laws”) applies to obligations and activities under this Indenture. Despite any other provision of this Indenture, no party shall take or direct any action that would contravene, or cause any other party to contravene, applicable Privacy Laws. The Issuer shall, prior to transferring or causing to be transferred personal information to the Trustee, obtain and retain required consents of the relevant individuals to the collection, use and disclosure of their personal information, or shall have determined that such consents either have previously been given upon which the parties can rely or are not required under the Privacy Laws. The Trustee shall use commercially reasonable efforts to ensure that its services hereunder comply with Privacy Laws. Specifically, the Trustee agrees: (a) to have a designated chief privacy officer; (b) to maintain policies and procedures to protect personal information and to receive and respond to any privacy complaint or inquiry; (c) to use personal information solely for the purposes of providing its services under or ancillary to this Indenture and not to use it for any other purpose except with the consent of or direction from the Issuer or the individual involved; (d) not to sell or otherwise improperly disclose personal information to any third party; and (e) to employ administrative, physical and technological safeguards to reasonably secure and protect personal information against loss, theft, or unauthorized access, use or modification.

11.16 Compliance with Anti-Money Laundering Legislation

The Trustee shall retain the right not to act and shall not be liable for refusing to act if, due to a lack of information or for any other reason whatsoever, the Trustee, in its sole judgment, determines that such act might cause it to be in non-compliance with any applicable anti-money laundering or anti- terrorist legislation, regulation or guideline. The Issuer hereby agrees that if any account to be opened, or interest to be held, by the Trustee in connection with this Indenture, for or to the credit of the Issuer, is intended to be used by or on behalf of a third party, the Issuer will complete and execute forthwith a declaration in the Trustee’s prescribed form as to the particulars of such third party.

ARTICLE 12

SUPPLEMENTAL INDENTURES

12.1 Supplemental Indentures

From time to time the Trustee and the Issuer may and, when required by this Indenture, they shall, execute, acknowledge and deliver by their proper officers deeds or indentures supplemental hereto, which thereafter shall form part hereof, for any one or more of the following purposes:

12.1.1. adding to the provisions hereof such additional covenants of the Issuer, enforcement provisions and other provisions for the protection of the Holders of Notes and/or providing for events of default in addition to those herein specified;

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12.1.2. making such provisions not inconsistent with this Indenture as may be necessary or desirable with respect to matters or questions arising hereunder, including the making of any modifications in the form of the Notes which do not affect the substance thereof and which, in the opinion of the Trustee (relying on the opinion of Counsel), it may be expedient to make, provided that the Trustee shall be of the opinion (relying on the opinion of Counsel) that such provisions and modifications will not be materially prejudicial to the rights of the Holders;

12.1.3. evidencing the succession, or successive successions, of any other Person to the Issuer and the covenants of and obligations assumed by any such successor in accordance with the provisions of this Indenture;

12.1.4. giving effect to any Extraordinary Resolution passed as provided in Article 9;

12.1.5. making any additions to, deletions from or alterations of the provisions of this Indenture (including any of the terms and conditions of the Notes) which, in the opinion of the Trustee (relying on the opinion of Counsel), are not materially prejudicial to the rights of the Holders and which are necessary or advisable in order to incorporate, reflect or comply with Indenture Legislation;

12.1.6. adding to or altering the provisions hereof in respect of the transfer of any Notes, including provision for the exchange of Notes of different denominations, in a manner which, in the opinion of the Trustee (relying on the opinion of Counsel), is not materially prejudicial to the rights of the Holders;

12.1.7. correcting or rectifying any ambiguities, defective provisions, errors or omissions herein, provided that, in the opinion of the Trustee (relying on the opinion of Counsel), neither the rights of the Trustee nor the Holders are materially prejudiced thereby;

12.1.8. providing for the issue of Notes of any one or more Series; and

12.1.9. any other purpose not inconsistent with the terms of this Indenture provided that, in the opinion of the Trustee (relying on the opinion of Counsel), the rights of the Trustee and of the Holders are in no way materially prejudiced thereby;

provided that the Trustee may in its discretion decline to enter into any supplemental indenture which in the opinion of the Trustee would materially prejudice the Trustee when the supplemental indenture shall become effective.

ARTICLE 13

MISCELLANEOUS

13.1 Counterparts

This Indenture may be executed in several counterparts including by facsimile or in electronic form, each of which when so executed shall be deemed to be an original, and such counterparts together shall constitute one and the same instrument and notwithstanding their date of execution shall be deemed to bear the same date as of the date hereof.

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13.2 Language of Indenture

The parties hereto have requested that this document be drafted in the English language.

Les parties ont demandé que le présent document soit rédigé en langue anglaise.

13.3 Benefit of Indenture

Except as provided in Article 4, nothing in this Indenture or in the Notes, express or implied, will give to any Person, other than the parties to this Indenture, any Paying Agent, any registrar of Notes and their successors under this Indenture and the Holders of Notes, any benefit or any legal or equitable right, remedy or claim under this Indenture.

13.4 Assignment

This Indenture may not be assigned by any party without the prior written consent of the other parties.

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IN WITNESS WHEREOF the parties hereto have executed this Indenture under the hands of their proper officers duly authorized in that behalf.

EMERA INCORPORATED
By:	(signed) “●”
Name:	●
Title:	●
By:	(signed) “●”
Name:	●
Title:	●
AMERICAN STOCK TRANSFER & TRUST COMPANY, LLC
By:	(signed) “●”
Name:	●
Title:	Authorized Signatory
By:	(signed) “●”
Name:	●
Title:	Authorized Signatory
CST TRUST COMPANY
By:	(signed) “●”
Name:	●
Title:	Authorized Signatory
By:	(signed) “●”
Name:	●
Title:	Authorized Signatory