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 February, 2012

Commission File Number: 333-172405

Emera Incorporated

(Exact name of registrant as specified in its charter)

1223 Lower Water Street

P.O. Box 910

Halifax NS B3J 3S8

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 þ

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):            

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨     No þ

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-            

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.

Date: February 14 , 2012	EMERA INCORPORATED
	By:	“Stephen D. Aftanas”
		Name: Stephen D. Aftanas
		Title: Corporate Secretary

2

EXHIBIT INDEX

Exhibit No.	Description
99.1	Emera Incorporated Management’s Discussion and Analysis for the year ended December 31, 2011
99.2	Emera Incorporated audited comparative consolidated financial statements as at and for the years ended December 31, 2011and December 31, 2010
99.3	Form 52-109F1 Certification of Annual Filings by the Chief Executive Officer
99.4	Form 52-109F1 Certification of Annual Filings by the Chief Financial Officer
99.5	Emera Incorporated Earnings Coverage Ratio for the Twelve Months Ended December 31, 2011
99.6	Emera Incorporated Media Release dated February 10, 2012

3

EX-99.1

Exhibit 99.1

Management’s Discussion & Analysis

As at February 10, 2012

Management’s Discussion and Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its primary subsidiaries and investments (“Emera”) during the fourth quarter of 2011 relative to 2010; and the full year 2011 relative to 2010 and 2009; and its financial position as at December 31, 2011 relative to 2010. 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.

Effective January 1, 2011, Emera changed the basis of presentation of its financial statements, including the application of rate-regulated accounting policies for Emera’s rate-regulated subsidiaries, from Canadian Generally Accepted Accounting Principles (“CGAAP”) to United States Generally Accepted Accounting Principles (“USGAAP”) for information derived from the Consolidated Statements of Income for the three months and year ended December 31, 2011 and Consolidated Balance Sheets as at December 31, 2011. Financial information for 2010 and 2009 has been adjusted to reflect USGAAP and is clearly labeled “adjusted”.

This discussion and analysis should be read in conjunction with the Emera Incorporated annual audited consolidated financial statements and supporting notes as at and for the year ended December 31, 2011, prepared in accordance with USGAAP.

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, revenue and expenses. Emera’s rate-regulated subsidiaries include:

Emera Rate-Regulated Subsidiary	Accounting Policies Approved/Examined By
Nova Scotia Power Inc. (“NSPI”)	Nova Scotia Utility and Review Board (“UARB”)
Bangor Hydro Electric Company (“Bangor Hydro”)	Maine Public Utilities Commissions (“MPUC”) and the Federal Energy Regulatory Commission (“FERC”)
Maine Public Service Company (“MPS”)	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”)
Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)	National Energy Board (“NEB”)

All amounts are in Canadian dollars (“CAD”) except for the Maine Utility Operations section of the MD&A, which is 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 or on EDGAR at www.sec.gov.

1

Forward Looking Information

This MD&A contains “forward-looking information” within the meaning of applicable Canadian securities laws and “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words “anticipates”, “believes”, “could”, “estimates”, “expects”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words.

The forward-looking information in this MD&A includes statements which reflect the current view with respect to the Company’s objectives, plans, financial and operating performance, business prospects and opportunities. 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 times at which, such events, performance or results will be achieved.

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations are discussed in the Outlook section of the MD&A and may also include: regulatory risk; operating and maintenance risks; economic conditions; availability and price of energy and other commodities; capital resources and liquidity risk; weather; commodity price risk; competitive pressures; construction; derivative financial instruments and hedging availability and cost of financing; interest rate risk; counterparty risk; competitiveness of electricity as an energy source; commodity supply; environmental risks; foreign exchange; regulatory and government decisions including changes to environmental, financial reporting and tax legislation; loss of service area; 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.

2

Structure of MD&A

This MD&A begins with an Introduction and Strategic Overview; followed by the Consolidated Financial Review of the Statements of Income, Balance Sheets, Statements of Cash Flows, and outstanding share data; then presents information separately on Emera’s consolidated subsidiaries and investments, specifically:

• NSPI;

• Maine Utility Operations (Bangor Hydro, MPS and its parent company, Maine and Maritimes Corporation (“MAM”));

• Caribbean Utility Operations (BLPC and its parent company, Light & Power Holdings Ltd. (“LPH”), GBPC and St. Lucia Electricity Services Limited (“Lucelec”));

• Pipelines (Brunswick Pipeline and Maritimes & Northeast Pipeline (“M&NP”));

• Other operations and investments are grouped and discussed under Services, Renewables and Other Investments (“SRO”) and include:

o Emera Energy Inc. (“Emera Energy”) includes (Emera Energy Services, Bayside Power Limited Partnership (“Bayside Power”), Bear Swamp Power Company LLC. (“Bear Swamp”)),

o Emera Utility Services Inc. (“EUS”),

o Emera Newfoundland & Labrador Holdings Inc. (“ENL”),

o Algonquin Power & Utilities Corp. (“APUC”),

o California Pacific Utilities Ventures, LLC (“CPUV”) and

o Atlantic Hydrogen Inc. (“AHI”); and

• Corporate

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

INTRODUCTION AND STRATEGIC OVERVIEW

Emera Incorporated is an energy and services company with $6.9 billion in assets. The Company invests in electricity generation, transmission and distribution, gas transmission and utility energy services. Emera’s strategy is focused on the transformation of the electricity industry to cleaner generation and the delivery of that cleaner energy to market. Emera has interests throughout northeastern North America, in three Caribbean countries and in California.

Emera’s goal is to increase earnings per share by an average of 4 percent to 6 percent annually and to build and diversify its income base with a focus on cleaner energy in its markets. Emera will continue to build its existing business and will leverage its core strength in the electricity business to pursue acquisitions and greenfield development opportunities in regulated electricity transmission, distribution and lower risk generation.

Approximately 85 percent of Emera’s net income is earned by its rate-regulated subsidiaries. The success of these subsidiaries is integral to the creation of shareholder value, providing strong, predictable income and cash flows to fund dividends and reinvestment.

3

Non-GAAP Financial Measures

Emera uses financial measures that do not have a standardized meaning under USGAAP.

NSPI

“Electric margin” is a non-GAAP financial measure used by NSPI and is defined as “Electric revenues” less “Regulated fuel for generation and purchased power” and “Regulated fuel for generation and purchased power – affiliates”, net of the “Regulated fuel adjustment”, fuel-related foreign exchange gains or losses and other fuel-related costs. This measure is disclosed as management believes it provides useful information regarding the effect of the fuel adjustment mechanism (“FAM”) on NSPI’s operations. Electric margin is discussed further in the Consolidated Financial Review – Consolidated Financial Highlights section and the NSPI – Review of 2011 section.

Services, Renewables and Other Investments

“Net income applicable to common shares, absent the Bear Swamp after-tax mark-to-market adjustment”, “Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment”, “Contribution to consolidated net income, absent the Bear Swamp after-tax mark-to-market adjustment” and “Contribution to consolidated net earnings per common share, absent the Bear Swamp after-tax mark-to-market adjustment” are non-GAAP financial measures used by Emera. Management discloses these financial measures as it believes the inclusion of the mark-to-market adjustment in Bear Swamp’s financial results does not accurately reflect its operational performance. The adjustment is discussed further in the Consolidated Financial Review – Consolidated Financial Highlights section, Consolidated Financial Review – Significant Items section, and Services, Renewables and Other Investments – Review of 2011 section.

Earnings before interest and taxes (“EBIT”) is a non-GAAP financial measure used by Emera and is defined as Income before “Interest expense, net” and “Income tax expense (recovery)”. This measure is disclosed as management believes it provides useful information on how it views the operations of Emera Energy and EUS. EBIT is discussed in the Services, Renewables and Other Investments – Review of 2011 section.

4

CONSOLIDATED FINANCIAL REVIEW

Consolidated Financial Highlights

For the   millions of Canadian dollars (except per share amounts)	Three months ended December 31						Year ended December 31
	2011			2010 (adjusted)			2011			2010 (adjusted)			2009 (adjusted)
Operating revenues		$512.0			$408.9			$2,064.4			$1,606.1			$1,490.1
Net income attributable to common shareholders		46.8			24.1			241.1			190.7			186.3
Earnings per common share – basic		$0.38			$0.21			$1.99			$1.67			$1.65
Earnings per common share – diluted		$0.38			$0.21			$1.97			$1.65			$1.61
Dividends per common share declared		-			-			$1.3125			$1.1625			$1.0300
For the   millions of Canadian dollars (except per share amounts)	Three months ended December 31						Year ended December 31
Operating Unit Contributions	2011			2010 (adjusted)			2011			2010 (adjusted)			2009 (adjusted)
NSPI		$22.2			$19.9			$123.5			$119.2			$110.8
Maine Utility Operations		9.8			7.8			37.0			31.9			27.5
Caribbean Utility Operations		3.1			(7.7	)		46.8			19.8			2.9
Pipelines		6.9			8.0			27.9			28.9			30.1
Services, Renewables and Other Investments		6.0			1.8			27.0			8.6			14.7
Corporate		(1.2	)		(5.7	)		(21.1	)		(17.7	)		0.3
Net income attributable to common shareholders		$46.8			$24.1			$241.1			$190.7			$186.3
Net income applicable to common shares, absent the Bear Swamp after-tax mark-to-market adjustment		$47.5			$26.7			$241.9			$199.3			$185.6
Earnings per common share – basic		$0.38			$0.21			$1.99			$1.67			$1.65
Earnings per common share – basic, absent the Bear Swamp after-tax mark-to- market adjustment		$0.39			$0.23			$2.00			$1.75			$1.64

	As at December 31
	2011		2010 (adjusted)		2009 (adjusted)
Total assets	$	6,923.6	$	6,079.0	$	5,247.3
Total long-term liabilities		4,298.2		3,941.7		2,955.8

5

Highlights of the changes are summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31			Year ended December 31
Consolidated net income attributable to common shareholders – 2009 (adjusted)					$186.3
NSPI – Increased net income primarily due to decreased income taxes partially offset by increased operating, maintenance and general expenses (“OM&G”) and decreased electric margin					8.4
Maine Utility Operations – Increased net income primarily due to transmission rate increases and increased transmission pool revenue related to recovery of regionally funded transmission investments, partially offset by a stronger average CAD in 2010					4.4
Caribbean Utility Operations – Increased primarily due to initial investment in LPH offset in part by GBPC acquisition-related costs					16.9
Pipelines – Decreased net income primarily due to decreased income from M&NP equity investment					(1.2	)
Services, Renewables and Other Investments – Decreased net income primarily due to an unfavorable change in the fair value of the net derivatives in Bear Swamp, partially offset by increased earnings in Emera Energy and EUS					(6.1	)
Corporate – Increased primarily due to increased interest expense and acquisition-related costs					(18.0	)
Consolidated net income attributable to common shareholders – 2010 (adjusted)		$24.1			$190.7
NSPI – Increased net income primarily due to increased income tax recovery, partially offset by decreased electric margin and increased OM&G expenses		2.3			4.3
Maine Utility Operations – Increased net income during the quarter primarily due to lower OM&G expenses in Bangor Hydro, partially offset by a decrease in electric revenue; increased net income year-over-year primarily due to the recovery of a greater amount of regionally funded transmission investments, lower OM&G expenses and the acquisition of MAM in Q4 2010		2.0			5.1
Caribbean Utility Operations – Increased net income during the quarter primarily due to increased ownership of both GBPC and LPH. Year-over-year increase also reflects incremental $5.8 million gain on the acquisition of LPH recorded in 2011 versus 2010; and increased earnings in GBPC		10.8			27.0
Pipelines – Decreased net income primarily due to decreased income from M&NP equity investment		(1.1	)		(1.0	)
Services, Renewables and Other Investments – Increased net income during the quarter due primarily to a positive change in the fair value of the net derivatives in Bear Swamp. Increased year-over-year net income primarily due to gain on APUC subscription receipts and a positive change in the fair value of the net derivatives in Bear Swamp		4.2			18.4
Corporate – Decreased costs during the quarter primarily due to decreased deferred compensation, lower business acquisition costs and foreign exchange gains; Increased costs year-over-year primarily due to higher financing costs partially offset by a higher income tax recovery		4.5			(3.4	)
Consolidated net income attributable to common shareholders – 2011		$46.8			$241.1

Basic earnings per share were $0.38 in Q4 2011 compared to $0.21 in Q4 2010 (adjusted); and $1.99 for the full year 2011 compared to $1.67 in 2010 (adjusted) and $1.65 in 2009 (adjusted).

6

Developments

Emera

Strategic Investment Agreement with Algonquin Power & Utilities Corp.

Emera has a Strategic Investment Agreement (“SIA”) with Algonquin Power & Utilities Corp (“APUC” or “Algonquin”) which establishes how Emera and APUC will work together to pursue specific strategic investments of mutual benefit. The SIA outlines “areas of pursuit” for both Emera and APUC. For Emera, these include investment opportunities related to regulated renewable generation and transmission projects within its service territories, and large electric utilities. For Algonquin, these include investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. Emera is committed to working with Algonquin on opportunities that fit within Algonquin’s “areas of pursuit”.

The SIA also provides for Emera to acquire up to 25% of APUC through the purchase of common shares issued by APUC to fund certain investment opportunities developed in conjunction with Emera under the SIA. The share purchases are executed via the acquisition of subscription receipts in exchange for promissory notes at an agreed upon price, which are then exchangeable into common shares when certain conditions relating to specific transactions are met. The acquisition of subscription receipts is subject to approvals required under applicable laws, including the rules of the Toronto Stock Exchange (“TSX”).

Emera and Algonquin are currently working to complete two such transactions, as set out below:

California Pacific Transaction

On January 1, 2011, Emera and APUC closed their acquisition of the California-based electricity distribution and related generation assets of NV Energy, Inc. for total consideration of $136.8 million CAD ($137.5 million USD), subject to final adjustments. A new utility company, California Pacific Electric Company, LLC (“California Pacific”) was established to own and operate the assets. California Pacific is wholly-owned by California Pacific Utilities Ventures LLC (“CPUV”), which in turn is owned 49.999 percent by Emera and 50.001 percent by APUC. Emera paid $31.8 million CAD ($31.2 million USD) for its interest in the common shares of CPUV.

Pursuant to an April 2009 Subscription Receipts Agreement with APUC, upon the closing of the California Pacific transaction in Q1 2011, as described above, Emera exchanged subscription receipts acquired in 2009 into 8.523 million APUC common shares issued at $3.25 per share, resulting in an after-tax gain of $12.8 million. This gain is recorded in “Other income (expenses), net” on Emera’s Consolidated Statements of Income for the year ended December 31, 2011. As a result of this transaction, and APUC’s subsequent conversion of certain of its debentures to equity, Emera owns an approximate 6.2 percent equity interest in APUC as at December 31, 2011.

Consistent with the framework established by the SIA referred to above, in April 2011 Emera agreed to sell its 49.999 percent direct ownership in CPUV, to APUC for $38.8 million, subject to applicable regulatory approval. In connection with this sale, Emera purchased 8.211 million subscription receipts from APUC at an issue price of $4.72 each for a total purchase price of $38.8 million. Emera has issued two promissory notes to APUC in exchange for these subscription receipts, the proceeds of which will be used by APUC to pay Emera for its CPUV ownership interest. The subscription receipts are convertible to 8.211 million APUC shares in two tranches. 4.79 million will be exchanged for APUC shares following applicable regulatory approval of the CPUV ownership transfer, including the MPUC approval referenced below under the heading “APUC Withdrawal from First Wind Transaction”. The remainder will be exchanged upon completion of California Pacific’s first rate case, expected in 2012. The purchase of subscription receipts has received final Toronto Stock Exchange approval.

7

New Hampshire Transaction

On March 25, 2011, Emera purchased 12 million subscription receipts from APUC at an issue price of $5.00 each for a total purchase price of $60 million. Emera issued a promissory note in exchange for the subscription receipts. The subscription receipts are convertible to 12 million APUC common shares upon the acquisition by APUC’s regulated subsidiary, Liberty Energy Utilities Co., of all issued and outstanding shares of Granite State Electric Company and Energy North Natural Gas Inc., two regulated utilities, currently owned by National Grid USA (the “New Hampshire Transaction”). The acquisitions are subject to applicable regulatory approvals and the conversion of subscription receipts is subject to the MPUC approval referenced below under the heading “APUC Withdrawal from First Wind Transaction”. The purchase of subscription receipts has received final Toronto Stock Exchange approval.

Assuming the completion of the sale of CPUV to APUC and the New Hampshire Transactions, which are expected in 2012, the associated conversion of the subscription receipts to APUC common shares, and the exercise of Emera’s anti-dilution rights, Emera’s ownership interest in APUC will increase to approximately 18 percent.

The table below summarizes the aforementioned transactions:

Underlying Transaction	No. of shares/subscription receipts		Price per subscription receipt		Quarter closed / expected to close
Acquisition of California Pacific		8,523,000		$3.25		Q1 2011
New Hampshire Transaction		12,000,000		$5.00		Q1 2012
Sale of California Pacific		8,211,000		$4.72		Q1 2012

APUC Withdrawal from First Wind Transaction

Emera and Algonquin had planned to partner with First Wind Holdings LLC (“First Wind”) to own 370 MW of wind energy projects in the northeastern United States. As regulator of Emera’s Maine utilities, the MPUC must approve any new affiliation (defined as an investment that is over 10%) between Emera and certain enterprises, including those that own generation in the restructured Maine market, such as First Wind and Algonquin. On January 13, 2012, MPUC staff issued a report recommending the Commission not approve the First Wind transaction, nor Emera’s plan to increase its ownership in Algonquin beyond 10%. Emera disagrees with the conclusions in the report, and outlined its concerns in a formal response filed January 23, 2012.

On January 27, 2012, APUC announced it would not be proceeding with its 12.5% investment in First Wind, citing the longer than anticipated regulatory process in Maine, and other transactions it became involved with since the First Wind acquisition process commenced. Emera plans to continue to pursue the First Wind transaction, as detailed below. Both Emera and Algonquin remain committed to the SIA, and are hopeful that APUC removing itself from the First Wind transaction will address the MPUC’s concerns.

The MPUC was scheduled to render a formal decision on these matters on January 31, 2012. That decision has been delayed, but is expected to be issued in the first quarter of 2012.

Emera had purchased 6.9 million subscription receipts for $5.37 each on July 29, 2011 in connection with this transaction. These will now terminate, as will the $37 million promissory note, Emera had issued in exchange for the subscription receipts.

Emera’s Investment in First Wind

Subject to the approval of the MPUC as discussed above, Emera is partnering with First Wind to own 370 MW of wind energy facilities in the northeastern United States. These assets will become part of a new operating company, owned 51 percent by First Wind, and 49 percent by a new Emera owned entity, Northeast Wind. Northeast Wind will invest a total of approximately $353 million USD to acquire its 49 percent interest in the operating company, including

8

a $150 million USD loan. The acquisition requires certain state and federal regulatory approvals, all of which have been obtained with the exception of the MPUC approval as noted above. Emera will finance the transaction through existing credit facilities subject to lender approval.

Issue of Medium-Term Notes

On December 13, 2011, Emera completed the issue of $250 million Series H Medium-Term Notes. The Series H Notes bear interest at a rate of 2.96 percent and yield 2.969 percent per annum until December 13, 2016.

The net proceeds of the offering were used to repay short-term borrowings and for general corporate purposes.

Increase in Common Share Dividend

On September 23, 2011, Emera’s Board of Directors approved an increase in the annual common share dividend rate from $1.30 to $1.35, and accordingly declared a quarterly dividend of $0.3375 per common share.

Common Share Financing

On March 16, 2011, Emera completed an offering of 6,359,500 common shares, including the exercise of the over-allotment option of 829,500 common shares, at $31.70 per common share, for net proceeds of approximately $196.0 million. The net proceeds of the offering were used for general corporate purposes, including repayment of indebtedness under Emera’s credit facility.

The Barbados Light & Power Company Limited

On December 20, 2010, Emera offered to purchase all issued and outstanding common stock of LPH, the parent company of BLPC, at a cash price of $25.70 Barbadian dollars per share. The offer closed on January 24, 2011, and on January 25, 2011, Emera purchased 7.2 million shares representing an additional interest of 41.8 percent. With this additional investment of $92.6 million, Emera became the majority shareholder of LPH, with a total interest of 80.1 percent. Based on the purchase price allocation, as determined under USGAAP, the fair value of the net assets acquired in the LPH acquisition exceeded the purchase price by $28.2 million, which Emera has recorded as a non-taxable gain in “Other income (expenses), net” on Emera’s Consolidated Statements of Income for the year ended December 31, 2011. Further information on the gain is provided in the Consolidated Financial Review – Significant Items section.

US Securities and Exchange Commission Registration

On October 5, 2011, Emera registered its common shares under the US Securities Exchange Act of 1934, as amended (“the Exchange Act”).

On February 23, 2011, Emera registered its debt securities, first preferred shares and second preferred shares under the US Securities Act of 1933, as amended.

NSPI

UARB Decision on 2012 Fuel Adjustment Mechanism

On December 19, 2011, the UARB approved NSPI’s customer rates associated with the 2012 FAM adjustment related to the recovery of prior period fuel costs. The recovery of these costs began January 1, 2012. The approved customer rates seek to recover $69.0 million of prior years’ unrecovered fuel costs in 2012.

9

United States Securities and Exchange Commission Registration Status

Consistent with several Canadian industry peers, NSPI requested and received an exemption from Canadian securities regulators allowing it to continue to report its financial results in accordance with USGAAP. On December 12, 2011, NSPI filed with the United States Securities Exchange Commission (“SEC”), to remove from registration all unsold debt securities as of that date. NSPI also filed to terminate its reporting obligations under Section 15(d) of the Exchange Act.

2012 General Rate Decision

On May 13, 2011, NSPI filed a General Rate Application (“GRA”) with the UARB requesting an average 7.3 percent rate increase across all customer classes effective January 1, 2012. On November 29, 2011, the UARB approved a settlement agreement between NSPI and customer representatives which resulted in an average rate increase of 5.1 percent for all customers, effective January 1, 2012. Rates were approved based on a 9.2 percent return on equity (“ROE”), applied to a 37.5 percent common equity component with a target earnings range of 9.1 percent to 9.5 percent on maximum actual equity of 40 percent.

NewPage Port Hawkesbury Corp.

On September 9, 2011, NewPage Port Hawkesbury Corp. (“NewPage”), NSPI’s largest customer was granted creditor protection under the Companies’ Creditors Arrangement Act (“CCAA”). On September 7, 2011, NewPage Group Inc., NewPage’s corporate parent, commenced a voluntary case under Chapter 11 of the United States Bankruptcy Code. NewPage has suspended operations and is actively seeking a buyer for its facility. In light of this, the 2012 General Rate Decision, approved by the UARB, provides for any unrecovered non-fuel electric charges in 2012 related to this customer to be deferred and recovered beginning in 2013. NewPage was also responsible for the engineering, procurement and construction of a 60 MW biomass facility in Port Hawkesbury, Nova Scotia for NSPI. NSPI is proceeding with this project and has assumed full project management responsibilities.

Canadian Environmental Regulations

On August 19, 2011, Environment Canada announced proposed regulations for a new national carbon dioxide framework for the electricity sector in Canada. These proposed regulations would apply to new coal-fired electricity generation units; and existing coal-fired electricity generation units that have reached the end of their deemed economic life of forty-five years after commissioning. These proposed regulations will be effective July 1, 2015. Nova Scotia’s existing greenhouse gas regulations require reductions in NSPI’s emissions similar to those reflected in the federal framework. NSPI is engaged with federal and provincial agencies in reviewing the implications of this federal framework and its alignment with its current operating plans under existing Nova Scotia regulations.

Deferral of Certain Tax Benefits Decision

In December 2010, the UARB granted NSPI approval to defer $14.5 million of tax benefits which arose in 2010 related to renewable energy projects. On July 21, 2011, the UARB approved an agreement NSPI reached with stakeholders to apply the deferral against the FAM regulatory asset, which reduced the FAM regulatory asset effective January 1, 2011. The application of the deferral reduced the amount of the FAM balance outstanding with the reduction applied to the amount that would otherwise be recovered from customers in 2012 as noted in the “UARB Decision on 2012 Fuel Adjustment Mechanism” section above.

10

Light–emitting Diode Streetlight Legislation

On May 19, 2011, the Nova Scotia Government passed legislation making light-emitting diode (“LED”) lighting mandatory on Nova Scotia’s roads and highways. This legislation builds on previous initiatives focused on energy efficiency and environmental responsibility. The cost to convert to LED lighting province-wide is estimated to be in the range of $100 million. NSPI’s related capital costs will be subject to UARB review and approval.

Nova Scotia Provincial Environmental Regulations

On May 19, 2011, the Nova Scotia Government approved The Electricity Act (Amended) to facilitate the eligibility of energy from the Lower Churchill Project in Labrador as a resource for meeting Nova Scotia’s renewable electricity targets. The amendment requires regulations to be developed that increase the percentage of renewable energy in the generation mix from the planned 25 percent in 2015, to 40 percent by 2020.

On April 11, 2011, the Nova Scotia Government announced that the cap on the annual amount of new forest biomass that can be used to generate electricity will be lowered by 30 percent to 350,000 dry tonnes per year. NSPI’s 60 MW Port Hawkesbury Biomass Project is unaffected by this announcement.

Depreciation Settlement

On May 11, 2011, the UARB approved changes to NSPI’s depreciation rates following NSPI’s completion of a depreciation study and a settlement agreement with stakeholders. The overall impact on the average depreciation rate is immaterial. The new depreciation rates are effective January 1, 2012, as approved by the UARB in the 2012 General Rate Decision.

Digby Wind Renewable Energy Project

On March 9, 2011, the UARB approved a capital work order for the Digby Wind Renewable Energy Project, which included a substation, network upgrades and interconnection costs, in the amount of $79.8 million. This project went into service in December 2010.

Maine Utility Operations

Private Placement of Senior Unsecured Notes

On January 31, 2012, Bangor Hydro completed the issue of an unsecured $70.0 million USD senior note. The Series 2012-A Senior Note bears interest at a rate of 3.61 percent per annum until January 31, 2022. The net proceeds of the note offering were used to repay borrowings under the revolving credit facility.

Caribbean Utility Operations

Sale of St. Lucia Electricity Services

On January 31, 2012, a wholly-owned subsidiary of Emera sold its 19.1 percent interest in St. Lucia Electricity Services (“Lucelec”) at book value to Light & Power Holdings Ltd. (“LPH”), a subsidiary owned 80.1 percent by Emera, for $29.1 million USD effective January 1, 2012. The transaction is expected to allow for greater cooperation between the two electric utilities, including a sharing of skills and increased efficiencies that are expected to result in benefits to customers in both countries. The terms of the acquisition agreement provide for a potential sales price increase or decrease of up to $4 million USD within 30 months of the closing date of the transaction. Any adjustment would be triggered by either an additional public offering by Lucelec or a change in Lucelec’s allowed return on equity as a result of a change in its regulatory framework.

11

GBPC Credit Agreement

On January 25, 2012, GBPC entered into an unsecured credit agreement with Scotiabank (Bahamas) Limited in the amount of $56.2 million USD. The proceeds of the credit agreement will be used to finance the construction of a 52-MW power plant on Grand Bahama Island. The credit agreement bears interest at a rate of the three month LIBOR rate plus 1.2 percent and is repayable in forty equal, consecutive quarterly installments over a ten year period. The payments commence at the earlier of six months after the completion of the construction of the power plant or January 31, 2013.

Appointments

Directors

Ray Ivany, President and Vice-Chancellor of Acadia University, joined NSPI’s Board of Directors on September 22, 2011.

James Eisenhauer, FCA was appointed Chairman of NSPI’s Board of Directors on May 2, 2011, replacing George A Caines, QC, who retired. On May 4, 2011, Mr. Eisenhauer was elected to Emera’s Board of Directors at the Company’s Annual General Meeting.

Executive

Bruce Marchand was appointed Chief Legal Officer of Emera Incorporated effective January 1, 2012. Prior to joining Emera, Mr. Marchand was Senior Partner in the Halifax office of McInnes Cooper, an Atlantic Canadian law firm.

Barbara Meens Thistle was appointed Chief Human Resources Officer at Emera Incorporated and Vice President, Human Resources, NSPI on November 25, 2011. Previously, she served as General Manager Human Resources, Procurement and Real Estate at NSPI.

Robert Hanf was appointed Executive Chairman of Light & Power Holdings Ltd. and Director of Barbados Light & Power Company Limited on September 13, 2011. Prior to these appointments, Mr. Hanf served as Chief Legal Officer of Emera Incorporated.

Sarah MacDonald was appointed President and Chief Executive Officer of GBPC on June 7, 2011. Prior to this appointment, Ms. MacDonald served as the Executive Vice President of Human Resources at Emera Incorporated and Chief Executive Officer of Emera Utility Services Inc.

Judy Steele, FCA was appointed Chief Financial Officer of Emera Incorporated on May 16, 2011, on an interim basis until such time as a permanent CFO is named. Prior to this appointment, Ms. Steele served as Vice President Finance of Emera Energy Inc.

12

Significant Items

Bear Swamp Mark-to-Market Adjustment

As part of its long-term energy and capacity supply agreement with the Long Island Power Authority (“LIPA”), which extends to 2021, Bear Swamp has contracted with Emera’s joint venture partner to provide the off-peak power necessary to produce the requirements of the LIPA contract. One of the contracts is marked-to-market through income, as it does not meet the stringent accounting requirements of hedge accounting.

As at December 31, 2011, the fair value of the contract was a net liability of $9.6 million (December 31, 2010 (adjusted) – $8.2 million net liability), which will reverse over the life of the agreement as it is realized.

The mark-to-market adjustment relating to this contract was as follows:

For the   millions of Canadian dollars (except per share amounts)	Three months ended December 31						Year ended December 31
	2011		2010 (adjusted)		2011		2010 (adjusted)		2009 (adjusted)
Mark-to-market (loss) gain		$(1.2)		$(4.4)		$(1.3)		$(14.4)		$1.2
After-tax mark-to-market (loss) gain		$(0.7)		$(2.6)		$(0.8)		$(8.6)		$0.7
Earnings per common share – basic		$0.38		$0.21		$1.99		$1.67		$1.65
Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment		$0.39		$0.23		$2.00		$1.75		$1.64

Gain on Exchange of Subscription Receipts to Shares

As discussed in the Emera Developments section, pursuant to an April 2009 subscription receipts agreement with APUC, and upon closing of the California Pacific transaction in Q1 2011, Emera exchanged subscription receipts acquired in 2009 into 8.523 million APUC common shares, issued at $3.25 per share. This resulted in an after-tax gain of $12.8 million recorded in Q1 2011 in “Other income (expenses), net” on Emera’s Consolidated Statements of Income.

Gain on Business Acquisition

Under USGAAP, in circumstances where the fair value of net assets acquired in a business acquisition exceeds the purchase price, the difference is recorded as a gain in the period.

Emera’s interest in LPH was acquired in two tranches, in Q2 2010 and Q1 2011, and gave rise to non-taxable gains of $22.5 million and $28.2 million, respectively. These amounts have been recorded in “Other income (expenses), net” on Emera’s Consolidated Statements of Income.

13

REVIEW OF 2011

Emera Consolidated Statements of Income

For the   millions of dollars (except earnings per common share)	Three months ended December 31					Year ended December 31
	2011		2010 (adjusted)			2011		2010 (adjusted)		2009 (adjusted)
Operating revenues		$512.0		$408.9			$2,064.4		$1,606.1		$1,490.1
Regulated fuel for generation and purchased power		215.0		157.8			866.4		634.6		550.0
Regulated fuel adjustment		(4.5)		(24.0)			(8.5)		(99.0)		8.5
Non-regulated fuel for generation and purchased power		18.3		19.4			73.9		83.9		29.5
Non-regulated direct costs		20.4		16.2			60.9		62.3		37.9
Operating, maintenance and general		121.9		103.7			455.0		351.2		299.1
Provincial, state, and municipal taxes		12.5		11.9			49.2		47.4		48.0
Depreciation and amortization		73.7		69.8			250.0		213.5		199.7
Income from operations		54.7		54.1			317.5		312.2		317.4
Income from equity investments		4.2		1.7			21.5		15.3		28.9
Other income (expenses), net		1.5		(5.5)			43.1		12.5		20.4
Interest expense, net		37.3		37.3			159.4		148.8		132.8
Income before provision for income taxes		23.1		13.0			222.7		191.2		233.9
Income tax expense (recovery)		(26.3)		(10.6)			(36.7)		(8.1)		37.4
Net income		49.4		23.6			259.4		199.3		196.5
Non-controlling interest in subsidiaries		2.6		(0.5	)		11.7		5.6		10.2
Net income of Emera Incorporated		46.8		24.1			247.7		193.7		186.3
Preferred stock dividends		-		-			6.6		3.0		-
Net income attributable to common shareholders		$46.8		$24.1			$241.1		$190.7		$186.3
Earnings per common share – basic		$0.38		$0.21			$1.99		$1.67		$1.65
Earnings per common share – diluted		$0.38		$0.21			$1.97		$1.65		$1.61

Emera Incorporated’s consolidated net income increased $22.7 million to $46.8 million in Q4 2011 compared to $24.1 million in Q4 2010 (adjusted). For the year ended December 31, 2011, Emera’s consolidated net income increased $50.4 million to $241.1 million compared to $190.7 million in 2010 (adjusted) and $186.3 million in 2009 (adjusted).

14

Highlights of the changes are summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31		Year ended December 31
Consolidated net income attributable to common shareholders – 2009 (adjusted)				$186.3
Operating revenues – Increased primarily due to the acquisition of Bayside Power, Brunswick Pipeline becoming operational, and increased EUS revenues due to increase in large construction projects; partially offset by lower fuel-related revenues in NSPI				116.0
Regulated fuel for generation and purchased power – Increased primarily due to higher commodity prices				(84.6)
Regulated fuel adjustment – Increased due to an under-recovery of current year fuel costs and a rebate to customer of prior years’ over recovery				107.5
Non-regulated fuel for generation and purchased power – Increased primarily due to the acquisition of Bayside Power				(54.4)
Non-regulated direct costs – Increased primarily due to an increase in large construction projects in EUS				(24.4)
OM&G – Increased primarily due to increased pension, storm and customer service costs and acquisition of Bayside Power				(52.1)
Depreciation and amortization – Increased primarily due to increased property, plant and equipment and increased regulatory amortization				(13.8)
Income from equity investments – Decreased primarily due to unfavourable change in the fair value of the net derivatives in Bear Swamp				(13.6)
Interest expense, net – Increased primarily due to increased debt used to fund business acquisitions				(16.0)
Income tax expense – Decreased primarily due to lower income before provision for income taxes, deductions related to renewable investments and a change in the expected benefit from other accelerated tax deductions				45.5
Other				(5.7	)
Consolidated net income attributable to common shareholders – 2010 (adjusted)		$24.1		$190.7
Operating revenues – Decreased during the quarter primarily due to lower industrial sales volumes in NSPI; increased year-over-year due to higher fuel-related revenues in NSPI		(14.4)		17.4
Regulated fuel for generation and purchased power – Decreased during the quarter primarily due to lower sales volumes; decreased year-over-year primarily due to lower commodity prices and a change in the generation mix		16.2		41.8
Regulated fuel adjustment – Decreased due to an under-recovery of current period fuel costs and change in recovery of prior periods’ FAM balance		(19.5)		(90.5)
Income tax expense – Decreased primarily due to a change in the expected benefit from accelerated tax deductions and lower income before provision for income taxes in NSPI		16.7		31.2
Impact of the acquisitions of GBPC, MAM and LPH		3.8		47.7
Other		19.9		2.8
Consolidated net income attributable to common shareholders – 2011		$46.8		$241.1

15

Consolidated Balance Sheets Highlights

Significant changes in the consolidated balance sheets between December 31, 2011 and 2010 (adjusted) include:

millions of Canadian dollars	Increase (Decrease)		Explanation
Assets
Cash and cash equivalents		$69.6	See consolidated cash flow highlights section.
Restricted cash		(44.6)	Decreased primarily due to use of restricted cash in Q1 2011 in connection with the CPUV investment, partially offset by restricted cash acquired with LPH acquisition( 1).
Receivables, net		66.7	Increased primarily due to acquisition of a controlling interest in LPH (1), higher fuel-related electricity pricing effective January 1, 2011 and timing of billings and receipts.
Inventory		21.0	Increased primarily due to acquisition of a controlling interest in LPH (1).
Derivative instruments (current and long-term)		(18.8)	Decreased primarily due to settlements and unfavourable commodity positions, partially offset by favourable USD price positions.
Other assets (current and long-term)		114.7	Increased primarily due to purchases of APUC subscription receipts.
Property, plant & equipment, net of accumulated depreciation		551.8	Increased primarily due to acquisition of a controlling interest in LPH (1).and capital spending, partially offset by depreciation.
Investments subject to significant influence		(23.3)	Decreased primarily due to acquisition of a controlling interest in LPH (1), partially offset by the APUC investment.
Available-for-sale investments		53.8	Increased due to acquisition of a controlling interest in LPH (1).
Goodwill		30.3	Increased primarily due to finalization of purchase price allocation of GBPC and a weaker Canadian dollar.
Liabilities and Equity
Short-term debt and long-term debt (including current portion)		311.9	Increased primarily due to acquisition of a controlling interest in LPH (1) and purchases of APUC subscription receipts.
Accounts payable		39.0	Increased due to timing of payments and acquisition of a controlling interest in LPH (1) .
Deferred income taxes (current and long-term)		62.5	Increased primarily due to increased deferred income tax liability on property, plant and equipment, including renewable investments and acquisition of a controlling interest in LPH (1), resulting in reclassification of a deferred income tax asset.
Regulatory liabilities (current and long-term)		10.8	Increased primarily due to acquisition of a controlling interest in LPH (1), partially offset by decreased deferred income tax regulatory liability, decreased derivative regulatory liability and decreased regulatory liability related to the 2010 renewable tax benefits deferral.
Pension and post-retirement liabilities (current and long-term)		130.7	Increased primarily due to a change in the discount rate used in determining the pension and post-retirement obligations, and 2011 investment losses.
Other liabilities (current and long- term)		14.5	Increased primarily due to acquisition of a controlling interest in LPH (1).
Asset retirement obligations		(41.9)	Decreased primarily due to change in estimates of retirement dates and future decommissioning costs, partially offset by acquisition of a controlling interest in LPH (1).
Common stock		247.2	Issuance of common shares.
Accumulated other comprehensive loss		107.5	Increased primarily due to higher underfunded amount in pension plans resulting from a change in discount rates, and 2011 investments losses; partially offset by the favourable effect of a stronger CAD on Emera’s foreign subsidiaries.
Retained earnings		82.4	Net income of Emera in excess of dividends paid.
Non-controlling interest in subsidiaries		70.1	Increased primarily due to acquisition of a controlling interest in LPH (1).

(1) Emera acquired a controlling interest in LPH in 2011, and accordingly, its asset and liabilities are fully consolidated in the December 31, 2011 Balance Sheets. Previously, LPH had been accounted for under the equity method, with the net investments included in “Investments Subject to Significant Influence”.

16

Consolidated Cash Flow Highlights

Significant changes in the statements of cash flows between December 31, 2011 and 2010 (adjusted) include:

Year ended December 31   millions of Canadian dollars	2011			2010 (adjusted)			Explanation
Cash and cash equivalents, beginning of period		$7.3			$20.2
Provided by (used in):
Operating activities		399.5			419.2		Cash provided by operating activities decreased in 2011 primarily due to unfavourable non-cash working capital changes. Cash from operating activities excluding non-cash working capital increased primarily due to the collection of the FAM receivable and the acquisitions of LPH, GBPC and MAM.
Investing activities		(660.8)			(886.0)		Cash used in investing activities decreased in 2011 primarily due to the acquisitions of MPS and GBPC in 2010, and lower capital spending in NSPI; partially offset by the purchase of CPUV, and APUC subscription receipts.
Financing activities		331.4			454.6		Cash provided by financing activities decreased in 2011 primarily due to reduced borrowing and higher dividends on common and preferred shares, partially offset by a common share issuance.
Foreign currency impact on cash balances		(0.5	)		(0.7	)
Cash and cash equivalents, end of period		$76.9			$7.3

 Outstanding Share Data

Issued and Outstanding:	Millions of Shares		Common Stock millions of Canadian dollars
December 31, 2009 (adjusted)		112.98		$1,097.9
Issued for cash under Purchase Plans		1.32		34.4
Discount on shares purchased under Dividend Reinvestment Plan		-		(1.5)
Options exercised under senior management stock option plan		0.32		6.0
Stock-based compensation		-		1.0
December 31, 2010 (adjusted)		114.62		$1,137.8
Issuance of common stock		6.36		196.0
Issued for cash under Purchase Plans		1.40		42.8
Discount on shares purchased under Dividend Reinvestment Plan		-		(1.8)
Options exercised under senior management stock option plan		0.45		8.8
Stock-based compensation		-		1.4
December 31, 2011		122.83		$1,385.0

As at January 27, 2012, the amount of issued and outstanding common stock was 122.95 million.

17

NSPI

Overview

NSPI was created in 1992 through the privatization of the crown corporation Nova Scotia Power Corporation (“NSPC”). NSPI is a fully-integrated regulated electric utility and the primary electricity supplier in Nova Scotia. NSPI has $3.9 billion of assets and provides electricity generation, transmission and distribution services to approximately 493,000 customers. The Company owns 2,374 MW of generating capacity, of which approximately 52 percent is coal-fired; natural gas and/or oil comprise another 28 percent of capacity; and hydro and wind total 20 percent. In addition, NSPI has contracts to purchase renewable energy from independent power producers (“IPP”). These IPPs own 229 MW, increasing to 259 MW in 2012, of wind and biomass fueled generation capacity. A further 83 MW of renewable capacity is being built directly or purchased under long-term contracts by NSPI and is expected to be in service by the end of 2013. NSPI also owns approximately 5,000 kilometers of transmission facilities and 26,000 kilometers of distribution facilities. The Company has a workforce of approximately 1,900 people.

NSPI is a public utility as defined in the Public Utilities Act (Nova Scotia) (“Act”) and is subject to regulation under the Act by the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. The Company is not subject to a general annual rate review process, but rather participates in hearings from time to time at the Company’s or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s target regulated return on equity (“ROE”) range for 2011 was 9.1 percent to 9.6 percent, based on an actual, average regulated common equity component of up to 40 percent of regulated capitalization. The 2012 General Rate Decision adjusted the 2012 ROE range to 9.1 percent to 9.5 percent.

On May 13, 2011, NSPI filed a GRA with the UARB requesting an average 7.3 percent rate increase across all customer classes effective January 1, 2012. On November 29, 2011, the UARB approved the settlement which resulted in an average rate increase of approximately 5.1 percent for all customers, effective January 1, 2012. Rates were approved based on a 9.2 percent ROE, applied to a 37.5 percent common equity component.

In 2009, the UARB approved a FAM allowing NSPI to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

18

Review of 2011

NSPI Net Income   millions of Canadian dollars (except per share amounts)	Three months ended December 31				Year ended December 31
	2011		2010 (adjusted)		2011		2010 (adjusted)		2009 (adjusted)
Operating revenues		$289.2		$303.2		$1,233.0		$1,191.4		$1,211.8
Fuel for generation and purchased power		127.0		146.1		546.3		578.6		525.8
Fuel for generation and purchased power – affiliates (1)		0.8		0.1		1.1		8.1		(25.1)
Fuel adjustment		(4.5)		(24.0)		(8.5)		(99.0)		8.5
Operating, maintenance and general		75.0		67.5		268.6		245.8		223.9
Provincial grants and taxes		9.8		10.1		38.7		40.1		40.5
Depreciation and amortization		58.8		63.7		187.2		188.1		171.5
Total operating expenses		266.9		263.5		1,033.4		961.7		945.1
Income from operations		22.3		39.7		199.6		229.7		266.7
Other expenses, net		2.1		3.5		8.9		11.3		3.3
Interest expense, net		23.6		26.8		104.2		104.7		102.8
Income before provision for income taxes		(3.4)		9.4		86.5		113.7		160.6
Income tax (recovery) expense		(27.5)		(12.4)		(44.9)		(13.4)		40.3
Net income of Nova Scotia Power Inc.		24.1		21.8		131.4		127.1		120.3
Preferred stock dividends		1.9		1.9		7.9		7.9		9.5
Contribution to consolidated net income		$22.2		$19.9		$123.5		$119.2		$110.8
Contribution to consolidated earnings per common share		$0.18		$0.17		$1.02		$1.04		$0.98

(1) Fuel for generation and purchased power – affiliates includes proceeds from the sale of natural gas.

NSPI’s contribution to consolidated net income increased $2.3 million to $22.2 million in Q4 2011 compared to $19.9 million in Q4 2010 (adjusted). NSPI’s contribution to consolidated net income for the year ended December 31, 2011 increased $4.3 million to $123.5 million compared to $119.2 million in 2010 (adjusted) and $110.8 million in 2009 (adjusted). Highlights of the changes are summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31		Year ended December 31
Contribution to consolidated net income – 2009 (adjusted)				$110.8
Decreased electric margin (see Electric Margin section for explanation)				(11.6)
Increased OM&G expenses primarily due to increased pension, storm costs and customer service initiatives				(21.9)
Increased net depreciation and amortization primarily due to increased property, plant and equipment and increased regulatory amortization				(16.1)
Decreased other expenses, net primarily due to increased allowance for equity funds used during construction related to increased capital spending				4.3
Decreased income taxes primarily due to decreased income before provision for income taxes, deductions related to renewable investments and a change in the expected benefit from other accelerated tax deductions				53.7
Contribution to consolidated net income – 2010 (adjusted)		$19.9		$119.2
Decreased electric margin (see Electric Margin section for explanation)		(12.6)		(6.9)
Increased OM&G expenses primarily due to increased pension costs, plant maintenance costs and labour escalation		(7.5)		(22.8)
Decreased net depreciation and amortization primarily due to decreased regulatory amortization partially offset by increased property, plant and equipment		4.7		1.7
Increased income tax recovery primarily due to a change in the expected benefit from accelerated tax deductions and decreased income before provision for income taxes		15.1		31.5
Other		2.6		0.8
Contribution to consolidated net income – 2011		$22.2		$123.5

19

Operating Revenues – Regulated

NSPI’s Operating Revenues – Regulated include sales of electricity and other services as summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31				Year ended December 31
	2011		2010 (adjusted)		2011		2010 (adjusted)		2009 (adjusted)
Electric revenues		$282.9		$296.4		$1,209.7		$1,167.3		$1,188.1
Other revenues		6.3		6.8		23.3		24.1		23.7
Operating revenues – regulated		$289.2		$303.2		$1,233.0		$1,191.4		$1,211.8

Electric Revenues

Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q1 and Q4 the strongest periods, reflecting colder weather and fewer daylight hours in the winter season.

NSPI’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, and the province’s universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other electric revenues consist of export sales, sales to municipal electric utilities and revenues from street lighting.

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

Q4 Electric Sales Volumes   Gigawatt hours (“GWh”)							Annual Electric Sales Volumes GWh
	2011		2010		2009			2011		2010		2009
Residential		1,073		1,080		1,091	Residential		4,275		4,147		4,228
Commercial		768		765		772	Commercial		3,102		3,088		3,107
Industrial		568		957		998	Industrial		3,516		3,908		3,642
Other		83		84		81	Other		313		312		328
Total		2,492		2,886		2,942	Total		11,206		11,455		11,305

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

Q4 Electric Revenues   millions of Canadian dollars
	2011		2010		2009
Residential		$141.0		$137.1		$140.4
Commercial		85.8		82.2		84.2
Industrial		45.2		66.0		67.3
Other		10.9		11.1		11.0
Total		$282.9		$296.4		$302.9

Annual Electric Revenues   millions of Canadian dollars
	2011		2010		2009
Residential		$564.9		$531.0		$547.3
Commercial		341.8		325.4		333.9
Industrial		260.1		269.3		263.8
Other		42.9		41.6		43.1
Total		$1,209.7		$1,167.3		$1,188.1

20

Electric revenues decreased $13.5 million to $282.9 million in Q4 2011 compared to $296.4 million in Q4 2010. For the year ended December 31, 2011, electric revenues increased $42.4 million to $1,209.7 million compared to $1,167.3 million in 2010 and $1,188.1 million in 2009. Highlights of the changes are summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31		Year ended December 31
Electric revenues – 2009				$1,188.1
Decreased fuel-related electricity pricing effective January 1, 2010				(22.4)
Change in residential and commercial sales volumes primarily due to warmer weather				(10.7)
Increased industrial sales volumes from several large industrial customers				13.2
Other				(0.9)
Electric revenues – 2010		$296.4		$1,167.3
Increased fuel-related electricity pricing effective January 1, 2011		11.5		51.5
Year-over-year increased residential sales volumes due to load growth and colder weather		(1.2)		15.2
Decreased industrial sales volume primarily due to suspended operations of a large industrial customer		(23.2)		(24.1)
Other		(0.6)		(0.2)
Electric revenues – 2011		$282.9		$1,209.7

Electric Margin

NSPI distinguishes revenues related to the recovery of fuel costs (“fuel electric revenues”) from revenues related to the recovery of non-fuel costs (“non-fuel electric revenues”) because the FAM introduced on January 1, 2009 enables NSPI to seek recovery of fuel costs through regularly scheduled rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. Consequently, fuel electric revenues and fuel costs do not have a material effect on NSPI’s electric margin or net income, with the exception of the incentive component of the FAM, whereby NSPI retains or absorbs 10 percent of the over or under recovered amount to a maximum of $5 million.

As fuel costs are recovered through the FAM, electric margin and net income are influenced primarily by revenues relating to non-fuel costs. NSPI’s customer classes contribute differently to the Company’s non-fuel electric revenues, with residential and commercial customers contributing more than industrials. Accordingly, changes in residential and commercial load, largely due to weather and growth, have the largest effect on non-fuel electric revenues. Changes in industrial load, which are generally due to economic conditions, have less of an effect on non-fuel electric revenues than a similar volume change in residential and commercial load.

Electric margin is summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31				Year ended December 31
	2011		2010		2011		2010		2009
Fuel electric revenues – current year		$115.6		$129.1		$512.6		$513.7		$509.3
Fuel electric revenues – preceding years		6.1		(5.7)		26.6		(22.4)		–
Non-fuel electric revenues		161.2		173.0		670.5		676.0		678.8
Total electric revenues		$282.9		$296.4		$1,209.7		$1,167.3		$1,188.1
Fuel for generation and purchased power, including affiliates		(127.8)		(146.2)		(547.4)		(586.7)		(500.7)
Fuel adjustment		4.5		24.0		8.5		99.0		(8.5)
Foreign exchange and other fuel-related costs		(1.4)		(3.4)		(7.4)		(9.3)		3.0
Electric margin		$158.2		$170.8		$663.4		$670.3		$681.9

21

NSPI’s electric margin decreased $12.6 million to $158.2 million in Q4 2011 compared to $170.8 million in Q4 2010 primarily due to decreased large industrial sales. For the year ended December 31, 2011, NSPI’s electric margin decreased $6.9 million to $663.4 million compared to $670.3 million in 2010 primarily due to decreased large industrial sales, partially offset by increased residential sales as a result of load growth and colder weather. NSPI’s electric margin decreased in 2010 to $670.3 million from $681.9 million in 2009 due to lower residential sales related to warmer weather and the recognition of a FAM incentive expense compared to a recovery in 2009.

Q4 Average Electric Margin/Megawatt hour (“MWh”)							Annual Average Electric Margin/MWh
	2011		2010		2009			2011		2010		2009
Dollars per MWh		$63		$59		$59	Dollars per MWh		$59		$59		$60

The change in average electric margin per MWh in Q4 2011 compared to Q4 2010 reflects a change in sales volume mix largely due to decreased large industrial sales.

The change in average electric margin per MWh in 2010 compared to 2009 reflects a change in sales volume mix and recognition of a FAM incentive expense in 2010 compared to a recovery in 2009.

Regulated Fuel for Generation and Purchased Power (including affiliates)

Capacity

To ensure reliability of service, NSPI maintains a generating capacity greater than firm peak demand. The total Company-owned generation capacity is 2,374 MW, which is supplemented by 229 MW contracted with IPPs. NSPI meets the planning criteria for reserve capacity established by the Maritime Control Area and the Northeast Power Coordinating Council.

NSPI facilities continue to rank among the best in Canada on capacity related performance indicators. The high availability and capability of low cost thermal generating stations provide lower cost energy to customers. In 2011, thermal plant availability was unchanged from 2010 at 87 percent. Sustained high availability and low forced outage rates on low cost facilities are good indicators of sound maintenance and investment practices.

Q4 Production Volumes   GWh
	2011		2010		2009
Coal and petcoke		1,624		2,049		2,069
Natural gas		482		438		534
Oil		7		16		16
Renewables		327		340		281
Purchased power		298		315		335
Total		2,738		3,158		3,235

Purchased power includes 227 GWh of renewables in Q4 2011 (2010 – 175 GWh; 2009 – 92 GWh).

Annual Production Volumes   GWh
	2011		2010		2009
Coal and petcoke		6,848		7,839		8,177
Natural gas		2,430		2,275		1,612
Oil		35		36		307
Renewables		1,335		1,017		1,065
Purchased power		1,269		997		931
Total		11,917		12,164		12,092

Purchased power includes 743 GWh of renewables in 2011 (2010 – 526 GWh; 2009 – 301 GWh).

Q4 Average Unit Fuel Costs
	2011		2010		2009
Dollars per MWh		$47		$46		$43

Annual Average Unit Fuel Costs
	2011		2010		2009
Dollars per MWh		$46		$48		$41

NSPI’s percentage of solid fuel generation decreased to approximately 57 percent in 2011, down from 64 percent in 2010 and 68 percent in 2009. Economic dispatch of the generating fleet brings the lowest cost options on stream first, such that the incremental cost of production increases as sales volume increases. Historically, solid fuels have had the lowest per unit fuel cost, after hydro and NSPI-owned wind, which have no fuel cost component. Natural gas, oil, and purchased power have the next lowest fuel cost, depending on the relative pricing of each. During 2011, natural gas represented a higher percentage of the annual energy requirement than prior years as economic dispatch favored natural gas for much of the year. Additionally, the introduction of new renewable generation has decreased coal consumption.

22

The average unit fuel costs decreased in 2011 compared to 2010 primarily due to decreased natural gas prices and increased hydro and wind production.

The average unit fuel costs increased in 2010 compared to 2009 primarily due to higher priced imported coal and solid fuel commodity mix related to emission compliance.

A large portion of NSPI’s fuel supply comes from international suppliers, and is subject to commodity price and foreign exchange risk. NSPI seeks to manage this risk through the use of financial hedging instruments and physical contracts and utilizes a portfolio strategy for fuel procurement with a combination of long, medium, and short-term supply agreements. It also provides for supply and supplier diversification. Foreign exchange risk is managed through forward and swap contracts. Fuel contracts may also be exposed to broader global conditions which may include impacts on delivery reliability and price, despite contracted terms. Further details on NSPI’s risk management strategies related to fuel for generation and purchased power are discussed in the Business Risks section.

Fuel for generation and purchased power, including affiliates decreased $18.4 million to $127.8 million in Q4 2011 compared to $146.2 million in Q4 2010. For the year ended December 31, 2011, fuel for generation and purchased power, including affiliates decreased $39.3 million to $547.4 million compared to $586.7 million in 2010 and $500.7 million in 2009.

Highlights of the changes are summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31		Year ended December 31
Fuel for generation and purchased power, including affiliates – 2009				$500.7
Commodity price and volume increases				34.5
Changes in generation mix and plant performance				24.3
Solid fuel commodity mix and additives related to emission compliance				25.3
Valuation of contract receivable (see discussion below)				8.7
Increased sales volume				2.7
Increased hydro production				(1.1)
Increased proceeds from the resale of natural gas				(9.8)
Mark-to-market on natural gas hedges recognized in 2009 as they were no longer required due to decreased 2009 production volumes				2.2
Other				(0.8)
Fuel for generation and purchased power, including affiliates – 2010		$146.2		$586.7
Valuation of contract receivable (see discussion below)		3.2		27.8
Changes in generation mix and plant performance		(3.9)		12.0
Decreased commodity prices		(1.0)		(38.9)
Decreased (increased) hydro and wind production		0.6		(19.9)
Changes in solid fuel commodity mix and additives related to emission compliance		3.2		(7.3)
Decreased sales volume		(18.8)		(8.3)
Other		(1.7)		(4.7)
Fuel for generation and purchased power, including affiliates – 2011		$127.8		$547.4

NSPI had a long-term contract receivable with a natural gas supplier that was required to be fair-valued. The natural gas supply contract settled in November 2010. The fair value related to the contract had a favourable impact on natural gas pricing during 2010. The effect is segregated in the table above.

23

Regulated Fuel Adjustment

The regulated fuel adjustment related to the fuel adjustment mechanism (“FAM”) for NSPI includes the effect of fuel costs in both the current and two preceding years specifically:

• The difference between actual fuel costs and amounts recovered from customers in the current year. This amount, net of the incentive component, is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities”.

• The recovery from (rebate to) customers of under (over) recovered fuel costs from prior years.

On December 19, 2011, the UARB approved NSPI’s customer rates associated with the 2012 FAM adjustment related to the recovery of prior period fuel costs. The recovery of these costs began January 1, 2012. The approved customer rates seek to recover $69.0 million of prior years’ unrecovered fuel costs in 2012.

In December 2010, as part of the FAM regulatory process, the UARB approved NSPI’s setting of the 2011 base cost of fuel and the under-recovered fuel-related costs from prior years. The UARB approved the recovery of the prior year FAM balance from customers over three years, effective January 1, 2011, with 50 percent to be recovered in 2011, 30 percent in 2012 and 20 percent in 2013.

Details of the FAM regulatory asset are summarized in the following table:

millions of Canadian dollars	2011		2010		2009
FAM regulatory asset (liability) – Balance at January 1		$92.9		$(9.9)		-
Under (over) recovery of current year fuel costs		35.1		76.6		$(8.5)
(Recovery from) rebate to customers of prior years’ fuel costs		(26.6)		22.4		-
Application of deferral related to tax benefits from 2010		(14.5)		-		-
Interest revenue (expense) on FAM balance		6.8		3.8		(1.4)
FAM regulatory asset (liability) – Balance at December 31		$93.7		$92.9		$(9.9)

NSPI has recognized a deferred income tax expense related to the fuel adjustment based on NSPI’s enacted statutory income tax rate. As at December 31, 2011, NSPI’s deferred income tax liability related to the FAM was $29.0 million (2010 – $29.2 million).

Provincial Grants and Taxes

NSPI pays annual grants to the Province of Nova Scotia in lieu of municipal taxation other than deed transfer tax.

Regulatory Amortization

Regulatory amortization is included in depreciation and amortization. Regulatory amortization decreased $7.7 million to $16.0 in Q4 2011 compared to $23.7 million in Q4 2010 and decreased $17.8 million to $19.1 million for the year ended December 31, 2011 compared to $36.9 million in 2010 primarily due to a $14.5 million deferral of certain tax benefits arising in 2010 related to renewable energy projects and decreased discretionary regulatory amortization recorded in 2011, as discussed below.

Regulatory amortization increased $9.7 million to $36.9 million for the year ended December 31, 2010 compared to $27.2 million in 2009 primarily due to a $14.5 million deferral of certain tax benefits arising in 2010 related to renewable energy projects as approved by the UARB, partially offset by a reduction in amortization of the pre-2003 income tax regulatory asset resulting from the UARB’s 2010 ROE decision of $4.8 million in 2010 (2009 – $10.0 million). The 2010 ROE decision allows NSPI to recognize additional amortization amounts in current periods and to reduce amortization in future periods to provide flexibility relating to customer rate requirements.

24

Other Expenses, Net

Other expenses, net decreased $1.4 million to $2.1 million in Q4 2011 compared to $3.5 million in Q4 2010 (adjusted) and decreased $2.4 million to $8.9 million for the year ended December 31, 2011 compared to $11.3 million in 2010 (adjusted) primarily due to decreased foreign exchange losses recovered through the FAM.

Other expenses, net increased $8.0 million to $11.3 million for the year ended December 31, 2010 (adjusted) compared to $3.3 million in 2009 (adjusted) primarily due to increased foreign exchange losses, recovered through the FAM, partially offset by increased allowance for equity funds used during construction related to increased capital spending.

Income Taxes

In 2011, NSPI was subject to provincial capital tax (0.075 percent), corporate income tax (32.5 percent) and Part VI.1 tax relating to preferred stock dividends (40 percent). NSPI also receives a reduction in its corporate income tax otherwise payable related to the Part VI.1 tax deduction (29 percent of preferred stock dividends).

In Q4 2011, NSPI modified its estimate of the expected tax benefit of tax deductions, electing to amend its tax returns for the years 2006 through 2009. This resulted in a $23.3 million reduction in income tax expense and a $3.0 million increase in interest revenue, recorded in the quarter. This change in accounting estimate has been accounted for on a prospective basis.

In Q4 2010, NSPI revised its estimate of the 2010 expected benefit from accelerated tax deductions, resulting in a $7.2 million reduction in income tax expense.

25

MAINE UTILITY OPERATIONS

Overview

Maine Utility Operations (“Maine Utilities”) includes Bangor Hydro Electric Company (“Bangor Hydro”), Maine Public Service Company (“MPS”) and Maine and Maritimes Corporation (“MAM”), the parent company of MPS. All amounts in the Maine Utility Operations section are reported in USD unless otherwise stated. MAM was purchased in late December 2010, thus its results are not included in the 2010 (adjusted) or 2009 (adjusted) comparative information.

Bangor Hydro and MPS are both transmission and distribution (“T&D”) electric utilities. Bangor Hydro is the second largest electric utility in Maine. Bangor Hydro has approximately $806.8 million of assets and serves approximately 118,000 customers in eastern Maine while MPS has approximately $139.6 million of assets and serves approximately 36,000 customers in northern Maine.

Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through both utilities’ T&D networks. Bangor Hydro owns and operates approximately 1,000 kilometers of transmission facilities and 7,200 kilometers of distribution facilities. Bangor Hydro’s workforce is approximately 300 people. MPS owns and operates approximately 600 kilometers of transmission facilities, and 2,900 kilometers of distribution facilities. MPS’ workforce is approximately 125 people. The Maine Utilities currently have approximately $150 million of additional transmission development in progress.

Approximately 50 percent of Maine Utilities’ electric revenue represents distribution operations, 33 percent is associated with transmission operations and 17 percent relates to stranded cost recoveries. The rates for each element are established in distinct regulatory proceedings.

Distribution Operations

Maine Utilities’ distribution businesses operate under a traditional cost-of-service regulatory structure. Distribution rates are set based on an allowed ROE of 10.2 percent, on a common equity component of 50 percent.

Transmission Operations

Bangor Hydro

Bangor Hydro’s local transmission rates are set by the FERC annually on June 1, based upon a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted transmission investments and expenses. The allowed ROE for these local transmission investments is 11.14 percent. The common equity component is based upon the prior calendar year actual average balances. On June 1, 2011, Bangor Hydro’s local transmission rates decreased by approximately 10 percent (2010 – increased 37 percent).

Bangor Hydro’s bulk transmission assets are managed by the ISO-New England (“ISO”) as part of a region-wide pool of assets. The ISO manages the regions’ bulk power generation and transmission systems and administers the open access transmission tariff. Currently, Bangor Hydro, along with all other participating transmission providers, recovers the full cost of service for its transmission assets from distribution companies in New England, based on a regional formula that is updated on June 1 of each year. This formula is based on prior year regionally funded transmission investments and expenses, adjusted for current year forecasted investments and expenses. Bangor Hydro’s allowed ROE for these transmission investments ranges from 11.64 percent to 12.64 percent, and the common equity component is based upon the prior calendar year average balances. The cost recovery is recorded as transmission pool revenue in the Consolidated Statements of Income. The participating transmission providers are also required to contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent. These transmission pool expenses are recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income.

26

On June 1, 2010, Bangor Hydro’s regional transmission revenue requirement increased by 22 percent, and on June 1, 2011, it increased by a further 9 percent.

MPS

MPS local transmission rates are set annually based on a formula through its Open Access Transmission Tariff (“OATT”). Rates derived from the previous calendar year results go into effect June 1 for wholesale customers and July 1 for retail customers. The allowed ROE for transmission operations is 10.5 percent, and is based on the actual prior calendar year common equity balances. The allowed ROE is determined by negotiation with customers in the formula change years of the OATT, which occur every three years. The last OATT formula change year was 2009. On June 1, 2011, MPS’ local transmission rates increased by 3 percent for wholesale customers (2010 – increased 63 percent) and by 4 percent for retail customers (2010 – increased by 64 percent) on July 1, 2011.

MPS’ electric service territory is not interconnected to the New England bulk power systems, and MPS is not a member of ISO New England.

Stranded Cost Recoveries

Electric utilities in Maine are entitled to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC. Unlike T&D operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through rates. Generally, regulatory rates to recover stranded costs are set every three years, on a levelized basis, and determined under a traditional cost-of-service approach.

Bangor Hydro

Bangor Hydro’s net regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract and the unamortized portion on its loss on the sale of its investment in the Seabrook nuclear facility. These net regulatory assets total approximately $65.3 million as at December 31, 2011 (2010 – $74.9 million) or 8 percent of Bangor Hydro’s net asset base (2010 – 10 percent).

In May 2011, the MPUC approved an approximate 27 percent increase in Bangor Hydro’s stranded cost rates for the period of June 1, 2011 to February 28, 2014. The increased stranded cost revenues are offset, for the most part by changes in regulatory amortizations, purchased power expense and resale of purchased power. The allowed ROE used in setting these new stranded cost rates is 7.4 percent, with a common equity component of 48 percent.

While the stranded cost revenue requirements differ throughout the period due to changes in annual stranded costs, the actual annual stranded cost revenues are the same during the period. To levelize the impact of the varying revenue requirements, cost or revenue deferrals are recorded as a regulatory asset or liability, and addressed in subsequent stranded cost rate proceedings, where customer rates are adjusted accordingly.

MPS

In December 2011, the MPUC approved MPS’ stranded cost rates for the three-year period January 1, 2012 through December 31, 2014. This revised three-year agreement, which amortizes essentially all of MPS’ remaining stranded costs, has an ROE of 7.2 percent and a common equity component of 50 percent. Any residual stranded costs remaining after December 31, 2014 will be recovered in future rate proceedings.

27

Review of 2011

Maine Utilities’ Net Income   millions of US dollars (except per share amounts)	Three months ended December 31						Year ended December 31
	2011		2010 (adjusted)		2011		2010 (adjusted)		2009 (adjusted)
Operating revenues – regulated		$50.6		$42.8		$204.1		$167.2		$151.5
Operating revenues – non-regulated		0.1		-		0.5		-		-
Total operating revenues		50.7		42.8		204.6		167.2		151.5
Regulated fuel for generation and purchased power		9.2		7.5		27.9		29.2		27.7
Transmission pool expense (1)		4.3		4.9		17.9		18.3		15.5
Operating, maintenance and general		10.6		10.2		45.3		36.3		29.6
Provincial, state and municipal taxes		2.2		1.6		9.0		6.8		6.3
Depreciation and amortization		8.4		5.1		36.9		20.9		23.5
Total operating expenses		34.7		29.3		137.0		111.5		102.6
Income from operations		16.0		13.5		67.6		55.7		48.9
Other income		1.6		1.1		4.3		4.1		2.3
Interest expense, net		2.8		2.7		11.8		10.7		12.2
Income before provision for income taxes		14.8		11.9		60.1		49.1		39.0
Income tax expense		5.2		4.3		22.7		18.2		13.9
Contribution to consolidated net income – USD		$9.6		$7.6		$37.4		$30.9		$25.1
Contribution to consolidated net income – CAD		$9.8		$7.8		$37.0		$31.9		$27.5
Contribution to consolidated earnings per common share – CAD		$0.08		$0.07		$0.31		$0.28		$0.24
Net income weighted average foreign exchange rate – CAD/USD		$1.02		$1.03		$0.99		$1.03		$1.10

(1) Transmission pool expense is included in “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income.

Maine Utilities’ contribution to consolidated net income increased by $2.0 million to $9.6 million in Q4 2011 compared to $7.6 million in Q4 2010 (adjusted). Maine Utilities’ contribution to consolidated net income increased by $6.5 million to $37.4 million for the year ended December 31, 2011 compared to $30.9 million in 2010 (adjusted) and $25.1 million in 2009 (adjusted).

28

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

For the   millions of US dollars	Three months ended December 31		Year ended December 31
Contribution to consolidated net income – 2009 (adjusted)				$25.1
Increased electric revenue due primarily to transmission rate increases in 2009 and 2010				6.1
Increased transmission pool revenue due to recovery of regionally funded transmission investments				10.2
Increased OM&G expenses primarily due to increased labour and benefit costs and lower capitalized construction overheads				(6.7)
Increased transmission pool expenses due to increased charges for Bangor Hydro’s share of regionally funded transmission investments and expenses as well as favourable temperatures during high peak electric loads in New England in 2010				(2.8)
Increased income tax expense primarily due to increased income before provision for income taxes				(4.3)
Other				3.3
Contribution to consolidated net income – 2010 (adjusted)		$7.6		$30.9
Decreased electric revenue during the quarter in Bangor Hydro due to lower sales volumes resulting from warmer temperatures, a transmission rate decrease in June 2011 and lower transmission wheeling revenue from a wind generator		(2.0)		(0.9)
Increased transmission pool revenue year-over-year primarily due to recovery on larger regionally funded transmission investments, partially offset by less favourable weather in 2011		(0.4)		2.2
Decreased OM&G expenses in Bangor Hydro primarily due to an increase in capitalized construction overheads		2.9		3.9
Increased Bangor Hydro income tax expense primarily due to increased income before provision for income taxes		(0.5)		(2.7)
Impact of the acquisition of MAM net of income taxes		1.1		2.7
Other		0.9		1.3
Contribution to consolidated net income – 2011		$9.6		$37.4

Maine Utilities’ USD and CAD contribution to consolidated net income increased in Q4 2011 and for the year ended December 31, 2011. The impact of a stronger Canadian dollar, year over year, reduced CAD earnings by $0.1 million in Q4 2011 and $1.5 million for the year ended December 31, 2011.

For the three months ended December 31, 2011, MPS contributed approximately $9.2 million to Maine Utilities’ Operating revenues – regulated and $1.1 million to consolidated net income. For the year ended December 31, 2011, MPS contributed approximately $34.9 million to Maine Utilities’ Operating revenues – regulated and $2.7 million to consolidated net income. MPS was purchased in late December 2010, and accordingly did not have an impact on 2010 or 2009 operating revenues – regulated nor consolidated net income.

29

Operating Revenues – Regulated

Q4 Operating Revenues – Regulated   millions of US dollars							Annual Operating Revenues – Regulated   millions of US dollars
	2011		*2010 (adjusted)		*2009 (adjusted)			2011		*2010 (adjusted)		*2009 (adjusted)
Residential		$17.2		$13.6		$12.6	Residential		$68.1		$50.6		$48.3
Commercial		14.3		10.3		9.1	Commercial		56.2		39.4		35.9
Industrial		2.6		2.9		2.4	Industrial		11.2		11.5		10.2
Other		3.0		2.2		1.9	Other		10.3		9.4		10.4
Total electric revenues		$37.1		$29.0		$26.0	Total electric revenues		$145.8		$110.9		$104.8
Resale of purchased power		4.7		4.6		4.9	Resale of purchased power		18.1		18.3		18.9
Transmission pool		8.8		9.2		7.0	Transmission pool		40.2		38.0		27.8
Operating revenues – regulated		$50.6		$42.8		$37.9	Operating revenues – regulated		$204.1		$167.2		$151.5

Electric sales volume is primarily driven by general economic conditions, population and weather. Electric sales pricing in Maine is regulated, and therefore changes in accordance with regulatory decisions.

For the   millions of US dollars	Three months ended December 31		Year ended December 31
Operating revenues – regulated 2009				$151.5
Increased electric revenues due to increased transmission rates discussed below, increased load offset by a reduction in stranded cost rates				6.1
Increased transmission pool revenues due to recovery of higher regionally-funded transmission investments and more favourable temperatures				10.2
Other				(0.6)
Operating revenues – regulated 2010		$42.8		$167.2
Increased electric revenues due to acquisition of MAM, the effect of transmission rate changes discussed below, partially offset by less favourable temperatures in 2011		8.1		34.9
Increased transmission pool revenues year-over-year due to recovery of higher regionally-funded transmission investments partially offset by less favourable temperatures in 2011		(0.4)		2.2
Other		0.1		(0.2)
Operating revenues – regulated 2011		$50.6		$204.1

Electric Revenue

Q4 Electric Sales Volumes							Annual Electric Sales Volumes
GWh	2011		*2010		*2009		GWh	2011		*2010		*2009
Residential		196.2		155.0		154.2	Residential		778.5		591.0		591.5
Commercial		207.4		146.7		144.8	Commercial		846.4		594.1		588.0
Industrial		91.1		84.4		78.2	Industrial		380.5		363.0		342.0
Other		2.8		2.9		2.9	Other		11.4		11.6		11.6
Total		497.5		389.0		380.1	Total		2,016.8		1,559.7		1,533.1

*MAM is not included in 2010 and 2009 operating statistics.

30

Q4 Average Electric Revenue/MWh							Annual Average Electric Revenue/MWh
	2011		*2010 (adjusted)		*2009 (adjusted)			2011		*2010 (adjusted)		*2009 (adjusted)
Dollars per MWh		$75		$75		$68	Dollars per MWh		$72		$71		$68

*MAM is not included in 2010 and 2009 operating statistics.

There was no change in annual average electric revenue per MWh in 2011 compared to 2010 (adjusted). Decreased transmission rates were offset by increased stranded cost rates.

The change in average electric revenue per MWh in 2010 (adjusted) compared to 2009 (adjusted) reflects increases in transmission rates on June 1, 2010, November 1, 2009 and June 1, 2009, partially offset by the impact of a stranded cost rate decrease on June 1, 2009.

Regulated Fuel for Generation and Purchased Power

Bangor Hydro has several above-market purchase power contracts pre-dating the Maine market restructuring, as well as an additional power purchase contract entered into in Q3 2011 with a wind generator. Power purchased under the older arrangements is resold to a third party at market rates as determined through a bid process administered and approved by the MPUC, while the purchased power from the wind generator is sold directly into the New England market. The difference between the cost of the power purchased under these arrangements and the revenue collected is recovered through stranded cost rates under a full reconciliation rate mechanism.

MPS has an expired power purchase contract that is currently being recovered in stranded cost rates and the related deferred asset is being amortized accordingly.

Income Taxes

Maine Utilities’ are subject to corporate income tax at the statutory rate of 40.8 percent (combined US federal and state income tax rate).

31

CARIBBEAN UTILITY OPERATIONS

Overview

Caribbean Utility Operations includes Emera’s:

• 80.1 percent investment in Light & Power Holdings Ltd. (“LPH”) and its wholly-owned subsidiary Barbados Light & Power Company Ltd. (“BLPC”). BLPC is a vertically-integrated utility and the sole provider of electricity on the island of Barbados which serves approximately 123,000 customers and is regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted BLPC a franchise to produce, transmit and distribute electricity on the island until 2028. BLPC is regulated under a cost-of-service model with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. BLPC’s approved regulated return on assets for 2011 is 10 percent. BLPC’s first rate adjustment since 1983 was approved in January 2010 and was effective March 1, 2010. A fuel pass-through mechanism ensures fuel costs are recovered. A controlling interest in LPH was acquired in January 2011, and accordingly its results are not consolidated in the 2010 and 2009 comparative information; these results contain only equity income.

• 50 percent direct and 30.4 percent indirect interest in Grand Bahama Power Company Ltd. (“GBPC”), a vertically-integrated utility and the sole provider of electricity on Grand Bahama Island. GBPC serves 19,000 customers and is regulated by GBPA, which has granted it a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass-through mechanism and flexible tariff adjustment policy to ensure costs are recovered and a reasonable return earned. A controlling interest in GBPC was acquired in December 2010, and accordingly its results are not consolidated in the 2010 and 2009 comparative information; these results contain only equity income.

• 19.1 percent interest in St. Lucia Electricity Services Limited (“Lucelec”), a vertically-integrated electric utility on the island of St. Lucia. The investment in Lucelec is accounted for on the equity basis.

32

Review of 2011

Caribbean Utility Operations’ Net Income   millions of Canadian dollars (except per share   amounts)	Three months ended December 31						Year ended December 31
	2011		2010 (adjusted)		2011		2010 (adjusted)		2009 (adjusted)
Operating revenues – regulated		$108.0		-		$406.3		-		-
Regulated fuel for generation and purchased power		73.4		-		273.7		-		-
Operating, maintenance and general (1)		23.5		$6.9		87.3		$6.9		-
Property taxes		0.3		-		1.4		-		-
Depreciation and amortization		5.4		-		22.6		-		-
Total operating expenses		102.6		6.9		385.0		6.9		-
Income from operations		5.4		(6.9)		21.3		(6.9)		-
Income from equity investments		0.7		(0.7)		2.8		4.7		$3.6
Other income (expenses), net		0.3		(2.6)		35.7		19.7		-
Interest expense, net		2.2		-		8.6		-		-
Income before provision for income taxes		4.2		(10.2)		51.2		17.5		3.6
Income tax expense		0.5		-		0.7		-		-
Net income		3.7		(10.2)		50.5		17.5		3.6
Non-controlling interest in subsidiaries		0.6		(2.5)		3.7		(2.3)		0.7
Contribution to consolidated net income		$3.1		$(7.7)		$46.8		$19.8		$2.9
Contribution to consolidated earnings per common share		$0.03		$(0.06)		$0.39		$0.17		$0.03

(1) 2010 Operating maintenance and general costs comprise costs associated with the acquisition of controlling interest in GBPC.

Caribbean Utility Operations’ contribution to consolidated net income increased by $10.8 million to $3.1 million in Q4 2011 compared to a loss of $7.7 million in Q4 2010 (adjusted). For the year ended December 31, 2011, contribution to consolidated net income increased by $27.0 million to $46.8 million in 2011 compared to $19.8 million in 2010 (adjusted) and $2.9 million in 2009 (adjusted). Highlights of the net income changes are summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31		Year ended December 31
Contribution to consolidated net income – 2009 (adjusted)				$2.9
Gain on initial investment in LPH				22.5
GBPC acquisition-related costs				(6.1)
Increased income from equity investment in LPH				5.4
Decreased income from equity investment in GBPC				(1.0)
Loss on acquisition of GBPC				(2.4)
Other				(1.5)
Contribution to consolidated net income – 2010 (adjusted)		$(7.7)		$19.8
Gain on initial investment in LPH recorded in 2010		-		(22.5)
Gain on acquisition of controlling interest in LPH in 2011		-		28.2
GBPC acquisition-related costs recorded in 2010		6.1		7.3
Increased income from increased investments in LPH and GBPC		1.1		9.3
Increased income due to regulatory deferral in GBPC		-		4.4
Other		3.6		0.3
Contribution to consolidated net income – 2011		$3.1		$46.8

33

Operating Revenues – Regulated

Q4 Operating Revenues – Regulated   millions of Canadian dollars
	2011
Residential electric revenues		$11.6
Commercial electric revenues		20.0
Industrial electric revenues		3.9
Other electric revenues		0.9
Total electric revenues		$36.4
Other – service installation revenue and fuel surcharge		71.6
Operating revenues - regulated		$108.0

Annual Operating Revenues – Regulated   millions of Canadian dollars
	2011
Residential electric revenues		$45.3
Commercial electric revenues		84.5
Industrial electric revenues		14.3
Other electric revenues		3.6
Total electric revenue		$147.7
Other – service installation revenue and fuel surcharge		258.6
Operating revenues – regulated		$406.3

Electric Revenue

Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial electricity sales are seasonal, with Q2 and Q3 the strongest periods, reflecting warmer weather.

Q4 Electric Sales Volumes   GWh
	2011
Residential		97.3
Commercial		179.9
Industrial		23.6
Other		5.7
Total		306.5

Annual Electric Sales Volumes   GWh
	2011
Residential		384.8
Commercial		701.1
Industrial		91.9
Other		21.8
Total		1,199.6

Q4 Average Electric Revenue/MWh
	2011
Dollars per MWh		$119

Annual Average Electric Revenue/MWh
	2011
Dollars per MWh		$123

Regulated Fuel for Generation and Purchased Power

Q4 Production Volumes
GWh
	2011
Oil		339.2

Annual Production Volumes
GWh
	2011
Oil	1,316.7

Q4 Average Unit Fuel Costs
	2011
Dollars per MWh		$216

Annual Average Unit Fuel Costs
	2011
Dollars per MWh	$	208

Fuel Recovery Mechanisms

BLPC

All BLPC fuel costs are passed to customers through the fuel clause adjustment (“fuel surcharge”). Fair Trading Commission, Barbados has approved the calculation of the fuel surcharge, which is adjusted on a monthly basis. BLPC has the ability to carryover an under-recovery to later months to smooth the fuel surcharge for customers.

GBPC

The base tariff for GBPC includes a component to recover the cost of $20 USD per barrel of oil consumed by GBPC for generation of electricity. The amount by which actual fuel costs exceed $20 USD dollars per barrel is recovered or rebated through the fuel surcharge, which is adjusted on a monthly basis. The methodology for calculating the amount of the fuel surcharge has been approved by GBPA.

34

Income from Equity Investments

In 2011, income from equity investments included Emera’s 19.1 percent investment in Lucelec only. Emera acquired controlling interests in GBPC in December 2010 and LPH in January 2011, and accordingly those investments are consolidated in 2011.

In 2010, income from equity investments included Emera’s 19.1 percent interest in Lucelec, its 25 percent investment in GBPC prior to acquiring the controlling interest in December 2010, and the 38.4 percent investment in LPH, which was acquired that year. In 2009, income for equity investment included the Lucelec and GBPC investments.

Regulatory Deferrals

On July 14, 2011, GBPA approved the recovery of a $4.7 million asset impairment charge recorded in 2010. As a result, the charge was reversed through earnings in Q3 2011, and recorded as a regulatory asset, which will be amortized into income over a 25 year period commencing upon completion of the new 52 MW diesel generation unit scheduled to be on line mid-2012.

On April 12, 2011, GBPA approved, as part of the fuel surcharge, the recovery of the net costs of leasing the temporary generation required to meet peak demand for electricity until the commission of a new 52-MW power plant. The amount by which the actual cost of the temporary generation exceeds what has been recovered through the fuel surcharge has been recorded as a regulatory asset which will be amortized into income.

Income Taxes

The Caribbean Utility Operations are subject to corporate income tax at the following statutory rates:

• LPH is subject to corporate income tax at the statutory rate of 25 percent;

• BLPC is subject to corporate income tax at the statutory rate of 15 percent;

• GBPC is not subject to corporate income tax; and

• Lucelec is subject to corporate income tax at the statutory rate of 30 percent. Equity income is recorded net of tax.

35

PIPELINES

Overview

Pipelines comprises Emera’s wholly-owned Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”) and the Company’s 12.9 percent interest in the Maritimes & Northeast Pipeline (“M&NP”).

Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Canaport™ re-gasified liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick, to markets in the northeastern United States. The pipeline, which went into service in July 2009, transports re-gasified liquefied natural gas for Repsol Energy Canada under a 25 year firm service agreement. The NEB, which regulates Brunswick Pipeline, has classified it as a Group II pipeline. Brunswick Pipeline is accounted for as a direct financing lease.

M&NP is a $2 billion, 1,400-kilometer pipeline which transports natural gas from offshore Nova Scotia to markets in Maritime Canada and the northeastern United States. The investment in M&NP is equity accounted.

Review of 2011

Pipelines’ Net Income   millions of Canadian dollars (except per share amounts)	Three months ended December 31								Year ended December 31
	2011		2010 (adjusted)		2011		2010 (adjusted)		2009 (adjusted)
Brunswick Pipeline
Operating revenues – regulated		$12.7		$12.0		$49.7		$48.9		$22.5
Other income (expense), net		(0.2)		0.8		0.2		1.4		18.9
Interest expense, net		7.6		7.7		30.2		30.6		21.5
Brunswick Pipeline net income		4.9		5.1		19.7		19.7		19.9
Income from equity investment		2.0		2.9		8.2		9.2		10.2
Contribution to consolidated net income		$6.9		$8.0		$27.9		$28.9		$30.1
Contribution to consolidated earnings per common share		$0.06		$0.07		$0.23		$0.25		$0.27

Pipelines’ contribution to consolidated net income decreased by $1.1 million to $6.9 million in Q4 2011 compared to $8.0 million in Q4 2010 (adjusted). For the year ended December 31, 2011, Pipelines’ contribution to consolidated net income decreased $1.0 million to $27.9 million compared to $28.9 million in 2010 (adjusted) and $30.1 million in 2009 (adjusted). Highlights of the income changes are summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31		Year ended December 31
Contribution to consolidated net income – 2009 (adjusted)				$30.1
Brunswick Pipeline – Decreased net income primarily due to unfavorable change in the mark-to-market of currency hedges, partially offset by a full year of operations in 2010				(0.2)
Decreased income from equity investment primarily due to increased MN&P financing charges on the US portion of the pipeline as a result of debt recapitalization, and the recognition of a settlement in the first half of 2009 combined with a stronger CAD in 2010				(1.0)
Contribution to consolidated net income – 2010 (adjusted)		$8.0		$28.9
Brunswick Pipeline – Decreased net income during the quarter primarily due to the unfavorable change in the mark-to-market of currency hedges		(0.2)		-
Decreased income from equity investment due to lower toll rates in M&NP		(0.9)		(1.0)
Contribution to consolidated net income – 2011		$6.9		$27.9

36

Brunswick Pipeline

The Company records the net investment in a lease under the direct finance method, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. This accounting method has the effect of recognizing higher revenues in the early years of the contract than would have been recorded if the toll revenues were recorded as received.

Income Taxes

Brunswick Pipeline is subject to corporate income tax at the statutory rate of 27.0 percent (combined Canadian federal and provincial income tax rate). M&NP’s equity income is recorded net of tax.

37

SERVICES, RENEWABLES AND OTHER

INVESTMENTS

Overview

Services, Renewables and Other Investments (“SRO”) includes Emera Energy (“Emera Energy”); Emera Utility Services Inc. (“EUS”); and Emera Newfoundland & Labrador Holdings Inc. (“ENL”), as well as other investments.

• Emera Energy includes:

• Emera Energy Services, a physical energy business which purchases and sells natural gas and electricity and provides related energy asset management services.

• Bayside Power, a 260-MW gas-fired merchant electricity generating facility in Saint John, New Brunswick.

• Emera’s 50 percent joint venture ownership of Bear Swamp, a 600-MW pumped storage hydro-electric facility in northern Massachusetts. This investment is equity accounted.

• EUS is a utility services contractor.

• ENL is a wholly-owned subsidiary of Emera focused on transmission investments related to a proposed 824-MW hydro-electric generating facility at Muskrat Falls in Labrador. These investments include an estimated $1.2 billion transmission project between Newfoundland and Nova Scotia, incorporating a 180-kilometre subsea cable (“Maritime Link Project”). In addition, together with Nalcor Energy, Newfoundland and Labrador’s provincial energy crown corporation leading the project in that province, Emera is investing in the development of a $2.1 billion electricity transmission project in Newfoundland and Labrador (“Labrador-Island Transmission Link Project”). These projects are scheduled to be in service in 2017. Development costs incurred to date have been capitalized.

• Other investments include a 6.26 percent investment in Algonquin Power & Utilities Corporation (“APUC”), a 49.999 percent investment in California Pacific Utilities Ventures (“CPUV”) and a 37.7 percent investment in Atlantic Hydrogen Inc. (“AHI”). These investments are equity accounted.

38

Review of 2011

Emera Energy and EUS are reported on an income before interest expense, net and income tax expense (recovery) (“EBIT”) basis.

Services, Renewables and Other Investments Net Income millions of Canadian dollars (except per share amounts)	Three months ended December 31						Year ended December 31
	2011		2010 (adjusted)		2011		2010 (adjusted)		2009 (adjusted)
Emera Energy		$2.4		$(0.3)		$7.6		$3.6		$10.9
EUS		2.1		3.0		4.4		7.0		1.8
Income (loss) from equity investments		0.7		0.2		2.9		(0.3)		-
Other income, net		0.5		-		14.6		-		-
Interest expense, net		-		0.2		0.9		1.2		1.7
Income tax expense (recovery)		(0.3)		0.9		1.6		0.5		(3.7)
Contribution to consolidated net income		$6.0		$1.8		$27.0		$8.6		$14.7
Bear Swamp after-tax mark-to-market adjustment		$(0.7)		$(2.6)		$(0.8)		$(8.6)		$0.7
Contribution to consolidated net income, absent the Bear Swamp after-tax mark-to-market adjustment		$6.7		$4.4		$27.8		$17.2		$14.0
Contribution to consolidated earnings per common share		$0.05		$0.02		$0.22		$0.08		$0.13
Contribution to consolidated earnings per common share, absent the Bear Swamp after-tax mark-to-market adjustment		$0.06		$0.04		$0.23		$0.15		$0.12

SRO’s contribution to consolidated net income increased by $4.2 million to $6.0 million in Q4 2011 compared to net income of $1.8 million in Q4 2010 (adjusted). For the year ended December 31, 2011, contribution to consolidated net income increased $18.4 million to $27.0 million compared to $8.6 million in 2010 (adjusted) and $14.7 million in 2009 (adjusted). Highlights of the income changes are summarized in the following table:

For the   millions of Canadian dollars	Three months ended December 31		Year ended December 31
Contribution to consolidated net income – 2009 (adjusted)				$14.7
Emera Energy – Decreased due primarily to an unfavourable change in the fair value of the net derivatives in Bear Swamp, lower equity income and the stronger CAD, partially offset by improved Emera Energy results				(7.3)
EUS – Increased primarily due to the successful completion of large construction projects and the expansion of the communications business				5.2
Income tax expense – Increased due to increased income				(4.2)
Other				0.2
Contribution to consolidated net income – 2010 (adjusted)		$1.8		$8.6
Emera Energy – Increased during the quarter and year-over-year due to a positive change in the fair value of the net derivatives in Bear Swamp; increased year-over-year also due to stronger energy marketing results, partially offset by the reversal of 2010 mark-to-market gains		2.7		4.0
EUS – Decreased due to reduced construction activity		(0.9)		(2.6)
Income from equity investments – Increased investments in APUC and CPUV		0.5		3.2
Other income, net – Increased year-over-year primarily due to an after-tax gain of $12.8 million on APUC subscription receipts		0.5		14.6
Income tax expense – Increased year-over-year primarily due to the taxable gain on APUC subscription receipts		1.2		(1.1)
Other		0.2		0.3
Contribution to consolidated net income – 2011		$6.0		$27.0

39

Emera Energy

Bear Swamp Mark-to-Market Adjustment

Bear Swamp has an agreement to supply energy and capacity to the Long Island Power Authority (“LIPA”) through to 2021. Bear Swamp has contracted with its joint venture partner to provide the power necessary to produce the requirements of the LIPA contract. One of the contracts between Bear Swamp and Emera is marked-to-market through earnings, as it does not meet the stringent accounting requirements for hedge accounting.

As at December 31, 2011 the fair value of the contract was a net liability of $9.6 million (December 31, 2010 (adjusted) – $8.2 million net liability). The fair value of this derivative is subject to market volatility of power prices and will reverse over the life of the agreement as it is realized.

Other Income, Net

Other income, net includes Emera’s 6.26 percent investment in APUC, 49.999 percent investment in CPUV and a 37.7 percent investment in AHI.

Income Taxes

Emera Energy is subject to corporate income tax at the statutory rate of 41.0 percent (combined US federal and state income tax rate) on its US sourced income and 30.9 percent (combined Canadian federal and provincial) on its Canada sourced income. Bear Swamp’s equity income is recorded net of tax.

EUS is subject to corporate income tax at the statutory rate of 30.9 percent (combined Canadian federal and provincial).

40

CORPORATE

Overview

Corporate includes certain corporate-wide functions including executive management, strategic planning, treasury services, financial reporting, tax planning, business development and corporate governance. Corporate also includes interest expense and income taxes associated with corporate activities.

Review of 2011

Corporate   millions of Canadian dollars	Three months ended December 31						Year ended December 31
	2011		2010 (adjusted)		2011		2010 (adjusted)		2009 (adjusted)
Revenue		$7.6		$7.7		$30.2		$30.6		$30.0
Corporate costs		4.4		9.2		27.3		27.3		21.4
Interest expense		8.5		7.7		33.9		32.0		22.8
Income tax recovery		(4.1)		(3.5)		(16.5)		(14.0)		(14.5)
		(1.2)		(5.7)		(14.5)		(14.7)		0.3
Preferred stock dividends		-		-		6.6		3.0		-
Contribution to consolidated net income		$(1.2)		$(5.7)		$(21.1)		$(17.7)		$0.3

Revenue

Revenue consists of intercompany interest and preferred dividends from Brunswick Pipeline.

Corporate Costs

Corporate costs decreased by $4.8 million to $4.4 million in Q4 2011 compared to $9.2 million in Q4 2010 (adjusted) due primarily to decreased deferred compensation and business acquisition costs as well as foreign exchange gains resulting from a stronger CAD. Corporate costs increased $5.9 million to $27.3 million in 2010 (adjusted) compared to $21.4 million in 2009 due to acquisition-related costs.

Interest Expense

Interest expense increased $0.8 million to $8.5 million in Q4 2011 compared to $7.7 million in Q4 2010 (adjusted). Interest expense increased $1.9 million to $33.9 million for the year ended December 31, 2011 compared to $32.0 million in 2010 (adjusted) and $22.8 million in 2009 due to an increase in borrowings primarily to fund business acquisitions.

Income Tax Recovery

Income tax recovery increased by $0.6 million to $4.1 million in Q4 2011 compared to $3.5 million in Q4 2010 (adjusted) and increased $2.5 million to $16.5 million for the year ended December 31, 2011 compared to $14.0 million in 2010 (adjusted) primarily due to increased interest expense.

Preferred Stock Dividends

Preferred stock dividends increased $3.6 million to $6.6 million for the year ended December 31, 2011; compared to $3.0 million in 2010 (adjusted); and increased for the year ended December 31, 2010, by $3.0 million from nil in 2009 (adjusted), due to the issuance of preferred shares in June 2010.

41

OUTLOOK

Emera will continue to pursue investment opportunities related to the transformation of the energy industry to produce lower emissions. Emera has embarked on a significant capital plan to increase the Company’s generation from renewable sources, to improve the transmission connections within its service territories, and to expand access to natural gas as Emera transitions to a cleaner, greener company.

Although markets in Maine and Nova Scotia are otherwise mature, the transformation of energy supply to lower emission sources has created the opportunity for organic growth within NSPI and Emera’s Maine Utility Operations. The utilities expect average income growth to be 3 percent to 5 percent annually over the next five years as new investments are made in renewable generation and transmission.

NSPI

NSPI anticipates earning a regulated ROE within its allowed range in 2012. NSPI continues to implement its strategy, which is focused on regulated investments in renewable energy and system reliability projects with an annual capital expenditure plan of approximately $330 million in 2012. NSPI expects to finance its capital expenditures with funds from operations and debt.

Maine Utility Operations

USD income from Maine Utility Operations is expected to be slightly higher in 2012 compared to 2011 due to the recovery of investments in new transmission assets. In 2012, Maine Utilities expects to invest approximately $116 million USD, including approximately $78 million USD for major transmission projects.

Caribbean Utility Operations

Income from Caribbean Utility Operations is expected to be higher in 2012 compared to 2011 primarily as a result of increased capital investments in LPH and GBPC. Caribbean Utility Operations plans to invest approximately $63 million in capital programs in 2012.

Pipelines

Income from Pipelines is expected to decline marginally in 2012 as compared to 2011 as a result of capital lease accounting treatment which yields declining earnings over the life of the asset.

Services, Renewables and Other Investments

Income from Services, Renewables and Other Investments is expected to be consistent with 2011. ENL plans to invest approximately $100 million on the Maritime Link Project and Labrador-Island Transmission Link Project in 2012.

Corporate

Income from Corporate is expected to be lower in 2012 compared to 2011 due to higher interest costs due to business growth.

42

LIQUIDITY AND CAPITAL RESOURCES

The Company generates cash primarily through the generation, transmission and distribution of electricity through its regulated electric utilities. The utilities’ customer bases are diversified by both sales volumes and revenues among customer classes. Circumstances that could affect the Company’s ability to generate cash include general economic downturns in Emera’s markets, the loss of one or more large customers, regulatory decisions affecting customer rates and changes in environmental legislation. Emera’s subsidiaries are capable of paying dividends to Emera provided they do not breach their debt covenants after giving effect to the dividend payment.

In addition to internally generated funds, Emera and its subsidiaries have, in aggregate access to $1.3 billion committed syndicated revolving bank lines of credit as discussed in the table below. In August 2011, Emera increased its committed syndicated bank line from $600 million to $700 million, and NSPI reduced its committed syndicated revolving bank line from $600 million to $500 million. The maturity of both facilities was extended from June 2013 to June 2015. NSPI has an active commercial paper program for up to $400 million, of which outstanding amounts are 100 percent backed by NSPI’s bank line referred to above, which results in an equal amount of credit being considered drawn and unavailable.

As at December 31, 2011, the Company’s total credit facilities, outstanding borrowings and available capacity were as follows:

millions of dollars	Maturity		Revolving Credit Facilities		Utilized		Undrawn and Available
Emera – Operating and acquisition credit facility		June 2015 –Revolver		$700		$263		437
NSPI – Operating credit facility		June 2015 –Revolver		500		318		182
Bangor Hydro – in USD – Operating credit facility		September 2013 –Revolver		80		66		14
Other – in USD – Operating credit facilities		2012		21		8		13

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.

Debt Management

Emera

In February 2011, Emera filed an amended and restated short form base shelf prospectus. This amendment increased the aggregate principal amount of debt securities and preferred shares that may be offered from time to time under the short form base shelf prospectus from $500 million to $650 million. As at December 31, 2011, $150 million in preferred shares and $250 million of medium-term notes have been issued under the short form base shelf prospectus and shelf prospectus supplements.

The weighted average coupon rate of Emera’s outstanding medium-term notes as at December 31, 2011 was 3.93 percent (2010 – 4.45 percent). All of the outstanding debt matures within the next ten years. The quoted yield for the same or similar issues of the same remaining maturities was 2.88 percent as at December 31, 2011 (2010 – 3.73 percent).

43

Emera’s credit ratings issued by Dominion Bond Rating Service (“DBRS”) and Standard & Poor’s (“S&P”) are as follows:

	DBRS		S&P
Long-term corporate		BBB (high)		BBB+
Preferred stock		Pfd-3 (high)		P-2 (Low)

NSPI

In May 2011, NSPI filed an amendment to its amended and restated short form base shelf prospectus and an amendment to its prospectus supplement for medium-term notes (unsecured). These amendments increased the aggregate principal amount of debt securities and medium-term notes that may be offered from time to time under the short form base shelf prospectus and prospectus supplement from $500 million to $800 million. As at December 31, 2011, $300 million in medium-term notes have been issued under NSPI’s short form base shelf prospectus and prospectus supplement since their initial filing in 2010.

Concurrently with the Canadian filing of these amendments, NSPI also filed a registration statement with the SEC to register debt securities having an aggregate initial offering price of up to $500 million for sale in the United States. As discussed in the NSPI Developments section, on December 12, 2011, NSPI filed a post-effective amendment to its registration statement with the SEC, removing from registration all unsold debt securities as of that date.

The weighted average coupon rate on NSPI’s outstanding medium-term and debenture notes as at December 31, 2011 and 2010 was 6.74 percent. Approximately 27 percent of the debt matures over the next ten years, 70 percent matures between 2021 and 2040 and 3 percent, matures in 2097. The quoted yield for the same or similar issues of the same remaining maturities was 3.51 percent as at December 31, 2011 (2010 – 4.50 percent).

NSPI’s credit ratings issued by DBRS and S&P’s are as follows:

	DBRS		S&P
Corporate		N/A		BBB+
Senior unsecured debt		A (low)		BBB+
Preferred stock		Pfd-2 (low)		P-2 (low)
Commercial paper		R-1 (low)		A-1 (low)

Maine Utility Operations

On January 31, 2012, Bangor Hydro completed the issue of an unsecured $70.0 million USD senior note. The Series 2012-A Senior Note bears interest at a rate of 3.61 percent per annum until January 31, 2022. The net proceeds of the note offering were used to repay borrowings under the revolving credit facility.

On April 27, 2011, MPS renewed its existing $10 million USD revolving credit facility, with a new expiration date of December 31, 2012.

On June 24, 2010, Bangor Hydro entered into a 39 month revolving credit facility for $80 million USD.

The weighted-average coupon rate on Bangor Hydro’s outstanding long-term debt as at December 31, 2011 was 7.01 percent (2010 – 6.96 percent). Approximately 87 percent of the debt matures over the next 10 years; the remaining matures in 2022. The quoted market weighted average interest rate for the same or similar issues of the same remaining maturities was 2.54 percent as at December 31, 2011 (2010 – 3.81 percent).

The weighted-average coupon rate on MPS’ outstanding long-term debt as at December 31, 2011 and 2010 was 4.46 percent. All of the debt matures over the next 10 years. The quoted market weighted average interest rate for the same or similar issues of the same remaining maturities was 3.58 percent as at December 31, 2011 (2010 – 4.85 percent).

44

Bangor Hydro and MPS have no public debt, and accordingly have no requirement for public credit ratings. Both utilities believe that their credit facility provides adequate access to capital to support current operations and a base level of capital expenditures. For additional capital needs, both utilities expect to have sufficient access to competitively priced funds in the unsecured debt market.

Caribbean Utility Operations

On January 25, 2012, GBPC entered into an unsecured credit agreement with Scotiabank (Bahamas) Limited in the amount of $56.2 million USD. The proceeds of the credit agreement will be used to finance the construction of a 52-MW power plant on Grand Bahama Island. The credit agreement bears interest at a rate of the three month LIBOR rate plus 1.2 percent and is repayable in forty equal, consecutive quarterly installments over a ten year period. The payments commence at the earlier of six months after the completion of the construction of the power plant or January 31, 2013.

In October 2011, GBPC entered into a 12 month revolving credit facility for $11 million Bahamian dollars.

The weighted-average coupon rate on BLPC’s’ outstanding long-term debt as at December 31, 2011, was 6.30 percent. Approximately 77 percent of the debt matures over the next 10 years; the remaining issue matures in 2025. The market weighted average interest rate is based on the last rate of debt issuances of 6.85 percent.

The weighted-average coupon rate on GBPC’s outstanding long-term debt as at December 31, 2011, was 6.64 percent (2010 – 6.61 percent). Approximately 66 percent of the debt matures over the next 10 years; the remaining issue matures in 2023. The market weighted average interest rate is 7.00 percent as at December 31, 2011 (2010 – 5.86 percent), based on the last rate of debt issuances.

BLPC and GBPC have no public debt, and accordingly have no requirement for public credit ratings. Both utilities believe their credit facilities provide adequate access to capital to support current operations and a base level of capital expenditures. For additional capital needs, both utilities expect to have sufficient access to competitively priced funds in the unsecured debt market.

Contractual Obligations

As at December 31, 2011, commitments for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	Total		2012		2013		2014		2015		2016		Thereafter
Long-term debt (1)		$3,307.0		$30.0		$380.9		$301.5		$591.9		$254.8		$1,747.9
Purchased power (2)		1,840.8		100.3		113.4		117.6		117.8		118.0		1,273.7
Coal, biomass, oil and natural gas supply		1,188.1		233.0		159.9		109.5		63.4		22.4		599.9
Pension and post-retirement obligations (3)		757.9		66.3		67.3		66.9		60.1		51.5		445.8
Asset retirement obligations		361.1		5.3		2.3		2.4		2.0		3.1		346.0
Transportation (4)		150.0		72.5		29.3		26.8		16.5		2.2		2.7
Long-term service agreements (5)		35.1		12.2		11.3		6.1		5.0		0.5		-
Capital projects		78.2		56.3		3.5		0.6		3.9		-		13.9
Leases (6)		32.3		3.9		3.3		3.2		3.1		2.8		16.0
Other		18.2		5.2		3.8		3.6		3.6		1.0		1.0
		$7,768.7		$585.0		$775.0		$638.2		$867.3		$456.3		$4,446.9

(1) Long-term debt: Emera’s and NSPI’s revolving credit facilities mature in June 2015.

(2) Purchased power: annual requirement to purchase 100 percent of electricity production from independent power producers over varying contract lengths up to 25 years.

(3) Pension and post-retirement obligations: are based on regulatory requirements and assume that members stop accruing service effective December 31, 2011. As most of Emera’s defined benefit pension plans still allow continued accrual of service and each plan’s contribution requirements are reassessed on a regular basis, actual future pension contributions will differ from the amounts shown.

(4) Transportation: purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines.

(5) Long-term service agreements: outsourced management of the Company’s computer and communication infrastructure, vegetation management and maintenance of certain generation equipment.

(6) Leases: operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

45

Capital Expenditures

Capital expenditures for 2011, including AFUDC, were approximately $515 million and included:

• $320 million in NSPI;

• $100 million in Maine Utility Operations;

• $70 million in Caribbean Utility Operations; and

• $25 million in Services, Renewables and Other Investments.

Forecasted Gross Consolidated Capital Expenditures

For the year ended   December 31, 2012   millions of Canadian   dollars	NSPI		Maine Utility Operations		Caribbean Utility Operations		Services, Renewable and other investments		Corporate		Total
Generation		$142		NA		$45		$13		-		$200
Transmission		68		$83		11		100		-		262
Distribution		72		18		3		-		-		93
Facilities, equipment, vehicles and other		48		16		4		-		-		68
Total		$330		$117		$63		$113		-		$623

Significant Individual Capital Projects

millions of   Canadian dollars	Nature of Project	Pre-2012 Spending		2012 Forecast		Post-2012 Forecast		Expected year of completion
NSPI	Port Hawkesbury Biomass		$143		$56		$8		2013
	Transmission		-		1		11		2013
	LED Streetlight Conversion		-		6		94		2016
	Marshall Falls Hydro Upgrade		-		3		15		2017
Maine Utility Operations	Transmission		65		45		79		2012 – 2014
	Technology		3		11		7		2014
Caribbean Utility Operations	West Sunrise Plant		41		38		-		2012
Services, Renewables and other investments	Bayside Power Gas Turbine Upgrade		9		13		4		2012
	Maritime Link Project		10		30		1,160		2017
	Labrador-Island Transmission Project		-		70		530		2017

PENSION FUNDING

For funding purposes, Emera determines required contributions to its largest defined benefit pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the impact of investment gains and losses are recognized over a three year period. The cash required in 2012 for defined benefit pension plans will be approximately $73.7 million (2011 – $51.9 million actual). All pension plan contributions are tax deductible and will be funded with cash from operations.

46

Emera’s defined benefit pension plans employ a long-term strategic approach with respect to asset allocation, real return and risk. The underlying objective is to earn an appropriate return given the Company’s goal of preserving capital within an acceptable level of risk for the pension fund investments.

To achieve the overall long-term asset allocation pension assets are overseen by external investment managers per the pension plan’s investment policy and governance framework. The asset allocation includes investments in the assets of Canadian and global equities, domestic bonds, and short-term investments. Emera reviews investment manager performance on a regular basis and adjusts the plans’ asset mixes as needed in accordance with the pension plan’s investment policy.

Emera’s projected contributions to defined contribution pension plans are $6.5 million for 2012 (2011 – $6.2 million actual).

OFF-BALANCE SHEET ARRANGEMENTS

Upon privatization of the former provincially owned NSPC in 1992, NSPI became responsible for managing a portfolio of defeasance securities, which as at December 31, 2011, totaled $1.0 billion. The securities are held in trust for Nova Scotia Power Finance Corporation (“NSPFC”), an affiliate of the Province of Nova Scotia. NSPI is responsible for ensuring the defeasance securities provide the principal and interest streams to match the related defeased NSPC debt. Approximately 73 percent of the defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance portfolio has a market value higher than the related debt, reducing the future risk of this portion of the portfolio.

Emera had the following guarantees and letter of credits as at December 31, 2011:

• NSPI has provided a limited guarantee for the indebtedness of Renewable Energy Services Ltd. (“RESL”). The guarantee is up to a maximum of $23.5 million. As at December 31, 2011, RESL’s indebtedness under the loan agreement was $21.9 million. NSPI holds a security interest in the present and future assets of RESL.

• Emera has provided a guarantee to LIPA on behalf of Bear Swamp for Bear Swamp’s long-term energy and capacity supply agreement (“Agreement”) with LIPA, which expires on April 30, 2021. The guarantee is for 50 percent of the relevant obligations under the Agreement up to a maximum of $18.6 million USD. As at December 31, 2011, the fair value of the Agreement is positive.

• Emera has provided a guarantee to the Bank of Nova Scotia on behalf of Bear Swamp for Bear Swamp’s interest rate swaps entered into between Bear Swamp and the Bank of Nova Scotia which expires on May 9, 2012. The guarantee is for 50 percent of the relevant obligations up to a maximum of $1.0 million USD. In the event Emera was required to make a payment to the Bank of Nova Scotia under this guarantee, the guarantee provides that Emera is able to seek recovery from Bear Swamp’s creditors after Bear Swamp has paid its debts in full. As at December 31, 2011, the fair value of that agreement is positive.

• At the request of Emera and its subsidiaries, a financial institution has issued standby letters of credit in the amount of $11.4 million for the benefit of third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one year term and are renewed annually as required.

• A financial institution has issued a standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2012 and is renewed annually. The amount committed as at December 31, 2011 was $22.5 million.

47

• A financial institution has issued a standby letter of credit to secure obligations under an unfunded pension plan in BHE. The letter of credit expires in October 2012 and is renewed annually. The amount committed as at December 31, 2011 was $2.2 million USD.

• A financial institution has been issued direct pay letters of credit totaling $23.9 million USD to secure principal and interest payments related to Maine Public Utilities Financing Bank bonds issued on behalf of MPS, related to qualifying distribution assets.

No liability has been recognized on the consolidated balance sheets related to any potential obligation under these guarantees and letters of credit.

TRANSACTIONS WITH RELATED PARTIES

In the ordinary course of business, Emera purchased natural gas transportation capacity from M&NP, an investment under significant influence of the Company, totaling $10.6 million (2010 – $12.8 million) for the three months ended December 31, 2011, and $47.3 million (2010 – $55.1 million) for the year ended December 31, 2011. The amount is recognized in “Regulated fuel for generation and purchased power” or netted against energy marketing margin in “Non-regulated operating revenues” and is measured at the exchange amount. As at December 31, 2011, the amount payable to the related party was $3.3 million (December 31, 2010 – $3.9 million), and is under normal interest and credit terms.

DIVIDENDS AND PAYOUT RATIOS

Emera Incorporated’s common dividend rate was $1.31 ($0.3250 per quarter in Q1, Q2 and Q3 and $0.3375 in Q4) per common share in 2011 and $1.16 ($0.2725 in Q1, $0.2825 in Q2 and Q3 and $0.3250 in Q4) per common share in 2010, representing a payout ratio of approximately 65.8 percent in 2011 and 69.2 percent in 2010.

On September 23, 2011, Emera’s Board of Directors approved an increase in the annual common share dividend rate from $1.30 to $1.35, and accordingly declared a quarterly dividend of $0.3375 per common share.

In February 2010, the Board of Directors approved a quarterly dividend increase, effective May 3, 2010, to $0.2825 per common share, and in September 2010, approved a further increase to $0.3250 effective November 1, 2010 reflecting an increase on an annualized basis to $1.30 per common share.

Effective September 25, 2009, Emera changed its Common Shareholders Dividend Reinvestment and Share Purchase Plan to provide for a discount of up to 5 percent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends under this Plan.

RISK MANAGEMENT AND FINANCIAL

INSTRUMENTS

Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management practices are overseen by the Board of Directors. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operations.

48

The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. Collectively these contracts are considered “derivatives”.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts where the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to Accumulated Other Comprehensive Loss (“AOCL”) and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period.

Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value, with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the UARB. 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 when the derivatives settle. 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 through the FAM.

Derivatives that do not meet any of the above criteria are designated as HFT and are recognized on the balance sheet at fair value. All gains and losses are recognized in net income of the period unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies.

Hedging Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives in valid hedging relationships:

As at   millions of Canadian dollars	December 31 2011		December 31 2010 (adjusted)
Derivative instrument assets (current and other assets)		$5.7		$7.0
Derivative instrument liabilities (current and long-term liabilities)		(27.8)		(18.3)
Net derivative instrument liabilities		$(22.1)		$(11.3)

49

Hedging Impact Recognized in Net Income

The Company recognized the following gains (losses) related to the effective portion of hedging relationships under the following categories:

For the millions of Canadian dollars	Three months ended December 31		Year ended December 31
	2011	2010	2011	2010
		(adjusted)		(adjusted)
Regulated operating revenues	$0.3	-	$2.7	-
Non-regulated fuel and purchased power	(2.3)	$(2.1)	(7.0)	$(8.6)
Other income (expenses), net	(0.2)	-	(0.3)	-
Effectiveness net losses	$(2.2)	$(2.1)	$(4.6)	$(8.6)

The effectiveness gains (losses) reflected in the above table would be offset in net income by the change in 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 December 31			Year ended December 31
		2011	2010		2011	2010
			(adjusted)			(adjusted)
Non-regulated fuel and purchased power		$0.5	-		$(0.4)	-
Ineffectiveness gains (losses)		$0.5	-		$(0.4)	-

Regulatory Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to derivatives receiving regulatory deferral:

As at   millions of Canadian dollars	December 31 2011		December 31 2010 (adjusted)
Derivative instrument assets (current and other assets)		$44.5		$59.9
Regulatory assets (current and other assets)		46.3		34.2
Derivative instrument liabilities (current and long-term liabilities)		(46.3)		(34.2)
Regulatory liabilities (current and long-term liabilities)		(44.5)		$(59.9)
Net asset (liability)		-		-

Regulatory Impact Recognized in Net Income

The Company recognized the following (losses) gains related to derivatives receiving regulatory deferral as follows:

For the   millions of Canadian dollars	Three months ended December 31			Year ended December 31
		2011	2010		2011	2010
			(adjusted)			(adjusted)
Other income (expenses), net		-	$1.0		-	$1.5
Regulated fuel for generation and purchased power		$(3.8)	(10.9)		$(21.3)	(66.8)
Net losses		$(3.8)	$(9.9)		$(21.3)	$(65.3)

50

Held-for-trading Items Recognized on the Balance Sheets

The Company has the following categories on the balance sheet related to HFT derivatives:

As at   millions of Canadian dollars	December 31 2011			December 31 2010 (adjusted)
Derivative instruments assets (current and other assets)		$16.7			$18.8
Derivative instruments liabilities (current and long-term liabilities)		(14.7	)		(13.2	)
Net derivative instrument assets		$2.0			$5.6

Held-for-trading Items Recognized in Net Income

The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in net income:

For the   millions of Canadian dollars	Three months ended December 31			Year ended December 31
		2011	2010 (adjusted)		2011	2010 (adjusted)
Non-regulated operating revenues		$4.0	$6.2		$14.0	$21.2
Other income (expenses), net		0.2	0.9		(0.1)	2.7
Net gains		$4.2	$7.1		$13.9	$23.9

Business Risks

Measurement of Risk

Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach. Certain risk management activities for Emera are overseen by the Enterprise Risk Management Committee to ensure such risks are appropriately assessed, monitored and controlled within predetermined risk tolerances established through approved policies.

The Company’s risk management activities are focused on those areas that most significantly impact profitability, quality of income and cash flow. These risks include, but are not limited to, exposure to commodity prices, foreign exchange, acquisition risk, interest rates, commercial relationships, credit, labour, weather and regulatory risks, and changes in environmental legislation.

In this section, Emera describes some of the principal risks management believes could materially affect its business, revenues, operating income, net income, net assets or liquidity or capital resources. The nature of risk is such that no list can be comprehensive, and other risks may arise or risks not currently considered material may become material in the future.

Commodity Price Risk

A large portion of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. Fuel contracts may be exposed to broader global conditions which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts. In addition, the adoption and implementation of FAMs in certain subsidiaries has further helped manage this risk.

51

Coal/Petroleum Coke

A substantial portion of NSPI’s coal and petroleum coke (“petcoke”) supply comes from international suppliers, which was contracted at or near the market prices prevailing at the time of contract. The Company has entered into fixed-price and index price contractual arrangements for coal with several suppliers as part of the fuel procurement portfolio strategy. All index-priced contractual arrangements are matched with a corresponding financial instrument to fix the price. The approximate percentage of coal and petcoke requirements contracted as at December 31, 2011 are as follows:

2012 – 94 percent

2013 – 32 percent

2014 – 15 percent

Heavy Fuel Oil

NSPI manages exposure to changes in the market price of heavy fuel oil through the use of swaps, options, and forward contracts. For 2012 and 2013, NSPI currently does not have heavy fuel oil hedging requirements due to favourable natural gas pricing.

BLPC and GBPC do not use derivatives to manage the changes in market price of heavy fuel oil. GBPC pays the spot market rate, and BLPC’s fuel pricing is based on the three-day average market price.

Natural Gas

NSPI has entered into multi-year contracts to purchase approximately 38,400 mmbtu of natural gas per day in 2012, and 20,100 mmbtu of natural gas per day in 2013. Volumes exposed to market prices are managed using financial instruments where the fuel is required for NSPI’s generation; and the balance is sold against market prices when available for resale. As at December 31, 2011, amounts of natural gas volumes that have been economically and/or financially hedged are approximately as follows:

2012 – 83 percent

2013 – 31 percent

Foreign Exchange Risk

The Company enters into foreign exchange forward and swap contracts to limit exposure on foreign currency transactions such as fuel purchases, revenue streams and capital expenditures.

NSPI

The risk due to fluctuation of the CAD against the USD for fuel purchases in NSPI is measured and managed. In 2012, NSPI expects approximately 63 percent of its anticipated net fuel costs to be denominated in USD. Forward contracts to buy $256.0 million USD were in place as at December 31, 2011 at a weighted average rate of $0.9912, representing 81 percent of 2012’s anticipated USD requirements. Forward contracts to buy $752.0 million USD in 2013 through 2016 at a weighted average rate of $1.0096 were in place as at December 31, 2011. These contracts cover 60 percent of anticipated USD requirements in these years. As at December 31, 2011, there were no fuel-related foreign exchange swaps outstanding.

Bayside Power

Bayside Power uses foreign exchange forward contracts to hedge the currency risk for capital projects denominated in foreign currencies. Forward contracts to buy €9.6 million were in place as at December 31, 2011 at a weighted average rate of $1.3770 for capital projects in 2012. Forward contracts to buy €2.8 million were in place as at December 31, 2011 at a weighted average rate of $1.3951 for capital projects in 2015.

52

Brunswick Pipeline

Brunswick Pipeline uses forward contracts to hedge the currency risk associated with revenue streams denominated in foreign currencies. Forward contracts to sell $53.8 million USD in 2012 were in place as at December 31, 2011 at an average rate of $1.0654 and sell $78 million USD in 2013 through 2016 at a weighted average rate of $1.0591. These contracts cover 95 percent of anticipated USD revenue inflows in 2012 and 33 percent of anticipated USD revenue inflows in 2013 through 2016.

Acquisition Risk

The risks associated with Emera’s acquisition strategy include the availability of suitable acquisition candidates, obtaining the necessary regulatory approval for any acquisition and assimilating and integrating acquired companies into the Company. In addition, potential difficulties inherent in acquisitions may adversely affect the results of an acquisition. These include delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies from completed transactions.

Emera mitigates these risks by following systematic procedures for integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to close monitoring and review by the Board of Directors.

Interest Rate Risk

Emera utilizes a combination of fixed and variable rate debt financing for operations and capital expenditures resulting in an exposure to interest rate risk. The Company seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. Floating-rate debt is estimated to represent approximately 15 percent of total debt in 2012. The Company has two interest rate hedging contracts outstanding as at December 31, 2011, fixing the variable interest rates on $22.6 million USD of Maine Public Utilities Financing Bank bonds at MPS.

Commercial Relationships Risk

NSPI

For the year ended December 31, 2011, NSPI’s five largest customers contributed approximately 13.3 percent (2010 – 14.7 percent) of electric revenues. The loss of a large customer could have a material effect on NSPI’s operating revenues. NSPI works to mitigate this risk through the regulatory process.

NSPI’s largest customer was granted creditor protection under the Companies’ Creditors Arrangement Act (“CCAA”), and suspended operations in September 2011. This customer contributed approximately 6.0 percent (2010 – 7.9 percent) of NSPI’s electric revenues for the year ended December 31, 2011. NSPI is working to recover an outstanding receivable owing from this customer through the CCAA claims process, including a claim for set-off against amounts owing from NSPI to the customer that exceeds the amount receivable. The 2012 General Rate Decision, approved by the UARB, provides for any unrecovered non-fuel electric charges in 2012 related to this customer to be deferred and recovered beginning in 2013.

53

Brunswick Pipeline

Brunswick Pipeline has a 25 year firm service agreement with Repsol Energy Canada (“REC”). The pipeline was used solely in 2011 and 2010 to transport natural gas from the Canaport LNG terminal in Saint John, New Brunswick to the United States border for REC. The risk of non-payment is mitigated as Repsol YPF, S.A (“Repsol”), the parent company of REC, has provided Brunswick Pipeline with a guarantee for all RECs’ payment obligations under the firm service agreement. As at December 31, 2011 the net investment in direct financing lease with Repsol was $493.8 million. Repsol is rated investment grade BBB/Baa1; credit ratings and other company information are monitored on an ongoing basis. There is currently no allowance for credit losses related to this agreement.

Bayside Power

Bayside Power sells all its generation during the months of November through March to NB Power in accordance with a long-term purchase power agreement (“PPA”). Revenue from this PPA contributed 46.5 percent (2010 – 48.0 percent) to Bayside Power’s electric revenues for the year ended December 31, 2011. The PPA expires March 31, 2021, with an option to renew for an additional five year term, provided both parties consent to the renewal.

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 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.

Labour Risk

Certain Emera employees are subject to collective labour agreements. Approximately 55 percent of the full-time and term employees at NSPI, BLPC, GBPC, Bangor Hydro, EUS, and MPS are represented by local unions. Approximately 45 percent of the labour force is covered by collective labour agreements that will expire within the next twelve months. Emera seeks to manage this risk through ongoing discussions with the local unions.

Weather Risk

Shifts in weather patterns affect electric sales volumes and associated revenues. Extreme weather events generally result in increased operating costs associated with restoring power to customers. Emera responds to significant weather event related outages according to each subsidiary’s respective Emergency Services Restoration Plan.

Regulatory Risk

The Company’s rate-regulated subsidiaries are subject to risk in the recovery of costs and investments in a timely manner. The Company manages this risk through ongoing stakeholder consultation and engagement on aspects such as utility operations, rate filings and capital plans.

NSPI

NSPI faces risk with respect to the recovery of costs and investments in a timely manner. As a regulated, cost-of-service utility with an obligation to serve, NSPI must obtain regulatory approval to change general electricity rates and riders. Costs and investments can be recovered after and once the UARB has approved recovery in adjustments to rates or riders, which normally requires a public hearing process.

54

During public hearing processes, consultants and customer representatives scrutinize the Company’s costs, actions and plans, and the UARB determines whether to allow recovery and to adjust rates based upon NSPI’s evidence and any contrary evidence from other hearing participants. The Company manages this regulatory risk through transparent regulatory disclosure, ongoing stakeholder consultation and multi-party engagement on aspects such as utility operations, rate filings and capital plans. The Company employs a collaborative regulatory approach through technical conferences and negotiated settlements.

Bangor Hydro

Bangor Hydro’s business consists of three primary components which are each governed by their own regulatory structure. The components include distribution, transmission and stranded cost recoveries.

Distribution Operations

Bangor Hydro’s distribution business operates under the regulation of the MPUC and operates under a traditional cost-of-service regulatory structure. Distribution rates are set based on an allowed ROE of 10.2 percent, on a common equity component of 50 percent.

Transmission Operations

Bangor Hydro’s local transmission rates are set by the FERC annually on June 1, based upon a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted transmission investments and expenses. The allowed ROE for these local transmission investments is 11.14 percent. The common equity component is based upon the prior calendar year actual average balances. On June 1, 2011, Bangor Hydro’s local transmission rates decreased by approximately 10 percent (2010 – increased 37 percent).

Bangor Hydro’s bulk transmission assets are managed by the ISO-New England (“ISO”) as part of a region-wide pool of assets. The ISO manages the regions’ bulk power generation and transmission systems and administers the open access transmission tariff. Currently, Bangor Hydro, along with all other participating transmission providers, recovers the full cost of service for their transmission assets, from distribution companies in New England, based on a regional formula that is updated on June 1 of each year. This formula is based on prior year regionally funded transmission investments and expenses, adjusted for current year forecasted investments and expenses. Bangor Hydro’s allowed ROE for these transmission investments ranges from 11.64 percent to 12.64 percent, and the common equity component is based upon the prior calendar year average balances. The participating transmission providers are also required to contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent.

On June 1, 2010, Bangor Hydro’s regional transmission revenue requirement increased by 22 percent; and on June 1, 2011, it increased by a further 9 percent.

Stranded Cost Recoveries

Electric utilities in Maine are entitled to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC. Generally, the regulatory rates to recover stranded costs are set every three years on a levelized basis and determined under a traditional cost of service approach.

In May 2011, the MPUC approved an approximate 27 percent increase in Bangor Hydro’s stranded cost rates for the period of June 1, 2011 to February 28, 2014. The increased stranded cost revenues are offset, for the most part, by changes in regulatory amortizations, purchased power expense and resale of purchased power. The allowed ROE used in setting these new stranded cost rates is 7.4 percent, with a common equity component of 48 percent.

55

While the stranded cost revenue requirements differ throughout the period due to changes in annual stranded costs, the actual annual stranded cost revenues are the same during the period. To levelize the impact of the varying revenue requirements, cost or revenue deferrals are recorded as a regulatory asset or liability, and addressed in subsequent stranded cost rate proceedings, where customer rates are adjusted accordingly.

MPS

Similar to Bangor Hydro, MPS’ business consists of three primary components which are each governed by their own regulatory structure. The components are distribution, transmission and stranded cost recoveries.

Distribution Operations

MPS’ distribution business operates under the regulation of the MPUC and operates under a traditional cost-of-service regulatory structure. Distribution rates are set based on an allowed ROE of 10.2 percent, on a common equity component of 50 percent.

Transmission Operations

MPS local transmission rates are set annually based on a formula through its OATT. Rates derived from the previous calendar year results go into effect June 1 for wholesale customers and July 1 for retail customers. The allowed ROE for transmission operations is 10.5 percent, and is based on the actual prior calendar year common equity balances. The allowed ROE is determined by negotiation with customers in the formula change years of the OATT, which occur every three years. The last OATT formula change year was 2009. On June 1, 2011, MPS’ local transmission rates increased by 3 percent for wholesale customers (2010 – increased 63 percent) and by 4 percent for retail customers (2010 – increased by 64 percent) on July 1, 2011.

MPS’ electric service territory is not interconnected to the New England bulk power systems, and MPS is not a member of ISO New England.

Stranded Cost Recoveries

In December 2011, the MPUC approved MPS’ stranded cost rates for the three-year period January 1, 2012 through December 31, 2014. This revised three-year agreement, which amortizes essentially all of MPS’ remaining stranded costs, has an ROE of 7.2 percent and a common equity component of 50 percent. Any residual stranded costs remaining after December 31, 2014 will be recovered in future rate proceedings.

The Barbados Light & Power Company Limited

BLPC, a wholly-owned subsidiary of LPH, is the sole electric utility on the island of Barbados. BLPC is subject to regulation under the Utilities Regulation (Procedural) Rules 2003 (“Rules”) by Fair Trading Commission, Barbados, an independent regulator. The Rules give the Fair Trading Commission, Barbados utility regulation functions which include establishing principles for arriving at rates to be charged, monitoring the rates charged to ensure compliance, and setting the maximum rates for regulated utility services. The government of Barbados has granted BLPC a franchise to produce, transmit and distribute electricity on the island until 2028.

BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and providing an appropriate return to investors. BLPC’s approved regulated return on assets for 2011 is 10 percent.

BLPC’s first rate adjustment since 1983 was approved in January 2010 and was effective March 1, 2010.

All BLPC fuel costs are passed to customers through the fuel surcharge. Fair Trading Commission, Barbados has approved the calculation of the fuel surcharge, which is adjusted on a monthly basis. BLPC has the ability to carryover an under-recovery to later months to smooth the fuel surcharge for customers.

56

Grand Bahama Power Company Limited

GBPC is the sole utility operator on Grand Bahama Island. GBPA regulates the utility and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit, and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policy to ensure that costs are recovered and a reasonable return earned.

The base tariff for GBPC includes a component to recover the cost of $20 USD per barrel of oil consumed by GBPC for generation of electricity. The amount by which actual fuel costs exceed $20 USD dollars per barrel is recovered or rebated through the fuel surcharge, which is adjusted on a monthly basis. The methodology for calculating the amount of the fuel surcharge has been approved by GBPA.

Changes in Environmental Legislation

NSPI is subject to regulation by federal, provincial, state, regional, and local authorities with regard to environmental matters primarily related to its utility operations. Changes to climate change and air emissions standards could adversely affect utility operations.

In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI.

Conformance with legislative and NSPI requirements are verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the 2011 and 2010 audits.

NSPI is committed to operating in a manner that is respectful and protective of the environment, and in full compliance with legal requirements and Company policy. NSPI has implemented this policy through development and application of environmental management systems.

Climate Change and Air Emissions

Greenhouse Gas Emissions

NSPI has stabilized, and in recent years, reduced greenhouse gas emissions. This has been achieved by energy efficiency and conservation programs, increased use of natural gas and the addition of new renewable energy sources to the generation portfolio.

Greenhouse gas emissions from NSPI facilities have been capped beginning in 2010 through to 2020. The regulations allow for multi-year compliance periods recognizing the variability in electricity supply sources and demand. Over the decade, the caps will be achieved by a combination of additional renewable generation, import of non-emitting energy, and energy efficiency and conservation.

In 2011, Environment Canada announced proposed regulations for a new national carbon dioxide framework for the electricity sector in Canada. These proposed regulations would apply to new coal-fired electricity generation units; and existing coal-fired electricity generation units that have reached the end of their deemed economic life of forty-five years after commissioning. These proposed regulations will be effective July 1, 2015. Nova Scotia’s existing greenhouse gas regulations require reductions in NSPI’s emissions similar to those reflected in the federal framework. NSPI is engaged with federal and provincial agencies in reviewing the implications of this federal framework and its alignment with its current operating plans under existing Nova Scotia regulations.

57

Renewable Energy

The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix. The target date for 5 percent of electricity to be supplied from post-2001 sources of renewable energy, owned by independent power producers, was extended to 2011 from 2010. The target for 2013, which requires an additional 5 percent of renewable energy, is unchanged.

On May 19, 2011 the Nova Scotia Government approved The Electricity Act (Amended) to facilitate the eligibility of energy from the Lower Churchill Project in Labrador as a resource for meeting Nova Scotia’s renewable electricity targets. The amendment requires regulations to be developed that increase the percentage of renewable energy in the generation mix from the planned 25 percent in 2015, to 40 percent by 2020.

Mercury, Nitrogen Oxide and Sulphur Dioxide Emissions

NSPI completed a capital program to add sorbent injection to each of the seven pulverized fuel coal units in 2010 at a cost of $17.3 million. This was put in place to address planned reductions in mercury emissions limits, which are set out in the following table:

Year	Mercury Emissions Limit (kg)
2009		168
2010		110
2011 – 2012		100
2013		85
2014 – 2019		65
2020		35

Any mercury emission above 65 kg, between 2010 and 2013, must be offset by lower emissions in the 2014 to 2020 period.

NSPI completed its capital program of retrofitting low nitrogen oxide combustion firing systems on six of its seven pulverized fuel coal units in early 2009 at a cost of $23.3 million. NSPI now meets the nitrogen oxide emission cap of 21,365 tonnes per year established by the Nova Scotia Government effective 2010. These investments, combined with the purchasing of low sulphur coal, allows NSPI to meet the provincial air quality regulations.

NSPI will meet ever-reducing sulphur dioxide emission cap requirements through the use of a blend of net lower sulphur content solid fuel.

Compared to historical levels, NSPI will have reduced mercury emissions by 60 percent effective 2014, nitrogen oxide by 40 percent effective 2009 and sulphur dioxide by 50 percent effective 2010.

DISCLOSURE AND INTERNAL CONTROLS

The Company, under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, has designed as at December 31, 2011 disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”) as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”).

As permitted, the Company has limited the scope of its design of DC&P and ICFR by excluding the controls, policies and procedures at LPH, which was acquired on January 25, 2011. Summary financial information about the acquisition is included in Note 18 of the Consolidated Financial Statements as at and for the year ended December 31, 2011 and 2010. The relative size of the entity has not materially changed since its acquisition dates.

58

Pursuant to Section 404(c) of the Sarbanes-Oxley Act of 2002 (“SOX”), as added by Section 989G of the Dodd-Frank Wall Street Reform and Consumer Protection Act, the requirement under Section 404(b) of SOX to file an auditor attestation report on an issuer’s ICFR does not apply with respect to any audit report prepared for an issuer that is neither an accelerated filer nor a large accelerated filer, as defined in Rule 12b-2 under the Exchange Act. NSPI is currently not an accelerated filer or a large accelerated filer and, therefore, is not required to file attestation reports on its ICFR. As previously noted, in December 2011, NSPI made the necessary filings to terminate its SEC reporting obligations. As a new registrant, Emera is not required to include an attestation report on its ICFR in its first Annual Report to be filed with the SEC for the year ending December 31, 2011, but would be required to include an attestation report in its subsequent Annual Reports for any year in which it is an accelerated filer or a large accelerated filer.

The Chief Executive Officer and the Chief Financial Officer have caused to be evaluated under their supervision, with the assistance of company employees, the effectiveness of the Company’s DC&P and ICFR and based on that evaluation, have concluded DC&P and ICFR were effective at December 31, 2011.

There have been no changes in Emera or its consolidated subsidiaries’ ICFR during the period beginning on January 1, 2011 and ending on December 31, 2011, which have materially affected, or are reasonably likely to materially affect ICFR.

SIGNIFICANT ACCOUNTING POLICIES AND

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 on-going 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-regulation, the determination of pension and other post-retirement employee benefits, unbilled revenue, useful lives for depreciable assets, income taxes, asset retirement obligations and goodwill impairment assessments. Actual results may differ from these estimates.

Rate Regulation

The rate-regulated accounting policies of NSPI, Bangor Hydro, MPS, BLPC, GBPC and Brunswick Pipeline may differ from accounting policies for non-rate-regulated companies. NSPI, Bangor Hydro, MPS, BLPC and GBPC accounting policies are subject to examination and approval by their respective regulators. These accounting policy differences occur when the regulators render their decisions on rate applications or other matters and generally involve a difference in the timing of revenue and expense recognition. The accounting for these items is based on the expectation of the future actions of the regulators.

If the regulators’ future actions are different from their previous rulings, the timing and amount of the recovery of liabilities and refund of assets, recorded or unrecorded, could be significantly different from that reflected in the financial statements.

Pension and Other Post-Retirement Employee Benefits

The Company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future experience.

59

The benefit cost and accrued benefit obligation for employee future benefits included in annual compensation expenses are affected by employee demographics, including age, compensation levels, employment periods, contribution levels and earnings on plan assets.

Changes to the provision of the plan may also affect current and future pension costs. Benefit costs may also be affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and discount rates used in determining the accrued benefit obligation and benefit costs.

The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.

Emera’s accounting policy is to amortize the net actuarial gain or loss, which exceeds 10 percent of the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”) and the market-related value of assets, over active plan members’ average remaining service period, which is currently 9 years. Emera’s use of smoothed asset values further reduces the volatility related to the amortization of actuarial investment experience. As a result, the main cause of volatility in reported pension cost is the discount rate used to determine the PBO.

The discount rate used to determine benefit costs is based on the yield of high quality long-term corporate bonds in each operating entity’s country. The discount rate is determined with reference to bonds which have the same duration as the PBO as at January 1 of the fiscal year rounded to the nearest 25 basis points. For benefit cost purposes, NSPI’s rate was 5.50 percent for 2011 (2010 – 6.50 percent) and Bangor Hydro’s rate was 5.60 percent for 2011 (2010 – 6.00 percent). MPS’ rate was 5.40 for 2011 (2010 – 5.75 percent) and GBPC’s rate for 2011 was 6.00 percent (2010 – 6.00 percent).

The expected return on plan assets is based on management’s best estimate of future returns, considering economic and consensus forecasts. The benefit cost calculations assumed that plan assets would earn a rate of return of 7.00 percent for 2011 (2010 – 7.25 percent) for NSPI and 8.00 percent for 2011 and 2010 for Bangor Hydro. The assumed rate of return on plan assets for 2011 and 2010 was 8.50 percent for MPS and 6.00 percent for 2011 and 2010 for GBPC.

The reported benefit cost for 2011, based on management’s best estimate assumptions, is $55.7 million. While there are numerous assumptions which are used to determine the benefit cost, the discount rate and asset return assumptions have an impact on the calculations.

The following shows the impact on 2011 benefit cost of a 25 basis point change (0.25 percent) in the discount rate and asset return assumptions:

		0.25% Increase		0.25% Decrease
millions of dollars	2011	2010	2011	2010
Discount rate assumption	$(3.9)	$(3.5)	$4.0	$3.6
Asset return assumption	$(2.0)	$(1.8)	$2.0	$1.8

Unbilled Revenue

Electric revenues are billed on a systematic basis over a one or two-month period for NSPI and a one-month period for Bangor Hydro, MPS, BLPC and GBPC. At the end of each month, the Company must make an estimate of energy delivered to customers since the date their meter was last read and of related revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including current month’s generation, estimated customer usage by class, weather, line losses and applicable customer rates. EUS includes an estimate of work completed under contracts but not yet billed at the end of each month. Brunswick Pipeline also makes an estimate of toll revenues at the end of each month. Based on the extent of the estimates included in the determination of unbilled revenue, actual results may differ from the estimate. As at December 31, 2011, unbilled revenues amount to $133.6 million (2010 – $126.4 million) on a base of annual operating revenues of approximately $2,064.4 billion (2010 – $1,606.1 billion).

60

Property, Plant and Equipment

Property, plant and equipment represents 62.0 percent of total assets recognized on the Company’s balance sheet. Included in “Property, plant and equipment” are the generation, transmission and distribution and other assets of the Company. Due to the magnitude of the Company’s property, plant and equipment, changes in estimated depreciation rates can have a material impact on depreciation expense.

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated assets are determined based on formal depreciation studies and require the appropriate regulatory approval.

On May 11, 2011, the UARB approved changes to NSPI’s depreciation rates following NSPI’s completion of a depreciation study and a settlement agreement with stakeholders. The overall impact on the average deprecation rate is immaterial. The new depreciation rates are effective January 1, 2012, as approved by the UARB in the 2012 General Rate Decision.

Income Taxes

Income taxes are determined based on the expected tax treatment of transactions recorded in the consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of jurisdictions, the likelihood that deferred tax assets will be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. If interpretations differ from those of tax authorities or if the recovery of deferred tax assets or timing of reversals is not as anticipated, the provision for income taxes could increase or decrease in future periods. The amount of any such increase or decrease cannot be reasonably estimated.

Asset Retirement Obligations

An asset retirement obligation (“ARO”) is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any accretion expense not yet approved by the regulator is deferred to a regulatory asset in “Property, plant and equipment” and included in the next depreciation study.

Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.

61

The key assumptions used to determine the ARO are as follows:

Asset	Credit-adjusted     risk-free rate			Estimated undiscounted future obligation (millions of dollars)			Expected   settlement date   (number of years)
		2011	2010		2011	2010		2011	2010
Thermal		5.1 – 5.3%	5.2 – 5.3%		$142.8	$258.9		21 – 32	10 – 29
Hydro		5.1 – 5.3%	5.2 – 5.3%		127.6	101.4		20 – 50	21 – 51
Wind		5.1 – 5.2%	5.2%		27.4	45.5		17 – 24	13 – 20
Combustion turbines		5.1 – 5.3%	5.2 – 5.3%		8.3	12.9		5 – 34	1 – 14
Transmission & distribution		4.3 – 5.8%	5.7%		30.4	21.6		1 – 14	1 – 15
Pipeline		3.50%	3.80%		24.6	11.0		38	39
					$361.1	$451.3

As at December 31, 2011, the AROs recorded on the balance sheet were $99.9 million (2010 – $141.8 million). The Company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $358.1 million, which will be incurred between 2012 and 2062. The majority of these costs will be incurred between 2032 and 2047.

Goodwill Impairment Assessments

Goodwill represents the excess of the acquisition purchase price for Bangor Hydro, GBPC, ICDU and MAM over the fair values assigned to individual assets acquired and liabilities assumed. Emera is required to perform an impairment assessment annually, or in the interim if an event occurs that indicates the fair value of Bangor Hydro, GBPC, ICDU or MAM may be below its carrying value. Emera performs its annual impairment test as at October 1.

Emera’s reporting units will first assess qualitative factors to determine whether it is more likely than not that the assets’ fair value is less than the carrying amount, in which case it is necessary to perform the quantitative goodwill impairment test. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. There was no impairment provision required in 2011 or 2010.

CHANGES IN ACCOUNTING POLICIES AND

PRACTICES

Future Accounting Pronouncements

Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities, ASU No. 2011-11

In December 2011, The Financial Accounting Standards Board (“FASB”) issued an accounting standards update which requires companies to disclose gross information and net information about both instruments and transactions eligible for offset in the statement of financial positions and instruments and transactions subject to an agreement similar to a master netting arrangement to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU No. 2011-11 is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013 with required disclosures made retrospectively for all comparative periods presented. The Company is currently evaluating the impact that the adoption will have in the financial statements.

62

Other Comprehensive Income, ASU No. 2011-05

In June 2011, FASB issued an accounting standards update amending Accounting Standards Codification (“ASC”) 220 to improve the comparability, consistency and transparency of comprehensive income reporting. The guidance requires that items of net income, items of other comprehensive income and total comprehensive income be presented in one continuous statement or two separate but consecutive statements. Items that are reclassified from other comprehensive income to net income must be presented separately on the face of the financial statements. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Retrospective application of the new disclosures will be required for comparative periods. The adoption of this update will change the order in which certain consolidated financial statements are presented and provide additional detail on those financial statements where applicable, but will not have any other impact to the consolidated financial statements.

Subsequently in December 2011, FASB issued ASU No. 2011-12, Deferral of the Effective Date for Amendments to Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The amendments in ASU No. 2011-12 defer the changes in ASU No. 2011-05 that relate to the presentation of reclassification adjustments out of AOCL.

Fair Value Measurement, ASU No. 2011-04

In May 2011, FASB issued an accounting standards update amending ASC 820 to achieve common fair value measurement and disclosure requirements between USGAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify the intent concerning the application of existing requirements and include some instances where a particular principle or requirement for measuring fair value or disclosing information related to fair value measurements has changed. ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the impact that the adoption will have in the consolidated financial statements.

SUMMARY OF QUARTERLY RESULTS

For the quarter ended   millions of dollars (except   per share amounts)	Q4 2011		Q3 2011		Q2 2011		Q1 2011		Q4 2010 (adjusted)		Q3 2010 (adjusted)		Q2 2010 (adjusted)		Q1 2010 (adjusted)
Total operating revenues		$512.0		$496.1		$501.7		$554.6		$408.9		$394.0		$364.7		$438.5
Net income attributable to common shareholders		46.8		40.8		29.9		123.6		24.1		40.3		48.5		77.8
Earnings per common share – basic		0.38		0.33		0.24		1.06		0.21		0.35		0.43		0.68
Earnings per common share – diluted		0.38		0.33		0.24		1.03		0.21		0.35		0.42		0.67

Quarterly total operating revenues and net income attributable to common shareholders are affected by seasonality. Q1 and Q4 are generally the strongest because a significant portion of the Company’s operations are located in northeast North America, where winter is the peak electricity season. Quarterly results are also affected by items outlined in the Significant Items section.

63

OPERATING STATISTICS (Unaudited)

FIVE-YEAR SUMMARY

Year Ended December 31	2011		2010 (adjusted)		2009 (adjusted)		2008 (adjusted)		2007 (adjusted)
Electric energy sales (GWh)
Residential		5,458.9		4,738.2		4,819.2		4,769.6		4,738.5
Commercial		6,562.3		5,584.4		3,694.4		3,721.1		3,768.5
Industrial		3,988.5		4,268.2		3,985.3		4,491.5		4,568.4
Other		347.0		620.1		1,166.9		652.2		655.4
Total electric energy sales		16,356.7		15,210.9		13,665.8		13,634.4		13,730.8
Sources of energy (GWh)
Thermal – coal		6,848.0		7,838.7		8,177.3		9,008.9		9,561.4
– oil		1,070.8		36.1		306.9		340.7		516.6
– natural gas		4,304.7		4,183.0		2,141.4		1,257.9		1,057.1
Hydro		1,414.5		991.5		1,063.4		1,065.3		908.8
Wind		247.0		25.3		1.8		2.4		2.4
Purchases		3,518.3		2,987.4		2,846.1		2,874.5		2,654.7
Total generation and purchases		17,403.3		16,062.0		14,536.9		14,549.7		14,701.0
Losses and internal use		1,046.6		851.1		871.1		915.3		970.2
Total electric energy sold		16,356.7		15,210.9		13,665.8		13,634.4		13,730.8
Electric customers
Residential		696,970		588,935		539,333		535,494		530,955
Commercial		79,817		61,620		51,768		54,461		51,083
Industrial		2,517		2,558		2,543		2,541		2,543
Other		10,446		9,422		9,155		9,064		9,574
Total electric customers		789,750		662,535		602,799		601,560		594,155
Capacity
Generating nameplate capacity (MW)
Coal fired		1,243		1,243		1,243		1,243		1,243
Dual fired		350		350		350		365		350
Gas turbines		666		599		564		289		304
Hydroelectric		395		395		395		395		395
Wind turbines		82		76		1		1		1
Diesel		173		61		15		15		15
Steam		47		51		-		-		-
Independent power producers		264		347		172		120		120
		3,220		3,122		2,740		2,428		2,428
Total number of employees		3,458		2,972		2,350		2,215		2,194
km of transmission lines		6,800		6,700		6,300		6,400		6,100
km of distribution lines		41,600		40,900		33,800		32,600		32,000

REGULATED   ELECTRIC	Customers		Employee Count		Peak Demand (MW)		Energy Sales (Gwh)		Total Assets (billions)		Rate Base (billions)		Income (millions)		Allowable ROE 2011			Allowable ROE 2010
NSPI		493,183		1,883		2,168		11,206		$3.9		$3.5		$123.5		9.1-9.6	%		9.1-9.6	%
Bangor Hydro		118,080		295		290.9		1,520.5		0.82		0.50		34.2		11.21	%		11.18	%
MPS		36,293		127		102.1		496.3		0.14		0.06		2.8		9.69	%		9.76	%
BLPC		122,900		500		160.1		934.6		0.5		0.3		14.0		10.0	%		-
GBPC		19,180		174		64.1		328.3		0.2		-		5.2		-			-

64

THREE YEAR FINANCIAL SUMMARY

For the year ended December 31 (millions of Canadian dollars)	2011			2010 (adjusted)			2009 (adjusted)
Consolidated Statements of Income
Operating revenues		$2,064.4			$1,606.1			$1,490.1
Operating expenses
Regulated fuel for generation and purchased power		866.4			634.6			550.0
Regulated fuel adjustment		(8.5	)		(99.0	)		8.5
Non-regulated fuel for generation and purchased power		73.9			83.9			29.5
Non-regulated direct costs		60.9			62.3			37.9
Operating, maintenance and general		455.0			351.2			299.1
Provincial, state and municipal taxes		49.2			47.4			48.0
Depreciation and amortization		250.0			213.5			199.7
Income from operations		317.5			312.2			317.4
Income from equity investments and other income (expenses), net		64.6			27.8			49.3
Interest expense, net		159.4			148.8			132.8
Income before provision for income taxes		222.7			191.2			233.9
Income tax expense (recovery)		(36.7	)		(8.1	)		37.4
Net income		259.4			199.3			196.5
Non-controlling interest in subsidiaries		11.7			5.6			10.2
Net income of Emera Incorporated		247.7			193.7			186.3
Preferred stock dividends		6.6			3.0			-
Net income attributable to common shares		241.1			190.7			186.3
Balance Sheets Information
Current assets		993.3			840.1			811.5
Property, plant and equipment, net of accumulated depreciation		4,294.4			3,742.6			3,104.2
Other assets
Deferred income taxes		33.1			31.1			66.2
Derivative instruments		39.6			36.0			45.4
Regulatory assets		312.2			354.9			278.8
Net investment in direct financing lease		492.0			491.5			480.1
Investments subject to significant influence		222.7			246.0			216.3
Available-for-sale investments		54.6			0.8			1.0
Intangibles, net of accumulated amortization		100.7			98.7			93.0
Goodwill		197.7			167.4			87.6
Other		183.3			69.9			63.2
Total assets		6,923.6			6,079.0			5,247.3
Current liabilities		801.7			605.9			857.7
Long-term liabilities
Long-term debt		3,273.5			3,115.3			2,272.7
Deferred income taxes		228.6			168.5			126.2
Derivative instruments		38.7			28.9			35.5
Regulatory liabilities		107.1			65.2			91.5
Asset retirement obligations		99.9			141.8			104.5
Pension and post-retirement liabilities		530.8			400.0			292.4
Other long-term liabilities		19.6			22.0			33.0
Equity
Common stock		1,385.0			1,137.8			1,097.9
Preferred stock		146.7			146.7			-
Contributed surplus		3.3			3.2			3.0
Accumulated other comprehensive loss		(671.7	)		(564.2	)		(426.2	)
Retained earnings		735.9			653.5			594.8
Total Emera Incorporated equity		1,599.2			1,377.0			1,269.5
Non-controlling interest in subsidiaries		224.5			154.4			164.3
Total equity		1,823.7			1,531.4			1,433.8
Total liabilities and equity		6,923.6			6,079.0			5,247.3
Statements of Cash Flow Information
Cash provided by operating activities		399.5			419.2			318.1
Cash used in investing activities		(660.8	)		(886.0	)		(380.8	)
Cash provided by financing activities		331.3			454.6			61.2
Financial ratios ($ per share)
Earnings per share		$1.99			$1.67			$1.65

65

EX-99.2

Exhibit 99.2

EMERA INCORPORATED

Consolidated Financial Statements

December 31, 2011 and 2010

66

MANAGEMENT REPORT

Management’s Responsibility for Financial Reporting

The accompanying consolidated financial statements of Emera Incorporated and the information in this annual report are the responsibility of management and have been approved by the Board of Directors (“Board”).

The consolidated financial statements have been prepared by management in accordance with United States Generally Accepted Accounting Principles. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. In preparation of these consolidated financial statements, estimates are sometimes necessary when transactions affecting the current accounting period cannot be finalized with certainty until future periods. Management represents that such estimates, which have been properly reflected in the accompanying consolidated financial statements, are based on careful judgements and are within reasonable limits of materiality. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects. Management has prepared the financial information presented elsewhere in the annual report and has ensured that it is consistent with that in the consolidated financial statements.

Emera Incorporated maintains effective systems of internal accounting and administrative controls, consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate, and that Emera Incorporated’s assets are appropriately accounted for and adequately safeguarded.

The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting and is ultimately responsible for reviewing and approving the consolidated financial statements. The Board carries out this responsibility principally through its Audit Committee.

The Audit Committee is appointed by the Board, and its members are directors who are not officers or employees of Emera Incorporated. The Audit Committee meets periodically with management, as well as with the internal auditors and with the external auditors, to discuss internal controls over the financial reporting process, auditing matters and financial reporting issues, to satisfy itself that each party is properly discharging its responsibilities, and to review the annual report, the consolidated financial statements and the external auditors’ report. The Audit Committee reports its findings to the Board for consideration when approving the consolidated financial statements for issuance to the shareholders. The Audit Committee also considers, for review by the Board and approval by the shareholders, the appointment of the external auditors.

The consolidated financial statements have been audited by Ernst & Young LLP, the external auditors, in accordance with Canadian Generally Accepted Auditing Standards and the standards of the Public Company Accounting Oversight Board (United States). Ernst & Young LLP has full and free access to the Audit Committee.

February 10, 2012

“Christopher Huskilson”	“Judy Steele, FCA”
President and Chief Executive Officer	Chief Financial Officer

67

INDEPENDENT AUDITORS’ REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of Emera Incorporated

We have audited the accompanying consolidated financial statements of Emera Incorporated, which comprise the consolidated balance sheets as at December 31, 2011 and 2010, and the consolidated statements of income, cash flows, comprehensive income and changes in shareholders’ equity, for each of the years in the two-year period ended December 31, 2011, and a summary of significant accounting policies and other explanatory information.

Management’s responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with United States generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Emera Incorporated as at December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2011 in accordance with United States generally accepted accounting principles.

Halifax, Canada	“Ernst & Young LLP”
February 10, 2012	Chartered accountants

68

Emera Incorporated

Consolidated Statements of Income

Years Ended December 31

millions of Canadian dollars (except per share amounts)	2011		2010 (as adjusted –note 35)
Operating revenues
Regulated		$1,891.0		$1,411.6
Non-regulated		173.4		194.5
Total operating revenues		2,064.4		1,606.1
Operating expenses
Regulated fuel for generation and purchased power		866.4		634.6
Regulated fuel adjustment (note 5)		(8.5)		(99.0)
Non-regulated fuel for generation and purchased power		73.9		83.9
Non-regulated direct costs		60.9		62.3
Operating, maintenance and general		455.0		351.2
Provincial, state, and municipal taxes		49.2		47.4
Depreciation and amortization		250.0		213.5
Total operating expenses		1,746.9		1,293.9
Income from operations		317.5		312.2
Income from equity investments (note 15)		21.5		15.3
Other income (expenses), net (note 6)		43.1		12.5
Interest expense, net (note 7)		159.4		148.8
Income before provision for income taxes		222.7		191.2
Income tax expense (recovery) (note 8)		(36.7)		(8.1)
Net income		259.4		199.3
Non-controlling interest in subsidiaries		11.7		5.6
Net income of Emera Incorporated		247.7		193.7
Preferred stock dividends		6.6		3.0
Net income attributable to common shareholders		$241.1		$190.7
Weighted average shares of common stock outstanding (in millions)
Basic		121.0		114.2
Diluted		126.2		120.4
Earnings per common share (note 9)
Basic		$1.99		$1.67
Diluted		$1.97		$1.65
Dividends per common share declared		$1.3125		$1.1625

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

69

Emera Incorporated

Consolidated Balance Sheets

As at December 31

millions of Canadian dollars	2011		2010 (as adjusted –note 35)
Assets
Current assets
Cash and cash equivalents		$76.9		$7.3
Restricted cash (note 10)		14.0		58.6
Receivables, net (note 11)		459.6		392.9
Income taxes receivable		41.6		37.0
Inventory (note 12)		198.8		177.8
Deferred income taxes (note 8)		14.0		13.7
Derivative instruments (note 24)		27.3		49.7
Regulatory assets (note 23)		141.6		90.5
Prepaid expenses		15.1		9.5
Other current assets		4.4		3.1
Total current assets		993.3		840.1
Property, plant and equipment, net of accumulated depreciation of $2,838.0 and $2,462.6, respectively (note 13)		4,294.4		3,742.6
Other assets
Deferred income taxes (note 8)		33.1		31.1
Derivative instruments (note 24)		39.6		36.0
Regulatory assets (note 23)		312.2		354.9
Net investment in direct financing lease (note 14)		492.0		491.5
Investments subject to significant influence (note 15)		222.7		246.0
Available-for-sale investments (note 16)		54.6		0.8
Goodwill (note 17)		197.7		167.4
Intangibles, net of accumulated amortization of $59.7 and $40.2 respectively		100.7		98.7
Other		183.3		69.9
Total other assets		1,635.9		1,496.3
Total assets		$6,923.6		$6,079.0

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

70

Emera Incorporated

Consolidated Balance Sheets – Continued

As at December 31

millions of Canadian dollars	2011		2010 (as adjusted – note 35)
Liabilities and Equity
Current liabilities
Short-term debt (note 19)		$210.3		$81.7
Current portion of long-term debt (note 20)		35.7		10.6
Accounts payable		332.9		293.9
Income taxes payable		1.9		0.2
Deferred income taxes (note 8)		10.9		8.5
Derivative instruments (note 24)		50.1		36.8
Regulatory liabilities (note 23)		23.9		55.0
Pension and post-retirement liabilities (note 26)		8.8		8.9
Other current liabilities (note 21)		127.2		110.3
Total current liabilities		801.7		605.9
Long-term liabilities
Long-term debt (note 20)		3,273.5		3,115.3
Deferred income taxes (note 8)		228.6		168.5
Derivative instruments (note 24)		38.7		28.9
Regulatory liabilities (note 23)		107.1		65.2
Asset retirement obligations (note 22)		99.9		141.8
Pension and post-retirement liabilities (note 26)		530.8		400.0
Other long-term liabilities		19.6		22.0
Total long-term liabilities		4,298.2		3,941.7
Commitments and contingencies (note 27)
Equity
Common stock, no par value; unlimited shares authorized; 122.83 million shares and 114.62 million shares issued and outstanding, respectively (note 28)		1,385.0		1,137.8
Cumulative preferred stock Series A, par value $25 per share; unlimited shares authorized; 6 million shares issued and outstanding (note 30)		146.7		146.7
Contributed surplus		3.3		3.2
Accumulated other comprehensive loss (note 31)		(671.7)		(564.2)
Retained earnings		735.9		653.5
Total Emera Incorporated equity		1,599.2		1,377.0
Non-controlling interest in subsidiaries		224.5		154.4
Total equity		1,823.7		1,531.4
Total liabilities and equity		$6,923.6		$6,079.0

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

Approved on behalf of the Board of Directors

“John T. McLennan”	“Christopher G. Huskilson”
Chairman	President and Chief Executive Officer

71

Emera Incorporated Consolidated Statements of Cash Flows

Years Ended December 31

millions of Canadian dollars	2011		2010 (as adjusted –note 35)
Operating activities
Net income		$259.4		$199.3
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		263.2		231.6
Income from equity investments, net of dividends		(0.9)		9.5
Allowance for equity funds used during construction		(13.1)		(11.8)
Deferred income taxes, net		11.6		39.1
Net change in pension and post-retirement obligations		(8.1)		(15.5)
Regulated fuel adjustment		(15.2)		(102.8)
Net changes in fair value of derivative instruments		6.6		(0.7)
Net change in regulatory assets and liabilities		(13.4)		(30.7)
Other operating activities, net		(50.3)		18.5
Changes in non-cash working capital
Receivables, net		(45.0)		39.5
Income taxes receivable		(4.2)		(32.7)
Inventory		(3.9)		13.6
Prepaid expenses		(1.2)		(2.3)
Other current assets		0.1		1.5
Accounts payable		2.1		53.4
Income taxes payable		1.5		(2.6)
Other current liabilities		10.3		12.3
Net cash provided by operating activities		399.5		419.2
Investing activities
Additions to property, plant and equipment		(472.1)		(525.5)
Acquisition, net of cash acquired		(41.9)		(157.7)
Decrease in restricted cash		57.9		(58.4)
Purchase of investments subject to significant influence, inclusive of acquisition costs (note 15)		(33.8)		(88.4)
Allowance for borrowed funds used during construction		(10.9)		(10.5)
Retirement spending, net of salvage		(16.8)		(16.3)
Purchase of subscription receipts		(136.0)		-
Other investing activities		(7.2)		(29.2)
Net cash used in investing activities		(660.8)		(886.0)
Financing activities
Change in short-term debt, net		133.0		(24.1)
Retirement of long-term debt		(13.4)		(346.8)
Proceeds from long-term debt		251.8		542.3
Net repayments under committed credit facilities		(119.6)		258.9
Issuance of common stock, net of issuance costs		244.0		39.5
Issuance of preferred stock		-		145.2
Dividends on common stock		(157.6)		(132.0)
Dividends on preferred stock		(6.6)		(3.0)
Dividends paid by subsidiaries to non-controlling interest		(8.7)		(7.9)
Other financing activities		8.5		(17.5)
Net cash provided by financing activities		331.4		454.6
Effect of exchange rate changes on cash and cash equivalents		(0.5)		(0.7)
Net increase (decrease) in cash and cash equivalents		69.6		(12.9)
Cash and cash equivalents, beginning of period		7.3		20.2
Cash and cash equivalents, end of period		$76.9		$7.3
Cash and cash equivalents consists of:
Cash		$59.2		$7.3
Short-term investments		17.7		-
Cash and cash equivalents		$76.9		7.3
Supplemental disclosure of cash paid (received):
Interest		$170.4		$149.7
Income and capital taxes		$(33.0)		$(2.1)

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

72

Emera Incorporated

Consolidated Statements of Comprehensive Income (note 31)

Years Ended December 31

millions of Canadian dollars	2011		2010 (as adjusted – note 35)
Net income attributable to common shareholders		$241.1		190.7
Other comprehensive income (loss), net of tax
Unrealized losses on cash flow hedges (1)		(10.8)		(0.5)
Hedging losses included in income (2)		2.1		6.6
Net change in unrecognized pension and post-retirement benefit costs (3)		(122.9)		(113.4)
Unrealized loss on available-for-sale investment		(0.3)		(0.2)
Unrealized gain (loss) on translation of self-sustaining foreign operations (4)		24.4		(30.5)
Other comprehensive loss, net of tax (5)		(107.5)		(138.0)
Comprehensive income attributable to common shareholders		$133.6		$52.7

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

1) Net of tax recovery of $7.8 million (2010 - $4.8 million tax recovery) for the year ended December 31, 2011.

2) Net of tax expense of $3.2 million (2010 - $4.6 million tax expense) for the year ended December 31, 2011.

3) Net of tax recovery of $8.4 million (2010 - $2.6 million tax recovery) for the year ended December 31, 2011.

4) Net of tax expense of $0.1 million (2010 - nil) for the year ended December 31, 2011.

5) Net of tax recovery of $12.9 million (2010 - $2.8 million tax recovery) for the year ended December 31, 2011.

73

Emera Incorporated

Consolidated Statements of Changes in Equity

Years Ended December 31

millions of Canadian dollars	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Loss (“AOCL”)		Retained Earnings		Non- Controlling Interest		Total Equity
2011
Balance, December 31, 2010 (as adjusted – note 35)		$1,137.8		$146.7		$3.2		$(564.2)		$653.5		$154.4		$1,531.4
Net income of Emera Incorporated		-		-		-		-		247.7		11.7		259.4
Other comprehensive loss, net of tax recovery of $12.9		-		-		-		(107.5)		-		-		(107.5)
Issuance of common stock, net of issuance costs		196.0		-		-		-		-		-		196.0
Additional investments		-		­		-		-		-		67.1		67.1
Cash dividends declared on preferred stock ($1.1000/share)		-		-		-		-		(6.6)		-		(6.6)
Cash dividends declared on common stock ($1.3125/share)		-		-		-		-		(158.7)		-		(158.7)
Dividends paid by subsidiaries to non-controlling interest		-		-		-		-		-		(0.7)		(0.7)
Common stock issued under purchase plan		41.0		-		-		-		-		-		41.0
Senior management stock options exercised		8.8		-		(0.6)		-		-		-		8.2
Stock option expense		-		-		0.7		-		-		-		0.7
Other stock-based compensation		1.4		-		-		-		-		-		1.4
Preferred dividends paid by subsidiaries to non-controlling interest		-		-		-		-		-		(8.0)		(8.0)
Balance, December 31, 2011		$1,385.0		$146.7		$3.3		$(671.7)		$735.9		$224.5		$1,823.7
2010 (as adjusted – note 35)
Balance, December 31, 2009		$1,097.9		-		$3.0		$(426.2)		$594.8		$164.3		$1,433.8
Net income of Emera Incorporated		-		-		-		-		193.7		5.6		199.3
Other comprehensive loss, net of tax recovery of $2.8		-		-		-		(138.0)		-		-		(138.0)
Additional investment		-		-		-		-		-		(5.5)		(5.5)
Cash dividends declared on preferred stock ($0.4980/share)		-		-		-		-		(3.0)		-		(3.0)
Cash dividends declared on common stock ($1.1625/share)		-		-		-		-		(132.0)		-		(132.0)
Common stock issued under purchase plan		32.9		-		-		-		-		-		32.9
Senior management stock options exercised		6.0		-		(0.5)		-		-		-		5.5
Stock option expense		-		-		0.7		-		-		-		0.7
Other stock-based compensation		1.0		-		-		-		-		-		1.0
Issuance of preferred shares		-		146.7		-		-		-		-		146.7
Preferred dividends paid by subsidiaries to non-controlling interest		-		-		-		-		-		(8.0)		(8.0)
Other		-		-		-		-		-		(2.0)		(2.0)
Balance, December, 2010		$1,137.8		$146.7		$3.2		$(564.2)		$653.5		$154.4		$1,531.4

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

74

Emera Incorporated

Notes to the Consolidated Financial Statements

As at December 31, 2011 and 2010

1.      SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both the regulated and non-regulated operations of Emera Incorporated are as follows:

A.    Nature of Operations

Emera Incorporated is an energy and services company which invests in electricity generation, transmission and distribution, gas transmission and utility energy services.

Emera’s primary rate-regulated subsidiaries at December 31, 2011 include the following:

• Nova Scotia Power Inc. (“NSPI”), a fully-integrated electric utility and the primary electricity supplier in Nova Scotia serving approximately 493,000 customers;

• Bangor Hydro Electric Company (“Bangor Hydro”) and Maine Public Service Company (“MPS”), (a wholly-owned subsidiary of Maine and Maritimes Corporation (“MAM”)), which together provide transmission and distribution services to approximately 154,000 customers in Maine;

• an 80.1 percent interest in Light & Power Holdings Ltd. (“LPH”), the parent of The Barbados Light & Power Company Limited (“BLPC”), a vertically integrated utility and sole provider of electricity on the island of Barbados serving approximately 123,000 customers;

• a 50.0 percent direct and 30.4 percent indirect interest (through ICD Utilities Limited (“ICDU”)) 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; and

• Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”), a 145 kilometer pipeline carrying re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25 year firm service agreement with Repsol Energy Canada (“REC”).

Emera Incorporated and its subsidiaries (“Emera” or the “Company”) also own investments in other non rate-regulated energy related companies, including:

• Emera Energy Services, a physical energy business which purchases and sells natural gas and electricity and provides related energy asset management services;

• Bayside Power Limited Partnership (“Bayside Power”), a 260-megawatt (“MW”) electricity generating facility in Saint John, New Brunswick ;

• Emera Utility Services Inc. (“EUS”), a utility services contractor;

• a 50 percent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), a 600-MW pumped storage hydro-electric facility in northern Massachusetts;

• Emera Newfoundland & Labrador Holdings Inc. (“ENL”), a development project focused on transmission investments related to the proposed 824-MW hydro-electric generating facility at Muskrat Falls in Labrador, scheduled to be in service in 2017;

• a 12.9 percent interest in Maritimes & Northeast Pipeline (“M&NP”), a 1,400 kilometer pipeline which transports natural gas from offshore Nova Scotia to markets in Maritime Canada and the northeastern United States;

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

• a 49.999 percent interest in California Pacific Utilities Ventures, LLC, (“CPUV”);

• a 6.3 percent investment in Algonquin Power & Utilities Corp (“APUC”);

• a 37.7 percent investment in Atlantic Hydrogen Inc. (“AHI”); and

• other investments.

75

B.    Basis of Presentation

Effective January 1, 2011, Emera changed the basis of presentation of its financial statements (including the application of rate-regulated accounting policies for Emera’s rate-regulated subsidiaries) from Canadian Generally Accepted Accounting Principles (“CGAAP”) to United States Generally Accepted Accounting Principles (“USGAAP”).

These consolidated financial statements are prepared and presented in accordance with USGAAP and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for Annual Reports filed under the Multi-Jurisdictional Disclosure System. These consolidated financial statements should be read in conjunction with note 35, detailing the CGAAP to USGAAP transition and reconciliation information.

In the opinion of management, these consolidated financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera Incorporated.

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

C.    Principles of Consolidation

The consolidated financial statements of Emera Incorporated include the accounts of Emera Incorporated and its majority-owned subsidiaries, and a variable interest entity where Emera is the primary beneficiary. All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power.

Where Emera does not control an investment, but has significant influence over operating and financing policies of the investee, the investment is accounted for under the equity method. The cost method of accounting is used for investments where Emera does not have significant influence over the operating and financial policies of the investee.

D.    Use of Management Estimates

The preparation of 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 on-going basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Significant estimates are included in unbilled revenue, allowance for doubtful accounts, inventory, valuation of derivative instruments, depreciation, amortization, regulatory assets and regulatory liabilities (including the determination of the current portion), income taxes (including deferred income taxes), pension and post-retirement benefits, asset retirement obligations (“AROs”) and contingencies. Actual results may differ significantly from these estimates.

E.    Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an independent third party regulator; are designed to recover the costs of providing the regulated products or services; and it is reasonable to assume rates are set at levels such that the costs can be charged to and collected from customers.

Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable of recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory

76

precedent set for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income. Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.

For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator.

F.    Foreign Currency Translation

Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income.

Assets and liabilities of self-sustaining foreign operations are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average rates for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCL.

G.    Revenue Recognition

Operating revenues are recognized when electricity is delivered to customers or when products are delivered and services are rendered. Revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on meter readings and estimates, which occur on a systematic basis throughout a month. At the end of each month, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The accuracy of the unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes.

The Company records the net investment in a lease under the direct finance method, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item for a direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.

Other revenues are recognized when services are performed or goods delivered.

H.    Research and Development Costs

Research and development costs are expensed as incurred.

I.    Stock-Based Compensation

The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; and a performance share unit (“PSU”) plan. The Company accounts for its plans in accordance with the fair value based method of accounting for stock-based compensation. Stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are measured at fair value and re-measured at fair value at each reporting date with the change in liability recognized as expense.

77

J.    Employee Benefits

The costs of the Company’s pension and other post-employment benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-employment plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in AOCL.

K.    Earnings per Share

Basic earnings per share (“EPS”) is determined by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares and DSUs outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the employee common share purchase plan, PSUs and the senior management stock option plan.

L.    Cash and Cash Equivalents

Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. The short-term investments of $17.7 million have an effective interest rate of 3.4 percent at December 31, 2011 (2010 – nil short-term investments).

M.    Receivables and Allowance for Doubtful Accounts

Customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date.

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit risk assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis.

Management estimates uncollectible accounts receivable after considering historical loss experience, current events and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.

N.    Inventory

Inventory, consisting of fuel and materials, is measured at the lower of cost or market. Fuel cost is determined using the weighted average method and material cost is determined using the average costing method. Fuel and materials are charged to inventory when purchased and then expensed or capitalized, as appropriate, using the weighted average cost method for fuel and average costing method for materials.

O.    Property, Plant and Equipment

Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of contributions received in aid of construction.

The cost of additions, including betterments and replacements of units of property plant and equipment are included in “Property, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation with no gain or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions occur.

78

Normal maintenance projects are expensed as incurred. Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When a cost increases the life or value of the underlying asset, the cost is capitalized.

P.    Capitalization Policy

The cost of property, plant, and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, AROs and overhead directly attributable to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits, insurance, inventory, and fleet operating and maintenance.

Q.    Allowance for Funds Used During Construction

AFUDC represents the cost of financing regulated construction projects and is capitalized to the cost of property, plant and equipment. As approved by their respective regulator, NSPI, Bangor Hydro, MPS, GBPC, and Brunswick Pipeline include an equity cost component in AFUDC in addition to a charge for borrowed funds. AFUDC is a non-cash item; cash is realized under the rate-making process over the service life of the related property, plant and equipment through future revenues resulting from a higher rate base and recovery of higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to “Interest expense, net”, while the equity component is included in “Other income (expenses), net”. AFUDC is calculated using a weighted average cost of capital, as per the method of calculation approved by the respective regulator, and is compounded semi-annually. The annual AFUDC consisted of the following:

	2011						2010
	Total		Debt Component		Equity Component		Total		Debt Component		Equity Component
NSPI		7.87%		4.06%		3.81%		7.96%		4.15%		3.81%
Bangor Hydro		9.00%		2.60%		6.40%		8.59%		2.66%		5.93%
MPS		8.89%		2.40%		6.49%		N/A		N/A		N/A
GBPC		10.00%		4.40%		5.60%		N/A		N/A		N/A

R.    Depreciation

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets, including assets under capital leases, in each category. The service lives of regulated assets are determined based on formal depreciation studies and require the appropriate regulatory approval.

The estimated useful lives, in years, for each major category of property, plant and equipment consist of the following:

Generation	15 to 131
Transmission	10 to 83
Distribution	11 to 75
General plant	5 to 53

S.    Intangible Assets

Intangible assets consist primarily of land rights and computer software with definite lives. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated assets are determined based on formal depreciation studies and require the appropriate regulatory approval. Intangible assets with indefinite lives are not amortized but tested for impairment at least annually.

79

The estimated useful lives, in years, for each major category of intangibles with definite lives consist of the following:

Land rights	50 to 143
Computer software	3 to 10

The estimated aggregate amortization expense for each of the five succeeding fiscal years is as follows:

	$0000000.00	$0000000.00	$0000000.00	$0000000.00	$0000000.00
millions of Canadian dollars	2012	2013	2014	2015	2016
Land rights	$1.1	$1.1	$1.1	$1.1	$1.1
Computer software	7.0	6.9	5.1	5.1	4.7
	$8.1	$8.0	$6.2	$6.2	$5.8

T.    Asset Impairment

Goodwill

Goodwill is subject to an annual impairment test. Emera has early adopted Accounting Standards Update (“ASU”) Number (“No.”) 2011-08, “Intangibles – Goodwill and Other”. This new approach was used in the annual impairment test on October 1 (refer to Note 2), or when events or circumstances indicate that an asset may be impaired. In line with this standard, Emera’s reporting units will first assess qualitative factors to determine whether it is more likely than not that the assets’ fair value is less than the carrying amount, in which case it is necessary to perform the quantitative goodwill impairment test. The carrying amount of the reporting unit’s goodwill may not be recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value.

Long-Lived Assets

Other long-lived assets require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. Emera bases its evaluation of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements, and other external market conditions or factors.

Assets Held and Used: The carrying amount of assets held and used is considered not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value.

Assets Held for Sale: The carrying value of assets held for sale is considered not recoverable if it exceeds the fair value less the cost to sell. An impairment charge is recorded for any excess of the carrying value over the fair value less estimated costs to sell.

Cost and Equity Method Investments

The carrying value of investments accounted for under the cost and equity methods are assessed for impairment by comparing the fair values of these investments to their carrying values, if a fair value assessment was completed; or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a charge is recognized equal to the amount the carrying value exceeds the investment’s fair value.

Financial Assets

The Company assesses at each balance sheet date whether there is objective evidence that a financial asset or a group of financial assets is impaired. In the case of equity securities classified as available-for-sale, a significant or prolonged decline in the fair value of the security below its cost is considered as an indicator that the securities are impaired. In the case of debt securities classified as available-for-sale, a breach of contract such as default or delinquency in interest or principal payments, or evidence of significant financial difficulty of the issuer is considered an indicator of impairment. If any such evidence exists for available-for-sale financial assets, the cumulative loss, measured as the difference between the acquisition cost and the current fair value, less any impairment loss on that financial asset previously recognized in income, is removed from AOCL and recognized on the Consolidated Statements of Income.

80

There were no material asset impairments for the years ended December 31, 2011 and 2010.

U.    Debt Financing Costs

The Company capitalizes the external costs of obtaining debt financing and includes them in “Other” as part of “Other assets” on the Consolidated Balance Sheet; premiums and discounts are netted against “Long-term debt” on the Consolidated Balance Sheet. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “Interest expense, net”.

V.    Income Taxes and Investment Tax Credits

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the balance sheet and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.

Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned by Bangor Hydro or MPS on regulated assets are deferred and amortized over the estimated service lives of the related properties, as required by United State tax laws and Maine regulatory practices.

Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively.

W.    Asset Retirement Obligations

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any accretion expense not yet approved by the regulator is deferred to a regulatory asset in “Property, plant and equipment” and included in the next depreciation study.

Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.

81

X.    Derivatives and Hedging Activities

Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management practices are overseen by the Board of Directors. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operations.

The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and interest rates using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures, options, forwards, and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. Collectively these contracts are considered “derivatives”.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. Emera continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exception where the criteria are no longer met.

Derivatives qualify for hedge accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to AOCL and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income in the reporting period.

Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value, with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

Derivatives entered into by NSPI that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the Nova Scotia Utility and Review Board (“UARB”). 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 when the derivatives settle. 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 through the FAM.

Derivatives that do not meet any of the above criteria are designated as HFT derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

Emera classifies gains and losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory and property, plant and equipment, depending on the nature of the item being economically hedged. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows.

Y.    Fair Value Measurement

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (refer to notes 24 and 25). Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best

82

available information including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. The Company uses a fair value hierarchy, based on the relative objectivity of the inputs used to measure fair value, with Level 1 representing the highest.

The three levels of the fair value hierarchy are defined as follows:

Level 1 Valuations - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 Valuations - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 Valuations - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. Emera’s primary reasons for a Level 3 classification are as follows:

• While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

• The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

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

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Z.    Variable Interest Entities

The Company performs ongoing analysis to assess whether it holds any variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly-owned facilities.

VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is not recorded in the Company’s consolidated financial statements.

LPH has established a self-insurance fund (“SIF”) primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. LPH holds a variable interest in the SIF for which it was determined that LPH was the primary beneficiary and, accordingly, the SIF must be consolidated by LPH. In its determination that LPH controls the SIF, management considered that in substance the activities of the SIF are being conducted on behalf of LPH’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because LPH, 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.

NSPI holds a variable interest in Renewable Energy Services Ltd. (“RESL”), a VIE for which it was determined that NSPI was not the primary beneficiary since it does not have the controlling financial interest of RESL. NSPI has provided a $23.5 million guarantee with no set term for the indebtedness of RESL under a loan agreement between RESL and a third party lender, in support of which NSPI holds a security interest in all present and future assets of RESL. The guarantee arose in conjunction with NSPI’s participation in a wind energy project at Point Tupper, Nova Scotia, which is being operated by RESL. Under a purchased power agreement, NSPI purchases, at a fixed price, 100 percent of the power generated by the project. A default by RESL, under its loan agreement, would require NSPI to make payment under the guarantee. As at December 31, 2011, RESL’s indebtedness under the loan agreement was $21.9 million (2010 – $23.1 million), and NSPI has not recorded a liability in relation to the guarantee.

83

Bangor Hydro holds a variable interest in Chester Static Var Compensator (“SVC”), a VIE for which it was determined that Bangor Hydro was not the primary beneficiary since it does not have the controlling financial interest of Chester SVC. A subsidiary of Bangor Hydro is a 50 percent general partner in Chester SVC, which owns electrical equipment that supports a major transmission line. A wholly-owned subsidiary of Central Maine Power Company owns the other 50 percent interest. Chester SVC is 100 percent debt financed and accordingly the partners have no equity interest; and the holders of the SVC notes are without recourse against the partners or their parent companies.

The Company has identified certain long-term purchase power agreements that could be defined as variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

Emera’s consolidated VIE is recorded as an “Available-for-sale investment”. The following table provides information about Emera’s consolidated and unconsolidated VIEs as at December 31:

millions of Canadian dollars	2011			2010
		Total assets	Maximum exposure to loss		Total assets	Maximum exposure to loss
Consolidated VIE
BLPC SIF Available-for-sale investment		$54.1	$54.1		-	-
Unconsolidated VIEs in which Emera has Variable Interests
RESL		-	23.5		-	$23.5
Chester SVC		-	-		-	-

AA.    Available-for-sale Investments

Assets designated as Available-for-sale are non-derivative financial assets (equity and debt securities) intended to be held for an indefinite period of time, and may be sold in response to needs for liquidity or changes in interest rates, exchange rates or equity prices.

Regular purchases and sales of financial assets are recognized at fair value, including transaction costs, on the trade date, the date on which the Company commits to purchase or sell the asset; and subsequently carried at fair value based on current bid prices on the market. Unrealized gain and losses arising from changes in the fair value of available-for-sale assets are recognized in AOCL until the financial asset is sold, or otherwise disposed of, or until the financial investment is determined to be impaired, at which time the cumulative gain or loss will be included in income for the period.

Interest on available-for-sale debt securities is calculated using the effective interest method and is recognized on the Consolidated Statements of Income in “Other income (expenses), net”. Dividends on available-for-sale equity securities are recognized on the Consolidated Statements of Income in “Other income (expenses), net”.

BB.    Derivative Positions and Cash Collateral

Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”.

84

2.    CHANGE IN ACCOUNTING POLICY

In Q1 2011, the Company changed the date of its annual impairment test from March 31 to October 1. The change was made to more closely align the impairment testing date with the long-range planning and forecasting process. Emera believes the change in the annual impairment testing date did not delay, accelerate, or avoid an impairment charge and has determined this change in accounting policy is preferable under the circumstances and does not result in adjustments to the financial statements when applied retrospectively.

In Q4 2011, Emera early adopted ASU No. 2011-08, “Intangibles – Goodwill and Other”. This new approach was used in its annual impairment test on October 1, 2011.

3.    FUTURE ACCOUNTING PRONOUNCEMENTS

Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities, ASU No. 2011-11

In December 2011, The Financial Accounting Standards Board (“FASB”) issued an accounting standards update which requires companies to disclose gross information and net information about both instruments and transactions eligible for offset in the statement of financial positions and instruments and transactions subject to an agreement similar to a master netting arrangement to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU No. 2011-11 is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013 with required disclosures made retrospectively for all comparative periods presented. The Company is currently evaluating the impact that the adoption will have in the financial statements.

Other Comprehensive Income, ASU No. 2011-05

In June 2011, FASB issued an accounting standards update amending Accounting Standards Codification (“ASC”) 220 to improve the comparability, consistency and transparency of comprehensive income reporting. The guidance requires that items of net income, items of other comprehensive income and total comprehensive income be presented in one continuous statement or two separate but consecutive statements. Items that are reclassified from other comprehensive income to net income must be presented separately on the face of the financial statements. ASU No. 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Retrospective application of the new disclosures will be required for comparative periods. The adoption of this update will change the order in which certain consolidated financial statements are presented and provide additional detail on those financial statements where applicable, but will not have any other impact to the consolidated financial statements.

Subsequently in December 2011, FASB issued ASU No. 2011-12, Deferral of the Effective Date for Amendments to Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The amendments in ASU No. 2011-12 defer the changes in ASU No. 2011-05 that relate to the presentation of reclassification adjustments out of AOCL.

Fair Value Measurement, ASU No. 2011-04

In May 2011, FASB issued an accounting standards update amending ASC 820 to achieve common fair value measurement and disclosure requirements between USGAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify the intent concerning the application of existing requirements and include some instances where a particular principle or requirement for measuring fair value or disclosing information related to fair value measurements has changed. ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the impact that the adoption will have in the consolidated financial statements.

85

4.    SEGMENT INFORMATION

Emera is an energy and services company which invests in electricity generation, transmission and distribution, gas transmission and utility energy services. Emera manages its reportable segments separately due to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income and total assets.

As at December 31, 2011, Emera has five reporting segments, specifically:

• NSPI;

• Maine Utility Operations (Bangor Hydro and MPS);

• Caribbean Utility Operations (BLPC, GBPC and Lucelec);

• Brunswick Pipeline; and

• Other (Emera Energy Services, EUS, M&NP, other strategic investments, holding companies, and inter-segment eliminations).

Bangor Hydro and MPS have been combined into Maine Utility Operations as the companies have similar geographical, operating, and regulatory environments. In Q4 2010, MPS was reported in “Other”. BLPC, GBPC and Lucelec have been combined into Caribbean Utility Operations as the companies have similar regulated operations including generation, transmission and distribution. In Q4 2010, the Company reported Caribbean Utility Operations in “Other” as Emera’s investment in these entities was not substantial enough to meet segment reporting requirements. Prior periods have been restated to reflect the Maine Utility and Caribbean Utility Operations as segments.

millions of Canadian dollars	NSPI		Maine Utility Operations		Caribbean Utility Operations		Brunswick Pipeline		Other and Eliminations		Total
Year ended December 31, 2011
Operating revenues from external customers (1)		$1,232.5		$202.4		$406.3		$49.7		$148.9		$2,039.8
Inter-segment revenues (1)		0.5		-		-		-		24.1		24.6
Total operating revenues		1,233.0		202.4		406.3		49.7		173.0		2,064.4
Allowance for funds used during construction – debt and equity		16.2		6.1		1.5		-		0.2		24.0
Regulated fuel adjustment		(8.5)		-		-		-		-		(8.5)
Depreciation and amortization		187.2		36.5		22.6		0.1		3.6		250.0
Interest expense		122.6		14.0		9.2		-		34.7		180.5
Interest revenue		10.0		0.5		-		-		(0.3)		10.2
Internally allocated interest (2)		-		-		-		(30.2)		30.2		-
Gain on acquisition		-		-		-		-		28.2		28.2
Income from equity investments		-		-		2.8		-		18.7		21.5
Income tax expense (recovery)		(44.9)		22.4		0.7		-		(14.9)		(36.7)
Capital expenditures		307.9		91.9		69.6		0.2		25.4		495.0
Net income attributable to common shareholders		123.5		37.0		46.8		19.7		14.1		241.1
As at December 31, 2011
Total assets		3,897.0		963.0		848.8		545.8		669.0		6,923.6
Investments subject to significant influence		-		1.2		26.7		-		194.8		222.7
Goodwill		-		116.4		77.5		-		3.8		197.7

(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs.

86

millions of Canadian dollars	NSPI		Maine Utility Operations		Caribbean Utility Operations		Brunswick Pipeline		Other and Eliminations		Total
Year ended December 31, 2010
Operating revenues from external customers (1)		$1,190.2		$172.4		-		$48.9		$171.0		$1,582.5
Inter-segment revenues (1)		1.2		-		-		-		22.4		23.6
Total operating revenues		1,191.4		172.4		-		48.9		193.4		1,606.1
Allowance for funds used during construction – debt and equity		17.2		5.1		-		-		-		22.3
Regulated fuel adjustment		(99.0)		-		-		-		-		(99.0)
Depreciation and amortization		188.1		21.5		-		0.1		3.8		213.5
Interest expense		117.7		12.6		-		-		33.2		163.5
Interest revenue		4.1		-		-		-		0.1		4.2
Internally allocated interest (2)		-		-		-		(30.6)		30.6		-
Gain on acquisition		-		-		-		-		22.5		22.5
Income from equity investments		-		-		$4.7		-		10.6		15.3
Income tax expense (recovery)		(13.4)		18.8		-		-		(13.5)		(8.1)
Capital expenditures		533.3		41.3		-		10.8		(18.9)		566.5
Net income attributable to common shareholders		119.2		31.9		19.8		19.7		0.1		190.7
As at December 31, 2010
Total assets		3,804.7		880.8		395.9		507.8		489.8		6,079.0
Investments subject to significant influence		-		1.1		136.7		-		108.2		246.0
Goodwill		-		113.5		53.5		-		0.4		167.4

(1) All significant inter-company balances and inter-company transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities that have not been eliminated because management believes that the elimination of these transactions would understate property, plant and equipment, operating, maintenance and general expenses, or regulated fuel for generation and purchased power. Eliminated transactions are included in determining reportable segments.

(2) Segment net income is reported on a basis that includes internally allocated financing costs.

5.    REGULATED FUEL ADJUSTMENT

The regulated fuel adjustment related to the fuel adjustment mechanism (“FAM”) for NSPI includes the effect of fuel costs in both the current and two preceding years, specifically, and as detailed in the table below:

• The difference between actual fuel costs and amounts recovered from customers in the current year. This amount, net of the incentive component, is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities”.

• The recovery from (rebate to) customers of under (over) recovered fuel costs from prior years.

The regulated fuel adjustment for the years ending December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Under recovery of current year fuel costs		$(35.1)		$(76.6)
Recovery from (rebate to) customers of prior years’ fuel costs		26.6		(22.4)
Fuel adjustment		$(8.5)		$(99.0)

The Company has recognized a deferred income tax expense related to the regulated fuel adjustment based on NSPI’s enacted statutory tax rate. As at December 31, 2011, NSPI’s deferred income tax liability related to the FAM was $29.0 million (2010 - $29.2 million).

The FAM regulatory asset includes amounts recognized as a fuel adjustment, associated interest that is included in “Interest expense, net”, and the application of the 2010 deferral of tax benefits (see Regulatory Matters, Note 23).

87

The following table shows the balance sheet classification of the various components of the FAM balances as at December 31:

		$00000000.00		$00000000.00
millions of Canadian dollars	2011		2010
Current regulatory asset		$69.0		$27.2
Long-term regulatory asset		24.7		65.7
FAM regulatory asset		$93.7		$92.9
Current deferred income tax liability		$(21.4)		$(8.8)
Long-term deferred income tax liability		(7.6)		(20.4)
FAM deferred income tax liability		$(29.0)		$(29.2)

6.    OTHER INCOME (EXPENSES), NET

Other income (expenses), net for the years ended December 31 consisted of the following:

		$00000000.00		$00000000.00
millions of Canadian dollars	2011		2010
Gain on business acquisition (1) (note 18)		$28.2		$22.5
Gain on exchange of subscription receipts to common shares of APUC (2)		15.1		-
Allowance for equity funds used during construction		13.1		11.8
Amortization of defeasance costs		(12.1)		(12.1)
Foreign exchange losses		(2.7)		(1.1)
Foreign exchange losses recovered through the FAM		(5.2)		(9.4)
Recognition of regulatory asset in GBPC		4.4		-
Other		2.3		0.8
		$43.1		$12.5

(1) Emera’s interest in LPH was acquired in two tranches in Q2 2010 and Q1 2011 giving rise to non-taxable gains.

(2) Pursuant to an April 2009 subscription agreement with APUC, on January 1, 2011, Emera exchanged subscription receipts it acquired in 2009 into 8.523 million APUC common shares issued at $3.25 per share, resulting in a gain of $15.1 million (after-tax gain of $12.8 million).

7.    INTEREST EXPENSE, NET

Interest expense, net for the years ended December 31 consisted of the following:

		$00000000.00		$00000000.00
millions of Canadian dollars	2011		2010
Interest on debt (1)		$174.8		$154.8
Allowance for borrowed funds used during construction		(10.9)		(10.5)
Interest revenue		(10.2)		(4.2)
Other		5.7		8.7
		$159.4		$148.8

(1) Interest on debt includes amortization of debt financing costs, premiums and discounts.

8.    INCOME TAXES

The income tax provision, for the years ended December 31, differs from that computed using the statutory rates for the following reasons:

millions of Canadian dollars			2011				2010
Income before provision for income taxes	$	222.7			$	191.2
Income taxes, at statutory rates		72.4		32.5%		65.0		34.0%
Deferred income taxes on regulated income recorded as regulatory assets		(60.3)		(27.1)%		(67.9)		(35.5)%
Change in estimate of prior years expected benefit of tax deductions		(25.2)		(11.3)%		-		-
Net tax effect of equity earnings		(8.4)		(3.8)%		(5.8)		(3.0)%
Non-taxable gain on business acquisition		(9.6)		(4.3)%		(7.5)		(3.9)%
Non-deductible regulatory amortization		5.5		2.5%		11.8		6.2%
Reduction in FAM regulatory asset		(4.7)		(2.1)%		-		-
Recovery of prior year income taxes		(1.7)		(0.8)%		(4.7)		(2.5)%
Other		(4.7)		(2.1)%		1.0		0.5%
Income tax expense (recovery)		$(36.7)		(16.5)%		$(8.1)		(4.2)%

88

The 2011 statutory income tax rate of 32.5 percent (2010 – 34 percent) represents the combined Canadian federal and Nova Scotia provincial income tax rates which are the relevant tax jurisdictions for Emera.

The following reflects the composition of taxes on income from continuing operations for the years ended December 31:

millions of Canadian dollars	2011		2010
Income tax recovery – current
Domestic		$(45.8)		$(45.2)
Foreign		(2.5)		(2.0)
Income tax expense – deferred
Domestic		2.5		29.0
Foreign		25.0		12.3
Operating loss carry forwards		(15.9)		(2.2)
Income tax expense (recovery)		$(36.7)		$(8.1)

Foreign income before taxes was $164.1 million in 2011 and $102.5 million in 2010.

The deferred income tax assets and liabilities as at December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Deferred income tax assets:
Pension and other post-retirement liabilities		$230.4		$173.1
Tax loss carry forwards		74.0		54.7
Asset retirement obligations		42.9		63.2
Intangibles		27.8		27.6
Other		52.9		29.5
Total deferred income tax assets before valuation allowance		428.0		348.1
Valuation allowance		(17.3)		(14.4)
Total deferred income tax assets after valuation allowance		$410.7		$333.7
Deferred income tax liabilities:
Property, plant and equipment		$469.6		$353.9
Net investment in direct financing lease		50.3		32.9
Regulatory assets (deferral of FAM)		29.0		29.2
Other		54.2		49.9
Total deferred income tax liabilities		$603.1		$465.9
Consolidated Balance Sheet presentation
Current deferred income tax assets		$14.0		$13.7
Long-term deferred income tax assets		33.1		31.1
Current deferred income tax liabilities		(10.9)		(8.5)
Long-term deferred income tax liabilities		(228.6)		(168.5)
Net deferred income tax liabilities		$(192.4)		$(132.2)

For regulated entities, to the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized. These amounts include a gross up to reflect the income tax associated with future revenues required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets.

In Q4 2011, NSPI modified its estimate of the expected tax benefit of tax deductions, electing to amend its tax returns for the years 2006 through 2009. This resulted in a $23.3 million reduction in income tax expense and a $3.0 million increase in interest revenue, recorded in the quarter. This change in accounting estimate has been accounted for on a prospective basis.

In Q4 2010, NSPI revised its estimate of the 2010 expected benefit from accelerated tax deductions, resulting in a $7.2 million reduction in income tax expense.

89

The following table summarizes as at December 31, 2011 the net operating loss (“NOL”), capital loss and tax credit carryovers and the associated carryover periods, and the valuation allowances for amounts which Emera has determined that realization is uncertain:

millions of Canadian dollars	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Expiration Period
NOL		$59.9		$(0.6)		$59.3		2014-2031
Capital loss		14.1		(14.1)		-		Indefinite
Investment tax credit		0.3		-		0.3		Indefinite
Total		$74.3		$(14.7)		$59.6

As at December 31, 2011, Emera had a gross NOL carryover of $215.1 million, capital loss carryover of $64.1 million, and an investment tax credit carry forward of $0.8 million.

Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that Emera is more likely than not to realize all recorded deferred income tax assets, except for the losses noted above and unrealized capital gains on certain investments. A valuation allowance has been recorded as at December 31, 2011 related to these losses and investments.

The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows:

		$000000.00		$000000.00
millions of Canadian dollars	2011		2010
Balance, January 1		$12.9		$12.1
Increases due to tax positions related to prior year		0.3		-
Increases due to tax positions related to current year		2.5		2.4
Decreases due to settlements with taxing authorities		(1.1)		-
Decreases due to expiration of statute of limitations		(1.7)		(1.6)
Balance, December 31		$12.9		$12.9

The total amount of unrecognized tax benefits as at December 31, 2011 was $12.9 million (2010 – $12.9 million) which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $1.3 million (2010 – $1.3 million). In the next twelve months, it is reasonable that $2.2 million of unrecognized tax benefits may be recognized due to statute expirations or settlement agreements with taxing authorities.

The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, US and non-US income and withholding taxes for which deferred taxes might otherwise be required have not been provided for on a cumulative amount of temporary differences related to investments in foreign subsidiaries of approximately $290.6 million as at December 31, 2011. It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred.

Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados and St. Lucia income tax returns. As at December 31, 2011, the Company’s tax years still open to examination by taxing authorities include 2002 and subsequent years. With few exceptions, the Company is no longer subject to examination for years prior to 2006.

90

9.    EARNINGS PER SHARE

The following table reconciles the computation of basic and diluted earnings per share for the years ended December 31:

millions of Canadian dollars, except per share amounts	2011		2010
Numerator
Net income attributable to common shareholders		$241.1		$190.7
Preferred stock dividends of subsidiary		8.0		8.0
Diluted numerator		249.1		198.7
Denominator
Weighted average shares of common stock outstanding		120.5		113.7
Weighted average DSUs outstanding		0.5		0.5
Weighted average shares of common stock outstanding – basic		121.0		114.2
Effect of dilutive securities		4.2		5.1
Stock-based compensation and employee common share purchase plan		1.0		1.1
Weighted average shares of common stock outstanding – diluted		126.2		120.4
Earnings per common share
Basic		$1.99		$1.67
Diluted (1)		$1.97		$1.65

(1) The calculation of diluted earnings per share for the years ended December 31, 2011 excluded the impact of $0.2 million (2010 – nil million) of unexercised stock options that had an anti-dilutive effect.

10.    RESTRICTED CASH

Restricted cash as at December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Restricted cash – BLPC (1)		$11.2		-
Restricted cash – Emera (2)		-		$58.4
Restricted cash – Other		2.8		0.2
		$14.0		$58.6

(1) This cash is held for the SIF at BLPC 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. The cash is not available for the Company to use in its operations.

(2) The cash was held for purposes of the CPUV acquisition and was not available for the Company to use in its operations.

11.    RECEIVABLES, NET

Receivables, net as at December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Customer accounts receivable – billed		$310.7		$250.8
Customer accounts receivable – unbilled		133.6		126.4
Total customer accounts receivable		444.3		377.2
Allowance for doubtful accounts		(12.8)		(6.6)
Customer accounts receivable, net		431.5		370.6
Other		28.1		22.3
		$459.6		$392.9

12.    INVENTORY

Inventory as at December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Fuel		$134.6		$129.1
Materials		64.2		48.7
		$198.8		$177.8

91

13.    PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment as at December 31 consisted of the following regulated and non-regulated assets:

millions of Canadian dollars	2011		2010
Generation		$3,208.5		$2,916.1
Transmission		1,027.4		919.9
Distribution		1,893.6		1,588.8
General plant and other		531.4		446.4
Total cost		6,660.9		5,871.2
Less: Accumulated depreciation		(2,838.0)		(2,462.6)
		3,822.9		3,408.6
Construction work in progress		471.5		334.0
Net book value		4,294.4		3,742.6

For the year ended December 31, 2011, AFUDC of $23.6 million (2010 – $21.7 million) was capitalized to “Property, plant and equipment”.

As a result of regulator-approved accounting policies and depreciation rates, NSPI, Bangor Hydro, and MPS defer certain costs within “Property, plant and equipment” that would not otherwise be deferred in the absence of rate-regulation. Cumulative differences between items recognized for rate regulatory purposes and applicable accounting standards including depreciation rates, AFUDC and overhead costs cannot be separately determined. Cumulative amounts related to asset retirement obligations and the associated accretion expense were $17.1 million as at December 31, 2011 (2010 – $15.3 million).

14.    NET INVESTMENT IN DIRECT FINANCING LEASE

Brunswick Pipeline commenced service on July 16, 2009, transporting re-gasified LNG for Repsol Energy Canada under a 25 year firm service agreement. The agreement meets the definition of a direct financing capital lease for accounting purposes. The net investment in direct financing lease consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease.

millions of Canadian dollars	2011			2010
Total minimum lease payments to be received		$1,440.7			$1,495.4
Less: amounts representing estimated executory costs		(249.8	)		(258.7	)
Minimum lease payments receivable		$1,190.9			$1,236.7
Estimated residual value of leased property (unguaranteed)		183.0			183.0
Less: unearned finance lease income		(880.1)			(928.2)
Net investment in direct financing lease		$493.8			$491.5
Principal due within one year (included in “Other current assets”)		(1.8)			-
		$492.0			$491.5

Future minimum lease payments to be received for the next five years:

millions of Canadian dollars	For the year ended December 31
	2012		2013		2014		2015		2016
Minimum lease payments to be received		$58.8		$58.8		$60.0		$61.6		$61.6
Less: amounts representing estimated executory costs		(9.1)		(9.2)		(9.4)		(9.6)		(9.8)
Minimum lease payments receivable		$49.7		$49.6		$50.6		$52.0		$51.8

92

15.    INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME

Investments subject to significant influence consisted of the following:

	Carrying Value As at December 31			Equity Income For the Year Ended December 31				Percentage of Ownership
millions of Canadian dollars		2011	2010		2011	2010			2011
M&NP (1)		$125.0	$118.8		$8.3	$9.1			12.9
APUC (1) (3)		43.7	-		2.4	-			6.3
CPUV		37.6	-		2.1	-			49.999
Lucelec (1)		26.7	25.0		2.0	2.1			19.1
AHI		5.9	3.6		(1.6)	(0.4)			37.7
Maine Electric Power Company Inc.		0.9	0.9		-	-			21.7
Maine Yankee Atomic Power Company (1)		0.3	0.2		-	-			12.0
LPH (2)		-	111.7		0.8	5.2			-
GBPC (2)		-	-		-	(2.6	)		-
Bear Swamp		(17.4)	(14.2)		7.5	1.9			50.0
		$222.7	$246.0		$21.5	$15.3

(1) Although Emera’s ownership percentage of these entities is relatively low, it does have significant influence over the operating and financial decisions of these companies through Board representation. Therefore, Emera records its investment in APUC, Maine Yankee Atomic Power Company, Lucelec and M&NP using the equity method. This is consistent with industry practice for similar investments with significant influence.

(2) Emera gained control of GBPC on December 22, 2010 and LPH on January 25, 2011; the above information does not include the income or the carrying value after gaining control, at which point the investments were consolidated.

(3) As at December 31, 2011, the market price / share is $6.42 which indicates a fair market value of this investment of $54.7, as it is a publicly traded entity.

Equity investments include a $32.9 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 and is therefore not subject to amortization.

16.    AVAILABLE-FOR-SALE INVESTMENTS

The available-for-sale investments consist primarily of investments in debt and equity securities held in trust on behalf of BLPC’s SIF for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain of BLPC’s generating, transmissions and distribution systems. The SIF Fund assets are not available to the Company for use in its operations.

Emera has classified these investments as available-for-sale and recorded all such investments at their fair market value as at December 31, 2011.

Available-for-sale financial assets as at December 31 include the following:

millions of Canadian dollars	2011		2010
Common shares	$	1.3	$	0.8
Mutual funds		17.8		-
Corporate bonds, debentures, short and medium term notes		27.7		-
Government bonds		7.8		-
	$	54.6	$	0.8

93

The change in available-for-sale assets is as follows:

millions of Canadian dollars	2011		2010
Balance, beginning of the period		$0.8		$1.0
Resulting from acquisitions		53.5		-
Additions, net of foreign exchange loss		36.5		-
Disposals		(35.8)		-
		$55.0		$1.0
Change in fair value
Gain recognized in regulatory liability		(0.1)		-
Loss recognized in other comprehensive income during the period		(0.3)		(0.2)
		$(0.4)		$(0.2)
Balance, end of the period		$54.6		$0.8

There were no impairment provisions for available-for-sale investments for the years ended 2011 and 2010.

The maturity profile of debt securities included in the available-for-sale assets as at December 31 is as follows:

millions of Canadian dollars	2011		2010
Maturity within 1 year		$12.7		-
Maturity in 1-5 years		22.8		-
		$35.5		-

The maximum exposure to credit risk at the reporting date is the carrying value of the debt securities. None of these financial instruments are either past due or impaired.

17.    GOODWILL

The change in goodwill for the years ended December 31 is due to the following:

millions of Canadian dollars	2011		2010
Balance, January 1		$167.4		$87.6
Acquisitions		26.1		84.8
Change in foreign exchange rate		4.2		(5.0)
Balance, December 31		$197.7		$167.4

18.    ACQUISITIONS

Light & Power Holdings Ltd.

On January 25, 2011, Emera acquired 7.2 million shares of LPH, the parent company of BLPC, a vertically-integrated utility and the sole provider of electricity on the island of Barbados with a franchise to produce, transmit and distribute electricity on the island until 2028, for total cash consideration of $92.6 million CAD ($92.8 million USD). As a result, Emera became the majority shareholder of LPH, with a total interest of 80.1 percent. This investment was made to increase Emera’s regulated transmission, distribution and generation portfolio.

Prior to this transaction, Emera owned 38.3 percent of LPH with a carrying value of $113.5 million CAD ($113.8 million USD). The fair value of Emera’s interest in LPH immediately prior to the acquisition date was $84.8 million CAD ($85.0 million USD).

The fair value of the assets of a regulated utility are generally deemed to equal book value (rate base) given the regulated utility’s earnings are a function of its rate base, as determined by the regulator. The purchase price was negotiated between arms-length parties. The differential between the two amounts resulted in Emera recording a gain on acquisition of $28.2 million, which Emera has recorded as a non-taxable gain in “Other income (expenses), net” on Emera’s Consolidated Statements of Income for the year ended December 31, 2011.

94

The valuation technique used to measure the acquisition-date fair value of the assets and liabilities of LPH was book value for regulated assets given the regulatory environment in which BLPC operates. Non-regulated assets were measured based on recent transactions. Accordingly, a third party valuation of assets and liabilities was not performed.

The purchase price allocation has been finalized. The total purchase price has been allocated to the fair value of assets and liabilities as follows:

	millions of Canadian dollars
Cash and cash equivalents		$58.4
Restricted cash		12.3
Receivables, net		23.4
Income tax receivable		0.2
Inventory		16.3
Prepaid expenses		2.9
Property, plant and equipment		292.0
Available-for-sale investments		52.5
Other non-current assets		1.6
Current portion of long-term debt		(7.5)
Account payable		(33.7)
Other current liabilities		(5.3)
Long-term debt		(43.1)
Deferred income taxes		(9.5)
Regulatory liabilities		(62.7)
ARO		(2.2)
Other long-term liabilities		(2.5)
Gain on business acquisition (1)		(28.2)
Non-controlling interest		(58.2)
Total purchase consideration		$206.7

(1) The gain shown above represents the net effect of the gain on acquisition of $56.3 million net of a loss of $28.1 million on a business combination achieved in stages, which requires the revaluation of the existing interest to the implied value from the second investment at the date of acquiring control. The gain is included in “Other income (expenses) net” in the Consolidated Statements of Income.

The Company has included operating revenues of $282.4 million and net income attributable to common shareholders of $12.0 million for BLPC in its consolidated net income attributable to common shareholders for fiscal 2011 related to the period subsequent to January 25, 2011.

The Company also incurred $2.0 million in acquisition-related costs of which $1.5 million was recorded in 2011. These costs are included in “Operating, maintenance and general expense” in the Consolidated Statements of Income.

Supplemental Pro Forma Data

The unaudited pro forma statement below gives effect to the acquisition of a controlling interest in BLPC as if the transaction had occurred at the beginning of 2010. This pro forma data is presented for informational purposes only and does not purport to be indicative of the results of future operations or of the results that would have occurred had the acquisition taken place at the beginning of 2010.

For the	Year ended December 31
millions of Canadian dollars	2011		2010
Operating revenues		$2,081.7		$1,867.8
Net income attributable to common shareholders		241.4		200.9
Pro forma basic earnings per share		$1.99		$1.76
Pro forma diluted earnings per share		$1.97		$1.73

95

Grand Bahama Power Company Limited

On December 22, 2010, Emera acquired 50 percent of the outstanding common shares of GBPC, an integrated utility and sole provider of electricity on Grand Bahama Island; and an additional 10.7 percent interest in ICD Utilities Limited (“ICDU”), owner of the remaining 50 percent interest in GBPC, for total cash consideration of $81.6 million CAD ($82.0 million USD), giving Emera an 80.4 percent direct and indirect interest in GBPC. This investment was made to increase Emera’s regulated electricity, transmission and generation portfolio.

Prior to the transaction, Emera owned 50 percent of ICDU and indirectly through this ownership 25 percent of GBPC. This interest in ICDU had a carrying value of $39.2 million CDN ($39.4 million USD). The fair value of Emera’s interest in ICDU immediately prior to the acquisition date, was $36.8 million CDN ($37.0 million USD).

As a result of this transaction, the Company recorded a loss on a business acquisition achieved in stages related to the pre-existing investment of $2.4 million.

The valuation of the acquisition-date fair value of GBPC’s assets and liabilities was performed by a third party. The valuation technique primarily involved the cost approach for property, plant and equipment and comparable debt issuances for long-term debt. Quoted prices or public sourced information was utilized where possible in the valuation. The purchase price allocation has been finalized. The total purchase price has been allocated to the fair value of assets and liabilities as follows:

	millions of Canadian dollars
Receivables, net		$19.2
Inventory		16.2
Prepaid expenses		1.2
Other non-current assets		0.5
Property, plant and equipment		153.4
Goodwill		75.6
Short-term debt		(1.9)
Current portion of long-term debt		(4.2)
Account payable		(20.6)
Other current liabilities		(3.5)
Long-term debt		(83.1)
Pension and post-retirement liabilities		(5.5)
Non-controlling interest		(28.9)
Total purchase consideration		$118.4

The goodwill that arose on the acquisition of GBPC is a result of expected operational efficiencies and synergies that Emera’s management believes it can bring to the operation of GBPC, as well as additional strategic opportunities in the region.

The Company has included operating revenues of $124.0 million and net income attributable to common shareholders of $4.6 million for GBPC in its consolidated net income attributable to common shareholders for fiscal 2011.

The Company also incurred $4.9 million in acquisition-related costs of which $6.1 million was expensed in 2010, offset with a recovery of $1.2 million recorded in 2011. These expenses are included in “Operating, maintenance and general expense” in the “Consolidated Statements of Income.”

Supplemental Pro Forma Data

The unaudited pro forma statement below gives effect to the acquisition of a controlling interest of GBPC as if the transaction had occurred at the beginning of 2010. This pro forma data is presented for informational purposes only and does not purport to be indicative of the results of future operations or of the results that would have occurred had the acquisition taken place at the beginning of 2010.

96

For the	Year ended December 31
millions of Canadian dollars	2011		2010
Operating revenues		$2,064.4		$1,717.9
Net income attributable to common shareholders		241.1		187.3
Pro forma basic earnings per share		$1.99		$1.64
Pro forma diluted earnings per share		$1.97		$1.62

Maine & Maritimes Corporation

On December 21, 2010, Emera acquired all of the outstanding common shares of MAM, a publically held United States corporation, and the parent company of MPS for cash consideration of $77.2 million CAD ($75.8 million USD). This investment was made to increase Emera’s transmission and distribution portfolio.

The valuation technique used to measure the acquisition-date fair value of the assets and liabilities of MAM was book value for regulated assets given the regulatory environment in which MPS operates. Accordingly, a third party valuation of assets and liabilities was not performed.

The purchase price allocation has been finalized. The total purchase price has been allocated to the fair value of assets and liabilities as follows:

	millions of Canadian dollars
Cash and cash equivalents		$0.6
Restricted cash		0.2
Receivables, net		8.3
Income taxes receivable		1.2
Inventory		1.1
Regulatory assets – current		9.9
Prepaid expenses		0.9
Other current assets		0.3
Property, plant and equipment		66.6
Regulatory assets – non-current		22.3
Investments subject to significant influence		0.4
Goodwill		31.7
Other non-current assets		3.9
Short-term debt		(2.3	)
Current portion of long-term debt		(1.1	)
Account payable		(4.8	)
Regulatory liabilities – current		(0.5	)
Other current liabilities		(3.3	)
Long-term debt		(23.0	)
Deferred income taxes		(16.3	)
Derivative instruments		(3.6	)
Regulatory liabilities – long-term		(5.2	)
Pension and post-retirement liabilities		(7.1	)
Other long-term liabilities		(3.0	)
Total purchase consideration		$77.2

The goodwill that arose on the acquisition of MAM is a result of expected operational efficiencies and synergies that Emera’s management believes it can bring to the operation of MAM, as well as additional strategic opportunities in the region.

97

The Company has included operating revenues of $34.6 million and net income attributable to common shareholders of $2.8 million for MPS in its consolidated net income attributable to common shareholders for fiscal 2011. The Company also incurred $4.7 million in acquisition-related costs which were expensed during 2010 and included in “Operating, maintenance and general expense” in the “Consolidated Statements of Income.”

Supplemental Pro Forma Data

The unaudited pro forma statement below gives effect to the acquisition of MPS as if the transaction had occurred at the beginning of 2010. This pro forma data is presented for informational purposes only and does not purport to be indicative of the results of future operations or of the results that would have occurred had the acquisition taken place at the beginning of 2010.

For the	Year ended December 31
millions of Canadian dollars	2011		2010
Operating revenues		$2,064.4		$1,642.2
Net income attributable to common shareholders		241.1		189.5
Pro forma basic earnings per share		$1.99		$1.66
Pro forma diluted earnings per share		$1.97		$1.64

19.    SHORT-TERM DEBT

Emera’s short-term borrowings consist of commercial paper issuances, advances on the revolving credit facilities and short-term notes. Short-term debt and related the weighted-average interest rate as at December 31 consisted of the following:

millions of Canadian dollars	2011		Weighted- average interest rate		2010		Weighted- average interest rate
Emera
Advances on the revolving credit facilities (1)		$2.4		3.50%		$1.5		3.75%
Promissory note issued to APUC		135.8		-		27.7		-
NSPI
Advances on the revolving credit facilities (1)		4.6		3.25%		1.6		3.50%
Commercial paper (re-classed from long-term debt) (2)		59.3		1.08%		46.7		1.07%
MPS
Advances on the revolving credit facilities		0.7		3.25%		2.3		1.39%
GBPC
Advances on the revolving credit facilities		7.5		5.75%		1.9		5.50%
Short-term debt		$210.3				$81.7

(1) Advances on the long-term revolving credit facilities (note 20) can be made by way of overdraft on accounts for Emera and NSPI for up to $30 million and $50 million, respectively.

(2) NSPI’s commercial paper is backed by a revolving credit facility which matures in 2015. NSPI has the ability to refinance commercial paper on a long-term basis; however amounts expected to be paid through working capital are classified as short-term debt. All other drawings are classified as long-term debt (note 20).

The Company’s total short-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:

millions of Canadian dollars	Maturity		2011		2010
MPS – revolving credit facility		2012		$10.2		$9.9
GBPC – revolving credit facility		2012		11.2		10.9
Total				21.4		20.8
Less:
Advances under revolving credit facilities				8.2		4.2
Use of available facilities				8.2		4.2
Available capacity under existing agreements				$13.2		$16.6

As at December 31, 2011, these credit facilities require commitment fees ranging from 0.20% to 0.27% basis points. The weighted average interest rate on outstanding short-term debt at December 31, 2011 was 1.78% (2010 – 1.37%).

98

Credit Facilities

On April 27, 2011, Maine Public Service Company renewed its existing $10 million USD revolving credit facility with Bank of America, with a new expiration date of December 31, 2012.

In October 2011, GBPC entered into a 12 month revolving credit facility for $11 million Bahamian dollars with Scotiabank (Bahamas) Limited.

20.    LONG-TERM DEBT

Emera’s long-term debt includes the issuances detailed below. Medium-term notes and debentures are issued under trust indentures at fixed interest rates and are unsecured unless noted below. Also included are certain bankers’ acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year. Long-term debt as at December 31 consisted of the following:

millions of Canadian dollars	Stated Interest Rate		Effective Interest Rate		Maturity		2011		2010
Emera
Bankers acceptances, LIBOR loans (1)		-		2.16%		4 year renewal		$251.0		$396.7
Medium-term notes
Series F		4.10%		4.19%		2014		250.0		250.0
Series G		4.83%		4.89%		2019		225.0		225.0
Series H		2.96%		3.05%		2016		250.0		-
								725.0		475.0
Promissory note				-		2016		1.8		-
Capital lease obligations								1.7		2.5
								979.5		874.2
NSPI
Commercial Paper (2)		-		1.08%		4 year renewal		$312.8		$288.4
Medium-term notes
Series F		8.85%		8.21%		2025		125.0		125.0
Series I		8.40%		8.43%		2015		70.0		70.0
Series L		8.30%		8.96%		2036		60.0		60.0
Series M (3)		8.50%		7.76%		2026		40.0		40.0
Series N		7.60%		7.57%		2097		50.0		50.0
Series P		6.28%		6.28%		2029		40.0		40.0
Series R		7.45%		7.51%		2031		75.0		75.0
Series S		6.95%		7.12%		2033		200.0		200.0
Series T		5.75%		6.09%		2013		300.0		300.0
Series V		5.67%		5.71%		2035		150.0		150.0
Series W		5.95%		6.01%		2039		200.0		200.0
Series X		5.61%		5.65%		2040		300.0		300.0
								1,610.0		1,610.0
Debentures – Series 3		9.75%		9.99%		2019		95.0		95.0
Capital lease obligations								-		0.1
								2,017.8		1,993.5
Bangor Hydro (4)
LIBOR loans and demand loans (5)		-		2.14%		2 year renewal		$63.3		$38.6
General & refunding mortgage bonds (6)
$20 million		8.98%		8.98%		2022		20.3		19.9
$30 million		10.25%		10.25%		2020		30.5		29.8
								50.8		49.7

99

millions of Canadian dollars	Stated Interest Rate		Effective Interest Rate		Maturity		2011		2010
Bangor Hydro Continued (4)
Senior unsecured notes
$20 million 2002		6.09%		6.09%		2012		20.3		19.9
$50 million 2003 (7)		5.31%		5.31%		2018		32.3		36.2
$30 million 2007		5.65%		5.65%		2014		30.5		29.8
$20 million 2007		5.87%		5.87%		2017		20.3		19.9
								103.4		105.8
								217.5		194.1
MPS (4)
Maine Public Utility Financing Bank Bonds (8)		0.46%		6.20%		2021		$13.8		$13.5
Maine Public Utility Financing Bank Bonds (8)		0.46%		6.32%		2025		9.2		8.9
LIBOR loans								-		1.0
Capital lease obligations								-		0.1
								23.0		23.5
GBPC (4)
Unsecured notes		5.96%		5.96%		2014		$31.9		$35.5
Bond notes		7.07%		7.07%		2020- 2023		52.7		49.7
								84.6		85.2
BLPC
Royal Bank of Canada (9)		7.00%		7.00%		2021		$11.3		-
National Insurance Board (9)		6.65%		6.65%		2020		10.2		-
National Insurance Board (9)		6.875%		6.875%		2025		10.2		-
First Caribbean International Bank (10)		5.985%		5.985%		2015		4.3		-
European Investment Bank (11)		4.27%		4.27%		2013		7.9		-
								43.9		-
Adjustments
Commercial Paper in NSPI re-classed to short-term debt (2)		1.08%		4 year renewal				(59.3)		(46.7)
Unamortized debt discount – net								2.2		2.1
Amount due within one year								(35.7)		(10.6)
								(92.8)		(55.2)
Long-Term Debt								$3,273.5		$3,115.3

(1) Emera’s revolving credit facility matures in June 2015, at which point the Company has the intention to renew under similar terms. The credit facility can be extended annually with the approval of the syndicated banks.

(2) NSPI’s commercial paper is backed by a revolving credit facility which matures in 2015. NSPI has the ability to refinance commercial paper on a long-term basis; however amounts expected to be paid through working capital are classified as short-term debt (note 19). All other drawings are classified as long-term debt.

(3) Notes extendable until 2056 at the option of the holders.

(4) Debt issued and payable in USD.

(5) Bangor Hydro’s revolving credit facility matures in September 2013, at which point the Company has the intention to renew under similar terms.

(6) Secured by property, plant and equipment of Bangor Hydro.

(7) Sinking fund payments beginning in year five.

(8) The interest on these USD variable rate bonds is fixed through the MPS interest rate swaps. The 1996 Series bonds of $13.6 million, due in 2021, are fixed at 4.42 percent, while the 2000 Series bonds of $9.0 million, due in 2025, are fixed at 4.53 percent.

(9) Debt issued and payable in Barbadian dollars. Borrowings are secured under a Debenture Trust Deed which creates a first and floating charge on the Company’s property, present and future.

(10) Debt issued and payable in USD. Borrowings are secured under a Debenture Trust Deed which creates a first and floating charge on the Company’s property, present and future.

(11) Debt issued and payable in USD. Borrowings are guaranteed by the Government of Barbados.

100

The Company’s total long-term credit facilities, outstanding borrowings and available capacity as at December 31 were as follows:

millions of Canadian dollars	Maturity		2011		2010
Emera – revolving credit facility (1)		June 2015		$700.0		$600.0
NSPI – revolving credit facility (2)		June 2015		500.0		600.0
Bangor Hydro – revolving credit facility		September 2013		81.4		79.6
Total				1,281.4		1,279.6
Less:
Borrowings under credit facilities				634.1		726.8
Letters of credit issued inside credit facilities				13.7		11.4
Use of available facilities				647.8		738.2
Available capacity under existing agreements				$633.6		$541.4

(1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $30 million and such advances are classified as short-term debt (note 19).

(2) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million and such advances are classified as short-term debt (note 19).

Credit Facilities

In June, 2010, Emera entered into a three year revolving credit facility for $600 million with a syndicate of banks. In June, 2010, NSPI entered into a three year revolving credit facility for $600 million with a syndicate of banks. In August 2011, Emera increased its committed syndicated revolving bank line of credit from $600 million to $700 million, and NSPI reduced its committed syndicated revolving bank line of credit from $600 million to $500 million. The maturity of both facilities was extended from June 2013 to June 2015.

NSPI has an active commercial paper for up to $400 million, of which outstanding amounts are 100 percent backed by NSPI’s bank line, which results in an equal amount of credit being considered drawn and unavailable.

On June 24, 2010, Bangor Hydro entered into a 39 month revolving credit facility for $80 million USD with a syndicate of banks.

Issuances

On December 13, 2011, Emera completed the issue of $250 million Series H Medium-Term Notes. The Series H Notes bear interest at a rate of 2.96 percent and yield 2.969 percent per annum until December 13, 2016.

The net proceeds of the offering will be used to repay short-term borrowings and for general corporate purposes.

Debt Covenants

Emera and certain subsidiaries debt obligations contain covenants related to the amount of debt to capitalization as defined in certain agreements. In addition, other covenants and financial reporting obligations exist. Failure to comply with these covenants could result in an event of default, which if not cured or waived, could result in the acceleration of outstanding debt obligations. As at December 31, 2011, Emera and each of its subsidiaries were in compliance with all respective financial covenants related to outstanding debt.

Debt shelf prospectus

Emera

In February 2011, Emera filed an amended and restated short form base shelf prospectus. This amendment increased the aggregate principal amount of debt securities and preferred shares that may be offered from time to time under the short form base shelf prospectus from $500 million to $650 million. As at December 31, 2011, $150 million in preferred shares and $250 million of medium term notes have been issued under the short form base shelf prospectus and shelf prospectus supplements. Concurrently with the Canadian filing of this amendment, Emera also filed a registration statement on Form F-9 with the U.S. Securities and Exchange Commission to register debt securities and preferred shares having an aggregate initial offering price of up to $500 million for sale in the United States.

101

NSPI

In May 2011, NSPI filed an amendment to its amended and restated short form base shelf prospectus and an amendment to its prospectus supplement for medium-term notes (unsecured). These amendments increased the aggregate principal amount of debt securities and medium-term notes that may be offered from time to time under the short form base shelf prospectus and prospectus supplement from $500 million to $800 million. As at December 31, 2011, $300 million in medium-term notes have been issued under NSPI’s short form base shelf prospectus and prospectus supplement since their initial filing in 2010.

Long-Term Debt Maturities

As at December 31, 2011, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follows:

millions of   Canadian dollars	2012		2013		2014		2015		2016		Greater than 5 years		Total
Emera		$1.1		$0.9		$250.7		$251.6		$250.2		$225.0		$979.5
NSPI		-		300.0		-		323.5		-		1,335.0		1,958.5
Bangor Hydro		24.9		67.9		35.1		4.6		4.6		80.4		217.5
MPS		-		-		-		-		-		23.0		23.0
GBPC		4.0		4.2		15.7		8.1		-		52.6		84.6
BLPC		-		7.9		-		4.1		-		31.9		43.9
Total		$30.0		$380.9		$301.5		$591.9		$254.8		$1,747.9		$3,307.0

21.    OTHER CURRENT LIABILITIES

Other current liabilities as at December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Accrued charges		$69.0		$59.6
Accrued interest on long-term debt		38.0		37.7
Sales taxes payable		12.8		7.0
Dividends payable		2.0		2.1
Other		5.4		3.9
		$127.2		$110.3

22.    ASSET RETIREMENT OBLIGATIONS

Asset Retirement Obligations (“ARO”) mostly relate to the reclamation of land at the thermal, hydro, and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment. Certain hydro, transmission and distribution assets may have additional ARO that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the fair value of any related ARO cannot be made at this time.

The change in ARO for the years ended December 31 is as follows:

millions of Canadian dollars	2011		2010
Balance, January 1		$141.8		$104.5
Additions		-		32.1
Additions due to acquisition		2.3		-
Liabilities settled		(1.3)		(1.2)
Accretion included in depreciation expense		4.5		3.6
Accretion deferred to regulatory asset		1.9		2.1
Revisions in estimated cash flows		(49.3)		0.7
Balance, December 31		$99.9		$141.8

102

As at December 31, 2011 and 2010, some of the Company’s transmission and distribution assets may have additional conditional ARO which are not recognized in the financial statements as the fair value of these obligations could not be reasonably estimated given there is insufficient information to do so. Management will continue to monitor these obligations and a liability will be recognized in the period in which an amount becomes determinable.

During Q4, 2011, Emera Brunswick Pipeline’s estimated cash flows with respect to its ARO were updated as a result of the National Energy Board’s new guidelines for the calculation of reclamation and abandonment costs for Canadian pipelines. The change resulted from a change in the estimate of future reclamation and abandonment costs.

During Q2 2011, NSPI’s estimated future cash flows with respect to ARO were updated to reflect the results of a settlement agreement with stakeholders which was approved by the UARB, following the completion of a depreciation study. The changes resulted from a change in estimates of retirement dates and future decommissioning costs. The new accretion rates are effective January 1, 2012.

23.    REGULATORY MATTERS

NSPI

NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (the “Act”) and is subject to regulation under the Act by the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s target regulated return on equity (“ROE”) range for 2011 was 9.1 percent to 9.6 percent based on an actual, average regulated common equity component of up to 40 percent of regulated capitalization. NSPI has a FAM, which enables NSPI to seek recovery of fuel costs through regularly scheduled rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. The FAM has an incentive component, whereby NSPI retains or absorbs 10 percent of the over or under recovered amount to a maximum of $5 million.

In May, 2011, NSPI filed a General Rate Application (“GRA”) with the UARB requesting an average 7.3 percent rate increase across all customer classes effective January 1, 2012. In November, 2011, the UARB approved a settlement agreement between NSPI and customer representatives which resulted in an average rate increase of 5.1 percent for all customers, effective January 1, 2012. Rates were approved based on a 9.2 percent ROE, applied to a 37.5 percent common equity component with a target earnings range of 9.1 percent to 9.5 percent on maximum actual equity of 40 percent.

Maine Utilities

Both Bangor Hydro and MPS’ core businesses are the transmission and distribution of electricity, with distribution operations and stranded cost recoveries regulated by the Maine Public Utilities Commission (“MPUC”). Each Company’s transmission operations are regulated by the Federal Energy Regulatory Commission (“FERC”). The rates for these three elements are established in distinct regulatory proceedings.

Distribution Operations

Maine Utilities’ distribution businesses operate under a traditional cost-of-service regulatory structure. Distribution rates are set based on an allowed ROE of 10.2 percent, on a common equity component of 50 percent.

103

Transmission Operations

Bangor Hydro

Bangor Hydro’s local transmission rates are set by the FERC annually on June 1, based upon a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted transmission investments and expenses. The allowed ROE for these local transmission investments is 11.14 percent. The common equity component is based upon the prior calendar year actual average balances. On June 1, 2011, Bangor Hydro’s local transmission rates decreased by approximately 10 percent (2010 – increased 37 percent).

Bangor Hydro’s bulk transmission assets are managed by the ISO-New England (“ISO”) as part of a region-wide pool of assets. The ISO manages the regions’ bulk power generation and transmission systems and administers the open access transmission tariff. Currently, Bangor Hydro, along with all other participating transmission providers, recovers the full cost of service for its transmission assets from distribution companies in New England, based on a regional formula that is updated on June 1 of each year. This formula is based on prior year regionally funded transmission investments and expenses, adjusted for current year forecasted investments and expenses. Bangor Hydro’s allowed ROE for these transmission investments ranges from 11.64 percent to 12.64 percent, and the common equity component is based upon the prior calendar year average balances. The cost recovery is recorded as transmission pool revenue in the Consolidated Statements of Income. The participating transmission providers are also required to contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent. These transmission pool expenses are recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income.

On June 1, 2010, Bangor Hydro’s regional transmission revenue requirement increased by 22 percent, and on June 1, 2011, it increased by a further 9 percent.

MPS

MPS local transmission rates are set annually based on a formula through its Open Access Transmission Tariff (“OATT”). Rates derived from the previous calendar year results go into effect June 1 for wholesale customers and July 1 for retail customers. The allowed ROE for transmission operations is 10.5 percent, and is based on the actual prior calendar year common equity balances. The allowed ROE is determined by negotiation with customers in the formula change years of the OATT, which occur every three years. The last OATT formula change year was 2009. On June 1, 2011, MPS’ local transmission rates increased by 3 percent for wholesale customers (2010 – increased 63 percent) and by 4 percent for retail customers (2010 – increased by 64 percent) on July 1, 2011.

MPS’ electric service territory is not interconnected to the New England bulk power system, and MPS is not a member of the ISO.

Stranded Cost Recoveries

Electric utilities in Maine are entitled to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC. Unlike T&D operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through rates. Generally, regulatory rates to recover stranded costs are set every three years, on a levelized basis, and determined under a traditional cost-of-service approach.

Bangor Hydro

Bangor Hydro’s net regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract and the unamortized portion on its loss on the sale of its investment in the Seabrook nuclear facility. These net regulatory assets total approximately $65.3 million as at December 31, 2011 (2010 – $74.9 million) or 8 percent of Bangor Hydro’s net asset base (2010 – 10 percent).

104

In May 2011, the MPUC approved an approximate 27 percent increase in Bangor Hydro’s stranded cost rates for the period of June 1, 2011 to February 28, 2014. The increased stranded cost revenues are offset, for the most part, by changes in regulatory amortizations, purchased power expense and resale of purchased power. The allowed ROE used in setting these new stranded cost rates is 7.4 percent, with a common equity component of 48 percent.

While the stranded cost revenue requirements differ throughout the period due to changes in annual stranded costs, the actual annual stranded cost revenues are the same during the period. To levelize the impact of the varying revenue requirements, cost or revenue deferrals are recorded as a regulatory asset or liability, and addressed in subsequent stranded cost rate proceedings, where customer rates are adjusted accordingly.

MPS

In December 2011, the MPUC approved MPS’ stranded cost rates for the three-year period January 1, 2012 through December 31, 2014. This revised three-year agreement, which amortizes essentially all of MPS’ remaining stranded costs, has an ROE of 7.2 percent and a common equity component of 50 percent. Any residual stranded costs remaining after December 31, 2014 will be recovered in future rate proceedings.

The Barbados Light & Power Company Limited

BLPC is a vertically integrated utility and sole provider of electricity on the island of Barbados.

BLPC is subject to regulation under the Utilities Regulation (Procedural) Rules 2003 (“Rules”) by Fair Trading Commission, Barbados, an independent regulator. The Rules give the Fair Trading Commission, Barbados utility regulation functions which include establishing principles for arriving at rates to be charged, monitoring the rates charged to ensure compliance, and setting the maximum rates for regulated utility services. The government of Barbados has granted BLPC a franchise to produce, transmit and distribute electricity on the island until 2028.

BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and providing an appropriate return to investors. BLPC’s approved regulated return on assets for 2011 is 10 percent.

BLPC’s first rate adjustment since 1983 was approved in January 2010 and was effective March 1, 2010.

All BLPC fuel costs are passed to customers through the fuel surcharge. Fair Trading Commission, Barbados has approved the calculation of the fuel surcharge, which is adjusted on a monthly basis. BLPC has the ability to carryover an under-recovery to later months to smooth the fuel surcharge for customers.

Grand Bahama Power Company Limited

GBPC is a vertically-integrated utility and sole provider of electricity on Grand Bahama Island. The Grand Bahama Port Authority (“GBPA”) regulates the utility and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit, and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policy to ensure that costs are recovered and a reasonable return earned.

The base tariff for GBPC includes a component to recover the cost of $20 USD per barrel of oil consumed by GBPC for generation of electricity. The amount by which actual fuel costs exceed $20 USD dollars per barrel is recovered or rebated through the fuel surcharge, which is adjusted on a monthly basis. The methodology for calculating the amount of the fuel surcharge has been approved by GBPA.

105

Brunswick Pipeline

Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas from the Canaport™ re-gasified liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick, to markets in the northeastern United States. Brunswick Pipeline entered into a 25 year firm service agreement commencing in July 2009 with Repsol Energy Canada. The pipeline is considered a Group II pipeline regulated by the National Energy Board (“NEB”). The NEB Gas Transportation Tariff is filed by Brunswick Pipeline in compliance with the requirements of the NEB Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline.

Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable of recovery either because the Company received specific approval from the appropriate regulator, or due to regulatory precedent set for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income.

Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income.

Regulatory assets and liabilities as at December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Regulatory assets
Deferred income tax regulatory asset	$	94.8	$	64.8
Regulated fuel adjustment mechanism		93.7		92.9
Unamortized defeasance costs		82.4		94.6
Deferrals related to derivative instruments		48.4		40.4
Pre-2003 income tax and related interest		42.0		56.9
Purchase power contracts		14.2		24.3
Seabrook nuclear project		11.8		14.3
Pension and postretirement medical plan		9.7		11.6
Deferral of income and capital taxes not included in Q1 2005 rates		7.8		10.0
Smart Grid		7.4		4.8
Stranded cost revenue & purchase power reconciliation deferrals		5.7		5.3
Deferral of demand side management		5.4		7.5
Hydro-Quebec Obligation		5.4		5.7
Asset impairment recovery		4.7		-
Deferred leasing costs		4.4		-
Other		16.0		12.3
	$	453.8	$	445.4
Current	$	141.6	$	90.5
Long-term		312.2		354.9
Total regulatory assets	$	453.8	$	445.4
Regulatory liabilities
Self-Insurance Fund	$	64.7		-
Deferrals related to derivative instruments		45.6	$	64.1
Deferred income tax regulatory liabilities		19.5		36.6
2010 renewable tax benefits deferral		-		14.5
Other		1.2		5.0
	$	131.0	$	120.2
Current	$	23.9	$	55.0
Long-term		107.1		65.2
Total regulatory liabilities	$	131.0	$	120.2

Deferred Income Tax Regulatory Asset and Liability

To the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized.

106

Regulated Fuel Adjustment Mechanism

As discussed in Note 5, the UARB approved the implementation of a FAM for NSPI effective January 1, 2009. The change in the FAM balance for the years ended December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Balance, January 1		$92.9		$(9.9)
Under recovery of current year fuel costs		35.1		76.6
(Recovery from) rebate to customers of prior years’ fuel costs		(26.6)		22.4
Application of the deferral related to tax benefits from 2010		(14.5)		-
Interest revenue on FAM balance		6.8		3.8
Balance, December 31		$93.7		$92.9

Unamortized Defeasance Costs

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities held in trust, which as at December 31, 2011, totaled $1.0 billion (2010 – $1.0 billion). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amortized over the life of the defeased debt as permitted by the UARB.

Deferrals Related to Derivative Instruments

NSPI defers changes in fair value of derivatives that are documented as economic hedges, and for which the NPNS exception has not been taken as a regulatory asset or liability as approved by the UARB. The gain or loss is recognized when the derivatives settle in fuel for generation and purchased power, other expenses, inventory or property, plant and equipment, depending on the nature of the item being economically hedged.

Pre-2003 Income Tax and Related Interest

NSPI has a regulatory asset related to pre-2003 income taxes that have been paid, but not yet recovered from customers as a result of capital cost allowance deductions NSPI claimed in its corporate income tax return that were disallowed in a Supreme Court decision. NSPI applied to the UARB to include recovery of these costs in customer rates. In February 2007, the UARB approved recovery of this regulatory asset over eight years, commencing April 1, 2007.

In January 2010, NSPI reached an agreement with stakeholders on its calculation of the Company’s regulated ROE. The agreement provides NSPI with flexibility in amortizing its pre-2003 income tax regulatory asset such that NSPI has flexibility in recognizing additional amortization in current periods and reducing amortization in future periods. The approval of the 2012 General Rate Decision provided continuation of this flexibility. For the year ended December 31, 2011, NSPI recorded an additional discretionary $0.1 million (2010 – $4.8 million) of regulatory amortization expense.

Power Purchase Contracts

Bangor Hydro has power purchase contracts, which it was required to negotiate when oil prices were high, with several independent power producers. Bangor Hydro attempted to alleviate the adverse impact of these high-cost contracts and in doing so incurred costs to restructure certain of the contracts. The MPUC has allowed Bangor Hydro to defer these costs and recover them in stranded cost rates. The contract restructuring costs are being recovered over a 20-year period ended in June 2018. In 2011, Bangor Hydro entered into a 20-year power purchase contract with a wind farm to purchase 20 percent of the energy generated. As with the Company’s other power purchase contracts, the MPUC has allowed Bangor Hydro full cost recovery for this contract.

Seabrook Nuclear Project

Bangor Hydro and MPS were participants in the Seabrook nuclear project in Seabrook, New Hampshire. In 1986 Bangor and MPS sold their respective interests with a combined cost of approximately $179.1 million. Both companies reached separate agreements with the MPUC providing for the recovery through customer rates of, in Bangor Hydro’s case 70 percent of 1984 year-end investment in Seabrook Unit 1 over 30 years ending in October 2015 and in MPS’s case, 60 percent costs associated with Seabrook Units 1 and 2 over 30 years ending in 2016.

107

Pension and Postretirement Medical Plan

As a result of purchase accounting, all unrecognized actuarial gains and losses, prior service cost, and the net transition asset/liability associated with the pension and postretirement medical benefit plans were eliminated as a result of the BHE and MPS mergers with Emera. As a result of regulatory accounting, a regulatory asset of $30 million, equal to these unrecognized amounts was established at the merger dates. BHE and MPS are amortizing the regulatory asset balance over the same period at which the corresponding gains and losses were being amortized when they were a component of pension and postretirement benefit expense.

Deferral of Income and Capital Taxes Not Included in Q1 2005 Rates

The UARB agreed to allow NSPI to defer taxes not reflected in rates for the period January 1, 2005 until April 1, 2005, the date when new rates became effective. As a result, NSPI deferred $16.7 million, consisting of $4.5 million of provincial and federal grants and $12.2 million in income taxes. The UARB approved recovery of this regulatory asset over eight years, commencing April 1, 2007.

Smart Grid

In 2010, BHE received an Accounting Order from the MPUC which allowed for the deferral of costs associated with the BHE’s Smart Grid project for future recovery.

Stranded Cost Revenue & Purchased Power Reconciliation deferral

Bangor Hydro and MPS have full recovery of stranded cost revenues and expenses, with deferral of variances between actual amounts and those used to set rates. Stranded cost rates are adjusted periodically to account for these cost deferrals.

Deferral of Demand Side Management

The UARB agreed to allow NSPI to defer up to $12.8 million of demand side management expenditures for the period January 1, 2008 through December 31, 2009, to be recovered in rates over six years commencing January 1, 2009.

Hydro-Quebec Obligation

The obligation associated with Hydro-Quebec represents the estimated present value of Bangor Hydro’s estimated future payments for net costs associated with ownership and operation of the Hydro-Quebec intertie between the New England utilities and Hydro-Quebec. The obligation has been recognized in other liabilities and the MPUC has permitted recovery of this obligation. The regulatory asset and obligation are being reduced as expenses are incurred with the reduction of the regulatory asset amortized to purchase power expense.

Asset Impairment Recovery

On July 14, 2011, GBPA approved the recovery of a $4.7 million asset impairment charge recorded in 2010. As a result, the charge was reversed through earnings in Q3, 2011, and instead recorded as a regulatory asset which will be amortized into income over a 25 year period commencing upon completion of the new 52 MW diesel generation unit scheduled to be on line mid-2012.

Deferred Leasing Costs

On April 12, 2011, GBPA approved as part of the fuel surcharge the recovery of the net costs of leasing the temporary generation required to meet peak demand for electricity until the commission of a new 52 MW power plant. The amount by which the actual cost of the temporary generation exceeds what has been recovered through the fuel surcharge has been recorded as a regulatory asset which will be amortized into income.

108

Self-Insurance Fund

LPH has established a self-insurance fund (“SIF”) primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. LPH holds a variable interest in the SIF for which it was determined that LPH was the primary beneficiary and, accordingly, the SIF must be consolidated by LPH. In its determination that LPH controls the SIF, management considered that in substance the activities of the SIF are being conducted on behalf of LPH’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because LPH, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. The SIF Fund assets are not available to the Company for use in its operations.

2010 Renewable Tax Benefits Deferral

In 2010, the UARB granted NSPI approval to defer certain tax benefits related to renewable energy projects arising in 2010. In 2011, the UARB approved an agreement NSPI reached with stakeholders to apply the deferral against the FAM regulatory asset, which reduced the FAM regulatory asset effective January 1, 2011. The application of the deferral reduced the amount of the FAM balance outstanding with the reduction applied to the amount that would otherwise be recovered from customers in 2012.

24.    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 NPNS exception are not recognized on the balance sheet; they are recognized in income when they settle. The Company continually assesses contracts designated under the NPNS exception 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 AOCL and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in fair value from cash flow hedges is recognized in net income in the reporting period.

Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value with any changes in fair value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting.

3. Derivatives entered into by NSPI, that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the UARB. 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 when the derivatives settle. 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 through the FAM.

109

4. Derivatives that do not meet any of the above criteria are designated as HFT and are recognized on the balance sheet at fair value. All gains and losses are recognized in net income of the period unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting treatment applies.

Derivative assets and liabilities relating to the foregoing categories as at December 31 consisted of the following:

	Derivative Assets				Derivative Liabilities
millions of Canadian dollars	2011		2010		2011		2010
Current
Cash flow hedges
Power and gas swaps		-		-		$8.1		$6.4
Foreign exchange forwards		$2.7		$2.4		0.5		-
		2.7		2.4		8.6		6.4
Regulatory deferral
Commodity swaps and forwards
Coal purchases		5.4		23.6		0.1		1.9
Natural gas purchases and sales		0.7		0.8		33.5		20.3
Heavy fuel oil (“HFO”) purchases		-		1.9		-		1.3
Foreign exchange forwards		6.0		2.1		-		1.2
Physical natural gas purchases and sales		4.2		4.3		0.1		-
		16.3		32.7		33.7		24.7
HFT derivatives
Power swaps and physical contracts		1.4		10.5		1.2		2.6
Foreign exchange forwards		-		1.4		-		-
Natural gas swaps, futures, forwards and physical contracts		10.9		7.6		10.6		8.0
		12.3		19.5		11.8		10.6
Total gross current derivatives		31.3		54.6		54.1		41.7
Impact of master netting agreements with intent to settle net or simultaneously		(4.0)		(4.9)		(4.0)		(4.9)
Total current derivatives		27.3		49.7		50.1		36.8
Long-term
Cash flow hedges
Power swaps		0.2		0.5		12.8		8.3
Interest rate swaps		-		-		6.2		3.6
Foreign exchange forwards		2.8		4.1		0.2		-
		3.0		4.6		19.2		11.9
Regulatory deferral
Commodity swaps and forwards
Coal purchases		6.7		18.5		-		-
Natural gas purchases and sales		-		0.1		5.1		1.8
Foreign exchange forwards		18.2		2.2		7.9		9.4
Physical natural gas purchases and sales		3.7		8.1		-		-
		28.6		28.9		13.0		11.2
HFT derivatives
Power swaps and physical contracts		0.9		1.0		0.8		0.9
Natural gas swaps, futures, forwards and physical contracts		6.8		2.0		5.4		5.4
		7.7		3.0		6.2		6.3
Total gross long-term derivatives		39.3		36.5		38.4		29.4
Impact of master netting agreements with intent to settle net or simultaneously		0.3		(0.5)		0.3		(0.5)
Total long-term derivatives		39.6		36.0		38.7		28.9
Total derivatives		$66.9		$85.7		$88.8		$65.7

110

Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

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 and capital projects denominated in foreign currency for Brunswick Pipeline and Bayside Power, respectively. MPS entered into an interest rate swap to hedge the fluctuation in interest rates on long-term debt.

As previously noted, the effective portion of the change in fair value of these derivatives is included in AOCL, until the hedged transactions are recognized in income. The ineffective portion is recognized in income of the period. The table below shows the amounts related to cash flow hedges recorded in AOCL and income for the years ended December 31, 2011:

millions of Canadian dollars					2011				2010
	Power and Gas Swaps		Interest Rate Swaps		Foreign Exchange Forwards		Power Swaps		Foreign Exchange Forwards
Unrealized loss in non-regulated fuel and purchased power – ineffective portion		$(0.4)		-		-		-		-
Realized loss in non-regulated fuel and purchased power		(7.0)		-		-		$(8.6)		-
Realized gain in regulated operating revenue		-		-		$2.7		-		-
Realized loss in other income (expenses), net		-		-		(0.3)		-		-
Total (losses) gains in income		$(7.4)		-		$2.4		$(8.6)		-
Total unrealized (loss) gain in OCL – effective portion, net of tax		$(5.9)		$(1.4)		$(1.4)		$(0.3)		$6.4

The Company expects $5.0 million (after-tax) of unrealized losses currently in AOCL to be reclassified into net income within the next twelve months, as the underlying hedged transactions settle.

As at December 31, 2011, the Company had the following notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle as outlined below:

millions	2012		2013		2014		2015		2016
Power swaps (megawatt hours (“MWh”)) purchases		0.3		0.3		0.3		0.3		0.3
Gas swaps (Mmbtu) purchases		1.6		-		-		-		-
Foreign exchange forwards (EURO) purchases		9.6		-		-		2.8		-
Foreign exchange forwards (USD) sales		$53.8		$48.0		$15.0		$9.0		$6.0

In addition, the Company has interest rate swaps on long-term debt of $13.8 million until 2021 and $9.2 million until 2025.

111

Regulatory Deferral

As previously noted, NSPI receives approval from the UARB for regulatory deferral of gains and losses on certain derivatives documented as economic hedges that do not qualify for hedge accounting, including certain physical contracts that do not qualify for the NPNS exemption.

For the years ended December 31, the Company has recorded the following realized and unrealized gains (losses) with respect to derivatives receiving regulatory deferral:

	Regulatory Assets				Regulatory Liabilities
millions of Canadian dollars	2011		2010		2011		2010
Current
Commodity swaps and forwards
Coal purchases		$(1.0)		$(20.2)		$17.3		$(15.9)
Natural gas purchases and sales		13.7		3.5		(0.4)		0.1
HFO purchases		(1.3)		(1.2)		1.9		8.0
Foreign exchange forwards		(1.6)		(20.0)		(3.9)		9.0
Physical natural gas purchases and sales		0.1		(3.9)		0.1		(3.9)
Long-term
Commodity swaps and forwards
Coal purchases		-		(15.3)		11.8		(9.0)
Natural gas purchases and sales		3.3		(0.2)		0.1		(0.1)
HFO purchases		-		(1.3)		-		2.0
Foreign exchange forwards		(1.5)		6.7		(16.0)		18.1
Physical natural gas purchases and sales		-		-		4.4		(3.9)

Regulatory Impact Recognized in Net Income

For the years ended December 31, the Company recognized the following (losses) gains related to derivatives receiving regulatory deferral as follows:

millions of Canadian dollars	2011		2010
Other expenses, net		-		$1.5
Regulated fuel for generation and purchased power		$(21.3)		(66.8)
Net losses		$(21.3)		$(65.3)

Commodity Swaps and Forwards

As at December 31, 2011, the Company had the following notional volumes of outstanding commodity swaps and forward contracts designated for regulatory approval that are expected to settle as outlined below:

	2012		2013		2014
millions	Purchases		Purchases		Purchases
Coal (metric tonnes)		0.5		0.3		0.1
Natural gas (Mmbtu)		20.1		7.6		-

Foreign Exchange Swaps and Forwards

As at December 31, 2011, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:

	2012		2013		2014		2015		2016
Fuel purchases exposure (millions of US dollars)		$256.0		$212.0		$210.0		$210.0		$120.0
Weighted average rate		0.9912		1.0251		1.0106		1.0090		0.9814
% of USD requirements		81.3%		67.3%		66.7%		66.7%		38.1%

112

Held-for-Trading Derivatives

In the ordinary course of its business, Emera enters into physical contracts for the purchase and sale of natural gas; and power and natural gas swaps, forwards, and futures to economically hedge those physical contracts. These derivatives are all considered HFT.

For the years ended December 31, the Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives:

millions of Canadian dollars	2011		2010
Power swaps and physical contracts in non-regulated operating revenues		$(5.9)		$9.4
Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues		19.9		11.8
Foreign exchange forwards in other income (expenses), net		(0.1)		2.7
		$13.9		$23.9

As at December 31, 2011, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below:

millions	2012		2013		2014		2015		2016		2017
Natural gas purchases (Mmbtu)		89.0		44.3		29.8		22.4		5.8		-
Natural gas sales (Mmbtu)		47.1		14.6		3.7		1.8		-		-
Power purchases (MWh)		0.2		-		-		-		-		-
Power sales (MWh)		0.2		-		-		-		-		-
Foreign exchange forwards (USD)		-		-		-		-		-		-

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 counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties and deposits or collateral are requested on any high risk accounts.

The Company assesses the potential for credit losses on a regular basis, and where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated.

As at December 31, 2011, the maximum exposure the Company has to credit risk is $414.9 million (2010 – $412.3 million) which includes accounts receivable net of collateral/deposits and assets related to derivatives.

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The total cash deposits/collateral on hand as at December 31, 2011 was $111.6 million (2010 – $66.3 million) which mitigates the Company’s maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company.

113

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

As at December 31, 2011, the Company had $92.3 million (2010 – $55.9 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 $80.0 million (2010 – $49.2 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric revenue.

Concentration risk

The Company’s concentrations of risk as at December 31 consisted of the following:

	2011 millions of Canadian dollars		% of total exposure			2010 millions of Canadian dollars		% of total exposure
Receivables, net
Regulated utilities
Residential		141.5		27	%		115.8		24	%
Commercial		92.8		18	%		64.0		13	%
Industrial		34.5		7	%		38.0		8	%
Other		28.0		5	%		27.4		6	%
		296.8		57	%		245.2		51	%
Trading group
Credit rating of A- or above		7.0		1	%		10.6		2	%
Credit rating of BBB- to BBB+		5.5		1	%		7.1		1	%
Not rated – fully collateralized		11.7		2	%		6.2		1	%
Not rated		27.8		5	%		39.7		9	%
		52.0		9	%		63.6		13	%
Other accounts receivable		110.8		21	%		84.1		18	%
		459.6		87	%		392.9		82	%
Derivative Instruments (current and long-term)
Credit rating of A- or above		44.3		9	%		56.6		12	%
Credit rating of BBB- to BBB+		10.2		2	%		11.8		2	%
Not rated		12.4		2	%		17.3		4	%
		66.9		13	%		85.7		18	%
		$526.5		100	%		$478.6		100	%

Cash Collateral

The Company’s cash collateral positions as at December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Cash collateral provided to others		$71.6		$41.6
Cash collateral received from others		5.7		3.0

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt to fall below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at December 31, 2011, the total fair value of these derivatives, was a net liability position is $88.8 million (2010 – $65.7 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.

114

25.    FAIR VALUE MEASUREMENTS

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (see note 24), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows:

Level 1 Valuations - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 Valuations - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 Valuations - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. Emera’s primary reasons for a Level 3 classification are as follows:

• While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

• The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

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

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following tables set out the classification of the methodology used by the Company to fair value its derivatives as at December 31:

							2011
millions of Canadian dollars	Level 1		Level 2		Level 3		Total
Assets
Cash flow hedges
Power and gas swaps		$0.2		-		-		$0.2
Foreign exchange forwards		-		$5.5		-		5.5
		0.2		5.5		-		5.7
Regulatory deferral
Commodity swaps and forwards
Coal purchases		-		12.1		-		12.1
Natural gas purchases and sales		(0.4)		0.7		-		0.3
Foreign exchange forwards		-		24.2		-		24.2
Physical natural gas purchases and sales		-		-		$7.9		7.9
		(0.4)		37.0		7.9		44.5
HFT derivatives
Power swaps and physical contracts		0.3		-		1.6		1.9
Natural gas swaps, futures, forwards and physical contracts		-		10.4		4.4		14.8
		0.3		10.4		6.0		16.7
Total assets		0.1		52.9		13.9		66.9

115

							2011
millions of Canadian dollars	Level 1		Level 2		Level 3		Total
Liabilities
Cash flow hedges
Power and gas swaps		$20.9		-		-		$20.9
Foreign exchange forwards				$0.7		-		0.7
Interest rate swaps		-		6.2		-		6.2
		20.9		6.9		-		27.8
Regulatory deferral
Commodity swaps and forwards
Natural gas purchases and sales		38.3		-		-		38.3
Foreign exchange forwards		-		7.9		-		7.9
Physical natural gas purchases and sales		-		-		$0.1		0.1
		38.3		7.9		0.1		46.3
HFT derivatives
Power swaps and physical contracts		0.3		-		1.3		1.6
Natural gas swaps, futures, forwards and physical contracts		2.7		7.3		3.1		13.1
		3.0		7.3		4.4		14.7
Total liabilities		62.2		22.1		4.5		88.8
Net (liabilities) assets		$(62.1)		$30.8		$9.4		$(21.9)

	2010
millions of Canadian dollars	Level 1		Level 2		Level 3		Total
Assets
Cash flow hedges
Power and gas swaps		$0.5		-		-		$0.5
Foreign exchange forwards		-		$6.5		-		6.5
		0.5		6.5		-		7.0
Regulatory deferral
Commodity swaps and forwards
Coal purchases (1)		-		41.2		-		41.2
Natural gas purchases and sales (2)		0.1		-		-		0.1
HFO purchases		-		1.9		-		1.9
Foreign exchange forwards		-		4.3		-		4.3
Physical natural gas purchases and sales		-		-		$12.4		12.4
		0.1		47.4		12.4		59.9
HFT derivatives
Power swaps and physical contracts		-		-		9.0		9.0
Foreign exchange forwards		-		1.4		-		1.4
Natural gas swaps, futures, forwards and physical contracts		0.5		1.4		6.5		8.4
		0.5		2.8		15.5		18.8
Total assets		1.1		56.7		27.9		85.7
Liabilities
Cash flow hedges
Power and gas swaps		$14.7		-		-		$14.7
Interest rate swaps		-		$3.6		-		3.6
		14.7		3.6		-		18.3
Regulatory deferral
Commodity swaps and forwards
Coal purchases (1)		-		1.0		-		1.0
Natural gas purchases and sales (2)		21.3		-		-		21.3
HFO purchases		-		1.3		-		1.3
Foreign exchange forwards		-		10.6		-		10.6
		21.3		12.9		-		34.2
HFT derivatives
Power swaps and physical contracts		-		-		$1.3		1.3
Natural gas swaps, futures, forwards and physical contracts		6.0		1.5		4.4		11.9
		6.0		1.5		5.7		13.2
Total liabilities		42.0		18.0		5.7		65.7
Net (liabilities) assets		$(40.9)		$38.7		$22.2		$20.0

  (1)    Balance was reclassified to Level 2 from Level 1

  (2)    Balance was reclassified to Level 1 from Level 3

116

The change in the fair value of the Level 3 financial assets for the year ended December 31, 2011 was as follows:

	Regulatory Deferral		Trading Derivatives
millions of Canadian dollars	Physical natural gas purchases and sales		Power		Natural Gas		Total
Balance, January 1		$12.4		$9.0		$6.5		$27.9
Reduction of benefit included in regulated fuel for generation and purchased power		(4.2)		-		-		(4.2)
Unrealized losses included in regulatory assets or liabilities		(0.3)		-		-		(0.3)
Total realized and unrealized (losses) gains included in non-regulated operating revenues		-		(7.4)		(2.1)		(9.5)
Balance, December 31		$7.9		$1.6		$4.4		$13.9

The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2010 was as follows:

	Regulatory Deferral		Trading Derivatives
millions of Canadian dollars	Physical natural gas purchases and sales		Power		Natural Gas		Total
Balance, January 1		-		$1.3		$4.4		$5.7
Unrealized losses included in regulatory assets or liabilities		$0.1		-		-		0.1
Total realized and unrealized (losses) gains included in non-regulated operating revenues		-		-		(1.3)		(1.3)
Balance, December 31		$0.1		$1.3		$3.1		$4.5

The financial assets and liabilities included on the balance sheet that are not measured at fair value as at December 31 consisted of the following:

	2011				2010
millions of Canadian dollars	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including current portion)		$3,309.2		$3,935.0		$3,125.9		$3,520.8

The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturity, without considering the effect of third party credit enhancements.

All other financial assets and liabilities such as cash and cash equivalents, restricted cash, accounts receivable, short-term debt and accounts payable are carried at cost. The carrying value approximates fair value due to the short-term nature of these financial instruments.

26.    EMPLOYEE BENEFIT PLANS

Emera maintains a number of contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees; and plans providing non-pension benefits for its retirees in Nova Scotia, Maine, Barbados and Grand Bahama Island.

Emera acquired control of LPH, the parent company of BLPC, in January 2011; therefore, it is not included in the December 31, 2010 comparative information.

117

Benefit Obligation and Plan Assets

The changes in Benefit Obligation and Plan Assets, and the Funded Status for all plans for the years ended December 31 were as follows:

	2011				2010
millions of Canadian dollars	Defined benefit pension plans		Non-pension benefits plans		Defined benefit pension plans		Non-pension benefits plans
Change in Projected Benefit Obligation and Accumulated Post-retirement Benefit Obligation
Balance, January 1		$1,048.3		$88.2		$898.1		$83.4
Service cost		15.4		2.9		11.3		2.4
Plan participant contributions		6.2		0.2		5.7		0.2
Interest cost		56.6		4.7		56.6		4.7
Plan amendments		-		(0.1)		(1.0)		-
Benefits paid		(49.5)		(5.5)		(44.5)		(6.2)
Actuarial losses		85.6		8.0		128.0		6.2
Foreign currency translation adjustment		2.8		1.2		(5.9)		(2.5)
Balance, December 31		1,165.4		99.6		1,048.3		88.2
Change in Plan assets
Balance, January 1		724.2		$3.4		$663.3		$3.3
Employer contributions		51.9		5.3		39.9		5.8
Plan participant contributions		6.2		0.2		5.7		0.2
Benefits paid		(49.5)		(5.5)		(44.5)		(6.2)
Actual return on assets, net of expenses		(11.9)		-		63.6		0.3
Foreign currency translation adjustment		1.5		-		(3.8)		-
Balance, December 31		722.4		3.4		724.2		3.4
Funded Status, end of year		$(443.0)		$(96.2)		$(324.1)		$(84.8)

As at December 31, the aggregate financial position for all pension plans where the Projected Benefit Obligation (PBO) or, for post-retirement benefit plans, the Accumulated Post-retirement Benefit Obligation (APBO), exceeds the plan assets was as follows:

Plans with PBO/APBO in excess of Plan assets			2011		2010
millions of Canadian dollars	Defined benefit pension plans		Non-pension benefits plans		Defined benefit pension plans		Non-pension benefits plans
PBO/APBO		$1,163.2		$99.6		$1,046.5		$88.2
Fair Value of Plan Assets		720.0		3.4		722.0		3.4
Funded Status		$(443.2)		$(96.2)		$(324.5)		$(84.8)

The Accumulated Benefit Obligation (“ABO”) for the defined benefit pension plans was $1,080.9 as at December 31, 2011 (2010 – $987.4 million). As at December 31, the aggregate financial position for all plans with an ABO in excess of the Plan assets was as follows:

Pension Plans with ABO in excess of Plan assets	2011		2010
millions of Canadian dollars	Defined benefit pension plans		Defined benefit pension plans
ABO		$1,079.3		$985.9
Fair Value of Plan Assets		720.0		722.0
Funded Status		$(359.3)		$(263.9)

Balance Sheet

The amounts recognized in the Consolidated Balance Sheets as at December 31 consisted of the following:

118

	2011				2010
millions of Canadian dollars	Defined benefit pension plans		Non-pension benefits plans		Defined benefit pension plans		Non-pension benefits plans
Current liabilities		$(4.6)		$(4.2)		$(3.9)		$(5.0)
Long-term liabilities		(438.5)		(92.3)		(320.2)		(79.8)
Other asset (noncurrent)		0.3		-		-		-
Amount included in deferred tax asset		22.9		6.7		13.1		2.4
AOCL after tax adjustment		502.0		11.7		388.8		6.7
Net amount recognized at end of year		$82.1		$(78.1)		$77.8		$(75.7)

Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCL. The following tables provide detail on the change in AOCL during fiscal 2011 relating to these items; and the composition of the year-end balance:

Accumulated Other Comprehensive Loss   millions of Canadian dollars	Actuarial losses (gains)		Past service (gains) costs
Defined Benefit Pension Plans
Balance, January 1		$402.3		$(0.4)
Amortized in current period		(24.2)		(0.1)
Current year addition to AOCL		154.0		-
Transfer to other regulatory asset (1)		(3.9)		-
Foreign currency translation adjustment		(2.8)		-
Balance, December 31		$525.4		$(0.5)
Non-pension benefits plans
Balance, January 1		$21.9		$(12.8)
Amortized in current period		(1.6)		1.6
Current year addition to AOCL		8.2		-
Transfer to other regulatory asset (1)		(0.2)		-
Foreign currency translation adjustment		0.9		0.4
Balance, December 31		$29.2		$(10.8)

(1) For MPS, as a result of regulatory accounting, any gain or loss is transferred to regulatory assets and amortized over the same period as the corresponding actuarial gains or losses.

	2011			2010
Accumulated Other Comprehensive Loss millions of Canadian dollars		Defined benefit pension plans	Non-pension benefits plans		Defined benefit pension plans	Non-pension benefits plans
Actuarial losses		$525.4	$29.2		$402.3	$21.9
Past service (gains)		(0.5)	(10.8)		(0.4)	(12.8)
Total AOCL on a pre-tax basis		524.9	18.4		401.9	9.1
Less: amount included in deferred tax asset		(22.9)	(6.7)		(13.1)	(2.4)
Net amount in AOCL after tax adjustment		$502.0	$11.7		$388.8	$6.7

The amounts in the foregoing table were not recognized in Emera’s net periodic benefit cost as at December 31.

Benefit Cost Components

			2011				2010
millions of Canadian dollars	Defined benefit pension plans		Non-pension benefits plans		Defined benefit pension plans		Non-pension benefits plans
Service cost		15.4		2.9		11.3		2.4
Interest cost		56.6		4.7		56.6		4.7
Expected return on plan assets		(56.3)		(0.2)		(55.8)		(0.3)
Current year amortization of:
Actuarial losses		24.5		1.9		11.0		1.2
Past service costs (gains)		0.1		(2.0)		0.2		(2.4)
Total		40.3		7.3		23.3		5.6

The expected return on plan assets is determined based on the market-related value of plan assets of $803.8 million as at January 1, 2011 (2010 – $775.1 million), adjusted for interest on certain cash flows during the year. The market related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight line basis into the market related value of assets over a five-year period.

119

Pension Plan Asset Allocations

Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a broad basket of investment grade securities. Emera’s target asset allocation is as follows:

Canadian Pension Plans

Asset Class	Target Range at Market
Short term securities		0	%	to	5	%
Fixed income		25	%	to	40	%
Equities:
Canadian		23	%	to	33	%
Non-Canadian (World)		32	%	to	42	%

Non-Canadian Pension Plans

Asset Class	Target Range at Market (weighted average)
Short term securities		4	%	to	10	%
Fixed income		22	%	to	36	%
Equities:
US		37	%	to	55	%
Non-US		17	%	to	27	%

For Bangor Hydro and MPS, the investment of the Non-Canadian pension assets is overseen by their management teams. For GBPC, the investment of Non-Canadian pension assets is overseen by GBPA.

The fair values of investments as at December 31, 2011, by asset category, are as follows:

millions of Canadian dollars	Level 1		%
Cash and cash equivalents		$17.3		2.4	%
Equity Securities:
Canadian equity		162.2		22.5	%
US equity		188.4		26.1	%
Other equity		89.6		12.4	%
Fixed income securities:
Canadian government		141.7		19.6	%
US government		12.5		1.7	%
Other government		0.7		0.1	%
Corporate debt		109.7		15.2	%
Real estate		0.3		-	%
Total		$722.4		100	%

120

The fair values of investments as at December 31, 2010, by asset category, are as follows:

millions of Canadian dollars	Level 1		%
Cash and cash equivalents		$9.9		1.4%
Equity Securities:
Canadian equity		192.7		26.5%
US equity		189.5		26.1%
Other equity		90.4		12.5%
Fixed income securities:
Canadian government		122.3		16.9%
US government		10.7		1.5%
Other government		0.6		0.1%
Corporate debt		107.6		14.9%
Real estate		0.5		0.1%
Total		$724.2		100%

Refer to Note 1(Y), “Summary of Significant Accounting Policies – Fair Value Measurement,” for more information on the fair value hierarchy and inputs used to measure fair value. All investments were deemed Level 1 for the years ended December 31, 2011 and 2010.

Investments in Emera or NSPI

As at December 31, 2011 and 2010, the pension funds do not hold any material investments in Emera Incorporated or NSPI securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities.

Canadian Post Retirement Benefit Plans

There are no assets set aside to pay for the Canadian post-retirement benefit plans. As is common in Canada, post-retirement health benefits are paid from general accounts on a pay as you go basis.

US Post Retirement Benefit Plans

Emera’s US subsidiaries currently provide certain post-retirement benefit health care and life insurance benefits for employees retiring after age 55 who meet eligibility requirements. Post-retirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify plans in whole or in part at any time.

Bangor Hydro and MPS provide retiree medical benefits to certain classes of employees. The Company’s retiree medical expenses are incorporated into rate filings with its regulators and are recovered through its electric rates to customers.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (MMA) added prescription drug coverage to Medicare, with a 28 percent tax free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. Emera’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit post-retirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.

The Company received subsidy payments under Part D for the 2009 and 2010 plan years. Its 2011 Part D subsidy application with the Centers for Medicare and Medicaid Services was approved in December 2010, and the company expects to receive payment later this year.

121

Emera’s target asset allocation for its US Post Retirement Benefits Plan is as follows:

Asset Class	Target Range at Market (weighted average)
Short term securities		10%	to	50%
Fixed income		0%	to	40%
Equities:
US		0%	to	60%
Non-US		0%	to	20%

The fair values of investments as at December 31, 2011, by asset category, are as follows:

millions of Canadian dollars	Level 1		%
Cash and cash equivalents		$1.1		32.4%
Equity Securities:
US equity		1.5		44.1%
Fixed income securities:
US government		0.8		23.5%
Total		$3.4		100%

The fair values of investments as at December 31, 2010, by asset category, are as follows:

millions of Canadian dollars	Level 1		%
Cash and cash equivalents		$1.1		32.4%
Equity Securities:
US equity		1.5		44.1%
Fixed income securities:
US government		0.8		23.5%
Total		$3.4		100%

Refer Note 1(Y), “Summary of Significant Accounting Policies – Fair Value Measurement,” for more information on the fair value hierarchy and inputs used to measure fair value. All investments were deemed Level 1 for the years ended December 31, 2011 and 2010.

Investments in Emera or NSPI

As at December 31, 2011 and 2010, the assets related to the post-retirement benefit plans do not hold any material investments in Emera Incorporated or NSPI securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities.

Cash Flows

The following table shows the expected cash flows for defined benefit pension and other post-retirement benefit plans:

millions of Canadian dollars	Defined benefit pension plans		Non-pension benefits plans
Expected Employer contributions:
2012		$73.7		$6.2
Expected Benefit Payments:
2012		53.2		6.2
2013		56.7		6.9
2014		60.3		7.3
2015		64.4		7.6
2016		68.8		8.0
2017 - 2021		416.9		48.5

122

Assumptions

The following table shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans:

	2011				2010
(weighted average assumptions)	Defined benefit pension plans		Non-pension benefits plans		Defined benefit pension plans		Non-pension benefits plans
Benefit obligation – December 31:
Discount rate		4.96%		4.80%		5.51%		5.55%
Rate of compensation increase		3.52%		3.50%		3.75%		3.75%
Health care trend - initial (next year)		-		6.40%		-		6.70%
- ultimate		-		4.40%		-		4.50%
- year ultimate reached		-		2014		-		2014
Benefit cost for year ended December 31:
Discount rate		5.51%		5.56%		6.46%		6.25%
Expected long-term return on plan assets		7.08%		-		7.31%		-
Rate of compensation increase		3.75%		3.75%		3.75%		3.75%
Health care trend - initial (current year)		-		6.90%		-		7.53%
- ultimate		-		4.55%		-		4.51%
- year ultimate reached		-		2014		-		2014

The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan.

Sensitivity Analysis for Non-Pension Benefits Plans

The health care cost trend significantly influences the amounts presented for health care plans. An increase or decrease of one percentage point of the assumed health care cost trend would have had the following impact in 2011:

millions of Canadian dollars	Increase		Decrease
Service cost and interest cost		$0.9		$(0.8)
Accumulated post-retirement benefit obligation, December 31		11.0		(9.0)

Amounts to be Amortized in the Next Fiscal Year

The following table shows the amounts from the AOCL which is expected to be recognized as part of the net periodic benefit cost in fiscal 2012:

millions of Canadian dollars	Defined benefit pension plans		Non-pension benefits plans
Actuarial (losses)		$(33.1)		$(2.4)
Past service gains		-		1.8
Total		$(33.1)		$(0.6)

Defined Contribution Plan

Emera also provides a defined contribution pension plan for certain employees. The Company’s contribution for 2011 was $6.3 million (2010 – $2.6 million).

123

27.    COMMITMENTS AND CONTINGENCIES

A.    Commitments

As at December 31, 2011, commitments (excluding pensions and other post-retirement benefits, long-term debt, and ARO) for each of the next five years and in aggregate thereafter consisted of the following:

millions of Canadian dollars	2012		2013		2014		2015		2016		Thereafter		Total
Purchased power (1)		$100.3		$113.4		$117.6		$117.8		$118.0		$1,273.7		$1,840.8
Coal, biomass, oil and natural gas supply		233.0		159.9		109.5		63.4		22.4		599.9		$1,188.1
Transportation (2)		72.5		29.3		26.8		16.5		2.2		2.7		$150.0
Long-term service agreements (3)		12.2		11.3		6.1		5.0		0.5		-		$35.1
Capital projects		56.3		3.5		0.6		3.9		-		13.9		$78.2
Leases (4)		3.9		3.3		3.2		3.1		2.8		16.0		$32.3
Other		5.2		3.8		3.6		3.6		1.0		1.0		$18.2
Total		$483.4		324.5		$267.4		$213.3		$146.9		$1,907.2		$3,342.7

(1) Purchased power: annual requirement to purchase 100 percent of electricity production from independent power producers over varying contract lengths up to 25 years.

(2) Transportation: purchasing commitments for transportation of solid fuel and transportation capacity on various pipelines.

(3) Long-term service agreements: outsourced management of the Company’s computer and communication infrastructure, vegetation management and maintenance of certain generating equipment.

(4) Leases: operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles.

B.    Legal Proceedings

A number of individuals who live in proximity to the Company’s Trenton generating station have filed a statement of claim for an unspecified amount against NSPI in respect of emissions from the operation of the plant for the period from 2001 forward. The plaintiffs claim unspecified damages as a result of interference with enjoyment of, or damage to, their property; and adverse health effects they allege were caused by such emissions. The Company has filed a defense to the claim. The outcome of this litigation, and therefore an estimate of any contingent loss, is not determinable.

On October 31, 2011, MF Global Holding Ltd., the parent company of MF Global Inc. (“MFG”), a futures commission merchant used by Emera Energy Services (“Emera Energy”) for natural gas and electricity futures filed for Chapter 11 bankruptcy. Emera Energy was able to transfer its open future positions to other brokers; however $5.46 million USD of its posted margin was frozen with MFG and Emera Energy was unable to transfer these funds. Legal proceedings related to the bankruptcy have been initiated and are expected to involve cross-border insolvency proceedings as a result of MFG’s global affiliates. Although management expects to recover the majority of the frozen funds, a provision has been recognized and the net amount has been reclassified to “Other long-term assets”. The outcome of the bankruptcy proceedings is currently not determinable.

In addition, Emera and its subsidiaries may, from time to time, be involved in legal proceedings, claims and litigations that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company.

C.    Environment

Emera’s activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore, and enhance the quality of the environment including air, water and solid waste. Emera’s environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations were $67.2 million during 2011 and are estimated to be $439.6 million from 2012 through 2015. Amounts that have been committed are included in “Capital projects” in the commitments included in note 27A. The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies may be enacted in response to issues such as climate change and other pollutant emissions.

124

NSPI

NSPI is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI.

Conformance with legislative and NSPI requirements are verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the 2011 and 2010 audits.

Climate Change and Air Emissions

Greenhouse Gas Emissions

NSPI has stabilized, and in recent years, reduced greenhouse gas emissions. This has been achieved by energy efficiency and conservation programs, increased use of natural gas and the addition of new renewable energy sources to the generation portfolio.

Greenhouse gas emissions from NSPI facilities have been capped beginning in 2010 through to 2020. The regulations allow for multi-year compliance periods recognizing the variability in electricity supply sources and demand. Over the decade, the caps will be achieved by a combination of additional renewable generation, import of non-emitting energy, and energy efficiency and conservation.

In 2011, Environment Canada announced proposed regulations for a new national carbon dioxide framework for the electricity sector in Canada. These proposed regulations would apply to new coal-fired electricity generation units; and existing coal-fired electricity generation units that have reached the end of their deemed economic life of forty-five years after commissioning. These proposed regulations will be effective July 1, 2015. Nova Scotia’s existing greenhouse gas regulations require reductions in NSPI’s emissions similar to those reflected in the federal framework. NSPI is engaged with federal and provincial agencies in reviewing the implications of this federal framework and its alignment with its current operating plans under existing Nova Scotia regulations.

Renewable Energy

The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix. The target date for 5 percent of electricity to be supplied from post-2001 sources of renewable energy, owned by independent power producers, was extended to 2011 from 2010. The target for 2013, which requires an additional 5 percent of renewable energy, is unchanged.

On May 19, 2011 the Nova Scotia Government approved The Electricity Act (Amended) to facilitate the eligibility of energy from the Lower Churchill Project in Labrador as a resource for meeting Nova Scotia’s renewable electricity targets. The amendment requires regulations to be developed that increase the percentage of renewable energy in the generation mix from the planned 25 percent in 2015, to 40 percent by 2020.

Mercury, Nitrogen Oxide and Sulphur Dioxide Emissions

NSPI completed a capital program to add sorbent injection to each of the seven pulverized fuel coal units in 2010 at a cost of $17.3 million. This was put in place to address planned reductions in mercury emissions limits, which are set out in the following table:

125

Year	Mercury Emissions Limit (kg)
2009		168
2010		110
2011 - 2012		100
2013		85
2014 - 2019		65
2020		35

Any mercury emission above 65 kg, between 2010 and 2013, must be offset by lower emissions in the 2014 to 2020 period.

NSPI completed its capital program of retrofitting low nitrogen oxide combustion firing systems on six of its seven pulverized fuel coal units in early 2009 at a cost of $23.3 million. NSPI now meets the nitrogen oxide emission cap of 21,365 tonnes per year established by the Nova Scotia Government effective 2010. These investments, combined with the purchasing of low sulfur coal, allows NSPI to meet the provincial air quality regulations.

NSPI will meet ever-reducing sulphur dioxide emission cap requirements through the use of a blend of net lower sulphur content solid fuel.

Compared to historical levels, NSPI will have reduced mercury emissions by 60 percent effective 2014, nitrogen oxide by 40 percent effective 2009 and sulphur dioxide by 50 percent effective 2010.

Poly Chlorinated Bi-Phenol Transformers

In response to the Canadian Environmental Protection Act 1999, 2008 Poly Chlorinated Bi-Phenol (“PCB”) Regulations to phase out electrical equipment and liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other electrical equipment on its system that do not meet the 2008 PCB Regulations Standard by 2014. In addition, there is a project to phase out the use of pole mount transformers before 2025 including a capital program to destroy all confirmed PCB contaminated pole mount transformers taken out of service through attrition. The combined total cost of these projects is estimated to be $36.5 million and, as at December 31, 2011 approximately $7.8 million (2010 - $5.4 million) has been spent to date. NSPI has recognized an ARO of $20.6 million as at December 31, 2011 (2010 - $13.9 million) associated with the PCB phase-out program.

Maine Utilities

Poly Chlorinated Bi-Phenol Transformers

In response to a Maine environmental regulation to phase out PCB transformers, the Maine Utilities implemented multi-year programs to eliminate transformers on their systems that did not meet the new State environmental guidelines. The Maine Utilities completed their programs in 2011. The cost of testing the transformers was expensed as incurred; replacement transformers and the cost to install those transformers were capitalized. As at December 31, 2011, all transformers have been remediated and are PCB-free in this effort; the total cumulative expenditures associated with the Maine Utilities’ programs at December 31, 2011 was $4.4 million (December 31, 2010 - $3.0 million).

The Barbados Light & Power Company Limited

BLPC implemented a Health Safety Environmental and Quality Management system in 2006 to assist in safeguarding the health and safety of its employees, contractors and customers while ensuring protection of the environment. The Company conducted an environmental impact assessment on its facilities and significant environmental aspects were identified and programs were developed.

126

D.    Principal Risks and Uncertainties

In this section, Emera describes some of the principal risks management believes could materially affect Emera’s business, revenues, operating income, net income, net asset or liquidity or capital resources. The nature of risk is such that no list can be comprehensive, and other risks may arise or risks not currently considered material may become material in the future.

Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach.

Acquisition Risk

The risks associated with Emera’s acquisition strategy include the availability of suitable acquisition candidates, obtaining the necessary regulatory approval for any acquisition and assimilating and integrating acquired companies into the Company. In addition, potential difficulties inherent in acquisitions may adversely affect the results of an acquisition. These include delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies from completed transactions.

Emera mitigates these risks by following systematic procedures for integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to close monitoring and review by the Board of Directors.

Regulatory Risk

The Company’s rate-regulated subsidiaries are subject to risk in the recovery of costs and investments in a timely manner. The Company manages this regulatory risk through transparent regulatory disclosure, ongoing stakeholder consultation and multi-party engagement on aspects such as utility operations, rate filings and capital plans.

Changes in Environmental Legislation

The Company is subject to regulation by federal, provincial, state, regional, and local authorities with regard to environmental matters primarily related to its utility operations. Changes to climate change and air emissions standards could adversely affect utility operations.

Emera is committed to operating in a manner that is respectful and protective of the environment, and in full compliance with legal requirements and Company policy. Emera and its wholly-owned subsidiaries have implemented this policy through development and application of environmental management systems.

Commodity Prices and Foreign Exchange Rate Fluctuations

A substantial amount of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. Fuel contracts may be exposed to broader global conditions which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts. In addition, the adoption and implementation of FAMs in certain subsidiaries has further helped manage this risk.

The Company enters into foreign exchange forward and swap contracts to limit exposure on foreign currency transactions such as fuel purchases and USD revenue streams.

127

Commercial Relationships

NSPI

For the year ended December 31, 2011, NSPI’s five largest customers contributed approximately 13.3 percent (2010 – 14.7 percent) of electric revenues. The loss of a large customer could have a material effect on NSPI’s operating revenues. NSPI works to mitigate this risk through the regulatory process.

NSPI’s largest customer was granted creditor protection under the Companies’ Creditors Arrangement Act (“CCAA”), and suspended operations in September 2011. This customer contributed approximately 6.0 percent (2010 – 7.9 percent) of NSPI’s electric revenues for the year ended December 31, 2011. NSPI is working to recover an outstanding balance of $11.6 million through the CCAA claims process, including a claim for set-off against amounts owing from NSPI to the customer that exceeds the amount receivable. The 2012 General Rate Decision, approved by the UARB, provides for any unrecovered non-fuel electric charges in 2012 related to this customer to be deferred and recovered beginning in 2013.

Brunswick Pipeline

Brunswick Pipeline has a 25 year firm service agreement with Repsol Energy Canada (“REC”). The pipeline was used solely in 2011 and 2010 to transport natural gas from the Canaport LNG terminal in Saint John, New Brunswick to the United States border for REC. The risk of non-payment is mitigated as Repsol YPF, S.A (“Repsol”), the parent company of REC, has provided Brunswick Pipeline with a guarantee for all RECs’ payment obligations under the firm service agreement. As at December 31, 2011 the net investment in direct financing lease with Repsol was $493.8 million. Repsol is rated investment grade BBB/Baa1; credit ratings and other company information are monitored on an ongoing basis. There is currently no allowance for credit losses related to this agreement.

Bayside Power

Bayside Power sells all of its power during the winter months, November through March, to NB Power in accordance with a long-term purchase power agreement (“PPA”). Revenue from this PPA contributed 46.5 percent (2010 – 48.0 percent) to Bayside Power’s electric revenues for the year ended December 31, 2011. The PPA expires March 31, 2021, with an option to renew for an additional five year term, provided both parties consent to the renewal.

Labour Risk

Certain Emera employees are subject to collective labour agreements. Approximately 55 percent of the full-time and term employees at NSPI, BLPC, GBPC, Bangor Hydro, EUS, and MPS are represented by local unions. Approximately 45 percent of the labour force is covered by collective labour agreements that will expire within the next twelve months. Emera seeks to manage this risk through ongoing discussions with local unions.

Weather Risk

Shifts in weather patterns affect electric sales volumes and associated revenues. Extreme weather events generally result in increased operating costs associated with restoring power to customers. Emera responds to significant weather event related outages according to each subsidiary’s respective Emergency Services Restoration Plan.

Interest Rate Risk

The Company utilizes a combination of fixed and variable rate debt financing for operations and capital expenditures resulting in an exposure to interest rate risk. The Company seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt.

128

E.    Collaborative Arrangement

Bangor Hydro

Through Bangor Hydro, the Company is a party to a collaborative arrangement with National Grid Transmission Services Corporation to develop the Northeast Energy Link (“NEL”) Project. The cost of development activities, including acquisition of land in the transmission corridor and acquisition of necessary governmental and regulatory permits and approvals, are shared equally between the Company and National Grid. Bangor Hydro has deferred $2.5 million USD of costs associated with the NEL project as at December 31, 2011 (2010 – $2.4 million USD), reported in the Consolidated Balance Sheets in “Other” as part of other assets.

F.    Guarantees and Letters of Credit

Emera had the following guarantees and letter of credits as at December 31, 2011:

• NSPI has provided a limited guarantee for the indebtedness of RESL. The guarantee is up to a maximum of $23.5 million. As at December 31, 2011, RESL’s indebtedness under the loan agreement was $21.9 million. NSPI holds a security interest in the present and future assets of RESL. For further information refer to Note 1Z.

• Emera has provided a guarantee to the Long Island Power Authority (“LIPA”) on behalf of Bear Swamp for Bear Swamp’s long-term energy and capacity supply agreement (“PPA”) with LIPA, which expires on April 30, 2021. The guarantee is for 50 percent of the relevant obligations under the PPA up to a maximum of $18.6 million USD. As at December 31, 2011, the fair value of the PPA is positive.

• Emera has provided a guarantee to the Bank of Nova Scotia on behalf of Bear Swamp for Bear Swamp’s interest rate swaps entered into between Bear Swamp and the Bank of Nova Scotia which expires on May 9, 2012. The guarantee is for 50 percent of the relevant obligations up to a maximum of $1.0 million USD. In the event Emera was required to make a payment to the Bank of Nova Scotia under this guarantee, the guarantee provides that Emera is able to seek recovery from Bear Swamp’s creditors after Bear Swamp has paid its debts in full. As at December 31, 2011, the fair value of that agreement is positive.

• At the request of Emera and its subsidiaries, a financial institution has issued standby letters of credit in the amount of $11.4 million for the benefit of third parties that have extended credit to Emera and its subsidiaries. These letters of credit typically have a one year term and are renewed annually as required.

• A financial institution has issued a standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2012 and is renewed annually. The amount committed as at December 31, 2011 was $22.5 million.

• A financial institution has issued a standby letter of credit to secure obligations under an unfunded pension plan in BHE. The letter of credit is renewed annually in October. The amount committed as at December 31, 2011 was $2.2 million USD.

• A financial institution has been issued direct pay letters of credit totaling $23.9 million USD to secure principal and interest payments related to Maine Public Utilities Financing Bank bonds issued on behalf of MPS, related to qualifying distribution assets.

No liability has been recognized in the consolidated balance sheets related to any potential obligation under these guarantees and letters of credits.

129

28.    COMMON STOCK

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

			2011				2010
Issued and outstanding:	Millions of shares		Millions of Canadian dollars		Millions of shares		Millions of Canadian dollars (adjusted)
Balance, January 1		114.62		$1,137.8		112.98		$1,097.9
Issuance of common stock		6.36		196.0		-		-
Issued for cash under Purchase Plans at market rate		1.40		42.8		1.32		34.4
Discount on shares purchased under Dividend Reinvestment Plan		-		(1.8)		-		(1.5)
Options exercised under senior management share option plan		0.45		8.8		0.32		6.0
Stock-based compensation		-		1.4		-		1.0
Balance, December 31		122.83		$1,385.0		114.62		$1,137.8

In March 2011, Emera issued 6,359,500 common shares, which included the exercise of the over-allotment option of 829,500 common shares. The shares were issued at $31.70 per share for net proceeds after-tax and issuance costs of $196.0 million.

As at December 31, 2011, there were 3.4 million (2010 – 3.8 million) common shares reserved for issuance under the senior management stock option plan, and 0.3 million (2010 – 0.5 million) common shares reserved for issuance under the employee common share purchase plan. The issuance of common shares under the current or proposed common share compensation arrangements will not exceed ten percent of Emera’s outstanding common shares.

29.    STOCK-BASED COMPENSATION

EMPLOYEE COMMON STOCK PURCHASE PLAN AND COMMON SHAREHOLDERS DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN (“Purchase Plans”)

The Company has an Employee Common Share Purchase Plan to which employees make cash contributions for the purpose of purchasing common shares. The Company also contributes to the plan a percentage of the employees’ contributions. The plan allows the reinvestment of dividends. The maximum aggregate number of common shares reserved for issuance under this plan is 2.0 million common shares.

The Company uses the fair value based method to measure the compensation expense related to its employee purchase plan. Compensation cost recognized for the year ended December 31, 2011 was $0.7 million (2010 – $0.7 million) and is included in “Operating, maintenance and general”.

The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”), which provides an opportunity for shareholders to reinvest dividends and to make cash contributions for the purpose of purchasing common shares. Effective September 25, 2009, Emera changed its Dividend Reinvestment Plan to provide for a discount of up to 5% from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends under the Plans.

STOCK-BASED COMPENSATION PLANS

Stock Option Plan

The Company has a stock option plan that grants options to senior management of the Company for a maximum term of ten years. The option price of the stock options is the closing market price of the stocks on the day before the option is granted. The maximum aggregate number of shares issuable under this plan is 6.7 million shares.

130

All options granted to date are exercisable on a graduated basis with up to 25 percent of options exercisable on the first anniversary date and in further 25 percent increments on each of the second, third and fourth anniversaries of the grant. If an option is not exercised within ten years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five percent of the issued and outstanding common stocks on the date the option is granted.

If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person due to retirement or termination for other than just cause, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the 24 months following the date the optionee retires, but in any case prior to the expiry of the option in accordance with its terms.

If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person due to employment termination for just cause, resignation or death, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the six months following the date the optionee is terminated, resigns, or dies, as applicable, but in any case prior to the expiry of the option in accordance with its terms.

The Company uses the fair value based method to measure the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. The fair value of stock option awards granted was estimated on the date of grant using a Black-Scholes valuation model. The expected term of the option awards is calculated based on historical exercise behavior and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the Bank of Canada seven-year government bond yields. The expected dividend yield incorporates current dividend rates as well as historical dividend increase patterns. Emera’s expected stock price volatility was estimated using its three-year historical volatility. The following table shows the weighted-average fair values per stock option along with the assumptions incorporated into the valuation models for options granted:

	2011		2010
Weighted average fair value per option		$19.96		$19.38
Expected term		7 years		7 years
Risk-free interest rate		3.88%		3.92%
Expected dividend yield		4.89%		4.91%
Expected volatility		14.32%		14.16%

A summary of stock option activity for the year ended December 31, 2011 and information related to outstanding and exercisable stock options as at December 31, 2011 is presented in the following table.

	Stock Options		Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Life (in years)		Aggregate Intrinsic Value (millions of Canadian dollars)
Outstanding as at December 31, 2010		2,146,078		$21.02		6.7		$22.2
Granted		217,300		32.06				0.2
Exercised		(448,725)		19.45				6.1
Forfeited		(83,256)		27.03				0.5
Outstanding as at December 31, 2011		1,831,397		$22.44		6.4		$19.4
Exercisable as at December 31, 2011		1,161,397		$20.57				$14.5

Compensation cost recognized for stock options for the year ended December 31, 2011 was $0.7 million (2010 – $0.7 million) and is included in “Operating, maintenance and general”.

As at December 31, 2011, the compensation cost related to unvested and outstanding stock options was $0.9 million and expected to be recognized over a weighted-average period of 3.3 years (2010 – $1.0 million, 3.3 years). Cash received from option exercises for the year ended December 31, 2011 was $8.7 million (2010 – $6.3 million). The total intrinsic value of options exercised for the year ended December 31, 2011 was $6.1 million (2010 – $4.1 million). The range of exercise prices for the options outstanding as at December 31, 2011 was $15.73 to $32.06 (2010 – $13.70 to $31.02).

131

Share Unit Plans

The Company has deferred share unit (“DSU”) and performance share unit (“PSU”) plans. The DSU and PSU liabilities are marked-to-market at the end of each period based on the common share price at the end of the period.

Deferred Share Unit Plan

Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares referred to as the Dividend Reinvestment Plan (“DRIP”), the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns, or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan.

Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50% of the value of their actual annual incentive award (25% in the first year of the program) will be payable in DSUs until the applicable guidelines are met.

When incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares, referred to as DRIP. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee (“MRCC”), payments may be made in the form of actual shares.

In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to recognize singular achievements or to achieve certain corporate objectives.

A summary of the activity related to employee and director DSU’s for the year ended December 31, 2011 is presented in the following table:

	Employee DSU		Weighted Average Grant Date Fair Value		Director DSU		Weighted Average Grant Date Fair Value
Outstanding as at December 31, 2010		338,322		$20.71		149,943		$23.19
Granted including DRIP		44,537		31.15		46,161		32.31
Exercised		(19,938)		22.27		-		-
Outstanding as at December 31, 2011		362,921		$21.91		196,104		$25.34

Compensation cost recognized for employee and director DSU for the year ended December 31, 2011 was $1.2 million (2010 – $3.6 million). Compensation cost capitalized for employee and director DSU for the year ended December 31, 2011 was $0.1 million (2010 – nil). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2011 were $0.4 million (2010 – $1.1 million).

132

Performance Share Unit Plan

Under the PSU plan, executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year overlapping performance cycles. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Dividend equivalents are awarded and are used to purchase additional PSUs, also referred to as DRIP. The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of retirement, disability or death.

A summary of the activity related to employee PSU’s for the year ended December 31, 2011 is presented in the following table:

	Employee PSU		Weighted Average Grant Date Fair Value
Outstanding as at December 31, 2010		362,261		$25.95
Granted including DRIP		140,340		31.18
Exercised		(136,345)		23.13
Forfeited		(11,798)		28.96
Outstanding as at December 31, 2011		354,458		$29.01

Compensation cost recognized for the PSU plan for the year ended December 31, 2011 was $3.7 million (2010 – $6.1 million). Compensation cost capitalized for employee PSU for the year ended December 31, 2011 was $0.2 million (2010 – nil). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2011 were $1.2 million (2010 – $1.9 million).

Non-Vested Stock-Based Compensation Plans

For the year ended December 31, 2011, a summary of activity from the different plans is presented in the following table:

					Share Unit Plan
	Stock Option Plan				DSU Plan				PSU Plan
	Number of options		Weighted Average Grant Date Fair Value		Number of share units		Weighted Average Grant Date Fair Value		Number of share units		Weighted Average Grant Date Fair Value
Non-vested shares as at December 31, 2010		889,528		$22.86		20,797		$21.70		225,916		$27.65
Granted		217,300		32.06		682		31.08		140,340		31.18
Vested		(353,572)		22.16		(10,767)		21.14		(125,496)		23.79
Forfeited		(83,256)		27.03		-		-		(11,798)		28.96
Non-vested shares as at December 31, 2011		670,000		$30.38		10,712		$22.85		228,962		$31.86

The total fair value of shares vested for all the plans was $60.6 million for the year ended December 31, 2011 (2010 – $58.3 million). The weighted-average grant date fair value of shares, granted for all the plans, for the year ended December 31, 2011 was $23.42 (2010 – $21.69).

133

Fully-Vested Stock-Based Compensation Plans

			Share Unit Plan
	Stock Option Plan		DSU Plan		PSU Plan
Outstanding
Number of options/share units		1,831,397		548,313		125,497
Weighted-average exercise price of options		$22.44		-		-
Aggregate intrinsic value/fair value of options/share units		$19,411,216		$18,116,262		$4,146,421
Weighted-average remaining contractual terms of option/share units		6.4 years		-		-
Currently Exercisable
Number of options/share units		1,161,397		-		-
Weighted-average exercise price of options		$20.57		-		-
Aggregate intrinsic value/fair value of options/share units		$14,487,594		-		-
Weighted-average remaining contractual terms of option/share units		5.1 years		-		-

30. CUMULATIVE PREFERRED STOCK

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

			2011				2010
Issued and outstanding:	Millions of shares		Millions of dollars		Millions of shares		Millions of dollars
Balance		6.0		$146.7		6.0		$146.7

In June 2010, Emera issued six million 4.40% Cumulative Five-Year Rate Reset First Preferred Stock, Series A (“First Preferred Stock, Series A”). The $150 million First Preferred Stock, Series A were issued at $25.00 per share for net after-tax and transaction costs proceeds of $146.7 million.

As the First Preferred Shares, Series A are neither redeemable at the option of the shareholder nor have a mandatory redemption date, they are classified as equity and the associated dividends will be deducted on the consolidated statements of earnings immediately before arriving at “Net earnings attributable to common shareholders” and will be shown on the consolidated statement of equity as a deduction from retained earnings.

The First Preferred Shares, Series A are entitled to receive fixed cumulative preferred cash dividends in the amount of $1.10 per share per annum for each year up to and including May 15, 2015. For each five-year period after this date, the holders of First Preferred Shares, Series A are entitled to receive reset fixed cumulative preferred cash dividends. The reset annual dividends per share will be determined by multiplying the $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 1.84 percent.

The holders of First Preferred Shares, Series A will have the right, at their option, to convert their shares into an equal number of Cumulative Floating Rate First Preferred Shares, Series B of the Company on August 15, 2015 and every five years thereafter.

The First Preferred Shares, Series B have the same characteristics as the Series A shares, with the exception of the calculation of the floating dividend rate for the Series B shares being the sum of the T-bill rate plus 1.84 percent.

The holders of the First Preferred Shares, Series B will have the right, at their option, to convert their shares into an equal number of Series A shares of the Company on August 15, 2020 and every five years thereafter.

On August 15, 2015 and August 15, 2020 respectively and on August 15 every five years thereafter, the Company has the right to redeem for cash the outstanding First Preferred Shares, Series A or B in whole or in part at a price of $25 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption.

134

The First Preferred Shares of each series rank on a parity with the First preferred Shares of every other series and are entitled to a preference over a the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares will be entitled to attend any meeting of shareholders of the Company and to vote at any such meeting.

31.    ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income (loss) as at December 31, 2011 and 2010 are as follows:

					2011						2010
millions of Canadian dollars	Opening Balance		Net Change		Ending Balance		Opening Balance		Net Change		Ending Balance
(Losses) gains on derivatives recognized as Cash Flow Hedges		$(2.2)		$(8.7)		$(10.9)		$(8.3)		$6.1		$(2.2)
Net change in unrecognized pension and post-retirement benefit costs		(394.5)		(122.9)		(517.4)		(281.1)		(113.4)		(394.5)
Unrealized loss on available-for-sale investments		(1.2)		(0.3)		(1.5)		(1.0)		(0.2)		(1.2)
Unrealized (loss) gain on translation of self-sustaining foreign operations		(166.3)		24.4		(141.9)		(135.8)		(30.5)		(166.3)
Accumulated Other Comprehensive Loss		$(564.2)		$(107.5)		$(671.7)		$(426.2)		$(138.0)		$(564.2)

32.    NON-CONTROLLING INTEREST IN SUBSIDIARIES

Non-controlling interest in subsidiaries as at December 31 consisted of the following:

millions of Canadian dollars	2011		2010
Preferred shares of NSPI	$	132.2	$	132.2
Preferred shares of Bangor Hydro		0.4		0.5
BLPC		60.6		-
ICDU		31.3		21.7
	$	224.5	$	154.4

Preferred shares of NSPI:

Authorized:

Unlimited number of First Preferred shares, issuable in series.

Unlimited number of Second Preferred shares, issuable in series.

			2011				2010
Issued and outstanding:	Millions of shares		Millions of dollars		Millions of shares		Millions of dollars
Balance		5.4		$132.2		5.4		$132.2

Series D First Preferred Stock:

On and after October 15, 2015, Series D First Preferred Stock is redeemable by NSPI, in whole at any time or in part from time to time at $25 per share plus accrued and unpaid dividends. NSPI also has the option, commencing October 15, 2015, to exchange the Series D First Preferred Stock into Emera common stock determined by dividing $25 by the greater of $2 and the market price of the Emera common stock.

135

Commencing on and after January 15, 2016, with prior notice and prior to any dividend payment date, each Series D First Preferred Stock will be exchangeable at the option of the holder into fully paid and freely tradable Emera common stock determined by dividing $25 by the greater of $2 and the market price of the Emera common stock, subject to the right of NSPI to redeem such stock for cash or to cause the holders of such stock to sell on the exchange date all or any part of such stock to substitute purchasers found by NSPI. NSPI will pay all accrued and unpaid dividends to the exchange date.

Each Series D First Preferred Stock is entitled to a $1.475 per share per annum fixed cumulative preferential dividend, as and when declared by the Board of Directors, accruing from the date of issue and payable quarterly on the fifteenth day of January, April, July and October of each year.

The First Preferred Shares of each series rank on a parity with the First preferred Shares of every other series issued by NSPI and are entitled to a preference over NSPI’s Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of NSPI in the liquidation, dissolution or wind-up, whether voluntary or involuntary.

In the event NSPI fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of NSPI’s First Preferred Shares will be entitled to attend any meeting of shareholders of NSPI and to vote at any such meeting.

33.    RELATED PARTY TRANSACTIONS

In the ordinary course of business, Emera purchased natural gas transportation capacity from M&NP, an investment under significant influence of the Company, totaling $47.3 million (2010 – $55.1 million) for the year ended December 31, 2011. The amount is recognized in “Regulated fuel for generation and purchased power” or netted against energy marketing margin in “Non-regulated operating revenues” and is measured at the exchange amount. As at December 31, 2011, the amount payable to the related party was $3.3 million (2010 – $3.9 million), and is under normal interest and credit terms.

34.    QUARTERLY DATA (UNAUDITED)

For the quarter ended   millions of Canadian dollars   (except per share amounts)	Q4 2011		Q3 2011		Q2 2011		Q1 2011		Q4 2010		Q3 2010		Q2 2010		Q1 2010
Total operating revenues		$512.0		$496.1		$501.7		$554.6		$408.9		$394.0		$364.7		$438.5
Net income		49.4		48.3		34.2		127.5		23.6		45.4		50.7		79.6
Net income attributable to common shareholders		46.8		40.8		29.9		123.6		24.1		40.3		48.5		77.8
Earnings Per Share - basic		$0.38		$0.33		$0.24		$1.06		$0.21		$0.35		$0.43		$0.68
Earnings Per Share - diluted		$0.38		$0.33		$0.24		$1.03		$0.21		$0.35		$0.42		$0.67
Dividends per common share declared		-		$0.6625		$0.3250		$0.3250		-		$0.6075		$0.2825		$0.2725

136

35.    USGAAP TRANSITION

ADOPTION OF USGAAP

In February 2008, the Canadian Institute of Chartered Accountants (“CICA”) announced that CGAAP for publically accountable enterprises would be replaced by IFRS for fiscal years beginning on or after January 1, 2011. In Q4 2009, due primarily to the continued uncertainty around the applicability of a rate-regulated accounting standard under IFRS, management reviewed the option of adopting USGAAP instead of IFRS. During Q1 2010, the Company’s Board of Directors approved the transition to USGAAP as recommended by management. The adoption of USGAAP has been made on a retrospective basis with restatement of prior periods’ financial statements to reflect USGAAP requirements in effect at that time.

For annual reporting purposes, the transition date to USGAAP is January 1, 2010, which is the commencement of the 2010 comparative period to the Company’s 2011 financial statements.

As a result of NSPI’s decision to transition to USGAAP, effective January 1, 2011 there was an amendment to NSPI’s regulated accounting policy for financial instruments and hedges which was approved by the UARB. The effects of this amendment were applied retrospectively, in accordance with that policy, without restatement of prior period income. The adjustments related to the amended accounting policy have been included with the adjustments as described further in this note.

Measurement, classification and disclosure differences arising out of the Company’s election to adopt USGAAP are presented below. With respect to measurement and classification differences, Section I “USGAAP differences”, presents quantitative reconciliations of balance sheets, income statements and statements of cash flows, previously presented in accordance with CGAAP, to the respective amounts and classifications under USGAAP, together with descriptions of the various significant measurement and classification differences arising from the adoption of USGAAP. Balance sheet reconciliations are presented as at January 1, 2010 and December 31, 2010, representing the commencement and ending dates of the comparative financial year to 2011. Income statement and statement of cash flow reconciliations are presented for the three, six and nine months ended March 31, 2010, June 30, 2010, and September 30, 2010, respectively and for the year ended December 31, 2010, which are periods that will be presented as comparatives to 2011 financial reporting.

In addition, USGAAP requires certain disclosures of financial information, significant to the Company, that are in addition to the required disclosure under CGAAP.

Except as otherwise disclosed in this note, the change in basis of accounting from CGAAP to USGAAP did not materially impact accounting policies or disclosures. Reference should be made to the previously filed CGAAP financial statements as at and for the year ended December 31, 2010 for additional information on CGAAP accounting policies and practices.

The following table summarizes the increases (decreases) to total assets:

As at   millions of Canadian dollars	Notes		January 1 2010		December 31 2010
Total assets – CGAAP				$5,277.5		$6,321.8
Accounting for joint ventures		A		(76.4)		(75.4)
Offsetting		B		(0.9)		-
Income taxes		C		17.2		(136.4)
Hedging		F		99.1		42.3
Issue costs		G		16.4		18.9
Business combinations		J		(0.2)		7.7
Pension and other post-retirement benefits		K		(85.1)		(100.4)
Other				(0.3)		0.5
Total transition adjustments				(30.2)		(242.8)
Total assets – USGAAP				$5,247.3		$6,079.0

137

The following table summarizes the increases (decreases) to total liabilities:

As at   millions of Canadian dollars	Notes		January 1 2010		December 31 2010
Total liabilities – CGAAP				$3,739.5		$4,527.5
Accounting for joint ventures		A		(76.5)		(75.9)
Offsetting		B		(0.9)		-
Income taxes		C		17.0		(131.2)
Hedging		F		51.9		49.8
Issue costs		G		17.5		20.0
Pension and other post-retirement benefits		K		199.3		291.8
Preferred stock of NSPI		P		(134.0)		(134.1)
Other				(0.3)		(0.3)
Total transition adjustments				74.0		20.1
Total liabilities – USGAAP				$3,813.5		$4,547.6

The following table summarizes the increases (decreases) to net income:

For the   millions of Canadian dollars	3 months ended March 31 2010 (unaudited)		6 months ended June 30 2010 (unaudited)		9 months ended September 30 2010 (unaudited)		Year ended December 31 2010
Net income attributable to common shareholders – CGAAP		$77.1		$106.7		$151.5		$191.1
Note C – Income taxes		1.2		1.0		(3.9)		(5.0)
Note F – Hedging		(0.7)		(4.9)		(5.4)		(6.0)
Note J – Business combinations		-		22.5		22.3		8.4
Note K – Pension and other post-retirement benefits		0.6		1.1		1.7		2.3
Note P – Preferred stock of NSPI		-		0.1		0.1		0.1
Note R – Stock-based compensation		(0.1)		(0.1)		(0.2)		(0.2)
Note S – Foreign currency translation		(0.4)		(0.4)		(0.1)		(0.3)
Other		0.1		0.3		0.6		0.3
Total transition adjustments		0.7		19.6		15.1		(0.4)
Net income attributable to common shareholders – USGAAP		$77.8		$126.3		$166.6		$190.7
Earnings per common share – basic – CGAAP		$0.68		$0.94		$1.33		$1.68
Effect of USGAAP transition		-		0.17		0.13		(0.01)
Earnings per common share – basic – USGAAP		$0.68		$1.11		$1.46		$1.67

138

USGAAP differences

The reconciliations of the January 1, 2010 and December 31, 2010 Balance Sheets from CGAAP to USGAAP are as follows:

As at January 1, 2010   millions of Canadian dollars	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Assets
Current assets
Cash and cash equivalents		A		$21.8		$(1.6)		$20.2
Restricted cash		A		1.0		(1.0)		-
Receivables, net		A, B		413.1		(4.8)		408.3
Income taxes receivable				4.0		-		4.0
Inventory				174.5		-		174.5
Deferred income taxes		C		46.7		(23.6)		23.1
Derivatives in a valid hedging relationship		D		26.3		(26.3)		-
Held-for-trading derivatives		D		13.1		(13.1)		-
Derivative instruments		D		-		39.3		39.3
Regulatory assets		E, F		-		131.7		131.7
Prepaid expenses		A		7.4		(0.2)		7.2
Other current assets		G, H		-		3.2		3.2
Total current assets				707.9		103.6		811.5
Property, plant and equipment		A, C, I, J		2,933.7		170.5		3,104.2
Construction work-in-progress		I		220.2		(220.2)		-
				3,153.9		(49.7)		3,104.2
Other assets
Deferred income taxes		C		4.4		61.8		66.2
Derivatives in a valid hedging relationship		D		30.9		(30.9)		-
Held-for-trading derivatives		D		30.7		(30.7)		-
Derivative instruments		A, D		-		45.4		45.4
Regulatory assets		C, E, F, J, K		-		278.8		278.8
Net investment in direct financing lease		F		476.9		3.2		480.1
Investments subject to significant influence		A		218.4		(2.1)		216.3
Available-for-sale investment		M		47.3		(46.3)		1.0
Goodwill				87.6		-		87.6
Intangibles		L		92.1		(92.1)		-
Other		A, C, E, G, H, K, L, M		427.4		(271.2)		156.2
Total other assets				1,415.7		(84.1)		1,331.6
Total assets				$5,277.5		$(30.2)		$5,247.3

139

As at January 1, 2010   millions of Canadian dollars	Notes		CGAAP		Effect of transition to USGAAP			USGAAP
Liabilities and Equity
Current liabilities
Short-term debt				$300.3		-			$300.3
Current portion of long-term debt		A		108.1		(1.6)			106.5
Accounts payable		A, B, N		-		218.3			218.3
Accounts payable and accrued charges		N		305.9		(305.9)			-
Income taxes payable		C		2.3		1.2			3.5
Dividends payable		O		1.7		(1.7)			-
Derivatives in a valid hedging relationship		D		61.0		(61.0)			-
Held-for-trading derivatives		D		18.6		(18.6)			-
Derivative instruments		A, D		-		78.2			78.2
Regulatory liabilities		C, E, F		-		50.0			50.0
Pension and post-retirement liabilities		K		-		9.2			9.2
Other current liabilities		C, H, N, O, P		-		91.7			91.7
Total current liabilities				797.9		59.8			857.7
Long-term liabilities
Long-term debt		A, G, P		2,318.4		(45.7)			2,272.7
Deferred income taxes		C, K		194.1		(67.9)			126.2
Derivatives in a valid hedging relationship		D		25.7		(25.7)			-
Held-for-trading derivatives		D		15.8		(15.8)			-
Derivative instruments		A, D		-		35.5			35.5
Regulatory liabilities		C, E, F		-		91.5			91.5
Asset retirement obligations				104.5		-			104.5
Pension and post-retirement liabilities		K		-		292.4			292.4
Other long-term liabilities		A, E, H, K		148.1		(115.1)			33.0
Preferred shares issued by a subsidiary		P		135.0		(135.0	)		-
Total long-term liabilities				2,941.6		14.2			2,955.8
Non-controlling interest		Q		32.1		(32.1)			-
Equity
Common stock		R		1,096.7		1.2			1,097.9
Contributed surplus		R		3.6		(0.6)			3.0
Accumulated other comprehensive loss		A, C, F, K, S		(186.7)		(239.5)			(426.2)
Retained earnings		F, G, J, K, P, R, S		592.3		2.5			594.8
Total Emera Incorporated equity				1,505.9		(236.4)			1,269.5
Non-controlling interest in subsidiaries		P, Q		-		164.3			164.3
Total equity				1,505.9		(72.1	)		1,433.8
Total liabilities and equity				$5,277.5		$(30.2)			$5,247.3

140

As at December 31, 2010   millions of Canadian dollars	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Assets
Current assets
Cash and cash equivalents		A		$9.4		$(2.1)		$7.3
Restricted cash		A		59.6		(1.0)		58.6
Receivables, net		A		396.5		(3.6)		392.9
Income taxes receivable		C		43.4		(6.4)		37.0
Inventory				177.8		-		177.8
Deferred income taxes		C		28.2		(14.5)		13.7
Derivatives in a valid hedging relationship		D		28.4		(28.4)		-
Held-for-trading derivatives		D		22.1		(22.1)		-
Derivative instruments		A, D		-		49.7		49.7
Regulatory assets		E, F		-		90.5		90.5
Prepaid expenses		A		9.8		(0.3)		9.5
Other current assets		G, H		-		3.1		3.1
Total current assets				775.2		64.9		840.1
Property, plant and equipment		A, C, I, J		3,456.1		286.5		3,742.6
Construction work-in-progress		I		333.0		(333.0)		-
				3,789.1		(46.5)		3,742.6
Other assets
Deferred income taxes		C		12.9		18.2		31.1
Derivatives in a valid hedging relationship		D		26.1		(26.1)		-
Held-for-trading derivatives		D		15.3		(15.3)		-
Derivative instruments		A, D		-		36.0		36.0
Regulatory assets		C, E, F, K		-		354.9		354.9
Net investment in direct financing lease		F		488.2		3.3		491.5
Investments subject to significant influence		A, C, J		238.9		7.1		246.0
Available-for-sale investment		M		47.0		(46.2)		0.8
Goodwill		J, K		178.9		(11.5)		167.4
Intangibles		L		98.1		(98.1)		-
Other		A, C, E, G, H, J, K, L, M		652.1		(483.5)		168.6
Total other assets				1,757.5		(261.2)		1,496.3
Total assets				$6,321.8		$(242.8)		$6,079.0

141

As at December 31, 2010   millions of Canadian dollars	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Liabilities and Equity
Current liabilities
Short-term debt		G		$81.3		$0.4		$81.7
Current portion of long-term debt		A		12.7		(2.1)		10.6
Accounts payable		A, N		-		293.9		293.9
Accounts payable and accrued charges		N		399.6		(399.6)		-
Income taxes payable		C		1.1		(0.9)		0.2
Deferred income taxes		C		-		8.5		8.5
Dividends payable		O		1.8		(1.8)		-
Derivatives in a valid hedging relationship		D		8.6		(8.6)		-
Held-for-trading derivatives		D		31.1		(31.1)		-
Derivative instruments		A, D		-		36.8		36.8
Regulatory liabilities		C, E, F		-		55.0		55.0
Pension and post-retirement liabilities		K		-		8.9		8.9
Other current liabilities		A, C, H, N, O, P		-		110.3		110.3
Total current liabilities				536.2		69.7		605.9
Long-term liabilities
Long-term debt		A, G, P		3,153.7		(38.4)		3,115.3
Deferred income taxes		C, K		359.8		(191.3)		168.5
Derivatives in a valid hedging relationship		D		21.3		(21.3)		-
Held-for-trading derivatives		D		18.0		(18.0)		-
Derivative instruments		A, D		-		28.9		28.9
Regulatory liabilities		C, E, F		-		65.2		65.2
Asset retirement obligations				141.8		-		141.8
Pension and post-retirement liabilities		K		-		400.0		400.0
Other long-term liabilities		E, H, K		161.7		(139.7)		22.0
Preferred shares issued by a subsidiary		P		135.0		(135.0)		-
Total long-term liabilities				3,991.3		(49.6)		3,941.7
Non-controlling interest		Q		20.7		(20.7)		-
Equity
Common stock		R		1,136.5		1.3		1,137.8
Preferred stock				146.7		-		146.7
Contributed surplus		R		3.7		(0.5)		3.2
Accumulated other comprehensive loss		A, C, F, J, K, Q, S		(164.7)		(399.5)		(564.2)
Retained earnings		C, F, G, J, K, P, R, S		651.4		2.1		653.5
Total Emera Incorporated equity				1,773.6		(396.6)		1,377.0
Non-controlling interest in subsidiaries		P, Q		-		154.4		154.4
Total equity				1,773.6		(242.2)		1,531.4
Total liabilities and equity				$6,321.8		$(242.8)		$6,079.0

142

The adjustments to January 1, 2010 and December 31, 2010 equity are as follows:

As at January 1, 2010   millions of Canadian   dollars	Common Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss)		Retained Earnings		Non-controlling Interest in Subsidiaries		Total Equity
CGAAP		$1,096.7		$3.6		$(186.7)		$592.3		-		$1,505.9
Note A – Accounting for joint ventures		-		-		0.1		-		-		0.1
Note C – Income taxes		-		-		0.2		-		-		0.2
Note F – Hedging		-		-		36.6		10.6		-		47.2
Note G – Issue costs		-		-		-		(1.1)		-		(1.1)
Note J – Business combinations		-		-		-		(0.2)		-		(0.2)
Note K – Pension and other post-retirement benefits		-		-		(277.6)		(6.8)		-		(284.4)
Note P – Preferred stock of NSPI		-		-		-		1.8		$132.2		134.0
Note Q – Non-controlling interest in subsidiaries		-		-		-		-		32.1		32.1
Note R – Stock-based compensation		1.2		(0.6)		-		(0.6)		-		-
Note S – Foreign currency translation		-		-		1.2		(1.2)		-		-
Total transition adjustments		1.2		(0.6)		(239.5)		2.5		164.3		(72.1)
USGAAP		$1,097.9		$3.0		$(426.2)		$594.8		$164.3		$1,433.8

As at December 31, 2010   millions of Canadian   dollars	Common Stock		Preferred Stock		Contributed Surplus		Accumulated Other Comprehensive Income (Loss)		Retained Earnings		Non- controlling Interest in Subsidiaries		Total Equity
CGAAP		$1,136.5		$146.7		$3.7		$(164.7)		$651.4		-		$1,773.6
Note A – Accounting for joint ventures		-		-		-		0.5		-		-		0.5
Note C – Income taxes		-		-		-		0.2		(5.4)		-		(5.2)
Note F – Hedging		-		-		-		(12.1)		4.6		-		(7.5)
Note G – Issue costs		-		-		-		-		(1.1)		-		(1.1)
Note J – Business combinations		-		-		-		(0.5)		8.2		-		7.7
Note K – Pension and other post-retirement benefits		-		-		-		(387.9)		(4.3)		-		(392.2)
Note P – Preferred stock of NSPI		-		-		-		-		1.9		$132.2		134.1
Note Q – Non-controlling interest in subsidiaries		-		-		-		(1.5)		-		22.2		20.7
Note R – Stock-based compensation		1.3		-		(0.5)		-		(0.8)		-		-
Note S – Foreign currency translation		-		-		-		1.6		(1.6)		-		-
Other		-		-		-		0.2		0.6		-		0.8
Total transition adjustments		1.3		-		(0.5)		(399.5)		2.1		154.4		(242.2)
USGAAP		$1,137.8		$146.7		$3.2		$(564.2)		$653.5		$154.4		$1,531.4

143

The statements of income for the 2010 periods reconciled from CGAAP to USGAAP are as follows:

For the three months ended March 31, 2010   millions of Canadian dollars   (except per share amounts) (Unaudited)	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Operating revenues
Electric		T		$412.1		$(412.1)		-
Finance income from direct finance lease		T		14.2		(14.2)		-
Other		T		3.8		(3.8)		-
Regulated		F, T, U		-		395.4		$395.4
Non-regulated		A, T, U		-		43.1		43.1
Total operating revenues				430.1		8.4		438.5
Operating expenses
Regulated fuel for generation and purchased power		U, V		217.7		(23.7)		194.0
Regulated fuel adjustment				(39.4)		-		(39.4)
Non-regulated fuel for generation and purchase power		A, V		-		23.1		23.1
Non-regulated direct costs		U		-		8.2		8.2
Operating, maintenance and general		A, K, R, U		76.7		0.8		77.5
Provincial, state and municipal taxes		A		12.4		(0.4)		12.0
Depreciation and amortization		A, C, X		42.3		5.0		47.3
Regulatory amortization		X		5.4		(5.4)		-
Total operating expenses				315.1		7.6		322.7
Income from operations				115.0		0.8		115.8
Income from equity investments		A		2.3		(1.6)		0.7
Other income (expenses), net		A, F, S, T, U, W, Y		-		(1.8)		(1.8)
Financing charges		P, W, Y		43.2		(43.2)		-
Interest expense, net		A, C, U, W, Y		-		37.6		37.6
Income before provision for income taxes				74.1		3.0		77.1
Income tax expense (recovery)		A, C		(2.8)		0.3		(2.5)
Net income				76.9		2.7		79.6
Non-controlling interest in subsidiaries		P		(0.2)		2.0		1.8
Net income attributable to common shareholders				$77.1		$0.7		$77.8
Weighted average number of shares (in millions)
Basic				113.2		0.4		113.6
Diluted				120.0		-		120.0
Earnings per common share
Basic				$0.68		-		$0.68
Diluted				$0.66		$0.01		$0.67
Dividends per common share declared				$0.2725		-		$0.2725

144

For the six months ended June 30, 2010   millions of Canadian dollars   (except per share amounts) (Unaudited)	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Operating revenues
Electric		T		$739.7		$(739.7)		-
Finance income from direct finance lease		T		29.0		(29.0)		-
Other		T		18.8		(18.8)		-
Regulated		F, T, U		-		721.0		$721.0
Non-regulated		A, T, U		-		82.2		82.2
Total operating revenues				787.5		15.7		803.2
Operating expenses
Regulated fuel for generation and purchased power		U, V		375.0		(45.4)		329.6
Regulated fuel adjustment				(52.0)		-		(52.0)
Non-regulated fuel for generation and purchase power		A, V		-		43.9		43.9
Non-regulated direct costs		U		-		23.5		23.5
Operating, maintenance and general		A, K, R, U, W		158.0		2.3		160.3
Provincial, state and municipal taxes		A		24.5		(0.8)		23.7
Depreciation and amortization		A, C, X		85.4		10.2		95.6
Regulatory amortization		X		10.9		(10.9)		-
Total operating expenses				601.8		22.8		624.6
Income from operations				185.7		(7.1)		178.6
Income from equity investments		A, C		6.2		1.7		7.9
Other income (expenses), net		F, J, S, T, U, W, Y		-		17.7		17.7
Financing charges		P, W, Y		84.3		(84.3)		-
Interest expense, net		A, C, P, U, W, Y		-		75.4		75.4
Income before provision for income taxes				107.6		21.2		128.8
Income tax expense (recovery)		A, C		0.9		(2.4)		(1.5)
Net income				106.7		23.6		130.3
Non-controlling interest in subsidiaries		P		-		4.0		4.0
Net income attributable to common shares				$106.7		$19.6		$126.3
Weighted average number of shares (in millions)
Basic				113.3		0.4		113.7
Diluted				120.2		(0.1)		120.1
Earnings per common share
Basic				$0.94		$0.17		$1.11
Diluted				$0.92		$0.16		$1.08
Dividends per common share declared				$0.5550		-		$0.5550

145

For the nine months ended September 30, 2010   millions of Canadian dollars   (except per share amounts) (Unaudited)	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Operating revenues
Electric		T		$1,074.0		$(1,074.0)		-
Finance income from direct finance lease		T		42.8		(42.8)		-
Other		T		44.2		(44.2)		-
Regulated		F, T, U		-		1,053.9		$1,053.9
Non-regulated		A, T, U		-		143.3		143.3
Total operating revenues				1,161.0		36.2		1,197.2
Operating expenses
Regulated fuel for generation and purchased power		U, V		541.9		(65.1)		476.8
Regulated fuel adjustment				(75.0)		-		(75.0)
Non-regulated fuel for generation and purchase power		A, V		-		64.5		64.5
Non-regulated direct costs		U		-		46.1		46.1
Operating, maintenance and general		A, K, R, U, W		244.1		3.4		247.5
Provincial, state and municipal taxes		A		36.8		(1.3)		35.5
Depreciation and amortization		A, C, X		127.9		15.8		143.7
Regulatory amortization		X		16.7		(16.7)		-
Total operating expenses				892.4		46.7		939.1
Income from operations				268.6		(10.5)		258.1
Income from equity investments		A, C		11.3		2.3		13.6
Other income (expenses), net		F, J, S, T, U, W, Y		-		18.0		18.0
Financing charges		P, W, Y		124.6		(124.6)		-
Interest expense, net		A, C, P, U, W, Y		-		111.5		111.5
Income before provision for income taxes				155.3		22.9		178.2
Income tax expense (recovery)		A, C		0.6		1.9		2.5
Net income				154.7		21.0		175.7
Non-controlling interest in subsidiaries		P		0.1		6.0		6.1
Net income of Emera Incorporated				154.6		15.0		169.6
Preferred stock dividends		C		3.1		(0.1)		3.0
Net income attributable to common shareholders				$151.5		$15.1		$166.6
Weighted average number of shares (in millions)
Basic				113.5		0.5		114.0
Diluted				120.2		0.1		120.3
Earnings per common share
Basic				$1.33		$0.13		$1.46
Diluted				$1.31		$0.12		$1.43
Dividends per common share declared				$1.1625		-		$1.1625

146

For the year ended December 31, 2010   millions of Canadian dollars   (except per share amounts)	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Operating revenues
Electric		T		$1,436.1		$(1,436.1)		-
Finance income from direct finance lease		T		56.5		(56.5)		-
Other		T		61.1		(61.1)		-
Regulated		F, T, U		-		1,411.6		$1,411.6
Non-regulated		A, T, U		-		194.5		194.5
Total operating revenues				1,553.7		52.4		1,606.1
Operating expenses
Regulated fuel for generation and purchased power		U, V		718.7		(84.1)		634.6
Regulated fuel adjustment				(99.0)		-		(99.0)
Non-regulated fuel for generation and purchase power		A, V		-		83.9		83.9
Non-regulated direct costs		U		-		62.3		62.3
Operating, maintenance and general		A, J, K, R, U, W		336.1		15.1		351.2
Provincial, state and municipal taxes		A		49.1		(1.7)		47.4
Depreciation and amortization		A, C, X		173.6		39.9		213.5
Regulatory amortization		X		41.3		(41.3)		-
Total operating expenses				1,219.8		74.1		1,293.9
Income from operations				333.9		(21.7)		312.2
Income from equity investments		A, C		13.6		1.7		15.3
Other income (expenses), net		F, J, S, T, U, W, Y		-		12.5		12.5
Financing charges		P, W, Y		168.4		(168.4)		-
Interest expense, net		A, C, P, U, W, Y		-		148.8		148.8
Income before provision for income taxes				179.1		12.1		191.2
Income tax expense (recovery)		A, C		(12.8)		4.7		(8.1)
Net income				191.9		7.4		199.3
Non-controlling interest in subsidiaries		P		(2.3)		7.9		5.6
Net income of Emera Incorporated				194.2		(0.5)		193.7
Preferred stock dividends		C		3.1		(0.1)		3.0
Net income attributable to common shareholders				$191.1		$(0.4)		$190.7
Weighted average number of shares (in millions)
Basic				113.7		0.5		114.2
Diluted				120.3		0.1		120.4
Earnings per common share
Basic				$1.68		$(0.1)		$1.67
Diluted				$1.65		-		$1.65
Dividends per common share declared				$1.1625		-		$1.1625

147

The consolidated statements of cash flows for the 2010 periods reconciled from CGAAP to USGAAP are as follows:

For the three months ended March 31, 2010   millions of Canadian dollars (Unaudited)	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Net cash used in operating activities		A, P, R, Y		$(5.7)		$3.1		$(2.6)
Net cash used in investing activities		A, Y		(66.7)		(1.6)		(68.3)
Net cash provided by financing activities		P, R		62.3		(2.1)		60.2
Effect of exchange rate changes on cash and cash equivalents				(0.2)		0.6		0.4
Net decrease in cash and cash equivalents				(10.3)		-		(10.3)
Cash and cash equivalents, beginning of period		A		21.8		(1.6)		20.2
Cash and cash equivalents, end of period		A		$11.5		$(1.6)		$9.9
For the six months ended June 30, 2010   millions of Canadian dollars (Unaudited)	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Net cash provided by operating activities		A, P, R, Y		$105.1		$4.9		$110.0
Net cash used in investing activities		A, Y		(298.2)		(3.9)		(302.1)
Net cash provided by financing activities		A, P, R		220.0		(3.2)		216.8
Effect of exchange rate changes on cash and cash equivalents				0.5		(0.3)		0.2
Net increase (decrease) in cash and cash equivalents				27.4		(2.5)		24.9
Cash and cash equivalents, beginning of period		A		21.8		(1.6)		20.2
Cash and cash equivalents, end of period		A		$49.2		$(4.1)		$45.1
For the nine months ended September 30, 2010   millions of Canadian dollars (Unaudited)	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Net cash provided by operating activities		A, P, R, Y		$230.9		$7.1		$238.0
Net cash used in investing activities		A, Y		(452.0)		(6.4)		(458.4)
Net cash provided by financing activities		A, P, R		247.2		(3.7)		243.5
Effect of exchange rate changes on cash and cash equivalents				(0.4)		0.6		0.2
Net increase (decrease) in cash and cash equivalents				25.7		(2.4)		23.3
Cash and cash equivalents, beginning of period		A		21.8		(1.6)		20.2
Cash and cash equivalents, end of period		A		$47.5		$(4.0)		$43.5
For the year ended December 31, 2010   millions of Canadian dollars	Notes		CGAAP		Effect of transition to USGAAP		USGAAP
Net cash provided by operating activities		A, C, P, R, Y, J		$416.4		$2.8		$419.2
Net cash used in investing activities		A, C, Y, J		(894.8)		8.8		(886.0)
Net cash provided by financing activities		A, P, R		466.2		(11.6)		454.6
Effect of exchange rate changes on cash and cash equivalents				(0.2)		(0.5)		(0.7)
Net decrease in cash and cash equivalents				(12.4)		(0.5)		(12.9)
Cash and cash equivalents, beginning of period		A		21.8		(1.6)		20.2
Cash and cash equivalents, end of period		A		$9.4		$(2.1)		$7.3

148

NOTES TO THE TRANSITIONAL ADJUSTMENTS

Under USGAAP, the Company is (i) measuring certain assets, liabilities, revenues and expenses differently than it had been under CGAAP (see details on each measurement change below); and (ii) disclosing certain assets, liabilities, revenues and expenses on different lines in the financial statements than they had been under CGAAP (see details on each classification change below).

A. Accounting for joint ventures (measurement difference)

The Company exercises joint control over its investment in Bear Swamp with its third-party partner and therefore, proportionately consolidated the investment under CGAAP. Under the proportionate consolidation method the Company recognized its pro-rata share of the jointly controlled assets and liabilities of Bear Swamp in the Company’s balance sheet and recognized its pro-rata share of the revenues and expenses of Bear Swamp in the Company’s income statement.

Under USGAAP, the Company accounts for its investment in Bear Swamp using the equity method, whereby the amount of the investment is adjusted quarterly for the Company’s pro-rata share of Bear Swamp’s post-acquisition net income and reduced by the amount of any dividends received. The Company’s pro-rata share of Bear Swamp’s net income is recognized in “Income from equity investments”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Current assets
Cash and cash equivalents		$(1.6)		$(2.1)
Restricted cash		(1.0)		(1.0)
Receivables, net		(3.9)		(3.2)
Derivative instruments		-		(0.8)
Prepaid expenses		(0.2)		(0.2)
Property, plant and equipment		(51.0)		(48.1)
Other assets
Derivative instruments		(16.1)		(5.3)
Investments subject to significant influence		(2.0)		(14.3)
Other		(0.6)		(0.4)
Current liabilities
Current portion of long-term debt		(1.6)		(2.1)
Accounts payable		(1.2)		(1.9)
Derivative instruments		(1.4)		(2.9)
Other current liabilities		-		(0.1)
Long-term liabilities
Long-term debt		(63.8)		(58.5)
Derivative instruments		(5.9)		(10.4)
Other long-term liabilities		(2.6)		-
Equity
Accumulated other comprehensive income (loss)		0.1		0.5

149

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31, 2010 (Unaudited)		6 months ended June 30, 2010 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Non-regulated operating revenues		$(3.6)		$(15.6)		$(23.0)		$(28.1)
Non-regulated fuel for generation and purchased power		(4.6)		(9.0)		(13.0)		(17.2)
Operating, maintenance and general		(0.9)		(1.7)		(2.9)		(4.9)
Provincial, state and municipal taxes		(0.4)		(0.8)		(1.3)		(1.7)
Depreciation and amortization		(0.4)		(0.8)		(1.2)		(1.8)
Income from equity investments		(1.6)		1.8		2.4		1.8
Other income (expenses), net		(0.2)		-		-		-
Interest expense, net		(0.3)		(0.5)		(0.7)		(1.0)
Income tax expense (recovery)		1.2		(1.0)		(1.5)		0.3

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Net cash provided by (used in) operating activities		$0.1		$(3.2)		$(4.5)		$(0.4)
Net cash (used in) provided by investing activities		(0.1)		(0.2)		0.1		1.5
Net cash provided by (used in) financing activities		-		0.9		1.5		(1.6)
Cash and cash equivalents, beginning of period		(1.6)		(1.6)		(1.6)		(1.6)
Cash and cash equivalents, end of period		(1.6)		(4.1)		(4.5)		(2.1)

B. Offsetting (measurement difference)

Certain items on the balance sheets are being offset where a legal right of setoff exists. Differences exist between CGAAP and USGAAP in defining what balances may be offset. As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Receivables, net		$(0.9)		-
Accounts payable		(0.9)		-

C. Income taxes (measurement difference)

In addition to the tax effects of other transition adjustments, the following are included in the income tax adjustments.

Investment tax credits (“ITCs”)

Under CGAAP, the Company recognizes ITCs as a reduction from the related expenditures where there is reasonable assurance of collection. Under USGAAP, the Company recognizes ITCs as a reduction of income tax expense in the current and future periods to the extent that realization of such benefit is more likely than not.

150

Tax rates

Under CGAAP, the Company measured income taxes using substantively enacted income tax rates. Under USGAAP, the Company uses enacted income tax rates. The Company recognized an income tax liability under USGAAP for the difference between the enacted tax rates and the substantively enacted tax rates for the Part VI.1 tax deduction related to preferred share dividends.

Uncertain tax positions

Under CGAAP, the Company recognized the benefit of an uncertain tax position when it was probable of being sustained.

Under USGAAP, the Company recognizes the benefit of an uncertain tax position only when it is more likely than not that such a position will be sustained by the taxing authorities based on the technical merits of the position. The current and deferred income tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Current assets
Income taxes receivable		-		$(6.4)
Deferred income taxes		$(23.6)		(14.5)
Property, plant and equipment		1.1		1.4
Other assets
Deferred income taxes		61.7		17.9
Regulatory assets		(23.1)		(134.9)
Investments subject to significant influence		-		(0.6)
Other		1.1		0.7
Current liabilities
Income taxes payable		1.2		(0.8)
Deferred income taxes		-		8.5
Regulatory liabilities		6.7		4.1
Other current liabilities		1.3		1.1
Long-term liabilities
Deferred income taxes		(53.6)		(176.5)
Regulatory liabilities		61.4		32.4
Equity
Accumulated other comprehensive income (loss)		0.2		0.2
Retained earnings		-		(5.4)

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010 (Unaudited)
Depreciation and amortization		$0.1		$0.2		$0.3		$0.4
Income from equity investments		-		(0.1)		(0.4)		(0.6)
Interest expense, net		(0.3)		(0.3)		(0.4)		(0.2)
Income tax expense (recovery)		(1.0)		(1.0)		3.7		4.3
Preferred stock dividends		-		-		(0.1)		(0.1)

151

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Net cash provided by operating activities		-		-		-		$0.3
Net cash used in investing activities		-		-		-		(0.3)

D. Derivatives (classification change)

Under CGAAP, the Company was disclosing its derivatives in valid hedging relationships and held-for-trading derivatives as separate line items on the balance sheet. Under USGAAP, the Company has included these balances together in “Derivative instruments”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Current assets
Derivative instruments		$39.4		$50.5
Derivatives in a valid hedging relationship		(26.3)		(28.4)
Held-for-trading derivatives		(13.1)		(22.1)
Other assets
Derivative instruments		61.6		41.4
Derivatives in a valid hedging relationship		(30.9)		(26.1)
Held-for-trading derivatives		(30.7)		(15.3)
Current liabilities
Derivative instruments		79.6		39.7
Derivatives in a valid hedging relationship		(61.0)		(8.6)
Held-for-trading derivatives		(18.6)		(31.1)
Long-term liabilities
Derivative instruments		41.5		39.3
Derivatives in a valid hedging relationship		(25.7)		(21.3)
Held-for-trading derivatives		(15.8)		(18.0)

E. Regulatory assets and liabilities (classification change)

Under CGAAP, the Company was disclosing its regulatory assets and liabilities in other assets and liabilities respectively. Under USGAAP, the Company discloses its regulatory assets and liabilities as separate line items on the balance sheet.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Current assets
Regulatory assets		$55.8		$63.7
Other assets
Regulatory assets		273.1		466.3
Other		(328.9)		(530.0)
Current liabilities
Regulatory liabilities		21.2		22.1
Long-term liabilities
Regulatory liabilities		0.5		11.9
Other long-term liabilities		(21.7)		(34.0)

152

F. Hedging (measurement change)

Brunswick Pipeline

Under CGAAP, cash flow hedging strategies of Brunswick Pipeline qualified for hedge accounting. Under USGAAP, the Company determined that certain cash flow hedging strategies did not qualify for hedge accounting primarily due to differences in effectiveness testing requirements. The Company changed its effectiveness testing for hedges put in place beginning January 1, 2010 and these hedges qualify for hedge accounting under USGAAP.

As a result of disqualifying cash flow hedges in place prior to 2010, Brunswick Pipeline must recognize changes in fair value on these derivatives in net income of the period, rather than deferring the changes to accumulated other comprehensive income. In addition, because of the change in effectiveness testing effective January 1, 2010, Brunswick Pipeline must measure and recognize any ineffectiveness of its hedging strategies in net income of the period.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Net investment in direct financing lease		$3.2		$3.2
Accumulated other comprehensive income (loss)		(7.4)		(1.4)
Retained earnings		10.6		4.6

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Regulated operating revenues		$(2.0)		$(4.2)		$(5.9)		$(7.4)
Other income (expenses), net		1.3		(0.7)		0.5		1.4

Nova Scotia Power

In addition to the above, effective for 2011, NSPI implemented an amended hedge accounting policy which was approved by the UARB. The amended policy resulted from stakeholder requests to simplify the accounting for derivatives used to manage risk and to alleviate any USGAAP issues which would result in increased income volatility. The amended policy is applied retrospectively with restatement of prior periods with the exception of prior period income, and requires regulatory deferral for commodity, foreign exchange and interest derivatives documented as economic hedges and for physical contracts that do not qualify for the NPNS exception under USGAAP.

As a result of the amended accounting policy, NSPI receives regulatory deferral for any changes in fair value on derivatives documented as economic hedges. As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Current assets
Regulatory assets		$75.9		$26.9
Other assets
Regulatory assets		20.0		12.2
Current liabilities
Regulatory liabilities		22.1		28.6
Long-term liabilities
Regulatory liabilities		29.8		21.2
Equity
Accumulated other comprehensive income (loss)		44.0		(10.7)

153

G. Issue costs

Classification change

Under CGAAP, debt financing costs, premiums and discounts were netted against long-term debt. Under USGAAP, debt financing costs are included in “Other” as part of “Other assets”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Other current assets		$1.8		$1.0
Other, included in other assets		13.5		16.8
Short-term debt		-		0.4
Long-term debt		15.3		17.4

Measurement Change

Under CGAAP, the straight-line method of amortizing debt financing costs, premiums and discounts was used to approximate the effective interest method. Under USGAAP, the straight-line method is not appropriate so the effective interest method has been adopted.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Other, included in other assets		$1.1		$1.1
Long-term debt		2.2		2.2
Retained earnings		(1.1)		(1.1)

H. Current other assets and liabilities (classification change)

Under CGAAP, the Company was disclosing its other assets and liabilities on the balance sheet as long-term. Under USGAAP, the Company has included the current portion of these balances in “Other current assets” and “Other current liabilities”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Other current assets		$1.5		$2.1
Other, included in other assets		(1.5)		(2.1)
Other current liabilities		2.8		3.9
Other long-term liabilities		(2.8)		(3.9)

I. Construction work-in-progress (classification change)

Under CGAAP, the Company was disclosing its construction work-in-progress (“CWIP”) as a separate line item on the balance sheet. Under USGAAP, the Company has included this balance in “Property, plant and equipment” and will disclose its CWIP balance annually in the notes to the December 31 financial statements.

154

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1   2010		December 31 2010
Property, plant and equipment		$220.2		$333.0
Construction work-in-progress		(220.2)		(333.0)

J. Business combinations (measurement change)

Acquisition-related transaction costs

Under CGAAP, acquisition-related transaction costs were capitalized and included in the allocation of the purchase price to the acquired assets and liabilities. Under USGAAP, acquisition-related transaction costs are expensed in the period incurred, beginning with transactions completed on or after January 1, 2009.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Property, plant and equipment		$(0.2)		$(0.2)
Other, included in other assets		-		(0.5)
Goodwill		-		(10.7)
Accumulated other comprehensive income (loss)		-		0.1
Retained earnings		(0.2)		(11.5)

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Operating, maintenance and general		-		-		-		$11.3

Business combinations achieved in stages

Under CGAAP, for business combinations achieved in stages, the acquirer does not re-measure its previously held equity interest in an acquired company. Under USGAAP, the acquirer re-measures the previously held equity interest at the acquisition-date fair value and recognizes the resulting gain or loss, if any, in income.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Property, plant and equipment		$0.4		-
Regulatory assets		(0.4)		-
Goodwill		-		$(2.4)
Retained earnings		-		(2.4)

155

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Other income (expenses), net		-		-		-		$(2.4)

Negative goodwill

Under CGAAP, where the net assets in a business combination exceed the purchase price, sometimes referred to as “negative goodwill”, the excess should be eliminated, to the extent possible, by allocating the negative goodwill as a pro rata reduction of the amounts that otherwise would be assigned to certain of the acquired assets. Under USGAAP, the negative goodwill gives rise to an extraordinary gain which is recognized in income.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Investments subject to significant influence		-		$21.5
Accumulated other comprehensive income (loss)		-		(0.6)
Retained earnings		-		22.1

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Other income (expenses), net		-		$22.5		$22.3		$22.1

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Net cash used in operating activities		-		-		-		(11.3)
Net cash provided by investing activities		-		-		-		11.3

K. Pension and other post-retirement benefits (measurement change)

Under CGAAP, the Company disclosed, but did not recognize, its unamortized gains and losses, its past service costs, and its unamortized transitional obligation associated with pension and other post-retirement benefits. Under USGAAP, the Company has recognized its unfunded pension obligation as a liability; the unamortized gains and losses and past service costs are recognized in AOCL; and the unamortized transitional obligation previously determined under CGAAP is recognized in “Retained earnings”.

156

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Other assets
Regulatory assets		$9.2		$11.6
Other		(94.3)		(113.5)
Goodwill		-		1.5
Current liabilities
Pension and post-retirement liabilities		9.2		8.9
Long-term liabilities
Deferred income taxes		(14.3)		(14.7)
Pension and post-retirement liabilities		292.4		400.0
Other long-term liabilities		(88.0)		(102.4)
Equity
Accumulated other comprehensive income (loss)		(277.6)		(387.9)
Retained earnings		(6.8)		(4.3)

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Operating, maintenance and general		$(0.6)		$(1.1)		$(1.7)		$(2.3)

L. Intangibles (classification change)

Under CGAAP, the Company was disclosing its intangibles as a separate line item on the balance sheet. Under USGAAP, the Company has included this balance in “Other” as part of “Other assets”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Other, included in other assets		$92.1		$98.2
Intangibles		(92.1)		(98.2)

M. Investments (measurement change)

Under CGAAP, certain investments of the Company were classified as an available-for-sale investment and measured at cost as the investments are not actively traded in an open market. Under USGAAP, investments measured at cost because they do not trade in an active market are not included in “Available-for-sale investment” therefore the Company has included these investments in “Other assets”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010			December 31 2010
Other, included in other assets		$46.3			46.2
Available-for-sale investment		(46.3	)		(46.2	)

157

N. Accounts payable (classification change)

Under CGAAP, trade and non-trade payables were recognized in accounts payable and accrued charges. Under USGAAP, trade payables are recognized in “Accounts payable” and non-trade payables are recognized in “Other current liabilities”.

As at January 1 and December 31, 2010, the effect the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Accounts payable		$220.4		$296.5
Accounts payable and accrued charges		(305.9)		(399.6)
Other current liabilities		85.5		103.1

O. Dividends payable (classification change)

Under CGAAP, the Company was disclosing dividends payable as a separate line item on the balance sheet. Under USGAAP, the Company has included this balance in “Other current liabilities”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Dividends payable		$(1.7)		$(1.8)
Other current liabilities		1.7		1.8

P. Preferred stock of Nova Scotia Power Inc. (measurement change)

Under CGAAP, NSPI’s preferred stock was classified as a liability; preferred stock dividends were classified as an expense in the income statement and were accrued monthly; and issuance costs were deferred on the balance sheet as a deferred financing charge and amortized to income over the life of the preferred stock.

Under USGAAP, NSPI’s preferred stock is classified as equity in “Non-controlling interest” as the preferred stock does not meet the USGAAP definition of a liability; preferred stock dividends are deducted from retained earnings and are accrued as declared; and issuance costs are netted against the preferred stock on the balance sheet and are not amortized.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Other current liabilities		$0.3		$0.3
Long-term debt		0.7		0.6
Preferred shares issued by a subsidiary		(135.0)		(135.0)
Retained earnings		1.8		1.9
Non-controlling interest in subsidiaries		132.2		132.2

158

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Financing charges		$(2.0)		$(4.0)		$(6.0)		$(8.0)
Interest expense, net		-		(0.1)		(0.1)		(0.1)
Non-controlling interest in subsidiaries		2.0		4.0		6.0		8.0

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Net cash provided by operating activities		$2.0		$4.0		$6.0		$8.0
Net cash used in financing activities		(2.0)		(4.0)		(6.0)		(8.0)

Q. Non-controlling interest in subsidiaries (classification change)

Under CGAAP, non-controlling interest in subsidiaries (“NCI”) is classified outside shareholders’ equity, after liabilities. Under USGAAP, NCI is included in total equity.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Non-controlling interest		$(32.1)		$(20.7)
Accumulated other comprehensive income (loss)		-		(1.5)
Non-controlling interest in subsidiaries		32.1		22.2

R. Stock-based compensation (measurement change)

Employee Common Share Purchase Plan

Under CGAAP, the Company was recognizing the amount of its contribution in excess of 5 percent of the average market price of the shares. Under USGAAP, the Company’s employee common share purchase plan is considered compensatory and the Company’s contribution to the plan should be recognized.

Senior Management Stock Option Plan

Under CGAAP, the Company was amortizing the compensation cost associated with its stock option over two years, the average vesting period of the four awards. Under USGAAP, the Company has chosen to amortize the compensation cost over four years, the vesting period of the entire award.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Common stock		$1.2		$1.3
Contributed surplus		(0.6)		(0.5)
Retained earnings		(0.6)		(0.8)

159

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is as reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Operating, maintenance and general		$0.1		$0.1		$0.2		$0.2

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows results is as follows:

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Net cash used in operating activities		$(0.1)		$(0.1)		$(0.2)		$(0.2)
Net cash provided by financing activities		0.1		0.1		0.2		0.2

S. Foreign currency translation (measurement change)

Under CGAAP, the Company’s Canadian division of Emera Energy Services had a Canadian functional currency. Monetary assets and liabilities denominated in a foreign currency were converted to Canadian dollars at rates of exchange prevailing at the balance sheet date. The effect of periodic changes in exchange rates were charged to income.

Under USGAAP, the Company has determined that Emera Energy Services has a US functional currency. Asset and liabilities are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average rates for the periods. The resulting exchange gains (losses) on the assets and liabilities are deferred and included in accumulated other comprehensive income.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):

As at   millions of Canadian dollars	January 1 2010		December 31 2010
Accumulated other comprehensive income		$1.2		$1.6
Retained earnings		(1.2)		(1.6)

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Other income (expenses), net		$(0.4)		$(0.4)		$(0.1)		$(0.3)

T. Revenue (classification change)

Under CGAAP, revenue was recognized in electric revenue, finance income from direct finance lease and other revenue. Under USGAAP, revenue is recognized in regulated operating revenues, non-regulated operating revenue income and other income (expense), net.

160

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 20 2010 (Unaudited)		Year ended December 31 2010
Electric revenue		$(412.1)		$(739.7)		$(1,074.0)		$(1,436.1)
Finance income from direct finance lease		(14.2)		(29.0)		(42.8)		(56.5)
Other revenue		(3.8)		(18.8)		(44.2)		(61.1)
Regulated operating revenues		391.2		712.8		1,040.1		1,391.9
Non-regulated operating revenues		38.6		74.2		119.9		159.9
Other income (expense), net		0.3		0.5		1.0		1.9

U. Netting of certain revenues and expenses (measurement change)

Under CGAAP, the Company was netting certain revenues and expenses in its statements of income. Under USGAAP, revenues are classified on a gross or net basis depending on whether the Company is acting as the principal or an agent in the transaction. The adoption of USGAAP has resulted in certain revenue transactions disclosed on a net basis under CGAAP to be presented on a gross basis under USGAAP.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Regulated operating revenues		$6.2		$12.5		$19.8		$27.2
Non-regulated operating revenues		8.1		23.5		46.4		62.6
Regulated fuel for generation and purchased power		3.9		7.6		12.5		17.0
Non-regulated direct costs		8.2		23.5		46.1		62.3
Operating, maintenance and general		2.2		4.9		7.6		10.5
Other income (expenses), net		0.1		0.2		0.2		0.3
Interest expense, net		0.1		0.2		0.2		0.3

V. Fuel for generation and purchased power (classification change)

Under CGAAP, all fuel for generation and purchased power was recognized as such. Under USGAAP, regulated and non-regulated fuel for generation and purchased power are recognized separately.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Regulated fuel for generation and purchased power		$(27.7)		$(52.9)		$(77.5)		$(101.1)
Non-regulated fuel for generation and purchased power		27.7		52.9		77.5		101.1

161

W. Interest expense (classification change)

Under CGAAP, interest expense, amortization of defeasance costs, and foreign exchange gains and losses were included in financing charges. Under USGAAP, interest expense is disclosed in a separate line item and amortization of defeasance costs and foreign exchange gains and losses are included in “Other income (expense), net”.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Operating, maintenance and general		-		$0.1		$0.1		$0.2
Other income (expenses), net		$(5.6)		(9.9)		(16.6)		(26.0)
Financing charges		(45.8)		(90.0)		(136.8)		(186.5)
Interest expense, net		40.2		80.0		120.1		160.3

X. Regulatory amortization (classification change)

Under CGAAP, regulatory amortization was disclosed as a separate line item. Under USGAAP, regulatory amortization is included in “Depreciation and amortization”.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Depreciation and amortization		$5.4		$10.9		$16.7		$41.3
Regulatory amortization		(5.4)		(10.9)		(16.7)		(41.3)

Y. Allowance for funds used during construction (classification change)

Under CGAAP, AFUDC was included in financing charges. Under USGAAP, allowance for equity funds used during construction is included in “Other income (expenses), net” and allowance for borrowed funds used during construction is netted against “Interest expense, net”.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Other income (expenses), net		$2.6		$5.7		$10.6		$15.6
Financing charges		4.6		9.7		18.2		26.0
Interest expense, net		(2.0)		(4.0)		(7.6)		(10.4)

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:

For the   millions of Canadian dollars	3 months ended March 31 2010 (Unaudited)		6 months ended June 30 2010 (Unaudited)		9 months ended September 30 2010 (Unaudited)		Year ended December 31 2010
Net cash provided by operating activities		$2.0		$4.0		$7.6		$10.4
Net cash provided by investing activities		(2.0)		(4.0)		(7.6)		(10.4)

162

36.    SUBSEQUENT EVENTS

Bangor Hydro

On January 31, 2012, Bangor Hydro completed the issue of an unsecured $70.0 million USD senior note. The Series 2012-A Senior Note bears interest at a rate of 3.61 percent per annum until January 31, 2022. The net proceeds of the note offering were used to repay borrowings under the revolving credit facility.

GBPC

On January 25, 2012, GBPC entered into an unsecured credit agreement with Scotiabank (Bahamas) Limited in the amount of $56.2 million USD. The proceeds of the credit agreement will be used to finance the construction of a 52-MW power plant on Grand Bahama Island. The credit agreement bears interest at a rate of the three month LIBOR rate plus 1.2 percent and is repayable in forty equal, consecutive quarterly installments over a ten year period. The payments commence at the earlier of six months after the completion of the construction of the power plant or January 31, 2013.

163

EX-99.3

Exhibit 99.3

FORM 52-109F1

CERTIFICATION OF ANNUAL FILINGS

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

1. Review: I have reviewed the AIF, if any, annual financial statements and annual MD&A, including, for greater certainty, all documents and information that are incorporated by reference in the AIF (together, the “annual filings”) of Emera Inc., (the “issuer”) for the financial year ended December 31, 2011.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the annual 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, for the period covered by the annual filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the annual financial statements together with the other financial information included in the annual 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 annual 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 financial year end

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 annual 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 N/A

5.3 Limitation on scope of design: The issuer has disclosed in its annual 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 a business that the issuer acquired not more than 365 days before the issuer’s financial year end; 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. Evaluation: The issuer’s other certifying officer(s) and I have

a. evaluated, or caused to be evaluated under our supervision, the effectiveness of the issuer’s DC&P at the financial year end and the issuer has disclosed in its annual MD&A our conclusions about the effectiveness of DC&P at the financial year end based on that evaluation; and

b. evaluated, or caused to be evaluated under our supervision, the effectiveness of the issuer’s ICFR at the financial year end and the issuer has disclosed in its annual MD&A

i. our conclusions about the effectiveness of ICFR at the financial year end based on that evaluation; and

ii. N/A

7. Reporting changes in ICFR: The issuer has disclosed in its annual MD&A any change in the issuer’s ICFR that occurred during the period beginning on October 1, 2011 and ended on December 31, 2011 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

8. Reporting to the issuer’s auditors and board of directors or audit committee: The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of ICFR, to the issuer’s auditors, and the board of directors or the audit committee of the board of directors any fraud that involves management or other employees who have a significant role in the issuer’s ICFR.

Date: February 10, 2012

By:	“Christopher Huskilson”
	President and Chief Executive Officer

EX-99.4

Exhibit 99.4

FORM 52-109F1

CERTIFICATION OF ANNUAL FILINGS

I, Judy Steele, Chief Financial Officer of Emera Inc., certify the following:

1. Review: I have reviewed the AIF, if any, annual financial statements and annual MD&A, including, for greater certainty, all documents and information that are incorporated by reference in the AIF (together, the “annual filings”) of Emera Inc., (the “issuer”) for the financial year ended December 31, 2011.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the annual 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, for the period covered by the annual filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the annual financial statements together with the other financial information included in the annual 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 annual 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 financial year end

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 annual 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 N/A

5.3 Limitation on scope of design: The issuer has disclosed in its annual 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 a business that the issuer acquired not more than 365 days before the issuer’s financial year end; 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. Evaluation: The issuer’s other certifying officer(s) and I have

a. evaluated, or caused to be evaluated under our supervision, the effectiveness of the issuer’s DC&P at the financial year end and the issuer has disclosed in its annual MD&A our conclusions about the effectiveness of DC&P at the financial year end based on that evaluation; and

b. evaluated, or caused to be evaluated under our supervision, the effectiveness of the issuer’s ICFR at the financial year end and the issuer has disclosed in its annual MD&A

i. our conclusions about the effectiveness of ICFR at the financial year end based on that evaluation; and

ii. N/A

7. Reporting changes in ICFR: The issuer has disclosed in its annual MD&A any change in the issuer’s ICFR that occurred during the period beginning on October 1, 2011 and ended on December 31, 2011 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

8. Reporting to the issuer’s auditors and board of directors or audit committee: The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of ICFR, to the issuer’s auditors, and the board of directors or the audit committee of the board of directors any fraud that involves management or other employees who have a significant role in the issuer’s ICFR.

Date: February 10, 2012

By:	“Judy Steele”
	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 audited consolidated financial statements of Emera Incorporated (Emera) for the year ended December 31, 2011, in conjunction with an amended and restated short form base shelf prospectus dated February 18, 2011.

The following earnings coverage ratio is calculated on a consolidated basis for the twelve-month period ended December 31, 2011.

	Twelve months ended December 31, 2011
Earnings Coverage (1)	2.07

⁽¹⁾ Earnings coverage is equal to consolidated net earnings applicable to common shares plus: income taxes, interest on long term-debt, amortization of debt financing and after-tax preferred share dividends declared during the year together with undeclared preferred share dividends, if any, divided by interest on long-term debt plus amortization of debt financing and pre-tax preferred dividends.

Emera’s dividend requirements on all of its preferred shares, adjusted to before-tax equivalent using an effective income tax rate of 32.5 percent, amounted to $23.7 million for the 12 months ended December 31, 2011. Emera’s interest requirements for the 12 months then ended amounted to $159.3 million. Emera’s consolidated income before interest and income tax for the 12 months ended December 31, 2011 was $378.3 million, which is 2.07 times Emera’s aggregate dividend and interest requirements for this period.

EX-99.6

Exhibit 99.6

Emera Reports 2011 Earnings

HALIFAX, Nova Scotia, February 10, 2012 (EMA-TSX): Emera Inc.’s consolidated net income for the year ended December 31, 2011 was $241.1 million, compared to $190.7 million in 2010. Earnings per share were $1.99 compared to $1.67 in 2010. Excluding the effect of mark-to-market accounting adjustments in Bear Swamp, and accounting gains on an acquisition, 2011 net income was $213.7 million, compared to $176.8 million in 2010; and 2011 earnings per share were $1.77 compared to $1.55 in 2010. Higher earnings year-over-year primarily resulted from increased investment in the Caribbean, and a $12.8 million after-tax gain on Algonquin Power & Utilities Corp. (Algonquin) subscription receipts recorded in Q1 2011.

Consolidated net income for the three months ended December 31, 2011 was $46.8 million compared to $24.1 million for the fourth quarter of 2010. Quarterly earnings per share were $0.38 in 2011 and $0.21 for the same period in 2010. Higher earnings in the quarter are primarily due to increased investments in the Caribbean.

“2011 was another record year for earnings,” said Chris Huskilson, President and CEO of Emera Inc. “Our Caribbean investments made a meaningful contribution to earnings, we have begun integrating Maine Public Service with Bangor Hydro, the Lower Churchill project continues to advance, and in December, we were pleased to have registered the Maritime Link Project for its environmental approval process.”

Nova Scotia Power Inc. (NSPI) contributed $123.5 million to consolidated net income for the year ended December 31, 2011, compared to $119.2 million in 2010; and $22.2 million in Q4 2011 compared to $19.9 million for the same period in 2010. The higher net income was primarily due to $23.3 million of income tax recoveries arising from the amendment of prior years’ tax returns. This more than offset decreased electric margin from industrial customers and increased pension costs. In November 2011, the Nova Scotia Utility and Review Board approved a rate settlement agreement for NSPI which resulted in an average rate increase of approximately 5.1% for all customers effective January 1, 2012.

Maine Utility Operations contributed $37.0 million to consolidated net income in 2011 compared to $31.9 million for the same period in 2010. The increase is primarily due to increased returns from new transmission investments, lower operating, maintenance and general expenses and the acquisition of Maine and Maritimes Corporation in Q4 2010. Maine Utilities contributed $9.8 million to consolidated net income in Q4 2011 compared to $7.8 million for the same period in 2010.

Excluding the impact of the accounting gains previously noted, Caribbean Utility Operations (the Caribbean) contributed $18.6 million to consolidated net income in 2011 compared to a loss of $2.7 million in 2010. For the fourth quarter of 2011, the Caribbean contributed $3.1 million to consolidated net income compared to a loss of $7.7 million for the same period in 2010. The increased net income during the quarter and year-over-year was due to increased investments in both Grand Bahama Power Company (GBPC) and Barbados Light and Power; and higher earnings at GBPC, which had expensed $6.1 million of acquisition related costs in the fourth quarter of 2010.

Pipelines contributed $27.9 million to consolidated net income in 2011 compared to $28.9 million in 2010; and $6.9 million in Q4 2011 compared to $8.0 million in Q4 2010.

Emera’s Services Renewables and Other investments (SRO) contributed $27.0 million to consolidated net income in 2011 compared to $8.6 million in 2010. Excluding the effect of the mark-to-market accounting adjustments in Bear Swamp previously noted, SRO contributed $27.8 million in 2011, compared to $17.2 million in 2010. The increase is primarily due to the $12.8 million after-tax gain realized on Algonquin subscription receipts. This segment contributed $6.7 million to consolidated net income in Q4 2011 compared to $4.4 million in Q4 2010. The increase during the quarter is primarily due to stronger energy marketing results.

Forward Looking Information

This news release contains forward looking information. Actual future results may differ materially. Additional information related to Emera, including the company’s Annual Information Form, can be found on SEDAR at www.sedar.com or on EDGAR at www.sec.gov.

Teleconference Call

The company will be hosting a teleconference at 4:00 pm Atlantic time today (3:00 pm Toronto/Montreal/New York; 2:00 pm Winnipeg; 12:00 pm Vancouver) to discuss the 2011 financial results.

Analysts and other interested parties wanting to participate in the call should dial 1-866-225-0198 (in Toronto 416-340-8061) at least 10 minutes prior to the start of the call. 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 1-800-408-3053 (in Toronto 905-694-9451), access code 7847722# (available until midnight, Friday, February 24, 2012). The teleconference will also be web cast live at emera.com and available for playback for one year.

About Emera

Emera Inc. is an energy and services company with $6.9 billion in assets and 2011 revenues of $2.1 billion. The company invests in electricity generation, transmission and distribution, as well as gas transmission and utility energy services. Emera’s strategy is focused on the transformation of the electricity industry to cleaner generation and the delivery of that clean energy to market. Emera has interests throughout northeastern North America, in three Caribbean countries and in California. More than 80% of the company’s earnings come from regulated investments. Emera common and preferred shares are listed on the Toronto Stock Exchange and trade respectively under the symbol EMA and EMA.PR.A. Additional information can be accessed at www.emera.com, www.sedar.com, or on www.sec.gov.

For more information, please contact:

Jill MacDonald, CA

Manager, Investor Relations

(902) 428-6486