EX-99.1

EX-99.1 2 d555438dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

2017

Annual Information Form

Emera Incorporated

March 29, 2018

LOGO

2017 Annual Information Form

TABLE OF CONTENTS


DEFINITIONS			2

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION			11

INTRODUCTION			13

CORPORATE STRUCTURE			15

GENERAL DEVELOPMENT OF THE BUSINESS			16

Financing Activity			24

Changes in Business Expected During 2018			25

DESCRIPTION OF THE BUSINESS			31

Emera Florida and New Mexico			32

Nova Scotia Power			36

Emera Maine			38

Emera Energy			43

Corporate and Other			45

Risk Factors			47

CAPITAL STRUCTURE			47

Common Shares			47

Emera First Preferred Shares			48

Emera Second Preferred Shares			54

Share Ownership Restrictions			54

DIVIDENDS			55

Credit Ratings			57

Market for Securities			58

Trading Price and Volume			58

TRANSFER AGENT AND REGISTRAR			61

DIRECTORS AND OFFICERS			61

CERTAIN PROCEEDINGS			67

LEGAL PROCEEDINGS AND REGULATORY ACTIONS			68

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS			68

MATERIAL CONTRACTS			68

EXPERTS			68

ADDITIONAL INFORMATION			69

Appendix “A” Emera Incorporated Audit Committee Charter			70

2017 Annual Information Form

DEFINITIONS

For convenience, terms used throughout this AIF shall have the following meanings:

“2016 Order” means the June 2016 NMPRC order;

“2019 Notes” means the USD$500 million aggregate principal amount of 2.15% Senior Notes due 2019;

“2021 Notes” means the USD$750 million aggregate principal amount of 2.70% Senior Notes due 2021;

“2026 Notes” means the USD$750 million aggregate principal amount of 3.55% Senior Notes due 2026;

“2046 Notes” means the USD$1.25 billion aggregate principal amount of 4.75% Senior Notes due 2046;

“Acquisition Credit Facilities” means the Company’s non-revolving term credit facilities from a syndicate of banks in an aggregate principal amount of USD$6.5 billion;

“adjusted net income” means net income attributable to common shareholders, as defined by USGAAP excluding the effect of after-tax mark-to-market adjustments and the impact in 2017 of US tax reform, signed into legislation on December 22, 2017 in the US Tax Cuts and Jobs Act of 2017 (refer to the “Changes in Business Expected During 2018” section for further details). The mark-to-market adjustments are related to certain derivative instruments, the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp, the mark-to-market adjustments related to an interest rate swap in EBPC, the mark-to-market adjustments related to the effect of USD$-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering for the TECO Transaction and the mark-to-market adjustments included in Emera Energy’s margin, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered and the amortization of transportation capacity recognized as a result of certain marketing and trading transactions. See the “Non-GAAP Financial Measures” section of the MD&A for the year ended December 31, 2017, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com;

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

“AIF” means this 2017 Annual Information Form of Emera;

“APUC” means Algonquin Power & Utilities Corp., a company incorporated under the federal laws of Canada and traded on the TSX under the symbol “AQN”;

“AST Canada” means AST Trust Company (Canada), formerly known as CST Trust Company;

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

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“Bahamas DRs” means the DRs listed on BISX;

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

“Barbados DRs” means the DRs listed on the BSE;

“Bayside Power LP” means Bayside Power Limited Partnership, a limited partnership governed by the laws of the Province of New Brunswick and wholly-owned directly by Emera, and which owns and operates a 290 MW gas-fired electricity generating facility;

“BBD” means Barbadian dollars;

“BISX” means The Bahamas International Securities Exchange;

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

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

“Board” means the Board of Directors of Emera;

“Brooklyn Energy” means Brooklyn Power Corporation, a 30 MW biomass co-generation company incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct subsidiary of Emera;

“Brunswick Pipeline” means the pipeline delivering re-gasified natural gas from the Canaport LNG gas terminal near Saint John, New Brunswick to markets in the Northeastern United States, which is owned directly by EBPC. The pipeline travels through southwest New Brunswick and connects with M&NP at the Canada/US border near Baileyville, Maine;

“BSD” means Bahamian dollars;

“BSE” means the Barbados Stock Exchange;

“CAD” means Canadian dollars;

“CAIR” means the Clean Air Interstate Rule;

“Canadian Notes” means the $500 million 2.90 % senior unsecured notes due 2023;

“Companies Act Relief” means an order of the Nova Scotia Securities Commission pursuant to the Companies Act (Nova Scotia) exempting Emera from the requirement to prepare its annual financial statements in accordance with IFRS;

“Company” means Emera;

“Completion Guarantee” means a completion guarantee granted by Emera in favour of the Government of Canada under which Emera has guaranteed the performance of the obligations of NSP Maritime Link Inc. to cause the completion of the

2017 Annual Information Form

Maritime Link Project in the circumstances and within the timelines provided for in the Completion Guarantee. The Payment Obligation Agreement and Completion Guarantee collectively satisfy the requirement in the FLG term sheet to deliver the Emera Guarantee Agreement;

“Corporate and Other” means Emera’s consolidated investment in Emera Utility Services, EBPC, Emera Reinsurance and Emera’s non-consolidated investments in ENL, NSP Maritime Link Inc., LIL and M&NP. Corporate and Other also includes other investments and interest revenue on intercompany financings and costs allocated to corporate activities not directly associated with operations; for more information, see the “Corporate and Other” section in the MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com;

“CSAPR” means Cross-State Air Pollution Rule;

“Debenture Offering” means the sale of the Debentures by the Selling Debentureholder;

“Debentures” means the 4.0% convertible unsecured subordinated debentures of Emera represented by instalment receipts that were issued on September 28 and October 2, 2015 in order to finance a portion of the TECO Transaction;

“Directors” mean the directors of Emera and “Director” means any one of them;

“Dividend Reinvestment Plan” means the Common Shareholders’ Dividend Reinvestment and Share Purchase Plan;

“Domlec” means Dominica Electricity Services Limited, an integrated electric utility on the island of Dominica, incorporated under the laws of the Commonwealth of Dominica, and an indirect subsidiary of Emera, through ECI;

“DR” means a depositary receipt representing common shares of Emera;

“EBH2” means Emera (Barbados) Holdings No. 2 Inc., a company incorporated under the laws of St. Lucia and an indirect wholly-owned subsidiary of Emera;

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

“ECC” means NSPI Energy Control Center;

“ECI” means Emera (Caribbean) Incorporated, a company incorporated under the laws of Barbados and an indirect subsidiary of Emera and the parent company of BLPC;

“ECRC” means the environmental cost recovery clause;

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

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

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“Emera” means Emera Incorporated, a public company incorporated under the laws of the Province of Nova Scotia and traded on the TSX under the symbol “EMA”;

“Emera Caribbean” means Emera’s direct and indirect ownership interests in ECI, BLPC, Domlec, GBPC and Lucelec;

“Emera Energy” means Emera Energy Incorporated, a wholly-owned, direct subsidiary of Emera, amalgamated under the laws of the Province of Nova Scotia, and Emera Energy Limited Partnership, a wholly-owned subsidiary of Emera formed under the laws of the Province of Nova Scotia, and whose business collectively includes the businesses of Emera Energy Services and Emera Energy Generation;

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

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

“Emera Florida and New Mexico” means TECO Energy and its holdings, including TEC, NMGC and TECO Finance;

“Emera Guarantee Agreement” means the condition precedent in the FLG term sheet to deliver to the Government of Canada a guarantee of certain payment and performance obligations, which condition precedent was satisfied collectively by the Completion Guarantee and the Payment Obligation Agreement;

“Emera Maine” means the company resulting from the merger of Bangor Hydro and MPS under the laws of the State of Maine on January 1, 2014, and a wholly-owned indirect subsidiary of Emera;

“Emera Reinsurance” means Emera Reinsurance Limited, a captive insurance company incorporated under the laws of Barbados and a wholly-owned direct subsidiary of Emera, which provides insurance and reinsurance to Emera and certain affiliates to enable more cost efficient management of risk and deductible levels across Emera.

“Emera Utility Services” means Emera Utility Services Inc., a company incorporated under the laws of the Province of New Brunswick and a wholly-owned direct subsidiary of Emera, which provides utility construction services in the Atlantic Provinces;

“ENL” means Emera Newfoundland and Labrador Holdings Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly-owned, direct subsidiary of Emera, and the parent company of NSP Maritime Link Inc. and ENL Island Link Inc.;

“ENL Island Link Inc.” means ENL Island Link Incorporated, a company incorporated under the laws of the Province of Newfoundland and Labrador and a wholly-owned, direct subsidiary of ENL;

“EUHL” means Emera Utilities Holdings Ltd., a company incorporated under the laws of Barbados and a wholly owned, indirect subsidiary of Emera and the direct and indirect parent company of ICDU and GBPC;

“Exemptive Relief” means the relief granted to Emera by Canadian securities regulators allowing it to continue to report its financial results in accordance with USGAAP;

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

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

“FCM” means forward capacity market;

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

“Final Instalment” means the remaining $667 per Debenture that was payable on August 2, 2016;

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

“FLG” means the loan guarantee pursuant to which the Government of Canada provides financial support to the Maritime Link Project;

“FPSC” means the Florida Public Service Commission, the regulator of Tampa Electric and PGS;

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

“GBPC” means Grand Bahama Power Company Limited, a vertically integrated electric utility company incorporated under the laws of the Commonwealth of The Bahamas and a direct and indirect subsidiary of EUHL;

“Government of Canada Bond Yield” on any date means the yield to maturity on such date (assuming semi-annual compounding) of a Canadian dollar denominated non-callable Government of Canada bond with a term to maturity of five years as quoted as of 10:00 a.m. (Toronto time) on such date and which appears on the Bloomberg Screen GCAN5YR Page on such date; provided that, if such rate does not appear on the Bloomberg Screen GCAN5YR Page on such date, the Government of Canada Bond Yield will mean the average of the yields determined by two registered Canadian investment dealers selected by the Company as being the yield to maturity on such date (assuming semi-annual compounding) which a Canadian dollar denominated non-callable Government of Canada bond would carry if issued in Canadian dollars at 100% of its principal amount on such date with a term to maturity of five years;

“Government of Canada T-Bill Rate” means, for any quarterly floating rate period, the average yield expressed as a percentage per annum on three month Government of Canada treasury bills, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable floating rate calculation date;

“GRA” means a general rate application;

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

“Hybrid Notes” means the USD$1.2 billion unsecured, fixed-to-floating subordinated notes due 2076;

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

“IFRS” means International Financial Reporting Standards;

“Interest Reset Date” means June 15, 2026, and on every quarter thereafter that the Hybrid Notes are outstanding until their maturity on June 15, 2076;

“IPPs” means independent power producers;

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“IRCD” means the Independent Regulatory Commission, Dominica, the independent regulator of Domlec;

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

“km” means kilometres;

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

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

“LNG” means liquefied natural gas;

“Lucelec” means St. Lucia Electricity Services Limited, a company incorporated under the laws of St. Lucia in which Emera holds an indirect 19.1% interest through ECI;

“M&NP” means the Maritimes & Northeast Pipeline, a pipeline that transports natural gas from offshore Nova Scotia to markets in the Maritime Provinces and New England, in which Emera holds an indirect 12.9% interest;

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

“Maritime Link” or “NSP Maritime Link Inc.” or “NSPML” means NSP Maritime Link Incorporated, a wholly-owned direct subsidiary of ENL incorporated under the laws of the Province of Newfoundland and Labrador that is developing the Maritime Link Project;

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

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

“MD&A” means Emera’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2017, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com;

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

“Moody’s” means the credit rating agency Moody’s Investor Services, Inc.;

“MPS” means Maine Public Service Company, a transmission and distribution electric utility company incorporated pursuant to the laws of the State of Maine, and a wholly-owned, direct subsidiary of MAM which merged on January 1, 2014 with Bangor Hydro to form Emera Maine;

2017 Annual Information Form

“MPUC” means the Maine Public Utilities Commission, the independent regulator of Emera Maine;

“MW” means the amount of power measured in megawatts;

“Nalcor” means Nalcor Energy, a company that is incorporated under a special act of the Legislature of the Province of Newfoundland and Labrador as a Crown corporation;

“NB Power” means New Brunswick Power Corporation, a provincial Crown corporation formed under the laws of the Province of New Brunswick, responsible for the generation, transmission and distribution of electricity in the Province of New Brunswick;

“NEB” means the Canadian National Energy Board, the independent regulator of EBPC;

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

“New England Gas Generation Facilities” or “NEGG Facilities” means a three-facility, 1,115 MW combined-cycle gas-fired electricity generating investment in the Northeastern United States, comprising Bridgeport Energy (560 MW) in Bridgeport, Connecticut; Tiverton Power (290 MW) in Tiverton, Rhode Island; and Rumford Power (265 MW) in Rumford, Maine;

“NMGC” means New Mexico Gas Company, Inc., a regulated gas distribution utility incorporated under the laws of Delaware and serving customers across New Mexico;

“NMPRC” means the New Mexico Public Regulation Commission, the regulator of NMGC;

“Northeastern United States” means the region of the United States consisting of New England and the States of New Jersey, New York and Pennsylvania;

“NSPI” or “Nova Scotia Power” means Nova Scotia Power Incorporated, a vertically integrated electric utility incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct and indirect subsidiary of Emera;

“NSPI’s Annual Information Form” means the 2017 Annual Information Form of NSPI dated March 29, 2018, a copy of which is available electronically under NSPI’s profile on SEDAR at www.sedar.com;

“NWP” means Northeast Wind Partners II, LLC, a company formerly owned 51% by First Wind and 49% by Emera. Emera sold its investment in NWP on January 29, 2015;

“Officers” mean the executive officers of Emera and “Officer” means any one of them;

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

“Payment Obligation Agreement” means a payment obligation agreement between Emera, NSP Maritime Link Inc. and the Government of Canada, which together with the Completion Guarantee collectively satisfy the requirement in the FLG term sheet to deliver the Emera Guarantee Agreement;

2017 Annual Information Form

“PGAC” means purchased gas adjustment clause;

“PGS” means the Peoples Gas System Division of TEC, a regulated gas distribution utility, serving customers across Florida;

“PowerTel” means PowerTel Utility Contractors Limited;

“Province” means a province of Canada and includes, when the context requires, the provincial government;

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

“Rating Agencies” means collectively Moody’s and S&P, and “Rating Agency” means any one of the Rating Agencies;

“RECL” means Repsol Energy Canada Ltd.;

“Repsol” means Repsol S.A, the parent company of RECL;

“ROE” means return on equity;

“S&P” means the credit rating agency Standard & Poor’s Rating Services;

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

“SEC” means the United States Securities and Exchange Commission;

“Securities Act” United States Securities Act of 1933, as amended;

“SEDAR” means the System for Electronic Documents Analysis and Retrieval;

“Selling Debentureholder” means Emera Holdings NS Company, a company incorporated under the laws of the Province of Nova Scotia and a wholly-owned direct subsidiary of Emera;

“Series 2016-A Conversion, First Preferred Shares” means the cumulative preferential first preferred shares, Series 2016-A of Emera;

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

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

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

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

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

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

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

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“Small Business Advocate” means a person or organization appointed to represent the interests of small businesses as defined in the Small Business Advocate Regulations made under the Public Utilities Act;

“SoBRA” means solar base rate adjustment;

“South Canoe Wind Project” means a 102 MW wind farm near New Russell, Nova Scotia;

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

“Tampa Electric” means the Tampa Electric Division of TEC, an integrated regulated electric utility, serving customers in West Central Florida;

“TEC” means Tampa Electric Company, a wholly-owned subsidiary of TECO Energy, incorporated under the laws of the State of Florida with regulated electric and gas utilities in Florida, collectively, Tampa Electric and PGS;

“TECO Energy” means TECO Energy, Inc., an energy-related holding company incorporated under the laws of the State of Florida with regulated electric and gas utilities in Florida and New Mexico;

“TECO Finance” means TECO Finance, Inc., a wholly-owned financing subsidiary of TECO Energy;

“TECO Transaction” means the acquisition by Emera of TECO Energy;

“TSX” means The Toronto Stock Exchange;

“UARB” means the Nova Scotia Utility and Review Board, the independent regulator of NSPI; “U.S.” means the United States;

“U.S. Notes” means, collectively, the 2019 Notes, the 2021 Notes, the 2026 Notes and the 2046 Notes;

“U.S. Tax Cuts Act” means the US Tax Cuts and Jobs Act of 2017;

“United States” means the United States of America;

“USD$” means U.S. dollars; and

“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.

All amounts are in CAD except where otherwise stated.

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

The information presented in this AIF is as at December 31, 2017, unless otherwise specified.

2017 Annual Information Form

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION

This AIF, including the documents incorporated herein by reference, contains “forward-looking information” and “forward-looking statements” within the meaning of applicable securities laws (collectively, “forward-looking information”). The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would”, and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. References to “Emera” in this section include references to the subsidiaries of Emera.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements which reflect the current view of Emera’s management with respect to Emera’s objectives, plans, financial and operating performance, business prospects and opportunities. The forward-looking information reflects management’s current beliefs and is based on information currently available to Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time(s) at which, such events, performance or results will be achieved. All such forward-looking information in this AIF is provided pursuant to safe harbour provisions contained in applicable securities laws.

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes, but is not limited to, statements regarding: Emera’s revenue, earnings and cash flow; the growth and diversification of Emera’s business and earnings base; future annual net income and dividend growth; expansion of Emera’s business in the United States and elsewhere; the integration of TECO Energy’s electric and gas utility businesses with the existing operations of Emera; the expected compliance by Emera and its subsidiaries with the regulation of its operations; the expected timing of regulatory decisions; forecasted capital expenditures; the nature, timing and costs associated with certain capital projects; the expected impact on Emera of challenges in the global economy; estimated energy consumption rates; expectations related to annual operating cash flows; the expectation that Emera will continue to have reasonable access to capital in the near to medium term; expected debt maturities, repayments and renewals; expectations about increases in interest expense and/or fees associated with debt securities and credit facilities; no material adverse credit rating actions expected in the near term; the successful development of relationships with various stakeholders, the impact of currency fluctuations; expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within the United States.

The forecasts and projections that make up the forward-looking information are based on reasonable assumptions which include, but are not limited to: 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; seasonal weather patterns remaining stable; no significant cyber or physical attacks or disruptions to Emera’s systems; the continued ability to maintain transmission and distribution systems to ensure their continued performance; continued investment in wind and hydro generation; continued natural gas activity; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and commodity prices; no significant variability in interest rates; the impact of the TECO acquisition on total assets, net income, long-term growth, access to equity and debt capital markets, credit profile, economies of scale and ability to deploy capital; expectations regarding the nature, timing and costs of capital spending of Emera and its subsidiaries; expectations regarding rate base growth; the continued competitiveness of electricity pricing when compared with other alternative sources of energy; the

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continued availability of commodity supply; the absence of significant changes in government energy plans and environmental laws and regulations that may materially affect the operations and cash flows of Emera; maintenance of adequate insurance coverage; the expected implementation and impact of Emera’s integrated enterprise resource planning system; the ability to obtain and maintain licenses and permits; no material decrease in market energy sales prices; favourable labour relations; and sufficient human resources to deliver service and execute the capital program.

The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors that could cause results or events to differ from current expectations include, but are not limited to: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; capital market and liquidity risk;; future dividend growth; timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of adequate insurance coverage; changes in customer energy usage patterns; developments in technology which could reduce demand for electricity; weather; commodity price risk; unanticipated maintenance and other expenditures; system operating and maintenance risk;; derivative financial instruments and hedging; interest rate risk; credit risk; commercial relationship risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; market energy sales prices; labour relations; and availability of labour and management resources.

For additional information with respect to Emera’s risk factors, reference should be made to the section of this AIF entitled “Risk Factors” and to Emera’s continuous disclosure materials filed from time to time on SEDAR at www.sedar.com.

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.

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INTRODUCTION

Emera is a geographically diverse energy and services company with approximately $29 billion in assets and 2017 revenues of approximately $6 billion. Emera has investments in electricity generation, transmission and distribution and gas transmission and distribution, predominantly within rate-regulated utilities which support strong, consistent earnings and cash flow. Emera seeks to provide its customers with reliable, cost-effective and sustainable energy products and services, and provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States and the Caribbean.

The Company’s strategic focus remains fundamentally unchanged - investing in the transformation of high carbon to low carbon energy by investing in cleaner energy generation, transmission assets to bring cleaner energy to market and natural gas infrastructure.

Utilities

Regulated utilities are the foundation of Emera’s business, providing the company with strong and consistent earnings. From its beginnings as NS Power Holdings Incorporated in 1998 following the privatization of Nova Scotia Power Corporation in 1992, Emera has grown by investing in its businesses and through strategic acquisitions. Emera became an international business with the acquisition of Bangor Hydro in 2001 and expanded its investment in the State of Maine by adding MAM in 2010. In July 2016, Emera significantly increased its presence in the United States by completing the TECO Transaction. In the Caribbean, Emera has built a business of scale, starting with its investment in Lucelec in 2007, and now wholly-owning the electric utility in Barbados and holding an indirect majority ownership interest in electric utility Dominica. On January 15, 2018, Emera increased its indirect majority ownership interest in the electric utility in Grand Bahama to 100%.

At the core of Emera’s electric utilities strategy is identifying opportunities to invest in the transition from higher-carbon methods of electricity generation to lower-carbon alternatives. In September 2017, Tampa Electric announced its intention to invest approximately USD$ 850 million over four years in 600 MW of new solar projects across its territory. Please refer to the “Emera Florida and New Mexico” portion of the section entitled “Changes in Business Expected During 2018” for further details. NSPI has invested in wind energy, biomass and hydroelectricity and is on track to meet a minimum 40% renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives. All investments have an emphasis on affordability and fuel cost stability for its customers. Emera’s strategy for its gas utilities is to invest in infrastructure renewal and expansion of service.

Transmission

Emera is investing in electricity transmission to help deliver renewable energy to market. Emera’s leadership in the Maritime Link Project and its investment in the Labrador-Island Transmission Link Project are helping to contribute to the transformation of the electricity market in the Atlantic Provinces, enabling growth in the availability of clean, renewable energy for the region. In addition, Emera expects that the Atlantic Provinces will benefit from enhanced connection to the Northeastern United States, providing potential for excess renewable energy to be delivered throughout that region.

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Non-regulated

Since its formation in 2003, Emera Energy has become an active participant in the Northeastern United States electricity and natural gas markets. It has built a strong marketing, trading and asset management business based on market knowledge, focus on customer service and robust risk management. The integration and performance of the New England Gas Generating Facilities purchased in 2013 has contributed significantly to the success of Emera Energy. Natural gas is an effective and reliable back-up for intermittent renewable sources and is a cleaner alternative to other fossil fuels. Emera Energy has invested to improve the performance of its natural gas generation assets in New England, creating long-term value for its business.

As it has grown, Emera has held true to the core values that guide its business: building relationships of integrity, focusing on operations and service excellence, investing in its people and making safety and health its foremost priority. For more information on the business operations of the Company, refer to the “Description of the Business” section below.

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CORPORATE STRUCTURE

Name and Incorporation

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

Amended Articles of Association

The Board approved amendments to the Company’s Articles of Association (the “Articles”), which were presented to its shareholders and approved on May 17, 2016. The primary intent of the substantive amendments was to modernize aspects of the Articles to reflect developments in technology, business practice, governing law and the regulatory environment. For more information on these amendments to the Company’s Articles, please refer to the Management Information Circular of Emera distributed in connection with Emera’s annual meeting of shareholders held on May 17, 2016, as amended, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Intercorporate Relationships

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


Subsidiaries	Percentage Ownership (%)⁽¹⁾	Jurisdiction ⁽²⁾
Tampa Electric Company	100	Florida
NSPI	100	Nova Scotia
Emera Maine	100	Maine
EE New England Gas Generation	100	Delaware
Emera Energy Services	100	Canada/United States
GBPC	100⁽³⁾	The Bahamas
ECI	100	Barbados
NMGC	100	Delaware
EBPC	100	Canada
ENL	100	Newfoundland and Labrador

⁽¹⁾	The percentage of votes attaching to all voting securities beneficially owned, or controlled or directed, directly or indirectly by Emera.

⁽²⁾	Jurisdiction of incorporation, continuance or formation.

⁽³⁾

On November 8, 2017, the minority shareholders of ICDUapproved Emera’s indirect acquisition of their common shares for total consideration of approximately USD$35 million. The acquisition of the minority shareholder common shares of ICDU was completed on January 15, 2018, increasing Emera’s indirect ownership interest in GBPC to 100%.

Emera’s other subsidiaries together account for less than 10% of total consolidated operating revenues and less than 20% of total consolidated assets of Emera for the year ended December 31, 2017.

2017 Annual Information Form

GENERAL DEVELOPMENT OF THE BUSINESS

EMERA

For investors, Emera seeks to deliver consistent earnings, cash flow and long-term growth, and accordingly, the primary measures of performance are annual dividend growth, earnings per common share growth, adjusted earnings per common share growth and total shareholder return (a non-USGAAP measure described in the “Non-GAAP Financial Measures” section of the MD&A, which is incorporated herein by reference). The Company targets 8% annual dividend growth through 2020. Emera targets achieving a minimum of 75% of its adjusted net income from its rate-regulated utilities and an average dividend payout ratio of 70% to 75% of adjusted net income. The following table details Emera’s one, three and five-year performance for these metrics, as well as the S&P/TSX Capped Utilities Index annualized total shareholder return for those periods:

For the year ended December 31, 2017


	1 year (%)			3 year (%)			5 year (%)
Dividend per share compound annual growth rate⁽¹⁾		6.5			12.9			9.4
Earnings per share compound annual growth rate		(6.0	)		(23.9	)		(6.7	)
Adjusted earnings per share compound annual growth rate		(11.2	)		3.3			5.9
Emera annualized total shareholder return⁽²⁾		8.3			11.2			11.0
S&P/TSX Capped Utilities Index annualized total shareholder return⁽³⁾		10.7			7.6			7.0

⁽¹⁾	The dividend per share compound annual growth rate is based on the dividends paid in the year.

⁽²⁾	Total shareholder return combines share price appreciation and dividends per common share paid during the fiscal year to show the total return to the shareholder expressed as an annualized percentage, assuming dividends are reinvested each time they are paid.

⁽³⁾

The S&P/TSX Capped Sector Indices provide liquid and tradable benchmarks for related derivative products of Canadian economic sectors. Constituents are selected from a stock pool of S&P/TSX Composite Index Stocks, and the relative weight of any single index constituent is capped at 25%. The indices are based upon the Global Industry Classification Standards (GICS^®). The S&P/TSX Capped Utilities Index imposes capped weights on the index constituents included in the S&P/TSX Composite that are classified in the GICS^® utilities sector.

Energy markets worldwide, in particular across North America, are undergoing foundational changes that have created significant investment opportunities for companies with Emera’s experience and capabilities. Key trends contributing to these investment opportunities include: aging infrastructure, lower-cost natural gas, growing demand for new electric heating and cooling solutions, the requirement for large-scale transmission projects to deliver new energy sources to customers, technological developments and environmental concerns. These environmental concerns include a desire to reduce emissions of carbon dioxide and other greenhouse gases and the potential system impacts of climate change, including changes in global and regional weather patterns, changes in the frequency and intensity of extreme weather events, and rising sea levels. At the core of Emera’s utilities strategy is identifying opportunities to invest in the transition from higher-carbon methods of electricity generation to lower-carbon alternatives, and the related transmission and distribution infrastructure to deliver that energy to market.

The energy sector continues to be impacted by mandated and incented carbon reductions throughout North America and in the Caribbean. It is unclear whether economic volatility, government policy and lower fossil fuel prices will slow the pace of change in the industry. Investment in wind, solar, and hydro generation, natural gas and new transmission infrastructure is likely to continue across the sector despite any cost differential with more carbon-intensive generating options. The capital spending requirements related to these investments will need to be managed within the context of overall energy pricing.

2017 Annual Information Form

In Florida, the Company is investing in a number of initiatives, including solar generation, that would reduce carbon emissions. In Nova Scotia, the Company has invested in wind energy, biomass and hydroelectricity and is on track to meet a minimum 40% renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives, with an emphasis on affordability and fuel cost stability for its customers.

Emera is investing in electricity transmission to deliver new renewable energy to market. Emera believes that its ownership in the Maritime Link Project and Labrador-Island Transmission Link Project will contribute to the transformation of the electricity market in the Atlantic Provinces, enabling growth in the availability of clean, renewable energy for the region. In addition, Emera believes that the Atlantic Provinces will benefit from enhanced connection to the Northeastern United States, providing potential for excess renewable energy to be delivered throughout that region.

Emera Energy is a physical energy marketing and trading business, complemented by a portfolio of competitive electricity generation facilities. A substantial portion of Emera Energy’s activities are in northeastern North America, and its market knowledge, focus on customer service and robust risk management are key success factors. Unlike the vast majority of Emera’s businesses, Emera Energy is not rate-regulated.

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

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

Emera has grown its asset base to deliver on its strategic objectives. Over the last 10 years, Emera’s ability to raise the capital necessary to fund investments has been a strong enabler of the Company’s growth. In addition to access to debt and equity capital markets, Emera believes that cash flow from operations will continue to play a role in financing the Company’s future growth. Maintaining strong, investment grade credit ratings is an important component of Emera’s financing strategy.

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

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

2017 Annual Information Form

For further information related to Emera’s consolidated revenues for the years ended December 31, 2017, December 31, 2016 and December 31, 2015, see the “Consolidated Financial Highlights” section in the MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

The following discussion summarizes key developments in Emera’s business and operations over the last three completed financial years.

TECO Energy

On July 1, 2016, Emera completed the acquisition of all outstanding shares of TECO Energy for approximately $8.4 billion (USD$6.5 billion). TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include Tampa Electric, PGS and NMGC, as further described below. TECO Energy shareholders received USD$27.55 per common share in cash, which represented an aggregate purchase price of approximately $13.9 billion (USD$10.7 billion) and which included the assumption of approximately $5.5 billion (USD$4.2 billion) of debt.

The net cash purchase price for the TECO Transaction was financed through: (i) $728 million (USD$560 million) related to the first instalment of Debentures; (ii) the Hybrid Notes; (iii) the Canadian Notes; and (iv) the U.S. Notes; (v) available cash on hand; and (vi) drawings of $1.4 billion (USD$1.1 billion) on the Acquisition Credit Facilities. Total proceeds of the debt, not otherwise required to complete the TECO Transaction, were used for general corporate purposes. On August 2, 2016, Emera obtained the Final Instalment and used the net proceeds of $1.4 billion to fully repay the Acquisition Credit Facilities.

Maritime Link Project and Strategic Partnership with Nalcor on Muskrat Falls Projects

On July 31, 2012, Emera and Nalcor, along with the Provinces of Nova Scotia and Newfoundland and Labrador, executed agreements in respect of the development and transmission of hydroelectric power from Muskrat Falls in Labrador to the island of Newfoundland, the Province of Nova Scotia and through to New England. These agreements set out the detailed terms pursuant to which:

•

Nalcor will construct and own a 824 MW hydro-electric generating facility at Muskrat Falls and a related transmission line in Labrador and the Labrador Transmission Assets;

•

Emera will invest in the Labrador-Island Transmission Link Project which Nalcor is building;

•

Emera will build, finance and, beginning in 2018, operate the Maritime Link Project, a transmission project linking the island of Newfoundland to Nova Scotia; and

•

The Maritime Link Project will be turned over to Nalcor at the end of the operational period, currently forecasted to be in 2055.

On April 23, 2014, the MLFT completed its offering of 3.5% amortizing bonds due December 1, 2052 for aggregate gross proceeds of approximately $1.3 billion. The amortization of the bonds is from December 1, 2020 to December 1, 2052. The bonds are guaranteed by the Government of Canada under the FLG and have been assigned a rating of “AAA” by S&P and DBRS. The net proceeds are being used to fund construction of the Maritime Link Project.

On March 12, 2015, NSP Maritime Link Inc. entered into the third of the Maritime Link Project’s three major contracts, with Abengoa S.A., a global Spanish energy and transmission construction company, for the construction of approximately 400 km of transmission lines in the Provinces of Newfoundland and Labrador and Nova Scotia. On November 25, 2015, Abengoa S.A. filed a notice under Spanish law, which provided for pre-insolvency protection in Spain. As a result of Abengoa S.A.’s failure to perform, NSP Maritime Link Inc. has terminated its contract with Abengoa S.A.

2017 Annual Information Form

On April 9, 2015, NSP Maritime Link Inc. and the Assembly of Nova Scotia Mi’kmaq Chiefs signed a Socio-Economic Agreement for the Maritime Link Project. Under the Socio-Economic Agreement, NSP Maritime Link Inc. will support ongoing engagement and commitments made during the environmental assessment process, including Mi’kmaq participation in environmental monitoring and employment and business opportunities for Mi’kmaq people.

In July 2016, NSP Maritime Link Inc. took direct assignment from Abengoa S.A. of the subcontract between PowerTel and Abengoa S.A. and as such NSP Maritime Link Inc. began directly managing PowerTel in completing the work on the two grounding lines and the alternating current transmission line.

On July 20, 2016, NSP Maritime Link Inc. announced EUS-Rokstad, a joint venture between Emera Utility Services and Rokstad Power, as the new transmission line contractor for the Maritime Link Project. EUS-Rokstad was responsible for completing construction of the high voltage direct current components of the transmission line. As part of the agreement entered into with NSP Maritime Link Inc., Emera Utility Services had responsibility for approximately 50 km of transmission line in Nova Scotia and Rokstad had responsibility for approximately 140 km of transmission line on the island of Newfoundland. Emera Utility Services and Rokstad Power were jointly and severally liable for completion of the project.

In September 2017, the UARB approved NSPI’s interim assessment payment to NSPML of the costs associated with the Maritime Link starting when the Maritime Link is in service. In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payment reflects NSPML’s proposal to reduce the assessment by deferring $53 million in each of 2018 and 2019, related to depreciation and amortization expenses. As these amounts are included in NSPI’s 2017, 2018 and 2019 fuel rates and are being recovered from customers, NSPI will provide a one-time credit to customers, including interest, in 2018 of approximately $17 million, in 2019 of approximately $36 million and in 2020 of approximately $53 million of these recoveries from customers, as the payments from NSPI to NSPML are not required in those years.

NSPI is also required to hold back $10 million from the interim assessment payment to NSPML in each of 2018 and 2019. The release of such amounts is subject to providing evidence to the UARB that at least that amount of benefit from the Maritime Link has been realized for NSPI customers in that year. If the $10 million in benefits is realized, the UARB will direct NSPI to pay the $10 million to NSPML for that year. If not realized, then the UARB will direct NSPI to pay to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM.

On December 8, 2017, the first successful trial of the Maritime Link was achieved. The Maritime Link completed commissioning and entered service on January 15, 2018, enabling the transmission of electricity between Newfoundland and Labrador and Nova Scotia.

Nova Scotia Power

Electricity Plan and Rate Stability

NSPI has a UARB approved FAM, allowing NSPI to recover fluctuating fuel costs from customers through annual fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. Pursuant to the FAM plan of administration, NSPI’s fuel costs are subject to independent audit.

2017 Annual Information Form

In December 2015, the UARB approved NSPI’s 2016 fuel rates and its recovery of prior period unrecovered fuel costs. The approved customer rates reset the base cost of fuel rates for 2016. In addition, $12 million of prior years’ unrecovered fuel costs was recovered in 2016. This resulted in a combined average rate decrease for customers of approximately 1% in 2016. The rates and recovery of these costs began on January 1, 2016.

The Electricity Plan Act was enacted by the Province in December 2015, with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period.

In March 2016, in accordance with the Electricity Plan Act, NSPI announced that it would not file a GRA for non-fuel electricity rates for the 2017 through 2019 period. This was a result of NSPI continuing to work towards rate stability for customers through a focused effort on reducing operating costs, increasing productivity levels and making service improvements. NSPI filed a three-year rate stability plan for fuel costs with the UARB for 2017 through 2019. The rate stability plan includes an average annual rate increase of 1.5% for each of these three years. Differences between actual fuel costs and fuel revenues recovered from customers will be recovered or returned to customers after 2019 as required under the Electricity Plan Act.

The Electricity Plan Act directs that any non-fuel revenues in excess of NSPI’s approved range of return in 2017 through 2019 will be applied to the FAM. In addition, the financial benefit resulting from a change in the recognition of tax benefits for the South Canoe Wind Project and Sable Wind Project is to be reserved and applied to the FAM to be used in the 2017 to 2019 period.

In December 2016, the UARB approved NSPI’s application to refund over-recovered fuel costs from 2016 to customers. The over-recovered 2016 fuel costs of $36 million were refunded to customers through a one-time credit on their bills in 2017 and allocated to customers based on their individual electricity usage in 2016. The amount refunded to customers included 2016 excess non-fuel revenues of $5 million.

As at December 31, 2017, the FAM had a net liability balance of $177 million (2016 – net liability balance $94 million). For more information refer to the “Business Overview and Outlook – NSPI”, “Regulated Fuel for Generation and Purchased Power” and “Regulatory Recovery Mechanisms” sections of the MD&A, which are incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

2017 Annual Information Form

Algonquin Power & Utilities Corp.

APUC is a diversified generation, transmission and distribution utility traded on TSX under the symbol “AQN”.

On May 24, 2016, Emera completed the sale of 50.1 million common shares of APUC, representing approximately 19.3% of APUC’s issued and outstanding common shares for gross proceeds of $544 million.

On June 30, 2016, Emera converted 12.9 million APUC subscription receipts and dividend equivalents into 12.9 million APUC common shares.

On December 8, 2016, Emera completed the sale of 12.9 million common shares of APUC, representing approximately 4.7% of APUC’s issued and outstanding common shares, for gross proceeds of $142 million. Emera no longer holds any interest in APUC.

Emera Maine

Emera Maine ROE Proceedings

From 2011 to 2016, four separate complaints were filed with FERC to challenge the ISO-New England Open Access Transmission Tariff-allowed based ROE. The first complaint, filed by a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users, has been remanded to FERC by the US Court of Appeals for further proceedings. A decision by FERC on the second and third complaints, brought by a group of consumer advocates and by a group of state commissions, state public advocates and end users respectively (“the ENE and MA AG II Cases”), is expected in 2018. The fourth complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”). Emera Maine has recorded a reserve of USD$ 4 million for the ENE and MA AG II Cases. These reserves have been recorded as “regulatory liabilities” on the consolidated balance sheets of Emera and as a reduction to “operating revenues – regulated electric” on the consolidated statements of income of Emera. The reserve was calculated based on Emera Maine’s best estimate of the probable outcome. No reserve has been made in relation to the first complaint or the EMCOS complaint due to the uncertainty of the outcomes.

Emera Caribbean

ECI Acquisition

On November 16, 2015, EBH2 announced its intention to acquire the outstanding common shares of ECI. Minority ECI shareholders could elect to receive $23.26 ($33.30 BBD) in cash per common share or 2.1 Barbados DRs representing common shares of Emera or a combination of cash and Barbados DRs. Each Barbados DR initially represented one quarter of an Emera common share. As a result of the offer, EBH2 acquired approximately 2.6 million common shares of ECI. As of January 29, 2016, EBH2 had increased its ownership in ECI from 80.7% to 95.5%.

On January 25, 2016, Emera announced that EBH2 would proceed to acquire the remaining common shares of ECI from minority shareholders on the same terms described above, by way of an amalgamation between ECI and a wholly owned subsidiary of EBH2. The amalgamation was completed on February 25, 2016, and EBH2 became the sole common shareholder of ECI. Pursuant to the amalgamation, holders of common shares of ECI received redeemable Class A preferred shares of the amalgamated company, which were redeemed on March 22, 2016.

2017 Annual Information Form

The Barbados DRs commenced trading on the BSE on January 8, 2016, and 2,200,525 Barbados DRs were outstanding as of December 31, 2017.

ICDU Acquisition

On October 13, 2017, Emera and ICDU announced that they had entered into a definitive agreement pursuant to which EUHL would acquire all of the shares of ICDU that it did not own. Minority ICDU shareholders could elect to receive BSD $8.85 in cash per common share or 0.913 Bahamas DRs. Each Bahamas DR initially represented one quarter of an Emera common share.

On November 8, 2017, the minority shareholders of ICDU approved Emera’s acquisition of their common shares for total consideration of approximately USD$35 million. The transaction was completed on January 15, 2018, and EUHL became the sole common shareholder of ICDU, increasing Emera’s indirect ownership interest in GBPC to 100%.

The Bahamas DRs commenced trading on the BISX on January 22, 2018.

Hurricane Matthew

In October 2016, the island of Grand Bahama took a direct hit from Hurricane Matthew. Property damage on the island was extensive. GBPC’s generation and substation infrastructure survived the storm well, however over 2,100 transmission and distribution poles and related conductor were damaged or destroyed, as were many connections to customer homes. Restoration efforts have been completed with the support of other Emera affiliates. Post hurricane load is down approximately 10% as compared to normal expectations; however, management anticipates that demand will recover to pre-storm levels in 2018.

Emera Caribbean has recorded USD$28 million of restoration costs associated with Hurricane Matthew with no impact to net income as USD$21 million was recorded as a regulated asset amortized over five years and USD$7 million was recorded as property, plant and equipment depreciating at an average 27 years. GBPC’s regulator has approved the full recovery of the storm restoration costs in this manner.

Domlec

Emera owns a controlling 51.9% interest in Domlec, an integrated utility on the island of Dominica. The 48.1% non-controlling interest is held by Dominica Social Security, the national pension scheme controlled by the Government, and other local investors. Emera’s total investment in Domlec is USD$7 million. On September 19, 2017, Dominica experienced unprecedented damage as a result of Hurricane Maria, facing sustained winds of over 175 miles per hour. All 36,000 of Domlec’s customers lost power following the storm.

The Company has implemented a restoration plan. All of Domlec’s USD$13 million of long-term debt is held by The National Bank of Dominica and the bank has agreed to defer payment of principal and interest on this debt through to at least April 2018.

While Domlec’s generating assets survived the storm with minimal damage, the Company’s transmission and distribution assets were significantly impacted. Domlec maintains insurance for its generation fleet and, as with most utilities, transmission and distribution networks are self-insured. Management has completed its damage assessment and an estimated impairment provision has been recorded at December 31, 2017. Emera’s portion of the estimated impairment provision is immaterial.

2017 Annual Information Form

Hurricanes Irma and Maria

During the third quarter of 2017, operations in Florida and the Caribbean were impacted by Hurricanes Irma and Maria. Irma, a Category 5 hurricane at its height, impacted the Caribbean and Florida over the course of several days in September making landfall in Florida on September 10, 2017. Hurricane Maria made landfall in Dominica on September 19, 2017, as a Category 5 hurricane. There were no material impacts from these storms on St. Lucia, Grand Bahamas or Barbados.

Tampa Electric

As a result of Hurricane Irma, 57% of Tampa Electric customers lost power. Power was restored to substantially all customers within seven days. There was minimal impact to earnings as a result of this storm. TEC incurred an estimated USD$105 million of storm restoration costs in 2017, of which USD$93 million are expected to be recoverable from the storm reserve, USD$8 million was charged to capital expenditures and USD$4 million to OM&G expenses. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated storm costs in excess of the reserve for several named storms, including Hurricane Irma, and to replenish the balance in the reserve to the USD$56 million level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. Please refer to the “Business Overview and Outlook – Emera Florida and New Mexico” section of the MD&A for further details, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

On January 30, 2018, Tampa Electric filed a settlement agreement with the FPSC, which was approved on February 6, 2018, allowing Tampa Electric to net the estimated amount of storm cost recovery against the utility’s estimated 2018 tax reform benefits in 2018. Dockets have been established to determine the appropriate actual storm costs to be recovered and the actual projected 2018 tax reform benefits, the dockets are expected to be resolved in 2018. Any difference between what was netted on an estimated basis and the results of the dockets to determine the actual costs and benefits would be trued up and recovered from or returned to customers in 2019. Beginning in January 2019, Tampa Electric would reflect the full impact of tax reform on Tampa Electric’s base rates.

First Wind

On January 29, 2015, Emera sold its 49% interest in NWP to First Wind for USD$223.3 million.

Appointments

Board of Directors

Effective November 10, 2017, Kent M. Harvey joined the Board. Mr. Harvey is the former Chief Financial Officer for PG&E Corporation, a Fortune 200 regulated electric and gas utility.

Executive

Effective March 31, 2018, Rick Janega is appointed the Chief Operating Officer, Electric Utilities – Canada, US Northeast and Caribbean. In addition to this new role, Mr. Janega will continue as President and Chief Executive Officer for ENL.

2017 Annual Information Form

Effective March 29, 2018, Chris Huskilson retires as President and Chief Executive Officer (“CEO”) and as a Director. The Board has appointed Scott Balfour, current Chief Operating Officer and former Chief Financial Officer, as President and CEO and as a Director, effective upon Mr. Huskilson’s retirement.

Effective December 1, 2017, Nancy Tower, the former Chief Corporate Development Officer of Emera, was appointed President and Chief Executive Officer of Tampa Electric. Gordon Gillette, Tampa Electric’s previous President and Chief Executive Officer, retired on November 30, 2017.

USGAAP – Exemptive Relief and Companies Act Relief

On January 26, 2018, Emera was granted the Exemptive Relief by Canadian securities regulators, which allows it to continue to report its financial results in accordance with USGAAP. Emera will also apply for the Companies Act Relief, which upon being granted will allow it to continue to be exempt from the requirement to prepare its annual financial statements in accordance with IFRS. Both the Exemptive Relief and the Companies Act Relief will remain in effect for Emera until the earlier of: (i) January 1, 2024; (ii) the first day of the Company’s financial year commencing after the Company ceases to have activities subject to rate regulation; and (iii) the effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within IFRS specific to entities with rate-regulated activities.

Financing Activity

Common Share Issuance

On December 28, 2017, Emera completed an offering of 14,614,000 common shares at $47.90 per common share. The aggregate gross and net proceeds from the offering were $700 million and $680 million, respectively. The proceeds of the offering will be used to support the Company’s recently announced growth initiatives and for general corporate purposes including to reduce indebtedness outstanding and to fund other ordinary course capital expenditures.

For more information on financing activities for Emera and its subsidiaries, please see “Liquidity and Capital Resources: Financing Activities” in the MD&A, incorporated herein by reference.

TECO Transaction Note Issuances

On June 16, 2016, Emera completed the issuance of: (i) the Hybrid Notes; and (ii) the Canadian Notes. Additionally, on June 16, 2016, Emera US Finance LP, a limited partnership financing subsidiary, wholly owned directly and indirectly by Emera completed the issuance of the U.S. Notes. The U.S. Notes are guaranteed by Emera and Emera US Holdings Inc., a wholly-owned direct and indirect subsidiary of Emera, on a joint and several basis, and were sold only to “qualified institutional buyers” under Rule 144A of the Securities Act and to non-U.S. persons under Regulation S of the Securities Act.

The proceeds of the Hybrid Notes, Canadian Notes and U.S. Notes were used to partially finance the purchase price for the TECO Transaction.

In connection with the initial issuance of the U.S. Notes, Emera US Finance LP entered into a registration rights agreement with the initial purchasers of the U.S. Notes in which it undertook to offer to exchange the U.S. Notes for new notes, in an equal principal amount and under the same terms, but which are registered under the Securities Act. On December 15, 2016, a registration statement on Form F-10/Form S-4 was declared effective by the SEC and on January 17, 2017 the new notes were issued.

2017 Annual Information Form

CHANGES IN BUSINESS EXPECTED DURING 2018

U.S. Tax Reform

On December 22, 2017, U.S. Tax Cuts Act was signed into legislation; however, some of the specific details have yet to be clarified. The Company is still analyzing certain aspects of the U.S. Tax Cuts Act, which could potentially affect measurement of balances at December 31, 2017 or potentially give rise to new deferred tax amounts. Further adjustments, if any, will be recorded by the Company during the measurement period in 2018 as permitted by SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act. The U.S. Tax Cuts Act provides that the measurement period must be completed by December 22, 2018. For a discussion of the key provisions of the U.S. Tax Cuts Act, the impact on Emera’s December 31, 2017 financial results and future impacts, refer to the “Developments” section of the MD&A, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

Emera Florida and New Mexico

Emera Florida and New Mexico earnings are most directly impacted by the rate of ROE and the capital structures approved by the FPSC and NMPRC, the prudent management of operating costs, the approved recovery of regulatory deferrals, weather and its impact on energy demand and the timing and amount of capital expenditures.

The Florida utilities anticipate earning within their allowed ROE ranges in 2018 and expect rate base and earnings to be higher than prior years. Tampa Electric expects customer growth rates in 2018 to be in line with 2017, reflective of economic growth in Florida. PGS expects customer growth rates in 2018 to be higher than 2017, reflective of economic growth in Florida and the optimization of existing gas main opportunities. Assuming normal weather, sales volumes are expected to increase consistent with customer growth.

In September 2017, Tampa Electric announced its intention to invest approximately USD$850 million over four years in new utility-scale solar photovoltaic projects across its service territory. A settlement agreement was filed with the FPSC requesting a base rate adjustment that provides for the recovery, upon in-service, of up to 600 MW of investments in utility-scale solar projects that will be phased in from late 2018 through early 2021. On November 6, 2017, the FPSC approved the settlement agreement. On December 12, 2017 Tampa Electric filed its petition along with supporting tariffs demonstrating the cost-effectiveness of the September 1, 2018 SoBRA representing 145 MW and $26 million in estimated revenue requirements. A decision by the FPSC to approve the tariffs on the first SoBRA filing is anticipated in the spring of 2018.

In September 2017, Tampa Electric was impacted by Hurricane Irma. The majority of Hurricane Irma restoration costs will be charged against Tampa Electric’s FPSC approved storm reserve, resulting in minimal impact on 2017 earnings. Estimated total restoration costs are USD$105 million with USD$93 million charged to the storm reserve, USD$8 million charged to capital expenditures and USD$4 million in operating, maintenance and general (OM&G) expense. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated restoration costs in excess of the reserve for several named storms including Hurricane Irma and to replenish the balance in the reserve to the USD$56 million level that existed as at October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018.

2017 Annual Information Form

On December 22, 2017, the US Tax Cuts Act was signed into legislation. It is expected there will be no material change in Tampa Electric, PGS or NMGC earnings as the reduction in the federal income tax rate will be offset by lower customer rates over time and the revaluation of the existing net deferred tax liabilities were offset with a regulatory liability, which will be returned to customers over time. The Tampa Electric solar settlement agreement provides for the impacts of tax reform to be offset by a reduction in base revenues through the adjustment of customer rates within 120 days of when tax reform became law. PGS and NMGC will address the impacts of tax reform through their normal regulatory process. NMGC filed a base rate case in February 2018 in which tax reform will be addressed. On January 9, 2018, the Florida Office of Public Counsel filed a petition with the FPSC requesting that the FPSC adjust rates for all utilities in Florida to reflect the reduction in the tax rate.

NMGC expects earnings to be consistent with prior years. Customer growth rates are expected to be consistent with 2017, reflecting expectations for housing starts and new connections. NMGC filed a rate case in February, 2018.

In 2018, Emera Florida and New Mexico expects to invest approximately USD$1.3 billion, including AFUDC, in capital projects compared to USD$700 million in 2017. Capital projects support normal system reliability and growth at the three utilities, including capital projects at Tampa Electric for transmission and distribution storm hardening. The increase over 2017 is primarily due to significant investment in the solar photovoltaic projects at Tampa Electric. PGS will make investments to expand its system and support customer growth, and continue with replacement of obsolete plastic, cast iron and bare steel pipe. NMGC will complete a project to relocate a portion of the gas pipeline feeding Taos, New Mexico, and will continue to invest in system improvements by replacing legacy pipe and making pipeline integrity management improvements.

Nova Scotia Power

NSPI’s earnings are most directly impacted by the range of ROE and capital structure approved by the UARB; the prudent management and approved recovery of operating costs, load demand, weather, the approved recovery of regulatory deferrals and the timing and amount of capital expenditures.

NSPI’s approved regulated ROE range is 8.75% to 9.25%, based on an actual five-quarter average regulated common equity component of up to 40%. NSPI anticipates earning within its allowed ROE range in 2018 and expects modest rate base growth which will deliver a similar modest increase in earnings.

The Electricity Plan Act was enacted by the Province in December 2015, with a goal of providing rate stability and predictability for customers for the 2017 through 2019 period.

2017 Annual Information Form

improvements. NSPI filed a three-year rate stability plan for fuel costs with the UARB for 2017 through 2019. The rate stability plan includes an average annual rate increase of 1.5% for each of these three years. Differences between actual fuel costs and fuel revenues recovered from customers will be recovered or returned to customers after 2019 as required under the Electricity Plan Act.

Although the energy market in Nova Scotia is otherwise mature, the transformation of energy supply to lower emission sources has driven organic growth within NSPI as investments have been made in renewable generation and system reliability projects.

NSPI is subject to environmental regulations as set by both the Province of Nova Scotia and the Government of Canada. The Company continues to work with both levels of government to comply with these regulations, maximizing efficiency of emission control measures. Over the past several years, the requirement to reduce Nova Scotia’s reliance upon higher carbon and greenhouse gas emitting sources of energy has resulted in NSPI making a significant investment in renewable energy sources and purchasing third party renewable energy.

In December 2016, the Government of Canada and eight provinces (including Nova Scotia) signed the Pan-Canadian Framework on Clean Growth and Climate Change. The Government of Canada has committed to ensuring that each of the Provinces and territories have the flexibility to design their own policies and programs to meet the Government of Canada’s emission-reduction targets, supported by federal investments in infrastructure, specific emission-reduction opportunities and clean technologies. NSPI continues to work with both the Province of Nova Scotia and the Government of Canada as the details of the agreements are finalized and to advance solutions that are in the best interest of customers.

In September 2017, the UARB approved NSPI’s interim assessment payment to NSPML of the costs associated with the Maritime Link starting when the Maritime Link is in service. The Maritime Link completed commissioning and entered service on January 15, 2018. The UARB approved annual payments are $110 million in 2018 and $111 million in 2019. In response to the delayed timing of energy delivery from the Muskrat Falls project, the approved interim assessment payment reflects NSPML’s proposal to reduce the assessment by deferring $53 million in each of 2018 and 2019, related to depreciation and amortization expenses. As these amounts are included in NSPI’s 2017, 2018 and 2019 fuel rates and are being recovered from customers, NSPI will provide a one-time credit to customers, including interest, in 2018 of approximately $17 million, in 2019 of approximately $36 million and in 2020 of approximately $53 million of these recoveries from customers, as the payments from NSPI to NSPML are not required in those years. NSPI is also required to hold back $10 million from the interim assessment payment to NSPML in each of 2018 and 2019. The release of such amounts is subject to providing evidence to the UARB that at least that amount of benefit from the Maritime Link has been realized for NSPI customers in that year. If the $10 million in benefits is realized, the UARB will direct NSPI to pay the $10 million to NSPML for that year. If not realized, then the UARB will direct NSPI to pay to NSPML only that portion that is realized and the balance will be refunded to customers through NSPI’s FAM.

In October 2017, the Province of Nova Scotia passed amendments to the Environment Act (Nova Scotia) to enable the development of a cap-and-trade program for carbon emissions. NSPI will continue to engage with the Province of Nova Scotia as details of the legislative framework are finalized and to advance solutions that are in the best interest of customers.

In the first quarter of 2018, the Government of Canada introduced proposed changes to the greenhouse gases coal regulations designed to remove coal fired generation by 2030, subject to equivalency agreements. It is also anticipated that the Government of Canada will also introduce a regulation specifying the emission intensities required for new gas fired generation and for boiler conversions from coal to gas. These provide the base conditions to establish amendments to the existing 2014 equivalency agreement.

2017 Annual Information Form

In 2018, NSPI expects to invest approximately $360 million, including AFUDC, in capital projects compared to $392 million in 2017. Capital will primarily be invested in projects which will support normal system reliability, with the decrease from 2017 driven by a reduction in spending on information technology and transmission projects.

Emera Maine

Emera Maine’s earnings are most directly impacted by the rate of ROE and rate base approved by its regulators, the prudent management and approved recovery of operating costs, load (including the effects of weather), and the timing and amount of capital expenditures.

Emera Maine’s 2018 rate base is expected to grow modestly due to ongoing investment in transmission and distribution infrastructure, resulting in modest growth in earnings.

On December 22, 2017, the US Tax Cuts Act was signed into legislation. It is expected there will be no material change in Emera Maine’s earnings as the reduction in the federal income tax rate will be incorporated into lower customer rates. The revaluation of the existing net deferred tax liabilities, at the new tax rate, were offset with a regulatory liability that will be returned to customers over time. Emera Maine will address the impacts of tax reform through its normal regulatory process.

There are currently four pending complaints filed with FERC to challenge the ISO-NE Open Access Transmission Tariff-allowed based ROE. On June 19, 2014, in connection with the first complaint, FERC set the base ROE at 10.57% and capped the total ROE, including the effect of incentive adders, at 11.74%. On April 14, 2017, the U.S. Court of Appeals for the District of Columbia Circuit vacated this order and remanded the case to FERC for further proceedings. No changes in reserves have been made as a result of the Court of Appeals vacating the FERC order, as the outcome is considered uncertain. For further discussion on the complaints, see “Emera Maine – Emera Maine ROE Proceedings” above and note 27 to the consolidated financial statements for the year ended December 31, 2017, which are incorporated herein by reference, and a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

In 2018, Emera Maine expects to invest approximately USD$70 million (2017 – USD$61 million), primarily in transmission and distribution capital projects.

Emera Caribbean

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

With oil being the predominant fuel source for generation of electricity in the Caribbean, and with fuel costs directly passed on to customers through electricity rates, any change in global fuel prices and resulting change in fuel costs will result in a similar change in customer rates and reported revenues. GBPC has implemented fuel hedging strategies to provide increased certainty to customers as to fuel costs and electricity rates. In support of reducing carbon emissions and exposure to carbon-based fuel sources, BLPC commissioned a 10 MW solar facility in Barbados, which became operational in 2016. Additional renewable energy generation and energy storage investments are being developed.

2017 Annual Information Form

On May 30, 2017, the Minister of Finance in Barbados delivered a new budget. Key measures include an increase in the National Social Responsibility Levy from 2% to 10% and the introduction of a 2% foreign exchange commission, both effective July 1, 2017. The National Social Responsibility Levy is charged on all goods imported into Barbados and on domestically manufactured goods. The impact of these changes is incorporated into BLPC’s cost of service.

The 2017 Atlantic hurricane season was active. The island of Grand Bahama was impacted by Hurricane Irma, however there was minimal damage to the system as a result of the storm. The island of Dominica was hit directly by Hurricane Maria, a Category 5 hurricane. Emera’s total investment in Domlec is USD$7 million. The Company has implemented a restoration plan and expects to have all main circuits energized and the system ready to connect customers who are ready and certified to be connected in 2018. Barbados was not affected by any hurricanes in 2017.

Overall, Emera Caribbean’s 2018 earnings are expected to increase over the prior year. Earnings from GBPC are expected to increase due to recovering load after the short term decline from Hurricane Matthew in 2016. The increase at GBPC will be partially offset by lower earnings in 2018 from BLPC due to increased interest expense as the utility rebalances its capital structure.

Emera Caribbean plans to invest approximately USD$85 million in capital programs in 2018 (2017 – USD$54 million). This increase is due to spending on transmission, battery storage, renewable generation and LED street lighting projects.

Emera Energy

Emera Energy Services

Earnings from Emera Energy Services are generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply and demand factors, can provide higher levels of margin opportunity. The business is seasonal, with Q1 and Q4 generally providing the greatest opportunity for earnings.

Planned investment by the industry in gas transportation infrastructure within the Northeastern United States over the next few years could reduce the degree of volatility recently experienced in the market, all other things being equal.

In addition to capitalizing on volatility-driven market opportunities, Emera Energy Services expects to continue to grow organically by building market share through strong customer service and expanding its geographic reach to adjacent markets, including the Mid-Atlantic region and Florida.

The Emera Energy Services business is generally expected to deliver net earnings of USD$15 to USD$30 million, with the opportunity for upside when market conditions present.

Emera Energy Generation

Earnings from Emera Energy Generation’s assets are largely dependent on market conditions, in particular, the relative pricing of electricity and natural gas, the absolute price of natural gas as the marginal fuel in the supply stack and capacity pricing in ISO-NE for the NEGG Facilities. Efficient operations of the fleet to ensure unit availability, cost management and effective commercial performance are key success factors.

Adjusted earnings from Emera Energy’s generating assets in 2018 are expected to benefit from higher capacity prices and fewer outage days, all other things being equal.

2017 Annual Information Form

In addition to energy margins and ancillary revenue, the NEGG Facilities and Bear Swamp earn revenue from capacity payments through the ISO-NE FCM, the annual reconfiguration capacity market and the monthly reconfiguration capacity market. Prices for the FCM, the largest of the components, are determined through an auction process held annually, three years in advance, thus currently providing revenue visibility to 2022, presuming the facilities continue to be available to support their capacity obligations. Details of pricing and estimated revenues are outlined in the table below for the NEGG Facilities, and Emera Energy’s 50% interest in Bear Swamp.


Forward Capacity Auction (“FCA”) Year	Clearing Price in $/kW – month (in USD)	Approximate Estimated Annual Capacity Revenue (in USD)⁽¹⁾
FCA 8 (June 2017 to May 2018)	$7.03	$100 million
FCA 9 (June 2018 to May 2019)	$9.55 and 11.08⁽¹⁾	$145 million
FCA 10 (June 2019 to May 2020)	$7.03	$106 million
FCA 11 (June 2020 to May 2021)	$5.30	$80 million
FCA 12 (June 2021 to May 2022)	$4.63	$71 million

⁽¹⁾	$11.08 was awarded for the Southeast Massachusetts/Rhode Island zone only and, as such, applies only to Tiverton.

In 2018, Emera Energy expects to invest approximately $50 million (2017 – $47 million) in capital projects related to its generating assets to continue to improve reliability.

Emera Technologies

In early 2018, a new organization subsidiary of Emera called Emera Technologies LLC was formed that will focus on innovation, capitalize on business opportunities and develop new technologies to position Emera as a dominant player in an evolving energy landscape. Robert Bennett, President and Chief Executive Officer, Emera US Holdings Inc., was appointed President and CEO of Emera Technologies LLC.

Corporate and Other

Corporate and Other includes corporate financing costs, AFUDC earnings as a result of the equity investment in Maritime Link Project and the Labrador-Island Transmission Link Project, project based construction services activity by Emera Utility Services and capital lease accounting treatment of the Brunswick Pipeline, which yields declining earnings over the life of the asset. The segment also includes corporate related costs that are dependent on the level of business development activity and acquisition related initiatives.

Corporate and Other’s contribution to consolidated adjusted net income is expected to be higher in 2018 primarily due to increased contributions from ENL as a result of increased equity investment in the Maritime Link which entered service on January 15, 2018 and higher tax recoveries due to the non-cash tax expense recognized in 2017 as a result of U.S. tax reform. This is partially offset by increased interest expense on higher short term borrowing and lower income tax recoveries in 2018 as a result of the lower US tax rate.

Corporate and Other expects to spend approximately $40 million on property, plant and equipment in 2018 (2017 – $21 million).

2017 Annual Information Form

ENL

Maritime Link

Future earnings contributions from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. The approved ROE is 9%. Earnings are expected to be higher in 2018 than in 2017 given increased equity investment.

In 2018, ENL expects to invest approximately $15 million in capital related to construction close out costs.

LIL

Future earnings from the LIL investment are dependent on the amount and timing of additional equity investments and the approved ROE, which is 8.5%. Emera’s total 2017 cash equity contributions were $55 million. The total equity contribution by Emera for the LIL is estimated to be approximately $600 million by the end of the project. No further equity contributions are forecasted until 2020.

DESCRIPTION OF THE BUSINESS

General

Emera is an energy and services company with approximately $29 billion in assets. Emera currently provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States and the Caribbean.

Emera is focused on growing shareholder value by identifying reliable and affordable energy solutions for customers, typically involving the replacement of higher carbon electricity generation with generation from cleaner sources, lower-carbon alternatives and the related transmission, distribution infrastructure and delivery of that energy to market.

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

The foundation of Emera’s strategy is its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. Emera and its subsidiaries had 7,531 employees at December 31, 2017, approximately 38% of whom are unionized.

Emera has grown its business through investments in its rate-regulated subsidiaries that are beneficial to its customers. Emera’s regulated subsidiaries include:

•

TEC (including PGS) and NMGC (see “Emera Florida and New Mexico” section below);

•

NSPI (see “Nova Scotia Power” section below);

•

Emera Maine (see “Emera Maine” section below); and

•

BLPC, GBPC and Domlec (see “Emera Caribbean” section below).

2017 Annual Information Form

Emera has also grown its business through its non-regulated subsidiaries (Emera Energy (see “Emera Energy” section below) and Emera Utility Services) and additional regulated strategic investments and activities that include:

•

Emera’s 100% investment in Maritime Link;

•

Emera’s 49.5% (December 31, 2016 – 62.7%) investment in the partnership capital of LIL; and

•

a 12.9% interest in M&NP (see “Corporate and Other” section below).

Emera Florida and New Mexico

Emera Florida and New Mexico consists of TECO Energy, a holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include TEC (which consists of two divisions, Tampa Electric and PGS), NMGC and TECO Finance. Tampa Electric provides electricity generation, transmission and distribution services in West Central Florida to approximately 750,000 customers with $9.0 billion in assets and 2,138 employees. PGS and NMGC are regulated gas distribution utilities, serving approximately 375,000 customers across Florida with $1.5 billion in assets and 563 employees, and 525,000 customers across New Mexico with $1.1 billion in assets and 707 employees, respectively.

Tampa Electric and PGS are regulated separately by the FPSC. Tampa Electric is also subject to regulation by FERC. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues or revenue requirements equal to their cost of providing service, including an appropriate return on invested capital.

NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to their cost of providing service, including an appropriate return on invested capital.

2017 Annual Information Form

Market and Sales


Emera Florida and New Mexico Electricity Revenue and Sales by Customer Class
	Electric Revenues (%)				GWh Electric Sales Volumes (%)
For the year ended December 31	2017		2016⁽¹⁾		2017		2016⁽¹⁾
Residential		49.1		54.5		47.1		47.8
Commercial		28.2		30.1		33.1		32.8
Industrial		7.7		8.0		10.6		10.0
Other		15.0		7.4		9.2		9.4

Total		100.0		100.0		100.0		100.0

⁽¹⁾	Financial results of Emera Florida and New Mexico are from July 1, 2016.


Emera Florida and New Mexico Gas Revenue and Sales by Customer Class
	Gas Revenues (%)				Therms Gas Sales Volumes (%)
For the year ended December 31	2017		2016⁽¹⁾		2017		2016⁽¹⁾
Residential		50.1		46.7		13.4		13.7
Commercial		30.1		29.0		29.5		28.7
Industrial		4.8		6.0		47.5		46.4
Other		15.0		18.3		9.6		11.2

Total		100.0		100.0		100.0		100.0

⁽¹⁾	Financial results of Emera Florida and New Mexico are from July 1, 2016.

Tampa Electric

At December 31, 2017, Tampa Electric owned 5,218 MW of generating capacity, of which 64% was natural gas-fired, 31% was conventional coal-fired, 4% was coal and petroleum coke and 1% was solar. Tampa Electric owns 2,140 km of transmission facilities and 18,550 km of distribution facilities.

Tampa Electric’s target regulated ROE range is 9.25% to 11.25%, on an allowed equity capital structure of 54%. An ROE of 10.25% is used for the calculation of the return on investments for clauses.

Fuel Recovery Clause

Tampa Electric has a fuel recovery clause that is approved by the FPSC, allowing it the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a fuel clause regulatory asset or liability and recovered from or returned to customers in a subsequent year.

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for purchased power, capacity, environmental and conservation costs, including a return on capital invested. Differences between the prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred to a corresponding regulatory asset or liability and recovered from or returned to customers in a subsequent year. In October 2017, the FPSC approved the 2018 cost-recovery rates for fuel and purchased power, capacity, environmental and conservation costs.

2017 Annual Information Form

Storm Reserve

The storm reserve is for hurricanes and other named storms that cause significant damage to Tampa Electric’s system. Tampa Electric can petition the FPSC to seek recovery of restoration costs over a 12-month period, or longer, as determined by the FPSC, as well as replenish the reserve. Tampa Electric petitioned the FPSC on December 28, 2017 for recovery of estimated storm costs in excess of the reserve for several named storms, including Hurricane Irma, and to replenish the balance in the reserve to the USD$56 million level that existed as of October 31, 2013. An amended petition was filed with the FPSC on January 30, 2018. Please refer to the “Business Overview and Outlook”, “Emera Florida and New Mexico” section of the MD&A for further details, which is incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

PGS

The PGS system includes approximately 20,380 km of natural gas mains and 11,550 km of service lines. Gas mains are distribution lines that serve as a common source of supply for more than one service line. Natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) was 1.8 billion therms in 2017.

The allowed ROE range for PGS is 9.25% to 11.75%, on an allowed equity capital structure of 54.7%. Absent any rate case filing, the bottom of the range will increase to 9.75% in 2021. An ROE of 10.75% is used for the calculation of return on investments for clauses.

Fuel Recovery Clause

PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its PGAC. This clause is designed to recover the actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity and other related items associated with the purchase, distribution and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap approved annually by the FPSC.

Other Cost Recovery Clauses

The FPSC annually approves cost-recovery rates for conservation costs including a return on capital invested incurred in developing and implementing energy conservation programs. In 2012, the FPSC approved a new cast iron/bare steel pipe replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. The FPSC approved a replacement program of approximately 5%, or 800 km, of the PGS system at a cost of approximately $80 million over a 10-year period. As part of the depreciation study settlement agreement approved by the FPSC in February 2017, the cast iron/bare steel clause was expanded to allow recovery of accelerated replacement of certain obsolete sections of pipe.

NMGC

NMGC serves about 60% of New Mexico’s population in 23 of its 33 counties. NMGC’s system includes approximately 2,650 km of transmission lines and 16,670 km of mains. Annual natural gas throughput is approximately 750 million therms.

The allowed ROE for NMGC is 10%, on an allowed equity capital structure of 52%. NMGC’s rates were established in a 2012 rate case settlement and were frozen until December 31, 2017 per the 2016 Order approving Emera’s acquisition of

2017 Annual Information Form

TECO Energy. Under the 2016 Order, NMGC will also provide customer credits of USD$4 million annually through June 30, 2018. NMGC expects to file a rate case in 2018 with new rates effective approximately twelve months after filing, subject to NMPRC approval.

Fuel Recovery Clause

NMGC recovers gas supply costs through a PGA clause. This clause recovers NMGC’s actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers.

On a monthly basis, NMGC can adjust the charges based on next month’s expected cost of gas and any prior month under-recovery or over-recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC’s annual PGA clause period runs from September 1 to August 31 and the reconciliation is filed in December. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGA clause is reasonable and necessary. In December 2016, NMGC received approval of its PGA clause continuation filing for the four-year period ending December 2020.

Revaluation of U.S. non-regulated deferred income taxes

On December 22, 2017, tax reform changes were signed into legislation. It is expected there will be no material change in Tampa Electric, PGS or NMGC earnings as the reduction in the federal income tax rate will be incorporated into lower customer rates over time and the revaluation of the existing net deferred tax liabilities, were offset with a regulatory liability, which will be returned to customers over time. The Tampa Electric solar settlement agreement provides for the impacts of tax reform to be offset by a reduction in base revenues through the adjustment of customer rates within 120 days of when tax reform became law. PGS and NMGC will address the impacts of tax reform through their normal regulatory process. On January 30, 2018, Tampa Electric filed a settlement agreement with the FPSC, which was approved on February 6, 2018, allowing Tampa Electric to net the estimated amount of storm cost recovery against the utility’s estimated 2018 tax reform benefits. Any difference would be trued up and recovered from or returned to customers in 2019. Beginning in January 2019, Tampa Electric would reflect the full impact of tax reform on Tampa Electric’s base rates. NMGC filed a base rate case in February 2018.

Contribution to Consolidated Net Income and Adjusted Net Income

For the year ended December 31, 2017, Emera Florida and New Mexico’s contribution to consolidated net income decreased by USD$57 million to USD$74 million compared to USD$131 million during the same period in 2016. Adjusted for the revaluation of US non-regulated deferred income taxes, Emera Florida and New Mexico’s adjusted contribution to consolidated net income increased by USD$164 million to USD$295 million in 2017 compared to USD$131 million during the same period in 2016. This is a result of 2017 having a full year of earnings, as compared to only one-half year of earnings in 2016 due to the TECO Transaction occuring on July 1, 2016.

Seasonal Nature

Electric and gas sales volumes are primarily driven by general economic conditions, population and weather. Residential and commercial electricity and gas sales are seasonal. In Florida, Q3 is the strongest period for electricity sales, reflecting warmer weather and cooling demand. In New Mexico and Florida, Q1 is the strongest period for gas sales due to colder weather and heating demand.

2017 Annual Information Form

Capital Expenditures

Emera Florida and New Mexico’s capital expenditures in 2017 were $914 million (2016 –$573 million for the period from July 1, 2016 – December 31, 2016).

Environmental Considerations

Tampa Electric has an ECRC which allows the company to earn a return on investments in new facilities to comply with new environmental regulations and to recover the costs to operate and maintain these facilities. Through its conservation cost recovery clause, Tampa Electric also offers its customers a comprehensive array of residential and commercial programs that have enabled the company to meet its required demand side management goals, reduce weather-sensitive peak demand and conserve energy.

Tampa Electric operates fossil fuel burning power plants with air emissions regulated by the Clean Air Act and material Clean Water Act implications and impacts by federal and state legislative initiatives. Tampa Electric has achieved the emission-reduction levels called for in Phase I and Phase II of CAIR and these expenses were rate recoverable under the Florida ECRC as approved by the FPSC. Similarly, future expenses should be eligible for recovery upon petition by Tampa Electric and approval by the FPSC. On July 7, 2011, the U.S. Environmental Protection Agency (“EPA”) released its final CAIR-replacement rule, called CSAPR. An update to CSAPR was finalized on October 26, 2016 and was implemented in 2017. Based on updated EPA modeling and favorable consideration of atmospheric dynamics, Florida is no longer subject to CSAPR requirements. However, Florida (including Tampa Electric power plants) could be subject to a future version of CSAPR as a result of an expected update triggered by compliance with the more stringent 2015 ozone standard or ongoing litigation related to current rule applicability.

Nova Scotia Power

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services in Nova Scotia to approximately 515,000 customers with approximately $5.0 billion in assets and an average of 1,800 active employees in 2017.

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

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, including an appropriate return to investors.

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

As at December 31, 2017, the FAM has a net liability balance of $177 million (2016 – $94 million net liability).

2017 Annual Information Form

Market and Sales


NSPI Revenue and Electricity Sales by Customer Class
	Electric Revenues (%)				GWh Electric Sales Volumes (%)
For the year ended December 31	2017		2016		2017		2016
Residential		51.9		51.9		42.7		42.7
Commercial		29.5		30.1		29.9		30.2
Industrial		15.3		14.8		24.1		24.2
Other		3.3		3.2		3.3		2.9

Total		100.0		100.0		100.0		100.0

Energy Sources and Generation

NSPI owns 2,488 MW of generating capacity, of which approximately 43% is coal-fired, 29% is natural gas and/or oil, 19% is hydro and wind, 7% is petroleum coke and 2% is biomass-fueled generation. The total NSPI-owned generation capacity is 2,488 MW, which is supplemented by 544 MW contracted with IPPs and Community Feed-In Tariff participants, which is expected to increase to 560 MW in 2018. IPP generation includes wind, tidal, biogas and biomass-fueled generation.

Comparative costs of fuel sources fluctuate from year to year. For information describing the percentage of total electric energy generated by fuel source and for information related to the cost of electricity generation, see the “NSPI Regulated Fuel for Generation and Purchased Power” section of the MD&A, which is incorporated herein by reference.

System Operations

The ECC co-ordinates and controls the electric generation and transmission and distribution facilities. The ECC is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a communication network used by system operators for remote monitoring and control of the power system components.

Through an interconnection agreement with NB Power, NSPI’s system has access to other regional power systems and the rest of the interconnected North American electric bulk power systems.

Transmission and Distribution

NSPI transmits and distributes electricity from its generating stations to its customers. NSPI’s transmission system consists of approximately 5,000 km of transmission facilities. The distribution system consists of approximately 27,000 km of distribution facilities.

Contribution to Consolidated Net Income

NSPI’s contribution to Emera’s consolidated net income was $129 million in 2017 ($130 million in 2016).

Seasonal Nature

Electric sales volume is primarily driven by general economic conditions, population, weather and demand side management. Residential and commercial electricity sales are seasonal in the Province of Nova Scotia, with Q1 typically being the strongest period, reflecting colder weather and fewer daylight hours in the winter season.

2017 Annual Information Form

Capital Expenditures

NSPI’s capital expenditures in 2017 were $392 million (2016 – $309 million).

The UARB prescribes and approves depreciation rates and regulated accounting policies. Depreciation rates are reviewed periodically. A settlement agreement on depreciation rates became effective on January 1, 2012. The overall impact of this settlement agreement on the average depreciation rate was immaterial.

Environmental Considerations

NSPI is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters, primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI. NSPI anticipates that any costs prudently incurred to achieve the legislated reductions will be recoverable from customers under NSPI’s regulatory framework.

Conformance with legislative and NSPI’s requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed up to the period ending December 31, 2017.

The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix. The most recent target for each year of 2015 through 2019 was 25% of electrical energy which will be derived from renewable sources. That target was exceeded for 2016, with 28% of NSPI’s generation mix coming from renewable sources. In 2020, the target is 40% of electrical energy to be derived from renewable sources. The Maritime Link Project will supply 153 MW of firm, on-peak power and approximately 900 GWh per year of renewable electricity to help NSPI meet the legislated target of 40% renewable electricity in 2020. NSPI plans to retire a coal-fired generating unit following the delivery of firm contract energy from Muskrat Falls.

On April 8, 2016, the Province of Nova Scotia amended the Renewable Electricity Regulations to remove a legal requirement to operate NSPI’s Port Hawkesbury biomass plant as a must-run facility which allows it flexibility in operating the facility to meet its renewable targets and delivering fuel savings to customers.

For further information on environmental regulations affecting NSPI, see NSPI’s Annual Information Form.

Emera Maine

Emera Maine’s transmission operations are regulated by FERC, and its distribution operations and stranded cost recoveries are regulated by the MPUC. Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through the utility’s transmission and distribution networks.

Emera Maine has approximately $1.2 billion of assets, serving approximately 158,000 customers in the State of Maine. Emera Maine owns and operates approximately 1,800 km of transmission facilities and 15,000 km of distribution facilities and has a workforce of approximately 400 people.

2017 Annual Information Form

Market and Sales

Approximately 54% of Emera Maine’s electric revenue represents distribution operations, 33% is associated with local transmission operations and 13% relates to stranded cost recoveries. The rates for each element are established in distinct regulatory proceedings.


Emera Maine Revenue and Electricity Sales by Customer Class
	Electric Revenues (%)				GWh Electric Sales Volumes (%)
For the year ended December 31	2017		2016		2017		2016
Residential		47.9		48.1		41.4		40.9
Commercial		36.7		37.5		39.9		40.2
Industrial		7.1		8.1		18.0		18.2
Other		8.3		6.3		0.7		0.7

Total		100.0		100.0		100.0		100.0

Distribution Operations

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. On December 21, 2016, Emera Maine’s distribution rates increased by 3.75%, including the recovery, over five years, of approximately USD$ 4 million of costs associated with a major storm in Maine in 2014. Also, effective December 21, 2016, the allowed ROE was reduced by 0.55% to 9.00% on a common equity component of 49%.

Revaluation of U.S. non-regulated deferred income taxes

On December 22, 2017, tax reform changes were signed into legislation. It is expected there will be no material change in Emera Maine’s earnings as the reduction in the federal income tax rate will be incorporated into lower customer rates. The revaluation of the existing net deferred tax liabilities, at the new tax rate, were offset with a regulatory liability that will be returned to customers over time. Emera Maine will address the impacts of tax reform through their normal regulatory process.

Contribution to Consolidated Net Income

Emera Maine’s contribution to consolidated net income was consistent at USD$36 million in 2017 (2016 – USD$36 million).

Seasonal Nature

Electricity sales in Maine vary over the year; Q1 and Q3 are typically the strongest. Q1 reflects colder weather and few daylight hours in the winter season, while Q3 reflects the hotter summer weather and the impact of summer tourism in the state.

Capital Expenditures

Emera Maine’s capital expenditures for the year ended 2017 were approximately $85 million (2016 – $86 million).

2017 Annual Information Form

Environmental Considerations

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

Emera Caribbean

As at December 31, 2017, Emera Caribbean includes a 100% investment in ECI and its wholly-owned subsidiary BLPC, a 50% direct and 30.4% indirect interest in GBPC (through a 60.7% interest in ICDU held by EUHL), a 51.9% indirect controlling interest, through ECI, in Domlec and a 19.1% indirect interest, through ECI, in Lucelec. On January 15, 2018, Emera completed its indirect acquisition of the common shares of ICDU held by minority shareholders for total consideration of approximately USD$35 million, increasing Emera’s direct and indirect ownership interest in GBPC to 100%.

BLPC

BLPC is a vertically-integrated utility and the provider of electricity on the Caribbean island of Barbados with approximately $0.5 billion of assets. It serves approximately 129,000 customers, has a workforce of approximately 342 employees and is regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted to BLPC a franchise to generate, transmit and distribute electricity on the island until 2028.

BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, including an appropriate return to investors. BLPC’s approved regulated return on rate base was 10% for 2017.

All BLPC fuel costs are passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The Fair Trading Commission, Barbados has approved the calculation of the fuel charge, which is adjusted on a monthly basis.

Domlec

Domlec is a vertically integrated utility on the island of Dominica with approximately EC$136 million of assets, which serves approximately 36,000 customers, has a workforce of approximately 254 employees, and is regulated by the IRCD. Domlec is listed on the Eastern Caribbean Securities Exchange. On October 7, 2013, the IRCD issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014 for a period of 25 years. Domlec’s approved allowable regulated return on rate base was 15% for 2017. A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely manner.

On September 18, 2017, Dominica experienced unprecedented damage as a result of Hurricane Maria, facing sustained winds of over 175 miles per hour. All 36,000 of Domlec’s customers lost power following the storm as its transmission and distribution assets were significantly impacted. Domlec has implemented a restoration plan. Domlec maintains insurance for its generation fleet and, as with most utilities, transmission and distribution networks are self-insured. Management has completed its damage assessment and an estimated impairment provision was recorded at December 31, 2017. Emera’s portion of the estimated impairment provision is immaterial.

2017 Annual Information Form

GBPC

GBPC is a vertically-integrated utility and the sole provider of electricity on Grand Bahama Island in the Bahamas with approximately $0.4 billion of assets. GBPC serves approximately 19,000 customers, has a workforce of approximately 212 employees and is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to generate, transmit and distribute electricity on the island until 2054. In December 2017, the GBPA approved GPBC’s regulated return on rate base of 8.5% for 2018. GBPC’s approved regulated return on rate base was 8.8% for 2017. A fuel pass-through mechanism provides the opportunity to recover all prudent fuel costs from customers in a timely manner.

In December 2016, the GBPA approved that over a five year period, 2017 to 2021, the all-in rate for electricity (fuel and base rates) will be held at 2016 levels. This is achievable, as GBPC’s fuel costs over this period are forecasted to decreased. Fuel costs are managed through a fuel hedging program which allows predictability of these costs. Any over-recovery of fuel costs during this period will be applied to the Hurricane Matthew regulatory deferral until such time as the deferral is recovered. Should GBPC recover funds in excess of the Hurricane Matthew regulatory deferral, the excess will be placed in a new storm reserve. If the Hurricane Matthew deferral is not fully recovered at the end of five years, GBPC will have the opportunity to request recovery from customers in future rates. As a component of its regulatory agreement GBPC has an earnings share mechanism to allow for earnings on rate base to be deferred to a regulatory asset or liability at the rate of 50% of amounts below a 7.8% return on rate base and 50% of amounts above 9.8% return on rate base respectively.

Lucelec

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

Market and Sales


Emera Caribbean Revenue and Electricity Sales by Customer Class⁽¹⁾
	Electric Revenues (%)				GWh Electric Sales Volumes (%)
For the year ended December 31	2017		2016		2017		2016
Residential		33.2		33.2		35.1		34.7
Commercial		57.7		57.2		57.1		57.2
Industrial		7.0		7.7		6.5		6.7
Other		2.1		1.9		1.3		1.4
Total		100.0		100.0		100.0		100.0

⁽¹⁾	Information included above includes 100% of BLPC, GBPC and Domlec.

Energy Sources and Generation

BLPC’s and GBPC’s energy sources for its electricity generation are primarily heavy fuel oil used for base load generation and light fuel oil used for peaking generation.

BLPC owns approximately 239 MW of generation comprised of: (i) 5 gas turbine units with a combined capacity of 86 MW (light oil and jet fuel oil-fired); (ii) 6 diesel units with a combined capacity of 113 MW (heavy oil-fired); and (iii) 2 steam units with a combined capacity of 40 MW (heavy oil-fired). In support of reducing carbon emissions and exposure to carbon-based fuel sources, BLPC commissioned a 10 MW solar facility in Barbados, which became operational in 2016.

2017 Annual Information Form

GBPC owns approximately 98 MW of heavy fuel oil-fired and medium and slow speed diesel generating units.

Domlec owns approximately 20 MW of oil-fired generation and 7 MW of hydro production.

Comparative costs of fuel sources fluctuate from year to year. For information describing the percentage of total electric energy generated by fuel source and for information related to the cost of electricity generation, see the “Emera Caribbean Regulated Fuel for Generation and Purchased Power” section of the MD&A, which is incorporated herein by reference.

System Operation

BLPC, GBPC and Domlec have system control centers which co-ordinate and control the electric generation and transmission facilities with the goal of providing a reliable and secure electricity supply while maintaining economy of operations. The system control centre is linked to the generating stations and other key parts of the system by the “Supervisory Control and Data Acquisition” system, a voice and data communications network.

Transmission and Distribution

BLPC, GBPC and Domlec transmit and distribute electricity from their generating stations to their customers.

BLPC’s transmission system consists of 150 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of 2,800 km of distribution lines which includes distribution supply substations.

GBPC’s transmission system consists of 138 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of approximately 860 km of distribution lines which includes distribution supply substations.

Domlec’s transmission system consists of 497 km of transmission lines, including major substations connected to the transmission and distribution system. The distribution system consists of approximately 716 km of distribution lines which includes distribution supply substations.

Contribution to Consolidated Net Income

Emera Caribbean’s contribution to Emera’s consolidated net income was USD$24 million in 2017 (USD$77 million in 2016). BLPC maintains a Self-Insurance Fund (“SIF”) for the purpose of building an insurance fund to cover risk against damage and consequential loss to certain of BLPC’s generating, transmission and distribution systems. In June 2016, BLPC secured support from the Government of Barbados and the Trustees of the SIF to reduce the contingency funding in the SIF to USD$22 million. As a result, Emera reduced the SIF regulatory liability to USD$30 million (USD$22 million) and recorded a pre-tax gain of $53 million (after-tax gain of $43 million)

Seasonal Nature

Electricity sales and related generation varies significantly over the year in the Caribbean; Q3 is typically the strongest period, reflecting warmer weather.

Capital Expenditures

Emera Caribbean’s capital expenditures for the year ended 2017 were approximately $72 million (2016 – $87 million).

2017 Annual Information Form

Environmental Considerations

Emera Caribbean has implemented a Health Safety Environmental and Management system to assist in safeguarding the health and safety of its employees, contractors and customers while ensuring protection of the environment.

Emera Energy

Emera Energy consists of Emera’s wholly-owned Emera Energy Services, EE New England Gas Generation, Bayside Power LP and Brooklyn Energy; and Emera’s indirect 50% interest in Bear Swamp.

Emera Energy Services

Emera Energy Services derives revenue and earnings from the wholesale marketing and trading of natural gas, electricity and other energy-related commodities and derivatives within its risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure. EES purchases and sells physical natural gas and electricity, the related transportation and transmission capacity rights, and provides related energy asset management services. EES is also responsible for commercial management of electricity production and fuel procurement for Emera Energy Generation’s fleet. The primary market area for the natural gas and power marketing and trading business is Northeastern United States, including the Marcellus shale gas region. EES also participates in the US Gulf Coast and Midwest/Central Canadian natural gas markets. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. EES operates in a competitive environment, and the business relies on knowledge of the region’s energy markets, understanding of pipeline and transmission infrastructure, a network of counterparty relationships and a focus on customer service. EES manages its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio.

Emera Energy Generation

Emera Energy wholly owns and operates a portfolio of high efficiency, non-utility electricity generating facilities in Northeastern United States. Emera Energy has approximately 114 employees in its wholly-owned generation business. The New England facilities participate in the regional capacity market and are compensated for being available to provide power. For the portion of output not committed under power purchase agreements, Emera Energy’s generation facilities sell into price-based competitive markets and earn revenues through the physical delivery of power and ancillary services, such as load regulation.

Market and Sales

Information regarding these facilities is summarized in the following table:

2017 Annual Information Form

Wholly-Owned

Generation Facilities

Location

Capacity
(MW)

Commissioning /
In-Service Date

Fuel

Description

New England

Bridgeport

Connecticut

560

1999

Natural gas

Selling electricity and capacity to ISO-NE

Tiverton ⁽¹⁾

Rhode Island

290

2000

Natural gas

Selling electricity and capacity to ISO-NE

Rumford

Maine

265

2000

Natural gas

Selling electricity and capacity to ISO-NE

Total New England

1,115

Maritime Canada

Bayside

New Brunswick

290

2001

Natural gas

Long-term power purchase agreement November – March; Selling electricity to Maritime Provinces and ISO-NE for remainder of year

Brooklyn

Nova Scotia

1996

Biomass

Long-term power purchase agreement

Total Maritime

Canada

320

Total

1,435

⁽¹⁾	A Q4 2016 upgrade at Tiverton increased its nameplate capacity from 265 MW to 290 MW.

Information regarding Emera Energy’s equity investment in Bear Swamp is summarized below:

Investments in

Generation Facilities

Ownership (%)

Location

Capacity
(MW)

Fuel

Description

New England

Bear Swamp

Massachusetts

600

Hydro

Long-term power purchase agreement and selling electricity and capacity to ISO-NE

Information regarding Emera Energy’s revenues is summarized below:


Emera Energy Adjusted Revenue ⁽¹⁾
For the year ended December 31	2017		2016
Electricity sales	$	263	$	413
Capacity revenues	$	82	$	47
Marketing and trading margin	$	44	$	58

Total	$	389	$	518

⁽¹⁾	Adjusted for the impact of mark-to-market.

2017 Annual Information Form

Revaluation of U.S. non-regulated deferred income taxes

Due to the enactment of U.S. Tax Cuts Act, Emera Energy recorded a non-cash income tax recovery resulting from the provisional revaluation of the existing US non-regulated net deferred income tax liabilities. This provisional revaluation of an existing liability is not the result of any operational or market driven event and therefore management believes excluding from adjusted net income the effect of this provisional revaluation better distinguishes the ongoing operations of the business, and allows investors to better understand and evaluate the Company.

Contribution to Consolidated Net Income and Adjusted Net Income

For the year ended December 31, 2017, Emera Energy’s contribution to consolidated net income increased $203 million to $93 million compared to a loss of $110 million during the same period in 2016. Adjusted for the revaluation of US non-regulated deferred income taxes and after-tax derivative mark-to-market and the amortization of transportation capacity, Emera Energy’s adjusted contribution to consolidated net income remained consistent at $24 million in 2017, as compared to 2016.

Seasonal Nature

The electricity generation business in the northeast of the United States is seasonal. Q1, Q3 and Q4 are generally the strongest periods, reflecting colder weather and fewer daylight hours in the winter season, and cooling load in the summer.

Capital Expenditures

Emera Energy’s capital expenditures for the year ended 2017 were approximately $47 million (2016 – $39 million).

Environmental Considerations

EE New England Gas Generation is subject to the Regional Greenhouse Gas Initiative for carbon dioxide emissions and the Acid Rain Program for sulphur dioxide emissions. EE New England Gas Generation emits approximately two million tons of carbon dioxideper year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions programs could adversely impact financial and operational performance.

Corporate and Other

Corporate and Other consists of Emera’s consolidated investment in Emera Utility Services, EBPC, Emera Reinsurance and Emera’s non-consolidated investments in ENL, NSP Maritime Link Inc., LIL and M&NP.

Emera Utility Services

Emera Utility Services Inc., a wholly-owned direct subsidiary of Emera, provides utility construction services in the Atlantic Provinces.

ENL

Emera has a 100% investment in Maritime Link, the company constructing a $1.56 billion transmission project, including two 170-km subsea cables, between the island of Newfoundland and the Province of Nova Scotia. The investment in Maritime Link is accounted for on the equity basis. This project completed commissioning and entered service on January 15, 2018.

2017 Annual Information Form

LIL

Emera has a 49.5% (2016 – 62.7%) investment in the partnership capital of LIL, which is a $3.7 billion electricity transmission project in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change based on the balance of capital investments required from Emera and Nalcor to complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined on completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Assets and Maritime Link projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49% of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. Nalcor has indicated that the project will be in service in Q2 2018.

EBPC

EBPC owns Brunswick Pipeline, a 145-km pipeline delivering re-gasified natural gas from the Canaport LNG import terminal near Saint John, New Brunswick to markets in the Northeastern United States. The pipeline travels through southwest New Brunswick and connects with M&NP at the Canada/U.S. border near Baileyville, Maine. Since its commissioning in July 2009, the pipeline has been used solely to transport natural gas for RECL under a 25 year firm service agreement. Brunswick Pipeline is regulated by the NEB, which has classified it as a Group II pipeline.

M&NP

Emera owns a 12.9% interest in M&NP, which is a 1,400 km pipeline that transports natural gas from offshore Nova Scotia to markets in the Maritime Provinces and the Northeastern United States.

Contribution to Consolidated Net Income and Adjusted Net Income

Corporate and Other’s contribution to consolidated net income decreased $20 million to a loss of $132 million compared to a loss of $112 million during the same period in 2016. Adjusted for the revaluation of U.S. non-regulated deferred income taxes and after-tax mark-to-market, Corporate and Other’s contribution to consolidated net income decreased $90 million to a loss of $88 million compared to $2 million during the same period in 2016. The 2016 mark-to-market primarily related to the effect of the Debenture Offering, USD$-denominated currency revaluation and forward contracts put in place to hedge the anticipated proceeds from the Final Instalment.

Capital Expenditures

Corporate and Other capital expenditures for the year ended 2017 were approximately $26 million (2016 – $8 million).

2017 Annual Information Form

Environmental Considerations

Brunswick Pipeline is regulated by the NEB and subject to both federal and provincial environmental regulations. Brunswick Pipeline has comprehensive integrity, safety and environmental programs in place, including an environmental management system and regularly scheduled physical inspections of the pipeline.

Economic Dependence

Brunswick Pipeline has a 25-year firm transport or pay service agreement with RECL, which runs to 2034. The risk of non-payment is mitigated as Repsol, the parent company of RECL, has provided EBPC with a guarantee for all RECL’s payment obligations under the firm service agreement.

RISK FACTORS

See the “Enterprise Risk and Risk Management” section of the MD&A and “Principal Financial Risks and Uncertainties” in the Commitments and Contingencies note to Emera’s financial statements for the year ended December 31, 2017, which are each incorporated herein by reference, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com.

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 is issuable in series.

As at December 31, 2017, 228,777,760 common shares, 3,864,636 Series A First Preferred Shares, 2,135,364 Series B First Preferred Shares, 10,000,000 Series C First Preferred Shares, 5,000,000 Series E First Preferred Shares, 8,000,000 Series F First Preferred Shares and 2,200,525 Barbados DRs 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 in respect of each common share held at such meetings.

The holders of common shares are entitled to dividends on a pro rata basis, as and when declared by the Board. Subject to the rights of the holders of the first preferred shares and second preferred shares, if any, who are entitled to receive dividends in priority to the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other class of shares of Emera.

On the liquidation, dissolution or winding-up of Emera, holders of common shares are entitled to participate rateably in any distribution of assets of Emera, subject to the rights of holders of first preferred shares and second preferred shares, if any, who are entitled to receive the assets of the Company on such a distribution in priority to the holders of the common shares.

2017 Annual Information Form

There are no pre-emptive, redemption, purchase or conversion rights attaching to the common shares.

The foregoing description is subject to the “Share Ownership Restrictions” section below.

Emera First Preferred Shares

The first preferred shares of each series rank on parity with the first preferred shares of every other series and are entitled to a preference over the second preferred shares, the common shares, and any other shares ranking junior to the first preferred shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary.

In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the first preferred shares, the holders of the first preferred shares will be entitled, for only as long as the dividends remain in arrears, to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting.

The first preferred shares of each series are not redeemable at the option of their holders.

The following series of First Preferred Shares have been authorized:

Series A First Preferred Shares

The holders of Series A First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

•

where entitled by law;

•

for meetings of the holders of first preferred shares as a class and holders of Series A First Preferred Shares as a series; and

•

in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series A First Preferred Shares.

In any instance where the holders of Series A First Preferred Shares are entitled to vote, each holder shall have one vote for each Series A Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series A First Preferred Shares were entitled to receive fixed cumulative preferential cash dividends in the amount of $0.2750 per share per quarter during the five-year period commencing on August 15, 2010 and ending on (and inclusive of) August 14, 2015, as and when declared by the Board. For each five-year period after this date, the holders of Series A First Preferred Shares will be entitled to receive reset fixed cumulative preferential cash dividends. The reset annual dividends per share will be determined by multiplying the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 1.84%, by $25.00. The dividend rate for the Series A First Preferred Shares was set at $0.1597 per share per quarter for the five-year period commencing on August 15, 2015 and ending on (and inclusive of) August 14, 2020.

The Series A First Preferred Shares were not redeemable by Emera prior to August 15, 2015. On that date and on August 15 every five years thereafter, Emera has the right in certain circumstances to redeem for cash all or any part of the then outstanding Series A First Preferred Shares at a price of $25.00 per share plus any accrued and unpaid dividends up to but excluding the date fixed for redemption. Emera did not exercise its right to redeem all or any part of the outstanding Series A First Preferred Shares on August 15, 2015.

2017 Annual Information Form

Subject to the automatic conversion described below and the right of Emera to redeem the Series A First Preferred Shares, on August 15, 2015 and on August 15 every five years thereafter, the holders of Series A First Preferred Shares have the right to convert any or all of their Series A First Preferred Shares into an equal number of Series B First Preferred Shares. In addition, the Series A First Preferred Shares may be automatically converted by Emera into Series B First Preferred Shares if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series A First Preferred Shares outstanding. On August 17, 2015, Emera announced that 2,135,364 issued and outstanding Series A First Preferred Shares were tendered for conversion, on a one-for-one basis, into Series B First Preferred Shares.

Series B First Preferred Shares

The holders of Series B First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

•

where entitled by law;

•

for meetings of the holders of first preferred shares as a class and holders of Series B First Preferred Shares as a series; and

•

in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series B First Preferred Shares.

In any instance where the holders of Series B First Preferred Shares are entitled to vote, each holder shall have one vote for each Series B Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series B First Preferred Shares are entitled to receive floating rate cumulative preferential cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-Bill Rate on the applicable reset date plus 1.84%, by $25.00. The dividend rate for the Series B First Preferred Shares was reset to $0.1473 per share for the quarter commencing on November 15, 2016 and ending on (and inclusive of) February 14, 2017, and was paid on February 15, 2017. The dividend rate for the Series B First Preferred Shares was reset to $0.1414 per share for the quarter commencing on February 15, 2017 and ending on (and inclusive of) May 14, 2017, and was paid on May 15, 2017. The dividend rate for the Series B First Preferred Shares was reset to $0.1510 per share for the quarter commencing on May 15, 2017 and ending on (and inclusive of) August 14, 2017, and was paid on August 15, 2017. The dividend rate for the Series B First Preferred Shares was reset to $0.1-635 per share for the quarter commencing on August 15, 2017 and ending on (and inclusive of) November 14, 2017, and was paid on November 15, 2017. The dividend rate for the Series B First Preferred Shares was reset to $0.1787 per share for the quarter commencing on November 15, 2017 and ending on (and inclusive of) February 14, 2018, and was paid on February 15, 2018.

Emera has the right in certain circumstances to redeem for cash all or any part of the outstanding Series B First Preferred Shares at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on August 15, 2020 and on August 15 every five years thereafter, or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2015.

2017 Annual Information Form

Subject to the automatic conversion described below and the right of Emera to redeem the Series B First Preferred Shares, on August 15, 2020 and on August 15 every five years thereafter, the holders of Series B First Preferred Shares have the right to convert any or all of their Series B First Preferred Shares into an equal number of Series A First Preferred Shares. In addition, Series B First Preferred Shares may be automatically converted by Emera into Series A First Preferred Shares if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series B First Preferred Shares outstanding.

Series C First Preferred Shares

The holders of Series C First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

•

where entitled by law;

•

for meetings of the holders of first preferred shares as a class and holders of Series C First Preferred Shares as a series; and

•

in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series C First Preferred Shares.

In any instance where the holders of Series C First Preferred Shares are entitled to vote, each holder shall have one vote for each Series C Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series C First Preferred Shares are entitled to receive fixed cumulative preferential cash dividends in the amount of $0.25625 per share per quarter during the six-year period commencing on August 15, 2012 and ending on (and inclusive of) August 14, 2018, as and when declared by the Board. For each five year period after this date, the holders of Series C First Preferred Shares will be entitled to receive reset fixed cumulative preferential cash dividends. The reset annual dividends per share will be determined by multiplying the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 2.65%, by $25.00.

The Series C First Preferred Shares will not be redeemable by Emera prior to August 15, 2018. On that date and on August 15 every five years thereafter, Emera has the right in certain circumstances to redeem for cash all or any part of the then outstanding Series C First Preferred Shares at a price equal to $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption.

Subject to the automatic conversion described below and the right of Emera to redeem Series C First Preferred Shares, on August 15, 2018 and on August 15 every five years thereafter, the holders of Series C First Preferred Shares have the right to convert any or all of their Series C First Preferred Shares into an equal number of Series D First Preferred Shares. In addition, Series C First Preferred Shares may be automatically converted by Emera into Series D First Preferred Shares if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series C First Preferred Shares outstanding.

Series D First Preferred Shares

As at December 31, 2017, there were no Series D First Preferred Shares issued and outstanding.

The holders of Series D First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

2017 Annual Information Form

•

where entitled by law;

•

for meetings of the holders of first preferred shares as a class and holders of Series D First Preferred Shares as a series; and

•

in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series D First Preferred Shares.

In any instance where the holders of Series D First Preferred Shares are entitled to vote, each holder shall have one vote for each Series D Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series D First Preferred Shares will be entitled to receive floating rate cumulative preferential cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-Bill Rate on the applicable reset date plus 2.65%, by $25.00.

Emera has the right in certain circumstances to redeem for cash all or any part of the outstanding Series D First Preferred Shares at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on August 15, 2023 and on August 15 every five years thereafter, or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15, 2018.

Subject to the automatic conversion described below and the right of Emera to redeem the Series D First Preferred Shares, on August 15, 2023 and on August 15 every five years thereafter, the holders of Series D First Preferred Shares have the right to convert any or all of their Series D First Preferred Shares into an equal number of Series C First Preferred Shares. In addition, Series D First Preferred Shares may be automatically converted by Emera into Series C First Preferred Shares if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series D First Preferred Shares outstanding.

Series E First Preferred Shares

The holders of Series E First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

•

where entitled by law;

•

for meetings of the holders of first preferred shares as a class and holders of Series E First Preferred Shares as a series; and

•

in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series E First Preferred Shares.

In any instance where the holders of Series E First Preferred Shares are entitled to vote, each holder shall have one vote for each Series E Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series E First Preferred Shares are entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board in the amount of $1.125 per share per annum in perpetuity, subject to the Company’s redemption rights. On or after August 15, 2018, the Company may, on not less than 30 nor more than 60 days’ notice, redeem the Series E First Preferred Shares in whole or in part, at the Company’s option without the consent of the holder, by the payment of: $26.00 per share if redeemed before August 15, 2019; $25.75 per share if redeemed on or after August 15, 2019

2017 Annual Information Form

but before August 15, 2020; $25.50 per share if redeemed on or after August 15, 2020 but before August 15, 2021; $25.25 per share if redeemed on or after August 15, 2021 but before August 15, 2022; and $25.00 per share if redeemed on or after August 15, 2022; together, in each case, with all accrued and unpaid dividends up to but excluding the date fixed for redemption.

Series F First Preferred Shares

The holders of Series F First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

•

where entitled by law;

•

for meetings of the holders of first preferred shares as a class and holders of Series F First Preferred Shares as a series; and

•

in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series F First Preferred Shares.

In any instance where the holders of Series F First Preferred Shares are entitled to vote, each holder shall have one vote for each Series F First Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series F First Preferred Shares are entitled to receive fixed cumulative preferential cash dividends in the amount of $0.265625 per share per quarter during the period commencing on August 15, 2014 and ending on (and inclusive of) February 14, 2020, as and when declared by the Board. For each five-year period after this date, the holders of Series F First Preferred Shares will be entitled to receive reset fixed cumulative preferential cash dividends. The reset annual dividends per share will be determined by multiplying the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 2.63%, by $25.00.

The Series F First Preferred Shares will not be redeemable by Emera prior to February 15, 2020. On that date and on February 15 every five years thereafter, Emera has the right in certain circumstances to redeem for cash all or any part of the then outstanding Series F First Preferred Shares, at a price of $25.00 per share plus any accrued and unpaid dividends up to but excluding the date fixed for redemption.

Subject to the automatic conversion described below and the right of Emera to redeem the Series F First Preferred Shares, on February 15, 2020 and on February 15 every five years thereafter, the holders of the Series F First Preferred Shares have the right to convert any or all of their Series F First Preferred Shares into an equal number of Series G First Preferred Shares. In addition, Series F First Preferred Shares may be automatically converted by Emera into Series G First Preferred Shares if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series F First Preferred Shares outstanding.

Series G First Preferred Shares

As at December 31, 2017, there were no Series G First Preferred Shares issued and outstanding.

The holders of Series G First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

•

where entitled by law;

2017 Annual Information Form

•

for meetings of the holders of first preferred shares as a class and holders of Series G First Preferred Shares as a series; and

•

in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series G First Preferred Shares.

In any instance where the holders of Series G First Preferred Shares are entitled to vote, each holder shall have one vote for each Series G Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of Series G First Preferred Shares will be entitled to receive floating rate cumulative preferential cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is the sum of the three-month Government of Canada T-Bill Rate on the applicable reset date plus 2.63%, by $25.00.

Emera has the right in certain circumstances to redeem for cash all or any part of the outstanding Series G First Preferred Shares at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on February 15, 2025 and on February 15 every five years thereafter, or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after February 15, 2020.

Subject to the automatic conversion described below and the right of Emera to redeem the Series G First Preferred Shares, on February 15, 2025 and on February 15 every five years thereafter, the holders of Series G First Preferred Shares have the right to convert any or all of their Series G First Preferred Shares into an equal number of Series F First Preferred Shares. In addition, Series G First Preferred Shares may be automatically converted by Emera into Series F First Preferred Shares if Emera determines that, following conversion by the holders, there would be less than 1,000,000 Series G First Preferred Shares outstanding.

Series 2016-A Conversion, First Preferred Shares

The Series 2016-A Conversion, First Preferred Shares were authorized pursuant to the Hybrid Notes offering in June 2016. As at December 31, 2017, there were no Series 2016-A Conversion, First Preferred Shares issued and outstanding.

The holders of Series 2016-A Conversion, First Preferred Shares are not entitled to attend any meetings of the shareholders of Emera or to vote at any such meeting, except for the following:

•

where entitled by law;

•

for meetings of the holders of first preferred shares as a class and holders of Series 2016-A Conversion, First Preferred Shares as a series; and

•

in situations when Emera fails to pay, in the aggregate, eight quarterly dividends on the Series 2016-A Conversion, First Preferred Shares.

In any instance where the holders of Series 2016-A Conversion, First Preferred Shares are entitled to vote, each holder shall have one vote for each Series 2016-A Conversion, First Preferred Share, subject to the restrictions described under “Share Ownership Restrictions” below.

The holders of each series of Series 2016-A Conversion, First Preferred Shares will be entitled to receive cumulative preferential cash dividends, if, as and when declared by the Board, at the same rate as would have accrued on the related series of Hybrid Notes (had such Hybrid Notes remained outstanding), payable on each semi-annual or quarterly dividend payment date, as the case may be. The Series 2016-A Conversion, First Preferred Shares do not have a fixed maturity date.

2017 Annual Information Form

The Series 2016-A Conversion, First Preferred Shares are not redeemable by Emera on or prior to June 15, 2026. After that date, Emera may redeem at any time all, or from time to time any part, of the outstanding Series 2016-A Conversion, First Preferred Shares, without the consent of the holders, on not more than 60 days and not less than 30 days prior notice, by the payment of an amount in cash for each such share so redeemed of USD$1,000 per share together with an amount equal to all accrued and unpaid dividends thereon.

Emera Second Preferred Shares

The second preferred shares have special rights, privileges, restrictions and conditions substantially similar to the first preferred shares, except that the second preferred shares rank junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Emera in the event of liquidation, dissolution or winding-up of Emera. As at December 31, 2017, Emera had not issued any second preferred shares.

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 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.

The common shares, and in certain circumstances the Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares and Series F First Preferred Shares are considered to be voting shares for purposes of the constraints on share ownership.

Emera’s Articles contain provisions for the enforcement of these constraints on share ownership including provisions for suspension of voting rights, forfeiture of dividends, prohibitions of share transfer and issuance, compulsory sale of shares and redemption, and suspension of other shareholder rights. The Board may require shareholders to furnish statutory declarations as to matters relevant to enforcement of the restrictions.

2017 Annual Information Form

DIVIDENDS

Any dividend payments will be at the Board’s discretion based upon earnings and capital requirements and any other factors as the Board may consider relevant. Emera has an 8% annual dividend growth target through 2020.

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


Common Shares^{(1), (2), (3) and (4)}
Fiscal Year	Record Date	Date Paid	Dividend (per share) ($)
2017	November 1 August 1 May 1 February 1	November 15 August 15 May 15 February 15		0.5650 0.5225 0.5225 0.5225
2016	November 1 July 22 May 2 February 2	November 15 August 15 May 16 February 16		0.5225 0.5225 0.4750 0.4750
2015	November 2 July 31 May 1 February 3	November 16 August 17 May 15 February 17		0.4750 0.4000 0.4000 0.3875


Series A First Preferred Shares
Fiscal Year	Record Date	Date Paid	Dividend (per share)
2017	November 1 August 1 May 1 February 1	November 15 August 15 May 15 February 15		0.1597 0.1597 0.1597 0.1597
2016	November 1 July 22 May 2 February 2	November 15 August 15 May 16 February 16		0.1597 0.1597 0.1597 0.1597
2015	November 2 July 31 May 1 February 3	November 15 August 17 May 15 February 17		0.1597 0.2750 0.2750 0.2750


Series B First Preferred Shares⁽⁵⁾
Fiscal Year	Record Date	Date Paid	Dividend (per share)
2017	November 1 August 1 May 1 February 1	November 15 August 15 May 15 February 15		0.1635 0.1510 0.1414 0.1473
2016	November 1 July 22 May 2 February 2	November 15 August 15 May 16 February 16		0.1457 0.1449 0.1393 0.1425
2015	November 2	November 15		0.1508

2017 Annual Information Form


Series C First Preferred Shares
Fiscal Year	Record Date	Date Paid	Dividend (per share)
2017	November 1 August 1 May 1 February 1	November 15 August 15 May 15 February 15		0.25625 0.25625 0.25625 0.25625
2016	November 1 July 22 May 2 February 2	November 15 August 15 May 16 February 16		0.25625 0.25625 0.25625 0.25625
2015	November 2 July 31 May 1 February 3	November 15 August 17 May 15 February 17		0.25625 0.25625 0.25625 0.25625


Series E First Preferred Shares
Fiscal Year	Record Date	Date Paid	Dividend (per share)
2017	November 1 August 1 May 1 February 1	November 15 August 15 May 15 February 15		0.28125 0.28125 0.28125 0.28125
2016	November 1 July 22 May 2 February 2	November 15 August 15 May 16 February 16		0.28125 0.28125 0.28125 0.28125
2015	November 2 July 31 May 1 February 3	November 15 August 17 May 15 February 17		0.28125 0.28125 0.28125 0.28125


Series F First Preferred Shares
Fiscal Year	Record Date	Date Paid	Dividend (per share)
2017	November 1 August 1 May 1 February 1	November 15 August 15 May 15 February 15		0.265625 0.265625 0.265625 0.265625
2016	November 1 July 22 May 2 February 2	November 15 August 15 May 16 February 16		0.265625 0.265625 0.265625 0.265625
2015	November 2 July 31 May 1 February 3	November 15 August 17 May 15 February 17		0.265625 0.265625 0.265625 0.265625

2017 Annual Information Form

⁽¹⁾	On February 6, 2015, Emera approved an increase in the annual common share dividend rate from $1.55 to $1.60. The first payment was effective May 2015.

⁽²⁾	On August 11, 2015, Emera approved an increase in the annual common share dividend rate from $1.60 to $1.90. The first payment was effective November 2015.

⁽³⁾	On July 4, 2016, Emera approved an increase in the annual common share dividend rate from $1.90 to $2.09. The first payment was effective August 2016.

⁽⁴⁾	On September 29, 2017, Emera approved an increase in the annual common share dividend rate from $2.09 to $2.26. The first payment was effective November 2017.

⁽⁵⁾	The Series B First Preferred Shares were issued August 17, 2015.

Emera maintains the Dividend Reinvestment Plan, which provides an opportunity for shareholders to reinvest dividends and to participate in optional cash contributions for the purpose of purchasing common shares. Dividends will reinvest at a discount of up to 5% from the average market price of Emera’s common shares.

CREDIT RATINGS

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


	Moody’s	S&P
Outlook	Negative	Stable
Corporate	Baa3	BBB +
Senior unsecured debt program	Baa3	BBB
Hybrid Notes	Ba2	BBB-
First Preferred Shares	N/A	P-2 (low)

⁽¹⁾

Ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities and are indicators of the likelihood of the payment capacity and willingness of an issuer to meet its financial commitment in accordance with the terms of the obligation. The credit ratings assigned by the Rating Agencies are not recommendations to buy, sell, or hold securities in as much as such ratings are not a comment upon the market price of the securities or their stability for a particular investor. The credit ratings assigned to the securities may not reflect the potential impact of all risks on the value of the securities. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a Rating Agency in the future if in its judgment circumstances so warrant.

Moody’s

Moody’s credit ratings are on a long term debt rating scale that ranges from AAA to C, representing the range from highest to lowest quality of such rated securities. The rating of Baa3 obtained from Moody’s in respect of the senior unsecured debt is the fourth highest of nine available rating categories and indicates that the obligations are subject to moderate credit risk. As such, they are considered medium-grade and may possess speculative characteristics. The rating of Ba2 from Moody’s in respect of the Hybrid Notes is characterized as having speculative elements and being subject to substantial credit risk. It is the fifth highest of nine available rating categories. Moody’s appends numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.

S&P

S&P’s credit ratings are on a long term debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The issuer rating of BBB+ obtained from S&P in respect of the corporate rating indicates that the issuer has adequate capacity to meet its financial commitments. The issue ratings of BBB and BBB- from

2017 Annual Information Form

S&P in respect of the senior unsecured debt and the Hybrid Notes, respectively, indicate that the obligations exhibit adequate protection parameters. The issue and issuer rating of BBB is the fourth highest of ten available ratings categories and the addition of a “(+)” or “(-)” designation after a rating indicates the relative standing within a particular category. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation.

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

Emera has made, or will make, payments in the ordinary course to the Rating Agencies in connection with the assignment of ratings on both Emera and its securities. In addition, Emera has made customary payments in respect of certain subscription services provided to Emera by the Rating Agencies during the last two years.

MARKET FOR SECURITIES

Trading Price and Volume

Emera’s common shares, Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares and Series F First Preferred Shares are listed and posted for trading on the TSX under the symbols “EMA”, “EMA.PR.A”, “EMA.PR.B”, “EMA.PR.C”, “EMA.PR.E” and “EMA.PR.F”, respectively. Depositary receipts representing common shares of Emera are listed on the BSE under the symbol EMABDR. As at January 22, 2018, depositary receipts representing common shares of Emera were listed on the BISX under the symbol EMAB.

The trading volume and high and low price for Emera’s securities for each month of 2017 are set out below:


Common Shares
2017	High ($)		Low($)		Volume
January		46.31		44.68		11,413,321
February		46.50		44.77		11,645,836
March		47.65		45.10		15,113,354
April		47.94		46.73		7,960,839
May		48.37		46.15		11,136,681
June		49.24		47.75		13,630,381
July		48.35		45.90		9,647,318
August		48.22		46.27		8,841,035
September		48.16		45.89		12,427,767
October		49.37		47.21		9,780,432
November		49.33		47.26		9,317,091
December		49.48		46.62		14,494,717


Series A First Preferred Shares
2017	High ($)		Low($)		Volume
January		15.99		15.06		209,554
February		16.73		15.44		257,610
March		16.94		16.18		85,046

2017 Annual Information Form


April	17.69	16.88	182,093
May	17.17	15.55	43,642
June	17.77	15.65	87,594
July	18.45	17.78	71,400
August	18.27	17.86	45,798
September	18.50	17.85	47,268
October	18.71	18.14	262,708
November	18.40	18.09	86,733
December	18.51	17.70	75,048


Series B First Preferred Shares
2017	High ($)		Low($)		Volume
January		14.51		13.73		6,920
February		15.67		14.50		44,190
March		16.03		14.92		33,300
April		16.39		16.00		57,384
May		16.26		15.01		69,865
June		17.62		15.11		35,166
July		18.00		17.40		18,109
August		18.49		17.75		21,030
September		18.31		17.90		19,404
October		18.52		18.00		20,900
November		18.40		17.76		18,825
December		18.24		17.64		34,635


Series C First Preferred Shares
2017	High ($)		Low($)		Volume
January		22.49		21.39		325,236
February		23.02		21.94		264,981
March		23.42		22.12		173,981
April		24.23		23.03		154,316
May		23.35		20.99		126,122
June		23.53		21.01		272,052
July		23.84		23.18		332,245
August		23.50		22.76		52,164
September		23.84		22.91		60,063
October		24.25		23.65		107,262
November		24.35		23.90		61,269
December		24.34		23.50		74,470


Series E First Preferred Shares
2017	High ($)		Low($)		Volume
January		22.45		20.96		52,451
February		22.48		21.73		34,857
March		22.72		22.03		57,253
April		22.93		22.37		74,009

2017 Annual Information Form


May	22.84	22.18	50,780
June	22.65	22.32	56,835
July	22.45	21.61	35,141
August	21.81	21.45	33,561
September	21.52	20.57	65,291
October	21.74	21.00	140,901
November	22.04	21.25	46,252
December	22.00	21.28	47,650


Series F First Preferred Shares
2017	High ($)		Low($)		Volume
January		22.47		21.38		123,526
February		22.75		22.00		264,364
March		23.14		22.02		274,163
April		24.07		22.96		104,104
May		23.16		21.00		107,137
June		23.48		21.21		107,013
July		23.88		23.25		99,233
August		23.81		23.20		164,864
September		24.50		23.33		47,220
October		24.77		24.02		69,545
November		24.50		24.09		33,576
December		24.47		23.64		57,398


Depositary Receipts*
2017	High ($) BBD		Low($) BBD		Volume
January		17.40		16.59		0
February		17.34		16.99		0
March		17.52		16.61		0
April		17.66		17.31		0
May		17.56		16.91		0
June		18.41		17.65		0
July		18.56		18.01		0
August		18.96		18.09		0
September		19.38		18.51		0
October		19.18		18.68		0
November		18.89		18.33		0
December		19.16		18.11		0

*	The DRs did not trade on the BSE in 2017. The table above represents the trading price of the Barbados DRs to the trading price of the Emera common shares on the TSX.

TRANSFER AGENT AND REGISTRAR

AST Canada acts as Emera’s transfer agent and registrar. Registers for the registration and transfer of securities of Emera are kept at AST Canada’s principal offices in Halifax, Montreal and Toronto.

2017 Annual Information Form

DIRECTORS AND OFFICERS

Directors

The following information is provided for each Director of Emera as at December 31, 2017:


Name and Residence	Principal Occupations During the Past Five Years and Other Information	Director Since ⁽¹⁾

Sylvia D. Chrominska⁽⁸⁾ Toronto, Ontario Canada	Former Group Head of Global Human Resources and Communications for The Bank of Nova Scotia, where she had global responsibility for human resources, corporate communications, government relations, public policy and corporate social responsibility of the Scotiabank Group. Former Chair of the Board of Scotia Group Jamaica Limited and Former Chair of the Board of Scotiabank Trinidad and Tobago Limited. A Director of Wajax Corporation.	2010

Henry E. Demone⁽³⁾⁽⁴⁾ Lunenburg, Nova Scotia Canada	Chairman and Chief Executive Officer of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May 2015. A Director of Saputo Inc.	2014

Allan L. Edgeworth⁽⁴⁾⁽⁹⁾ Calgary, Alberta Canada	Former President of ALE Energy Inc., a private consulting company. Former President and Chief Executive Officer of Alliance Pipeline. Director of AltaGas Ltd.	2005

James D. Eisenhauer, FCPA, FCA⁽²⁾ Lunenburg, Nova Scotia Canada	President and Chief Executive Officer of ABCO Group Limited, which has holdings in manufacturing and distribution activities. Former Chair of the NSPI Board of Directors from May 2011 until May 2016, and a former Director of NSPI since 2008.	2011

Kent M. Harvey⁽²⁾ New York, New York U.S.	Former Chief Financial Officer for PG&E Corporation, an energy-based holding company, and the parent of Pacific Gas and Electric Company, an energy company that serves 16 million Californians across a 70,000 square-mile service area in Northern and Central California.	2017

Christoper G. Huskilson⁽¹¹⁾ Wellington, Nova Scotia Canada	President and Chief Executive Officer since November 1, 2004. From July 2003 to November 2004, Chief Operating Officer of Emera. He held the office of President and Chief Executive Officer of Emera’s subsidiary, NSPI from November 2004 to May 2006, and before that Chief Operating Officer of NSPI from January 2001 to November 2004. Prior to 2001, actively engaged for more than five years in the affairs of NSPI in various managerial and executive capacities.	2004

2017 Annual Information Form


Name and Residence	Principal Occupations During the Past Five Years and Other Information	Director Since ⁽¹⁾

B. Lynn Loewen, FCPA, FCA⁽²⁾⁽⁵⁾ Westmount, Quebec Canada	President of Minogue Medical Inc., a healthcare organization which delivers innovative medical technologies to hospitals and clinics. President of Expertech Network Installation Inc. from 2008 to 2011.	2013

John T. McLennan⁽³⁾ Mahone Bay, Nova Scotia Canada	Former Chair of the Board from May 2009 to May 2014. Former Board member of Chorus Aviation Inc. from January 2006 to May 2014. Former Chair of the Board of NSPI from May 2006 to May 2009. Former Vice-Chair and Chief Executive Officer of Allstream Inc. (formerly AT&T Canada). He is presently a Director of Amdocs Ltd.	2005

Donald A. Pether⁽⁵⁾⁽⁶⁾ Dundas, Ontario Canada	Former Chair of the Board and Chief Executive Officer of ArcelorMittal Dofasco Inc., a Canadian steel producer. Director of Samuel, Son & Co. Ltd. and Schlegel Health Care Inc. Former Chair of the Canadian Steel Producers Association and former member of the board of the American Iron and Steel Institute. Honorary Doctor of Law degree from McMaster University. Member of the Council of Governors for the Art Gallery of Hamilton, the Board of the National Gallery of Canada Foundation and on the Board of the Manning Awards Foundation.	2008

John B. Ramil⁽⁵⁾ Tampa, Florida U.S.	Former President and Chief Executive Officer of TECO Energy. Held a variety of leadership positions in his four decades with Tampa Electric. Former member of the board of the Edison Electric Institute, an industry association. Chair of GuideWell Mutual Holding Corporation and Blue Cross and Blue Shield of Florida boards. Member of the Florida Council of 100, the board of the Moffitt Cancer Center Institute and Trustee and past Chair of the University of South Florida. Former member of the board of the Tampa Bay Partnership.	2016

Andrea S. Rosen⁽⁷⁾ Toronto, Ontario Canada	Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Former Director of Alberta Investment Management Corporation. Director of Manulife Financial Corporation.	2007

Richard P. Sergel⁽³⁾⁽⁴⁾ Boston, Massachusetts U.S.	Former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC). Former President and Chief Executive Officer of National Grid USA from 2000 to 2004. Also former President and Chief Executive Officer of the New England Electric System. Presently a Director of State Street Corporation. Has also served on the boards of the Edison Electric Institute and the Consortium for Energy Efficiency.	2010

2017 Annual Information Form


Name and Residence	Principal Occupations During the Past Five Years and Other Information	Director Since ⁽¹⁾

M. Jacqueline Sheppard⁽¹⁰⁾ Calgary, Alberta Canada	Chair of the Board since May 2014. Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Former Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a provincial Crown Corporation. Founder and Lead Director of Black Swan Energy Inc., an Alberta upstream energy company that is private equity financed. Director of Cairn Energy PLC, a publicly traded UK based international upstream oil and gas producer. Director of Seven Generations Energy Ltd., a publicly traded energy company focused on Canadian natural gas development.	2009

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

⁽²⁾	Denotes member of the Audit Committee;

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

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

⁽⁵⁾	Denotes member of the Health, Safety and Environment 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 Health, Safety and Environment Committee;

⁽¹⁰⁾	Denotes Chair of the Board;

⁽¹¹⁾	Effective March 29, 2018, Mr. Huskilson will retire as a Director and as President and Chief Executive Officer. Mr. Scott Balfour has been appointed a Director and the President and Chief Executive Officer to succeed Mr. Huskilson on that date.

As at December 31, 2017, the Directors, in total, beneficially owned or controlled, directly or indirectly, approximately 152,725 common shares or less than 1% of the issued and outstanding shares of Emera.

There are no material conflicts of interest between Emera or any of its subsidiaries and any director or officer of Emera or any of its subsidiaries.

Audit Committee

The Audit Committee of Emera is composed of the following four members, all of whom are independent Directors: Andrea S. Rosen (Chair), Kent M. Harvey, B. Lynn Loewen and James D. Eisenhauer. The responsibilities and duties of the Audit Committee are set out in the Audit Committee’s Charter, a copy of which is attached as Appendix “A” to this AIF.

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

Andrea S. Rosen, Committee Chair

Vice-Chair of TD Bank Financial Group and President, TD Canada Trust from 2002 to 2005. From 2001 to 2002, Executive Vice President of TD Commercial Banking and Vice Chair TD Securities. Before joining TD Bank, was Vice President of Varity Corporation from 1991 to 1994, and worked at Wood Gundy Inc. (later CIBC-Wood Gundy) in a variety of roles from 1981 to 1990, eventually becoming Vice President and Director. Holds a Bachelor of Laws from Osgoode Hall Law School and a

2017 Annual Information Form

Masters of Business Administration from the Schulich School of Business at York University. Received a Bachelor of Arts from Yale University. Former Director and member of the Audit Committee of Hiscox Ltd., a U.K. reporting issuer listed on the London Stock Exchange, and Director and member of the Audit Committee of Manulife Financial Corporation, an issuer listed on The Toronto Stock Exchange, New York Stock Exchange, The Stock Exchange of Hong Kong, and the Philippine Stock Exchange. Former Director of Alberta Investment Management Corporation. Member of the Board of Directors of the Institute of Corporate Directors.

B. Lynn Loewen, FCPA, FCA

President of Minogue Medical Inc., a healthcare organization which delivers innovative medical technologies to hospitals and clinics. Fellow of the Institute of Chartered Accountants, she has served in a number of senior roles at Bell Canada, Air Canada Jazz and Air Nova, and also was the Vice President, Financial Controls for BCE. She has served as Chair of the Audit Committee on the Public Sector Pension Investment Board, and was Chair of the Finance and Administration Committee of Mount Allison University. In January 2018, she was appointed Chancellor of Mount Allison University. She holds a Bachelor of Commerce from Mount Allison University.

James D. Eisenhauer, FCPA, FCA

President and Chief Executive Officer of ABCO Group Limited, which has holdings in manufacturing and distribution. Professional Engineer and a Fellow of the Chartered Professional Accountants of Nova Scotia. Mr. Eisenhauer was a member of the Board of Nova Scotia Business Inc. from 2005 to January 2013, serving as Chair from November 2010 to October 2012. He has also been a member of the Board of Stelia Aerospace North America Inc. since 2014 (and its predecessors, Composites Atlantic Limited since 1993 and Cellpack Aerospace Limited since 1987). He is also on the Advisory Board of Atlantic Industries Limited and is Chair of its Advisory Audit Committee. Mr. Eisenhauer holds a Bachelor of Science from Dalhousie University and a Bachelor of Engineering (with distinction) from the Technical University of Nova Scotia.

Kent M. Harvey

Former Chief Financial Officer for PG&E Corporation, a Fortune 200 energy-based holding company headquartered in San Francisco. PG&E Corporation is the parent company of Pacific Gas and Electric Company, one of the largest combined natural gas and electric energy companies in the United States. In over 33 years with PG&E Corporation, held progressively senior roles, including Senior Vice President and Chief Financial Officer 2009 to 2015, Senior Vice President, Chief Risk and Audit Officer 2005 to 2009. He was Senior Vice President, Chief Financial Officer and Treasurer with Pacific Gas and Electric Company, a subsidiary of PG&E Corporation, from 2000 to 2005. He holds a Bachelor’s degree in Economics and a Master’s degree in Engineering – Economic Systems, both from Stanford University.

Audit and Non-Audit Services Pre-Approval Process

The Audit Committee is responsible for the oversight of the work of the external auditors. As part of this responsibility, the Audit 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 will also require specific approval by the Audit Committee.

2017 Annual Information Form

Auditors’ Fees

The aggregate fees billed by Ernst & Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2017 and 2016 respectively, were as follows:


Service Fee	2017 ($)		2016 ($)
Audit Fees		1,495,580		1,161,150
Audit-Related Fees		445,769		651,397
Tax Fees		467,353		419,669
Other		Nil		Nil

Total		2,408,702		2,232,216

Audit-related fees for Emera relate to accounting and disclosure consultations and services associated with securities offerings. Tax fees for Emera relate to the structuring of cross-border financing of Emera’s subsidiaries and affiliates as well as tax compliance services and general tax consulting advice on various matters.

2017 Annual Information Form

Officers

The Officers⁽¹⁾ of Emera as at December 31, 2017 were as follows:



Chris Huskilson⁽²⁾ President and Chief Executive Officer Wellington, Nova Scotia Canada		President and Chief Executive Officer since November 1, 2004. From July 2003 to November 2004, Chief Operating Officer of Emera. He held the office of President and Chief Executive Officer of NSPI from November 2004 to May 2006, and before that Chief Operating Officer of NSPI from January 2001 to November 2004. Prior to 2001, actively engaged for more than five years in the affairs of NSPI in various managerial and executive capacities.

Scott Balfour⁽²⁾ Chief Operating Officer Halifax, Nova Scotia Canada		Chief Operating Officer since November 2016. Chief Operating Officer Northeast and Caribbean, from March to November 2016. Executive Vice President and Chief Financial Officer of Emera from April 2012 to March 2016. From May 2011 to April 2012, President of Ensimian Capital Corporation. From September 2005 to January 2011, President and Chief Financial Officer of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company.

Gregory W. Blunden, CPA, CA Chief Financial Officer Halifax, Nova Scotia Canada		Chief Financial Officer since March 2016. Previously Vice-President, Corporate Strategy & Planning of Emera and before that held the position of EVP, Customer, Business & Financial Services at NSPI.

Robert Hanf Executive Vice-President, Stakeholder Relations and Regulatory Affairs Halifax, Nova Scotia Canada		Executive Vice-President, Stakeholder Relations and Regulatory Affairs since August 2016. Previously, President and Chief Executive Officer of NSPI until August 2016 and before that Chief Legal Officer of Emera.

Bruce A. Marchand Chief Compliance Officer and Chief Legal Officer Halifax, Nova Scotia Canada		Chief Compliance Officer since December 1, 2014. Chief Legal Officer since January 2012. Prior to January 2012, Senior Partner at the law firm of McInnes Cooper.

R. Michael Roberts Chief Human Resources Officer Halifax, Nova Scotia Canada		Chief Human Resources Officer since December 1, 2014. Previously, President, Optimum Talent Atlantic of Halifax. Prior to that, Vice President, Corporate Development at Irving Shipbuilding and Vice President, Human Resources at Bell Aliant.

Daniel P. Muldoon Executive Vice-President Major Renewables and Alternative Energy Halifax, Nova Scotia Canada		Executive Vice-President, Major Renewables and Alternative Energy since May 2014. From June 16, 2011 to March 31, 2013, President and Chief Operating Officer, Emera Utility Services Inc. Prior to that, General Manager Engineering & Construction, Emera.

2017 Annual Information Form



Wayne O’Connor Executive Vice-President, Business Development and Strategy Halifax, Nova Scotia Canada		Executive Vice-President, Business Development and Strategy since December 15, 2017. Previously,, Executive Vice-President Corporate Strategy and Planning since March 2016. From October 2012 to February 2016, Executive Vice President Operations, NSPI. From June 2011 to October 2012, President and Chief Operating Officer of Emera Energy. From April 2008 to June 2011, Chief Operating Officer of Emera Energy.

Sarah R. MacDonald Executive Vice-President Corporate Safety and Environment Tampa, Florida United States		Executive Vice-President Corporate Safety and Environment since December 18, 2017. Also President of TECO Services, Inc. from September 1, 2016. From June 11, 2013 to July 7, 2017 Executive Chairman of ECI From June 30, 2011 to December 1, 2016, President and Chief Executive Officer of GBPC.

Stephen D. Aftanas Corporate Secretary Halifax, Nova Scotia Canada		Corporate Secretary since September 2008. From June 2007 to September 2008, Associate Corporate Secretary. From March 2006 to June 2007, Associate General Counsel, NSPI. Prior to March 2006, Senior Solicitor, Emera.

⁽¹⁾	Richard C. Janega is appointed Chief Operating Officer, Electric Utilities, Canada, US Northeast, and Caribbean, an Officer of the Company, effective March 31, 2018.

⁽²⁾	Effective March 29, 2018, Mr. Huskilson retires as President and Chief Executive Officer. Mr. Balfour has been appointed President and Chief Executive Officer to succeed Mr. Huskilson on that date.

As at December 31, 2017, the Directors and Officers, in total, beneficially owned or controlled, directly or indirectly, approximately 211,446 common shares or less than 1% of the issued and outstanding shares of Emera.

CERTAIN PROCEEDINGS

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

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

(a)

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

(b)

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

(2)

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

(3)

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

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(4)

have been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory body or has entered in a settlement agreement with a securities regulatory body, or is subject to any penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor making an investment decision.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

To the knowledge of Emera, there are no legal proceedings that individually or together could potentially involve claims against Emera or its subsidiaries for damages totaling 10% or more of the current assets of Emera, exclusive of interest and costs.

NO INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

MATERIAL CONTRACTS

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

Material contracts entered into in connection with the financings related to the TECO Transaction, namely, the applicable Trust Indenture and First Supplemental Indenture in respect of the issuance of each of the U.S. Notes, the Hybrid Notes and the Canadian Notes, have been filed on SEDAR at www.sedar.com.

EXPERTS

Interest of Experts

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

PricewaterhouseCoopers LLP were the auditors of TECO Energy, and as such were the auditors of the financial statements in respect of the TECO Transaction included in the business acquisition report of Emera filed on August 5, 2016, as set forth in its report thereon. In 2018, Ernst & Young LLP have been appointed auditors of TECO Energy, replacing PricewaterhouseCoopers LLP.

2017 Annual Information Form

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, 2017.

At any time, Emera will provide to any person upon request to the Corporate Secretary, a copy of the Emera Code of Conduct.

2017 Annual Information Form

Appendix “A”

Emera Incorporated

Audit Committee Charter

PART I

MANDATE AND RESPONSIBILITIES

Committee Purpose

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

•

the quality and integrity of Emera’s financial statements;

•

the effectiveness of Emera’s internal control systems over financial reporting;

•

the internal audit and assurance process;

•

the qualifications, independence and performance of the external auditors;

•

major financial risk exposures;

•

Emera’s compliance with legal requirements and securities regulations in respect of financial statements and financial reporting; and

•

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

1.	Financial Reporting

The Committee shall be responsible for reviewing, assessing the completeness and clarity of the disclosures in, and recommending to the Board for approval:

(i)

the audited annual financial statements of Emera, all related Management’s Discussion and Analysis, and earnings press releases;

(ii)

any documents containing Emera’s audited financial statements; and,

(iii)

the quarterly financial statements, all related Management’s Discussion and Analysis, and earnings press releases.

The Committee shall oversee and assess that adequate procedures are in place for the review of public disclosure of financial information.

2.	External Auditors

The Committee shall evaluate and recommend to the Board the external auditor to be nominated for the purpose of preparing or issuing the auditor’s report or performing other audit, review, or attest services for Emera, and the compensation of such external auditors.

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.

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

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At least annually, the Committee shall obtain and review a report by the external auditors describing: (i) the firm’s internal quality control procedures; (ii) any material issues raised by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, with respect to one or more external audits carried out by the firm, and any steps taken to deal with any such issues; and (iii) all relationships between the external auditors and Emera (to assess the auditors’ independence). After reviewing the foregoing report and the external auditors’ work throughout the year, the Committee shall evaluate the auditors’ qualifications, performance, professional skepticism and independence. Such evaluation should include the review and evaluation of the lead audit partner and take into account the opinions of Management and the internal auditor. The Committee shall determine that the external audit firm has a process in place to address the rotation of the lead audit partner and other audit partners serving the account as required under prescribed independence rules. The Committee shall make recommendations to the Board on appropriate actions to be taken which the Committee deems necessary to protect and enhance the independence of the external auditor.

The Committee shall review the experience and qualifications of the audit team, the performance of the external auditor, including assessing their effectiveness and quality of service, annually and, every five (5) years, perform a comprehensive review of the performance of the external auditors over multiple years to provide further insight on the audit firm, its independence and application of professional standards.

The Committee shall regularly review with the external auditors any audit problems or difficulties encountered during the course of the audit work, including any restrictions on the scope of the external auditors’ activities or access to requested information, and Management’s response.

The Committee will review differences that were noted or proposed by the external auditors, but that were considered immaterial or insignificant; and any “management” or “internal control” letter issued, or proposed to be issued.

3.	Non-Audit Services

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.

The Committee may establish specific policies and procedures concerning the performance of non-audit services by the external auditor so long as the requirements of applicable legislation and regulation are satisfied.

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

4.	Oversight and Monitoring of Audits

The Committee shall review with the external auditor, the internal auditors and Management (i) the audit function generally, (ii) the objectives, staffing, locations, co-ordination, reliance upon Management and internal audit and, (iii) for subsidiaries, reliance on external audit, (iv) general audit approach and scope of proposed audits of the financial statements of Emera and its subsidiaries, (v) the overall audit plans, (vi) the responsibilities of Management, the internal auditors and the external auditor, (vii) the audit procedures to be used and (viii) the timing and estimated budgets of the audits.

The Committee shall discuss with the external auditor any issues that arise with Management or the internal auditors during the course of the audit and the adequacy of Management’s responses in addressing audit-related deficiencies.

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The Committee shall review with Management the results of internal and external audits.

The Committee shall take such other reasonable steps as it may deem necessary to oversee that the audit was conducted in a manner consistent with applicable legal requirements and auditing standards of applicable professional or regulatory bodies.

5.	Oversight and Review of Accounting Principles and Practices

The Committee shall oversee, review and discuss with Management, the external auditor and the internal auditors:

the quality, appropriateness and acceptability of Emera’s accounting principles and practices used in its financial reporting, changes in Emera’s accounting principles or practices and the application of particular accounting principles and disclosure practices by Management to new transactions or events;

all significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including the effects of alternative methods within generally accepted accounting principles on the financial statements and any “other opinions” sought by Management from an independent auditor, other than the Company’s external auditors, with respect to the accounting treatment of a particular item, and other material written communications between the external auditors and management;

disagreements between Management and the external auditor or the internal auditors regarding the application of any accounting principles or practices;

any material change to Emera’s auditing and accounting principles and practices as recommended by Management, the external auditor or the internal auditors or which may result from proposed changes to applicable generally accepted accounting principles;

the effect of regulatory and accounting initiatives on Emera’s financial statements and other financial disclosures;

any reserves, accruals, provisions, estimates or Management programs and policies, including factors that affect asset and liability carrying values and the timing of revenue and expense recognition, that may have a material effect upon the financial statements of Emera;

the use of special purpose entities and the business purpose and economic effect of off-balance sheet transactions, arrangements, obligations, guarantees and other relationships of Emera and their impact on the reported financial results of Emera;

any legal matter, claim or contingency that could have a significant impact on the financial statements, Emera’s compliance policies and any material reports, inquiries or other correspondence received from regulators or governmental agencies and the manner in which any such legal matter, claim or contingency has been disclosed in Emera’s financial statements;

the treatment for financial reporting purposes of any significant transactions which are not a normal part of Emera’s operations.

6.	Hiring Policies

The Committee shall review and approve Emera’s hiring policy concerning partners or employees, as well as former partners and employees, of the present or former external auditors of Emera.

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7.	Pension Plans

The Committee shall exercise oversight of the pension plans in accordance with the Pension Oversight Framework adopted by Emera.

8.	Oversight of Finance Matters

The Committee shall review the appointments of key financial executives involved in the financial reporting process of Emera, including the Chief Financial Officer.

The Committee may request for review, and shall receive when requested, material tax policies and tax planning initiatives, tax payments and reporting and any pending tax audits or assessments. The Committee shall review Emera’s compliance with tax and financial reporting laws and regulations.

The Committee shall meet at least annually with Management to review and discuss Emera’s major financial risk exposures and the policy steps Management has taken to monitor and control such exposures, including the use of financial derivatives, hedging activities, and credit and trading risks.

The Committee may review any investments or transactions that the Committee wishes to review, or which the internal or external auditor, or any officer of Emera, may bring to the attention of the Committee within the context of this charter.

The Committee shall review financial information of material subsidiaries of Emera and any auditor recommendations concerning such subsidiaries.

The Committee may request for review, and shall receive when requested, all related party transactions required to be disclosed pursuant to generally accepted accounting principles, and discuss with Management the business rationale for the transactions and whether appropriate disclosures have been made.

9.	Internal Controls

The Committee shall oversee:

the adequacy and effectiveness of the Company’s internal accounting and financial controls and the recommendations of Management, the external auditor and the internal auditors for the improvement of accounting practices and internal controls; and

management’s compliance with the Company’s processes, procedures and internal controls.

In exercising such oversight, the Committee shall review and discuss each of the foregoing with Management, the external auditor and the internal auditor.

The Committee will carry out the following specific duties:

Review and discuss with the Chief Executive Officer and the Chief Financial Officer the procedures undertaken in connection with the Chief Executive Officer and Chief Financial Officer certifications for the annual and interim filings with applicable securities regulatory authorities.

Review disclosures made by Emera’s Chief Executive Officer and Chief Financial Officer during their certification process for the annual and interim filing with applicable securities regulatory authorities about any significant deficiencies in the design or operation of internal controls which could adversely affect Emera’s ability to record, process, summarize and report financial data or any material weaknesses in the internal controls, and any fraud involving management or other employees who have a significant role in the Emera’s internal controls.

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Discuss with Emera’s Chief Legal Officer at least annually any legal matters that may have a material impact on the financial statements, operations, assets or compliance policies and any material reports or inquiries received by Emera or any of its subsidiaries from regulators or governmental agencies.

10.

Internal Auditor

The lead internal auditor shall report directly to the Committee. The Committee shall:

(i)

approve the appointment of;

(ii)

review the terms of engagement of;

(iii)

provide input into the annual performance evaluation of and compensation payable to;

(iv)

approve the replacement or termination of;

the lead internal auditor. The Committee shall approve the charter, reporting relationship, activities, staffing, organizational structure, and budget of the internal audit department as changes are needed.

The Committee shall review and approve the annual internal audit plan, and all major changes to the plan. The Committee shall review and discuss with the internal auditors the scope, progress, and results of executing the internal audit plan. The Committee shall receive reports on the status of significant findings, recommendations, and management’s responses.

The Committee shall meet periodically with the internal auditors to discuss the progress of their activities, any significant findings stemming from internal audits, any issues that arise with Management, and the adequacy of Management’s responses in addressing audit-related deficiencies.

The Committee shall obtain from the internal auditors and review summaries of the significant reports to Management prepared by the internal auditors, and the actual reports if requested by the Committee, and Management’s responses to such reports.

The Committee shall annually receive and review a report on the Chief Executive Officers’ expense accounts.

The Committee may communicate with the internal auditors with respect to their reports and recommendations, the extent to which prior recommendations have been implemented and any other matters that the internal auditor brings to the attention of the Committee.

The Committee shall, annually or more frequently as it deems necessary, evaluate the internal auditors including their activities, organizational structure and qualifications and effectiveness. The internal auditors shall confirm to the Committee that they adhere to applicable professional standards.

The Committee shall review the independence of the internal auditors and shall make recommendations to the Board on appropriate actions to be taken which the Committee deems necessary to protect and enhance the independence of the internal auditors.

11.

Complaints

The Committee shall oversee procedures relating to the receipt, retention, and treatment of complaints received concerning accounting, internal accounting controls, or auditing matters. The Committee shall also review procedures concerning the confidential, anonymous submission of concerns by Emera’s employees relating to questionable accounting or auditing matters.

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12.

Other Responsibilities

The Committee shall:

(a)

Annually, review insurance programs;

(b)

Periodically review Management’s process for identifying non-compliance with legal and regulatory requirements;

(c)

Annually receive and review a report on executive officers’ compliance with the Company’s Code of Conduct; and

(d)

Perform such other duties and exercise such powers as may be directed or delegated to the Committee by the Board.

13.

Limitation on Authority

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

PART II

COMPOSITION

14.

Composition

(a)

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

(b)

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

(c)

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

(d)

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

(e)

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

2017 Annual Information Form

PART III

COMMITTEE PROCEDURE

15.

Meetings

(a)

Meetings of the Committee may be called by the Chair or at the request of any member. The Committee shall meet at least quarterly.

(b)

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

(c)

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

(d)

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

16.

Separate Sessions

(a)

The Committee Chair shall meet periodically with the Chief Financial Officer, the lead internal auditor and the external auditor in separate executive sessions to discuss any matters that the Committee or each of these groups believes should be discussed privately.

(b)

The Chief Financial Officer, the lead internal auditor and the external auditor shall have access to the Committee to bring forward matters requiring its attention.

(c)

The Committee shall meet periodically without Management present.

17.

Quorum

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

18.

Chair

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

19.

Secretary and Minutes

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

20.

Board Relationships and Reporting

The Committee shall:

(a)

Review annually the Committee’s Charter;

2017 Annual Information Form

(b)

Oversee the appropriate disclosure of the Committee’s Charter as well as other information concerning the Committee which is required to be disclosed by applicable legislation in Emera’s Annual Information Form and any other applicable disclosure documents;

(c)

Report to the Board at the next following board meeting on any meeting held by the Committee, and as required, regularly report to the Board on Committee activities, issues, and related recommendations; and

(d)

Maintain free and open communication between the Committee, the external auditors, internal auditors, and Management, and determine that all parties are aware of their responsibilities.

21.

Powers

The Committee shall:

(a)

examine and consider such other matters, and meet with such persons, in connection with the internal or external audit of Emera’s accounts, which the Committee in its discretion determines to be advisable;

(b)

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

(c)

have the right to inspect all records of Emera or its affiliates and may elect to discuss such records, or any matters relating to the financial affairs of Emera with the officers or auditors of Emera and its affiliates.

22.

Experts and Advisors

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