6-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of August, 2017

Commission File Number: 000-54516

Emera Incorporated

(Exact name of registrant as specified in its charter)

5151 Terminal Road

Halifax NS B3J 1A1

Canada

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F  ☐            Form 40-F  ☒

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):  ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):  ☐

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	EMERA INCORPORATED
Date: August 14, 2017	By:	/s/ Stephen Aftanas
		Name: Stephen D. Aftanas
		Title: Corporate Secretary

EXHIBIT INDEX

Exhibit No.	Description
99.1	Emera Incorporated Management’s Discussion and Analysis for the three month period ended July 31, 2017
99.2	Emera Incorporated unaudited interim financial statements for the three month period ended July 31, 2017
99.3	Form 52-109F2 Certification of Interim Filings by the Chief Executive Officer
99.4	Form 52-109F2 Certification of Interim Filings by the Chief Financial Officer
99.5	Emera Incorporated Earnings Coverage Ratio for the Twelve Months Ended July 31, 2017
99.6	Emera Incorporated Media Release dated August 10, 2017

EX-99.1

Exhibit 99.1

Management’s Discussion & Analysis

As at August 10, 2017

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 second quarter and year-to-date in 2017 relative to the same periods in 2016; and its financial position as at June 30, 2017 relative to December 31, 2016. 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. The Company’s activities are carried out through six business segments; Emera Florida and New Mexico, Nova Scotia Power Inc., Emera Maine, Emera Caribbean, Emera Energy and Corporate and Other.

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 six months ended June 30, 2017; and the Emera Incorporated annual MD&A and audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2016. 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 Equity Investment	Accounting Policies Approved/Examined By
Subsidiary
Tampa Electric – Electric Division of Tampa Electric Company (“TEC”)	Florida Public Service Commission (“FPSC”) and the Federal Energy Regulatory Commission (“FERC”)
Peoples Gas System (“PGS”) – Gas Division of TEC	FPSC
New Mexico Gas Company, Inc. (“NMGC”)	New Mexico Public Regulation Commission (“NMPRC”)
Nova Scotia Power Inc. (“NSPI”)	Nova Scotia Utility and Review Board (“UARB”)
Emera Maine	Maine Public Utilities Commission (“MPUC”) and 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”)
Equity 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”)	National Utility Regulatory Commission (“NURC”)

1

All amounts are in Canadian dollars (“CAD”), except for the Emera Florida and New Mexico, 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.

TABLE OF CONTENTS

Forward-looking Information	3
Introduction and Strategic Overview	3
Non-GAAP Financial Measures	5
Consolidated Financial Review	6
Significant Items Affecting Earnings	6
Consolidated Financial Highlights	8
Consolidated Income Statement and Operating Cash Flow Highlights	9
Business Overview and Outlook	11
Emera Florida and New Mexico	11
NSPI	12
Emera Maine	13
Emera Caribbean	13
Emera Energy	14
Corporate and Other	14
Consolidated Balance Sheet Highlights	16
Developments	17
Outstanding Common Stock Data	17
Emera Florida and New Mexico	17
NSPI	21
Emera Maine	23
Emera Caribbean	25
Emera Energy	27
Corporate and Other	30
Liquidity and Capital Resources	31
Consolidated Cash Flow Highlights	31
Contractual Obligations	33
Debt Management	33
Guarantees and Letters of Credit	34
Risk Management and Financial Instruments	35
Disclosure and Internal Controls	37
Critical Accounting Estimates	38
Changes in Accounting Policies and Practices	38
Summary of Quarterly Results	40

2

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 harbour 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 Business Overview and 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; enterprise resource planning implementation risk; 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 that could reduce demand for electricity; weather; commodity price risk; unanticipated maintenance and other expenditures; system operating and maintenance risk; project development and construction risk; derivative financial instruments and hedging; 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.

INTRODUCTION AND STRATEGIC OVERVIEW

Emera is a geographically diverse energy and services company. The Company has investments in electricity generation, transmission and distribution, gas transmission and distribution, and utility services, predominantly within rate-regulated utilities supporting strong, consistent earnings and cash flow. Emera seeks to provide its customers with reliable, cost-effective and sustainable energy products and services, and provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States and the Caribbean. For investors, Emera seeks to deliver long-term growth, and accordingly, the primary measures of performance are annual dividend growth, earnings per common share growth, adjusted earnings per common share growth (a non-GAAP measure described in the Non-GAAP Financial Measures section below) and total shareholder return. The Company targets eight per cent annual dividend growth through 2020.

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Emera targets achieving 75 to 85 per cent of its adjusted net income from its rate-regulated utilities, which is reflective of the Company’s low risk profile; and a dividend payout ratio of 70 to 75 per cent of adjusted net income.

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, lower-cost natural gas, growing demand for new electric heating and cooling solutions, the requirement for large-scale transmission projects to deliver new energy sources to customers, and environmental concerns. These environmental concerns include a desire to reduce emissions of carbon dioxide and other greenhouse gases and the potential effect of climate change, including changes in global and regional weather patterns, changes in the frequency and intensity of extreme weather events, and rising sea levels. 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, and the related transmission and distribution infrastructure to deliver that energy to market.

While it is still unclear whether economic volatility, government policy and lower fossil fuel prices will slow the pace of 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, natural gas and new transmission infrastructure is likely to continue across the sector despite any cost differential with more carbon-intensive generating options. The capital spending requirements related to these investments will need to be managed within the context of overall energy pricing.

In Florida, the Company is evaluating a number of initiatives, including transmission and solar generation that would reduce carbon emissions. 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 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 benefit from enhanced connection to the northeastern United States, providing potential for excess renewable energy to be delivered throughout that region.

Emera Energy is a component of Emera’s business that is not rate-regulated. Formed in 2003, Emera Energy is a physical energy marketing and trading business, complemented by a portfolio of competitive electricity generation facilities. A substantial portion of Emera Energy’s activities are in northeast North America, and the business is supported by comprehensive infrastructure and market knowledge, a focus on customer service and robust risk management.

A collaborative approach to strategic partnerships, combined with the ability to find creative solutions to work within and across multiple jurisdictions, and experience dealing with complex projects and investment structures are fundamental to Emera’s strategy. The Company will continue to make investments in its regulated utilities to benefit customers and focus on providing rate stability. 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 the utilities’ 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 has grown its asset base to 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. 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.

4

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 and foreign currency exchange 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.

The effect of foreign currency exchange on Emera’s net income is noteworthy, as it is expected that approximately 70 per cent of Emera’s adjusted net income will be derived from subsidiaries with a US functional currency. Emera‘s consolidated net income and cash flows will be impacted by movements in the US dollar relative to the Canadian dollar.

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. These measures are discussed and reconciled below.

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”) commodity 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 in 2016 related to the effect of USD-denominated currency and forward contracts for the TECO Energy, Inc. (“TECO Energy”) acquisition. These contracts were put in place to economically hedge the anticipated proceeds from the 2015 sale of $2.185 billion four per cent convertible unsecured subordinated debentures represented by instalment receipts (“the Debenture Offering” or “Debentures” or “Convertible Debentures”) for the 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 Review section, Emera Energy and Corporate and Other.

The following reconciles 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:

5

For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Net income attributable to common shareholders	$	101	$	208	$	413	$	252
After-tax mark-to-market gain (loss)	$	(16)	$	(30)	$	144	$	(106)
Adjusted net income attributable to common shareholders	$	117	$	238	$	269	$	358
Earnings per common share – basic	$	0.47	$	1.39	$	1.95	$	1.69
Adjusted earnings per common share – basic	$	0.55	$	1.59	$	1.27	$	2.40

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, invest in capital and finance working capital requirements.

Adjusted EBITDA is a non-GAAP financial measure used by Emera. Similar to adjusted net income calculations described above, this measure represents EBITDA absent the income effect of Emera’s mark-to-market adjustments.

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 operating performance. 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, Emera Florida and New Mexico, NSPI, Emera Maine, Emera Caribbean, Emera Energy, and Corporate and Other sections.

The following is a reconciliation of reported net income attributable to common shareholders to EBITDA and Adjusted EBITDA.

For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Net income (1)	$	110	$	217	$	432	$	272
Interest expense, net		178		107		353		182
Income tax expense		34		1		146		28
Depreciation and amortization		220		85		437		172
EBITDA		542		410		1,368		654
Mark-to-market gain (loss), excluding income tax and interest		(25)		(42)		207		(117)
Adjusted EBITDA	$	567	$	452	$	1,161	$	771

(1) Net income is income before Non-controlling interest in subsidiaries and Preferred stock dividends.

CONSOLIDATED FINANCIAL REVIEW

Significant Items Affecting Q2 Earnings

2017

Earnings Impact of After-Tax Mark-to-Market Gains and Losses

6

After-tax mark-to-market losses decreased $14 million to $16 million in Q2 2017 compared to $30 million in Q2 2016 mainly due to changes in existing positions on long-term natural gas contracts at Emera Energy. Year to date, after-tax mark-to-market increased $250 million to a $144 million gain in 2017 compared to a $106 million loss for the same period in 2016. 2016 year-to-date included a $117 million loss resulting from the reversal of 2015 gains on USD-denominated currency and forward contracts related to the financing of the TECO Energy acquisition. Other factors contributing to the increase include changes in existing positions on long-term contracts at Emera Energy, and the reversal of 2016 mark-to-market losses at Emera Energy.

2016

Investment in Algonquin Power and Utilities Corp.

On May 24, 2016, Emera completed the sale of 50.1 million common shares of Algonquin Power and Utilities Corp. (“APUC”), representing approximately 19.3 per cent of APUC’s issued and outstanding common shares, for gross proceeds of $544 million. This sale resulted in a pre-tax gain of $172 million or $1.15 per common share (after-tax gain of $146 million or $0.97 per common share), which was recorded in “Other income (expenses), net” in Q2 2016.

On June 30, 2016, Emera exchanged 12.9 million APUC subscription receipts and dividend equivalents into 12.9 million APUC common shares. This conversion resulted in a pre-tax gain of $63 million or $0.42 per common share (after-tax gain of $53 million or $0.35 per common share), which was recorded in “Other income (expenses), net” in Q2 2016. These shares were sold on December 8, 2016. Emera no longer holds any interest in APUC.

Gain on BLPC Self-Insurance Fund Regulatory Liability

BLPC maintains a 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. Third party risk advisors were engaged to support a detailed risk analysis, which was completed to quantify the prudent assessment of the risk to BLPC’s transmission and distribution system from natural catastrophes.

In June 2016, BLPC secured support from the Government of Barbados and the Trustees of the SIF to reduce the contingency funding in the SIF to $29 million ($22 million USD). As a result, Emera recorded a pre-tax gain of $53 million ($41 million USD) or $0.35 per common share and an after-tax gain of $43 million ($34 million USD) or $0.29 per common share in “Other income (expenses), net”. In Q3 2016, Emera received a distribution of $65 million ($50 million USD) from the fund.

Emera Energy Recognition of State Fuel Taxes

In Q2 2016, Emera Energy recorded a $20 million pre-tax or $0.13 per common share ($12 million after-tax or $0.08 per common share) liability for state tax on natural gas sales made from November 2013 through March 2016, including $4 million pre-tax ($2 million after-tax) related to Q1 2016. The recognition of this liability resulted in an increase to “Non-regulated fuel for generation and purchased power” in the period.

Acquisition Related Costs

Emera incurred after-tax costs of $42 million ($0.28 per common share) in Q2 2016 and $60 million year-to-date 2016 ($0.40 per common share) related to its acquisition of TECO Energy. All acquisition costs have been recognized in the Corporate and Other segment.

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Consolidated Financial Highlights

For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
Adjusted Net Income	2017		2016		2017		2016
Emera Florida and New Mexico	$	103	$	-	$	182	$	-
NSPI		29		28		99		81
Emera Maine		12		10		25		19
Emera Caribbean		11		58		18		68
Emera Energy		(11)		(29)		(1)		19
Corporate and Other		(27)		171		(54)		171
Adjusted net income attributable to common shareholders	$	117	$	238	$	269	$	358
After-tax mark-to-market gain (loss)		(16)		(30)		144		(106)
Net income attributable to common shareholders	$	101	$	208	$	413	$	252
For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues	$	1,469	$	499	$	3,326	$	1,376
Income from operations		291		1		872		271
Net income attributable to common shareholders		101		208		413		252
After-tax mark-to-market gain (loss)		(16)		(30)		144		(106)
Adjusted net income attributable to common shareholders	$	117	$	238	$	269	$	358
Earnings per common share – basic	$	0.47	$	1.39	$	1.95	$	1.69
Earnings per common share – diluted	$	0.47	$	1.38	$	1.94	$	1.68
Adjusted earnings per common share – basic	$	0.55	$	1.59	$	1.27	$	2.40
Dividends per common share declared	$	0.5225	$	0.4750	$	1.0450	$	0.9500
Adjusted EBITDA	$	567	$	452	$	1,161	$	771

The following table highlights significant changes in adjusted net income from 2016 to 2017.

For the millions of Canadian dollars	Three months ended June 30		Six months ended June 30
Adjusted net income – 2016	$	238	$	358
Emera Florida and New Mexico		103		182
2016 acquisition and financing costs related to the acquisition of TECO Energy		42		60
Emera Energy		6		(32)
2016 Emera Energy’s recognition of fuel taxes for 2013 to March 2016		12		12
NSPML and LIL AFUDC earnings		8		15
NSPI		1		18
2016 gain on BLPC SIF regulatory liability		(43)		(43)
TECO Energy post-acquisition financing costs		(45)		(90)
2016 gain on conversion of APUC subscription receipts and dividend equivalents to common shares of APUC		(53)		(53)
2016 gain on sale of APUC common shares		(146)		(146)
Other		(6)		(12)
Adjusted net income – 2017	$	117	$	269

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For the millions of Canadian dollars	Six months ended June 30
	2017		2016
Operating cash flow before changes in working capital	$	703	$	325
Change in working capital		(222)		151
Operating cash flow	$	481	$	476
Investing cash flow	$	(888)	$	178
Financing cash flow	$	227	$	5,810

As at millions of Canadian dollars	June 30 2017		December 31 2016
Working capital	$	488	$	301
Total assets	$	28,584	$	29,221
Total long-term debt (including current portion)	$	14,617	$	14,744

Q2 Consolidated Income Statement Highlights

Operational Results

Income from operations increased $290 million to $291 million in Q2 2017 compared to $1 million in Q2 2016. Absent mark-to-market increases of $25 million, income from operations increased $265 million mainly due to the contribution of Emera Florida and New Mexico and increased contribution from Emera Energy.

Total operating revenues increased $970 million to $1,469 million in Q2 2017 compared to $499 million in Q2 2016. Absent mark-to-market increases of $35 million, operating revenues increased $935 million due to:

• $946 million increase from Emera Florida and New Mexico;

• $24 million decrease from New England Gas Generating Facilities (“NEGG”) reflecting an unplanned outage at the Bridgeport Facility.

Total operating expenses increased $680 million to $1,178 million in Q2 2017 compared to $498 million in Q2 2016, primarily due to the addition of expenses from Emera Florida and New Mexico, partially offset by lower fuel expense at NEGG reflecting an unplanned outage at the Bridgeport Facility and the recognition of prior period state fuel taxes in Q2 2016.

Other income (expenses), net

Other income in Q2 2017 decreased $293 million to $1 million compared to $294 million in the same period in 2016. This was due to a $172 million gain on the 2016 sale of APUC common shares, a $63 million gain on the 2016 conversion of APUC subscription receipts and dividend equivalents into common shares, and a $53 million gain on the BLPC SIF regulatory liability in 2016.

Interest expense, net

Interest expense, net increased $71 million in Q2 2017 to $178 million compared to $107 million in the same period in 2016, due to interest expense from Emera Florida and New Mexico and interest on the permanent financing related to the TECO Energy acquisition, offset by the 2016 interest expense on the acquisition related Convertible Debentures.

Income tax expense

Income tax expense increased $33 million to $34 million in Q2 2017 compared to $1 million in Q2 2016 due to the non-taxable portion of gains on the 2016 APUC transactions and changes in the proportion of income earned in foreign jurisdictions. This was partially offset by decreased income before provision for income taxes.

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Year-to-Date Consolidated Income Statement and Operating Cash Flow Highlights

Operational Results

Income from operations increased $601 million to $872 million year-to-date in 2017 compared to $271 million for the same period in 2016. Absent mark-to-market increases of $190 million, income from operations increased $411 million mainly due to the contribution of Emera Florida and New Mexico, partially offset by decreased contribution from Emera Energy.

Total operating revenues increased $1,950 million to $3,326 million year-to-date in 2017 compared to $1,376 million in 2016. Absent mark-to-market increases of $200 million, operating revenues increased $1,750 million due to:

• $1,834 million increase from Emera Florida and New Mexico;

• $100 million decrease at NEGG reflecting lower hedged power prices, decreased sales volumes driven by an unplanned outage at the Bridgeport facility and less favourable market conditions.

Total operating expenses increased $1,349 million to $2,454 million year-to-date in 2017 compared to $1,105 million for the same period in 2016. This was due to the addition of expenses from Emera Florida and New Mexico. This increase was partially offset by decreased fuel expense at NEGG due to lower hedged natural gas prices, decreased volumes reflecting an unplanned outage at the Bridgeport Facility and lower sales volumes and the recognition of prior period state fuel taxes in Q2 2016.

Other income (expenses), net

Other income decreased $152 million to $3 million year-to-date in 2017 compared to $155 million for the same period in 2016. This was due to a $172 million gain on the 2016 sale of APUC common shares, a $63 million gain on the 2016 conversion of APUC subscription receipts and dividend equivalents into common shares, and a $53 million gain on the BLPC SIF regulatory liability in 2016. These 2016 gains were partially offset by $117 million of mark-to-market losses in 2016 relating to the TECO Energy acquisition related USD-denominated currency and forward contracts.

Interest expense, net

Interest expense, net increased $171 million year-to-date in 2017 to $353 million compared to $182 million in 2016. This was due to interest expense from Emera Florida and New Mexico and the financing related to the TECO Energy acquisition.

Income tax expense

Income tax expense increased $118 million to $146 million year-to-date compared to $28 million for the same period in 2016 primarily due to increased income before provision for income taxes, the non-taxable portion of gains on the 2016 APUC transactions and changes in the proportion of income earned in foreign jurisdictions. This was partially offset by increased deferred income taxes on regulated income recorded as regulatory assets and liabilities and the non-deductible portion of foreign exchange and mark-to-market adjustments related to the TECO Energy acquisition in 2016.

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Net cash provided by operating activities

Net cash provided by operating activities in 2017 increased $5 million to $481 million compared to $476 million during the same period in 2016 as explained below.

Cash from operations before changes in working capital increased by $378 million mainly due to the contribution from Emera Florida and New Mexico, partially offset by increased financing costs from long-term debt related to the TECO Energy acquisition and decreased margin from Emera Energy Services (“EES”) and NEGG.

Changes in working capital decreased operating cash flows by $373 million. This decrease is due to payments in 2017 related to significant year end accruals and refunds to customers in 2017 for fuel clause over-recoveries collected in 2016 at Emera Florida and New Mexico. In addition, the decrease is due to the timing of payments and changes in fuel inventory levels compared to 2016 at NSPI, changes in posted margin at EES, the recognition of prior period state fuel taxes at NEGG in 2016 and the impact of a weaker USD.

Effect of Foreign Currency Translation

Emera operates globally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and particularly the US dollar, which could positively or adversely affect results. Consistent with the Company’s risk management policies, currency risks are managed through matching US denominated debt to finance US operations and the use of short-term foreign currency derivative instruments to hedge specific transactions. Emera does not utilize derivative financial instruments for foreign currency trading or speculative purposes.

Components of net income and adjusted net income are translated at the weighted average rate of exchange. The table below includes Emera’s significant segments whose contribution to adjusted net income is recorded in US dollar currency.

millions of US dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Emera Florida and New Mexico	$	77	$	-	$	137	$	-
Emera Maine		9		7		19		14
Emera Caribbean		9		44		14		52
Emera Energy (1)		(1)		(14)		10		23
		94		37		180		89
Corporate and Other (2)		(29)		3		(58)		5
Total	$	65	$	40	$	122	$	94
FX rate for period	$	1.34	$	1.29	$	1.33	$	1.34

(1) Includes Emera Energy’s US dollar adjusted net income from EES, NEGG and Bear Swamp.

(2) Corporate and Other includes interest expense on US dollar denominated debt, net of interest income on an intercompany US dollar loan to Emera Energy.

BUSINESS OVERVIEW AND OUTLOOK

Emera Florida and New Mexico

Emera Florida and New Mexico includes TECO Energy, the parent company of TEC, NMGC and TECO Finance. TEC consists of two divisions; Tampa Electric, a vertically-integrated regulated electric utility engaged in the generation, transmission and distribution of electricity, serving customers in West Central Florida; and PGS, a regulated gas distribution utility engaged in the purchase, distribution and sale of natural gas, serving customers in Florida. NMGC is a regulated gas distribution utility engaged in the purchase, transmission, distribution and sale of natural gas serving customers in New Mexico.

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Emera Florida and New Mexico earnings are most directly impacted by the earned rate of return on equity (“ROE”) and the capital structures approved by the FPSC and NMPRC, the prudent management and approved recovery of operating costs, the approved recovery of regulatory deferrals, sales volumes, and the timing and amount of capital expenditures.

The Florida utilities anticipate earning within their allowed ROE ranges in 2017 and expect rate base and earnings to be higher than prior years. Tampa Electric and PGS expect higher customer growth rates in 2017 than those experienced in 2016, reflective of economic growth in Florida. Assuming normal weather, sales are expected to increase consistent with customer growth. In accordance with the 2013 settlement agreement approved by the FPSC, Tampa Electric increased base rates by $110 million USD on January 16, 2017, the commercial operation date of the Polk Power Station expansion project. This expansion project adds 460 MW of generating capacity and investment in related transmission system improvements needed to support the additional generation.

Due to milder weather, NMGC expects 2017 earnings to be below prior years. However, customer growth rates are expected to be higher in 2017 than in 2016, reflecting expectations for housing starts and new connections. For the remainder of 2017, sales growth is expected to be consistent with customer growth and costs will increase from prior years.

In 2017, Emera Florida and New Mexico expects to invest approximately $715 million USD, including allowance for funds used during construction (“AFUDC”), in capital projects compared to $795 million USD in 2016. The 2016 capital expenditures included approximately $135 million USD for the Polk Power Station expansion project and $35 million USD for the Florida utilities’ new customer relationship management and billing system, both of which went into service in January 2017. Capital projects support normal system reliability and growth at the three utilities. In addition, capital projects at Tampa Electric include programs for transmission and distribution system storm hardening, distribution system modernization and automated metering equipment, transmission system reliability requirements and investments in utility scale solar photovoltaic projects. PGS will make investments to expand its system and support customer growth, and continue with replacement of obsolete plastic, cast iron and bare steel pipe. NMGC will undertake a project relocating a portion of the gas pipeline feeding Taos, New Mexico, and will invest in a new customer relationship management and billing system.

NSPI

NSPI is a fully-integrated regulated electric utility. It is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services to customers. NSPI’s earnings are most directly impacted by the range of ROE and capital structure approved by the UARB, the prudent management and approved recovery of operating costs, load demand, weather, the approved recovery of regulatory deferrals and the timing and amount of capital spending.

NSPI anticipates earning within its allowed ROE range in 2017 and expects its earnings and rate base to generally be consistent with prior years.

The future earnings impact of the carbon emission reduction strategy being developed from the Pan-Canadian Framework on Clean Growth and Climate Change is unknown; however, NSPI anticipates that any costs prudently incurred to achieve the legislated reductions will be recoverable from customers under NSPI’s regulatory framework. NSPI continues to work with both the Province of Nova Scotia and the Government of Canada on details of the carbon emission reduction agreements and to advance solutions that are in the best interest of customers.

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In 2017, NSPI expects to invest approximately $400 million, including AFUDC, in capital projects compared to $309 million in 2016. In addition to capital projects to support normal system reliability the increase is primarily driven by increased spending on information technology and transmission projects.

Emera Maine

Emera Maine is a transmission and distribution electric utility in the State of Maine. Emera Maine’s earnings are most directly impacted by the combined impacts of the range of rates of ROE and rate base approved by its regulators, the prudent management and approved recovery of operating costs, sales volumes, and the timing and amount of capital expenditures.

Emera Maine’s 2017 rate base is expected to grow modestly due to ongoing investment in transmission and distribution infrastructure, resulting in growth in earnings.

There are currently four pending complaints filed with the FERC to challenge the ISO-New England (“ISO-NE”) Open Access Transmission Tariff-allowed base ROE. On June 19, 2014, in connection with the first complaint, the FERC set the base ROE at 10.57 per cent and capped the total ROE, including the effect of incentive adders, at 11.74 per cent. On April 14, 2017, the U.S. Court of Appeals for the District of Columbia Circuit vacated this order. No changes in reserves have been made as a result of the Court of Appeals vacating the FERC Order, as the outcome is considered uncertain. There are no further updates since December 31, 2016 for the other pending complaints. For further discussion on the complaints, see note 19 to the condensed consolidated interim financial statements for the quarter ended June 30, 2017.

In 2017, Emera Maine expects to invest approximately $85 million USD (2016 – $69 million USD actual) primarily on transmission and distribution capital projects.

Emera Caribbean

Emera Caribbean includes Emera (Caribbean) Incorporated (“ECI”) and its wholly owned subsidiary BLPC, a vertically integrated utility that is the provider of electricity in Barbados; an 80.4 per cent interest in GBPC, a vertically integrated utility and the sole provider of electricity on Grand Bahama Island; and a 51.9 per cent interest in Domlec, an integrated utility on the island of Dominica. In addition, Emera Caribbean includes a 19.1 per cent equity interest in Lucelec, a vertically integrated regulated electric utility on the island of St. Lucia.

Earnings from Emera Caribbean are most directly impacted by the rates of return on rate base approved by their regulators, capital structure, prudent management and approved recovery of operating costs, sales volumes and the timing and scale of capital expenditures.

Emera Caribbean’s 2017 earnings are expected to be less than prior years, excluding the impact of the Q2 2016 gain recognized on the Self-Insurance Fund regulatory liability. This is the result of expected short-term load decline in GBPC from Hurricane Matthew and higher interest charges in ECI on new debt issued in Q4 2016.

On May 30, 2017, the Minister of Finance in Barbados delivered a new budget. Key measures include an increase in the National Social Responsibility Levy (NSRL) from two per cent to ten per cent and the introduction of a two per cent foreign exchange commission, both effective July 1, 2017. The NSRL is charged on all goods imported into Barbados and on domestically manufactured goods. The impact of these immaterial changes will be incorporated into BLPC’s cost of service.

Emera Caribbean plans to invest approximately $75 million USD in capital programs in 2017 (2016 - $65 million USD). Capital projects in 2017 include investment in energy storage, advanced metering infrastructure (“AMI”) and renewables.

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Emera Energy

Emera Energy includes EES, a wholly owned physical energy marketing and trading business; EEG, a wholly owned portfolio of electricity generation facilities in New England and the Maritime provinces of Canada; and an equity investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

Emera Energy Services

EES, 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 and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 generally providing the greatest opportunity for earnings. Under normal market conditions, the business is generally expected to deliver adjusted net earnings of $15 to $30 million USD, with the opportunity for upside when market conditions present.

Emera Energy Generation

Earnings from EEG’s assets are largely dependent on market conditions, in particular, the relative pricing of electricity and natural gas; and capacity pricing for NEGG. Efficient operations of the fleet to ensure unit availability, cost management, and effective commercial management are key success factors.

Adjusted earnings from Emera Energy’s generating assets in 2017 are expected to be in line with 2016. Higher capacity prices that came into effect in June 2017 and the negative impact on 2016 earnings from the recognition of prior year state fuel taxes are expected to be offset by lower realized spark spreads year-over-year and to a lesser extent, the impact of an unplanned outage at the Bridgeport facility. The unit was taken offline for repair in mid-March 2017 and was returned to service in mid-June 2017.

In 2017, Emera Energy expects to invest approximately $55 million (2016 – $39 million) in capital related to its generating assets in order to further improve reliability and enhance plant output capacity.

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, 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” and costs associated with corporate activities that are not directly allocated to the operations of Emera’s subsidiaries and investments.

Other

Other includes consolidated investments in Brunswick Pipeline, Emera Reinsurance and Emera Utility Services. It also includes non-consolidated investments in NSPML (100 per cent investment), LIL (57.4 per cent investment) and M&NP (12.9 per cent investment). Investments in NSPML, LIL and M&NP are recorded as “Investments subject to significant influence” on Emera’s Condensed Consolidated Balance Sheets.

Corporate and Other’s contribution to consolidated adjusted net income is expected to be lower in 2017, primarily due to the 2016 gains associated with the sale of Emera’s investment in APUC and higher interest costs in 2017 as a result of permanent financing in place for the TECO Energy acquisition. This will be partially offset by higher Operating, maintenance and general (“OM&G”) costs in 2016 related to the TECO Energy acquisition and higher earnings in 2017 from Emera’s investment in ENL’s projects (NSPML and LIL).

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Corporate and Other, excluding ENL, expects to spend approximately $15 million on property, plant and equipment in 2017 (2016 - $7 million).

ENL

Throughout construction of both the Maritime Link Project and LIL, equity earnings in ENL are a result of AFUDC. Therefore, 2017 equity earnings contribution from ENL will be higher than 2016 as a result of Emera’s continued equity contribution while under construction, resulting in higher equity levels, and therefore higher AFUDC earnings.

NSPML

Future earnings contribution from the Maritime Link Project will be affected by the amount and timing of capital expenditures for construction activities and the approved ROE, which will determine the component of costs to be funded by equity. The Maritime Link Project is accounted for in Emera’s financial statements as an equity investment (see note 5 of the Condensed Consolidated Interim Financial Statements). The Company’s earnings through the construction period are derived from AFUDC on Emera’s equity investment of 30 per cent of the project costs to maintain a 70 per cent to 30 per cent debt-to-equity ratio. As Maritime Link construction costs are incurred, Emera will contribute equity and then earn AFUDC on that contribution. Maritime Link forecasted cash equity contributions for 2017 are $165 million, with total equity contributions for the Project estimated to be $450 million.

LIL

Future earnings from the LIL investment are dependent on the amount and timing of additional equity investments and the approved ROE. Emera’s total 2017 cash equity contributions are forecasted to be $55 million, with the Company’s total equity contribution for the project estimated to be approximately $600 million.

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Consolidated Balance Sheets Highlights

Significant changes in the condensed consolidated balance sheets between December 31, 2016 and June 30, 2017 include:

millions of Canadian dollars	Increase (Decrease)		Explanation
Assets
Cash and cash equivalents	$	(187)	Decreased primarily due to additions of property, plant and equipment, increased investment in LIL and NSPML and payment of common dividends. These decreases were partially offset by proceeds of long-term debt at GBPC, changes in short-term debt at Emera Florida and New Mexico, and changes in credit facilities.
Receivables, net		(91)	Decreased mainly due to lower commodity prices at Emera Energy and outages at EEG, seasonal trends of the business at Emera Florida and New Mexico, and the impact of a stronger CAD.
Derivative instruments (current and long-term)		(50)	Decreased primarily due to settlements of derivative instruments at Emera Energy and NSPI, unfavourable commodity hedges at NSPI, and lower natural gas swaps at Emera Florida and New Mexico.
Property, plant and equipment, net of accumulated depreciation		(221)	Decreased due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries and depreciation, partially offset by additions at NSPI and Emera Florida and New Mexico.
Investments subject to significant influence		184	Increased mainly due to investment in NSPML and LIL.
Goodwill		(208)	Decreased due to the effect of stronger CAD on the translation of Emera’s foreign subsidiaries.
Prepayments and other assets (current and long-term)		(64)	Decreased due to amortization of transportation assets, partially offset by new Asset Management Agreements (“AMA”).
Liabilities and Equity
Accounts payable		(279)	Decreased primarily due to timing of payments of project expenditures and accruals, and lower commodity prices at Emera Energy.
Deferred income tax liabilities, net of deferred income tax assets		113	Increased primarily due to tax deductions in excess of accounting depreciation related to property, plant and equipment.
Derivative instruments (current and long-term)		(247)	Decreased due to the reversal of 2016 AMA MTM losses and changes in existing positions on long term natural gas contracts at Emera Energy.
Regulatory liabilities (current and long-term)		(172)	Decrease reflects lower deferred fuel clause at TEC and decreased regulated derivatives at NSPI, partially offset by an increased Fuel Adjustment Mechanism (“FAM”) regulatory liability and deferred income tax regulatory asset at NSPI.
Pension and post-retirement liabilities (current and long-term)		(66)	Decreased due to supplemental executive retirement plan and other post-retirement payments in Emera Florida and New Mexico.
Common stock		93	Increased due to issuance of common stock for the dividend reinvestment program.
Accumulated other comprehensive income		(152)	Decreased due to the effect of stronger CAD on the translation of Emera’s foreign subsidiaries.
Retained earnings		194	Increased due to net income in excess of dividends paid.

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Developments

Appointments

On March 29, 2017, Chris Huskilson provided notice of his intention to retire as Chief Executive Officer (“CEO”) in 2018. Concurrently, Emera’s Board of Directors announced it will appoint Scott Balfour, current Chief Operating Officer and former Chief Financial Officer, as CEO upon Mr. Huskilson’s retirement.

OUTSTANDING COMMON STOCK DATA

Common stock Issued and outstanding:	millions of shares		millions of Canadian dollars
Balance, December 31, 2015		147.21	$	2,157
Conversion of Convertible Debentures		51.99		2,115
Issuance of common stock		7.69		338
Issued for cash under Purchase Plans at market rate		2.51		115
Discount on shares purchased under Dividend Reinvestment Plan		-		(5)
Options exercised under senior management stock option plan		0.62		17
Employee Share Purchase Plan		-		1
Balance, December 31, 2016		210.02	$	4,738
Conversion of Convertible Debentures (1)		0.13		5
Issued for cash under Purchase Plans at market rate		1.97		90
Discount on shares purchased under Dividend Reinvestment Plan		-		(4)
Options exercised under senior management stock option plan		0.04		1
Employee Share Purchase Plan		-		1
Balance, June 30, 2017		212.16	$	4,831

(1) During the six months ended June 30, 2017, 0.13 million common shares of Emera were issued relating to the conversion of the Convertible Debentures. As at June 30, 2017, a total of 52.12 million common shares of the Company were issued, representing conversion into common shares of more than 99.8% of the Convertible Debentures.

As at July 27, 2017 the amount of issued and outstanding common shares was 212.2 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 June 30, 2017 was 212.8 million (2016 – 149.7 million) and for the six months ended June 30, 2017 was 212.2 million (2016 – 149.2 million).

EMERA FLORIDA AND NEW MEXICO

Financial Highlights

All amounts are reported in USD, unless otherwise stated.

For the millions of US dollars (except per share amounts)	Three months ended June 30		Six months ended June 30
	2017		2017
Operating revenues – regulated electric	$	541	$	982
Operating revenues – regulated gas		160		387
Operating revenues – non-regulated		2		6
Total operating revenues		703		1,375
Regulated fuel for generation and purchased power		172		310
Regulated cost of natural gas		56		151
Contribution to consolidated net income – USD	$	77	$	137
Contribution to consolidated net income – CAD		103		182
Contribution to consolidated earnings per common share – CAD	$	0.48	$	0.86
Net income weighted average foreign exchange rate – CAD/USD	$	1.34	$	1.33
EBITDA – USD	$	270	$	510
EBITDA – CAD	$	363	$	680

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Net Income

Emera Florida and New Mexico’s contribution is summarized in the following table:

For the millions of US dollars	Three months ended June 30		Six months ended June 30
	2017		2017
Tampa Electric	$	76	$	119
PGS		10		24
NMGC		-		13
Other (1)		(9)		(19)
Contribution to consolidated net income	$	77	$	137

(1)  Other includes TECO Finance and administration costs.

Included below are comparisons of Emera Florida and New Mexico Q2 2017 quarterly results to the same period in 2016. Prior year data is for comparison purposes only, as the Emera acquisition was completed on July 1, 2016.

Tampa Electric’s net income increased $7 million to $76 million in Q2 2017 compared to $69 million for the same period in 2016 primarily due to higher base revenues related to completion of the Polk Power Station expansion project, warmer spring weather and customer growth. These were offset by increased depreciation and property tax expense, lower AFUDC earnings and income tax adjustments received in 2016, offsetting in Other. Year-to-date, Tampa Electric’s net income of $119 million was unchanged compared to the same period in 2016 due to unfavourable weather impacts on Q1 2017 results offsetting the favourable Q2 2017 results mentioned above.

On June 29, 2017, a tragic accident occurred during work being conducted at Tampa Electric’s Big Bend Power Station Unit Two, resulting in employee and contractor fatalities. Although the financial impact to Tampa Electric has not been fully determined, any such impact is expected to be substantially covered by insurance.

PGS’s net income increased $3 million to $10 million in Q2 2017 compared to $7 million for the same period in 2016 primarily due to higher sales to retail customers and lower depreciation expense as a result of the FPSC-approved 2016 depreciation study. PGS had increased retail therm sales due to customer growth and the strong Florida economy, including increased sales of compressed natural gas to vehicle fleets. Year-to-date, PGS’s net income increased $4 million to $24 million compared to $20 million for the same period in 2016 primarily due to the Q2 2017 explanation above, which were partially offset by unfavourable winter weather impacts on Q1 2017 results.

NMGC’s net income of nil in Q2 2017 was unchanged compared to the same period in 2016. Year-to-date, NMGC’s net income decreased $2 million to $13 million compared to $15 million for the same period in 2016 primarily due to unfavourable weather impacts on Q1 2017 results.

Other net loss decreased $3 million to $9 million in Q2 2017 compared to $12 million for the same period in 2016 due to income tax adjustments in 2016. Year-to-date, other net loss increased $3 million to $19 million compared to $16 million for the same period in 2016 primarily as a result of a Q1 2016 non-recurring $5 million gain from an accounting rule change related to stock-based compensation.

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Operating Revenues – Regulated Electric

Electric revenues increased $43 million to $ 541 million in Q2 2017 compared to $498 million in Q2 2016 primarily due to $30 million of higher base rate revenue related to completion of the Polk Power Station expansion in January 2017 and the pass through of higher fuel costs. Year-to-date, electric revenues increased $60 million to $ 982 million in 2017 compared to $922 million in 2016 primarily due to $50 million of higher base rate revenue related to the Polk Power Station expansion and the pass through of higher fuel costs.

Electric revenues are summarized in the following by customer class:

Electric Revenues millions of US dollars	Three months ended June 30		Six months ended June 30
	2017		2017
Residential	$	255	$	453
Commercial		149		280
Industrial		40		79
Other (1)		97		170
Total	$	541	$	982

(1) Other includes regulatory deferrals related to over-recovery of clause related costs.

Q2 Electric Sales Volumes Gigawatt hours (“GWh”)					YTD Electric Sales Volumes GWh
	2017		2016*			2017		2016*
Residential		2,294		2,241	Residential		4,055		4,155
Commercial		1,636		1,565	Commercial		3,067		2,953
Industrial		505		479	Industrial		1,008		940
Other		416		447	Other		802		848
Total		4,851		4,732	Total		8,932		8,896
*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.					*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.

Operating Revenues – Regulated Gas

Gas revenues increased $8 million to $ 160 million in Q2 2017 compared to $152 million in Q2 2016 primarily due to revenues related to the pass through of higher natural gas commodity costs in New Mexico and customer growth in Florida. Year-to-date, gas revenues increased $3 million to $ 387 million in 2017 compared to $384 million in 2016 primarily due to higher commodity costs and customer growth being partially offset by impacts from unfavourable winter weather in both Florida and New Mexico.

Gas revenues are summarized in the following tables by customer class:

Gas Revenues millions of US dollars	Three months ended June 30		Six months ended June 30
	2017		2016
Residential	$	72	$	200
Commercial		48		115
Industrial		9		17
Other (1)		31		55
Total	$	160	$	387

(1) Other includes regulatory deferrals related to over-recovery of clause related costs.

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Q2 Gas Sales Volumes Therms (millions)					YTD Gas Sales Volumes Therms (millions)
	2017		2016*			2017		2016*
Residential		59		58	Residential		197		214
Commercial		176		172	Commercial		399		412
Industrial		307		306	Industrial		606		619
Other		59		84	Other		99		152
Total		601		620	Total		1,301		1,397
*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.					*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.

Regulated Fuel for Generation, Purchased Power and Cost of Natural Gas

Electric Capacity

Regulated fuel for generation and purchased power increased $6 million to $172 million in Q2 2017 compared to $166 million in Q2 2016 and year-to-date increased $15 million to $310 million in 2017 compared to $295 million in 2016 due to higher natural gas and coal-fired generation offset by less purchased power.

Q2 Production Volumes GWh					YTD Production Volumes GWh
	2017		2016*			2017		2016*
Natural gas (1)		3,489		2,777	Natural gas (1)		5,764		5,419
Coal		1,670		1,499	Coal		3,278		2,486
Oil and petcoke		241		154	Oil and petcoke		536		456
Solar		14		1	Solar		23		2
Purchased power, net (1) (2)		(35)		831	Purchased power (1)		41		1,218
Total production volumes		5,379		5,262	Total production volumes		9,642		9,581
*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.					*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.
(1) Natural gas production was higher and purchased power was lower due to completion of Polk Power Station expansion in January 2017 and expiration of a purchased power contract in December 2016.					(1) Natural gas production was higher and purchased power was lower due to completion of Polk Power Station expansion in January 2017 and expiration of a purchased power contract in December 2016.
(2) Sales for resale exceeded purchased power in Q2 2017.

Q2 Average Fuel Costs/Megawatt Hour (“MWh”) US dollars			YTD Average Fuel Costs/MWh US dollars
	2017			2017
Dollars per MWh	$	32	Dollars per MWh	$	32

Average fuel cost per MWh was $32 for both Q2 2017 and year-to-date 2017 compared to $32 in Q2 2016 and $31 in year-to-date 2016.

Cost of Natural Gas

Regulated cost of natural gas increased $6 million to $56 million in Q2 2017 compared to $50 million in Q2 2016 primarily due higher commodity costs. Year-to-date, regulated cost of natural gas increased $4 million to $151 million in 2017 compared to $147 million in 2016 primarily due to higher commodity costs partially offset by lower sales volumes due to unfavourable winter weather.

Gas sales by type are summarized in the following table:

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Q2 Gas Sales Volumes by Type Therms (millions)					YTD Gas Sales Volumes by Type Therms (millions)
	2017		2016*			2017		2016*
System Supply		130		152	System Supply		339		415
Transportation		471		468	Transportation		962		982
Total		601		620	Total		1,301		1,397
*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.					*2016 data is for comparison purposes only. TECO Energy was acquired on July 1, 2016.

NSPI

Financial Highlights

For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated electric	$	304	$	314	$	700	$	712
Regulated fuel for generation and purchased power (1)		98		100		237		242
Contribution to consolidated net income	$	29	$	28	$	99	$	81
Contribution to consolidated earnings per common share	$	0.14	$	0.19	$	0.47	$	0.54
EBITDA	$	112	$	111	$	269	$	251

(1) Regulated fuel for generation and purchased power includes affiliate transactions and proceeds from the sale of natural gas.

Net Income

Highlights of the net income changes are summarized in the following table:

For the millions of Canadian dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income – 2016	$	28	$	81
Decreased operating revenues - see Operating Revenues - Regulated Electric below		(10)		(12)
Decreased fuel for generation and purchased power - see Regulated Fuel for Generation and Purchased Power below		2		5
Decreased fuel adjustment mechanism expense due to a rebate to customers of prior years’ over recovery of fuel costs partially offset by increased recovery of current year fuel costs		5		11
Decreased OM&G expenses primarily due to higher administrative overhead allocated to capital due to higher capital spending and lower pension expense; year-over-year also due to lower storm and maintenance costs		4		13
Decreased income tax expense primarily due to increased tax deductions in excess of accounting depreciation related to property, plant and equipment; year-over-year decrease partially offset by increased income before provision for income taxes		1		7
Other		(1)		(6)
Contribution to consolidated net income – 2017	$	29	$	99

Operating Revenues – Regulated Electric

Operating revenues decreased $10 million to $304 million in Q2 2017 compared to $314 million in Q2 2016 due to a $15 million one-time refund of 2016 fuel related revenues which was partially offset by a $6 million increase in fuel related electricity pricing.

Year-to-date, operating revenues decreased $12 million to $700 million in 2017 compared to $712 million in 2016. The one-time refund of 2016 fuel related revenues decreased revenues by $36 million, partially offset by a $13 million increase as a result of fuel related electricity pricing effective January 1, 2017 and a $9 million increase in residential sales volume due to colder weather and load growth.

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Electric revenues and sales volumes are summarized in the following tables by customer class:

Q2 Electric Revenues millions of Canadian dollars					YTD Electric Revenues millions of Canadian dollars
	2017		2016			2017		2016
Residential	$	147	$	156	Residential	$	375	$	379
Commercial		92		95	Commercial		195		204
Industrial		48		48	Industrial		94		96
Other		10		9	Other		21		21
Total	$	297	$	308	Total	$	685	$	700
Q2 Electric Sales Volumes GWh					YTD Electric Sales Volumes GWh
	2017		2016			2017		2016
Residential		959		967	Residential		2,470		2,398
Commercial		716		729	Commercial		1,567		1,569
Industrial		613		590	Industrial		1,214		1,168
Other		90		65	Other		186		144
Total		2,378		2,351	Total		5,437		5,279

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power decreased $2 million to $98 million in Q2 2017 compared to $100 million in Q2 2016 due to decreased commodity prices and increased hydro and wind production, partially offset by changes in generation mix and plant performance and increased sales volumes. Year-to-date, regulated fuel for generation and purchased power decreased $5 million to $237 million in 2017 compared to $242 million during the same period in 2016 due to decreased commodity prices, partially offset by increased sales volumes.

NSPI’s FAM regulatory liability balance has increased $33 million from $94 million at December 31, 2016 to $127 million at June 30, 2017 as a result of an over-recovery of current period fuel costs and the application of non-fuel revenues reduced by the refund to customers of prior years’ fuel costs.

22

Q2 Production Volumes GWh					YTD Production Volumes GWh
	2017		2016			2017		2016
Coal		1,024		984	Coal		2,685		2,309
Natural gas		367		300	Natural gas		618		585
Oil and petcoke		227		351	Oil and petcoke		576		855
Purchased power – other		39		94	Purchased power – other		136		189
Total non-renewables		1,657		1,729	Total non-renewables		4,015		3,938
Wind and hydro – renewables		387		312	Wind and hydro – renewables		763		718
Purchased power – Independent Power Producers (“IPP”)		282		260	Purchased power – IPP		652		614
Purchased power – Community Feed-in Tariff program (“COMFIT”)		127		95	Purchased power – COMFIT		272		210
Biomass – renewables		37		36	Biomass – renewables		80		106
Total renewables		833		703	Total renewables		1,767		1,648
Total production volumes		2,490		2,432	Total production volumes		5,782		5,586
Q2 Average Fuel Costs					YTD Average Fuel Costs
	2017		2016			2017		2016
Dollars per MWh produced	$	39	$	41	Dollars per MWh produced	$	41	$	43

Average fuel costs decreased in Q2 2017 and year-to-date primarily due to favourable solid fuel pricing and increased hydro and wind production. Quarter-over-quarter this was partially offset by unfavourable generation mix.

EMERA MAINE

Financial Highlights

All amounts are reported in USD, unless otherwise stated.

For the millions of US dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated electric	$	54	$	51	$	114	$	109
Regulated fuel for generation and purchased power (1)		14		13		29		27
Contribution to consolidated net income – USD	$	9	$	7	$	19	$	14
Contribution to consolidated net income – CAD	$	12	$	10	$	25	$	19
Contribution to consolidated earnings per common share – CAD	$	0.06	$	0.06	$	0.12	$	0.13
Net income weighted average foreign exchange rate – CAD/USD	$	1.34	$	1.29	$	1.33	$	1.33
EBITDA – USD	$	27	$	24	$	57	$	49
EBITDA – CAD	$	37	$	32	$	76	$	65

(1) Regulated fuel for generation and purchased power includes transmission pool expense.

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Net Income

Highlights of the net income changes are summarized in the following table:

For the millions of US dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income – 2016	$	7	$	14
Increased operating revenues - regulated electric (see Operating Revenues - Regulated Electric Section below)		3		5
Decreased OM&G due to increased capitalized construction overheads as a result of higher capital spending and lower storm costs		-		5
Increased income tax expense due to increased income before provision for income taxes		(2)		(4)
Other		1		(1)
Contribution to consolidated net income – 2017	$	9	$	19

Emera Maine’s CAD contribution to consolidated net income increased $2 million to $12 million in Q2 2017 from $10 million in Q2 2016. Year-to-date, increased $6 million to $25 million in 2017 from $19 million during the same period in 2016. The foreign exchange rate had minimal impact for the three months and six months ended June 30, 2017.

Operating Revenues – Regulated Electric

Emera Maine’s operating revenues – regulated include sales of electricity and other services as summarized in the following table:

Q2 Operating Revenues – Regulated Electric millions of US dollars					YTD Operating Revenues – Regulated Electric millions of US dollars
	2017		2016			2017		2016
Electric revenues	$	39	$	37	Electric revenues	$	83	$	79
Transmission pool revenues		13		12	Transmission pool revenues		25		23
Resale of purchased power		2		2	Resale of purchased power		6		7
Operating revenues – regulated electric	$	54	$	51	Operating revenues – regulated electric	$	114	$	109

Electric revenues are summarized in the following tables by customer class:

Q2 Electric Revenues millions of US dollars					YTD Electric Revenues millions of US dollars
	2017		2016			2017		2016
Residential	$	19	$	17	Residential	$	41	$	38
Commercial		16		14	Commercial		31		29
Industrial		2		3	Industrial		6		6
Other (1)		2		3	Other (1)		5		6
Total	$	39	$	37	Total	$	83	$	79

1) Other revenue includes amounts recognized relating to FERC transmission rate refunds and other transmission revenue adjustments.

Electric revenues increased $2 million to $39 million in Q2 2017 compared to $37 million in Q2 2016. Year-to-date, electric revenues increased $4 million to $83 million in 2017 compared to $79 million during the same period in 2016 due to transmission and distribution rate changes and increased sales volumes.

24

Electric sales volume are summarized in the following tables by customer class:

Q2 Electric Sales Volumes GWh					YTD Electric Sales Volumes GWh
	2017		2016			2017		2016
Residential		184		176	Residential		407		394
Commercial		186		183	Commercial		381		381
Industrial		83		85	Industrial		165		166
Other		3		4	Other		7		8
Total		456		448	Total		960		949

Regulated Fuel for Generation and Purchased Power

Emera Maine’s regulated fuel for generation and purchased power increased $1 million to $14 million in Q2 2017 compared to $13 million in Q2 2016. Year-to-date, regulated fuel for generation and purchased power increased $2 million to $29 million in 2017 compared to $27 million during the same period in 2016.

EMERA CARIBBEAN

Financial Highlights

All amounts are reported in USD, unless otherwise stated.

For the millions of US dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated electric	$	84	$	78	$	163	$	149
Regulated fuel for generation and purchased power		36		30		72		57
Contribution to consolidated net income – USD	$	9	$	44	$	14	$	52
Contribution to consolidated net income – CAD	$	11	$	58	$	18	$	68
Contribution to consolidated earnings per common share – CAD	$	0.05	$	0.39	$	0.08	$	0.46
Net income weighted average foreign exchange rate – CAD/USD	$	1.35	$	1.29	$	1.34	$	1.30
EBITDA – USD	$	25	$	67	$	48	$	90
EBITDA – CAD	$	34	$	86	$	64	$	118

Net Income

Highlights of the net income changes are summarized in the following table:

For the millions of US dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income – 2016	$	44	$	52
Increased operating revenues - see Operating Revenues - Regulated Electric below		6		14
Increased regulated fuel for generation - see Regulated Fuel for Generation and Purchased Power below		(6)		(15)
Decreased other income mainly due to a pre-tax gain recognized on the SIF regulatory liability in the prior year		(41)		(41)
Decreased income tax expense primarily due to Q2 2016 pre-tax gain recognized on the BLPC SIF regulatory liability		7		7
Other		(1)		(3)
Contribution to consolidated net income – 2017	$	9	$	14

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Emera Caribbean’s CAD contribution to consolidated net income decreased by $47 million to $11 million in Q2 2017 compared to $58 million in Q2 2016 and year-over-year decreased by $50 million to $18 million in 2017 compared to $68 million during the same period in 2016. The foreign exchange rate had minimal impact for the three and six months ended June 30, 2017.

Operating Revenues – Regulated Electric

Operating revenues increased $6 million to $84 million in Q2 2017 compared to $78 million in Q2 2016 due to an increase in fuel charge as a result of higher fuel prices at BLPC. Year-to-date, operating revenues increased $14 million to $163 million in 2017 compared to $149 million during the same period in 2016 due to an increase in fuel charge as a result of higher fuel prices in 2017 at BLPC, partially offset by lower sales volumes at GBPC due to the continued effect of Hurricane Matthew.

Electric revenues are summarized in the following tables by customer class:

Q2 Electric Revenues millions of US dollars					YTD Electric Revenues millions of US dollars
	2017		2016			2017		2016
Residential	$	28	$	25	Residential	$	53	$	48
Commercial		48		45	Commercial		93		84
Industrial		5		6	Industrial		11		13
Other		2		2	Other		3		3
Total	$	83	$	78	Total	$	160	$	148

Electric sales volumes are summarized in the following tables by customer class:

Q2 Electric Sales Volumes GWh					YTD Electric Sales Volumes GWh
	2017		2016			2017		2016
Residential		118		117	Residential		226		226
Commercial		194		195	Commercial		372		374
Industrial		21		24	Industrial		43		47
Other		4		5	Other		8		11
Total		337		341	Total		649		658

Regulated Fuel for Generation and Purchased Power

Regulated fuel for generation and purchased power increased $6 million to $36 million in Q2 2017 compared to $30 million in Q2 2016 and year-to-date increased $15 million to $72 million in 2017 compared to $57 million during the same period in 2016 primarily due to higher oil prices.

Q2 Production Volumes GWh					YTD Production Volumes GWh
	2017		2016			2017		2016
Oil		354		360	Oil		678		697
Hydro		10		9	Hydro		19		18
Solar		5		-	Solar		10		-
Total		369		369	Total		707		715

Q2 Average Fuel Costs/MWh					YTD Average Fuel Costs/MWh
US dollars	2017		2016		US dollars	2017		2016
Dollars per MWh	$	98	$	83	Dollars per MWh	$	102	$	80

The change in the average fuel costs in Q2 2017 compared to Q2 2016, and year-to-date in 2017 compared to the same periods in 2016 was the result of higher oil prices.

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EMERA ENERGY

Financial Highlights

For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Marketing and trading margin (1)	$	(2)	$	(14)	$	24	$	33
Electricity sales (2)		41		77		155		257
Total operating revenues – non-regulated		39		63		179		290
Non-regulated fuel for generation and purchased power (3)		20		75		107		189
Adjusted contribution to consolidated net income (loss)	$	(11)	$	(29)	$	(1)	$	19
After-tax derivative mark-to-market gain (loss)	$	(17)	$	(34)	$	143	$	11
Contribution to consolidated net income (loss)	$	(28)	$	(63)	$	142	$	30
Adjusted contribution to consolidated earnings per common share – basic	$	(0.05)	$	(0.19)	$	-	$	0.13
Contribution to consolidated earnings per common share – basic	$	(0.13)	$	(0.42)	$	0.67	$	0.20
Adjusted EBITDA	$	1	$	(29)	$	32	$	59

(1) Marketing and trading margin excludes a pre-tax mark-to-market loss of $25 million in Q2 2017 (2016 - $60 million loss) and a gain of $212 million YTD in 2017 (2016 - $12 million gain).

(2) Electricity sales excludes a pre-tax mark-to-market gain of $4 million in Q2 2017 (2016 - $4 million gain) and a loss of $3 million YTD in 2017 (2016 - $4 million loss).

(3) Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market loss of $5 million in Q2 2017 (2016 - $5 million gain) and a loss of $4 million YTD in 2017 (2016 - $8 million gain).

For the millions of Canadian dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income (loss) – 2016	$	(63)	$	30
Increased (decreased) marketing and trading margin quarter-over-quarter and year-over-year – See Marketing and Trading Margin below		12		(9)
Decreased electricity sales quarter-over-quarter mainly due to an unplanned outage at the Bridgeport Facility and a planned outage at Bayside Power. Year-over-year also due to lower hedged power prices and decreased sales volumes at NEGG driven by less favourable market conditions, partially offset by higher electricity prices at Bayside Power		(36)		(102)
Decreased non-regulated fuel for generation and purchased power quarter-over-quarter mainly due to the recognition of prior period state fuel taxes in Q2 2016, an unplanned outage at the Bridgeport Facility and a planned outage at Bayside Power in Q2 2017. Year-over-year also due to lower hedged natural gas prices and decreased volumes at NEGG driven by less favourable market conditions, partially offset by higher natural gas prices at Bayside Power		55		82
Decreased income tax recovery quarter-over-quarter mainly due to increased income before provision for income taxes. Year-over-year decreased income tax expense due to decreased income before provision for income taxes		(9)		11
Increased mark-to-market, net of tax quarter-over-quarter mainly due to changes in existing positions on long-term natural gas contracts. Year-over-year also due to the reversal of 2016 mark-to-market losses		17		132
Other		(4)		(2)
Contribution to consolidated net income (loss) – 2017	$	(28)	$	142

A portion of earnings are exposed to foreign exchange fluctuations, thereby affecting adjusted CAD contribution to net earnings. The impact of the change in USD/CAD exchange rate quarter-over-quarter decreased earnings in CAD by $1 million in Q2 2017 compared to Q2 2016. Year-to-date in 2017 the impact of the change in USD/CAD exchange rate decreased CAD earnings by $13 million compared to the same period in 2016.

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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 June 30				Six months ended June 30
	2017		2016		2017		2016
Marketing and trading margin	$	(2)	$	(14)	$	24	$	33
OM&G		5		2		10		12
Other income (expenses), net		-		-		-		(4)
Adjusted EBITDA		$    (7)		$    (16)	$	14	$	17

Marketing and Trading Margin

Marketing and trading margin increased $12 million to $(2) million in Q2 2017 compared to $(14) million in Q2 2016. Overall market conditions were comparable quarter-over-quarter. The increase is mainly due to lower short-term fixed cost commitments for transportation, more valuable transportation positions in 2017 that provided optimization opportunities, and growth in the volume of business.

Year-to-date, marketing and trading margin decreased $9 million to $24 million in 2017 compared to $33 million during the same period in 2016. This decrease is mainly due to less favourable transportation capacity hedges in Q1 2017 and increased gas transportation infrastructure in the northeast United States which reduced volatility, partially offset by the Q2 2017 factors noted above.

Emera Energy Generation

Adjusted EBITDA

Adjusted EBITDA for Emera Energy Generation is summarized in the following table:

For the millions of Canadian dollars	Three months ended June 30
	New England					Maritime Canada						Total
	2017		2016			2017			2016			2017		2016
Energy sales	$	23	$	50		$	1		$	14		$	24	$	64
Capacity and other		16		13			1			-			17		13
Electricity revenue	$	39	$	63		$	2		$	14		$	41	$	77
Non-regulated fuel for generation and purchased power		18		59			2			13			20		72
Provincial, state and municipal taxes		2		1			-			-			2		1
OM&G		11		11			5			6			16		17
Adjusted EBITDA	$	8	$	(8	)	$	(5	)	$	(5	)	$	3	$	(13	)

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For the millions of Canadian dollars	Six months ended June 30
	New England				Maritime Canada				Total
	2017		2016		2017		2016		2017		2016
Energy sales	$	88	$	189	$	39	$	42	$	127	$	231
Capacity and other		27		26		1		-		28		26
Electricity revenue	$	115	$	215	$	40	$	42	$	155	$	257
Non-regulated fuel for generation and purchased power		76		153		30		31		106		184
Provincial, state and municipal taxes		5		2		-		-		5		2
OM&G		20		20		10		12		30		32
Other income (expenses), net		-		-		-		1		-		1
Adjusted EBITDA	$	14	$	40	$	-	$	-	$	14	$	40

Adjusted EBITDA increased $16 million to $3 million in Q2 2017 from $(13) million in Q2 2016 mainly due to the recognition in Q2 2016 of $20 million in prior period state fuel taxes at NEGG. Absent this, adjusted EBITDA would have decreased $4 million in Q2 2017 compared to Q2 2016. This is due to the impact of an unplanned outage at the Bridgeport Facility which extended from mid-March 2017 to mid-June 2017, partially offset by higher capacity prices that came into effect for NEGG in June 2017.

Year-to-date, Adjusted EBITDA decreased $26 million to $14 million in 2017 from $40 million for the same period in 2016. Absent the $20 million in prior period state fuel taxes at NEGG, adjusted EBITDA would have decreased $46 million in 2017 compared to 2016. This is mainly due to lower realized energy margins in NEGG in Q1 2017, reflecting more favourable short-term energy hedges in 2016 compared to 2017 and lower energy sales volumes due to the unplanned outage at the Bridgeport Facility and less favourable market conditions.

Operating Statistics

For the	Three months ended June 30
	Sales Volumes (GWh) (1)				Plant Availability (%) (2)				Net Capacity Factor (%) (3)
	2017		2016		2017		2016		2017		2016
New England		461		1,318		53.1%		91.9%		18.9%		55.4%
Maritime Canada		26		431		27.8%		86.4%		3.7%		63.2%
Total		487		1,749		47.5%		90.6%		15.5%		57.1%
For the	Six months ended June 30
	Sales Volumes (GWh) (1)				Plant Availability (%) (2)				Net Capacity Factor (%) (3)
	2017		2016		2017		2016		2017		2016
New England		1,396		2,621		70.3%		94.0%		28.8%		55.1%
Maritime Canada		581		949		63.5%		91.1%		41.8%		69.6%
Total		1,977		3,570		68.8%		93.4%		31.7%		58.3%

(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.

NEGG sales volumes, plant availability and net capacity factor were lower quarter-over-quarter mainly due to the impact of an unplanned outage at the Bridgeport Facility from mid-March 2017 to mid-June 2017. Year-to-date decrease also due to less favourable market conditions in Q1 2017 reducing opportunities for economic dispatch.

The Maritime Canada Facilities’ sales volumes, plant availability and net capacity factor were lower quarter-over-quarter and year-to-date due to a planned outage at the Bayside Facility in Q2 2017.

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CORPORATE AND OTHER

Financial Highlights

For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated gas		12		12		25		25
Non-regulated operating revenue		19		8		35		16
Total operating revenue	$	31	$	20	$	60	$	41
Intercompany revenue (1)		9		9		19		19
Income (loss) from equity investments		23		24		45		48
Interest expense, net (2)		73		71		146		110
Adjusted contribution to consolidated net income (loss)	$	(27)	$	171	$	(54)	$	171
After-tax mark-to-market gain (loss)		1		4		1		(117)
Contribution to consolidated net income (loss)	$	(26)	$	175	$	(53)	$	54
Adjusted contribution to consolidated earnings per common share – basic		(0.13)		1.14		(0.25)		1.15
Contribution to consolidated earnings per common share – basic	$	(0.12)	$	1.17	$	(0.25)	$	0.36
Adjusted EBITDA	$	28	$	261	$	59	$	297

(1) Intercompany revenue consists of interest from Brunswick Pipeline, M&NP and EEG.

(2) Interest expense, net excludes a pre-tax mark-to-market gain of $1 million in Q2 and year-to-date 2017 (2016 – nil).

Net Income

Highlights of the income changes are summarized in the following table:

For the millions of Canadian dollars	Three months ended June 30		Six months ended June 30
Contribution to consolidated net income – 2016	$	175	$	54
Increased non-regulated operating revenue - see Operating Revenues below		11		19
Income from equity investments – see Income from Equity Investments below		(1)		(3)
2016 gain on sale of APUC common shares, pre-tax		(172)		(172)
2016 gain on conversion of APUC subscription receipts and dividend equivalents into APUC common shares, pre-tax		(63)		(63)
Increased interest expense - see Interest Expense below		(2)		(36)
Increased income tax recovery primarily due to decreased income before provision for income taxes, partially offset by the non-taxable portion of gains on APUC transactions in Q2 2016		36		48
After-tax mark-to-market loss in 2016 related to the adjustments from forward contracts economically hedging the debenture offering and the translation of the USD cash balance		(4)		117
Other		(6)		(17)
Contribution to consolidated net income (loss) – 2017	$	(26)	$	(53)

Operating Revenues

Operating revenues increased $11 million to $31 million in Q2 2017 compared to $20 million in Q2 2016. Year-to-date, operating revenues increased $19 million to $60 million in 2017 compared to $41 million in the same period in 2016 due to increased project activity in Emera Utility Services.

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Income from Equity Investments

Income from equity investments are summarized in the following table:

For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
LIL	$	9	$	6	$	18	$	10
NSPML		9		4		16		9
M&NP		5		5		11		11
APUC - sold in 2016		-		9		-		18
Income from equity investments	$	23	$	24	$	45	$	48

Income from equity investments decreased $1 million to $23 million in Q2 2017 compared to $24 million in Q2 2016. Year-to-date, income from equity investments decreased $3 million to $45 million in 2017 compared to $48 million during the same period in 2016. These variances are a result of the sale of APUC in 2016, partially offset by higher earnings from the increased investment in NSPML and LIL.

Interest Expense

Interest expense increased $2 million to $73 million Q2 2017 compared to $71 million in Q2 2016 as a result of the interest on the permanent USD denominated debt for the acquisition offset by the interest on the convertible debentures related to the TECO Energy acquisition in 2016. Year-to-date, interest expense increased $36 million to $146 million in 2017 compared to $110 million for the same period in 2016 primarily due to financing related to the TECO Energy acquisition.

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 sufficient 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 condensed consolidated statements of cash flows between the six months ended June 30, 2017 and 2016 include:

millions of Canadian dollars	2017		2016		$ Change
Cash and cash equivalents, beginning of period	$	404	$	1,073	$	(669)
Provided by (used in):
Operating cash flow before change in working capital		703		325		378
Change in working capital		(222)		151		(373)
Operating activities		481		476		5
Investing activities		(888)		178		(1,066)
Financing activities		227		5,810		(5,583)
Effect of exchange rate changes on cash and cash equivalents		(7)		(78)		71
Cash and cash equivalents, end of period	$	217	$	7,459	$	(7,242)

31

Cash Flow from Operating Activities

Refer to the Consolidated Income Statement and Operating Cash Flow Highlights earlier in the document for details.

Cash Flow Used In Investing Activities

Net cash used in investing activities increased $1,066 million to $888 million for the six months ended June 30, 2017 compared to cash provided by investing activities of $178 million in Q2 2016 due to an increase in capital spending and proceeds from the sale of APUC common shares in 2016.

Capital expenditures for the six months ended June 30, 2017, including AFUDC and net of proceeds from disposal of assets, were $728 million compared to $235 million during the same period in 2016. The increase was a result of the acquisition of TECO Energy and additional capital spending in NSPI, Emera Maine and Emera Energy, offset by a reduction in capital spend in Emera Caribbean. Details of the capital spend are shown below:

• $434 million at Emera Florida and New Mexico;

• $169 million at NSPI (2016 – $143 million);

• $54 million at Emera Maine (2016 – $32 million);

• $23 million at Emera Caribbean (2016 – $45 million);

• $37 million at Emera Energy (2016 – $12 million);

• $11 million in Corporate and Other (2016 – $3 million)

Cash Flow from Financing Activities

Net cash provided by financing activities decreased $5,583 million to $227 million for the six months ended June 30, 2017 compared to $5,810 million for the same period in 2016. The decrease was due to proceeds of the long-term debt issuance related to the acquisition of TECO Energy in 2016. This was partially offset by increased 2017 borrowings under committed credit facilities.

32

Contractual Obligations

As at June 30, 2017, contractual commitments for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2017		2018		2019		2020		2021		Thereafter		Total
Long-term debt	$	448	$	767	$	1,380	$	723	$	1,961	$	9,400	$	14,679
Interest payment obligations (1)		340		631		602		555		505		6,369		9,002
Purchased power (2)		136		230		222		210		206		2,338		3,342
Transportation (3)		265		406		300		273		190		1,571		3,005
Pension and post-retirement obligations (4)		66		47		48		49		51		863		1,124
Fuel and gas supply		344		230		120		47		39		-		780
Long-term service agreements (5)		61		64		63		30		40		213		471
Asset retirement obligations		2		2		1		2		43		390		440
Equity investment commitments (6)		220		25		-		190		-		-		435
Leases and other (7)		50		20		12		12		6		66		166
Capital projects		95		17		-		-		-		-		112
Demand side management		19		45		11		-		-		-		75
Long-term payable		2		4		5		5		5		10		31
Convertible debentures		-		-		-		-		-		4		4
	$      2,048		$      2,488		$      2,764		$      2,096		$      3,046		$      21,224		$      33,666

(1) 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 June 30, 2017, including any expected required payment under associated swap agreements.

(2) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.

(3) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines.

(4) Defined benefit funding contractual obligations were determined based on funding requirements and assuming pension accruals cease as at December 31, 2016. Credited service and earnings are assumed to be crystallized as at December 31, 2016. The Company’s contractual obligations for post-retirement (non-pension) benefits assumes members must be age 55 or over (50 for TECO Energy) as at December 31, 2016 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.

(5) 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.

(6) Emera has a commitment in connection with the Federal Loan Guarantee 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.

(7) Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 35 years. The timing and amounts payable to NSPML and NSPI’s future rate recoveries are dependent upon the in-service date of the Maritime Link, UARB decisions and the final costing of the Maritime Link after construction is complete. This transaction will be accounted for as a related party transaction in accordance with the Company’s accounting policies. The Company accounts for NSPML as an equity investment.

Debt Management

In addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $2.7 billion committed syndicated revolving bank lines of credit in either CAD or USD per the table below.

33

millions of dollars	Maturity	Revolving Credit Facilities		Utilized		Undrawn and         Available
Emera – Operating and acquisition credit facility	June 2020 – Revolver	$	700	$	225	$	475
Emera Florida and New Mexico - in USD - credit facilities	March 2018 -March 2022		1,300		803		497
NSPI – Operating credit facility	October 2021 – Revolver		600		320		280
Emera Maine – in USD – Operating credit facility	September 2019 – Revolver		80		41		39
Other – in USD – Operating credit facilities	Various		32		-		32

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 June 30, 2017.

NSPI

On June 28, 2017, NSPI amended its operating credit facility to extend the maturity from October 2020 to October 2021 and the debt to capitalization ratio from 0.65:1 to 0.70:1. All other terms of the agreement are the same.

Emera Florida and New Mexico

On March 8, 2017, TECO Energy/Finance extended the maturity date of its $400 million USD term bank credit facility from March 14, 2017 to March 8, 2018 with no significant change in commercial terms from the prior agreement.

On March 22, 2017, TECO Energy/Finance extended the maturity date of its $300 million USD bank credit facility from December 17, 2018 to March 22, 2022 with no significant change in commercial terms from the prior agreement.

On March 22, 2017, TEC extended the maturity date of its $325 million USD bank credit facility from December 17, 2018 to March 22, 2022, and reduced the existing letter of credit facility to $50 million USD from $200 million USD. There were no other significant changes in commercial terms from the prior agreement.

On March 22, 2017, NMGC extended the maturity date of its $125 USD million bank credit facility from December 17, 2018 to March 22, 2022 with no significant change in commercial terms from the prior agreement.

GBPC

On March 21, 2017, GBPC amended its loan agreement with the addition of two non-revolving term credit facilities. There were no significant changes in commercial terms from the prior agreement. The combined total of these new facilities is for up to $45 million USD. At June 30, 2017 a total of $30 million USD was drawn against the new facilities.

Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the Company’s 2016 annual MD&A, with the exception of the items noted below.

34

TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian is obligated to file, in respect of each mining permit, applications in connection with the change of control with the appropriate governmental entities. As each application is approved, Cambrian is required to post a bond or other appropriate collateral in order to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. As at June 30, 2017, TECO Energy had remaining indemnified bonds totaling $9 million ($7 million USD).

The amounts outlined above represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies.

The Company is working with Cambrian on the process to replace the remaining bonds. Pursuant to the securities purchase agreement, 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.

Emera has a standby letter of credit in the amount of $21 million to guarantee the performance of the obligations of the EUS-Rokstad joint venture. The letter of credit expires in August 2017. EUS-Rokstad is a joint venture between EUS and Rokstad Power, formed for the purpose of constructing the high voltage direct current components of NSPML’s transmission line. Rokstad Power has issued a separate letter of credit to Emera for their portion of the work to be performed under the contract. EUS and Rokstad Power are jointly and severally liable for completion of the project.

Emera has standby letters of credit in the amount of $21 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.

Emera Inc. on behalf of NSPI has a standby letter of credit to secure obligations under an unfunded pension plan. The letter of credit expires in June 2018 and is renewed annually. The amount committed as at June 30, 2017 was $51 million.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

There have been no material changes in Emera’s risk management profile and practices from those disclosed in the Company’s 2016 annual MD&A.

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	June 30 2017		December 31 2016
Derivative instrument assets (current and other assets)	$	6	$	10
Derivative instrument liabilities (current and long-term liabilities)		(15)		(27)
Net derivative instrument assets (liabilities)	$	(9)	$	(17)

35

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	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues – regulated	$	(3)	$	(2)	$	(6)	$	(5)
Non-regulated fuel for generation and purchased power		(1)		(1)		3		3
Income from equity investments		-		(1)		-		(1)
Effective net gains (losses)	$	(4)	$	(4)	$	(3)	$	(3)

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	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Non-regulated fuel for generation and purchased power	$	-	$	1	$	-	$	-
Ineffective gains (losses)	$	-	$	1	$	-	$	-

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	June 30 2017		December 31 2016
Derivative instrument assets (current and other assets)	$	150	$	229
Regulatory assets (current and other assets)		19		11
Derivative instrument liabilities (current and long-term liabilities)		(20)		(12)
Regulatory liabilities (current and long-term liabilities)		(150)		(231)
Net asset (liability)	$	(1)	$	(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	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Regulated fuel for generation and purchased power (1)	$	6	$	(1)	$	13	$	2
Net gains (losses)	$	6	$	(1)	$	13	$	2

(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 or property plant and equipment will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed.

36

Held-for-trading (“HFT”) 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	June 30 2017		December 31 2016
Derivative instruments assets (current and other assets)	$	70	$	37
Derivative instruments liabilities (current and long-term liabilities)		(193)		(434)
Net derivative instrument assets (liabilities)	$	(123)	$	(397)

HFT 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	Three months ended June 30				Six months ended June 30
		2017		2016		2017		2016
Operating revenue - non-regulated	$	59	$	35	$	383	$	257
Non-regulated fuel for purchased power		5		5		7		4
Net gains (losses)	$	64	$	40	$	390	$	261

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	June 30 2017		December 31 2016
Derivative instrument liabilities (current and long-term liabilities)	$	-	$	(2)
Net derivative instrument assets (liabilities)	$	-	$	(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	Three months ended June 30				Six months ended June 30
		2017		2016		2017		2016
Interest expense, net	$	1	$	-	$	1	$	-
Other income (expense)		-		(6)		-		(101)
Total gains (losses)	$	1	$	(6)	$	1	$	(101)

DISCLOSURE AND INTERNAL CONTROLS

Management is responsible for establishing and maintaining adequate disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”). The Company’s internal control framework is based on the criteria published in the Internal Control - Integrated Framework (2013), a report issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Management, including the Chief Executive Officer and Chief Financial Officer, evaluated the design of the Company’s DC&P and ICFR as at June 30, 2017, to provide reasonable assurance regarding the reliability of financial reporting in accordance with USGAAP.

Change in ICFR

37

During the first quarter of 2017, TEC implemented an SAP developed Customer Relationship Management and Billing System as a process improvement initiative which replaced their legacy customer information system. TEC has made appropriate changes to internal controls and procedures, as is expected with a major system implementation.

Except as described above, there were no changes in the Company’s ICFR during the six months ended June 30, 2017, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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 and long-lived assets impairment assessments, income taxes, asset retirement obligations, capitalized overhead and valuation of financial instruments. Actual results may differ significantly from these estimates. There was no material change in the nature of the Company’s critical accounting estimates from those disclosed in the Company’s 2016 annual MD&A.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

Future Accounting Pronouncements

The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (the “FASB”). The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in the 2016 audited consolidated financial statements, with the exception of the items noted below.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, codified as Accounting Standards Codification (“ASC”) Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect scope improvements and practical expedients. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption. The Company will adopt this guidance effective January 1, 2018.

The Company implemented a revenue recognition project plan in 2016. In Q1 2017, the Company concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. In Q2 2017, the Company completed an analysis of material regulated revenue streams and collectability risk and has concluded that there will be no material changes on adoption of this standard. The Company will adopt the standard using the modified retrospective approach. Emera continues to evaluate the impact of this standard on unregulated revenue streams and financial statement disclosure requirements. The Company continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force for developments.

38

Recognition and Measurement of Financial Assets and Financial Liabilities

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. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.

The standard requires investments in equity securities, except those accounted for under the equity method of accounting or those that result in consolidation, to be measured at fair value. The Company will elect to measure equity securities that do not have a readily determinable fair value, at cost minus impairment (if any), plus or minus observable price changes resulting from transactions for the identical or a similar investment of the same issuer. The standard eliminates the available-for-sale classification for equity investments that recognized changes in the fair value as a component of other comprehensive income, resulting in all changes in fair value being recognized in net income. The increase in volatility of Other income (expense), net as a result of the remeasurement of equity investments is not expected to be significant. The Company will adopt this guidance effective January 1, 2018 with a cumulative-effect adjustment to the Consolidated Balance Sheet.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component will be eligible for capitalization under this guidance. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization. The Company is currently evaluating the impact of the adoption of this standard on the consolidated financial statements, including the eligibility for capitalization of the other components of net benefit cost given the application of ASC 980 Regulated Operations. The Company will adopt this guidance effective January 1, 2018.

39

SUMMARY OF QUARTERLY RESULTS

For the quarter ended millions of Canadian dollars (except per share amounts)	Q2 2017		Q1 2017		Q4 2016		Q3 2016			Q2 2016		Q1 2016		Q4 2015		Q3 2015
Operating revenues	$	1,469	$	1,857	$	1,513	$	1,387		$	499	$	877	$	732	$	642
Net income (loss) attributable to common shareholders		101		312		70		(95	)		208		44		192		35
Adjusted net income attributable to common shareholders		117		152		104		14			238		120		87		23
Earnings per common share – basic		0.47		1.48		0.34		(0.52	)		1.39		0.30		1.31		0.24
Earnings per common share – diluted		0.47		1.47		0.34		(0.52	)		1.38		0.30		1.30		0.24
Adjusted earnings per common share – basic		0.55		0.72		0.51		0.08			1.59		0.81		0.59		0.16

Quarterly operating revenues and net income attributable to common shareholders are affected by seasonality. Historically, the first quarter has generally been the strongest because a significant portion of the Company’s operations are in northeastern North America, where winter is the peak electricity usage season. However, with the addition of Emera Florida and New Mexico, the third quarter will provide stronger earnings contributions due to summer being the heaviest electric consumption season in Florida. 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 also be affected by items outlined in the Significant Items Affecting Earnings section and mark-to-market adjustments.

40

EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Unaudited Condensed Consolidated

Interim Financial Statements

June 30, 2017 and 2016

1

Emera Incorporated

Condensed Consolidated Statements of Income (Unaudited)

For the millions of Canadian dollars (except per share amounts)	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Operating revenues
Regulated electric	$	1,217	$	480	$	2,379	$	1,054
Regulated gas		227		12		540		25
Non-regulated		25		7		407		297
Total operating revenues		1,469		499		3,326		1,376
Operating expenses
Regulated fuel for generation and purchased power		397		156		786		354
Regulated cost of natural gas		75		-		201		-
Regulated fuel adjustment mechanism and fixed cost deferrals		19		24		30		42
Non-regulated fuel for generation and purchased power		25		69		109		179
Non-regulated direct costs		10		-		20		2
Operating, maintenance and general		348		147		706		323
Provincial, state and municipal taxes		84		17		165		33
Depreciation and amortization		220		85		437		172
Total operating expenses		1,178		498		2,454		1,105
Income from operations		291		1		872		271
Income from equity investments (note 5)		30		30		56		56
Other income (expenses), net (note 6)		1		294		3		155
Interest expense, net (note 7)		178		107		353		182
Income before provision for income taxes		144		218		578		300
Income tax expense (note 8)		34		1		146		28
Net income		110		217		432		272
Non-controlling interest in subsidiaries		2		2		5		6
Net income of Emera Incorporated		108		215		427		266
Preferred stock dividends		7		7		14		14
Net income attributable to common shareholders	$	101	$	208	$	413	$	252
Weighted average shares of common stock outstanding (in millions) (note 10)
Basic		212.8		149.7		212.2		149.2
Diluted		213.5		150.3		212.8		149.8
Earnings per common share (note 10)
Basic	$	0.47	$	1.39	$	1.95	$	1.69
Diluted	$	0.47	$	1.38	$	1.94	$	1.68
Dividends per common share declared	$	0.5225	$	0.4750	$	1.0450	$	0.9500

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 June 30						Six months ended June 30
	2017			2016			2017			2016
Net income	$	110		$	217		$	432		$	272
Other comprehensive income (loss), net of tax
Foreign currency translation adjustment (1)		(184	)		(18	)		(232	)		(179	)
Unrealized gains (losses) on net investment hedges (2) (3)		39			-			52			-
Cash flow hedges
Net derivative gains (losses) (4)		3			3			5			17
Less: reclassification adjustment for losses (gains) included in income (5)		4			3			4			4
Net effects of cash flow hedges		7			6			9			21
Unrealized gains (losses) on available-for-sale investment
Unrealized gain (loss) arising during the period		1			-			4			-
Less: reclassification adjustment for (gains) losses recognized in income		-			-			(1	)		-
Net unrealized holding gains (losses)		1			-			3			-
Net change in unrecognized pension and post-retirement benefit obligation (6)		5			9			13			17
Other equity method reclassification adjustment (7)		-			(46	)		-			(46	)
Other comprehensive income (loss) (8)		(132	)		(49	)		(155	)		(187	)
Comprehensive income (loss)		(22	)		168			277			85
Comprehensive income (loss) attributable to non-controlling interest		-			3			2			-
Comprehensive income (loss) of Emera Incorporated	$	(22	)	$	165		$	275		$	85

The accompanying notes are an integral part of these condensed consolidated financial statements.

1) Net of tax recovery of nil (2016 – $5 million tax recovery) for the three months ended June 30, 2017 and tax recovery of nil (2016 – $3 million tax recovery) for the six months ended June 30, 2017.

2) The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations.

3) Net of tax expense of $1 million (2016 – nil tax expense) for the three months ended June 30, 2017 and tax expense of $1 million (2016 – nil tax expense) for the six months ended June 30, 2017.

4) Net of tax expense of nil (2016 – $1 million tax expense) for the three months ended June 30, 2017 and tax expense of nil (2016 – $1 million tax expense) for the six months ended June 30, 2017.

5) Net of tax expense of nil (2016 – $1 million tax expense) for the three months ended June 30, 2017 and tax expense of $1 million (2016 – $1 million tax recovery) for the six months ended June 30, 2017.

6) Net of tax expense of $2 million (2016 – nil tax expense) for the three months ended June 30, 2017 and tax expense of $2 million (2016 – nil) for the six months ended June 30, 2017.

7) Net of tax expense of nil (2016 – $9 million tax recovery) for the three months ended June 30, 2017 and tax recovery of nil (2016 – $9 million tax recovery) for the six months ended June 30, 2017.

8) Net of tax expense of $3 million (2016 – $12 million tax recovery) for the three months ended June 30, 2017 and tax expense of $4 million (2016 – $12 million tax recovery) for the six months ended June 30, 2017.

3

Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited)

As at millions of Canadian dollars	June 30 2017		December 31 2016
Assets
Current assets
Cash and cash equivalents	$	217	$	404
Restricted cash		82		87
Receivables, net		923		1,014
Income taxes receivable		40		33
Inventory		469		472
Derivative instruments (notes 12 and 13)		121		145
Regulatory assets (note 14)		79		80
Prepayments and other current assets		228		276
Total current assets		2,159		2,511
Property, plant and equipment, net of accumulated depreciation
and amortization of $7,843 and $7,787, respectively		17,069		17,290
Other assets
Income taxes receivable		48		48
Deferred income taxes		87		125
Derivative instruments (notes 12 and 13)		105		131
Pension and post-retirement assets (note 16)		8		9
Regulatory assets (note 14)		1,279		1,242
Net investment in direct financing lease		485		488
Investments subject to significant influence (note 5)		1,131		947
Investment securities		55		48
Goodwill		6,005		6,213
Other long-term assets		153		169
Total other assets		9,356		9,420
Total assets	$	28,584	$	29,221

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Emera Incorporated

Condensed Consolidated Balance Sheets (Unaudited) – Continued

As at millions of Canadian dollars	June 30 2017			December 31 2016
Liabilities and Equity
Current liabilities
Short-term debt (note 17)	$	1,039		$	961
Current portion of long-term debt		1,175			476
Accounts payable		963			1,242
Income taxes payable		3			19
Derivative instruments (notes 12 and 13)		129			325
Regulatory liabilities (note 14)		217			362
Pension and post-retirement liabilities (note 16)		25			58
Other current liabilities		254			281
Total current liabilities		3,805			3,724
Long-term liabilities
Long-term debt (note 18)		13,442			14,268
Deferred income taxes		1,747			1,672
Convertible debentures		4			8
Derivative instruments (notes 12 and 13)		99			150
Regulatory liabilities (note 14)		1,250			1,277
Asset retirement obligations		168			170
Pension and post-retirement liabilities (note 16)		636			669
Other long-term liabilities		482			467
Total long-term liabilities		17,828			18,681
Commitments and contingencies (note 19)
Equity
Common stock (note 9)		4,831			4,738
Cumulative preferred stock		709			709
Contributed surplus		76			75
Accumulated other comprehensive income (loss) (note 11)		(46	)		106
Retained earnings		1,270			1,076
Total Emera Incorporated equity		6,840			6,704
Non-controlling interest in subsidiaries		111			112
Total equity		6,951			6,816
Total liabilities and equity	$	28,584		$	29,221

The accompanying notes are an integral part of these condensed 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

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Emera Incorporated

Condensed Consolidated Statements of Cash Flows (Unaudited)

For the millions of Canadian dollars	Six months ended June 30
	2017		2016
Operating activities
Net income	$	432	$	272
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		431		179
Income from equity investments, net of dividends		(39)		(34)
Allowance for equity funds used during construction		(5)		(2)
Deferred income taxes, net		117		5
Net change in pension and post-retirement liabilities		(8)		14
Regulated fuel adjustment mechanism and fixed cost deferrals		34		42
Net change in fair value of derivative instruments		(267)		(27)
Net change in regulatory assets and liabilities		(73)		(4)
Net change in capitalized transportation capacity		61		118
Foreign exchange loss (gain)		-		47
Gain on APUC sale of common shares and conversion of subscription receipts		-		(235)
Other operating activities, net		20		(50)
Changes in non-cash working capital (note 20)		(222)		151
Net cash provided by operating activities		481		476
Investing activities
Additions to property, plant and equipment		(723)		(231)
Net purchase of investments subject to significant influence, inclusive of acquisition costs		(160)		(115)
Net proceeds on sale of investment subject to significant influence		-		525
Other investing activities		(5)		(1)
Net cash (used in) provided by investing activities		(888)		178
Financing activities
Change in short-term debt, net		113		(14)
Proceeds from long-term debt, net of issuance costs		39		6,236
Retirement of long-term debt		(14)		(8)
Net borrowings (repayments) under committed credit facilities		243		(295)
Issuance of common stock, net of issuance costs		5		18
Dividends on common stock		(138)		(97)
Dividends on preferred stock		(14)		(14)
Dividends paid by subsidiaries to non-controlling interest		(2)		(2)
Other financing activities		(5)		(14)
Net cash provided by financing activities		227		5,810
Effect of exchange rate changes on cash and cash equivalents		(7)		(78)
Net (decrease) increase in cash and cash equivalents		(187)		6,386
Cash and cash equivalents, beginning of period		404		1,073
Cash and cash equivalents, end of period	$	217	$	7,459
Cash and cash equivalents consists of:
Cash	$	213	$	4,717
Short-term investments		4		2,742
Cash and cash equivalents	$	217	$	7,459

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited)

millions of Canadian dollars	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss) (“AOCI”)			Retained Earnings			Emera Total Equity			Non-Controlling Interest			Total Equity
For the six months ended June 30, 2017
Balance, December 31, 2016	$	4,738	$	709	$	75	$	106		$	1,076		$	6,704		$	112		$	6,816
Net income of Emera Incorporated		-		-		-		-			427			427			5			432
Other comprehensive income (loss), net of tax expense of $4 million		-		-		-		(152	)		-			(152	)		(3	)		(155	)
Issuance of common stock, net of after-tax issuance costs		5		-		-		-			-			5			-			5
Dividends declared on preferred stock (Series A: $0.31940/share, Series B: $0.28870/share, Series C: $0.51250/share, Series E: $0.56250/share and Series F: $0.53125/share)		-		-		-		-			(14	)		(14	)		-			(14	)
Dividends declared on common stock ($1.0450/share)		-		-		-		-			(220	)		(220	)		-			(220	)
Common stock issued under purchase plan		86		-		-		-			-			86			-			86
Stock-based compensation		1		-		1		-			-			2			-			2
Other		1		-		-		-			1			2			(3	)		(1	)
Balance, June 30, 2017	$	4,831	$	709	$	76	$	(46	)	$	1,270		$	6,840		$	111		$	6,951

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Emera Incorporated

Condensed Consolidated Statements of Changes in Equity (Unaudited) – Continued

millions of Canadian dollars	Common Stock		Preferred Stock		Contributed Surplus			Accumulated Other Comprehensive Income (“AOCI”)			Retained Earnings			Emera Total Equity			Non-Controlling Interest			Total Equity
For the six months ended June 30, 2016
Balance, December 31, 2015	$	2,157	$	709	$	29		$	137		$	1,168		$	4,200		$	134		$	4,334
Net income of Emera Incorporated		-		-		-			-			266			266			6			272
Other comprehensive income (loss), net of tax recovery of $12M		-		-		-			(181	)		-			(181	)		(6	)		(187	)
Dividends declared on preferred stock (Series A: $0.31940/share, Series B: $0.28180/share, Series C: $0.51250/share, Series E: $0.56250/share and Series F: $0.53125/share)		-		-		-			-			(14	)		(14	)		-			(14	)
Dividends declared on common stock ($0.9500/share)		-		-		-			-			(140	)		(140	)		-			(140	)
Common stock issued under purchase plan		48		-		-			-			-			48			-			48
Stock-based compensation		16		-		-			-			-			16			-			16
Beneficial conversion feature, net of tax		-				43									43						43
Acquisition of non-controlling interest of ECI		3				7									10			(24	)		(14	)
Other		-		-		(5	)		(4	)		5			(4	)		(3	)		(7	)
Balance, June 30, 2016	$	2,224	$	709	$	74		$	(48	)	$	1,285		$	4,244		$	107		$	4,351

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Emera Incorporated

Notes to the Condensed Consolidated Interim Financial Statements (Unaudited)

As at June 30, 2017 and 2016

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 distribution and utility energy services.

Emera’s primary rate-regulated subsidiaries and investments at June 30, 2017 included the following:

• Emera Florida and New Mexico represents TECO Energy, Inc. (“TECO Energy”), a holding company with regulated electric and gas utilities in Florida and New Mexico which was acquired on July 1, 2016. TECO Energy’s holdings includes:

• Tampa Electric Company (“TEC”), which holds the Tampa Electric Division (“Tampa Electric”), an integrated regulated electric utility, serving approximately 746,000 customers in West Central Florida and Peoples Gas System Division, (“PGS”) a regulated gas distribution utility, serving approximately 375,000 customers across Florida;

• New Mexico Gas Company, Inc. (“NMGC”), a regulated gas distribution utility, serving approximately 521,000 customers across New Mexico;

• TECO Finance, Inc. (“TECO Finance”), a wholly owned financing subsidiary of TECO Energy;

• Nova Scotia Power Inc. (“NSPI”), a fully integrated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 512,000 customers;

• Emera Maine, an electric transmission and distribution utility, serving approximately 159,000 customers in Maine;

• Emera Caribbean represents Emera (Caribbean) Incorporated (“ECI”), a holding company that includes:

• The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados, serving approximately 129,000 customers;

• a 50.0 per cent direct and 30.4 per cent indirect interest (through a 60.7 per cent interest in ICD Utilities Limited) in Grand Bahama Power Company Limited (“GBPC”), a vertically integrated utility and sole provider of electricity on Grand Bahama Island, serving approximately 19,000 customers;

• a 51.9 per cent interest in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving approximately 36,000 customers;

• a 19.1 per cent indirect interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia;

• Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), 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, 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 generating first power in 2019 and full power in 2020. ENL’s two investments are:

• a 100 per cent investment 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, connecting the island of Newfoundland and Nova Scotia. This project is scheduled to be completed in Q4 2017 and to be in service by January 1, 2018;

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• a 57.4 per cent investment in the partnership capital of Labrador-Island Link Limited Partnership (“LIL”), a $3.7 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, Labrador Transmission Assets 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. Nalcor Energy has indicated that the LIL will be in service in Q2 2018.

• a 12.9 per cent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400-kilometre pipeline, which transports natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States.

Emera also owns investments in other energy-related non-regulated companies, including:

• Emera Energy, includes:

• Emera Energy Services, 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” (“NEGG”)), 1,115 MW of combined-cycle gas-fired electricity generating capacity in the northeastern United States;

• Bayside Power Limited Partnership (“Bayside Power”), a 290 MW gas-fired combined cycle power plant in Saint John, New Brunswick;

• Brooklyn Power Corporation (“Brooklyn Energy”), a 30 MW biomass co-generation 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”), a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts.

• Emera Reinsurance Limited, 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 US Finance LP, a wholly owned financing subsidiary of Emera;

• Emera US Holdings Inc., a wholly owned holding company for certain of Emera’s assets located in the United States;

• Emera Utility Services Inc., a utility services contractor primarily operating in Atlantic Canada; and

• other investments.

Basis of Presentation

These unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). The significant accounting policies applied to these unaudited condensed consolidated interim financial statements are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2016.

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. 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, 2017.

All dollar amounts are presented in Canadian dollars, unless otherwise indicated.

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Use of Management Estimates

The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may 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. Actual results may differ significantly from these estimates.

Seasonal Nature of Operations

Interim results are not necessarily indicative of results for the full year, primarily due to seasonal factors. Electricity and gas sales and related transmission and distribution, vary 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 historically a substantial portion of Emera’s electricity business is located. However, with the addition of Emera Florida and New Mexico, the third quarter will provide stronger earnings for Emera than prior to the acquisition due to the summer being the peak electricity season in Florida. Certain quarters may also be impacted by weather and the number and severity of storms.

2. FUTURE ACCOUNTING PRONOUNCEMENTS

The Company considers the applicability and impact of all Accounting Standard Updates (“ASU”) issued by the Financial Accounting Standards Board (the “FASB”). The ASUs that have been issued, but that are not yet effective, are consistent with those disclosed in the 2016 audited consolidated financial statements, with the exception of the items noted below.

Revenue from Contracts with Customers

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework, codified as Accounting Standards Codification (“ASC”) Topic 606. The FASB issued amendments to ASC Topic 606 during 2016 to clarify certain implementation guidance and to reflect scope improvements and practical expedients. The guidance will require additional disclosures regarding the nature, amount, timing and uncertainty of revenue and related cash flows arising from contracts with customers. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and will allow for either full retrospective adoption or modified retrospective adoption. The Company will adopt this guidance effective January 1, 2018.

The Company implemented a revenue recognition project plan in 2016. In Q1 2017, the Company concluded that the accounting for contributions in aid of construction will be out of the scope of the new standard. In Q2 2017, the Company completed an analysis of material regulated revenue streams and collectability risk and has concluded that there will be no material changes on adoption of this standard. The Company will adopt the standard using the modified retrospective approach. Emera continues to evaluate the impact of this standard on unregulated revenue streams and financial statement disclosure requirements. The Company continues to monitor the assessment of ASC Topic 606 by the AICPA Power and Utilities Revenue Recognition Task Force for developments.

Recognition and Measurement of Financial Assets and Financial Liabilities

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. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017.

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The standard requires investments in equity securities, except those accounted for under the equity method of accounting or those that result in consolidation, to be measured at fair value. The Company will elect to measure equity securities that do not have a readily determinable fair value, at cost minus impairment (if any), plus or minus observable price changes resulting from transactions for the identical or a similar investment of the same issuer. The standard eliminates the available-for-sale classification for equity investments that recognized changes in the fair value as a component of other comprehensive income, resulting in all changes in fair value being recognized in net income. The increase in volatility of Other income (expense), net as a result of the remeasurement of equity investments is not expected to be significant. The Company will adopt this guidance effective January 1, 2018 with a cumulative-effect adjustment to the Consolidated Balance Sheet.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. The standard, codified as ASC Topic 842, increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with terms of more than 12 months. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet. The effect of leases on the Consolidated Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. The guidance will require additional disclosures regarding key information about leasing arrangements. This guidance is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and is required to be applied using a modified retrospective approach. The Company is currently evaluating the impact of adoption of this standard on its consolidated financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The guidance requires the service cost component of defined benefit pension or other postretirement benefit plans to be reported in the same line items as other compensation costs. The other components of net benefit cost are required to be presented in the Consolidated Statements of Income outside of income from operations. Only the service cost component will be eligible for capitalization under this guidance. This guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. The guidance is required to be applied retrospectively for presentation in the Consolidated Statements of Income and prospectively for the guidance limiting capitalization. The Company is currently evaluating the impact of the adoption of this standard on the consolidated financial statements, including the eligibility for capitalization of the other components of net benefit cost given the application of ASC 980 Regulated Operations. The Company will adopt this guidance effective January 1, 2018.

3. ACQUISITION

TECO ENERGY INC.

On July 1, 2016, Emera acquired all of the outstanding common shares of TECO Energy for $27.55 US dollars (“USD”) per common share. The net cash purchase price totalled $8.4 billion ($6.5 billion USD), with an aggregate purchase price of $13.9 billion ($10.7 billion USD), including the assumption of $5.5 billion ($4.2 billion USD) in US debt on closing.

The majority of TECO Energy’s operations are subject to the rate-setting authority of the Federal Energy Regulatory Commission (“FERC”), Florida Public Service Commission (“FPSC”), and New Mexico Public Regulation Commission (“NMPRC”), and are accounted for pursuant to USGAAP, including the accounting guidance for regulated operations. Except for unregulated long-term debt acquired and deferred taxes, fair values of tangible and intangible assets and liabilities subject to these rate-setting provisions approximate their carrying values due to the fact that a market participant would not expect to recover any more or less than their net carrying value. Accordingly, assets acquired and liabilities assumed and pro-forma financial information do not reflect any adjustments related to these amounts.

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The acquisition is accounted for in accordance with the acquisition method of accounting. The excess of purchase price over estimated fair values of assets acquired and liabilities assumed has been recognized as goodwill at the acquisition date of July 1, 2016. The goodwill reflects the value paid for access to regulated assets, net income and cash flows in growth markets, opportunities for adjacency growth, long-term potential for enhanced access to capital as a result of increased scale and business diversity, and an improved earnings risk profile. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill.

The following table summarizes the final allocation of the purchase consideration to the assets and liabilities acquired as at July 1, 2016 based on their fair values, using the July 1, 2016 exchange rate of $1.00 USD = $1.3009 CAD.

	millions of Canadian dollars
Purchase Consideration	$            8,447
Fair value assigned to net assets:
Current assets (1)	$619
Regulatory assets (including current portion)	624
Property, plant and equipment, net	10,023
Other long-term assets	71
Current liabilities	(747)
Assumed long-term debt (including current portion)	(5,409)
Regulatory liabilities (including current portion)	(1,117)
Deferred income taxes	(800)
Pension and post-retirement liabilities (including current portion)	(480)
Other long-term liabilities	(146)
	$            2,638
Cash and cash equivalents	38
Fair value of net assets acquired	$            2,676
Goodwill	$            5,771

(1) Includes accounts receivables with fair value of $334 million comprised of gross contract value of $337 million, and $3 million of contractual receivables not expected to be collected.

Goodwill has been allocated to the TECO Energy reporting units as follows:

millions of Canadian dollars
Reporting Unit	Goodwill
Tampa Electric	$	4,552
PGS		744
New Mexico Gas		475
Goodwill	$	5,771

Goodwill is subject to an annual assessment for impairment at the reporting unit level. Adverse changes in assumptions could result in a material impairment of Emera’s goodwill.

Acquisition Related Expenses

There were no acquisition related expenses incurred for the three and six months ended June 30, 2017. Acquisition related expenses totalled $67 million ($42 million after tax) and $93 million ($60 million after tax) for the three and six months ended June 30, 2016. These acquisition related expenses were included in Interest expense, net and Operating, maintenance and general on the Condensed Consolidated Statements of Income.

Supplemental Pro Forma Data

The unaudited pro forma financial information below gives effect to the acquisition of TECO Energy as if the transaction had occurred at the beginning of 2016. This pro forma data is presented for information

13

purposes only, and does not purport to be indicative of the results that would have occurred had the acquisition taken place at the beginning of 2016, nor is it indicative of the results that may be expected in future periods.

Pro forma net income attributable to common shareholders excludes all non-recurring acquisition-related expenses incurred by TECO Energy and Emera and includes adjustments for pro forma financing costs associated with the acquisition. Total after-tax adjustments made to the pro forma net income attributable to common shareholders were $70 million and $41 million, respectively, for the three and six months ended June 30, 2016.

For the millions of Canadian dollars	Three months ended June 30		Six months ended June 30
	2016		2016
Pro forma operating revenues	$	1,340	$	3,123
Pro forma net income attributable to common shareholders	$	285	$	398

4. SEGMENT INFORMATION

Emera manages its reportable segments separately due in part 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 reported to the Company’s chief operating decision maker.

As at June 30, 2017, Emera has six reportable segments, specifically:

• Emera Florida and New Mexico;

• NSPI;

• Emera Maine;

• Emera Caribbean;

• Emera Energy; and

• Corporate and Other (includes Emera Utility Services, ENL, Emera Brunswick Pipeline, Corporate, other strategic investments and holding companies).

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millions of Canadian	Emera Florida and New Mexico		NSPI		Emera Maine		Emera Caribbean		Emera Energy		Corporate and Other		Inter- Segment Eliminations		Total
dollars
For the three months ended June 30, 2017
Operating revenues from external customers (1)	$	945	$	303	$	73	$	114	$	14	$	21	$	-	$	1,470
Inter-segment revenues (1)		-		1		-		-		3		10		(15)		(1)
Total operating revenues		945		304		73		114		17		31		(15)		1,469
Net income (loss) attributable to common shareholders (2)		103		29		12		11		(28)		(26)		-		101
For the six months ended June 30, 2017
Operating revenues from external customers (1)		1,834		698		152		218		380		46		-		3,328
Inter-segment revenues (1)		-		2		-		-		7		14		(25)		(2)
Total operating revenues		1,834		700		152		218		387		60		(25)		3,326
Net income (loss) attributable to common shareholders (2)		182		99		25		18		142		(53)		-		413
For the three months ended June 30, 2016
Operating revenues from external customers (1)		-	$	314	$	65	$	101	$	5	$	13	$	-	$	498
Inter-segment revenues (1)		-		-		-		-		3		7		(9)		1
Total operating revenues		-		314		65		101		8		20		(9)		499
Net income (loss) attributable to common shareholders (2)		-		28		10		58		(63)		175		-		208
For the six months ended June 30, 2016
Operating revenues from external customers (1)		-		711		145		199		293		28		-		1,376
Inter-segment revenues (1)		-		1		-		-		6		13		(20)		-
Total operating revenues		-		712		145		199		299		41		(20)		1,376
Net income (loss) attributable to common shareholders (2)		-		81		19		68		30		54		-		252

(1) All significant intercompany 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) Corporate and Other net income for the three months ended June 30, 2017 has been increased by amortization of $4 million and for the six months ended June 30, 2017 by $8 million related to the unregulated long-term debt fair market value adjustment recognized on the acquisition of TECO Energy.

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5. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Investments subject to significant influence consisted of the following:

	June 30		Carrying Value as at December 31		Equity Income for the three months ended June 30				Equity Income for the six months ended June 30				Percentage of Ownership
millions of Canadian dollars	2017		2016		2017		2016		2017		2016		2017
LIL (1)	$	473	$	400	$	9	$	6	$	18	$	10		57.4
NSPML		436		315		9		4		16		9		100.0
M&NP (2)		165		175		5		5		11		11		12.9
Lucelec (2)		38		39		1		-		2		1		19.1
Bear Swamp (3)		-		-		6		6		9		7		50.0
Algonquin Power and Utilities Corp (“APUC”) (4)		-		-		-		9		-		18		-
Other Investments		19		18		-		-		-		-		-
	$	1,131	$	947	$	30	$	30	$	56	$	56

(1) Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued.

(2) 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.

(3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $179 million distribution received in Q4 2015. Bear Swamp’s credit investment balance of $204 million (2016 - $217 million) is recorded in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets.

(4) In two separate transactions in 2016, Emera sold a total of 63 million common shares in APUC. Emera no longer holds any interest in APUC.

Equity investments include a $13 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 21). NSPML’s consolidated summarized balance sheet is illustrated as follows:

As at millions of Canadian dollars	June 30 2017		December 31 2016
Balance Sheet
Current assets	$	404	$	439
Property, plant and equipment		1,463		1,132
Non-current assets		118		276
Total assets		1,985		1,847
Current liabilities		228		219
Long-term debt		1,288		1,288
Non-current liabilities		33		25
Equity		436		315
Total liabilities and equity	$	91,985	$	1,847

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6. OTHER INCOME (EXPENSES), NET

Other income (expenses), net consisted of the following:

For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Gain on sale of APUC common shares	$	-	$	172	$	-	$	172
Gain on conversion of APUC subscription receipts and dividend equivalents to common shares of APUC		-		63		-		63
Gain on BLPC Self-Insurance Fund (“SIF”) regulatory liability		-		53		-		53
Allowance for equity funds used during construction		2		1		5		2
Foreign exchange gains (losses) and mark-to-market adjustments related to the TECO Energy acquisition		-		7		-		(133)
Other		(1)		(2)		(2)		(2)
	$	1	$	294	$	3	$	155

7. INTEREST EXPENSE, NET

Interest expense, net consisted of the following:

For the millions of Canadian dollars	Three months ended June 30				Six months ended June 30
	2017		2016		2017		2016
Interest on debt	$	170	$	61	$	338	$	110
Interest on Convertible Debentures (1)		-		43		-		65
Allowance for borrowed funds used during construction		(1)		(1)		(3)		(2)
Other		9		4		18		9
	$	178	$	107	$	353	$	182

(1) In 2015, Emera completed the sale of $2.185 billion four per cent convertible unsecured subordinated debentures represented by instalment receipts which were substantially all converted to equity in 2016.

8. 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 June 30				Six months ended June 30
	2017		2016		2017		2016
Income before provision for income taxes	$	144	$	218	$	578	$	300
Statutory income tax rate		31%		31%		31%		31%
Income taxes, at statutory income tax rate		45		68		179		93
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities		(11)		(14)		(35)		(27)
Foreign tax rate variance		11		(14)		19		(15)
Financing deductions		(5)		(5)		(9)		(8)
Non-taxable portion of gains on APUC transactions		-		(36)		-		(36)
Non-deductible (non-taxable) portion of foreign exchange and mark-to-market adjustments related to the TECO Energy acquisition		-		(1)		-		21
Other		(6)		3		(8)		-
Income tax expense	$	34	$	1	$	146	$	28
Effective income tax rate		24%		0%		25%		9%

The statutory income tax rate of 31 per cent represents the combined Canadian federal and Nova Scotia and New Brunswick 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 June 30				Six months ended June 30
	2017		2016		2017		2016
Income tax expense – current	$	18	$	5	$	29	$	23
Income tax expense (recovery) – deferred		16		(4)		117		5
Income tax expense	$	34	$	1	$	146	$	28

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 million, including interest. NSPI has prepaid $23 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. Should NSPI receive similar notices of reassessment for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute.

NSPI and its advisors believe NSPI has reported its tax position appropriately and NSPI is disputing the reassessments through the CRA Appeal process. NSPI continues to assess its options to resolving the dispute however the outcome of the Appeal process is not determinable at this time.

9. COMMON STOCK

Authorized: Unlimited number of non-par value common shares.

Issued and outstanding:	millions of shares		millions of Canadian dollars
Balance, December 31, 2016		210.02		$                4,738
Conversion of Convertible Debentures (1)		0.13		5
Issued for cash under Purchase Plans at market rate		1.97		90
Discount on shares purchased under Dividend Reinvestment Plan		-		(4)
Options exercised under senior management share option plan		0.04		1
Employee Share Purchase Plan		-		1
Balance, June 30, 2017		212.16		$                4,831

(1) During the six months ended June 30, 2017, 0.13 million common shares of Emera were issued relating to the conversion of the Convertible Debentures. As at June 30, 2017, a total of 52.12 million common shares of the Company were issued, representing conversion into common shares of more than 99.8% of the Convertible Debentures.

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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 June 30				Six months ended June 30
	2017		2016		2017		2016
Numerator
Net income attributable to common shareholders	$	101.0	$	207.8	$	413.4	$	252.1
Diluted numerator		101.0		207.8		413.4		252.1
Denominator
Weighted average shares of common stock outstanding		211.7		148.7		211.1		148.2
Weighted average deferred share units outstanding		1.1		1.0		1.1		1.0
Weighted average shares of common stock outstanding – basic		212.8		149.7		212.2		149.2
Stock-based compensation		0.6		0.6		0.5		0.6
Convertible Debentures		0.1		-		0.1		-
Weighted average shares of common stock outstanding – diluted		213.5		150.3		212.8		149.8
Earnings per common share
Basic	$	0.47	$	1.39	$	1.95	$	1.69
Diluted	$	0.47	$	1.38	$	1.94	$	1.68

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11. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income (loss), net of tax, are as follows:

millions of Canadian dollars	Unrealized (loss) gain on translation of self-sustaining foreign operations		Net change in net investment hedges		(Losses) gains on derivatives recognized as cash flow hedges		Net change in available-for- sale investments		Net change in unrecognized pension and post-retirement benefit costs		Total AOCI
For the six months ended June 30, 2017
Balance, January 1, 2017	$	486	$	(49)	$	(21)	$	(1)	$	(309)	$	106
Other comprehensive income (loss) before reclassifications		(229)		52		5		4		-		(168)
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		4		(1)		13		16
Net current period other comprehensive income (loss)		(229)		52		9		3		13		(152)
Other		-		-		-		-		-		-
Balance, June 30, 2017	$	257	$	3	$	(12)	$	2	$	(296)	$	(46)

millions of Canadian dollars	Unrealized (loss) gain on translation of self-sustaining foreign operations		Net change in net investment hedges		(Losses) gains on derivatives recognized as cash flow hedges		Net change in available-for- sale investments		Net change in unrecognized pension and post-retirement benefit costs		Total AOCI
For the six months ended June 30, 2016
Balance, January 1, 2016	$	490	$	-	$	(35)	$	-	$	(318)	$	137
Other comprehensive income (loss) before reclassifications		(173)		-		17		-		-		(156)
Amounts reclassified from accumulated other comprehensive income loss (gain)		-		-		4		-		17		21
Equity method reclassification adjustments		(36)		-		(7)		-		(3)		(46)
Net current period other comprehensive income (loss)		(209)		-		13		-		14		(181)
Other		(4)		-		-		-		-		(4)
Balance, June 30, 2016	$	277	$	-	$	(22)	$	-	$	(304)	$	(48)

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The reclassifications out of accumulated other comprehensive income (loss) are as follows:

For the			Three months ended June 30				Six months ended June 30
millions of Canadian dollars			2017		2016		2017		2016
	Affected line item in the Consolidated Financial Statements		Amounts reclassified from AOCI
Equity method reclassification adjustments
		Investments subject to significant influence	$	-	$	54	$	-	$	54
Total before tax				-		54		-		54
		Deferred income taxes		-		(8)		-		(8)
Total net of tax			$	-	$	46	$	-	$	46
Losses (gain) on derivatives recognized as cash flow hedges
Power and gas swaps		Non-regulated fuel for generation and purchased power	$	1	$	1	$	(3)	$	(3)
Interest rate swaps		Income from equity investments		-		1		-		1
Foreign exchange forwards		Operating revenue – regulated		3		2		6		5
Total before tax				4		4		3		3
		Income tax expense (recovery)		-		(1)		1		1
Total net of tax			$	4	$	3	$	4	$	4
Net change in available-for-sale investments
		Other income (expenses), net		-		-		(1)		-
Total before tax				-		-		(1)		-
		Income tax expense (recovery)		-		-		-		-
Total net of tax				-		-		(1)		-
Net change in unrecognized pension and post-retirement benefit costs
Actuarial losses (gains)		OM&G	$	5	$	10	$	15	$	22
Past service costs (gains)		OM&G		(2)		(3)		(4)		(5)
Total before tax				3		7		11		17
		Income tax expense (recovery)		2		-		2		-
Total net of tax			$	5	$	7	$	13	$	17
Total reclassifications out of AOCI, net of tax, for the period			$	9	$	56	$	16	$	67

12. 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,

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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 Tampa Electric, PGS, NMGC, NSPI, Emera Maine 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 millions of Canadian dollars	June 30 2017		December 31 2016		June 30 2017		December 31 2016
Current
Cash flow hedges
Power swaps	$	5	$	5	$	2	$	2
Foreign exchange forwards		-		-		10		12
		5		5		12		14
Regulatory deferral
Commodity swaps and forwards
Coal purchases		39		26		8		9
Power purchases		2		3		1		1
Natural gas purchases and sales		5		28		1		-
Heavy fuel oil purchases		2		6		6		4
Foreign exchange forwards		31		56		-		-
Physical natural gas and biofuel energy purchases and sales		1		-		2		-
		80		119		18		14
HFT derivatives
Power swaps and physical contracts		105		33		103		44
Natural gas swaps, futures, forwards, physical contracts		92		93		157		357
		197		126		260		401
Other derivatives
Foreign exchange forwards		-		-		-		1
		-		-		-		1
Total gross current derivatives		282		250		290		430
Impact of master netting agreements with intent to settle net or simultaneously		(161)		(105)		(161)		(105)
Total current derivatives		121		145		129		325
Long-term
Cash flow hedges
Power swaps		1		5		1		3
Foreign exchange forwards		-		-		2		10
		1		5		3		13
Regulatory deferral
Commodity swaps and forwards
Coal purchases		49		57		1		-
Power purchases		2		4		2		3
Natural gas purchases and sales		2		5		3		2
Heavy fuel oil purchases		1		4		3		3
Foreign exchange forwards		26		50		2		-
Physical natural gas and biofuel energy purchases and sales		-		-		1		-
		80		120		12		8
HFT derivatives
Power swaps and physical contracts		16		14		22		27
Natural gas swaps, futures, forwards and physical contracts		33		18		87		127
		49		32		109		154
Other derivatives
Interest rate swap		-		-		-		1
		-		-		-		1
Total gross long-term derivatives		130		157		124		176
Impact of master netting agreements with intent to settle net or simultaneously		(25)		(26)		(25)		(26)
Total long-term derivatives		105		131		99		150
Total derivatives	$	226	$	276	$	228	$	475

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 Condensed Consolidated Balance Sheets, are summarized in the following table:

	Derivative Assets				Derivative Liabilities
As at millions of Canadian dollars	June 30 2017		December 31 2016		June 30 2017		December 31 2016
Regulatory deferral	$	10	$	10	$	10	$	10
HFT derivatives		176		121		176		121
Total impact of master netting agreements with intent to settle net or simultaneously	$	186	$	131	$	186	$	131

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. The Company also enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline.

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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	Three months ended June 30
millions of Canadian dollars	2017						2016
	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	$	-	$	-
Realized gain (loss) in non-regulated fuel for generation and purchased power		(1)		-		-		(1)		-		-
Realized gain (loss) in operating revenue – regulated		-		-		(3)		-		-		(2)
Realized gain (loss) in income from equity investments		-		-		-		-		(1)		-
Total gains (losses) in net income	$	(1)	$	-	$	(3)	$	-	$	(1)	$	(2)

For the	Six months ended June 30
millions of Canadian dollars	2017						2016
	Power Swaps		Interest Rate Swaps		Foreign Exchange Forwards		Power Swaps		Interest Rate Swaps		Foreign Exchange Forwards
Realized gain (loss) in non-regulated fuel for generation and purchased power	$	3	$	-	$	-	$	3	$	-	$	-
Realized gain (loss) in operating revenue – regulated		-		-		(6)		-		-		(5)
Realized gain (loss) in income from equity investments		-		-		-		-		(1)		-
Total gains (losses) in net income	$	3	$	-	$	(6)	$	3	$	(1)	$	(5)

As at millions of Canadian dollars	June 30 2017						December 31 2016
	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	$	-	$	-	$	(11)	$	2	$	-	$	(22)

The Company expects $12 million of unrealized losses currently in AOCI to be reclassified into net income within the next 12 months, as the underlying hedged transactions settle.

As at June 30, 2017, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:

millions	2017		2018		2019		2020		2021
Foreign exchange forwards (USD) sales	$	27	$	45	$	30	$	30	$	-

Regulatory Deferral

As previously noted, Tampa Electric, PGS, NMGC, NSPI, Emera Maine 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.

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The Company has recorded the following changes in realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:

For the	Three months ended June 30
millions of Canadian dollars	2017						2016
	Commodity swaps and forwards		Physical natural gas and biofuel energy 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	$	(7)	$	-	$	(2)	$	14	$	-	$	(1)
Unrealized gain (loss) in regulatory liabilities		8		-		(11)		48		-		5
Realized (gain) loss in regulatory assets		-		-		-		(2)		-		3
Realized (gain) loss in regulatory liabilities		-		-		-		-		-		(2)
Realized (gain) loss in inventory (1)		(3)		-		(11)		3		-		(14)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		(2)		-		(4)		5		-		(4)
Total change in derivative instruments	$	(4)	$	-	$	(28)	$	68	$	-	$	(13)

(1) Realized (gains) losses will be recognized in regulated 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	Six months ended June 30
millions of Canadian dollars	2017						2016
	Commodity swaps and forwards		Physical natural gas and biofuel energy 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	$	(27)	$	(5)	$	(2)	$	18	$	-	$	2
Unrealized gain (loss) in regulatory liabilities		8		1		(17)		49		(1)		(45)
Realized (gain) loss in regulatory assets		-		-		-		-		-		3
Realized (gain) loss in regulatory liabilities		(1)		-		-		-		-		(2)
Realized (gain) loss in inventory (1)		(8)		-		(23)		3		-		(33)
Realized (gain) loss in regulated fuel for generation and purchased power (2)		(4)		-		(9)		11		-		(13)
Total change in derivative instruments	$	(32)	$	(4)	$	(51)	$	81	$	(1)	$	(88)

(1) Realized (gains) losses will be recognized in regulated 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 June 30, 2017, 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:

	2017		2018-2020
millions	Purchases		Purchases
Coal (metric tonnes)		-		2
Natural Gas (Mmbtu)		17		32
Heavy fuel oil (bbls)		-		2

Foreign Exchange Swaps and Forwards

As at June 30, 2017, 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:

	2017		2018-2020
Foreign exchange contracts (millions of US dollars)	$	82	$	284
Weighted average rate		1.0997		1.1496
% of USD requirements		81%		58%

The Company reassesses forecasted foreign exchange requirements periodically and will enter into additional hedges or unwind existing hedges, as required.

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 June 30				Six months ended June 30
	2017		2016		2017		2016
Power swaps and physical contracts in non-regulated operating revenues	$	5	$	2	$	6	$	(3)
Natural gas swaps, forwards, futures, physical contracts in non-regulated operating revenues		54		33		377		261
Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for purchased power		5		1		8		2
Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased power		-		4		(1)		2
Foreign exchange options in non-regulated operating revenue		-		-		-		(1)
	$	64	$	40	$	390	$	261

As at June 30, 2017, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

millions	2017		2018		2019		2020		2021
Natural gas purchases (Mmbtu)		228		139		98		66		44
Natural gas sales (Mmbtu)		192		89		27		10		1
Power purchases (MWh)		6		3		-		-		-
Power sales (MWh)		9		3		-		-		-
Foreign exchange options (USD)	$	6	$	4	$	-		-		-

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Other Derivatives

The Company has recognized the following realized and unrealized gains (losses) with respect to cash flow hedges for which documentation requirements have not been met:

For the millions of Canadian dollars					Three months ended June 30
	2017				2016
	Interest rate swaps		Foreign exchange forwards		Interest rate swaps		Foreign exchange forwards
Unrealized gain (loss) in other income (expense)	$	-	$	-	$	-	$	(6)
Unrealized gain (loss) in interest expense, net		1		-		-		-
Total gains (losses) in net income	$	1	$	-	$	-	$	(6)

For the	Six months ended June 30
millions of Canadian dollars	2017				2016
	Interest rate swaps		Foreign exchange forwards		Interest rate swaps		Foreign exchange forwards
Unrealized gain (loss) in other income (expense)	$	-	$	-	$	-	$	(101)
Unrealized gain (loss) in interest expense, net		1		-		-		-
Total gains (losses) in net income	$	1	$	-	$	-	$	(101)

As at June 30, 2017, 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.

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.

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

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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 June 30, 2017, the Company had $113 million (December 31, 2016 - $104 million) in financial assets considered to be past due, which have been outstanding for an average 68 days. The fair value of these financial assets is $99 million (December 31, 2016 - $91 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric and gas revenue.

Cash Collateral

The Company’s cash collateral positions consisted of the following:

As at millions of Canadian dollars	June 30 2017		December 31 2016
Cash collateral provided to others	$	97	$	91
Cash collateral received from others		50		52

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 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 falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at June 30, 2017, the total fair value of these derivatives, in a liability position, was $228 million (December 31, 2016 – $475 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.

13. 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 12), 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.

• The valuations of certain transactions were based on internal models, although quoted prices were utilized in the valuations.

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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	June 30, 2017
millions of Canadian dollars	Level 1		Level 2		Level 3		Total
Assets
Cash flow hedges
Power swaps	$	6	$	-	$	-	$	6
		6		-		-		6
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		79		-		79
Power purchases		4		-		-		4
Natural gas purchases and sales		1		6		-		7
Heavy fuel oil purchases		-		2		-		2
Foreign exchange forwards		-		57		-		57
Physical natural gas purchases and sales		-		-		1		1
		5		144		1		150
HFT derivatives
Power swaps and physical contracts		(4)		1		15		12
Natural gas swaps, futures, forwards, physical contracts and related transportation		1		28		29		58
		(3)		29		44		70
Total assets		8		173		45		226
Liabilities
Cash flow hedges
Power swaps		3		-		-		3
Foreign exchange forwards		-		12		-		12
		3		12		-		15
Regulatory deferral
Commodity swaps and forwards
Power purchases		4		-		-		4
Heavy fuel oil purchases		-		8		-		8
Natural gas purchases and sales		2		1		-		3
Foreign exchange forwards		-		2		-		2
Physical natural gas and biofuel energy purchases and sales		-		3		-		3
		6		14		-		20
HFT derivatives
Power swaps and physical contracts		6		2		8		16
Natural gas swaps, futures, forwards and physical contracts		2		20		155		177
		8		22		163		193
Other derivatives
Total liabilities		17		48		163		228
Net assets (liabilities)	$	(9)	$	125	$	(118)	$	(2)

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As at	December 31, 2016
millions of Canadian dollars	Level 1		Level 2		Level 3		Total
Assets
Cash flow hedges
Power swaps	$	10	$	-	$	-	$	10
		10		-		-		10
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		74		-		74
Power purchases		7		-		-		7
Natural gas purchases and sales		8		25		-		33
Heavy fuel oil purchases		3		5		1		9
Foreign exchange forwards		-		106		-		106
		18		210		1		229
HFT derivatives
Power swaps and physical contracts		(7)		1		-		(6)
Natural gas swaps, futures, forwards, physical contracts and related transportation		-		4		39		43
		(7)		5		39		37
Total assets		21		215		40		276
Liabilities
Cash flow hedges
Power swaps		4		-		-		4
Foreign exchange forwards		-		23		-		23
		4		23		-		27
Regulatory deferral
Commodity swaps and forwards
Power purchases		4		-		-		4
Heavy fuel oil purchases		-		6		-		6
Natural gas purchases and sales		1		1		-		2
		5		7		-		12
HFT derivatives
Power swaps and physical contracts		12		5		-		17
Natural gas swaps, futures, forwards and physical contracts		4		24		389		417
		16		29		389		434
Other derivatives
Foreign exchange forwards		-		1		-		1
Interest rate swaps		-		1		-		1
		-		2		-		2
Total liabilities		25		61		389		475
Net assets (liabilities)	$	(4)	$	154	$	(349)	$	(199)

The change in the fair value of the Level 3 financial assets for the three months ended June 30, 2017 was as follows:

	Regulatory Deferral				HFT Derivatives
millions of Canadian dollars	Oil financial derivatives		Physical natural gas purchases and sales		Power		Natural gas		Total
Balance, beginning of period	$	-	$	1	$	4	$	27	$	32
Total realized and unrealized gains (losses) included in non-regulated operating revenues		-		-		11		2		13
Balance, June 30, 2017	$	-	$	1	$	15	$	29	$	45

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The change in the fair value of the Level 3 financial liabilities for the three months ended June 30, 2017 was as follows:

	Regulatory Deferral				HFT Derivatives
millions of Canadian dollars	Oil financial derivatives		Physical natural gas and biofuel energy purchases and sales		Power		Natural gas		Total
Balance, beginning of period	$	-	$	-	$	1	$	155	$	156
Total realized and unrealized gains (losses) included in non-regulated operating revenues		-		-		7		-		7
Balance, June 30, 2017	$	-	$	-	$	8	$	155	$	163

The change in the fair value of the Level 3 financial assets for the six months ended June 30, 2017 was as follows:

	Regulatory Deferral				HFT Derivatives
millions of Canadian dollars	Oil financial derivatives		Physical natural gas purchases and sales		Power		Natural gas		Total
Balance, beginning of period	$	1	$	-	$	-	$	39	$	40
Unrealized gains (losses) included in regulatory assets or liabilities		(1)		1		-		-		-
Total realized and unrealized gains (losses) included in non-regulated operating revenues		-		-		15		5		20
Net transfers out of Level 3		-		-		-		(15)		(15)
Balance, June 30, 2017	$	-	$	1	$	15	$	29	$	45

The change in the fair value of the Level 3 financial liabilities for the six months ended June 30, 2017 was as follows:

	HFT Derivatives
millions of Canadian dollars	Power		Natural gas		Total
Balance, beginning of period	$	-	$	389	$	389
Total realized and unrealized gains (losses) included in non-regulated operating revenues		7		(238)		(231)
Net transfers out of Level 3		1		4		5
Balance, June 30, 2017	$	8	$	155	$	163

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 June 30, 2017, there were no transfers between levels. For the six months ended June 30, 2017, transfers out of Level 3 were a result of an increase in observable inputs. For the six months ended June 30, 2017, transfers into Level 3 were a result of a decrease 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. 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.

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Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives include 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.

As at	June 30, 2017
millions of Canadian dollars	Fair Value		Valuation Technique		Unobservable Input		Range		Weighted average
Assets
Regulatory deferral – Physical	$	1		Modelled pricing		Third-party pricing		$4.21 - $4.34		$4.26
natural gas purchases and sales						Probability of default		0.15%		0.15%
HFT derivatives –		15		Modelled pricing		Third-party pricing	$	21.40 - $82.40		$55.12
Power swaps and						Probability of default		0.00% - 0.01%		0.00%
physical contracts						Discount rate		0.00% - 0.13%		0.01%
HFT derivatives –		15		Modelled pricing		Third-party pricing		$1.98 - $4.96		$3.32
Natural gas swaps, futures, forwards,						Probability of default		0.00% - 0.07%		0.01%
physical contracts						Discount rate		0.00% - 0.30%		0.06%
and related transportation		14		Modelled pricing		Third-party pricing		$1.82 - $9.61		$3.73
						Basis adjustment		0.01% - 0.62%		0.58%
						Probability of default		0.00% - 0.20%		0.01%
						Discount rate		0.00% - 0.08%		0.01%
Total assets	$	45
Liabilities
HFT derivatives –	$	8		Modelled pricing		Third-party pricing		$21.40 - $82.40		$42.95
Power swaps and						Own credit risk		0.00% - 0.01%		0.00%
physical contracts						Discount rate		0.00% - 0.13%		0.01%
HFT derivatives –		151		Modelled pricing		Third-party pricing		$1.67 - $8.95		$4.03
Natural gas swaps, futures,						Own credit risk		0.00% - 0.01%		0.00%
forwards and physical contracts						Discount rate		0.00% - 0.13%		0.03%
		4		Modelled pricing		Third-party pricing		$2.07 - $9.61		$5.23
						Basis adjustment		0.04% - 0.62%		0.55%
						Own credit risk		0.00% - 0.01%		0.00%
						Discount rate		0.00% - 0.08%		0.01%
Total liabilities	$	163
Net assets (liabilities)	$	(118)

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The financial assets and liabilities included on the Condensed Consolidated Balance Sheets that are not measured at fair value consisted of the following:

As at	June 30, 2017
millions of Canadian dollars	Carrying Amount		Fair Value		Level 1		Level 2		Level 3		Total
Long-term debt (including current portion)	$	14,617	$	15,946	$	74	$	15,069	$	803	$	15,946

As at	December 31, 2016
millions of Canadian dollars	Carrying Amount		Fair Value		Level 1		Level 2		Level 3		Total
Long-term debt (including current portion)	$	14,744	$	15,723	$	78	$	14,843	$	802	$	15,723

The fair values of long-term debt instruments, classified as Level 1 in the fair value hierarchy, are valued using unadjusted quoted closing market prices that are traded in active markets.

Those classified as Level 2 are valued either by using recent quoted market prices for the instrument where the instrument is not frequently traded, by using quoted closing market prices for similar issues that are frequently traded in an active market or by using quoted market prices and applying estimated credit spreads, provided by third-party pricing services, to the par value of the security.

Those classified as Level 3 are valued by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality.

The Company has designated $1.2 billion United States dollar denominated Hybrid Notes as a hedge of the foreign currency exposure of its net investment in United States dollar denominated operations. A foreign currency gain of $39 million was recorded in Other Comprehensive Income for the three months ended June 30, 2017 (2016 – nil). A foreign currency gain of $52 million was recorded in Other Comprehensive Income for the six months ended June 30, 2017 (2016 – nil) There was no ineffectiveness for the three and six months ended June 30, 2017 (2016 – nil).

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.

14. 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 2016 annual audited consolidated financial statements.

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As at millions of Canadian dollars	June 30 2017		December 31 2016
Regulatory assets
Deferred income tax regulatory assets	$	689	$	632
Pension and post-retirement medical plan		368		373
Environmental remediation		44		49
Unamortized defeasance costs		36		39
2015 Demand side management deferral		30		32
GBPC Hurricane Matthew restoration		28		28
Stranded cost recovery		26		27
Deferrals related to derivative instruments		20		15
Debt basis adjustment		16		19
Cost-recovery clauses		12		12
Deferred bond refinancing costs		8		9
Other		81		87
	$	1,358	$	1,322
Current	$	79	$	80
Long-term		1,279		1,242
Total regulatory assets	$	1,358	$	1,322
Regulatory liabilities
Accumulated reserve - cost of removal	$	951	$	990
Deferrals related to derivative instruments		148		230
Regulated fuel adjustment mechanism		127		94
Cost-recovery clauses		82		153
Transmission and delivery storm reserve		60		75
Deferred income tax regulatory liabilities		34		26
Self-insurance fund (notes 6 and 21)		29		30
Bill reduction credit		6		10
Other		30		31
	$	1,467	$	1,639
Current	$	217	$	362
Long-term		1,250		1,277
Total regulatory liabilities	$	1,467	$	1,639

15. 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. All material amounts are under normal interest and credit terms.

Significant transactions between Emera and its associated companies include:

• Natural gas transportation capacity revenues from M&NP reported in the Condensed Consolidated Statements of Income. Revenues from M&NP, reported in Operating revenues, Non-regulated, totalled $6 million for the three months ended June 30, 2017 (2016 - $7 million) and $16 million for the six months ended June 30, 2017 (2016 - $15 million).

• Transmission construction revenues from NSPML reported in the Condensed Consolidated Statements of Income. Revenues from NSPML, reported in Operating revenues, Non-regulated, totalled $5 million for the three months ended June 30, 2017 (2016 - nil) and $12 million for the six months ended June 30, 2017 (2016 - nil).

There are no significant amounts between Emera and its associated companies reported on Emera’s Condensed Consolidated Balance Sheets as at June 30, 2017 and December 31, 2016.

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16. EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, Maine, Connecticut, Massachusetts, Rhode Island, New Mexico, Barbados, Dominica and Grand Bahama Island. For details of the Company’s employee benefit plan, refer to note 21 in Emera’s 2016 annual audited consolidated financial statements.

The net benefit cost of providing the defined benefit pension and non-pension benefit plans is detailed below:

For the	Three months ended				Six months ended
millions of Canadian dollars	June 30				June 30
	2017		2016		2017		2016
Defined benefit pension plans
Service cost	$	12	$	6	$	24	$	11
Interest cost		25		15		50		30
Expected return on plan assets		(33)		(18)		(66)		(33)
Current year amortization of:
Actuarial losses (gains)		10		11		19		21
Past service costs (gains)		-		-		-		(1)
Regulated asset (liability)		5		-		9		-
Total defined benefit pension plans		19		14		36		28
Non-pension benefits plan
Service cost		2		1		3		1
Interest cost		3		1		7		2
Expected return on plan assets		-		-		(1)		-
Current year amortization of:
Actuarial losses (gains)		-		-		1		1
Past service costs (gains)		(2)		(2)		(4)		(4)
Regulated asset (liability)		(1)		-		(1)		-
Total non-pension benefits plans		2		-		5		-
Total defined benefit plans	$	21	$	14	$	41	$	28

17. 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. For details regarding short-term debt refer to note 24 in Emera’s 2016 annual audited consolidated financial statements.

Recent financing activities

TECO Energy/TECO Finance Term Credit Facility

On March 8, 2017, TECO Energy/Finance extended the maturity date of its $400 million USD term bank credit facility from March 14, 2017 to March 8, 2018 with no significant change in commercial terms from the prior agreement. 

TECO Energy/TECO Finance Revolving Credit Facility

On March 22, 2017, TECO Energy/Finance extended the maturity date of its $300 million USD bank credit facility from December 17, 2018 to March 22, 2022 with no significant change in commercial terms from the prior agreement.

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TEC Credit Facility

On March 22, 2017, TEC extended the maturity date of its $325 million USD bank credit facility from December 17, 2018 to March 22, 2022, and reduced the existing letter of credit facility to $50 million USD from $200 million USD. There were no other significant changes in commercial terms from the prior agreement.

NMGC Credit Agreement

On March 22, 2017, NMGC extended the maturity date of its $125 million USD bank credit facility from December 17, 2018 to March 22, 2022 with no significant change in commercial terms from the prior agreement.

18. LONG-TERM DEBT

NSPI

On June 28, 2017, NSPI amended its operating credit facility to extend the maturity from October 2020 to October 2021 and the debt to capitalization ratio from 0.65:1 to 0.70:1. All other terms of the agreement are the same.

GBPC

On March 21, 2017, GBPC amended its loan agreement with the addition of two non-revolving term credit facilities. There were no significant changes in commercial terms from the prior agreement. The combined total of these new facilities is for up to $45 million USD. At June 30, 2017 a total of $30 million USD was drawn against the new facilities.

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19. COMMITMENTS AND CONTINGENCIES

A. Commitments

As at June 30, 2017, contractual commitments (excluding pensions and other post-retirement obligations, convertible debentures, long-term debt and AROs) for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2017		2018		2019		2020		2021		Thereafter		Total
Purchased power (1)	$	136	$	230	$	222	$	210	$	206	$	2,338	$	3,342
Transportation (2)		265		406		300		273		190		1,571		3,005
Fuel and gas supply		344		230		120		47		39		-		780
Long-term service agreements (3)		61		64		63		30		40		213		471
Equity investment commitments (4)		220		25		-		190		-		-		435
Leases and other (5)		50		20		12		12		6		66		166
Capital projects		95		17		-		-		-		-		112
Demand side management		19		45		11		-		-		-		75
	$	1,190	$	1,037	$	728	$	762	$	481	$	4,188	$	8,386

(1) Annual requirement to purchase electricity production from independent power producers or other utilities over varying contract lengths.

(2) Purchasing commitments for transportation of 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 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.

NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 35 years. The timing and amounts payable to NSPML and NSPI’s future rate recoveries are dependent upon the in-service date of the Maritime Link, UARB decisions and the final costing of the Maritime Link after construction is complete.

B. Legal Proceedings

Emera Florida and New Mexico

TECO Coal

TECO Coal was sold by TECO Energy on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”), prior to Emera’s acquisition of TECO Energy. On March 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified. The claim asserted breach of certain representations, and fraud and willful misconduct in connection therewith, of the Securities Purchase Agreement dated September 21, 2015 by and between TECO Diversified and Cambrian related to the purchase of TECO Coal by Cambrian. While the outcome of such matter is uncertain, management does not believe that its ultimate resolution will have a material adverse effect on the Company’s results of operations, financial condition or cash flows.

TECO Guatemala Holdings (“TGH”)

On December 19, 2013, the International Centre for the Settlement of Investment Disputes (“ICSID”) Tribunal hearing the arbitration claim of 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 favour of TGH and awarded damages to TGH of approximately $21 million USD, plus interest from October 21, 2010 at a rate equal to the U.S. prime rate plus 2 per cent.

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.

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.

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On April 5, 2016, an ICSID ad hoc Committee issued a decision in favour 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 million USD 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. As a result, TGH had the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21 million USD), as well as additional interest on the $21 million USD, and its full costs relating to the original arbitration and the new arbitration proceeding.

On September 23, 2016, TGH filed a request for resubmission to arbitration. On October 3, 2016, ICSID issued a notice of registration for TGH’s request for resubmission. A new tribunal has been constituted and it issued its first procedural order. TGH’s memorial is due on September 1, 2017. In addition, TGH has sued Guatemala in Washington, D.C. court to enforce the $21 million USD due and owing. Results to date do not reflect any benefit.

Superfund and Former Manufactured Gas Plant Sites

TEC, through its Tampa Electric and PGS divisions, is a potentially responsible party (“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 at June 30, 2017, TEC has estimated its ultimate financial liability to be $40 million ($30 million USD), primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Condensed Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years.

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. The FPSC has approved, as part of the PGS depreciation settlement, an agreement to accelerate the amortization of the regulated asset associated with this reserve.

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 FERC alleging that the 11.14 per cent base 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 (the “FERC Order”) in connection with this complaint that changed the methodology used to set the ROE and resulted in a lower base transmission ROE of 10.57 per cent and a lower total ROE (inclusive of incentive adders) of 11.74 per cent for the period of October 1, 2011 to December 31, 2012. The ROE was confirmed by FERC in two subsequent orders and the FERC Order was appealed by a group of New England Transmission Owners, including Emera Maine and by customers, to the U.S. Court of Appeals for the District of Columbia Circuit. On June 30, 2016, Emera Maine completed the processing of refunds to customers to reflect the 10.57 per cent ROE. On April 14, 2017, the U.S. Court of Appeals vacated the FERC Order. The Court concluded that FERC failed to make an explicit finding that the existing base ROE of 11.14 per cent was unjust and unreasonable, and failed to provide any reasoned basis for selecting 10.57 per cent as the new base ROE. The Court remanded the case to the FERC for further proceedings consistent with the Court’s order.

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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”). This complaint applies to the period from January 1, 2013 to 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 on similar grounds (“the MA AG II Case”) in relation to the period from July 31, 2014 to October 31, 2015. The ENE Case and MA AG II Case were subsequently consolidated by FERC into a single case.

On March 22, 2016, a FERC Administrative Law Judge (“ALJ”) issued a recommended decision to FERC with respect to the consolidated cases. 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 the MA AG II Case was a 10.90 per cent base ROE, with a 12.19 per cent maximum ROE. The ALJ’s recommended decision is not definitive and FERC has the ability to adjust the ALJ’s recommended decision. A decision by FERC is not expected until Q4 2017.

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 ROE to 8.61 per cent and the maximum ROE to 11.24 per cent for the period April 29, 2016 to July 29, 2017.

Emera Maine has recorded a reserve of $4 million USD for the ENE Case and MA AG II Case. The reserves recorded for these complaints have been recorded as “Regulatory liabilities” on the Condensed Consolidated Balance Sheets and as a reduction to “Operating revenues – regulated electric” on the Condensed 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. No change in reserves has been made in relation to the first FERC ROE complaint as a result of the D.C. Court of Appeals vacating the FERC Order 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. 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 assets or liquidity or capital resources in the near term. 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 to risk management.

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. As cost-of-service utilities with an obligation to serve customers, Tampa Electric, PGS, NMGC, NSPI, Emera Maine, BLPC, GBPC, and Domlec must

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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 as an adjustment 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 (including shifts in policy which could occur as a result of climate change concerns) and changes in governments. Emera’s investments in entities in which it has significant influence and which are subject to regulatory risk include: NSPML, LIL, M&NP and Lucelec.

During public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate-regulated companies and their respective regulators determine whether to allow recovery and to adjust rates based upon the 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.

Weather and Climate Risk

Shifts in weather patterns affect energy sales and associated revenues and costs. Extreme weather events generally result in increased operating costs associated with restoring service to customers as a result of unplanned outages. Emera responds to outages which occur as a result of significant weather events according to each subsidiary’s respective emergency services restoration plan.

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. In addition, Emera’s business could be materially affected by changes in government policy, utility regulation, and environmental and other legislation that could occur in response to environmental and climate change concerns.

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.

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Foreign Exchange Risk

The Company is exposed to foreign currency exchange rate changes. Emera operates globally, with an increasing amount of the Company’s adjusted net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the Canadian dollar and, particularly, the US dollar, which could positively or adversely affect results.

Consistent with the Company’s risk management policies, Emera manages currency risks through matching US denominated debt to finance its US operations and uses short-term foreign currency derivative instruments to hedge specific transactions. 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.

The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes, or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries are included in AOCI.

Capital Market and Liquidity Risk

Emera’s 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. After giving effect to the TECO Energy acquisition, Emera now has total debt of $15 billion. 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.

Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the company’s business and regulatory framework, the ability to recover costs and earn returns, diversification, leverage, and liquidity. A change to a credit rating as a result of changes in any of these items 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.

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting 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.

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.

For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. While regulatory ROE will generally 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.

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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 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.

Income Tax Risk

The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred tax benefits are determined by existing tax laws and could be negatively impacted by changes in 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 the corporate income tax rate. Although a reduction in the corporate income tax rate could result in lower future tax expense and tax payments, it would also reduce the value of the Company’s existing deferred tax assets and could result in a charge to earnings if written down. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results.

D. Guarantees and Letters of Credit

Emera’s guarantees and letters of credit are consistent with those disclosed in the 2016 audited consolidated financial statements, with the exception of the items noted below.

TECO Coal was sold on September 21, 2015 to Cambrian Coal Corporation (“Cambrian”). Pursuant to the sales agreement, Cambrian is obligated to file, in respect of each mining permit, applications in connection with the change of control with the appropriate governmental entities. As each application is approved, Cambrian is required to post a bond or other appropriate collateral in order to obtain the release of the corresponding bond secured by the TECO Energy indemnity for that permit. As at June 30, 2017, TECO Energy had remaining indemnified bonds totaling $9 million ($7 million USD).

The amounts outlined above represent the maximum theoretical amounts that TECO Energy would be required to pay to the surety companies.

The Company is working with Cambrian on the process to replace the remaining bonds. Pursuant to the securities purchase agreement, 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.

Emera has a standby letter of credit in the amount of $21 million to guarantee the performance of the obligations of the EUS-Rokstad joint venture. The letter of credit expires in August 2017. EUS-Rokstad is a joint venture between EUS and Rokstad Power, formed for the purpose of constructing the high voltage direct current components of NSPML’s transmission line. Rokstad Power has issued a separate letter of credit to Emera for their portion of the work to be performed under the contract. EUS and Rokstad Power are jointly and severally liable for completion of the project.

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Emera has standby letters of credit in the amount of $21 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.

Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under an unfunded pension plan. The letter of credit expires in June 2018 and is renewed annually. The amount committed as at June 30, 2017 was $51 million.

20. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the millions of Canadian dollars	Six months ended June 30
	2017		2016
Changes in non-cash working capital:
Receivables, net	$	68	$	78
Income taxes receivable		(7)		(29)
Inventory		(8)		43
Prepayments and other current assets		(31)		(23)
Accounts payable		(203)		39
Income taxes payable		(16)		16
Other current liabilities		(25)		27
Total non-cash working capital	$	(222)	$	151
Supplemental disclosure of non-cash activities:
Common share dividends reinvested	$	82	$	44

21. VARIABLE INTEREST ENTITIES

The Company performs ongoing analysis to assess whether it holds any Variable Interest Entities (“VIE”). 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.

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. In Q2 2014, when the critical milestones were achieved, 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.

BLPC 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

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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. Emera’s consolidated VIE in the SIF is recorded as an “Investment securities”, “Restricted cash” and “Regulatory liabilities” on the Condensed Consolidated Balance Sheets.

The Company has identified certain long-term purchase power agreements that meet the definition of 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.

The following table provides information about Emera’s portion of significant unconsolidated VIEs:

As at	June 30, 2017				December 31, 2016
millions of Canadian dollars	Total assets		Maximum exposure to loss		Total assets		Maximum exposure to loss
Unconsolidated VIEs in which Emera has variable interests
NSPML (equity accounted)	$	436	$	282	$	315	$	577

22. 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.

23. SUBSEQUENT EVENTS

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through August 10, 2017, the date the financial statements were issued.

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EX-99.3

Exhibit 99.3

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Christopher G. Huskilson, President and Chief Executive Officer of Emera Incorporated, certify the following:

1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended June 30, 2017.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

A. designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

i. material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

ii. information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

B. designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.

5.2 ICFR – material weakness relating to design: N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

a. the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of:

i. a proportionately consolidated entity in which the issuer has an interest;

ii. a special purpose entity in which the issuer has an interest; or

iii. a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and

b. summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements.

6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2017 and ended on June 30, 2017 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: August 10, 2017

“Christopher G. Huskilson”

Christopher G. Huskilson

President and Chief Executive Officer

EX-99.4

Exhibit 99.4

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Greg Blunden, Chief Financial Officer of Emera Incorporated, certify the following:

1. Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Emera Incorporated (the “issuer”) for the interim period ended June 30, 2017.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4. Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5. Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

A. designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

i. material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

ii. information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

B. designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (COSO) Internal Control-Integrated Framework.

5.2 ICFR – material weakness relating to design: N/A

5.3 Limitation on scope of design: The issuer has disclosed in its interim MD&A

a. the fact that the issuer’s other certifying officer(s) and I have limited the scope of our design of DC&P and ICFR to exclude controls, policies and procedures of:

i. a proportionately consolidated entity in which the issuer has an interest;

ii. a special purpose entity in which the issuer has an interest; or

iii. a business that the issuer acquired not more than 365 days before the last day of the period covered by the interim filings; and

b. summary financial information about the proportionately consolidated entity, special purpose entity or business that the issuer acquired that has been proportionately consolidated or consolidated in the issuer’s financial statements.

6. Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2017 and ended on June 30, 2017 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: August 10, 2017

“Greg Blunden”

Greg Blunden

Chief Financial Officer

EX-99.5

Exhibit 99.5

Emera Incorporated

Earnings Coverage Ratio

Pursuant to Section 8.4 of National Instrument 44-102, this updated calculation of the earnings coverage ratio is filed as an exhibit to the unaudited condensed consolidated financial statements of Emera Incorporated (“Emera”) for the six months ended June 30, 2017.

The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended June 30, 2017.

	Twelve months ended June 30, 2017
Earnings Coverage (1)		1.61

⁽¹⁾  Earnings coverage is equal to consolidated net income attributable to common shareholders plus: income taxes, interest on debt, amortization of debt financing costs, allowance for funds used during construction and preferred share dividends declared during the period together with undeclared preferred share dividends, if any, divided by interest on debt plus amortization of debt financing costs plus allowance for funds used during construction plus capitalized interest plus preferred dividends grossed up to a before-tax equivalent using an effective tax rate of 28.6 percent.

Emera’s dividend requirements on all of its preferred shares, grossed up to a before-tax equivalent using an effective income tax rate of 28.6 percent, amounted to $42 million for the twelve months ended June 30, 2017. Emera’s interest requirements for the twelve months ended June 30, 2017 amounted to $707 million. Emera’s consolidated income before interest and income tax for the twelve months ended June 30, 2017 was $1,208 million, which is 1.61 times Emera’s aggregate preferred dividends and interest requirements for this period.

EX-99.6

Exhibit 99.6

Emera Reports Q2 2017 Earnings

HALIFAX, Nova Scotia, August 10, 2017: Emera (TSX: EMA) today reported results for the second quarter of 2017.

Q2 2017 Highlights:

Reported Net Income:

• Reported Q2 2017 net income of $101 million, compared with net income of $208 million in Q2 2016.

• Reported earnings per common share in Q2 2017 were $0.47, compared with $1.39 per common share in Q2 2016.

Adjusted Net Income (excluding after-tax mark-to-market impacts):

• Adjusted net income ⁽¹⁾ was $117 million, or $0.55 per common share, in Q2 2017, compared with $238 million or $1.59 per common share in Q2 2016. Excluding the Q2 2016 gains, acquisition costs and tax adjustment Q2 2016 adjusted earnings would have been $50 million, or $0.34 on a per share basis.

• After-tax mark-to-market losses decreased $14 million to $16 million in Q2 2017 compared to $30 million in Q2 2016 mainly due to changes in existing positions on long-term natural gas contracts at Emera Energy.

• Q2 2017 adjusted net income ⁽¹⁾ included a contribution of $58 million from Emera Florida and New Mexico, net of the $45 million of permanent financing cost.

	Net income Three months ended June 30					Earnings per share Three months ended June 30
In millions of $CAD, except per share amounts	2017		2016			2017		2016
Adjusted	$	117	$	238		$	0.55	$	1.59
Gain on Algonquin Power & Utilities Corp (APUC) shares		—		(146	)		—		(0.97	)
Gain on conversion of APUC subscription receipts		—		(53	)		—		(0.35	)
Barbados Light & Power Company Self Insurance Fund (SIF) liability reduction		—		(43	)		—		(0.29	)
TECO acquisition costs		—		42			—		0.28
Emera Energy prior period fuel tax recognition		—		12			—		0.08
Adjusted excluding one-time items	$	117	$	50		$	0.55	$	0.34

Cash Flow ⁽¹⁾

• In 2017, year-to-date operating cash flow (before changes in working capital) increased $378 million, or 116 percent, to $703 million from $325 million in the 2016 period.

“Our second quarter results reflect Emera’s enhanced earning power and less seasonality from the combined businesses, as well as strong earnings across our regulated businesses,” said Emera’s President and CEO Chris Huskilson. “Our earnings and cash flow, combined with the steady progress on our capital plans, support Emera’s long-term prospects and dividend growth target.”

“Our financial success this quarter is overshadowed by the accident at TECO’s Big Bend facility and our deepest condolences are with the families of those who passed and were injured. This tragic incident has impacted all of us across Emera deeply and we are more focused than ever before on having world class safety programs, where all of our employees go home safely every day.” Huskilson added.

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2017 Year-to-Date Highlights

Reported Net Income:

• Reported net income of $413 million, compared with $252 million in the 2016 period.

• Reported earnings per share of $1.95, compared with $1.69 in the 2016 period

Adjusted Net Income ⁽¹⁾

• Adjusted net income was $269 million, or $1.27 per common share, compared with $358 million or $2.40 per common share, in the 2016 period. Adjusted net income in the 2016 period, excluding the Q2 2016 items noted above and the $18 million Q1 2016 TECO Energy acquisition costs was $188 million, or $1.26 on a per common share basis.

• Earnings per share increased only slightly in 2017 despite the 43 percent increase in adjusted net income, excluding 2Q 2016 one-time items, due to the new shares issued in August 2016 in conjunction with the TECO acquisition and the December 2016 equity issue.

• Year-to-date, after-tax mark-to-market increased $250 million to a $144 million gain in 2017 compared to a $106 million loss for the same period in 2016. 2016 included a $117 million loss resulting from the reversal of 2015 gains on USD-denominated currency and forward contracts related to the financing of the TECO Energy acquisition. In addition, losses have decreased due to changes in existing positions on long-term contracts at Emera Energy, and the reversal of 2016 mark-to-market losses at Emera Energy.

• Adjusted net income included a contribution of $92 million from Emera Florida and New Mexico, net of the $90 million of permanent financing costs.

	Net income Six months ended June 30					Earnings per share Six months ended June 30
In millions of $CAD, except per share amounts	2017		2016			2017		2016
Adjusted	$	269	$	358		$	1.27	$	2.40
Gain on Algonquin Power & Utilities Corp (APUC) shares		—		(146	)		—		(0.98	)
Gain on conversion of APUC subscription receipts		—		(53	)		—		(0.36	)
Barbados Light & Power Company Self Insurance Fund (SIF) liability reduction		—		(43	)		—		(0.29	)
TECO acquisition costs		—		60			—		0.40
Emera Energy fuel tax recognition		—		12			—		0.08
Adjusted excluding one-time items	$	269	$	188		$	1.27	$	1.26

Financial Highlights (in millions of $CAD, except per share amounts)

	Three months ended June 30						Six months ended June 30
	2017			2016			2017		2016
Net income attributable to common shareholders	$	101		$	208		$	413	$	252
After-tax mark-to-market gain (loss)	$	(16	)	$	(30	)	$	144	$	(106	)
Adjusted net income attributable to common shareholders (1)(2)	$	117		$	238		$	269	$	358
Earnings per common share - basic	$	0.47		$	1.39		$	1.95	$	1.69
Adjusted earnings per common share - basic (1)(2)	$	0.55		$	1.59		$	1.27	$	2.40
Weighted average shares of common stock outstanding - basic (millions of shares for the three months ended June 30)		213			150			212		149

⁽¹⁾ See “Non-GAAP Measures” noted below.

⁽²⁾ Adjusted net income ⁽¹⁾ and Adjusted earnings per common share ⁽¹⁾ exclude the effect of mark-to-market adjustments.

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Consolidated Financial Review:

Below is a table highlighting significant changes between adjusted net income from 2016 to 2017 in the second quarter and year-to-date periods.

For the millions of Canadian dollars	Three months ended June 30			Six months ended June 30
Adjusted net income – 2016	$	238		$	358
Emera Florida and New Mexico		103			182
2016 Acquisition and financing costs related to the acquisition of TECO Energy		42			60
Emera Energy (1)		6			(32	)
2016 Emera Energy’s recognition of fuel taxes for 2013 through March 2016		12			12
NSPML and LIL AFUDC earnings		8			15
NSPI		1			18
2016 gain on BLPC SIF regulatory liability		(43	)		(43	)
TECO Energy post-acquisition financing costs		(45	)		(90	)
2016 gain on conversion of APUC subscription receipts and dividend equivalents to common shares of APUC		(53	)		(53	)
2016 gain on sale of APUC common shares		(146	)		(146	)
Other		(6	)		(12	)
Adjusted net income – 2017	$	117		$	269

⁽¹⁾  Excludes the effect of mark-to-market adjustments.

Segment Results

Emera reports its results in six operating segments: Emera Florida and New Mexico, Nova Scotia Power Inc., Emera Maine, Emera Caribbean, Emera Energy, and Corporate & Other.

Segmented Results (in millions of $CAD, except per share amounts)

	Three months ended June 30						Six months ended June 30
	2017			2016			2017			2016
Emera Florida and New Mexico	$	103		$	—		$	182		$	—
Nova Scotia Power Inc.		29			28			99			81
Emera Maine		12			10			25			19
Emera Caribbean		11			58			18			68
Emera Energy (2)		(11	)		(29	)		(1	)		19
Corporate & Other (2)		(27	)		171			(54	)		171
Adjusted net income	$	117		$	238		$	269		$	358
Adjusted EPS (basic) (1)	$	0.55		$	1.59		$	1.27		$	2.40

⁽¹⁾  See “Non-GAAP Measures” noted below.

⁽²⁾  Adjusted net income ⁽¹⁾ excludes after-tax mark-to-market loss in Pipelines, Emera Energy, and Corporate and Other

Emera Florida and New Mexico’s net income was $103 million in Q2 2017, compared with $82 million in Q2 2016. Comparative information is presented for information only as Emera did not own the Emera Florida and New Mexico operations in the Q2 or year-to-date periods in 2016. Q2 2017 results were driven primarily by higher base revenues effective January 2017 when the Polk Power Station expansion entered service; higher electricity sales resulting from strong customer growth; and warmer than normal spring weather at Tampa Electric. The net contribution to adjusted net income was $58 million or $0.27 per common share net of the $45 million in after-tax permanent financing cost of the TECO Energy acquisition. Year-to-date 2017 net income was $182 million, essentially unchanged from the 2016 period, which reflects mild winter weather in Florida and New Mexico offset by customer growth, favorable second quarter weather and higher base revenues. Net of the $90 million of permanent financing cost, Emera Florida and New Mexico contributed $92 million, or $0.43 per common share, in the year-to-date 2017 period.

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Nova Scotia Power Inc.’s net income was consistent for the quarter at $29 million in Q2 2017, compared with $28 million in Q2 2016. NSPI’s net income year-to-date was $99 million compared to $81 million for the same period last year driven by lower OM&G and lower provision for income taxes partially offset by higher depreciation.

Emera Maine’s net income was $12 million Q2 2017, compared to Q2 2016 net income of $10 million. Emera Maine’s net income year-to-date was $25 million compared to $19 million for the same period last year. Year-to-date 2017 results were driven by lower OM&G and higher electric revenues as a result of transmission and distribution rate changes

Emera Caribbean’s net income of $11 million in Q2 2017 compared with $58 million in Q2 2016. Results in 2016 reflect the $43 million after-tax gain from the BLPC SIF as a result of the reduction in the regulatory liability. Excluding the 2016 gain, results reflect lower energy sales volumes at GBPC due to the continued effects of Hurricane Matthew, which struck Grand Bahama in October 2016 and higher interest charges on new debt issued in Q4 2016. Emera Caribbean’s net income year-to-date was $18 million compared to $68 million for the same period last year, driven by the same factors as Q2.

Emera Energy’s net loss, adjusted to exclude mark-to-market changes, was $11 million in Q2 2017 compared to a loss of $29 million in Q2 2016. Overall market conditions were comparable quarter over quarter. The increase is mainly due to the recognition in Q2 2016 of $12 million after tax of prior period state fuel taxes, lower short-term fixed cost commitments for transportation and more valuable transportation positions in Q2 2017; partially offset by the impact of an unplanned outage at Bridgeport Energy which extended from mid-March 2017 to mid-June 2017. Emera Energy’s adjusted net loss year-to-date was $1 million compared to adjusted net income of $19 million for the same period last year. Year-to-date 2017 results were driven by lower realized energy margins in the New England generating fleet in Q1, reflecting more favorable short-term economic hedges in 2016 compared to 2017; and less favorable transportation capacity hedges in Q1 2017 coupled with increased gas transportation infrastructure in the northeast United States which reduced volatility; partially offset by the Q2 2017 factors noted above.

Corporate & Other’s net loss, adjusted to exclude mark-to-market changes, was $27 million in Q2 2017 compared to adjusted net income of $171 million in Q2 2016. This was primarily due to interest expense as a result of interest on the permanent financing of the TECO acquisition partially offset by a combined $8 million higher AFUDC earnings on the NSPML and LIL transmission projects. Results in Q2 2016 included the $199 million of after-tax gains on the sale of the APUC shares and the conversion of the APUC subscription receipts in the second quarter of 2016, and $42 million of acquisition costs. Corporate & Other’s adjusted loss was $54 million for the year-to-date 2017 period compared to adjusted net income of $171 million for the same period last year. Year-to-date 2016 results include $60 million of after - tax TECO acquisition costs.

⁽¹⁾ Non-GAAP 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 and non-GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period. Refer to the Non-GAAP Financial Measures section of our Management’s Discussion and Analysis (“MD&A”) for further discussion of these items.

Forward Looking Information

This news release contains forward-looking information within the meaning of applicable securities laws. By its nature, forward-looking information requires Emera to make assumptions and is subject to inherent risks and uncertainties. These statements reflect Emera management’s current beliefs and are based on information currently available to Emera management. There is a risk that predictions, forecasts, conclusions and projections that constitute forward-looking information will not prove to be accurate, that Emera’s assumptions may not be correct and that actual results may differ materially from such forward-looking information. Additional detailed information about these assumptions, risks and uncertainties is included in Emera’s securities regulatory filings, including under the heading “Business Risks and Risk Management” in Emera’s annual Management’s Discussion and Analysis, and under the heading “Principal Risks and Uncertainties” in the notes to Emera’s annual and interim financial statements, which can be found on SEDAR at www.sedar.com.

Teleconference Call

The company will be hosting a teleconference Friday, August 11, 2017 at 11:00am Atlantic time (10:00am Toronto/Montreal/New York; 9:00am Winnipeg; 8:00am Calgary; 7:00am Vancouver) to discuss the Q2 2017 financial results.

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Analysts and other interested parties in North America wanting to participate in the call should dial 1-866-521-4909 at least 10 minutes prior to the start of the call. International participants wanting to participate should dial 1-647-427-2311. No pass code is required. The teleconference will be recorded. If you are unable to join the teleconference live, you can dial for playback, toll-free at 1-800-585-8367. The Conference ID is 53138266 (available until midnight, September 1, 2017).

The teleconference will also be web cast live at emera.com and available for playback for one year.

About Emera

Emera Inc. is a geographically diverse energy and services company headquartered in Halifax, Nova Scotia with approximately $29 billion in assets and 2016 revenues of more than $4 billion. The company invests in electricity generation, transmission and distribution, gas transmission and distribution, and utility energy services with a strategic focus on transformation from high carbon to low carbon energy sources. Emera has investments throughout North America, and in four Caribbean countries. Emera continues to target having 75-85% of its adjusted earnings come from rate-regulated businesses. Emera’s common and preferred shares are listed on the Toronto Stock Exchange and trade respectively under the symbol EMA, EMA.PR.A, EMA.PR.B, EMA.PR.C, EMA.PR.E, and EMA.PR.F. Depositary receipts representing common shares of Emera are listed on the Barbados Stock Exchange under the symbol EMABDR. Additional Information can be accessed at www.emera.com or at www.sedar.com.

For more information, please contact:

Mark Kane

Vice President, Investor Relations

(813) 228-1772

Neera Ritcey

Manager, Investor Relations

(902) 428-6059

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