Exhibit 99.1

Emera Incorporated

2011 Annual Information Form

March 29, 2012

TABLE OF CONTENTS

Definitions	1
Introduction	5
Cautionary note regarding forward-looking information	5
Corporate Structure	7
Name and Incorporation	7
Intercorporate Relationships	7
General Development of the Business	7
Acquisition of Interest in Lucelec by LPH	8
Strategic Partnership with Algonquin Power and Utilities Corp.	8
First Wind	9
Grand Bahama Power Company Limited	10
Maine & Maritimes Corporation	10
Light & Power Holdings Ltd.	10
Strategic Partnership with Nalcor Energy	11
Environmental Regulations – Canada	12
Environmental Regulations – Nova Scotia	12
Digby Wind Renewable Energy Project	12
Nova Scotia Renewable Energy Standard Regulation	13
Bayside Power LP	13
Brunswick Pipeline	13
Financing Activity	13
U. S. Securities and Exchange Commission Registration and Transition to USGAAP	15
Changes in Business Expected During Current Year	16
Description of the Business	17
General	17
Nova Scotia Power Inc.	19
Maine Utility Operations	19
Distribution	20
Transmission	20
Stranded Costs	20
Capital Expenditures	21
Environmental Considerations	21
Caribbean Utility Operations	22
Pipelines	23
New Head Office	23
Emera Employees	23
Emera Environmental Matters	23
Emera Taxation	23
Risk Factors	23
Commodity Price Risk	24
Foreign Exchange Risk	25
Acquisition Risk	26
Interest Rate Risk	26
Commercial Relationships Risk	26
Credit Risk	27
Labour Risk	27

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Weather	28
Regulatory Risk	28
Environment	30
Capital Markets	33
Construction and Development	33
Capital Structure	34
Common Shares	34
First Preferred Shares	34
Second Preferred Shares	35
Share Ownership Restrictions	35
Ratings	36
Dominion Bond Rating Service Limited	36
Standard & Poor’s	36
NSPI Series D First Preferred Shares	37
Dividends	37
Market for Securities	38
Trading Price and Volume	38
Transfer Agent and Registrar	39
Directors and Officers	39
Directors	39
Audit Committee	42
Audit and Non-Audit Services Pre-Approval Process	44
Auditors’ Fees	44
Officers	45
Certain Proceedings	46
Legal Proceedings and Regulatory Actions	46
No Interest of Management and Others in Material Transactions	46
Material Contracts	47
Management’s Discussion & Analysis	47
Experts	47
Interest of Experts	47
Additional Information	47
Appendix “A” – Audit Committee Charter	i

Note: The information presented in this Annual Information Form is as of December 31, 2011, unless otherwise specified.

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Definitions

For convenience, terms used throughout this 2011 AIF of Emera Incorporated shall have the following meanings:

“AIF” means this 2011 Annual Information Form of Emera;

“APUC” means Algonquin Power and Utilities Corp., formerly Algonquin Fund Power Income Fund, a company incorporated under the federal laws of Canada;

“Atlantic Hydrogen” means Atlantic Hydrogen Inc., a private company incorporated under the laws of the Province of New Brunswick;

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

“BLPC” means Barbados Light & Power Company Limited, an electric utility company incorporated under the laws of Barbados and a wholly-owned subsidiary of LPH;

“Bangor Hydro” means Bangor Hydro Electric Company, an electric utility company incorporated under the laws of the State of Maine and a wholly-owned subsidiary of Emera;

“Barbados Commission” means the Fair Trading Commission, Barbados, the independent regulator of BLPC;

“Bayside Power LP” means Bayside Power Limited Partnership, a limited partnership governed by the laws of the Province of New Brunswick and wholly-owned by Emera;

“Bear Swamp” means Bear Swamp Power Company, LLC, a company incorporated under the laws of Delaware in which Emera holds a 50% interest;

“Board” means the Board of Directors of Emera;

“Brunswick Pipeline” means the pipeline beginning at the Canaport^TM LNG LP owned liquefied natural gas terminal near Saint John, New Brunswick and connecting with the M&NP near Baileyville, Maine, wholly-owned by EBPC;

“CEA” means the Canadian Electricity Association;

“CGAAP” means Canadian Generally Accepted Accounting Principles from time to time approved by the Canadian Institute of Chartered Accountants, or any successor institute;

“CRA” means Canada Revenue Agency;

“CPUV” means California Pacific Utility Ventures, LLC, a company incorporated pursuant to the laws of the State of California, and the parent of California Pacific;

“CPUV Subscription Receipts” means the subscription receipts issued by APUC on September 12, 2011 which are exchangeable for 8.211 million common shares of APUC;

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“California Pacific” means California Pacific Electric Company, LLC, a company incorporated under the laws of the State of California;

“Company” means Emera;

“Computershare” means Computershare Trust Company of Canada;

“DBRS” means the credit rating agency Dominion Bond Rating Service Limited;

“Directors” means the directors of Emera;

“Dividend Reinvestment Plan” means Emera’s Common Shareholders Dividend Reinvestment and Share Purchase Plan, revised effective September 25, 2009;

“EBPC” means Emera Brunswick Pipeline Company Ltd., a company incorporated under the federal laws of Canada and a wholly-owned subsidiary of Emera and owner of the Brunswick Pipeline;

“ECL” means Emera Caribbean Limited, a company incorporated under the laws of Barbados and a wholly-owned subsidiary of Emera and parent of GBPC and ICDU;

“EMS” means environmental management systems;

“ENL” means ENL Maritime Link Incorporated (formerly called Emera Newfoundland & Labrador Incorporated), a company incorporated under the laws of the Province of Newfoundland and Labrador and a subsidiary of Emera Newfoundland & Labrador Holdings Incorporated;

“EUR” means Euros, the official currency of the European Union;

“EUS” means Emera Utility Services Inc. a company incorporated under the laws of the Province of New Brunswick and a wholly-owned subsidiary of Emera;

“Emera” means Emera Incorporated, a company incorporated under by the laws of the Province of Nova Scotia;

“Emera Energy” means Emera Energy Incorporated, a wholly-owned subsidiary of Emera, incorporated under the laws of the Province of Nova Scotia;

“Emera Energy Services” means Emera Energy Services, Inc., a company incorporated under the laws of the State of Delaware and a subsidiary of Emera Energy;

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

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

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

“First Wind Subscription Receipts” means the subscription receipts issued by APUC on July 29, 2011 which are exchangeable for approximately 6.9 million common shares of APUC;

“GBPA” means Grand Bahama Port Authority, regulator of GBPC;

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“GBPC” means Grand Bahama Power Company Limited, an electric utility company incorporated under the laws of the Commonwealth of the Bahamas and a subsidiary of ECL;

“GHG” means greenhouse gases;

“GWh” means gigawatt hours;

“ICDU” means ICD Utilities Limited, a company incorporated under the laws of the Commonwealth of the Bahamas and a subsidiary of ECL;

“IFRS” means International Financial Reporting Standards;

“IPPs” means independent power producers;

“IRP” means the Integrated Resource Plan filed with the UARB in 2007 and updated in 2009;

“ISO 14001” means the international standard developed by the International Organization for Standardization on environmental management and viewable at www.iso.org;

“LIPA” means Long Island Power Authority;

“LIBOR” means London Interbank Offered Rate;

“LPH” means Light & Power Holdings Ltd., a company incorporated under the laws of Barbados and whose shares are listed on the Barbados Stock Exchange, and a subsidiary of ECL and the parent of BLPC;

“Lucelec” means St. Lucia Electricity Services Ltd., a company incorporated under the laws of St. Lucia;

“M&NP” means the Maritimes & Northeast Pipeline, which transports natural gas from offshore Nova Scotia to markets in the Maritime Provinces and New England;

“MAM” means Maine & Maritimes Corporation, a company incorporated under the laws of the State of Maine, a wholly-owned subsidiary of Emera and the parent of MPS;

“MD&A” means Emera’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2011, a copy of which is available electronically at www.sedar.com under Emera’s profile;

“MMBTU” means one million British thermal units;

“MPS” means Maine Public Service Company, an electric utility company incorporated pursuant to the laws of the State of Maine, and a wholly-owned subsidiary of MAM;

“MPUC” means the Maine Public Utilities Commission, regulator of Bangor Hydro and MPS;

“MW” means the amount of power measured in mega-watts;

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

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“NEB” means the Canadian National Energy Board;

“NPCC” means the North American Northeast Power Coordinating Council, Inc.;

“NPNS” means normal purchases and normal sale;

“NSPI” means Nova Scotia Power Incorporated, a company incorporated under the laws of the Province of Nova Scotia and a wholly-owned subsidiary of Emera;

“NSPI’s Annual Information Form” means the 2011 Annual Information Form of NSPI dated March 29, 2012;

“NSPI Series D First Preferred Shares” means the 5.90% cumulative redeemable first preferred shares, series D of NSPI;

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

“New England” means the region of the northeast U.S. consisting of the States of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont;

“New Hampshire Subscription Receipts” means the subscription receipts issued by APUC on March 25, 2011 which are exchangeable for 12 million common shares of APUC;

“Northeastern U.S.” means New England, New Jersey, New York and Pennsylvania;

“Northeast Wind” means Northeast Wind Holdings, LLC, an entity owned by Emera to hold a 49% partnership interest in a joint venture with First Wind;

“OATT” means open access transmission tariff;

“Officers” means the executive officers of Emera;

“OpenHydro” means OpenHydro Group Limited, a company incorporated under the laws of Ireland;

“Order” means a cease trade order, an order similar to a cease trade order or an order that denies a company access to any exemption under securities legislation that was in effect for a period of more than thirty (30) consecutive days;

“Province” means the Province of Nova Scotia and includes, when the context requires, the provincial government of Nova Scotia, and “provincial” refers to Nova Scotia;

“RES” means the Province of Nova Scotia’s Renewable Energy Standards, viewable at www.gov.ns.ca/energy/renewables/renewable-energy-standard;

“ROA” means return on assets;

“ROE” means return on equity;

“Rating Agencies” means collectively DBRS and S&P, and “Rating Agency” means one of the Rating Agencies;

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“S&P” means the credit rating agency Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.;

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

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

“Series A First Preferred Shares” means the 4.40% cumulative 5-year rate reset first preferred shares, series A of Emera;

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

“State” means a state of the United States and includes, when the context requires, the state government;

“TSX” means The Toronto Stock Exchange;

“UARB” means the Nova Scotia Utility and Review Board, regulator of NSPI;

“U.S.” means the United States;

“USD $” means U.S. dollar(s);

“USGAAP” means the accounting principles which are recognized as being generally accepted and which are in effect from time to time in the U.S. as codified by the Financial Accounting Standards Board, or any successor institute;

“United States” means the United States of America; and

“Utilities Rules” means the Utilities Regulation (Procedural) Rules 2003 (Barbados);

All amounts are in Canadian dollars (“CAD”) except where otherwise stated.

Reference to “including” or “includes” means “including (or includes) but is not limited to” and shall not be construed to limit any general statement preceding it to the specific or similar items or matters immediately following it.

INTRODUCTION

Emera is an energy and services company headquartered in Halifax, Nova Scotia. The Company invests in electricity generation, transmission and distribution as well as gas transmission and utility energy services.

For more information on the business operations of the Company, see “Description of the Business” below.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION

This AIF, including the documents incorporated herein by reference, contains “forward-looking information” within the meaning of applicable Canadian securities laws and “forward looking

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statements” within the meaning of the United States Private Securities Legislation Reform Act of 1995 (collectively, “forward looking information”). The words “anticipates”, “believes”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “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 AIF, including the documents incorporated by reference, includes statements which reflect the current view with respect to Emera’s objectives, plans, financial and operating performance, business prospects and opportunities. The forward looking information reflects Emera’s 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 at times which, such events, performance or results will be achieved.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements regarding: Emera’s consolidated earnings and cash flow; the growth and diversification of Emera’s business and earnings base; future annual earnings growth; expansion of Emera’s business in the U.S. and elsewhere; the completion of announced acquisitions; the expected compliance by Emera and its subsidiaries with the regulation of their operations; the expected timing of regulatory decisions; forecasted gross capital expenditures; the nature, timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; expectations related to annual operating cash flows; the expectation that Emera will continue to have reasonable access to capital in the near to medium terms; expected debt maturities and repayments; expectations about increases in interest expense and/or fees associated with credit facilities; and no material adverse credit rating actions being expected in the near term.

The forecasts and projections that make up the forward-looking information are based on reasonable assumptions which include: the receipt of applicable regulatory approvals and requested rate decisions; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain transmission and distribution systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and commodity prices; no significant variability in interest rates; the continued competitiveness of electricity pricing when compared with other alternative sources of energy; the continued availability of commodity supply; the absence of significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of Emera; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; no material decrease in market energy sales prices; favourable labour relations; and sufficient human resources to deliver service and execute the capital program.

The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations include: commodity price and availability risk; foreign exchange risk; acquisition risk; interest rate risk; commercial relationship risk; credit risk; labour risk; weather; regulatory risk; environmental risks; operational risks; capital market risks including economic conditions, cost of financing, capital resources and liquidity risk; and construction and development risks. For additional information with respect to Emera’s risk factors, reference should be made to the section of this AIF entitled “Risk Factors”.

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

CORPORATE STRUCTURE

Name and Incorporation

Emera was incorporated on July 23, 1998 pursuant to the Companies Act (Nova Scotia). Emera’s principal, head and registered office is located at 1223 Lower Water Street, Halifax, Nova Scotia, B3J 3S8.

Intercorporate Relationships

The following organizational table sets forth the relationships between Emera and its principal subsidiaries as well as their respective jurisdictions of incorporation:

Subsidiaries (1)	Jurisdiction (2)
Nova Scotia Power Incorporated	Nova Scotia
Bangor Hydro Electric Company	Maine
Emera Brunswick Pipeline Company Ltd.	Canada
Light & Power Holdings Limited	Barbados

Notes:

(1) Emera’s direct or indirect ownership

(2) Jurisdiction of incorporation, continuance or formation

Emera’s other subsidiaries account for less than 20% of total consolidated assets, sales, and operating revenues for the year ended December 31, 2011.

GENERAL DEVELOPMENT OF THE BUSINESS

Emera is an energy and services company that invests in electricity generation, transmission and distribution as well as gas transmission and utility energy services. During the past three years, Emera sought growth from its existing businesses and leveraged its core strength in the electricity business as it pursued both acquisitions and greenfield development opportunities in regulated electricity transmission and distribution, and low risk generation through the investments noted below.

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For a discussion of the key developments in NSPI’s business and operations over the last three years, see NSPI’s Annual Information Form which is incorporated herein by reference.

Acquisition of Interest in Lucelec by LPH

Emera announced on October 4, 2011 that its wholly-owned subsidiary, ECL, agreed to sell its 19.1% interest in Lucelec at book value to LPH, also a subsidiary of Emera, for USD $26.09 million. The terms of the agreement between ECL and LPH provide for an adjustment in the sale price (either up or down) of up to USD $4 million within 30 months after the closing date. An adjustment will be triggered by an additional public offering by Lucelec or a change in its allowed ROE as a result of a change in its regulatory framework. The acquisition was subject to relevant governmental and regulatory approvals and closed on January 31, 2012.

Strategic Partnership with Algonquin Power and Utilities Corp.

Emera has an SIA with APUC 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 APUC, these include investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. Emera is committed to working with APUC on opportunities that fit within APUC’s “areas of pursuit”.

The SIA also provides for Emera to acquire up to 25% of APUC through the purchase of common shares issued by APUC to fund certain investment opportunities 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 approval by the MPUC and the rules of the TSX.

Emera and APUC are currently pursuing two 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 (USD $137.5 million), subject to final adjustments. A new utility company, California Pacific was established to own and operate the assets.

California Pacific is wholly-owned by CPUV, which in turn is owned 49.999% by Emera and 50.001% by APUC. Emera paid $31.8 million (USD $31.2 million) for its interest in the common shares of CPUV.

Pursuant to an April 2009 subscription agreement with APUC, upon the closing of the California Pacific transaction in Q1 2011, as described above, Emera exchanged subscription receipts it acquired in 2009 into 8.523 million common shares of APUC issued at $3.25 per share. As a result of this transaction, and APUC’s subsequent conversion of certain of its debentures to equity, Emera owns an approximate 5.8% equity interest in APUC as at March 26, 2012.

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Consistent with the framework established by the SIA referred to above, in April 2011 Emera agreed to sell its 49.999% 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 CPUV 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 the CPUV Subscription Receipts, the proceeds of which will be used by APUC to pay Emera for its CPUV ownership interest. The CPUV Subscription Receipts are convertible into 8.211 million shares of APUC in two tranches. 4.79 million CPUV Subscription Receipts will be exchanged for shares of APUC following applicable regulatory approval of the CPUV ownership transfer, including the MPUC approval referenced below under the subheading “First Wind”. The remainder will be exchanged upon completion of California Pacific’s first rate case, expected in 2012. The purchase of CPUV Subscription Receipts received final TSX approval.

New Hampshire Transaction

On March 25, 2011, Emera purchased 12 million New Hampshire 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 New Hampshire Subscription Receipts. The New Hampshire Subscription Receipts are convertible to 12 million common shares of APUC 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 electric utilities, currently owned by National Grid USA. The acquisitions are subject to applicable regulatory approvals and the conversion of the New Hampshire Subscription Receipts is subject to MPUC approval. The purchase of the New Hampshire Subscription Receipts also received final TSX approval.

Assuming the completion of the sale of CPUV to APUC and this transaction, 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 as required, Emera’s ownership interest in APUC will increase to approximately 17%.

First Wind

On April 30, 2011, Emera and APUC announced their intention to form a partnership with First Wind to own 370 MW of wind energy projects in the northeastern United States. On July 29, 2011, Emera purchased approximately 6.9 million First Wind Subscription Receipts from APUC at an issue price of $5.37 each for a total purchase price of $37 million which were to be convertible to approximately 6.9 million common shares of APUC immediately prior to the closing of the First Wind transaction.

As regulator of Emera’s Maine utilities, the MPUC must approve any new affiliation (being an investment in voting shares representing 10% or more of the voting shares of an entity) between Emera and certain enterprises, including those that own generation in the restructured Maine market, such as First Wind and APUC. On January 13, 2012, MPUC staff issued a report recommending that the MPUC not approve the proposed First Wind transaction, nor Emera’s plan to increase its ownership in APUC beyond 10%. Emera does not agree with the conclusions in the staff report, and outlined its concerns in a formal response filed on January 23, 2012.

APUC Withdrawal from First Wind Transaction

On January 27, 2012, APUC announced that it will not be proceeding with the First Wind investment, citing in part the longer than anticipated regulatory process in Maine, and therefore this partnership and the related conversion of the 6.9 million First Wind Subscription Receipts will no longer come into effect.

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Subject to satisfactory regulatory approval, Emera will proceed with the First Wind transaction on its own. First Wind’s assets include 385 MW of wind energy projects in the Northeastern U.S., including eight operating projects. These assets will become part of a new operating company, owned 51% by First Wind and 49% by a new Emera entity, Northeast Wind. Northeast Wind will invest a total of approximately USD $353 million to acquire its 49% interest in the operating company, including a USD $150 million loan.

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 delivered in Q2 2012.

If approved, Emera will finance the transaction through existing credit facilities subject to lender approval.

Grand Bahama Power Company Limited

On December 22, 2010, Emera purchased an additional 55.4% direct and indirect interest in GBPC for USD $88.1 million (CAD $87.7 million). The acquisition brings Emera’s direct and indirect interest in GBPC to 80.4%.

Emera acquired an initial indirect 25% interest in GBPC in September 2008 for USD $42 million through the acquisition of 50% of the shares of ICDU. ICDU owns a 50% interest in GBPC.

GBPC is an integrated utility serving 19,000 customers on Grand Bahama Island in The Bahamas, and is the only electric utility operator on Grand Bahama Island. It has 137 MW of installed oil-fired capacity. GBPA regulates GBPC and has granted the utility a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on Grand Bahama Island until 2054. There is a fuel pass-through mechanism, and flexible tariff adjustment policies ensure that GBPC’s costs are recovered and a reasonable return is earned. The purchase was funded with existing credit facilities.

Maine & Maritimes Corporation

On December 21, 2010, Emera purchased all of the outstanding shares of MAM for USD $80.4 million (CAD $81.9 million). MAM is the parent company of MPS, a regulated electric transmission and distribution utility serving approximately 36,000 electricity customers in northern Maine. MAM is also the parent company of MAM Utility Services Group, an unregulated corporation that provides electrical services, including transmission line and substation design and construction. The purchase was funded with existing credit facilities.

Light & Power Holdings Ltd.

On December 20, 2010, Emera offered to purchase all of the issued and outstanding common shares of LPH, the parent company of BLPC, at a cash price per share of BB$25.70 (Barbadian dollars) from LPH shareholders. The offer closed on January 24, 2011. On January 25, 2011, Emera purchased 7.2 million shares of LPH at a cash price per share of BB$25.70 (Barbadian dollars) representing an additional interest of 41.8%. With this additional investment of CAD $92.6 million, Emera became the majority shareholder of LPH, with a total interest of 79.98%.

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Previously, on May 11, 2010, Emera acquired a 38% interest in LPH for USD $85 million. BLPC is the sole utility operator on the island of Barbados, serving 123,000 customers. BLPC has three power generation stations with 239 MW of installed capacity. 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 ROA for 2011 is 10%. 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. This transaction was financed with existing credit facilities.

Strategic Partnership with Nalcor Energy

On November 18, 2010, Emera and Nalcor, with the endorsement of the governments of Nova Scotia and Newfoundland and Labrador, signed a term sheet which includes the obligation to negotiate and conclude final agreements for an estimated $6.2 billion hydro-electric development that would bring energy from a new hydro-electric generating facility at Muskrat Falls on the Lower Churchill River in Labrador to consumers in the Atlantic Provinces and New England. This development is expected to result in a strong regional system that enhances the ability to move energy among the Atlantic Provinces, improve reliability of the system and is consistent with Emera’s focus on cleaner, affordable electricity. The proposed agreement between Emera and Nalcor would see:

• Nalcor construct and own an estimated $2.9 billion, 824 MW hydro-electric generating facility at Muskrat Falls on the Lower Churchill River in Labrador with a planned in-service date of 2017;

• Emera and Nalcor together develop an estimated $2.1 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of the Muskrat Falls energy from Labrador to the island of Newfoundland (to be known as the “Labrador-Island Transmission Link Project”), with Emera investing in this project; and

• Emera build and own an estimated $1.2 billion transmission project between the island of Newfoundland and Nova Scotia, comprising a 180 kilometre subsea cable, in return for 20% of the energy output from Muskrat Falls for 35 years (to be known as the “Maritime Link”).

Agreements resulting from this term sheet will be subject to a number of conditions, including final approval of the boards of directors of Emera and Nalcor, approval of regulators in the Provinces of Nova Scotia and Newfoundland and Labrador, and all environmental approvals.

On December 13, 2010, ENL was incorporated as a subsidiary of Emera, holding Emera’s investment in the Maritime Link. The name of ENL was originally 63834 Newfoundland & Labrador Inc. That name was changed to Emera Newfoundland & Labrador Incorporated on February 8, 2011, and was changed to its present name, ENL Maritime Link Incorporated, on August 31, 2011. ENL Island Link Incorporated was incorporated in 2011 to hold Emera’s Investment in the Labrador-Island Transmission Link Project. Emera Newfoundland & Labrador Holdings Inc. was incorporated September 2, 2011 as a subsidiary of Emera, and became the parent of both ENL Maritime Link Incorporated and ENL Island Link Incorporated.

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Environmental Regulations – Canada

Greenhouse Gas

On August 19, 2011, Environment Canada announced proposed regulations for a new national GHG 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 once they have reached the end of their deemed economic life. These proposed regulations are expected to be published in 2012. On March 19, 2012 the governments of Canada and Nova Scotia announced that they are working towards an equivalency agreement on coal-fired electricity GHG regulations to avoid duplication of efforts to control GHG emissions. An equivalency agreement would see the provincial rules take precedence over the federal rules, as long as the provincial regulations achieve an equivalent environmental outcome. Nova Scotia’s existing GHG regulations require reductions of 25% in GHG emissions in the electricity sector by 2020. The Province plans to develop additional, increasingly stringent milestones between 2020 and 2030 to match the federal targets. See also the section entitled “General Development of the Business” in NSPI’s Annual Information Form.

Environmental Regulations – Nova Scotia

Biomass Cap

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% to 350,000 dry tonnes per year.

Renewable Electricity Plan

On October 15, 2010, the Province of Nova Scotia enacted regulations under the Electricity Act (Nova Scotia) related to the Province’s Renewable Electricity Plan. These regulations established the requirement that 25% of electricity must be supplied from renewable sources by 2015. These regulations build on previously legislated requirements for 2011 and 2013 by adding an additional 5% for 2015. Amendments to the Electricity Act, and the regulations, provided for the appointment of an independent renewable electricity administrator to conduct the procurement of at least 300 GWh of energy from IPPs to meet the 2015 standard.

On May 19, 2011, the government of Nova Scotia amended the Electricity Act (Nova Scotia) 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% in 2015 to 40% by 2020.

Mercury Emissions

On July 22, 2010, the government of Nova Scotia asked NSPI to develop a plan of staged mercury emission reductions for its generation facilities for the period of 2010 to 2020 and meet an annual cap of 35 kg beginning in 2020.

For further information regarding environmental regulations for Nova Scotia, see also the sections under the heading “General Developments of the Business” entitled – “Environmental Regulations – Canada” and “Environmental Regulations – Nova Scotia” in NSPI’s Annual Information Form.

Digby Wind Renewable Energy Project

On February 2, 2010, Emera announced its purchase of 100% of a 30 MW wind power project to be located in Digby County, Nova Scotia. Project assets acquired included development rights, a 20-year

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power purchase agreement with NSPI and rights to purchase 20 wind turbines. On May 28, 2010, NSPI purchased wind generation assets under development from a subsidiary of Emera for $30.1 million. This project went into service in December 2010. On March 9, 2011, the UARB approved a capital work order for the project, which included a substation, network upgrades and interconnection costs, in the total amount of $79.8 million. See also the section entitled “General Development of the Business” in NSPI’s Annual Information Form.

Nova Scotia Renewable Energy Standard Regulation

On October 9, 2009, the RES, which was established by the Nova Scotia government in January 2007 for the purpose of increasing the percentage of renewable energy in the Nova Scotia generation mix, was amended. Pursuant to the amendment, the target date for 5% of electricity to be supplied from post-2001 sources of renewable energy, owned by IPPs, was extended from 2010 to 2011. The target for 2013, which requires an additional 5% of renewable energy from either IPPs or NSPI, is unchanged. See also the section entitled “General Development of the Business – Nova Scotia Renewable Energy Standard Regulation” in NSPI’s Annual Information Form.

Bayside Power LP

On September 1, 2009, Emera’s subsidiary, Emera Energy, purchased a 100% interest in Bayside Power LP, which owns a 260 MW gas-fired combined cycle electricity generating facility, located in Saint John, New Brunswick. Until March 31, 2021, Bayside Power LP has a contract to supply electricity for the months of November through March. It operates as a merchant facility selling into the Maritime Provinces and, through a U.S. affiliate of Emera Energy, into the Northeastern U.S. markets for the balance of the year. Emera Energy has the option to extend the supply contract for an additional five years, through March 31, 2026.

Brunswick Pipeline

EBPC, a subsidiary of Emera, owns a natural gas pipeline that connects the Canaport^TM LNG LP owned liquefied natural gas import terminal near Saint John, New Brunswick, to markets in the Northeastern U.S. The 145 kilometre Brunswick Pipeline travels through southwest New Brunswick and connects with the Maine portion of the M&NP at the Canada/U.S. border near Baileyville, Maine. Emera has been an investor in M&NP since its inception in 1999.

Canaport^TM LNG LP is a partnership of Repsol YPF, S.A. and Irving Oil Limited. In 2006, Emera negotiated 25 year firm service and toll agreements with Repsol Energy Canada to transport natural gas through the Brunswick Pipeline. EBPC entered into agreements with M&NP’s parent, Spectra Energy Corp., an affiliate of which assisted EBPC in the Brunswick Pipeline permitting and construction process and which is currently contracted to operate the Brunswick Pipeline on EBPC’s behalf.

The project received NEB approval in the second quarter of 2007. Brunswick Pipeline commenced service on July 16, 2009.

Financing Activity

On May 19, 2010, Emera filed a short form base shelf prospectus permitting the issuance of up to an aggregate of $500 million of debt securities, including medium term notes and preferred shares.

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On May 26, 2010, Emera filed a prospectus supplement and issued 6,000,000 Series A First Preferred Shares at $25.00 per share for aggregate gross proceeds of $150 million. The Series A First Preferred Shares are convertible into Series B First Preferred Shares. For details regarding the terms of the Series A First Preferred Shares, see “Capital Structure” below.

On June 9, 2010, Emera filed a further prospectus supplement which allowed for the issuance of medium term notes with maturities of not less than 1 year and an aggregate principal amount not to exceed $350 million.

On February 18, 2011, Emera filed an amended and restated short form base shelf prospectus, amending and restating the short form base shelf prospectus dated May 19, 2010 by increasing the amount of debt securities and preferred shares permitted to be issued by Emera to up to an aggregate of $650 million.

On March 16, 2011, Emera issued a total of 6,359,500 common shares at $31.70 per common share pursuant to a short form prospectus offering of 5,530,000 common shares and the issuance of an additional 829,500 common shares pursuant to the exercise in full of the over-allotment option, for aggregate gross proceeds of $201,596,150. The short form prospectus was dated March 9, 2011.

On December 13, 2011, Emera made its first issue of medium term notes under the amended and restated short form base shelf prospectus dated February 18, 2011 and prospectus supplement dated June 9, 2010, representing $250 million in 2.96% Series H Notes. The Series H Notes bear interest at a rate of 2.69% and yield at 2.696% per annum until December 13, 2016.

On May 21, 2010, NSPI filed a short form base shelf prospectus related to the issuance of up to $500,000,000 in debt securities, including medium term notes and debentures. On June 9, 2010, NSPI filed a prospectus supplement which, together with the base shelf prospectus, provided for the issuance of up to an aggregate of $500,000,000 medium term notes. On June 15, 2010, NSPI made its first issue of medium term notes under this shelf prospectus, representing $300,000,000 5.61% Series X notes maturing on June 15, 2040.

On July 15, 2010, NSPI filed an amended and restated base shelf prospectus, amending and restating the shelf prospectus described above, which increased the amount of debt securities available for issue under the shelf program back to up to $500,000,000 in debt securities.

On May 13, 2011, NSPI filed Amendment No. 1 to the amended and restated base shelf prospectus which increased the amount of debt securities available for issue under the shelf program to $800,000,000 in debt securities, and filed Amendment No. 1 to the prospectus supplement to increase the aggregate principal amount of medium term notes offered from time to time under the shelf program to $800,000,000.

On March 6, 2012, NSPI made its second issue of medium term notes under the shelf program, representing $250,000,000 4.15% Series Y Notes maturing on March 6, 2042.

On January 25, 2012, GBPC entered into an unsecured credit agreement with Scotiabank (Bahamas) Limited in the amount of USD $56.2 million. 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 plus 1.2 % 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.

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On January 31, 2012, Bangor Hydro completed the issue of an unsecured USD $70 million senior note. The Series 2012-A Senior Note bears interest at 3.61% per annum until January 31, 2022.

On February 9, 2012, LPH Caribbean Holdings Ltd. entered into a secured credit agreement with The Bank of Nova Scotia in the amount of USD $14.2 million. The proceeds of the credit agreement were used to finance the purchase of a 19.1% interest in Lucelec from ECL. The credit agreement bears interest at a rate of the three month LIBOR plus 1.05% and is repayable in six equal, consecutive semi-annual instalments over a three year period. The payments commence six months after the initial drawdown. LPH has provided a cash deposit of BB $28.4 million (Barbadian dollars) and an unlimited guarantee as security for the credit agreement.

Emera has the following revolving $700 million credit facility for operating and acquisition financing requirements:

	Matures	Maximum Amount (millions  of dollars)
Short-term
4 Year revolving operating and acquisition credit facility	June 25, 2015	$	700.0	1

Note:

(1) In 2011, Emera amended the revolving credit facility by increasing it from $600 million to $700 million and extending its maturity until June 2015. As of March 15, 2012, $200.4 million was drawn down, leaving $499.6 million available credit under the facility.

Bangor Hydro has established the following credit facilities:

	Matures	Maximum Amount (millions  of US dollars)
Short-term
39 month revolving operating credit facility	September 23, 2013	$	80.0	1

Note:

(1) As of March 15, 2012, USD $4.0 million was drawn down, leaving $76.0 million available credit under the facility.

See also the section entitled “General Development of the Business – Financing Activity” in NSPI’s Annual Information Form.

U. S. Securities and Exchange Commission Registration and Transition to USGAAP

In 2008, the Canadian Institute of Chartered Accountants announced that CGAAP for publicly accountable enterprises would be replaced by IFRS for fiscal years beginning on or after January 1, 2011. Due primarily to the continued uncertainty around the applicability of a rate-regulated accounting standard under IFRS, Emera’s Board approved the transition to USGAAP instead of IFRS. 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.

Emera transitioned to USGAAP on January 1, 2011 and restated the 2010 comparative period for Emera’s 2011 financial statements.

On February 23, 2011, Emera filed a shelf registration statement with the SEC under the U.S. Securities Act of 1933, as amended, to register certain of its investment grade debt securities and

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preferred shares. On the same day, Emera registered its debt securities, First Preferred Shares and Second Preferred Shares under the US Securities Act of 1933, as amended. As a result of these registrations, Emera has reporting obligations under U.S. securities laws.

On October 5, 2011, Emera also registered its common shares under the U.S. Securities Act of 1933, as amended. On March 20, 2012, Emera filed with the SEC a post-effective amendment to its Form F-9 registration statement removing from registration its debt securities, First Preferred Shares and Second Preferred Shares. Emera continues to have reporting obligations under U.S. securities laws by virtue of the registration of its common shares.

Documents filed with the SEC are available to the public and can be viewed on the Electronic Data Gathering, Analysis, and Retrieval system (or EDGAR) website at www.sec.gov/edgar/searchedgar.

Changes in Business Expected During Current Year

Emera will continue to pursue investment opportunities related to the transformation of the energy industry to lower emissions. Emera’s subsidiaries have embarked on capital plans to increase generation from renewable sources, to improve the transmission connections within their 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% to 5% 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

Income from Emera’s Maine utility operations is expected to be higher in 2012 compared to 2011 due to the recovery of investments in new transmission assets. In 2012, Bangor Hydro, MAM and MPS expect to invest approximately USD $116 million in the aggregate, including approximately USD $78 million for major transmission projects.

Caribbean Utility Operations

Income from Emera’s Caribbean utility operations is expected to be higher in 2012 compared to 2011 primarily as a result of increased investments in LPH and GBPC. The Caribbean utilities plan to invest approximately $63 million in capital programs in 2012.

Pipelines

Income from Emera’s 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.

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DESCRIPTION OF THE BUSINESS

General

Emera is an energy and services company headquartered in Halifax, Nova Scotia with $6.9 billion in assets. 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 in the Atlantic Provinces, Maine, Massachusetts in three Caribbean countries and in California. Approximately 80% of Emera’s consolidated revenues are earned by its rate-regulated subsidiaries, including NSPI, Emera’s Maine and Caribbean utility operations, and EBPC:

• NSPI provides more than 95% of the electricity generation, transmission and distribution service in the Province of Nova Scotia. NSPI has $3.9 billion in assets, and approximately 493,000 customers. NSPI is regulated by the UARB under a cost-of-service utility model, with rates set to enable NSPI to recover all prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI operates as a monopoly in its service area. NSPI’s target regulated ROE range for 2011 was 9.1% to 9.6%, based on an actual average regulated common equity component of up to 40% of regulated capitalization. The 2012 general rate decision adjusted the 2012 ROE range to 9.1% to 9.5%.

• Emera’s Maine utility operations include Bangor Hydro, MPS and MAM. Bangor Hydro is an electricity transmission and distribution company with USD $806.8 million of assets serving approximately 118,000 customers in eastern Maine. Bangor Hydro’s transmission operations are regulated by FERC, and its distribution operations are regulated by the MPUC. MPS, a wholly-owned subsidiary of MAM, is a regulated transmission and distribution electric utility with approximately USD $139.6 million of assets serving 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 the transmission and distribution networks of Bangor Hydro and MPS. Both utilities operate under a traditional cost-of-service regulatory structure.

• Emera’s Caribbean utility operations consist of an 80.4% interest, held directly and indirectly, in GBPC; a 79.98% indirect interest in BLPC; and a 19.1% interest in Lucelec. GBPC is a vertically-integrated utility and the sole provider of electricity on Grand Bahama Island in the Bahamas. GBPC serves 19,000 customers and is regulated by GBPA which has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. Emera holds its indirect interest in GBPC through ICDU, which in turn owns a 50% interest in GBPC. ICDU is listed on the Bahamas International Securities Exchange. BLPC is a vertically-integrated utility and the sole electric utility operator on the Caribbean island of Barbados which serves approximately 123,000 customers and is regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted to BLPC a franchise to produce, transmit and distribute electricity on the island until 2028. Emera acquired its interest in BLPC through the purchase of 79.98% of the outstanding common shares of LPH, the parent company of BLPC. Lucelec is a vertically-integrated electric utility on the Caribbean island of St. Lucia. Lucelec is listed on the Eastern Caribbean Securities Exchange.

• EBPC is a natural gas pipeline company that owns the Brunswick Pipeline, a 145-kilometre pipeline carrying re-gasified liquefied natural gas from the Canaport^TM LNG LP terminal near

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Saint John, New Brunswick to markets in the Northeastern U.S. This federally regulated pipeline received NEB approval for shipping gas in January 2009 and commenced service on July 16, 2009, transporting re-gasified liquid natural gas for Repsol Energy Canada under a 25 year firm service agreement.

The success of Emera’s primary business is integral to the creation of shareholder value, providing strong, predictable earnings and growing cash flow to fund dividends and reinvestment. The essential nature of the services provided, the monopoly positions of NSPI, Bangor Hydro, BLPC, GBPC, and MPS, and their regulated market structures mean that NSPI and Bangor Hydro can generally be expected to produce stable earnings streams within regulated ranges. Although markets in the Province of Nova Scotia and the State of Maine are otherwise mature, the transformation of energy supply to lower emission sources has created the opportunity for organic growth within NSPI, Bangor Hydro and MPS.

Through EBPC and other strategic investments, Emera looks beyond its existing regulated electricity business to supplement organic growth. Emera’s goal is to increase earnings per share by an average of 4% to 6% annually and to build and diversify its income base with a focus on cleaner energy in its markets. To accomplish this, 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 low risk generation.

Emera has grown its business through additional strategic investments and activities that include:

• Bear Swamp, a 50% interest in a 600 MW pumped storage hydro-electric facility in Northern Massachusetts. Bear Swamp pumps water into its reservoir using lower priced off-peak power, and uses that hydro capacity to generate electricity during higher priced on-peak periods;

• a 49.99% interest in CPUV, the parent of California Pacific, a California based electricity distribution and generation utility;

• a 37.7% interest in Atlantic Hydrogen, a privately held New Brunswick corporation headquartered in Fredericton, New Brunswick that is developing greener energy solutions;

• a 12.9% interest in the $2 billion, 1,400 kilometer M&NP, which transports natural gas from offshore Nova Scotia to markets in the Maritime Provinces and the Northeastern U.S.;

• a 7.5% equity interest in OpenHydro, an Irish renewable energy company;

• a 5.8% interest in APUC, an Ontario based company that owns and operates a diversified portfolio of renewable energy and utility businesses through its subsidiaries;

• Emera Energy, a physical energy business which purchases and sells natural gas and electricity on behalf of third parties and provides related energy asset management services in Canada and, through its subsidiary, Emera Energy Services, in the U.S.;

• ENL referred to above;

• Emera’s investment in MAM referred to above;

• Emera Energy’s investment in Bayside Power LP referred to above;

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• EUS, a utility services contractor serving primarily power and telecommunications customers throughout the Atlantic Provinces; and

• Certain corporate-wide functions such as executive management, strategic planning, treasury services, financial reporting, tax planning, business development, corporate governance, and interest expense and income taxes associated with Emera’s business outside of its regulated electric utilities.

For information related to Emera’s consolidated revenues for the years ended December 31, 2011, December 31, 2010 and December 31, 2009, see the “Consolidated Financial Highlights” and “Emera Consolidated Statements of Income” sections in Emera’s MD&A.

Nova Scotia Power Inc.

See NSPI’s Annual Information Form which is incorporated herein by reference.

Maine Utility Operations

Emera’s Maine utility operations are comprised of Bangor Hydro, MPS and MAM. On December 21, 2010, Emera purchased all the outstanding shares of MAM. MAM is the parent company of MPS, a regulated electric transmission and distribution utility serving approximately 36,000 electricity customers in northern Maine. MAM is also the parent company of MAM Utility Services Group, an unregulated corporation that provides electrical services, including transmission line and substation design and construction.

Bangor Hydro and MPS are both transmission and distribution electric utilities. Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through both utilities transmission and distribution networks. Each company’s distribution operations and stranded cost recoveries are regulated by MPUC and their transmission operations are regulated by FERC.

Bangor Hydro is the second largest electric utility in Maine. Bangor Hydro owns and operates approximately 1,000 kilometres of transmission facilities and 7,200 kilometres of distribution facilities, and serves approximately 118,000 customers in eastern Maine. Bangor currently has a workforce of approximately 300 people.

In December 2010, Bangor Hydro’s 345 kilo-volt substation located on Keene Road in the State of Maine was completed at a total cost of approximately USD $33.0 million.

In December 2011, Bangor Hydro’s Line 64 Rebuild was completed at a total cost of approximately USD $34.9 million.

MPS owns and operates approximately 600 kilometres of transmission facilities, and 2,900 kilometres of distribution facilities. MPS’ workforce is approximately 125 people.

The Maine utility operations currently have approximately USD $150 million of additional transmission development in progress.

Bangor Hydro, MPS and MAM contributed to consolidated net income by USD $37.4 million in 2011 and USD $30.9 million in 2010 (adjusted).

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Distribution

The distribution services of Bangor Hydro and MPS operate under traditional cost-of-service regulatory structures. Distribution rates are set based on allowed ROE of 10.2%, on a common equity component of 50%.

Transmission

Bangor Hydro’s local transmission rates are set by FERC annually on June 1, based on a formula that utilizes prior year actual transmission investments and expenses, adjusted for current year forecasted transmission investments and expenses. 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% (2010 – increased 37%).

Bangor Hydro’s bulk transmission assets are managed by the ISO-New England as part of a region-wide pool of assets. The ISO-New England 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% to 12.64%, 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.

MPS transmission rates are set annually based on a formula through the 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%, 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. The last OATT formula change year was 2009. On June 1, 2011, MPS’ local transmission rates increased by 3% for wholesale customers (2010 – increased 63%) and by 4% for retail customers (2010 – increased by 64%) on July 1, 2011.

Stranded Costs

In addition to transmission and distribution assets, Bangor Hydro and MPS have net regulatory assets (or “stranded costs”), which arose through the restructuring of the electricity industry in the State of Maine in the late 1990s, and as a result of rate and accounting orders issued by its regulator. Pursuant to the Maine restructuring law, effective March 1, 2000, electric utilities in Maine are entitled to recover all prudently incurred stranded costs that resulted from the restructuring law that cannot reasonably be mitigated. Generally, the regulated rates to recover stranded costs are set every three years on a levelized basis and determined under a traditional cost of service approach.

The net regulatory assets of Bangor Hydro and MPS primarily include the costs associated with the restructuring of an above-market power purchase contract, and the unamortized portion on the loss on the sale of an investment in the Seabrook nuclear facility. Unlike transmission and distribution

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operational assets, which are generally sustained with new investment, the net 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 with full reconciliation for over or under recovery.

These net regulatory assets of Bangor Hydro total approximately USD $65.3 million at December 31, 2011 (USD $74.9 million at December 31, 2010) or 8% of Bangor Hydro’s net asset base (10% at December 31, 2010).

The net regulatory assets of MPS total approximately USD $20.5 million at December 31, 2011 ($28.5 million at December 31, 2010), or 29% of MPS’ net asset base.

In May 2011, the MPUC issued an order approving an increase of approximately 27% in Bangor Hydro’s stranded cost rates for the period from 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 (or “annual stranded costs”). The allowed ROE used in setting these new stranded cost rates is 7.4%, with a common equity component of 48%. 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 level 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.

In March 2010, the MPUC issued an order approving a settlement stipulation in which MPS’s stranded cost rates remained the same as in the previous three-year agreement. This revised two-year agreement, which expired on December 31, 2011, had an ROE of 9.6% for the first year and 8.6% for the second year, and a common equity component of 50%. MPS uses its deferred fuel balance from an expired power purchase contract in order to level rates.

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

In January 2010, the MPUC approved Bangor Hydro’s Smart Grid initiative, under which Bangor Hydro will invest approximately USD $8 million in advanced metering infrastructure meters. These meters are already deployed to 97% of Bangor Hydro’s customers and are used for automated meter reading and outage detection.

Capital Expenditures

Capital expenditures for the Maine utility operations for 2011 were approximately USD $100 million (December 31, 2010 – USD $44.3 million). The capital expenditure budget is approximately USD $117 million for 2012.

Environmental Considerations

Bangor Hydro and MPS are regulated by the U.S. Environmental Protection Agency for compliance with the Federal Water Pollution Control Act, the Clean Air Act, and other U.S. federal statutes governing the treatment and disposal of hazardous wastes. Bangor Hydro and MPS are also regulated by the State of Maine’s Department of Environmental Protection.

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Caribbean Utility Operations

Emera’s Caribbean utility operations consist of its interests in BLPC, GBPC and Lucelec.

BLPC, a wholly-owned subsidiary of LPH, is the sole provider of electricity on the Caribbean island of Barbados. BLPC is subject to regulation under the Utilities Rules by the Fair Trading Commission, Barbados. The Utilities Rules give the Barbados Commission 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 ROA for 2011 is 10%. 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.

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

GBPC is the sole provider of electricity on Grand Bahama Island. The 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 current base fuel tariff is calculated based on a price of USD $20 per barrel of oil. The amount by which actual fuel costs exceed USD $20 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 the GBPA.

On April 12, 2011, the GBPA approved the recovery of the net costs of leasing temporary generation to meet peak demand for electricity as part of the fuel surcharge; and a 4.5% base tariff rate increase effective January 1, 2011. The collection from customers of the 4.5% base tariff increase will be deferred and recorded as a regulatory asset until the commission of the new 52 MW diesel generation unit scheduled to be on line in mid-2012, at which time the regulatory asset will be amortized into earnings. The GBPA also approved the amortization over a 5 year period of the remaining book value and reclamation costs of generation units that may be retired as a result of the commissioning of the new 52 MW diesel facility and a 2012 tariff rate increase to provide GPBC with a 10% return on rate base.

On July 14, 2011, the GBPA approved the recovery of a $4.6 million asset impairment charge recorded in 2010. As a result, the charge was reversed through earnings in the third quarter of 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 generation facility referred to above.

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Lucelec is a vertically-integrated electric utility on the Caribbean island of St. Lucia. Lucelec is listed on the Eastern Caribbean Securities Exchange.

Pipelines

Emera’s pipeline business consists of its interests in the Brunswick Pipeline and the M&NP.

EBPC, a wholly-owned subsidiary of Emera, owns the Brunswick Pipeline which delivers natural gas from the Canaport^TM LNG LP owned import terminal near Saint John, New Brunswick to markets in the Northeastern U.S. The Brunswick Pipeline is classified as a Group 2 pipeline by the NEB. The pipeline went into service in July 2009.

Emera has a 12.9% interest in the M&NP which transports natural gas from offshore Nova Scotia to markets in the Maritime Provinces and New England by connecting with the Brunswick Pipeline near Baileyville, Maine.

New Head Office

The principal, head and registered office of Emera relocated, effective in the fall of 2011, to 1223 Lower Water Street, Halifax, Nova Scotia, B3J 3S8.

Emera Employees

Emera and its subsidiaries had approximately 3,500 employees at December 31, 2011, approximately 55% of whom are unionized. NSPI entered into an agreement in 2007 with approximately 900 unionized employees which will expire in March 2012. Bangor Hydro entered into a new collective agreement in July 2010, which will expire in July, 2015. MPS also has a contract with its unionized employees which will expire in October 2013. BLPC has a contract with its unionized employees which expired on December 31, 2011. GBPC has two unionized contracts, one with its management union which expired on December 31, 2004 and one with its workers union which expires on March 31, 2013. See also the section entitled “Risk Factors – Labour Risk” in this AIF.

Emera Environmental Matters

See the “Changes in Environmental Legislation” section of Emera’s MD&A. See also the “Environmental Matters” section of NSPI’s Annual Information Form.

Emera Taxation

See the “Provincial Grants and Taxes” section of the MD&A and see the “Income Taxes” sections of the MD&A for each of NSPI and Emera.

Risk Factors

Emera has a business-wide risk management program where development and implementation of the risk management framework is overseen by the Board of Directors. The identification and assessment of principal risks and the development of monitoring and mitigation strategies are the responsibility of management, with certain risk management activities being overseen by a management Enterprise Risk Management Committee. Under the Board of Directors Charter, the Board is responsible for considering Emera’s risk profile and overseeing Emera’s risk management by reviewing:

(a) the annual identification and assessment of the principal risks of Emera;

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(b) the process for ongoing monitoring and reporting of the principal risks of Emera;

(c) the effectiveness of Emera’s mitigation response to its principal risks; and

(d) the alignment of risk management with Emera’s risk profile, its strategy, and its organizational objectives, including capital and resources allocation.

In 2011, the Board oversaw the development of a comprehensive regular risk report in which management would outline mitigation strategies for the Company’s principal risks, determine trends associated with the risks, and identify responsibility for management and oversight of the risks.

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 risk, regulatory risks, and changes in environmental legislation. For additional information on the risk factors associated with NSPI, see the “Risk Factors” section in NSPI’s Annual Information Form.

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.

The following is a summary of the significant risk factors identified by Emera:

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. Emera seeks to manage this risk through the use of financial hedging instruments and physical contracts. In addition, the adoption and implementation of fuel adjustment mechanisms in certain subsidiaries has further helped manage this risk.

Coal/Petroleum Coke. A substantial portion of NSPI’s coal and petroleum coke supply comes from international suppliers, which are contracted at or near the market prices prevailing at the time of contract. NSPI has entered into fixed-price and index price contractual arrangements 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 petroleum coke requirements contracted at December 31, 2011 is as follows:

• 2012 – 94%

• 2013 – 32%

• 2014 – 15%

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 and the forecast that it will not burn a material amount of heavy fuel oil.

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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 38,388 MMBTU of natural gas per day in 2012, and 20,110 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. Gas volumes not required for generation will be resold into the gas market with the margin hedged using financial instruments. As at December 31, 2011, amounts of natural gas volumes that have been economically and/or financially hedged and contracted are approximately as follows:

• 2012 – 83%

• 2013 – 31%

Bayside Power LP has multi-year contracts to purchase approximately 36,500 MMBTU of natural gas per day through 2015; and an additional 7,000 MMBTU per day through 2012, at market index prices. During its annual November through March PPA period, Bayside Power LP’s commodity price exposure is substantially hedged via the PPA contract, except in the case of an unplanned outage. From April through October each year, as the plant contracts for electricity sales, pricing on the related gas volumes is hedged using financial instruments. Any amounts available for resale are sold against market prices. As at December 31, 2011, amounts of natural gas volumes that have been hedged are approximately as follows:

• 2012 – 39%

• 2013 – 39%

• 2014 – 39%

• 2015 – 39%

Purchased Power. Emera and its joint venture partner entered into a contract with Bear Swamp to fix the price of power necessary to produce the energy requirements of the LIPA contract. As at December 31, 2011, amounts of purchased power Emera has hedged are approximately as follows:

2012 – 95%

• 2013 – 95%

• 2014 – 95%

• 2015 – 94%

Foreign Exchange Risk

Emera 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 % of its anticipated net fuel costs to be denominated in USD. Forward contracts to buy USD $256.0 million were in place as at December 31, 2011 at a weighted average rate of $0.9912, representing 81 % of 2012’s anticipated USD requirements. Forward contracts to buy USD $752.0 million in 2013 through 2016 at a weighted

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average rate of $1.0096 were in place as at December 31, 2011. These contracts cover 60 % 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 LP uses foreign exchange forward contracts to hedge the currency risk for capital projects denominated in foreign currencies. Forward contracts to buy EUR 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 EUR 2.8 million were in place as at December 31, 2011 at a weighted average rate of $1.3951 for capital projects in 2015.

Brunswick Pipeline. EBPC, the owner of Brunswick Pipeline uses forward contracts to hedge the currency risk associated with revenue streams denominated in foreign currencies. Forward contracts to sell USD $53.8 million in 2012 were in place as at December 31, 2011 at an average rate of $1.0654 and sell USD $78 million in 2013 through 2016 at a weighted average rate of $1.0591. These contracts cover 95% of anticipated USD revenue inflows in 2012 and 33% 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 conducting due diligence, integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to monitoring and review by the Board.

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. Emera 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% 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 USD $22.6 million 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% (2010 – 14.7 %) 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 (Canada) (the “CCCA”), and suspended operations in September 2011. This customer contributed approximately 6.0% (2010 – 7.9%) of NSPI’s electric revenues for the year

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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.

Brunswick Pipeline. EBPC, the owner of 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 EBPC 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 LP sells all its generation during the months of November through March to NB Power in accordance with a long-term purchase power agreement (the “PPA”). Revenue from this PPA contributed 46.5% (2010 – 48.0%) to Bayside Power LP’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

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

NSPI has a contract with its union which will expire in 2012. Bangor Hydro entered into a new collective bargaining agreement in July 2010, which will expire in July, 2015. MPS also has a contract with its unionized employees which will expire in October, 2013. GBPC has a labour agreement with the Commonwealth Electrical Workers Union which expires on March 31, 2013. It also had an agreement with the Bahamas Industrial Engineers, Managerial & Supervisory Union which expired on December 2004, and management and the union continue to engage. BLPC has an agreement with the Barbados Workers Union which ended December, 2011 in respect of the administrative support group. Management and the union are in discussions with the operations group to negotiate their contract which expired in June, 2010.

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Weather

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. 

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, where possible, 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%, on a common equity component of 50%.

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%. 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% (2010 - increased 37%).

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

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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% to 12.64%, 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%; and on June 1, 2011, it increased by a further 9%.

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% 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%, with a common equity component of 48%.

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%, on a common equity component of 50%.

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%, 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% for wholesale customers (2010 – increased 63%) and by 4% for retail customers (2010 – increased by 64%) on July 1, 2011.

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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% and a common equity component of 50%. Any residual stranded costs remaining after December 31, 2014 will be recovered in future rate proceedings.

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 (the “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 ROA for 2011 is 10%.

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 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 USD $20 per barrel of oil consumed by GBPC for generation of electricity. The amount by which actual fuel costs exceed USD $20 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.

Environment

Emera is subject to regulation by federal, provincial and municipal 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.

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Corporate Environmental Governance. 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 policies. Emera and its wholly-owned subsidiaries have implemented this policy through the development and application of EMS.

Implementation of EMS has provided a systematic focus on environmental issues so risks are identified and managed proactively. All areas of Emera’s business continued initiatives commenced in 2010 to reduce potential environmental risks and associated costs. Activities included reducing air emissions, protecting water resources, and continued management of polychlorinated biphenyl (or PCB) contaminated electrical equipment.

Conformance with legislative and Company requirements are verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the 2011 audits. Plans are in place to promptly address any audit findings and continually improve the environmental management of Emera’s operations.

Oversight of environmental matters is carried out by the boards of directors of all Emera operating companies or committees of the boards with specific environmental responsibilities. In addition, an Environmental Council, made up of senior Emera employees, with working accountability for environmental matters, continues to guide the implementation of programs that address key environmental issues. In addition to programs involving employees, the EMS procedures of all wholly-owned subsidiaries include planning, implementing and monitoring of contractors’ performance.

NSPI’s IRP includes current environmental requirements and assumptions on future regulations as constraints on possible generation plans. This allows the development of revised generation plans for the future. NSPI stakeholders were engaged in the assumptions and the scenarios to be modelled. The results of the planning activities can be found on the NSPI website at www.nspower.ca.

In 2007, NSPI was audited by the CEA to verify the quality of its environmental reporting and management systems. The auditor from the CEA concluded that NSPI had “robust programs, environmental leadership and a strong, mature EMS”. In 2011, a review of NSPI’s EMS by an accredited ISO 14001 auditor determined that the EMS was strong, focused with engaged staff and would be considered ISO 14001 equivalent.

Environmental Regulation. NSPI produces its electrical energy from coal and petroleum coke (approximately 60%) and natural gas and/or oil (approximately 20%). As such, it is subject to regulation with respect to air pollutants and GHG emissions. NSPI operates under a cost-of-service regulation model. Accordingly, all prudently incurred costs, including those capital and operating costs associated with meeting present and future environmental liabilities, will be recovered in rates collected from customers.

NSPI is subject to environmental regulation as set by both Canadian and Nova Scotia governments. NSPI is in material compliance with all current environmental regulations. All required permits are in place for NSPI’s generating stations. These permits are generally for a ten year period but can be subject to review, variation, or suspension by the Minister of Environment of Nova Scotia.

Bangor Hydro and MPS are regulated by the U.S. Environmental Protection Agency as to compliance with the Federal Water Pollution Control Act, the Clean Air Act, and other U.S. federal statutes governing the treatment and disposal of hazardous wastes. Bangor Hydro and MPS are also regulated by the State of Maine’s Department of Environmental Protection.

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Brunswick Pipeline is a federally regulated undertaking and must operate in accordance with the National Energy Board Act (Canada), the Onshore Pipeline Regulations, 1999, the Canada Labour Code (Canada), Part II, the Canadian Environmental Protection Act (Canada), and any applicable provincial environmental regulations.

Climate Change and Air Emissions

Greenhouse Gas Emissions

NSPI has stabilized, and in recent years, reduced GHG 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.

GHG 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. These proposed regulations are expected to be published in 2012. In March, 2012 the governments of Canada and Nova Scotia announced that they are working towards an equivalency agreement on coal-fired electricity GHG regulations to avoid duplication of efforts to control GHG emissions. An equivalency agreement would see the provincial rules take precedence over the federal rules, as long as the provincial regulations achieve an equivalent environmental outcome. Nova Scotia’s existing GHG regulations require reductions of 25% in GHG emissions in the electricity sector by 2020. The Province plans to develop additional, increasingly stringent milestones between 2020 and 2030 to match the federal targets. NSPI is 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% 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% of renewable energy, is unchanged.

In May, 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% in 2015, to 40% by 2020.

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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.

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% effective 2014, nitrogen oxide by 40% effective 2009 and sulphur dioxide by 50% effective 2010.

Capital Markets

Emera generates cash primarily through its operations in regulated utilities. Circumstances that could affect the Company’s ability to generate cash include economic downturns in Emera’s markets and regulatory decisions affecting customer rates.

Volatility in the global capital markets can increase the cost, and affect the timing, of the issuance of long-term capital by the Company and its utilities. While the cost of borrowing may increase, the Company and its utilities expect to continue to have reasonable access to capital in the future. Based on expected cash from operations, Emera believes it has sufficient funds available to finance its projected growth, including capital expenditures and operations. However, if cash flow from operations is lower than expected, or if Emera incurs major unanticipated expenses related to development or maintenance of its existing assets, it may be required to seek additional capital to maintain, and/or adjust, planned expenditures levels.

Construction and Development

The development, construction and future operation of electricity generation, transmission and distribution, gas transmission and power facilities can be affected adversely by changes in government policy and regulation, environmental concerns, increases in capital and construction costs, construction delays, increases in interest rates and competition in the industry. In the event that any one of these factors emerges, the actual results may vary materially from projections, including projections of costs, power production, future revenue and earnings. The construction and development of Emera’s transmission and distribution projects and their future operations are subject to changes in the policies and laws of both Canadian and U.S. federal, provincial and State governments, and the governments in the Caribbean where Emera owns assets, including regulatory approvals and regulations relating to the environment, land use, health, conflicts of interest with other parties and other matters beyond the direct control of Emera. Changes in operating legislation may be in a manner which adversely affects Emera through the imposition of restrictions on its

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business activities or by the introduction of regulations that increase Emera’s operating costs thereby indirectly affecting Emera and potentially reducing dividends to shareholders. Income tax laws relating to Emera may be changed in a manner which adversely affects shareholders.

CAPITAL STRUCTURE

The authorized capital of Emera consists of an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares. Each class of preferred shares are issuable in series. As at December 31, 2011, 122,830,102 common shares, 6,000,000 Series A First Preferred Shares and no second preferred shares were issued and outstanding.

Common Shares

The holders of common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Emera, other than separate meetings of holders of any other class or series of shares, and to one vote for each common share on all matters to be voted on by the shareholders. Shareholders are entitled to receive on a pro rata basis such dividends as may be declared by the Directors out of funds legally available to Emera for the payment of the dividends. The common shares rank junior to the rights of the holders of all outstanding preferred shares as to the payment of dividends, and as to repayment of capital in the event of liquidation, dissolution or winding-up, whether voluntary or involuntary, or any other distribution of the assets of Emera among shareholders for the purpose of winding-up its affairs. Each common share is equal to every other common share and all common shares participate equally on liquidation or distribution of assets. There are no pre-emptive, redemption, purchase or conversion rights attaching to the common shares. The foregoing description is subject to the “Share Ownership Restrictions” section below.

First Preferred Shares

Series A First Preferred Shares

Emera has 6,000,000 Series A First Preferred Shares issued and outstanding. The holders of Series A First Preferred Shares will not be entitled to vote at any meetings of the shareholders of Emera, except where entitled by law and except for meetings of the holders of Series A First Preferred Shares, or if Emera fails to pay, from time to time, in the aggregate, eight quarterly dividends on any series of the First Preferred Shares on the dates on which the same should be paid according to their terms. In any instance where the holders of Series A First Preferred Shares are entitled to vote, each holder shall have one vote for each Series A Preferred Shares.

Each Series A First Preferred Share is entitled from the date of issue until August 14, 2015 to a fixed dividend of $0.2750 per share per quarter (an initial dividend was payable on August 16, 2010 of $0.2230 per share based on the June 2, 2010 closing). For each five year period after August 15, 2015, the holders of Series A First Preferred Shares will be entitled to receive a fixed cumulative preferential cash dividend, payable quarterly and determined by multiplying the annual fixed dividend rate, equal to the sum of the government of Canada yield on the applicable fixed rate calculation plus 1.84%, by $25.00

The Series A First Preferred Shares will not be redeemable by Emera prior to August 15, 2015. On that date and on August 15 every 5 years thereafter, Emera may redeem all or any part of the outstanding Series A First Preferred Shares at a rate of $25.00 per share plus any accrued and unpaid dividends.

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Subject to the automatic conversion and the redemption of the Series A First Preferred Shares by Emera, on August 15, 2015 and on August 15 every five years thereafter, upon thirty days notice, the holders of Series A First Preferred Shares may convert any or all of their Series A First Preferred Shares into an equal number of Series B First Preferred Shares. In addition, the Series A First Preferred shares may be automatically converted by Emera into Series B First Preferred Shares if Emera determines that there are less than 1,000,000 Series A First Preferred Shares.

Series A First Preferred Shares rank on parity with all other series of first preferred shares.

Series B First Preferred Shares

Currently, there are no Series B First Preferred Shares issued and outstanding.

The holders of Series B First Preferred Shares will be entitled to receive floating rate cumulative preferential cash dividends, as and when declared by the Board. Series B First Preferred shares are redeemable by Emera on not more than sixty days notice nor less than thirty days notice at an amount equal to (i) $25.00 together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on August 15, 2020 and on August 15 every 5 years thereafter or (ii) $25.50 together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2015.

Series B First Preferred Shares may be converted into an equal number of Series A First Preferred Shares on August 15, 2015 and on August 15 every 5 years thereafter. Series B First Preferred Shares may be automatically converted by Emera into Series A First Preferred Shares if Emera determines that there are less than 1,000,000 Series B First Preferred Shares.

Series B first preferred shares rank on parity will all other series of first preferred shares.

Second Preferred Shares

Currently, there are no second preferred shares issued and outstanding.

The second preferred shares have special rights, privileges, restrictions and conditions substantially similar to the first preferred shares, except that the second preferred shares rank junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Emera in the event of liquidation, dissolution or winding-up of Emera.

Share Ownership Restrictions

As required by the Nova Scotia Power Reorganization (1998) Act (Nova Scotia) and pursuant to the Nova Scotia Power Privatization Act (Nova Scotia), the articles of association of Emera provide that no person, together with associates thereof, may subscribe for, have transferred to that person, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, or vote, in the aggregate, voting shares of Emera to which are attached more than 15% of the votes attached to all outstanding voting shares of Emera. Non-residents of Canada may not subscribe for, have transferred to them, hold, beneficially own or control, directly or indirectly, otherwise than by way of security only, or vote, in the aggregate, voting shares of Emera to which are attached more than 25% of the votes attached to all outstanding voting shares of Emera. Votes cast by non-residents on any resolution at a meeting of common shareholders of Emera will be pro-rated so that such votes will not constitute more than 25% of the total number of votes cast.

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The common shares and Series A First Preferred Shares are considered to be voting shares for purposes of the constraints on share ownership.

Emera’s articles of association contain provisions for the enforcement of these constraints on share ownership, including provisions for suspension of voting rights, forfeiture of dividends, prohibitions of share transfer and issuance, compulsory sale of shares and redemption, and suspension of other shareholder rights.

Ratings

Emera has the following credit ratings by the Rating Agencies ^{( 1)}:

	DBRS		S&P
	2011	2010	2011	2010
Corporate	N/A	N/A	BBB+	BBB+
Senior unsecured debt program	BBB (high)	BBB (high)	BBB	BBB
Series A First Preferred Shares	Pfd3 (high)	Pfd3 (high)	P-2 (low)	P-2 (low)

Note:

(1) Ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities. The credit ratings assigned by the Rating Agencies are not recommendations to buy, sell or hold securities inasmuch as such ratings do not comment as to relevant price or suitability for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a Rating Agency in the future if in its judgment circumstances so warrant.

Dominion Bond Rating Service Limited

Dominion Bond Rating Service Limited’s (“DBRS”) credit ratings are on a long term debt rating scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB (high) from DBRS with respect to senior unsecured debt is characterized as “adequate credit quality” and is the fourth highest of ten available rating categories. The capacity for the repayment of financial obligations is considered acceptable. Entities rated BBB may be vulnerable to future events. The assignment of a “(high)” or “(low)” designation indicates relative standing within such category.

With respect to the Series A First Preferred Shares, the rating of Pfd-3 (high) is the highest of three sub-categories within the third highest rating of six standard categories of ratings utilized by DBRS for preferred shares.

There were no changes in DBRS’s ratings for Emera in 2010 and 2011.

Standard & Poor’s

Standard & Poor’s (“S&P”) credit ratings are on a long term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB+ obtained from S&P in respect of the corporate rating is characterized as having “adequate credit quality” and is the fourth highest of ten available rating categories. The rating of BBB from S&P in respect of the senior unsecured debt is characterized as adequate credit quality and is the fourth highest of ten available ratings categories. According to the S&P rating system, an obligor with debt

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securities rated BBB has adequate capacity to meet its financial commitments. However, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments. The addition of a “(+)” or “(-)” designation after a rating indicates the relative standing within a particular category.

A P-2 (low) rating with respect to Emera’s Series A First Preferred Shares is the third lowest of the three sub-categories within the second highest rating of the eight standard categories of ratings utilized by S&P transferred shares.

There were no changes in S&P’s ratings for Emera in 2010 and 2011.

NSPI Series D First Preferred Shares

NSPI has issued and outstanding 5.4 million 5.90% cumulative redeemable first preferred shares, Series D.

Subject to the approval of the TSX, commencing October 15, 2015, NSPI has the option to exchange the NSPI Series D First Preferred Shares into that number of Emera common shares determined by dividing $25.00, together with accrued and unpaid dividends, by the greater of $2.00 and 95% of the weighted average trading price of the Emera common shares on the TSX for the market price, being for the twenty trading days ending on the last trading day on or before the fourth trading day immediately prior to the time of exchange.

On and after January 15, 2016, upon sixty-five days’ prior notice and prior to any dividend payment date, each NSPI Series D First Preferred Share will be exchangeable, at the option of the holder, into that number of Emera common shares determined by dividing $25.00, together with accrued and unpaid dividends, by the greater of $2.00 and the market price. This exchange right of the holder is subject to the right of NSPI to redeem for cash on the exchange date, or cause the holders to sell on the exchange date to substitute purchasers found by NSPI, all or any part of such NSPI Series D First Preferred Shares, on the payment of $25.00 per share, together with accrued and unpaid dividends.

DIVIDENDS

Any dividend payments will be at the Board’s discretion based upon earnings and capital requirements and such other factors as the Board may consider relevant.

Emera changed the 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 Dividend Reinvestment Plan. Canadian resident registered shareholders are entitled to join this dividend plan.

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The Board approved the payment of the following dividends during the last three completed fiscal years:

Common Shares
Fiscal Year	Record Date	Date Paid	Dividend (per share)
2011	November 1	November 15	$	0.3375
	July 29	August 15	$	0.3250
	May 2	May 16	$	0.3250
	February 1	February 15	$	0.3250
2010	November 1	November 15	$	0.3250
	July 30	August 16	$	0.2825
	May 3	May 17	$	0.2825
	February 1	February 15	$	0.2725
2009	November 2	November 16	$	0.2725
	July 31	August 17	$	0.2525
	May 1	May 15	$	0.2525
	February 2	February 16	$	0.2525
Series A First Preferred Shares (1)
Fiscal Year	Record Date	Date Paid	Dividend (per share)
2011	November 1	November 15	$	0.2750
	July 29	August 15	$	0.2750
	May 2	May 16	$	0.2750
	February 1	February 15	$	0.2750
2010	November 1	November 15	$	0.2750
	July 30	August 16	$	0.2230

Note:

(1) The Series A First Preferred Shares were issued June 2, 2010.

MARKET FOR SECURITIES

Trading Price and Volume

Emera’s common shares and Series A First Preferred Shares are listed and posted for trading on the TSX under the symbols “EMA” and “EMA.PR.A” respectively. The trading volume and high and low price for Emera’s shares for each month of 2011 are set out below:

Common Shares
2011	High($)		Low($)		Volume
January		32.83		31.37		4,966,879
February		32.60		30.20		4,764,494
March		31.70		30.56		4,438,735
April		31.78		30.56		2,709,135
May		32.65		31.29		3,260,117
June		32.54		31.11		3,089,703
July		32.80		31.26		2,931,528
August		31.70		19.95		7,713,859
September		32.89		30.39		5,249,085
October		34.25		31.37		4,549,835
November		33.03		31.02		4,049,855
December		33.65		31.66		4,199,021

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Series A First Preferred Shares
2011	High($)		Low($)		Volume
January		27.16		25.62		163,007
February		25.97		25.35		135,008
March		25.80		25.04		97,757
April		26.11		25.45		49,586
May		25.89		25.33		110,679
June		26.10		25.65		59,862
July		26.26		25.50		201,957
August		26.05		25.00		141,195
September		26.05		25.25		82,855
October		26.35		25.38		60,274
November		25.94		25.40		112,280
December		25.91		25.31		119,110

TRANSFER AGENT AND REGISTRAR

Computershare acts as Emera’s transfer agent and registrar. The registers of transfers of securities of Emera are located at Computershare’s principal offices in Vancouver, Calgary, Toronto, Montreal and Halifax.

DIRECTORS AND OFFICERS

Directors

The following information is provided for each Director of Emera as of December 31, 2011:

Name and Residence	Director Since (1)	Principal Occupations During Past Five Years
Robert S. Briggs (2)(11) Carrabassett Valley, Maine U.S.	2001	Corporate Director. From 1991 to 2001, President and Chief Executive Officer of Bangor Hydro. From 2001 to 2006, Director of NSPI.
Thomas W. Buchanan (2) (3) (5) Calgary, Alberta Canada	2009	Chairman and Chief Executive Officer of Charger Energy Corp., a private oil and gas company formed in October 2010. Formerly a Director, President and CEO of Provident Energy Trust, a diversified energy income trust with investments in upstream oil and gas production and natural gas liquids midstream services, from March 2001 to April 2010. Currently a Director of Athabasca Oil Sands Corp., Hawk Exploration Ltd., Pace Oil and Gas Ltd. and Pembina Pipeline Corporation.

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Name and Residence	Director Since (1)	Principal Occupations During Past Five Years
Gail Cook-Bennett, C.M (3) (6) Toronto, Ontario Canada	2004	Chair of Manulife Financial since October 2008. Manulife provides life insurance, group life and health insurance, long-term care services, pension products, annuities, and mutual funds in Asia, Canada and the United States. Chair of the Canada Pension Plan Investment Board until October 2008, which has responsibility for investing Canada Pension Plan contributions. A Fellow of the Institute of Corporate Directors.
Allan L. Edgeworth (2) (4) (5) (8) Calgary, Alberta Canada	2005	President of ALE Energy Inc. Former President and Chief Executive Officer of Alliance Pipeline. Director of AltaGas Ltd. and Pembina Pipeline Corporation, and Commission Member and Director of the Alberta Securities Commission.
Christopher G. Huskilson (5) (9) Wellington, Nova Scotia Canada	2004	President and Chief Executive Officer of Emera since November 2004. Chair of Bangor Hydro, Director of NSPI and Chair or Director of a number of other Emera affiliated companies. Since June 1980, Mr. Huskilson has held a number of positions within NSPI and its predecessor, Nova Scotia Power Corporation.
John T. McLennan (10) Mahone Bay, Nova Scotia Canada	2005	Chair of the Board since May 2009. Former Chair of the Board of NSPI from May 2006 to May 2009. Director of Chorus Aviation Inc. and Amdocs Ltd. Former Vice-Chair and Chief Executive Officer of Allstream Inc. (formerly AT&T Canada).
Donald A. Pether (3) (4) Dundas, Ontario Canada	2008	Former Chair of the Board and Chief Executive Officer of ArcelorMittal Dofasco Inc. a Canadian steel producer. Director of Primary Energy Recycling Corp. and Samuel, Son & Co. Ltd.
Andrea S. Rosen (2) (7) Toronto, Ontario Canada	2007	Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Director of Alberta Investment Management Corporation, Hiscox Ltd. and Manulife Financial Corporation.
M. Jacqueline Sheppard (2) (4) (5) (11) Calgary, Alberta Canada	2009	Director and Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown Corporation. Director of Cairn Energy PLC, a publicly traded UK based international oil and gas producer and a Director of NWest Energy Inc., a publicly traded junior oil and gas

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Name and Residence	Director Since (1)	Principal Occupations During Past Five Years
		company. Ms. Sheppard is a Director and founding shareholder of a private junior Canadian oil and gas corporation and a Director and founding shareholder of a private international oil and gas corporation focusing on the Middle East, North Africa and the Mediterranean area. She is the former Executive Vice President, Corporate and Legal of Talisman Energy Inc., a Canadian, publicly traded, international oil and gas producer.
Richard P. Sergel (2) (3) (5) Wellesley, Massachusetts U.S.	2010	Former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC). He served as President and Chief Executive Officer of National Grid USA from 2000 to 2004. Prior to that he was President and Chief Executive Officer of the New England Electric System, where he held positions of increasing responsibility since 1979. Mr. Sergel is presently a director of State Street Corporation. He also served on the boards of the Edison Electric Institute and the Consortium for Energy Efficiency.
Sylvia D. Chrominska (4) Toronto, Ontario Canada	2010	Group Head of Global Human Resources and Communications for the Bank of Nova Scotia, where she has global responsibility for human resources, corporate communications, government relations, public policy and corporate social responsibility of the Scotiabank Group.
James D. Eisenhauer Lunenburg, Nova Scotia Canada	2011	President and Chief Executive Officer of ABCO Group Limited, which has holdings in manufacturing and distribution activities. Director of NSPI since 2008 and Chair of the NSPI Board of Directors since May 2011.

Notes:

(1) Denotes the year the individual became a Director of Emera. Directors are elected for a one year term which expires at the termination of Emera’s annual general meeting.

(2) Denotes member of the Audit Committee.

(3) Denotes member of the Nominating and Corporate Governance Committee;

(4) Denotes member of the Management Resources and Compensation Committee;

(5) Denotes member of the Technology and Development Committee;

(6) Denotes Chair of the Nominating and Corporate Governance Committee;

(7) Denotes Chair of the Audit Committee;

(8) Denotes Chair of the Management Resources and Compensation Committee;

(9) Denotes Chair of the Technology and Development Committee;

(10) Denotes Chairman of the Board; and

(11) Denotes member of the Board of Directors of Emera Newfoundland & Labrador Holdings Incorporated, the parent of ENL Maritime Link Incorporated and ENL Island Link Incorporated.

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As of December 31, 2011, the Directors in total beneficially owned or controlled approximately 25,029 common shares or less than 1% of the issued and outstanding shares of Emera.

Emera has an Audit Committee, a Management Resources and Compensation Committee, and a Nominating and Corporate Governance Committee. In September 2010, the Board established the Technology and Development Committee as an ad hoc committee of the Board, Chaired by Emera’s President and Chief Executive Officer. Its primary purpose was to assist the Board in evaluating opportunities for the Company in the area of strategic development, particularly related to identification and evaluation of new lines of business and new technologies, and making recommendations to the Board as appropriate. The mandate of the Technology and Development Committee provided that the Board would from time to time consider the duration of the existence of the Committee. In February, 2012, following a review of the mandate of the Committee by the Board of Directors, the Technology and Development Committee was dissolved, and any on-going work of the Committee will be carried on by the Board of Directors. The membership of each of these Committees is indicated above.

Audit Committee

The Audit Committee of Emera is composed of the following six members, all of whom are independent Directors: Andrea S. Rosen (Chair), Robert S. Briggs, Allan L. Edgeworth, Thomas W. Buchanan, M. Jacqueline Sheppard, and Richard P. Sergel. The responsibilities and duties of the Committee are set out in the Committee’s Charter, a copy of which is attached as Appendix “A” to this AIF.

The Board believes that the composition of the Audit Committee reflects a high level of financial literacy and experience. Each member of the Audit Committee has been determined by the Board to be “independent” and “financially literate” as such terms are defined under Canadian securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Committee. The following is a description of the education and experience of each member of the Committee that is relevant to the performance of her or his responsibilities as a member of the Audit Committee.

Name of Audit Committee Member

Experience and Education Related to Audit Committee Duties

Andrea S. Rosen, Committee Chair Since 2008

Vice-Chair of TD Bank Financial Group and President, TD Canada Trust from 2002 to 2005. From 2001 to 2002, Executive Vice President of TD Commercial Banking and Vice Chair TD Securities. Before joining TD Bank, she was Vice President of Varity Corporation from 1991 to 1994, and she worked at Wood Gundy Inc. (later CIBC-Wood Gundy) in a variety of roles from 1981 to 1990, eventually becoming Vice President and Director. She holds a Bachelor of Laws from Osgoode Hall Law School and a Masters of Business Administration from the Schulich School of Business at York University. She received a Bachelor of Arts from Yale University. Director at Hiscox Ltd., a U.K. reporting issuer listed on the London Stock Exchange where she is a member of the Audit Committee, and Director at Manulife Financial Corporation, an issuer listed on The Toronto Stock Exchange, New York Stock Exchange, The Stock Exchange of Hong Kong, and the Philippine Stock Exchange, where she is a member of the Audit Committee. Also a Director at Alberta Investment Management Corporation.

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Name of Audit Committee Member	Experience and Education Related to Audit Committee Duties
Robert S. Briggs	Lawyer by profession. Former President and Chief Executive Officer of Bangor Hydro gaining substantial experience in the preparation and review of financial statements, and the related analysis and notes in compliance with U.S. federal securities laws. Bachelor of Arts from the University of New Hampshire and a Juris Doctor from University of Maine School of Law.
Allan L. Edgeworth	President of ALE Energy Inc. and former President and Chief Executive Officer of Alliance Pipeline. Director of AltaGas Ltd. and Pembina Pipeline Corporation, and a Commission Member and Director of the Alberta Securities Commission. Bachelor of Applied Science in Geological Engineering and a graduate of the Queen’s Executive Program.
Thomas W. Buchanan, F.C.A.	Fellow Chartered Accountant. Chairman and Chief Executive Officer of Charger Energy Corp., a private oil and gas company, and former Chief Executive Officer of Provident Energy Trust, an investment trust that holds petroleum, natural gas and energy related assets, and former President and Chief Executive Officer, Executive Vice President and Chief Financial Officer of Provident’s predecessor, Founders Energy Ltd. From 1980 to 1982, worked as an accountant for Price Waterhouse. Former Manager of the Finance Group, Controller and Chief Financial Officer of Merland Explorations Ltd., North Canadian Oils Limited and Bankeno Resources Limited, respectively. Bachelor of Commerce degree from the University of Calgary.
M. Jacqueline Sheppard, Q.C.	Lawyer by profession. Director and Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown Corporation. Director of Cairn Energy PLC, a publicly traded UK based international oil and gas producer and a Director of NWest Energy Inc., a publicly traded junior oil and gas company. Director and founding shareholder of a private junior Canadian oil and gas corporation and a Director and founding shareholder of a private international oil and gas corporation focusing on the Middle East, North Africa and the Mediterranean area. Former Executive Vice President, Corporate and Legal of Talisman Energy Inc., a Canadian, publicly traded, international oil and gas producer. Rhodes Scholar, having received an Honors Jurisprudence, Bachelor of Arts and Masters of Arts from Oxford University in 1979, a Bachelor of Laws degree (Honours) from McGill University in 1981, and Bachelor of Arts degree from Memorial University of Newfoundland in 1977.
Richard P. Sergel	Former Chief Executive Officer of North American Electric Reliability Corporation. Former Chief Executive Officer of National Grid USA from 1998 to 2004. Held numerous positions with New England Electric System from 1978 to 1998. Audit Committee member of State Street Corporation. Bachelor of Science degree

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Name of Audit Committee Member	Experience and Education Related to Audit Committee Duties
	from Florida State University, Masters of Science degree from North Carolina State University, and a Masters of Business Administration degree from the University of Miami.

Audit and Non-Audit Services Pre-Approval Process

The Audit Committee is responsible for the oversight of the work of the external auditors. As part of this responsibility, the Committee is required to pre-approve the audit and non-audit services performed by the external auditors in order to assure that they do not impair the external auditors’ independence from the Company. Accordingly, the Audit Committee has adopted an Audit and Non-Audit Pre-Approval Policy, which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the external auditors may be pre-approved.

Unless a type of service has received the pre-approval of the Audit Committee it will require specific approval by the Audit Committee if it is to be provided by the external auditors. Any proposed services exceeding the pre-approved cost levels or budgeted amounts will also require specific approval by the Committee.

The Audit Committee considers whether the provision of any service raises an issue regarding the independence of the external auditors.

Auditors’ Fees

The aggregate fees paid to Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2011 and 2010 respectively, were as follows:

Service Fee	2011		2010
Audit Fees	$	931,750	$	643,731
Audit-related Fees	$	628,405	$	396,165
Tax Fees	$	389,151	$	177,107
All Other Fees		Nil		Nil
Total	$	1,949,306	$	1,217,003

Audit-related fees for Emera relate to accounting and disclosure consultations, services associated with securities offerings, and pension audits.

Tax fees for Emera relate to the structuring of cross-border financing of Emera’s subsidiaries and affiliates as well as tax compliance services and general tax consulting advice on various matters.

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Officers

The Officers of Emera as of December 31, 2011 were as follows:

Name and Municipality of Residence (1)	Position with Emera	Five Year History with Emera
Christopher G. Huskilson Wellington, Nova Scotia Canada	President and Chief Executive Officer	Since November 1, 2004. From July 4, 2003 to Nov. 1, 2004, Chief Operating Officer of Emera. Concurrently held the office of Chief Operating Officer of NSPI until January 9, 2004. Prior to 2003, actively engaged for more than five years in the affairs of NSPI in various managerial and executive capacities.
Nancy G. Tower Halifax, Nova Scotia Canada	Executive Vice President, Business Development	Since May 1, 2011. Also CEO of Emera Newfoundland and Labrador since May 11, 2011. From November 2005 to May 16, 2011, Executive Vice President and Chief Financial Officer. Prior to 2005, Vice-President Customer Operations for NSPI. From 1997 to 2000, Controller for NSPI.
Judy A. Steele Halifax, Nova Scotia Canada	Chief Financial Officer	Since May 16, 2011. Prior to May 2011, Vice President Finance of Emera Energy Inc. From 1999 to May 2007, held managerial and executive positions with Emera’s businesses.
Barbara Meens Thistle Tantallon, Nova Scotia Canada	Chief Human Resources Officer	Since November 25, 2011. From November 2011 to present, Vice President, Human Resources, NSPI. From 2009 to 2011, General Manager, Human Resources, Procurement and Real Estate for NSPI. Prior to 2009, National Director, Human Resources, Eastlink, and prior to that, Chief Human Resources Office at BC Hydro.
Richard J. Smith Halifax, Nova Scotia Canada	Vice President, Corporate Insurance and Asset Protection	Since September 2008. Prior to September 2008, Corporate Secretary of Emera and held other offices of Emera since 1998.
Megan Harris Halifax, Nova Scotia Canada	Vice President, Finance and Performance	Since May 2011. Prior to May 2011, was Chief Financial Officer of Ocean Nutrition Canada Inc. Prior to that, Chief Financial Officer and VP Finance of Day & Ross Transportation Group, McCain Group of Companies.
Stephen D. Aftanas Halifax, Nova Scotia Canada	Corporate Secretary	Since September 2008. From June 2007 to September 2008, Associate Corporate Secretary. From March 2006 to June 2007, Associate General Counsel. Prior to March 2006, Senior Solicitor.

Note:

(1) Bruce Marchand became the Chief Legal Officer of Emera, effective January 1, 2012. Prior to joining Emera, Mr. Marchand was a senior partner in the Halifax office of McInnes Cooper, an Atlantic Canadian law firm. Mr. Marchand replaces Robert Hanf who became Executive Chairman of LPH and Director of BLPH in September 2011.

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As a group, the Directors and Officers of Emera own beneficially, directly or indirectly, or exercise control or direction over approximately 51,243 common shares of Emera (or less than 1%).

Certain Proceedings

To the knowledge of Emera, none of the Directors or Officers of the Company:

1. are, as at the date of this AIF, or have been, within ten years before the date of this AIF, a director, chief executive officer or chief financial officer of any company that:

(a) was subject to an Order that was issued while the Director was acting in the capacity as director, chief executive officer or chief financial officer; or

(b) was subject to an Order that was issued after the Director ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer of chief financial officer;

2. with the exception of Mr. McLennan as set forth below, are, as at the date of this AIF, or have been within ten years before the date of this AIF, a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or

3. have, within the ten years before the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the proposed nominee.

John T. McLennan was the Chief Executive Officer of AT&T Canada when AT&T Canada filed for protection under the Companies’ Creditors Arrangement Act (Canada) on October 15, 2002.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings that individually or together could potentially involve claims against Emera for damages totalling 10% or more of the current assets of Emera, exclusive of interest and costs.

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of the following persons or companies, namely (a) a Director or Officer of Emera, (b) a person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over, more than 10% of any class or series of Emera’s outstanding voting securities, or (c) an associate or affiliate of any person or company named in (a) or (b), had a material interest in any transaction involving Emera within Emera’s last three completed financial years or during the current financial year that has materially affected or will materially affect Emera.

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MATERIAL CONTRACTS

Emera has no material contracts other than those entered into in the ordinary course of its business.

MANAGEMENT’S DISCUSSION & ANALYSIS

The MD&A of Emera for the financial year ended December 31, 2011 is incorporated herein by reference.

EXPERTS

Interest of Experts

Ernst & Young LLP are the external auditors of Emera. Ernst & Young LLP report that they are independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Nova Scotia.

ADDITIONAL INFORMATION

Additional Information relating to Emera may be found on SEDAR at www.sedar.com or upon request to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, N.S., B3J 2W5, telephone (902) 428-6096 or fax (902) 428-6171. Additional Information, including Directors’ and Officers’ remuneration and indebtedness, principal holders of Emera’s securities and securities authorized for issuance under equity compensation plans is contained in Emera’s information circular for the most recent annual meeting of Emera’s common shareholders. Additional financial information is provided in Emera’s financial statements and MD&A for the year ended December 31, 2011.

At any time, Emera will provide to any person upon request to the Corporate Secretary, a copy of the Emera Group of Companies’ Standards for Business Conduct, which is intended to be a code of ethics for the purposes of the Sarbanes Oxley Act of 2002.

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APPENDIX “A” – AUDIT COMMITTEE CHARTER

EMERA INCORPORATED

AUDIT COMMITTEE CHARTER

1. Purpose

There shall be a committee of the Board of Directors (the “Board”) of Emera Inc. (“Emera”) which shall be known as the Audit Committee (the “Committee”). The Committee shall assist the Board in discharging its oversight responsibilities concerning:

• the integrity of Emera’s financial statements;

• Emera’s internal control systems;

• the internal audit and assurance process;

• the external audit process;

• Emera’s compliance with legal and regulatory requirements; and

• any other duties set out in this Charter or delegated to the Committee by the Board.

2. Composition

(i) Emera’s Articles of Association require that the Committee shall be comprised of no less than three Directors none of whom may be Officers or employees of Emera nor may they be an Officer or employee of any affiliate of Emera. In addition, all members of the Committee shall be independent as required by applicable legislation.

(ii) The Board shall appoint members to the Committee who are financially literate, as required by applicable legislation, which at a minimum requires that Committee members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Emera’s financial statements.

(iii) Committee members shall be appointed at the Board meeting following the election of Directors at Emera’s annual shareholders’ meeting and membership may be based upon the recommendation of the Nominating and Corporate Governance Committee.

(iv) Pursuant to Emera’s Articles of Association, the Board may appoint, remove, or replace any member of the Committee at any time, and a member of the Committee shall cease to be a member of the Committee upon ceasing to be a Director. Subject to the foregoing, each member of the Committee shall hold office as such until the next annual meeting of shareholders after the member’s appointment to the Committee.

(v) The Secretary of the Committee shall advise Emera’s internal and external auditors of the names of the members of the Committee promptly following their election.

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3. Responsibilities

Financial Reporting

(a) The Committee shall be responsible for reviewing and recommending to the Board for approval:

(i) the audited annual financial statements of Emera, all related Management Discussion and Analysis, and earnings press releases;

(ii) any documents containing Emera’s audited financial statements including Emera’s Annual Report; and,

(iii) the quarterly financial statements, all related Management Discussion and Analysis, and earnings press releases.

(b) The Committee shall satisfy itself that adequate procedures are in place for the review of public disclosure of financial information and the Committee shall assess the adequacy of these procedures.

External Auditors

(i) The Committee shall evaluate and recommend to the Board the external auditor to be nominated for the purpose of preparing or issuing the auditor’s report or performing other audit, review, or attest services for Emera, as well as the compensation of such external auditors. The Committee shall not recommend the same external auditor as is being recommended for Nova Scotia Power Inc.

(ii) Once appointed, the external auditor shall report directly to the Committee, and the Committee shall oversee the work of the external auditor concerning the preparation or issuance of the auditor’s report or the performance of other audit, review or attest services for Emera.

(iii) The Committee shall be responsible for resolving disagreements between management and the external auditor concerning financial reporting.

Non-Audit Services

(i) The Committee shall be responsible for reviewing and pre-approving all non-audit services to be provided to Emera, or any of its subsidiaries, by the external auditor.

(ii) The Committee shall be permitted to establish specific policies and procedures concerning the performance of non-audit services so long as the requirements of applicable legislation are satisfied.

(iii) In accordance with policies and procedures established by the Committee, and applicable legislation, the Committee may delegate the pre-approval of non-audit services to a member of the Committee or a sub-committee thereof.

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Hiring Policies

The Committee shall be responsible for reviewing and approving Emera’s hiring policy concerning partners or employees, as well as former partners and employees, of the present or former external auditors of Emera.

Pension Plans

The Committee shall review management controls and processes concerning the administration of investment activities, financial reporting, and funding of the plans.

Other Responsibilities

The Committee shall:

(i) review any investment issues or policies which may arise from time to time until a committee is established by the Board to specifically deal with such issues; and

(ii) pursuant to Emera’s Articles of Association, perform such other duties and exercise such powers as may be directed or delegated to the Committee by the Board.

4. Internal Controls

Pursuant to Emera’s Articles of Association, the Committee shall:

(i) ensure that appropriate internal control procedures are in place and the Committee may examine and consider such other matters, and meet with such persons, in connection with the internal or external audit of Emera’s accounts, which the Committee in its discretion determines to be advisable;

(ii) have the authority to communicate directly with the internal and external auditors;

(iii) have the right to inspect all records of Emera or its affiliates and may elect to discuss such records, or any matters relating to the financial affairs of Emera with the Officers or auditors of Emera and its affiliates; and

(iv) review any investments or transactions that could adversely affect the well being of Emera which the internal or external auditor, or any Officer of Emera, may bring to the attention of the Committee.

5. Complaints

The Committee shall ensure that procedures exist relating to the receipt, retention, and treatment of complaints which may be received concerning accounting, internal accounting controls, or auditing matters, and in particular, the Committee shall be responsible for the establishment of procedures concerning the confidential, anonymous submission of concerns by Emera’s employees relating to questionable accounting or auditing matters.

6. Experts and Advisors

The Committee may, in consultation with the Chairman of the Board, engage and compensate any outside adviser that it determines necessary in order to carry out its duties.

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7. Internal Auditor

The chief internal auditor shall report directly to the Committee. The Committee shall oversee the appointment, replacement, or termination of the chief internal auditor.

8. Chair

Pursuant to Emera’s Articles of Association, the Committee shall choose one of its members to act as Chair of the Committee, which person shall not be the Chair of Nova Scotia Power Inc.’s Audit Committee. In selecting a Committee Chair, the Committee may consider any recommendation made by the Nominating and Corporate Governance Committee.

9. Secretary and Minutes

Pursuant to Emera’s Articles of Association, the Corporate Secretary of Emera shall act as the Secretary of the Committee. Emera’s Articles of Association require that the Minutes of the Committee be in writing and duly entered into Emera’s records, and the Minutes shall be circulated to all members of the Committee. The Secretary shall maintain all Committee records.

10. Meetings

(i) Meetings of the Committee may be called by the Chair or at the request of any member.

(ii) The timing and location of meetings of the Committee, and the calling of and procedure at any such meeting, shall be determined from time to time by the Committee.

(iii) Emera’s internal and external auditors shall be notified of all meetings of the Committee and shall have the right to appear before and be heard by the Committee.

(iv) Emera’s internal or external auditors may request the Chair of the Committee to consider any matters which the internal or external auditors believe should be brought to the attention of the Committee or the Board.

11. Quorum

Two members of the Committee present in person, by teleconferencing, or by videoconferencing, or by a combination thereof, will constitute a quorum.

12. Board Relationships and Reporting

The Committee shall:

(i) oversee the appropriate disclosure of the Committee’s Charter as well as other information concerning the Committee which is required to be disclosed by applicable legislation in Emera’s AIF and any other applicable disclosure documents; and

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(ii) as required, regularly report to the Board on Committee activities, issues, and related recommendations.

13. Limitation on Authority

Nothing articulated herein is intended to assign to the Committee the Board’s responsibility to oversee Emera’s compliance with applicable laws or regulations or to expand applicable standards of liability under statutory or regulatory requirements for the Directors or the members of the Committee.

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