Document:

EX-4.1

 Exhibit 4.1 
  

 
 Exhibit 4.1 
2015 
Annual Information Form
Emera Incorporated 
March 30, 2016
Emera 

			
	2015 Annual Information Form	  	
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 Table of Contents 
  

					
	 Definitions
	  	 	2-9	  
	 Cautionary Note Regarding Forward - Looking Information
	  	 	10-11	  
	 Introduction
	  	 	12	  
	 Corporate Structure
	  	 	13	  
	 General Development of the Business
	  	 	13	  
	 Emera Business and Operations Three-Year History
	  	 	13-23	  
	 Financing Activity
	  	 	23-27	  
	 Changes in Business Expected During 2016
	  	 	27-31	  
	 Description of the Business
	  	 	31-32	  
	 NSPI
	  	 	32-34	  
	 Emera Maine
	  	 	34-37	  
	 Emera Caribbean
	  	 	37-40	  
	 Emera Energy
	  	 	40-42	  
	 Pipelines
	  	 	42-43	  
	 Corporate and Other
	  	 	43	  
	 Risk Factors
	  	 	43	  
	 Capital Structure
	  	 	43	  
	 Common Shares
	  	 	44	  
	 Emera First Preferred Shares
	  	 	44-49	  
	 Emera Second Preferred Shares
	  	 	49	  
	 Share Ownership Restrictions
	  	 	49	  
	 NSPI Series D First Preferred Shares
	  	 	49	  
	 Dividends
	  	 	50-51	  
	 Credit Ratings
	  	 	51-52	  
	 Market for Securities
	  	 	53-54	  
	 Directors
	  	 	55-56	  
	 Audit Committee
	  	 	56-58	  
	 Officers
	  	 	59-60	  
	 Certain Proceedings
	  	 	61	  
	 Legal Proceedings and Regulatory Actions
	  	 	61	  
	 No Interest of Management and Others in Material Transactions
	  	 	61	  
	 Material Contracts
	  	 	62	  
	 Experts
	  	 	62	  
	 Additional Information
	  	 	62	  
	 Appendix “A”- Audit Committee Charter
	  	 	63-68	  

			
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 DEFINITIONS 

For convenience, terms used throughout this 2015 AIF of Emera Incorporated shall have the following meanings: 

“Adjusted net income” means net income attributable to common shareholders, as defined by USGAAP excluding the effect of after-tax
mark-to-market adjustments related to certain derivative instruments, the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp and NWP, the mark-to-market adjustments related to an
interest rate swap in EBPC, the mark-to-market adjustments related to the effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering for the TECO Transaction and
the mark-to-market adjustments included in Emera Energy’s margin, including adjustments related to the price differential between the point where natural gas is sourced and where it is delivered and the amortization of transportation capacity
recognized as a result of certain marketing and trading transactions. See the “Non-GAAP Financial Measures” section of the MD&A for the year ended December 31, 2015, which is incorporated herein by reference; 

“AFUDC” means allowance for funds used during construction and represents the cost of financing regulated construction projects and is
capitalized to the cost of property, plant and equipment, where permitted by the regulator; 
 “AIF” means this 2015 Annual Information
Form of Emera; 
 “APUC” means Algonquin Power & Utilities Corp., a company incorporated under the federal laws of Canada and traded on
the TSX under the symbol “AQN”; 
 “Atlantic Provinces” means the region of Canada consisting of the Provinces of New Brunswick,
Newfoundland and Labrador, Nova Scotia and Prince Edward Island; 
 “Bangor Hydro” means Bangor Hydro Electric Company, a transmission and
distribution electric utility company incorporated under the laws of the State of Maine and a wholly owned, indirect subsidiary of Emera which merged on January 1, 2014 with MPS to form Emera Maine; 

“Bangor Hydro District” means the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions
of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis and Aroostook; 
 “Bayside Power LP” means Bayside Power
Limited Partnership, a 290 MW gas-fired electricity generating facility and limited partnership governed by the laws of the Province of New Brunswick and wholly owned indirectly by Emera; 

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

“BLPC” means The Barbados Light & Power Company Limited, a vertically integrated electric utility company incorporated under the laws of
Barbados and a wholly owned, direct subsidiary of Emera (Caribbean) Incorporated; 
 “Board” means the Board of Directors of Emera; 

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

			
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 “Brunswick Pipeline” means the pipeline delivering re-gasified natural gas from the Canaport
LNG gas terminal near Saint John, New Brunswick to markets in the Northeastern United States, which is owned directly by EBPC. The pipeline travels through southwest New Brunswick and connects with M&NP at the Canada/US border near Baileyville,
Maine; 
 “Bull Hill” means Blue Sky East, LLC, a company incorporated under the laws of the State of Delaware which owns a 34.5 MW wind
farm located south of Bangor, Maine, and in which Emera held an indirect interest of 49% through its joint venture with First Wind in NWP until January 29, 2015, when Emera sold its interest in NWP; 

“CAD” means Canadian dollars; 

“CEO” means the President and Chief Executive Officer of Emera; 

“Company” means Emera; 
 “Completion
Guarantee” means a completion guarantee granted by Emera in favour of the Government of Canada under which Emera has guaranteed the performance of the obligations of NSP Maritime Link Inc. to cause the completion of the Maritime Link
Project in the circumstances and within the timelines provided for in the Completion Guarantee. The Payment Obligation Agreement (as defined below) and Completion Guarantee collectively satisfy the requirement in the FLG term sheet to deliver the
“Emera Guarantee Agreement”; 
 “Computershare” means Computershare Trust Company of Canada; 

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

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

“Debentures” means the 4.0% convertible unsecured subordinated debentures of Emera that were issued on September 28 and October 2, 2015
in order to finance a portion of the TECO Transaction; 
 “Debenture Offering” means the sale of the Debentures by the Selling
Debentureholder; 
 “Directors” mean the directors of Emera and “Director” means one of them; 

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

“Domlec” means Dominica Electricity Services Limited, an integrated electric utility on the island of Dominica, incorporated under the laws
of the Commonwealth of Dominica, and an indirect subsidiary of Emera, through Emera (Caribbean) Incorporated; 
 “DR” means depositary
receipt; 
 “EBH2” means Emera (Barbados) Holdings No. 2 Inc., an indirect wholly owned subsidiary of Emera; 

			
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 “EBPC” means Emera Brunswick Pipeline Company Ltd., a company incorporated under the federal
laws of Canada and a wholly owned, direct subsidiary of Emera; 
 “ECC” means NSPI Energy Control Center; 

“ECHL” means Emera Caribbean Holdings Limited (formerly Emera Caribbean Limited), a company incorporated under the laws of Barbados and a
wholly owned, direct subsidiary of Emera and the direct or indirect parent company of ICDU, GBPC, Emera (Caribbean) Incorporated, BLPC and Domlec; 

“ECI” means Emera (Caribbean) Incorporated (formerly Light & Power Holdings Ltd.), a company incorporated under the laws of Barbados and
which is an indirect subsidiary of ECHL and the parent company of BLPC; 
 “EE New England Gas Generation” means Emera Energy Generation II
LLC, a company incorporated under the laws of the State of Delaware that holds the New England Gas Generation Facilities and a wholly owned, direct subsidiary of Emera; 

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

“Emera” means Emera Incorporated, a public company incorporated under the laws of the Province of Nova Scotia and traded on the TSX under the
symbol “EMA”; 
 “Emera Caribbean” means Emera’s direct and indirect ownership interests in ECHL, Emera (Caribbean)
Incorporated, BLPC, Domlec, GBPC, Emera Utility Services Bahamas and Lucelec; 
 “Emera Energy” means Emera Energy Incorporated, a wholly
owned, direct subsidiary of Emera, amalgamated under the laws of the Province of Nova Scotia, and whose business collectively includes the businesses of Emera Energy Services and Emera Energy Generation; 

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

“Emera Energy Services” means Emera Energy Services, Inc., a natural gas and electricity marketing and trading company incorporated under the
laws of the State of Delaware and a wholly owned, indirect subsidiary of Emera Energy; 
 “Emera Guarantee Agreement” means the condition
precedent in the FLG term sheet to deliver to the Government of Canada a guarantee of certain payment and performance obligations, which condition precedent was satisfied collectively by the Completion Guarantee (as defined above) and the Payment
Obligation Agreement (as defined below); 
 “Emera Maine” means the company resulting from the merger of Bangor Hydro and MPS under the
laws of the State of Maine on January 1, 2014, and a wholly owned indirect subsidiary of Emera; 
 “Emera Reinsurance Limited” is a captive
insurance company incorporated under the laws of Barbados providing insurance and reinsurance to Emera and certain affiliates, to enable more cost efficient management of risk and deductible levels across Emera. 

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

			
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 “Emera Utility Services Bahamas” means Emera Utility Services (Bahamas) Limited, a company
incorporated under the laws of the Commonwealth of The Bahamas and a wholly owned indirect subsidiary of Emera ,which provides utility construction services in The Bahamas; 

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

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

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

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

“Final Instalment” means the remaining $667 per Debenture that is payable on the Final Instalment Date; 

“Final Instalment Date” means the date to be fixed following satisfaction of conditions precedent to the closing of the TECO Transaction;

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

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

“GBPC” means Grand Bahama Power Company Limited, a vertically integrated electric utility company incorporated under the laws of the
Commonwealth of The Bahamas and a direct and indirect subsidiary of ECHL; 
 “Government of Canada Bond Yield” means the yield to maturity
on such date (assuming semi-annual compounding) of a Canadian dollar denominated non-callable Government of Canada bond with a term to maturity of five years as quoted as of 10:00 a.m. (Toronto time) on such date and which appears on the Bloomberg
Screen GCAN5YR Page on such date; provided that, if such rate does not appear on the Bloomberg Screen GCAN5YR Page on such date, the Government of Canada Bond Yield will mean the average of the yields determined by two registered Canadian investment
dealers selected by the Company, as being the yield to maturity on such date (assuming semi-annual compounding) which a Canadian dollar denominated non-callable Government of Canada bond would carry if issued in Canadian dollars at 100% of its
principal amount on such date with a term to maturity of five years; 
 “Government of Canada T-bill Rate” means, for any quarterly
floating rate period, the average yield expressed as a percentage per annum on three month Government of Canada treasury bills, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable floating rate
calculation date; 
 “GRA” means a general rate application; 

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

“ICDU” means ICD Utilities Limited, a company incorporated under the laws of the Commonwealth of The Bahamas, traded on the Bahamas
International Securities Exchange (BISX) under the symbol “ICD” and a direct subsidiary of ECHL; 
 “IFRS” means International
Financial Reporting Standards; 

			
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 “IPPs” means independent power producers; 

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

“ISO-NE” means ISO-New England, an independent, non-profit Regional Transmission Organization which oversees the operation of New
England’s bulk electric power system and transmission lines, generated and transmitted by its member utilities; 
 “km” means
kilometres; 
 “Labrador-Island Transmission Link Project” or “LIL” means an electricity transmission project in Newfoundland and
Labrador being developed by Nalcor, which will enable the transmission of the Muskrat Falls energy between Labrador and the island of Newfoundland; 

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

“LNG” means liquefied natural gas; 

“Lower Churchill Project Phase I” means the development of the Muskrat Falls Generating Station and associated transmission assets and the
Labrador-Island Transmission Link Project; 
 “LPH” means Light & Power Holdings Ltd., the former name of ECI; 

“Lucelec” means St. Lucia Electricity Services Limited, a company incorporated under the laws of St. Lucia in which Emera holds an indirect
18.2% interest through ECHL; 
 “M&NP” means the Maritimes & Northeast Pipeline, a pipeline that transports natural gas from
offshore Nova Scotia to markets in the Maritime Provinces and New England, in which Emera holds an indirect 12.9% interest; 
 “Make-Whole
Payment” means an amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Debenture Offering had the Debentures remained outstanding
and continued to accrue interest until and including such date; 
 “MAM” means Maine & Maritimes Corporation, a company incorporated
under the laws of the State of Maine, the parent company of MPS, and a wholly owned, indirect subsidiary of Emera; MAM was dissolved when MPS and Bangor Hydro merged on January 1, 2014, forming Emera Maine; 

“Maritime Link” or “NSP Maritime Link Inc.” means NSP Maritime Link Incorporated, a wholly owned direct subsidiary of ENL
incorporated under the laws of the Province of Newfoundland and Labrador that is developing the Maritime Link Project; 
 “Maritime Link
Project” means the transmission project including two 170-kilometre sub-sea cables between the island of Newfoundland and the Province of Nova Scotia, being developed by NSP Maritime Link Inc.; 

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

			
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 “MD&A” means Emera’s Management’s Discussion and Analysis for the fiscal year
ended December 31, 2015, a copy of which is available electronically under Emera’s profile on SEDAR at www.sedar.com; 
 “MLFT”
means Maritime Link Financing Trust, a special purpose funding vehicle formed by Emera; 
 “MMSCFD” means million standard cubic feet per
day; 
 “MPS” means Maine Public Service Company, a transmission and distribution electric utility company incorporated pursuant to the
laws of the State of Maine, and a wholly owned, direct subsidiary of MAM which merged on January 1, 2014 with Bangor Hydro to form Emera Maine; 

“MPS District” means the franchise electric service territory associated with MPS in northern Maine; 

“MPUC” means the Maine Public Utilities Commission, the independent regulator of Emera Maine and of Bangor Hydro and MPS prior to their
merger effective January 1, 2014 to form Emera Maine; 
 “MW” means the amount of electricity measured in megawatts; 

“Muskrat Falls Generating Station” means a hydroelectric generating facility at Muskrat Falls being developed by Nalcor on the Lower
Churchill River in Labrador; 
 “Nalcor” means Nalcor Energy, a Newfoundland and Labrador provincial Crown corporation; 

“NB Power” means New Brunswick Power, a provincial Crown Corporation responsible for the generation, transmission and distribution of
electricity in the Province of New Brunswick; 
 “NEB” means the Canadian National Energy Board, the independent regulator of EBPC; 

“NERC” means North American Electric Reliability Corporation; 

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

“New England Transmission Operators” means transmission utilities in the ISO-NE territory; 

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

“Northeastern United States” means the region of the United States consisting of New England and the States of New Jersey, New York and
Pennsylvania; 
 “NSPI” or “Nova Scotia Power” means Nova Scotia Power Incorporated, a vertically integrated electric
utility incorporated under the laws of the Province of Nova Scotia and a wholly owned direct and indirect subsidiary of Emera; 
 “NSPI’s
Annual Information Form” means the 2015 Annual Information Form of NSPI dated March 30, 2016, a copy of which is available electronically under NSPI’s profile on SEDAR at www.sedar.com; 

			
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 “NSPI Board” means the Board of Directors of NSPI; 

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

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

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

“Order” means a cease trade order, an order similar to a cease trade order or an order that denies a company access to any exemption under
securities legislation that was in effect for a period of more than thirty (30) consecutive days; 
 “Payment Obligation Agreement” means a
payment obligation agreement between Emera, NSP Maritime Link Inc. and the Government of Canada, which together with the Completion Guarantee (as defined above) collectively satisfy the requirement in the FLG term sheet to deliver the “Emera
Guarantee Agreement”; 
 “Pipelines” means EBPC, and Emera’s interest in M&NP; 

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

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

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

“RECL” means Repsol Energy Canada Ltd.; 

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

“ROE” means return on equity; 

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

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

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

“Selling Debentureholder” means Emera Holdings NS Company, a company incorporated under the laws of the Province of Nova Scotia and a wholly
owned direct subsidiary of Emera; 
 “Series A First Preferred Shares” means the cumulative 5-year rate reset first preferred shares,
Series A of Emera; 
 “Series B First Preferred Shares” means the cumulative floating rate first preferred shares, Series B of Emera; 

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

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

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

			
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 “Series F First Preferred Shares” means the cumulative redeemable rate reset first preferred
shares, Series F of Emera; 
 “Series G First Preferred Shares” means the cumulative floating rate first preferred shares, Series G of
Emera; 
 “SIA” means the Strategic Investment Agreement dated April 29, 2011 between Emera and APUC; 

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

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

“TECO Energy” means TECO Energy, Inc., an energy-related holding company incorporated under the laws of the State of Florida with regulated
electric and gas utilities in Florida and New Mexico and traded on the New York Stock Exchange under the symbol “TE”. 
 “TECO
Transaction” means the pending acquisition by Emera of TECO Energy; 
 “TSX” means The Toronto Stock Exchange; 

“U.S.” means the United States; 

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

“United States” means the United States of America; 

“USD” means U.S. dollars; 

“USGAAP” means the accounting principles which are recognized as being generally accepted and which are in effect from time to time in the
U.S. as codified by the Financial Accounting Standards Board, or any successor institute; and 
 “West Sunrise Plant” means GBPC’s 52
MW electricity generation plant located on Grand Bahama Island. 
  
  

All amounts are in CAD except where otherwise stated. 

Reference to “including”, “include”, or “includes” means “including (or includes) but is not limited to” and shall not
be construed to limit any general statement preceding it to the specific or similar items or matters immediately following it. 
 The information presented
in this AIF is as of December 31, 2015, unless otherwise specified. 

			
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 CAUTIONARY NOTE REGARDING FORWARD – LOOKING INFORMATION 

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

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

The forward-looking information in this AIF, including the documents incorporated herein by reference, includes statements regarding: Emera’s revenue,
earnings and cash flow; the growth and diversification of Emera’s business and earnings base; future annual earnings growth; expansion of Emera’s business in the U.S. and elsewhere; the completion of announced acquisitions, including the
TECO Transaction; the expected compliance by Emera with the regulation of its operations; the expected timing of regulatory decisions; forecasted capital expenditures; the nature, timing and costs associated with certain capital projects; the
expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; expectations related to annual operating cash flows; the expectation that Emera will continue to have reasonable access to capital in the near to
medium term; expected debt maturities and repayments; expectations about increases in interest expense and/or fees associated with credit facilities; no material adverse credit rating actions being expected in the near term; the number of customers
served in the future; the successful execution of relationships with third-parties, such as agreements relating to the Maritime Link Project, Muskrat Falls and the Assembly of Nova Scotia Mi’Kmaq Chiefs; the impact of currency fluctuations;
expected changes in electricity rates; and the impacts of planned investment by the industry of gas transportation infrastructure within Northeastern United States. 

The forecasts and projections that make up the forward-looking information are based on reasonable assumptions which include: the receipt of applicable
regulatory approvals and requested rate decisions, including with respect to the TECO Transaction; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other
acts of nature or other major events; the continued ability to maintain transmission and distribution systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources;
the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and commodity prices; no significant variability in interest rates; the impact of the TECO Transaction on earnings, assets and Emera’s customer
base; the ability to receive permanent financing with respect to the TECO Transaction; the continued competitiveness of electricity pricing when compared with other alternative sources of energy; the continued availability of commodity supply; the
absence of significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of 

			
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Emera; maintenance of adequate insurance coverage; the ability to obtain and maintain licenses and permits; no material decrease in market energy sales prices; favourable labour relations; and
sufficient human resources to deliver service and execute the capital program. 
 The forward-looking information is subject to risks, uncertainties and
other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations include:
regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; capital market and liquidity risk; the completion of the TECO Transaction, including uncertainty regarding the length of time
required to complete the TECO Transaction; future dividend growth; timing and costs associated with certain capital projects; the expected impacts on Emera of challenges in the global economy; estimated energy consumption rates; maintenance of
adequate insurance coverage; changes in customer energy usage patterns; developments in technology; weather; commodity price risk; construction and development risk; unanticipated maintenance and other expenditures; derivative financial instruments
and hedging availability and inability to complete the Debenture Offering ; failure by Emera to repay the acquisition credit facilities relating to the TECO Transaction; potential unavailability of the acquisition credit facilities relating to the
TECO Transaction; alternate sources of funding that would be used to replace the acquisition credit facilities relating to the TECO Transaction may not be available when needed; impact of acquisition related expenses; interest rate risk; credit
risk; rating agency risk; commercial relationship risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax
legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; market energy sales prices; labour relations; and
availability of labour and management resources.
 For additional information with respect to Emera’s risk factors, reference should be made to the
section of this AIF entitled “Risk Factors”. 
 Readers are cautioned not to place undue reliance on forward-looking information as actual
results could differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this AIF and in the documents incorporated herein by reference
is qualified in its entirety by the above cautionary statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise. 

			
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 INTRODUCTION 

Emera is a geographically diverse energy and services company with approximately $12 billion in assets and 2015 revenues of $2.79 billion. Emera invests in
electricity generation, transmission and distribution, gas transmission and utility services. Emera’s business continues to grow and evolve. Meeting customer demand for cleaner affordable energy remains central to Emera’s strategy. 

Utilities 
 Regulated utilities are the foundation of
Emera’s business, providing the company with strong and consistent earnings. From its beginnings as NS Power Holdings Incorporated in 1998 following the privatization of Nova Scotia Power Corporation in 1992, Emera has grown by investing in its
businesses, and through strategic acquisitions. Emera became an international business with the acquisition of Bangor Hydro in 2001, and expanded its investment in the State of Maine by adding Maine & Maritimes Corporation (MAM) in 2010. In the
Caribbean, Emera has built a business of scale, starting with its investment in St. Lucia’s electric utility (Lucelec) in 2007, and now holding an indirect majority ownership interest in electric utilities in Barbados, Grand Bahama and
Dominica. 
 At the core of Emera’s utilities strategy is identifying opportunities to invest in the transition from higher carbon methods of
electricity generation to lower carbon alternatives. NSPI has invested in wind energy, biomass and hydroelectricity with the result that in 2015, 27% of NSPI’s generation mix was derived from renewable sources, and on track to meet a minimum
40% renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives, with an emphasis on affordability and fuel cost stability for its customers. 

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

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

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

			
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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 5151 Terminal Road, Halifax, Nova Scotia B3J 1A1. 

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

 

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

  

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

	(2)	Jurisdiction of incorporation, continuance or formation. 

	(3)	Emera and ECI are proceeding with a “going private transaction” pursuant to which ECI will amalgamate with Emera (Caribbean) (2016) Inc., a wholly owned
subsidiary of EBH2 under the Companies Act (Barbados), in order for Emera to indirectly acquire all of the common shares of ECI that it does not already own. The amalgamation occurred on February 25, 2016 resulting in 100% ownership of the common
shares of ECI by EBH2. 

 Emera’s other subsidiaries together account for less than 10% of total consolidated operating revenues and less
than 20% of total consolidated assets of Emera for the year ended December 31, 2015. 
 GENERAL DEVELOPMENT OF THE BUSINESS 

EMERA 
 Emera seeks to deliver long-term growth to
investors. Accordingly, annual dividend growth, earnings per common share growth and total shareholder return are the primary measures of performance. Emera is targeting 8% annual dividend growth through 2019. The following table details
Emera’s one, three and five-year performance for these metrics, as well as the S&P/TSX Capped Utilities Index annualized total shareholder return for those periods: 

			
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	 For the
	  	Year ended December 31, 2015	 
	 	  	1 year (%)	 	  	3 year (%)	 	  	5 year (%)	 
	 Dividend per share compound annual growth
rate(1)
	  	 	12.7	  	  	 	6.9	  	  	 	7.4	  
	 Adjusted earnings per share compound annual growth rate(2)
	  	 	1.3	  	  	 	6.9	  	  	 	5.9	  
	 Emera annualized total shareholder return
(2)
	  	 	16.4	  	  	 	12.1	  	  	 	11.1	  
	 S&P/TSX Capped Utilities Index annualized total shareholder return (3)
	  	 	(3.5	) 	  	 	2.3	  	  	 	3.5	  

  

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

	(2) 	The adjusted earnings per share compound annual growth rates do not include TECO Transaction related costs. 

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

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

 Energy markets worldwide, in particular across North America, are
undergoing foundational changes that have created significant investment opportunities for companies with Emera’s experience and capabilities. Key trends contributing to these investment opportunities include: aging infrastructure,
environmental concerns (including demand for new, less carbon-intensive and renewable generation), lower-cost natural gas, growing demand for new electric heating solutions, and the requirement for large-scale transmission projects to deliver new
energy sources to customers. Within this context, Emera is focused on growing shareholder value by identifying reliable and affordable energy solutions, typically involving the replacement of higher-carbon electricity generation with generation from
cleaner sources, and the related transmission and distribution infrastructure to deliver that energy to market. 
 Emera has strong partnerships and
relationships throughout the regions in which it operates and has established a diverse investment and operations profile that links its assets and capabilities in those regions. Core to Emera’s strategy is the ability to leverage these
particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company. 
 Emera’s strategy is based on its
collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across multiple jurisdictions, and its experience dealing with complex projects and investment structures. The Company expects to continue to
make investments in its regulated utilities to benefit customers and focus on providing rate stability to its customers. From time to time, Emera anticipates making acquisitions, both regulated and unregulated, where the business or asset acquired
aligns with Emera’s strategic initiatives and delivers shareholder value. 
 To ensure stability in Adjusted net income and cash flows, Emera employs
operating and governance models that focus on operational excellence, constructive regulatory approaches, proactive stakeholder engagement and a customer focus through service reliability and rate stability.

Emera targets achieving 75 to 85% of its Adjusted net income from rate-regulated subsidiaries, which generally contribute strong, predictable income and cash
flows that fund dividends, reinvestment and which is reflective of the Company’s risk tolerance. Emera has an annual dividend growth target of 8% through 2019. 

In 2015, approximately 65% of Emera’s Adjusted net income was earned by its rate-regulated subsidiaries, which is lower than 2014 (i.e., 67%) and is
lower than its strategic target mentioned above. Specifically, the lower percentage of Adjusted net income from non-rate regulated subsidiaries is a result of a substantial increase in Emera Energy’s earnings primarily due to strong performance
by the New England Gas Generating Facilities, and a strengthening U.S. dollar. It is not the result of a change in Emera’s risk tolerance, nor is it from additional capital allocations to non-regulated businesses. Rather, it is the result
of strong operating and financial performance of existing non-regulated investments 

			
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and businesses. Following the closing of the TECO Transaction, the Company is expected to achieve its Adjusted net income target of 75 to 85%. 

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

For further information related to Emera’s consolidated revenues for the years ended December 31, 2015, December 31, 2014 and December 31, 2013, see the
“Consolidated Financial Highlights”, “Emera Consolidated Statements of Income” and “2015 Consolidated Income Statement and Operating Cash Flow Highlights” sections in the MD&A, which are incorporated herein by
reference. 
 The following discussion summarizes key developments in Emera’s business and operations over the last three completed financial years.

 Pending Acquisition of TECO Energy 
 On September 4,
2015, the Company announced a definitive agreement for Emera to acquire TECO Energy. TECO Energy shareholders will receive $27.55 USD per common share in cash, which represents an aggregate purchase price of approximately $10.4 billion USD and
which includes the assumption of approximately $3.9 billion USD of debt. 
 TECO Energy is an energy-related holding company with regulated electric and gas
utilities in Florida and New Mexico. TECO Energy’s holdings include: Tampa Electric, an integrated regulated electric utility which serves more than 700,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution
utility which serves more than 350,000 customers across Florida; and New Mexico Gas Co., also a regulated gas distribution utility which serves more than 510,000 customers across New Mexico. 

Upon completion of the TECO Transaction, Emera will have over $26 billion of assets and more than 2.4 million electric and gas customers. Emera has fully
committed non-revolving term credit facilities in place from a syndicate of banks in an aggregate amount of $6.5 billion USD (the “Acquisition Credit Facilities”) to ensure the sufficiency of funding to complete the TECO Transaction. The
Acquisition Credit Facilities are comprised of (i) a $4.3 billion USD debt bridge facility, repayable in full on the first anniversary following its advance, and (ii) a $2.2 billion USD equity bridge facility repayable in full on the first
anniversary following its advance. Permanent financing of the TECO Transaction is expected to be obtained before or after closing, from one or more capital market offerings, including debt and preferred equity, as well as from internally generated
sources. A portion of the permanent financing has already been arranged through the sale of $2.185 billion of Debentures. The Acquisition Credit Facilities are available to address any temporary shortfalls while completing the balance of the
permanent financing. 
 Emera is required to effect reductions or make prepayments of the Acquisition Credit Facilities in an amount equal to the net cash
proceeds from any common equity, preferred equity, bond or other debt offerings and any non-ordinary course asset sales by Emera and its subsidiaries, subject to certain prescribed exceptions and certain other prescribed transactions. Net proceeds
from any such offerings, including the net proceeds of the Final Instalment under the Debenture Offering, or from any such non-ordinary course asset sales or transactions, will be applied to permanently reduce the commitments of the lenders under
the Acquisition Credit Facilities or to repay the Acquisition Credit Facilities after they are drawn. On October 16, 2015, Emera permanently reduced the USD bridge facility in the amount of approximately $588.3 million USD with the proceeds of
the first instalment of the Debentures and the proceeds from the Bear Swamp financing. 

			
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 The credit agreements pursuant to which the Acquisition Credit Facilities will be extended (the
“Acquisition Credit Agreements”) will contain certain prepayment options in favour of Emera and certain prepayment obligations upon the occurrence of certain events. In particular, the net proceeds of any equity or debt offering by Emera
and certain of its subsidiaries (other than certain permitted equity or debt offerings subject to certain prescribed exceptions) and of any non-ordinary course asset sales (subject to certain prescribed exceptions) and certain other prescribed
transactions will be required to be used to prepay the Acquisition Credit Facilities and any prepayment under the Acquisition Credit Facilities may not be re-borrowed. The Acquisition Credit Agreements will contain customary representations and
warranties and affirmative and negative covenants of Emera that will closely resemble those in Emera’s existing revolving credit facility (as the same may be amended to reflect the TECO Transaction). 

The cash purchase price of the TECO Transaction and the acquisition related costs will be financed at the closing of the acquisition with one or more of the
following sources: (i) net proceeds of the first instalment and the Final Instalment under the Debenture Offering, (ii) net proceeds of any subsequently completed preferred equity or bond or other debt offerings, (iii) amounts drawn under the
Acquisition Credit Facilities and Emera’s existing revolving credit facility, and (iv) existing cash on hand and other sources available to the Company. Common equity and other available sources are expected to comprise $1.7 billion USD to $2.1
billion USD of the long-term financing for the acquisition, preferred equity offerings are expected to amount to $0.8 billion USD to $1.2 billion USD and bond or other debt offerings are expected to amount to $3.4 billion USD to $3.8 billion USD.

 The closing of the TECO Transaction is expected to occur in mid-2016. It is subject to certain regulatory and government approvals, including
approval by the New Mexico Public Regulation Commission and the satisfaction of closing conditions. Below is a summary of the approvals received to date: 
  

	 	•	 	TECO Energy shareholder approval on December 3, 2015; 

  

	 	•	 	FERC approval on January 21, 2016; and 

  

	 	•	 	Committee on Foreign Investment in the United States approval on March 23, 2016. 

 Additionally, the waiting
period expired on February 8, 2016 under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. 
 On December 14, 2015, the New Mexico
Public Regulation Commission set a hearing to begin on May 23, 2016 for the joint application of the change in control of New Mexico Gas Co. effected by the TECO Transaction. 

Emera expects to incur a number of costs associated with completing the TECO Transaction. The majority of these costs will be non-recurring expenses
resulting from the acquisition, including costs relating to the financing of the acquisition and obtaining regulatory approvals. Additional unanticipated costs may be incurred relating to the TECO Transaction. 

Executive Appointments 
 On January 15, 2016, Greg Blunden
was appointed Chief Financial Officer (“CFO”) of Emera, effective March 1, 2016. Mr. Blunden has held financial leadership roles at Emera, Emera Maine and NSPI. Most recently, Mr. Blunden was Vice President, Corporate Strategy &
Planning. 
 On January 15, 2016, Emera’s current CFO, Scott Balfour, was appointed Chief Operating Officer, Northeast and Caribbean, effective March
1, 2016. Mr. Balfour will provide senior executive leadership for Emera’s existing operations, including NSPI, Emera Energy, Emera Maine, Emera Caribbean, EBPC and Emera Utility Services. 

On January 15, 2016, Wayne O’Connor was appointed Vice President, Corporate Strategy & Planning for Emera, effective March 1, 2016. Mr. O’Connor
will coordinate Emera’s planning and strategy development efforts to grow and expand the Company’s business. Previously, he was Executive Vice-President of Operations at NSPI. 

			
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 On September 22, 2015, Rob Bennett was appointed President and Chief Executive Officer of Emera U.S. Inc., a
wholly owned subsidiary of Emera, to lead the integration of TECO Energy. Previously, Mr. Bennett had been the Chief Operating Officer, Eastern Canada.

On August 31, 2015, Roman Coba was appointed Chief Information Officer of Emera.

Purchase of ECI Outstanding Shares 
 On November 16, 2015,
EBH2 announced its intention to acquire the outstanding common shares of ECI (the “Offer”). Minority ECI shareholders could elect to receive $23.26 ($33.30 BBD) in cash per common share (the “Cash Offer”) or 2.1 Emera DRs
representing common shares of Emera (the “DR Offer”) or a combination of the two offers. Each Emera DR initially represented one quarter of an Emera common share.

As a result of the Offer, EBH2 acquired approximately 2.6 million common shares of ECI. As of Janauary 29, 2016, EBH2 had increased its ownership in ECI
to 95.9% from 80.7%.
 On January 8, 2016, the Emera DRs began trading on the Barbados Stock Exchange. 

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

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

On July 31, 2012, Emera and Nalcor, along with the Provinces of Nova Scotia and Newfoundland and Labrador, executed 13 agreements in respect of the development
and transmission of hydroelectric power from Muskrat Falls on the Churchill River in Labrador to the island of Newfoundland, the Province of Nova Scotia and through to New England. The agreements relate to the development of the Muskrat Falls
Generating Station, the Labrador Transmission Assets, the Labrador-Island Transmission Link Project and the Maritime Link Project. More specifically, these agreements set out the detailed terms pursuant to which: 

 

	 	•	 	Nalcor will construct and own a 824 MW hydro-electric generating facility at Muskrat Falls on the Lower Churchill River in Labrador and the Labrador Transmission Assets; 

 

	 	•	 	Emera will invest in the Labrador-Island Transmission Link Project; and 

  

	 	•	 	Emera will build, finance and operate for 35 years beginning in 2018, the Maritime Link Project, a transmission project linking the island of Newfoundland to Nova Scotia. 

The execution of these agreements was followed, on November 30, 2012, with a finalization of a term sheet detailing the basis upon which the Government of
Canada would provide financial support to the Maritime Link Project by way of a loan guarantee. This loan guarantee (the “Federal Loan Guarantee” or “FLG”) provides, among other things, that the Government of Canada would fulfill
any payment obligations on the guaranteed debt relating to the Maritime Link Project in the event of a default on the guaranteed debt. The FLG enhances the credit rating of the debt financing of the Maritime Link Project to that of the Government of
Canada, thus providing a material reduction to the cost of borrowing for the project. 
 On December 5, 2012, the Newfoundland and Labrador legislature
voted in favour of a bill to approve the Muskrat Falls Generating Station, the Labrador Transmission Assets and the Labrador-Island Transmission Link Project. 

			
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 On December 17, 2012, Emera and Nalcor entered into a sanction agreement enabling both parties to advance
their respective projects. Nalcor officially sanctioned the Muskrat Falls Generating Station and the Labrador-Island Transmission Link Project on December 17, 2012, and at that time revised and finalized its capital cost estimates for the
Muskrat Falls Generating Station, including Labrador Transmission Assets, from $2.9 billion to $3.6 billion and from $2.1 billion to $2.6 billion for the Labrador-Island Transmission Link Project. This set the stage for construction to begin on the
Nalcor projects. On behalf of Emera, ENL’s two subsidiaries, NSP Maritime Link Inc. and ENL Island Link Inc. will respectively carry out the development of the Maritime Link Project and invest in the Labrador-Island Transmission Link Project.

 On January 28, 2013, NSP Maritime Link Inc. filed an application with the UARB seeking approval of the Maritime Link Project. Previously, on May 17,
2012, the Province of Nova Scotia passed the Maritime Link Act in order to enable a project specific review of the Maritime Link Project by the UARB. Pursuant to the Maritime Link Act, the Province of Nova Scotia announced the Maritime Link
Approval Process Regulations on October 2, 2012, setting out the approval process to be followed for the Maritime Link Project. 
 On February 11, 2013, ENL
Island Link Inc. invested $67.7 million in the Labrador-Island Transmission Link Project. 
 On June 21, 2013, NSP Maritime Link Inc. received a release
from the Federal Environmental Assessment process, as well as environmental approval from the Provinces of Newfoundland and Labrador and Nova Scotia for the Maritime Link Project. 

On July 22, 2013, NSP Maritime Link Inc. received the UARB decision on the Maritime Link Project. The UARB approved the Maritime Link Project subject to
certain conditions, including an assurance that additional market-priced energy will be available to Nova Scotians. The UARB approved requested project costs of $1.52 billion and the requested variance amount of $60 million, for total approved
project costs of $1.58 billion plus AFUDC. 
 On October 21, 2013, NSP Maritime Link Inc. filed the Maritime Link Project compliance filing with the
UARB. The compliance filing sought confirmation from the UARB that NSP Maritime Link Inc. has complied with each of the UARB conditions, including the condition relating to the availability of market-priced energy. 

On November 29, 2013, the UARB approved the Maritime Link Project compliance filing and gave its final approval of the Maritime Link Project. Subsequent
to that UARB approval, the Nova Scotia government passed legislative amendments to the Maritime Link Act (Nova Scotia), which clarified certain aspects of the regulatory framework in respect of the Maritime Link Project and provides NSP Maritime
Link Inc. with certain legal rights to facilitate the development and operation of the Maritime Link Project. 
 In early December 2013, Nalcor Energy and
the Government of Newfoundland and Labrador announced the Federal Loan Guarantee associated with the Muskrat Falls Generating Station, the Labrador Transmission Assets and the Labrador-Island Transmission Link Project had been issued, and the
financing for the Muskrat Falls Hydroelectric Project had been completed. 
 On December 13, 2013, NSP Maritime Link Inc. filed its first quarterly
compliance filing with the UARB, which included an updated capital cost estimate for the Maritime Link Project of $1.577 billion. Based upon this cost estimate and the application of the terms of the agreement with Nalcor, whereby NSP Maritime Link
Inc. will pay 20% of the total cost of the Lower Churchill Project Phase I and Maritime Link Project, the amount of this cost estimate that will be NSP Maritime Link Inc.’s responsibility will be $1.5554 billion. The parties have agreed that
Nalcor will be responsible for any difference between the $1.5554 billion and the final actual capital costs of the Maritime Link Project, up to $1.577 billion. Any such adjustment will be payable by Nalcor no later than 30 days after the actual
capital costs of the Maritime 

			
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Link Project are finally determined. Any actual capital costs of the Maritime Link Project in excess of the $1.577 billion shall be dealt with in accordance with the provisions of the Maritime
Link Joint Development Agreement.
 On January 30, 2014, NSP Maritime Link Inc. entered into the first of the Maritime Link Project’s three major
contracts: the supply and installation of the high-voltage direct current submarine cable. In February 2014, construction activities began in both Nova Scotia and Newfoundland and Labrador, with the initiation of rights-of-way clearing activities.

 On March 6, 2014, following satisfaction of the relevant conditions in the FLG term sheet, the Government of Canada issued the Federal Loan Guarantee in
respect of the Maritime Link Project. 
 On April 23, 2014, the MLFT completed its offering of $1.3 billion aggregate principal amount of 3.5% amortizing
bonds due December 1, 2052 at a price of $999.57 per $1,000 principal amount of bonds for aggregate gross proceeds of approximately $1.3 billion. The amortization of the bonds is from December 1, 2020 to December 1, 2052. The bonds are
guaranteed by the Government of Canada under the FLG and have been assigned a rating of “AAA” by S&P and DBRS. The net proceeds are being used to fund construction of the Maritime Link Project. 

Together with certain financing entered into earlier by or on behalf of MLFT and NSP Maritime Link Inc., this bond offering fully satisfied the obligations of
Emera under the Payment Obligation Agreement previously entered into between Emera, NSP Maritime Link Inc. and the Government of Canada. Upon completion of the bond offering, Emera became obligated under the Completion Guarantee previously
granted by Emera in favour of the Government Canada. Under the Completion Guarantee, Emera has guaranteed the performance of the obligations of NSP Maritime Link Inc. to cause the completion of the Maritime Link Project, in the circumstances and
within the timelines provided for in the Completion Guarantee. 
 On June 26, 2014, NSP Maritime Link Inc. entered into the second of the Maritime Link
Project’s three major contracts: the supply and installation of two HVdc converter stations as well as three substations and two transition compounds. 

In Q3 2014, the last of NSP Maritime Link Inc.’s labour agreements was signed. 

On March 12, 2015, NSP Maritime Link Inc. entered into the third of the Maritime Link Project’s three major contracts, with Abengoa S.A., a global
Spanish energy and transmission construction company for the construction of approximately 400 km of transmission lines in the Provinces of Newfoundland and Labrador and Nova Scotia. On November 25, 2015, Abengoa S.A. filed a notice under Spanish
law, which provides for pre-insolvency protection in Spain, giving Abengoa S.A. the opportunity to reach an agreement with creditors to avoid a full insolvency process. ENL has worked closely with Abengoa S.A. and the performance bond sureties to
minimize project impacts. Work on the Maritime Link Project continues. 
 On April 9, 2015, NSP Maritime Link Inc. and the Assembly of Nova Scotia
Mi’kmaq Chiefs signed a Socio-Economic Agreement for the Maritime Link Project. Under the Socio-Economic Agreement, NSP Maritime Link Inc. will support ongoing engagement and commitments made during the environmental assessment process,
including Mi’kmaq participation in environmental monitoring and employment and business opportunities for Mi’kmaq people. 

			
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 Purchase of Natural Gas Generation Facilities in New England 

On November 19, 2013, Emera acquired all of the outstanding equity interests in three combined-cycle gas-fired electricity generating facilities in New England
that make up EE New England Gas Generation: Bridgeport Energy (520 MW, since upgraded to 560 MW) in Bridgeport, Connecticut; Tiverton Power (265 MW) in Tiverton, Rhode Island; and Rumford Power (265 MW) in Rumford, Maine, for total cash
consideration of $573.9 million CAD ($548.4 million USD). This addition of gas generation in the Northeastern United States has been a strategic objective of Emera and is a complement to its hydro investment in the region. 

To finance the transaction, Emera utilized $150 million USD received on repayment of a loan to NWP, which was facilitated by the refinancing of that
entity’s indebtedness; a one-year $350 million USD non-revolving credit facility established by an indirect wholly owned subsidiary of Emera; and other cash resources on hand. 

First Wind 
 On June 15, 2012, Emera and First Wind closed
their transaction to jointly own and operate a 419 MW portfolio of wind energy projects in the Northeastern United States through a new company, NWP, owned 51% by First Wind and 49% by Emera. Emera invested $215 million USD, including
transaction costs, and loaned $150 million USD to NWP, to be repaid within five years. On November 14, 2013, Emera received repayment of the $150 million USD loan to NWP in full. First Wind managed and operated the wind energy projects,
and Emera Energy Services provided energy management services. 
 Emera and First Wind also had an agreement relating to additional wind energy projects
developed or acquired by First Wind. Under this agreement, on February 11, 2013, Emera, through its interest in NWP, acquired a 49% interest in 34 MW Bull Hill project for $14.4 million USD.

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

Strategic Partnership with Algonquin Power & Utilities Corp. 

APUC is a diversified generation, transmission and distribution utility traded on the TSX under the symbol “AQN”. The distribution group operates in
the United States and provides rate regulated water, electricity and natural gas utility services. The non-regulated generation group owns or has interests in a portfolio of North American-based contracted wind, solar, hydroelectric and natural gas
powered generating facilities. The transmission group invests in rate-regulated electric transmission and natural gas pipeline systems in the United States and Canada. 

Emera’s SIA with APUC establishes how Emera and APUC will work together to pursue specific strategic investments of mutual benefit. The SIA outlines
“areas of pursuit” for both Emera and APUC. For Emera, these include investment opportunities related to regulated renewable generation and transmission projects within its service territories, and large electric utilities. For APUC, these
include investment opportunities relating to unregulated renewable generation, small electric utilities and gas distribution utilities. Emera is committed to working with APUC on opportunities that fit within APUC’s “areas of
pursuit”. 
 The SIA also provides for Emera to acquire up to 25% of APUC through the purchase of common shares issued by APUC to fund certain
investment opportunities under the SIA. The acquisition of APUC shares is subject to regulatory approval. On June 25, 2012, Emera requested FERC and MPUC approval to increase its ownership in APUC to 25%; these approvals have now been received. The
MPUC order, received on January 28, 2013, gave approval of Emera’s 25% ownership interest in APUC and stipulated that Emera’s dollar investment in APUC cannot exceed 5% of Emera’s total assets. 

			
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 On October 28, 2014, the approval order was appealed by Houlton Water Company and the Industrial Energy
Consumer Group. Emera will continue to participate in the court appeal process to support the MPUC’s decision. 
 APUC share purchases by Emera have
generally been made through the acquisition of subscription receipts in exchange for promissory notes at an agreed upon price, which are then exchangeable into common shares upon meeting certain transaction specific conditions, or at a later date at
Emera’s option, as applicable. The acquisition and conversion of subscription receipts is subject to approvals required under applicable laws, including the rules of the TSX. 

As at December 31, 2015, Emera owned 50.1 million common shares of APUC and had 12.6 million outstanding subscription receipts and dividend equivalents, at an
average conversion price of $9.20 and an average book value of $8.03 per share. APUC’s market price per common share was $10.91 as at December 31, 2015 (2014 - $9.64). The outstanding subscription receipts became eligible for conversion into
APUC common shares at Emera’s election in Q4 2015 and will automatically convert to common shares in Q4 2016 if an election is not made. 
 As at
December 31, 2015, the carrying value of Emera’s investment in APUC was $503.7 million (2014 - $336.4 million). 
 Gains on Dilution of APUC Equity
Investment 
 In December 2015, APUC closed a 14.355 million common share offering. As a result, Emera recorded a dilution gain of $11.1 million
(after-tax earnings of $9.4 million or $0.06 per common share) in “Income from Equity Investments”, as described in the MD&A. 
 In Q3 2014
and Q4 2014 respectively, APUC closed 16.86 million and 10.05 million common share offerings. In addition, in Q3 2014, an over-allotment option of 2.52 million common shares was exercised. As a result of these two transactions, in Q3 2014, Emera
recorded a gain of $10.8 million (after-tax earnings of $9.1 million or $0.06 per common share) and in Q4 2014, a gain of $7.5 million (after-tax earnings of $6.4 million or $0.04 per common share) in “Income from Equity Investments”, as
described in the MD&A. 
 Empire District Electric Company Transaction 

On February 9, 2016, APUC announced its intention to acquire The Empire District Electric Company in a $3.4 billion transaction, which is expected to close in
Q1 2017. The closing of this transaction and its related financing is expected to reduce Emera’s ownership interest. 
 Nova Scotia Power 

Electricity Plan and Rate Stability 
 On November 9, 2015,
the Province of Nova Scotia released its electricity plan to support stable and predictable energy rates until 2019. The electricity plan also provides for the development of performance standards through a 2016 UARB regulatory process. On
December 18, 2015, the Province of Nova Scotia enacted the Electricity Plan Act, which requires NSPI to file a three-year rate plan for Fuel Costs in Q1 2016 and to file a three-year GRA to change non-fuel rates by April 30, 2016. NSPI filed
its three year rate plan for Fuel costs on March 7, 2016, indicating an average annual increase of 1.3 per cent per year from 2017 to 2019. NSPI has also confirmed that no GRA for non-fuel cost will be filed for the 2017 to 2019 period. 

The Electricity Plan Act directs NSPI to apply non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be
reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of certain tax benefits for the South Canoe Wind Project and the Sable Wind Project is to be reserved to be applied to
the FAM in the 2017 to 2019 period. The exception to this direction is to apply 

			
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a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would have been otherwise required. For more information, see
the “Regulated Fuel Adjustment Mechanism and FAM Regulatory Deferral” section of the MD&A, which is incorporated herein by reference. 

Emera Maine 
 FERC Audit 

In November 2014, the FERC commenced an audit covering the 2013 and 2014 period of Bangor Hydro’s compliance with conditions established in FERC’s
orders authorizing its acquisition of MPS, which occurred on January 1, 2014. These two predecessor companies formed Emera Maine. The final audit report was released in early January 2016. The findings in the audit report conclude that Emera Maine
did not follow the prescribed methodology for the calculation of AFUDC during the audit period and Emera Maine had included, in rates, costs of the Bangor Hydro and MPS merger prior to making the required filings. Emera Maine will fully comply with
the recommendations in the audit report, including making the required filings for the merger costs and re-calculating AFUDC for 2013 and 2014, as ordered, which resulted in an immaterial impact on the Company’s consolidated statements of
income. 
 Emera Maine ROE Proceedings 
 On September
30, 2011, a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users filed a complaint with the FERC alleging that the 11.14 % base ROE under the ISO-NE OATT was unjust and
unreasonable. On June 19, 2014, the FERC issued an order in connection with this complaint, changing the methodology used to set the ROE for transmission assets.

This change would lower the base transmission ROE to 10.57% for the period of October 1, 2011 to December 31, 2012, subject to a further proceeding to
finalize the determination of appropriate rates to be used in such calculation. The FERC decision would also lower the cap on the total ROE (inclusive of incentive adders) for transmission assets to 11.74%. In an order issued on October 16,
2014, the FERC confirmed that the ROE set in its earlier order was appropriate. 
 On March 3, 2015, in response to requests for rehearing from several
parties, FERC affirmed its initial Order, setting of the base ROE of 10.57% and capping the total ROE, including the effect of incentive adders, at 11.74%. Notices of Appeal to the U.S. Court of Appeals for the DC Circuit were filed by New England
Transmission Operators and the complainants in the case on April 30, 2015. In Q2 2015, Emera Maine began processing the refunds to customers, based on a 10.57% ROE. By court order dated August 20, 2015, the DC Court of Appeals decided to hold the
appeal of this case in abeyance pending the outcome of the consolidated cases (“ENE Case” and “MA AG II Case”) discussed below. 
 On
December 27, 2012, a second group of consumer advocates, including Environment Northeast filed a complaint with the FERC on similar grounds, arguing that the 11.14% base ROE under the OATT was unjust and unreasonable (the ENE Case). On June 19,
2014, the FERC issued an order in this second ROE case, finding in favour of the complainants and allowing the complaint to proceed. As a result, a new ROE will be calculated and set by the FERC. This complaint created a new 15-month refund
period beginning January 1, 2013 through March 31, 2014. 
 On July 31, 2014, a group of state commissions, state public advocates and end users filed
a third complaint with the FERC alleging the ROE earned on transmission investments is unjust and unreasonable and does not reflect current economic conditions (the MA AG II Case). Any potential refund arising from this third complaint will
relate to the period from July 31, 2014 to September 30, 2015, and the outcome will set the ROE going forward from the date of decision. 
 On November 24,
2014, FERC consolidated the ENE Case and MA AG II Case. A subsequent order by the FERC established a schedule for various procedural matters that turned the case over to an Administrative Law Judge in

			
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September 2015. Once that judge’s recommended decision is rendered, parties may file exceptions, and then the case is set for decision by FERC. 

Emera Maine has recorded net reserves of $6.9 million pre-tax ($5.0 million USD) (2014 - $8.5 million) for these refund complaints as at December 31, 2015,
based on a 10.57% ROE. 
 On March 22, 2016, the Administrative Law Judge issued a recommendation to the FERC with respect to the two outstanding ROE
complaints (ENE Case and MA AG II Case). Each complaint was for a 15-month period with the recommendation for the ENE Case being 9.59% ROE, with a 10.42% maximum ROE, and the recommendation for MA AG II Case being 10.90% ROE, with a 12.19%
maximum ROE. 
 USGAAP – Exemptive Relief and Companies Act Relief 

On April 28, 2014, Emera was granted exemptive relief by Canadian securities regulators allowing it to continue to report its financial results in accordance
with USGAAP (the “Exemptive Relief”). On July 9, 2014, Emera was granted an order pursuant to the Companies Act (Nova Scotia) exempting it from the Companies Act requirement to prepare its annual financial statements in accordance with
IFRS (the “Companies Act Relief”). Both the Exemptive Relief and the Companies Act Relief will remain in effect for Emera until the earlier of: (i) January 1, 2019; (ii) the first day of the Company’s financial year commencing after
the Company ceases to have activities subject to rate regulation; and (iii) the effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within IFRS specific to entities with
rate-regulated activities. The Exemptive Relief and the Companies Act Relief each replace previous similar exemptive relief that had been granted to Emera in 2012 and 2011 respectively, which would have expired by January 1, 2015. 

Financing Activity 
 Emera 

Debentures Represented by Instalment Receipts 
 To
finance a portion of the TECO Transaction, on September 28, 2015, Emera, through the Selling Debentureholder, completed the sale of $1.9 billion aggregate principal amount of Debentures, represented by instalment receipts. On October 2, 2015, in
connection with the Debenture Offering, the underwriters fully exercised an overallotment option and purchased an additional $285 million aggregate principal amount of Debentures at the Debenture Offering price. 

The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which $333 was paid on closing of the Debenture Offering or exercise of
over-allotment option, as applicable, with the Final Instalment being payable on the Final Instalment Date. 
 Prior to the Final Instalment Date, the
Debentures are represented by instalment receipts. The instalment receipts began trading on the TSX on September 28, 2015 under the symbol “EMA.IR”. The Debentures will not be listed. The Debentures will mature on September 29, 2025 and
bear interest at an annual rate of 4.00% per $1,000 principal amount of Debentures until and including the Final Instalment Date, after which the interest rate will be 0.00%. Based on the first instalment of $333 per $1,000 principal amount of
Debentures, the effective annual yield to and including the Final Instalment Date is 12%, and the effective annual yield thereafter is 0.00%. 
 If the
Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Debenture Offering, holders of Debentures who have paid the Final Instalment on or before the Final Instalment Date will be entitled to receive, on
the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, the Make-Whole Payment. 

			
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 No Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary
of the closing of the Debenture Offering. Under the terms of the instalment receipt agreement, Emera agreed that until such time as the Debentures have been redeemed in accordance with the foregoing or the Final Instalment Date has occurred, the
Company will at all times hold (on a consolidated basis) short-term USD investment grade securities or have cash on hand of not less than the aggregate amount of the first instalment paid on the closing of the Debenture Offering and the exercise of
the over-allotment option, in the event of a mandatory redemption. 
 At the option of the holders and provided that payment of the Final Instalment has
been made, each Debenture will be convertible into common shares of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $41.85 per common share. This is a
conversion rate of 23.8949 common shares per $1,000 principal amount of Debentures, subject to adjustment in certain events. 
 Prior to the Final
Instalment Date, the Debentures may not be redeemed by the Company, except that Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to
holders that the conditions precedent to the closing of the TECO Transaction will not be satisfied; (ii) termination of the TECO Transaction agreement; and (iii) April 24, 2017, if notice of the Final Instalment Date has not been given to holders on
or before April 21, 2017. Upon any such redemption, the Company will pay for each Debenture: (i) $333 plus accrued and unpaid interest to the holder of the instalment receipt; and (ii) $667 to the Selling Debentureholder on behalf of the holder
of the instalment receipt in satisfaction of the Final Instalment. In addition, after the Final Instalment Date, any Debentures not converted may be redeemed by Emera at a price equal to their principal amount plus any unpaid interest which accrued
prior to and including the Final Instalment Date. These costs will include a non-cash accounting charge for the difference between Emera’s closing share price on the issuance date of the convertible debentures and their exercise price. This
will be recognized once the contingencies surrounding regulatory and other approvals are resolved. 
 At maturity, Emera will repay the principal amount of
any Debentures not converted and remaining outstanding in cash. Emera has the right to satisfy the obligation to repay the principal amount due in common shares, which will be valued at 95% of the weighted-average trading price on the Toronto
Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date. 
 The proceeds of the first instalment of the
Debenture Offering are held and invested in short-term USD investment grade securities. The net proceeds of the Final Instalment will be used, together with the net proceeds of the first instalment, to finance, directly or indirectly, the TECO
Transaction and other acquisition related costs. To mitigate the foreign currency translation risk associated with the Final Instalment, Emera entered into USD denominated forward contracts, which are recorded on the consolidated balance
sheets. The mark-to-market effect on these hedges is reported in the income statement and affects income, but is not reflected in Adjusted net income. 

TECO Transaction Bridge Facility 
 Emera has fully
committed, non-revolving term credit facilities in place from a syndicate amount of $6.5 billion USD, which are referred to herein as the Acquisition Credit Facilities. On October 16, 2015, Emera permanently reduced the Acquisition Credit
Facilities in the amount of approximately $588.3 million USD with the proceeds of the first instalment of the Debentures and the proceeds from the Bear Swamp financing. 

Revolving Bank Line of Credit 
 On August 21, 2015,
Emera extended the maturity of its $700 million committed syndicated revolving bank line of credit from June 2019 to June 2020, with no change in commercial terms from the prior agreement. 

			
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 On November 18, 2014, Emera extended the maturity of its $700 million committed syndicated revolving bank
line of credit from June 2018 to June 2019, with no change in commercial terms from the prior agreement. 
 On November 19, 2013, Emera extended the
maturity of its $700 million committed syndicated revolving bank line of credit from June 2017 to June 2018, with no change in commercial terms from the prior agreement.

Non-Revolving Credit Facility 
 On November 19,
2013, an indirect wholly owned subsidiary of Emera entered in to a $350 million USD non-revolving credit facility. The credit facility was used to partially finance the acquisition of EE New England Gas Generation. During 2014, a portion of this
credit facility was repaid using funds from operations and Emera’s existing revolving bank line of credit. The remaining balance of $220 million USD of this non-revolving credit facility was repaid on February 5, 2015 using the proceeds from
the sale of NWP. 
 Medium Term Notes 
 On
October 20, 2014, Emera repaid the Series F $250 million 4.10% five-year medium term notes using its existing revolving bank line of credit. As noted below, the net proceeds of EBPC’s February 19, 2015 senior secured financing were used to
repay an intercompany loan with Emera for the construction of the Brunswick Pipeline. The funds from this intercompany loan repayment were used to reduce indebtedness outstanding under Emera’s existing revolving bank line of credit. 

Common Share Offering 
 On January 7, 2014, Emera
completed an offering of 8,665,000 common shares, including the exercise of the over-allotment option of 865,000 common shares, at $28.85 per common share, for gross proceeds of $250.0 million and net proceeds of approximately $240.0 million. The
net proceeds of the offering were used for general corporate purposes to support the Company’s recently announced growth initiatives and to reduce indebtedness outstanding under Emera’s credit facility. 

Preferred Share Offerings 
 On August 17, 2015,
2,135,364 of Emera’s 6,000,000 issued and outstanding Series A First Preferred Shares were tendered for conversion, on a one-for-one basis, into Series B First Preferred Shares. 

On June 9, 2014, Emera issued 8,000,000 Series F First Preferred Shares at $25.00 per share for gross proceeds of $200.0 million and net proceeds of
approximately $194.5 million. The net proceeds of this offering were used for general corporate purposes. 
 On June 10, 2013, Emera issued 5,000,000
Series E First Preferred Shares, including the exercise of the over-allotment option of 1,000,000 Series E Preferred Shares, at $25.00 per share for gross proceeds of $125.0 million and net proceeds of approximately $121.6 million. The net proceeds
of this offering were used for general corporate purposes, including the repayment of indebtedness under the Company’s credit facility. 
 NSPI

 On April 30, 2015, NSPI completed the issuance of $175 million Series AA Medium-Term Notes. The Series AA notes bear interest at a rate of 3.612% per
annum until May 1, 2045. The proceeds of the note offering were used for general corporate purposes, including the repayment of maturing corporate term debt. 

			
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 NSPI’s Series I $70 million 8.40% Medium-Term Notes matured and were repaid on October 23, 2015. 

On October 15, 2015, NSPI redeemed all of its issued and outstanding Series D Preferred Shares for an aggregate purchase price of $135 million. 

On January 10, 2014, November 18, 2014 and November 16, 2015, NSPI extended the maturity of its $500 million committed syndicated revolving bank line of
credit from June 2017 to June 2018, October 2019 and October 2020, respectively, with no change in commercial terms from the prior agreement. 
 Emera
Maine 
 On September 25, 2014, Emera Maine completed a securities issuance for $110 million USD senior unsecured notes. The 30-year notes bear
interest at a rate of 4.34% and will mature on September 25, 2044. Proceeds from the sale of the notes were used to repay existing indebtedness and for other general corporate purposes. 

On September 25, 2014, Emera Maine extended the maturity of its $80 million USD revolving senior credit facility from September 2014 to September 2019, with
no material change in commercial terms from the prior agreement. 
 On September 30, 2013, MPS renewed its existing $10 million USD revolving credit
facility, with a new expiration date of the earlier of September 30, 2014, or the effective date of the merger between MPS and Bangor Hydro, with no change in terms from the prior agreement, with an expiration date of September 30, 2014. This
agreement expired upon the merger of MPS and Emera Maine. 
 On September 30, 2013, MPS repaid its Maine Public Utility Financing Bank Bonds and associated
interest rate hedges with the proceeds from a $25.6 million USD non-revolving credit facility. 
 ENL 

On April 23, 2014, the MLFT completed its offering of $1.3 billion aggregate principal amount of 3.5% amortizing bonds. Further information on this is
provided in the General Development of the Business, Development of the Maritime Link Project and Strategic Partnership with Nalcor Energy on Muskrat Falls Projects. 

GBPC 
 On December 15, 2014, GBPC renewed its $20.2
million USD loan agreement to 2021 at a floating rate of LIBOR plus 1.75%. This loan is repayable in 28 equal quarterly installments. All other terms and conditions of the loan agreement remain unchanged. 

On January 16, 2013, GBPC issued 32,000 non-voting cumulative redeemable perpetual variable preferred shares at $1,000 Bahamian per share for gross proceeds
of $32.0 million Bahamian and net proceeds of $30.9 million Bahamian. The net proceeds of the share offering were used to repay intercompany loans with Emera for the construction of the West Sunrise Plant. 

On July 17, 2013, GBPC issued an additional 3,000 non-voting cumulative redeemable perpetual variable preferred shares at $1,000 Bahamian per share for gross
proceeds of $3.0 million Bahamian and net proceeds of $2.9 million Bahamian. 
 EBPC 

On February 19, 2015, EBPC completed a senior secured financing consisting of a non-revolving term credit facility for $250 million for a four-year term. The
credit facility bears interest at bankers’ acceptances rates plus 1.75% and expires on February 19, 2019. As noted above, the net proceeds of the financing were used to repay a $250 million intercompany loan with Emera for the construction of
the Brunswick Pipeline. 

			
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 Emera Energy Services 

On October 8, 2015, Bear Swamp refinanced its $125 million USD bank debt that was due to mature in 2017 and issued $400 million USD in senior secured 10-year
bonds, with $375 million USD at a fixed rate of 4.89%, and $25 million USD at a floating rate of LIBOR plus 2.70%. The proceeds of this financing were used to repay existing debt and provide working capital to the joint venture, with the
remainder shared equally between Emera and its joint venture partner. After fees and expenses, Emera received a $178.7 million ($137.3 million USD) non-taxable distribution in Q4 2015. 

Changes in Business Expected During 2016 
 Emera

 The TECO Transaction is expected to be accretive to earnings per share by approximately 5% in the first full calendar year following its closing,
growing to more than 10% by the third full year assuming a USD/CAD exchange rate consistent with that at the time of announcement of the transaction. As well, approximately 95% of the expected foreign exchange exposure to close the TECO Transaction
has been actually or effectively hedged. The TECO Transaction will result in further acquisition costs in 2016. 
 Emera’s operations are affected
by the U.S. dollar relative to the Canadian dollar. Approximately 50% of Emera’s Adjusted net income was derived from subsidiaries with a U.S. functional currency in 2015. TECO Energy’s operations are conducted in U.S. dollars and
following the TECO Transaction, Emera’s consolidated net income and cash flows will be affected to a greater extent by movements in the U.S. dollar relative to the Canadian dollar. 

NSPI 
 NSPI’s earnings are most directly affected by
the range of rate of return on equity and capital structure approved by the UARB; the prudent management and approved recovery of operating costs, load, and regulatory deferrals and the timing and amount of capital expenditures. NSPI anticipates
earning within its allowed ROE range in 2016 and expects its rate base to remain stable. Over the past several years, the requirement to reduce the Province of Nova Scotia’s reliance upon high carbon and greenhouse gas emitting sources of
energy has resulted in NSPI making significant investments in renewable energy sources and purchasing third party renewable energy. On November 10, 2015, NSPI announced it does not plan to file a GRA related to electricity rates for 2016. 

In December 2015, the Electricity Plan Act was enacted by the Province of Nova Scotia with a goal of providing rate stability and predictability for customers
for the 2017 through 2019 period. The Electricity Plan Act requires NSPI to file a three-year rate plan for fuel costs in Q1 2016 and to file a three-year application to change non-fuel rates by April 30, 2016. NSPI filed its three year
rate plan for Fuel costs on March 7, 2016, indicating an average annual increase of 1.3 per cent per year from 2017 to 2019. NSPI has also confirmed that no GRA for non-fuel cost will be filed for the 2017 to 2019 period.

NSPI expects to finance its capital expenditures with funds from operations and its credit facilities, as well as continued access to debt capital markets for
long-term financing.
 Overall, NSPI’s 2016 earnings are expected to be consistent with prior years. 

Emera Maine 
 Emera Maine’s earnings are most
directly affected by the combined impacts of the range of rates of return on equity and rate base approved by its regulators, the prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures.

 Emera Maine’s 2016 ROE is expected to be consistent with prior years. Its ongoing investment in transmission and distribution infrastructure is
expected to result in modest growth in rate base. 

			
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 Emera Maine has an agreement with Central Maine Power Company to pursue specific transmission opportunities
in Northern Maine that would relieve transmission congestion and more efficiently collect and deliver wind generation to New England markets. As part of this agreement, Emera Maine and Central Maine Power Company jointly responded to a request
for proposals for clean energy from Massachusetts, Connecticut and Rhode Island, through an existing jointly owned transmission company, Maine Electric Power Company Inc. (MEPCO). The demand for this renewable energy is growing as a result of
increasing renewable portfolio requirements of the southern New England states. 
 Future earnings will generally reflect the impact of transmission rate
decisions by the FERC. Emera Maine has fully reserved for the refunds required as a result of a FERC decision on the allowed ROE set at 10.57%. 
 Overall,
Emera Maine’s 2016 USD earnings are expected to be consistent with prior years. 
 Emera Caribbean 

Earnings from Emera Caribbean are most directly affected by the combined impacts of the range of rates of return on equity and rate base approved by their
regulators, capital structure, the prudent management and approved recovery of operating costs, load, and the timing and amount of capital expenditures. Earnings are also affected by the investment returns of Emera’s interest in BLPC’s
self-insurance fund. 
 The Barbados economy expects growth of approximately 1.8% in 2016. With oil being the predominant fuel source for generation of
electricity in the Caribbean, reduced oil prices may result in an economic benefit on the island in decreased cost of electricity to ratepayers. During 2015, BLPC recognized the need to reduce costs in the business to stabilize future rates to
customers. BLPC forecasts that it expects to maintain the 2015 cost savings into the future. 
 The economy of Grand Bahama Island is highly correlated to
the United States economy and has exhibited signs of improving economic growth and a corresponding growth in load in the industrial sector and weather related growth in the residential sector.

Effective February 1, 2016, the GBPA approved GBPC’s GRA applicable for the 2016 through 2018 period. Residential customers will see decreases of up to
4.5%, while commercial customers will see an increase of 1.5%. Commercial customers consume approximately 70% of GBPC’s production. Rates were approved based upon an 8.8% return on rate base, reduced from the previous level of
10%. This rate decision also allows for customers to install renewable energy systems and sell their excess energy to GBPC. This is based on a tariff rider scheduled to be in place by Q3 2016. 

There are growth opportunities for Emera in the Caribbean market centered on creating and capturing opportunities for cleaner fuels and renewable energy
generation. As part of this initiative, construction of a 10 MW solar facility began in Barbados in Q4 2015 and is scheduled for completion in the first half of 2016. In addition, an application to export natural gas to countries with no
free trade agreement with the United States, specifically The Bahamas, was filed with the US Department of Energy and approval was received on October 20, 2015, granting long-term multi contract authorization for Emera to export natural gas, by
vessel, in the amount of 8 MMSCFD. This complements the authorization received in April 2015 to export up to 25 MMSCFD to countries which have a free trade agreement with the United States. 

Overall, Emera Caribbean 2016 USD earnings are expected to be consistent with prior years. 

Pipelines 
 The timing of the income from Pipelines is
predominately a result of capital lease accounting treatment which yields declining earnings over the life of the asset. 
 Pipelines 2016 earnings are
expected to be consistent with prior years. 

			
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 Emera Energy 

Emera Energy Services 
 Emera Energy Services, Emera
Energy’s marketing and trading business, is generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply/demand
factors, can provide higher levels of margin opportunity. The past three years have seen favourable market conditions in this regard within Emera Energy’s key markets, with Q1 2014, in particular, experiencing unprecedented market volatility.
This was a result of the combined impacts of cold weather, constraints in the supply or transportation of natural gas, and other market factors, and contributed to very strong adjusted earnings1
from marketing and trading, particularly in 2014. 2015 has seen lower market volatility and pricing, and a resulting decrease in marketing and trading adjusted earnings compared to 2014. 

In addition to capitalizing on volatility-driven market opportunities, Emera Energy Services expects to continue to grow organically building market share
through superior customer service and expanding its geographic reach to adjacent markets, including the Marcellus Shale region. 
 Planned investment by the
industry in gas transportation infrastructure within the Northeastern United States over the next few years could reduce the degree of volatility recently experienced in the market, all other things being equal. This could negatively affect
profitability during certain periods. 
 Emera Energy Generation 

Earnings from Emera Energy Generation’s assets are largely dependent on market conditions, in particular, the relative pricing of electricity and natural
gas and capacity pricing for the New England Gas Generation Facilities. Efficient operations of the fleet to ensure unit availability, cost management and effective commercial performance are key success factors. 

2016 adjusted earnings from Emera Energy generating assets are expected to be lower than 2015, reflecting lower hedged and expected margins as compared to
2015. 
 In addition to energy margins and ancillary revenue, the EE New England Gas Generation and Bear Swamp earn revenue from capacity payments through
the forward capacity market (FCM), the annual reconfiguration capacity market and the monthly reconfiguration capacity market. Prices for the FCM, the largest of the three components, are determined through an auction process held annually, three
years in advance, providing revenue visibility to 2019, presuming the facilities continue to be available to support their capacity obligations. Details of pricing and estimated revenues are outlined in the table below for EE New England Gas
Generation, and Emera Energy’s 50% interest in Bear Swamp. 
  

							
	 Forward Capacity Auction (“FCA”) Year
	  	Clearing Price in $/kW-month
(in USD)	 	Approximate Estimated Annual Capacity
Revenue (in USD) (1)	 
	 FCA6 (June 2015 to May 2016)
	  	$3.43	 	$	40 million	  
	 FCA7 (June 2016 to May 2017)
	  	$3.15	 	$	40 million	  
	 FCA8 (June 2017 to May 2018)
	  	$7.025	 	$	100 million	  
	 FCA9 (June 2018 to May 2019)
	  	$9.55 and $11.08 (2)	 	$	145 million	  
	 FCA 10 (June 2019 to May 2020)
	  	$7.03	 	$	106 million	  

  

	(1)	Includes Emera’s 50% share of Bear Swamp’s capacity revenue 

	(2)	$11.08 was awarded for the Southeast Massachusetts/Rhode Island zone only and, as such, applies only to Tiverton 

 

	1 	Emera uses financial measures, such as “adjusted earnings”, that do not have standardized meaning under USGAAP and may not be comparable to similar measures presented by other entities. Emera calculates the
non-GAAP measures by adjusting certain GAAP and non-GAAP measures for specific items it believes are significant, but not reflective of underlying operations in the period. Refer to the Non-GAAP Financial Measures section of Emera’s MD&A
for further discussion of these items. 

			
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 Bear Swamp’s adjusted earnings will be lower in 2016 and the first half of 2017 primarily due to higher
interest costs as a result of its Q4 2015 refinancing. Beginning Q3 2017, these interest costs will be offset by higher capacity revenues. 
 Corporate
and Other 
 Corporate and Other is dependent, in part, on business development and acquisition related initiatives, which in 2016 will include further
acquisition costs related to the TECO Transaction, equity investments in the Maritime Link Project and the Labrador-Island Transmission Link Project, project based construction services activity by Emera Utility Services, growth or fluctuations in
APUC earnings (which Emera accounts one quarter after APUC reports such earnings), corporate financing and other corporate activities. 
 Corporate’s
contribution to consolidated net income in 2016 is expected to be lower than 2015 primarily due to further acquisition costs and associated financing initiatives related to the TECO Transaction. These costs will include a non-cash accounting charge
for the difference between Emera’s closing share price on the issuance date of the Debentures and their exercise price. This will be recognized upon the closing of the TECO Transaction once the contingencies surrounding regulatory and other
approvals are resolved. 
 On February 9, 2016, APUC announced its intention to acquire The Empire District Electric Company in a $3.4 billion transaction,
which is expected to close in Q1 2017. The closing of this transaction and its related financing are expected to reduce Emera’s ownership interest, as Emera did not take part in the equity issuance. Emera is expected to record a
non-cash dilution gain on its then interest in APUC at the time of APUC’s closing of this transaction. 
 ENL 

NSPML 
 As of December 31, 2015 and through its
subsidiary, NSP Maritime Link Inc., ENL has incurred total costs of approximately $693.9 million, including $78.1 million of AFUDC, in the development of the Maritime Link Project. As of December 31, 2015, ENL has invested a total of $154.9
million in equity, with remaining costs being funded with working capital and debt, which has been guaranteed by the Government of Canada. AFUDC on invested equity is being capitalized at an annual rate of 9.0%. 

ENL’s future earnings contribution from the Maritime Link Project will be affected by the timing of capital expenditures, which will determine the
component of costs to be funded by equity. Funds from the federally guaranteed debt financing completed in April 2014 were used to fund project costs until the project’s debt to equity ratio reached 70% to 30% respectively, which occurred in Q4
2015. From this point forward, project costs are funded with debt and equity at a 70% to 30% ratio, with equity contributions of $13.4 million in Q4 2015. 

Maritime Link Project currently forecasted equity contributions for 2016 and 2017 are $157 million and $159 million respectively, with total equity for the
project estimated to be $470.9 million. 
 LIL 

ENL is a partner with Nalcor Energy in LIL, which is currently estimated at approximately $3.1 billion. As at December 31, 2015, ENL has invested $207.3
million of equity, including $21.2 million of capitalized equity earnings in LIL. Equity earnings are recorded based on an annual rate of 8.8% of the equity invested. The return on ROE is approved by the NLPUB. There is currently an
application being heard by the NLPUB which includes a review of ROE. The NLPUB’s decision on ROE, will be applicable for all regulated electrical utilities in Newfoundland and Labrador and become the ROE applicable to ENL’s investment
in LIL.

			
	2015 Annual Information Form	  	
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 ENL has an ongoing equity investment opportunity in LIL. Future earnings are dependent on the timing of
additional equity investments and the approved ROE. Total equity contributions for 2015 for LIL are $118.4 million. 
 LIL currently forecasted equity
contributions for 2016 are $223 million, with total equity investment, by Emera, in the project estimated to be $409.1 million. 
 DESCRIPTION OF THE
BUSINESS 
 General 
 Emera Incorporated is an energy
and services company with approximately $12 billion in assets. Emera currently provides regional energy solutions by connecting its assets, markets and partners in Canada, the United States, and the Caribbean.

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

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

Emera’s strategy is based on its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and across
multiple jurisdictions, and its experience dealing with complex projects and investment structures. Emera and its subsidiaries had approximately 3,500 employees at December 31, 2015, approximately 49% of whom are unionized. 

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

	 	•	 	NSPI (see “NSPI” section below); 

  

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

  

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

  

	 	•	 	EBPC (see “Pipelines” section below). 

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

 

	 	•	 	Emera’s 100% investment in NSPML, a $1.5554 billion transmission project, including two 170-kilometre subsea cables, between the island of Newfoundland and Nova Scotia. The investment in NSPML is accounted for on
the equity basis with equity earnings equal to the ROE component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017; 

 

	 	•	 	 Emera’s 55.1% investment in the partnership capital of LIL, a $3.1 billion electricity transmission project
in Newfoundland and Labrador to enable the transmission of Muskrat Falls energy between Labrador and the island of Newfoundland. Emera’s percentage ownership in LIL is subject to change based on the balance of capital investments required from
Emera and Nalcor to complete construction of the LIL. Emera’s ultimate 

			
	2015 Annual Information Form	  	
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percentage investment in LIL will be determined on completion of the LIL and final costing of all transmission projects related to the Muskrat Falls development, including the LIL and Maritime
Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49% of the cost of all of these transmission developments. The investment in LIL is accounted for on the equity basis. This project is expected to go into
service in 2017; 

  

	 	•	 	Emera’s 19.59% investment in APUC, excluding outstanding subscription receipts and associated dividend equivalents. APUC is a diversified generation, transmission and distribution utility traded on the TSX under
the symbol “AQN”. The distribution group operates in the United States and provides rate regulated water, electricity and natural gas utility services. The non-regulated generation group owns or has interests in a portfolio of North
American-based contracted wind, solar, hydroelectric and natural gas powered generating facilities. The transmission group invests in rate-regulated electric transmission and natural gas pipeline systems in the United States and Canada. The
investment in APUC is accounted for on the equity basis. There is a one quarter lag in reporting as APUC’s information is generally not publicly available at the time of Emera’s public release of its financial results. As at December 31,
2015, Emera owned 50.1 million common shares, 12.6 million outstanding subscription receipts and dividend equivalents, at an average conversion price of $9.20. The outstanding subscription receipts became eligible for conversion into APUC common
shares at Emera’s election in Q4 2015 and will automatically convert to common shares in Q4 2016 if an election is not made; 

  

	 	•	 	a 12.9% interest in M&NP. 

 NSPI 

NSPI is the primary electricity supplier in Nova Scotia, providing electricity generation, transmission and distribution services in Nova Scotia to
approximately 506,000 customers with approximately $4.6 billion in assets and approximately 1,700 employees.
 NSPI is a public utility as defined in the
Public Utilities Act and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are
also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings from time to time at NSPI’s or the UARB’s request. NSPI is regulated under a cost of service model, with rates
set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s regulated ROE range for 2013 to 2015 was 8.75% to 9.25%, based on an actual average regulated common
equity component of up to 40% of actual average regulated capitalization. NSPI’s targeted regulated ROE range remains unchanged for 2016. 
 NSPI
operates with a FAM, which enables NSPI to recover fluctuating fuel expenses through annual fuel rate adjustments, which is subject to UARB review and approval. Differences between prudently incurred fuel costs and amounts recovered from customers
through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year. 

As at December 31, 2015 the FAM has a net liability balance of $28.3 million (2014 - $47.9 million net asset ). 

			
	2015 Annual Information Form	  	
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 Market and Sales 

NSPI 
 Revenue and Electricity Sales by Customer Class

  

																	
	 	  	Electric Revenues (%)	 	  	GWh Electric Sales Volumes (%)	 
	 For the year ended December 31
	  	2015	 	  	2014	 	  	2015	 	  	2014	 
	 Residential
	  	 	51.5	  	  	 	50.7	  	  	 	43.1	  	  	 	42.5	  
	 Commercial
	  	 	29.5	  	  	 	29.4	  	  	 	30.1	  	  	 	30.1	  
	 Industrial
	  	 	15.4	  	  	 	16.2	  	  	 	23.6	  	  	 	24.4	  
	 Other
	  	 	3.6	  	  	 	3.7	  	  	 	3.2	  	  	 	3.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	100.0	  	  	 	100.0	  	  	 	100.0	  	  	 	100.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Energy Sources and Generation 

NSPI’s energy sources for its electric energy generation are coal, petroleum coke (“petcoke”), natural gas, heavy fuel oil, hydroelectric
energy, light fuel oil (gas turbine), biomass and wind. NSPI also purchases electric energy from IPPs in the Province of Nova Scotia and neighbouring markets outside the Province of Nova Scotia. 

NSPI owns 2,483 MW of generating capacity, of which approximately 50% is coal-fired; natural gas and/or oil comprise another 28% of capacity; hydro and wind
total 19% and biomass-fueled generation of 3%. In addition, NSPI has contracts to purchase renewable energy from IPPs. These IPPs own 496 MW, increasing to 552 MW in 2016 of wind and biomass-fueled generation capacity.

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

System Operations 
 The ECC co-ordinates and controls the
electric generation and transmission and distribution facilities. The ECC is linked to the generating stations and other key facilities through the Supervisory Control and Data Acquisition system, a communication network used by system
operators for remote monitoring and control of the power system components. 
 Through an interconnection agreement with NB Power, NSPI’s system has
access to other regional power systems and the rest of the interconnected North American electric bulk power systems. 
 Transmission and Distribution

 NSPI transmits and distributes electricity from its generating stations to its customers. NSPI’s transmission system consists of approximately
5,000 km of transmission facilities. The distribution system consists of approximately 27,000 km of distribution facilities. 
 Contribution to
Consolidated Net Income 
 NSPI’s contribution to Emera’s consolidated net income was $129.9 million in 2015 and $124.9 million in 2014. 

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

			
	2015 Annual Information Form	  	
 34

  
  

 Capital Expenditures 

NSPI’s capital expenditures in 2015 were $274 million (2014 - $274 million). 

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

Environmental Considerations 
 NSPI is subject to
regulation by federal, provincial and municipal authorities with regard to environmental matters, primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits
authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to NSPI. Failure to comply with
environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on NSPI. 
 Conformance
with legislative and NSPI’s requirements is verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the audits completed to December 31, 2015. 

The Province of Nova Scotia has established targets with respect to the percentage of renewable energy in NSPI’s generation mix. The most recent target
for each year of 2015 through 2019 was 25% of electrical energy which will be derived from renewable sources. That target was exceeded for 2015, with 27% of NSPI’s generation mix coming from renewable sources. In 2020, the target is 40% of
electrical energy to be derived from renewable sources. The Maritime Link Project will supply 153 MW of firm, on-peak power and approximately 900 GWh per year of renewable electricity to help NSPI meet the legislated target of 40% renewable
electricity in 2020. NSPI plans to retire a coal-fired generating unit following the commencement of commercial operations of the Maritime Link. 
 For
further information on environmental regulations affecting NSPI, see NSPI’s Annual Information Form. 
 Emera Maine 

On November 29, 2012, Bangor Hydro and MPS submitted a regulatory filing with the MPUC seeking permission to merge into one entity. This proposed change
was also subject to regulatory approval by the FERC. The merger application included a proposal to harmonize distribution rates for most residential and small commercial customers on a revenue neutral basis. No change was proposed to other
rates or rate classes. Regulatory approval was received in 2013 from the MPUC and FERC for Bangor Hydro and MPS to officially merge on January 1, 2014. Harmonization of rates was deferred to a future case. 

Emera Maine’s transmission operations are regulated by FERC, and its distribution operations and stranded cost recoveries are regulated by the MPUC.
Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the energy delivered through the utility’s transmission and distribution networks. Throughout the discussion below, various references are
made to the two predecessor entities to Emera Maine, which existed as separate entities until December 31, 2013. 
 Emera Maine has approximately $1.1
billion USD of assets and approximately $670 million USD of net rate base. Emera Maine owns and operates approximately 1,700 km of transmission facilities and 15,000 km of distribution facilities and a workforce of approximately 400 people.

			
	2015 Annual Information Form	  	
 35

  
  

 Market and Sales 

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

																	
	 	  	Electric Revenues (%)	 	  	GWh Electric Sales Volumes (%)	 
	 For the year ended December 31
	  	2015	 	  	2014	 	  	2015	 	  	2014	 
	 Residential
	  	 	47.8	  	  	 	48.3	  	  	 	39.7	  	  	 	39.7	  
	 Commercial
	  	 	36.2	  	  	 	36.5	  	  	 	38.7	  	  	 	38.7	  
	 Industrial
	  	 	8.8	  	  	 	9.1	  	  	 	20.9	  	  	 	20.9	  
	 Other
	  	 	7.2	  	  	 	6.1	  	  	 	0.7	  	  	 	0.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	100.0	  	  	 	100.0	  	  	 	100.0	  	  	 	100.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Distribution Operations 

Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the MPUC. Prior
to July 1, 2014, the allowed ROE was 10.2%, on a common equity component of 50%. Effective July 1, 2014, the allowed ROE became 9.55% on a common equity component of 49%. 

Transmission Operations 
 There are two transmission
districts for Emera Maine, corresponding to the service territories of the two pre-merger entities. 
 Bangor Hydro District Transmission 

Bangor Hydro District’s local transmission rates are regulated by the FERC and set annually on June 1, based upon a formula utilizing prior year actual
transmission investments, adjusted for current year forecasted transmission investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments was 11.14%. Effective October 16, 2014, the allowed ROE
changed to 10.57%, pending two outstanding complaints filed with the FERC to challenge the ISO-NE OATT allowed base ROE of 11.14%. The common equity component (i.e., the equity base upon which the allowable ROE is earned) is based upon the prior
calendar year actual average balances. Effective June 1, 2015, transmission rates for the Bangor Hydro District increased by approximately 21% in connection with its annual transmission formula rate filing (2014 – increased by 13%). The
increase is associated primarily with the under-recovery of prior year regional transmission revenues collected in local rates, as well as the recovery of increased transmission plant in service. 

Bangor Hydro District’s bulk transmission assets are managed by the ISO-NE as part of a region-wide pool of assets. The ISO-NE manages the regions’
bulk power generation and transmission systems and administers the open access transmission tariff. Currently, Bangor Hydro District, along with all other participating transmission providers, recovers the full cost of service for its transmission
assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is based on prior year regionally funded transmission investments,
adjusted for current year forecasted investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments ranged from 11.64% to 12.64%. Effective October 16, 2014, the transmission investments allowed ROE
changed to a range from 11.07% to 11.74%, pending the two aforementioned complaints filed with FERC. The common equity component is based upon the prior calendar year average balances. The participating transmission providers are also required to
contribute to the cost of service of such transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent. On June 1, 2015, Bangor Hydro District’s regionally recoverable
transmission investments and expenses decreased by 6% (2014 – increased by 7%). 

			
	2015 Annual Information Form	  	
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 As at December 31, 2015, the Company had accrued $5.0 million USD associated with the FERC ROE complaints
relating to Bangor Hydro District (2014 – $7.3 million USD). Refunds for the first FERC ROE complaint are being made to customers over a one-year period which began with the June 1, 2015 rate change. 

MPS District Transmission 
 MPS District local
transmission rates are regulated by the FERC and set annually on June 1 for wholesale and July 1 for retail customers, based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year
forecasted investments. The current allowed ROE for transmission operations is 10.2%. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015, the transmission rates for the MPS
District decreased by approximately 24% for wholesale customers (2014 – increased by 2%) and on July 1, 2015 decreased by 22% for retail customers (2014 – increased by 11%) in connection with its annual transmission formula rate filing.
These decreases were primarily due to an increase in wholesale transmission revenue that allows for a decrease in local customer transmission rates. 
 The
MPS District electric service territory is not connected to the New England bulk power system and it is not a member of ISO-NE. MPS District is not a party to the previously discussed ROE complaints at the FERC. 

Stranded Cost Recoveries 
 Stranded cost recoveries in
Maine are set by the MPUC. Electric utilities are entitled to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting
orders issued by the MPUC. Unlike transmission and distribution operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to
income and recovered through rates. Generally, regulatory rates to recover stranded costs are set every three years, determined under a traditional cost-of-service approach and are fully recoverable. On July 1 of each year, stranded
cost rates are adjusted to reflect recovery of cost deferrals for the prior stranded costs rate year under the full recovery mechanism, as well as factor in any new stranded cost information. 

Bangor Hydro District Stranded Costs 
 Bangor Hydro
District’s net stranded regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract, and deferrals associated with reconciling stranded costs. These net regulatory assets total
approximately $19.7 million USD as at December 31, 2015 (2014 – $25.1 million USD) or 1.8% of Emera Maine’s net asset base (2014 – 2.3%). 

On July 1, 2014, the Bangor Hydro District stranded cost rates decreased by 10%. Earlier, on March 1, 2014, stranded costs rates had increased by
20%. The allowed ROE used in setting the new rates on July 1, 2014, and March 1, 2014, was 5.9%, with a prescribed common equity component of 48%. The July 1, 2014 rate decrease remained in effect for all of 2015, and there was no rate
change on July 1, 2015. 
 MPS District Stranded Costs 

Effective January 1, 2015, the stranded cost rates for the MPS District decreased by approximately 150%. This was principally due to the flow-back to
customers of certain benefits received by Emera Maine from Maine Yankee associated with litigation with the United States Department of Energy on nuclear waste disposal. The allowed ROE used in setting the new rates on January 1, 2015 was 6.75%,
with a common equity component of 48%. The reduced stranded cost revenues are offset by reductions in expense and do not affect income. The January 1, 2015 rate decrease remained in effect for all of 2015 and there was no rate change on
July 1, 2015. MPS District has a net stranded cost regulatory liability of $2.68 million USD as of December 31, 2015. 

			
	2015 Annual Information Form	  	
 37

  
  

 Contribution to Consolidated Net Income 

Emera Maine’s contribution to Emera’s consolidated net income was $35.6 million USD in 2015 and $38.4 million USD in 2014. 

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

Capital Expenditures 
 Emera Maine’s capital
expenditures for the year ended 2015 were approximately $66 million (2014 – $85 million). 
 Environmental Considerations 

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

Emera Caribbean 
 As of December 31, 2015, Emera Caribbean
includes a 95.5% indirect interest in BLPC, a 49.6 % indirect controlling interest in Domlec, an 80.4% direct and indirect interest in GBPC, an 18.2% indirect interest in Lucelec and a wholly owned indirect interest in Emera Utility Service Bahamas.
As of February 25, 2016, Emera Caribbean’s indirect interest in BLPC has increased to 100%. 
 BLPC 

BLPC is a vertically-integrated utility and the provider of electricity on the Caribbean island of Barbados with approximately $0.5 billion of assets. It
serves approximately 126,000 customers, has a workforce of approximately 330 employees and is regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted to BLPC a franchise to generate, transmit and distribute
electricity on the island until 2028. Emera acquired its indirect interest in BLPC through the purchase of approximately 80.1% of the outstanding common shares of LPH, now ECI, and the parent company of BLPC in 2010. In 2015, Emera
increased its ownership interest in BLPC to 95.5%. Emera initiated a process to purchase the remaining 4.5% of common shares from minority shareholders of ECI, which was completed on February 25, 2016. 

BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and
providing an appropriate return to investors. BLPC’s approved allowable regulated return on rate base for 2015 and 2014 is 10%. 
 A fuel pass-through
mechanism provides the opportunity to recover all fuel costs in a timely manner. The Fair Trading Commission, Barbados has approved the calculation of the fuel charge, which is adjusted on a monthly basis. 

Domlec 
 Domlec is a vertically-integrated utility on the
island of Dominica with approximately $ 0.1 billion of assets. Domlec serves approximately 36,000 customers, has a workforce of 238 employees, and is regulated by the IRCD. On October 7, 2013, the IRCD issued a Transmission, Distribution &
Supply License and a Generation License, both of which came into effect on January 1, 2014 for a period of 25 years. These new licenses replaced the existing license, which was due to expire on December 31, 2015. Domlec’s approved allowable
regulated return on rate base for 2015 and 2014 was 15%. 

			
	2015 Annual Information Form	  	
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 A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely
manner. 
 GBPC 
 Emera, through its wholly owned
subsidiary ECHL, has a 50.0% direct and 30.4% indirect interest in GBPC, a vertically-integrated utility and the sole provider of electricity on Grand Bahama Island in The Bahamas with approximately $0.4 billion of assets. GBPC serves approximately
19,000 customers, has a workforce of approximately 205 employees and is regulated by the GBPA. The GBPA has granted GBPC a licensed, regulated and exclusive franchise to generate, transmit and distribute electricity on the island until 2054.
GBPC’s approved allowable regulated return on rate base for 2015 and 2014 was 10%. A fuel pass-through mechanism provides the opportunity to recover fuel costs in a timely manner. ECHL holds its indirect interest in GBPC through ICDU, which in
turn owns a 50% interest in GBPC. ICDU is listed on the Bahamas International Securities Exchange. 
 Effective February 1, 2016, the GBPA approved
GBPC’s GRA for the 2016 through 2018 period. Residential customers will see decreases of up to 4.5%, while commercial customers will see an increase of 1.5%. Commercial customers consume approximately 70% of GBPC’s production. Rates
were approved based upon an 8.8% allowable return on rate base. This rate decision will allow for customers to install renewable energy systems and sell their excess energy to GBPC. This is based on a tariff rider scheduled to be in place by Q3
2016. 
 On June 29, 2012, GBPC announced a new regulatory rate structure which was approved by the GBPA and became effective July 1, 2012. The new
regulatory rate structure consists of two components: (i) a base rate intended to recover GBPC’s operating expenses, depreciation and return on capital investment; and (ii) a fuel charge intended to recover all of GBPC’s fuel costs. 

On January 17, 2013, GBPC and the GBPA finalized an Operating Protocol and Regulatory Framework agreement. This agreement formalized the operating
protocols and regulatory construct GBPC agreed to in principle in June 2012. 
 As part of the initial rate case filing under the new regulatory structure,
the GBPA approved a return on rate base of 10%. Every three years, commencing in January 2016, base rates will be reviewed and approved by the GBPA. 

As a component of its regulatory agreement with the GBPA, GBPC has an earnings share mechanism to allow for earnings above or below its approved 10% return on
rate base to be deferred to a regulatory asset or liability at the rate of 50% of amounts below a 9% return on rate base and 50% of amounts above 11% return on rate base respectively. 

Lucelec 
 Emera owns an 18.2% indirect interest, through
ECI’s 19.1% interest in Lucelec, a vertically-integrated regulated electric utility on the Caribbean island of St. Lucia. Lucelec is listed on the Eastern Caribbean Securities Exchange. 

Emera Utility Services Bahamas 
 Emera Utility Services
Bahamas provides utility construction services in The Bahamas. 

			
	2015 Annual Information Form	  	
 39

  
  

 Market and Sales 

Emera Caribbean Revenue and Electricity Sales by Customer Class(1) 

 

																	
	 	  	Electric Revenues (%)	 	  	GWh Electric Sales Volumes (%)	 
	 For the year ended December 31
	  	2015	 	  	2014	 	  	2015	 	  	2014	 
	 Residential
	  	 	32.4	  	  	 	33.4	  	  	 	33.7	  	  	 	33.4	  
	 Commercial
	  	 	57.0	  	  	 	58.6	  	  	 	56.8	  	  	 	56.9	  
	 Industrial
	  	 	8.8	  	  	 	6.3	  	  	 	7.7	  	  	 	7.7	  
	 Other
	  	 	1.8	  	  	 	1.7	  	  	 	1.8	  	  	 	2.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	100.0	  	  	 	100.0	  	  	 	100.0	  	  	 	100.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

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

 Energy Sources and Generation 

BLPC’s and GBPC’s energy sources for its electricity generation is primarily heavy fuel oil used for base load generation and light fuel oil used for
peaking generation. 
 BLPC owns approximately 239 MW of generation comprised of: (i) 5 gas turbine units with a combined capacity of 86 MW (light oil and
jet fuel oil-fired); (ii) 6 diesel units with a combined capacity of 113 MW (heavy oil-fired); and (ii) 2 steam units with a combined capacity of 40 MW (heavy oil-fired). 

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

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

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

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

Transmission and Distribution 
 BLPC, GBPC and Domlec
transmit and distribute electricity from their generating stations to their customers. 
 BLPC’s transmission system consists of 116 km of transmission
lines, including major substations connected to the transmission and distribution system. The distribution system consists of 2,800 km of distribution lines which includes distribution supply substations. 

GBPC’s transmission system consists of 138 km of transmission lines, including major substations connected to the transmission and distribution system.
The distribution system consists of approximately 850 km of distribution lines which includes distribution supply substations. 

			
	2015 Annual Information Form	  	
 40

  
  

 Domlec’s transmission system consists of 452 km of transmission lines, including major substations
connected to the transmission and distribution system. The distribution system consists of approximately 640 km of distribution lines which includes distribution supply substations. 

Contribution to Consolidated Net Income 
 Emera
Caribbean’s contribution to Emera’s consolidated net income was $31.4 million USD in 2015 and $26.0 million USD in 2014. 
 Seasonal Nature

 Electricity sales and related generation varies significantly over the year in the Caribbean; Q3 is typically the strongest period, reflecting warmer
weather. 
 Capital Expenditures 
 Emera
Caribbean’s capital expenditures for the year ended 2015 were approximately $44 million (2014 – $30 million). 
 Environmental Considerations

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

Emera Energy consists of Emera’s wholly owned Emera Energy Services, EE New England Gas Generation, Bayside Power LP and Brooklyn Energy; and Emera’s
indirect 50% interest in Bear Swamp. On January 29, 2015, Emera sold its interest in NWP to its 51% partner, First Wind. 
 Emera Energy Services

 Emera Energy Services derives revenue and earnings from the wholesale marketing and trading of natural gas, electricity and other energy-related
commodities and derivatives within the Company’s strict risk tolerances, including those related to value-at-risk (VaR) and credit exposure. More specifically, Emera Energy purchases and sells physical natural gas and related transportation
capacity rights, as well as providing related energy asset management services. EES is also responsible for commercial management of electricity production and fuel procurement for Emera Energy Generation’s fleet. Established in 2002, Emera
Energy’s marketing and trading business currently has approximately 80 employees engaged in commercial activities and related back office, legal and other support functions. The primary market for the marketing and trading business is
northeastern North America, including the Marcellus shale gas region, the U.S. Gulf Coast and Central Canada. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading
entities. Marketing and trading operates in a competitive environment, and its business relies on knowledge of the region’s energy markets, understanding of pipeline infrastructure, a network of counterparty relationships and a focus on
customer service. Emera Energy invests in physical transportation capacity rights to move gas across its portfolio, utilizes financial products to hedge commodity prices, and minimizes open commodity positions in order to maintain the low to
moderate risk profile of its marketing and trading business. 

			
	2015 Annual Information Form	  	
 41

  
  

 Emera Energy Generation 

Emera Energy wholly owns and operates a portfolio of high efficiency, non-utility electricity generating facilities in northeast North America. Emera Energy
has approximately 125 employees in its wholly owned generation business. The New England facilities participate in the regional capacity market and are compensated for being available to provide power. For the portion of output not committed under
power purchase agreements, Emera Energy’s generation facilities sell into price-based competitive markets and earn revenues through the physical delivery of power and ancillary services, such as load regulation. 

Market and Sales 
 Information regarding these facilities
is summarized in the following table: 
  

													
	 Wholly Owned Generation Facilities
	  	 Location
	  	Capacity
(MW)	 	  	Commissioning /
In-Service Date	  	 Fuel
	  	 Description

	 New England
	  		  				  		  		  	
						
	 Bridgeport (1)
	  	Connecticut	  	 	560	  	  	1999	  	Natural gas	  	Selling electricity and capacity to ISO-NE
	 Tiverton
	  	Rhode Island	  	 	265	  	  	2000	  	Natural gas	  	Selling electricity and capacity to ISO-NE
	 Rumford
	  	Maine	  	 	265	  	  	2000	  	Natural gas	  	Selling electricity and capacity to ISO-NE
		  		  	  
	  
	 	  		  		  	
	 Total New England
	  		  	 	1,090	  	  		  		  	
		  		  	  
	  
	 	  		  		  	
	 Maritime Canada
	  		  				  		  		  	
	 Bayside
	  	New Brunswick	  	 	290	  	  	2001	  	Natural gas	  	Long-term power purchase agreement November - March; Selling electricity to Maritime Provinces and ISO-NE for remainder of year
	 Brooklyn
	  	Nova Scotia	  	 	30	  	  	1996	  	Biomass	  	Long-term purchase power agreement
		  		  	  
	  
	 	  		  		  	
	 Total Maritime Canada
	  		  	 	320	  	  		  		  	
		  		  	  
	  
	 	  		  		  	
	 Total
	  		  	 	1,410	  	  		  		  	
		  		  	  
	  
	 	  		  		  	

  

	(1)	A Q2 2015 upgrade at Bridgeport increased its nameplate capacity from 540 MW to 560 MW. 

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

															
	 Investments in Generation
Facilities (1)
	  	Ownership (%)	 	  	 Location
	  	Capacity
(MW)	 	  	 Fuel
	  	 Description

	 New England
	  				  		  				  		  	
	 Bear Swamp
	  	 	50	  	  	Massachusetts	  	 	600	  	  	Hydro	  	Long-term power purchase agreement and selling electricity and capacity to ISO-NE

  

	(1)	In January 29, 2015, Emera completed the sale of its 49% interest in NWP to First Wind for $223.3 million USD. Emera’s carrying value of its 49% interest as at December 31, 2014 was $204.4 million USD.

 Information regarding Emera Energy’s revenues is summarized below: 

Emera Energy Revenue 
  

									
	 For the year ended December 31
	  	2015	 	  	2014	 
	 Electricity sales
	  	$	463.1	  	  	$	517.7	  
	 Capacity revenues
	  	$	43.7	  	  	$	45.8	  
	 Marketing and trading margin
	  	$	83.1	  	  	$	237.4	  
		  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	589.9	  	  	$	800.9	  
		  	  
	  
	 	  	  
	  
	 

			
	2015 Annual Information Form	  	
 42

  
  

 Contribution to Consolidated Net Income 

Emera Energy’s contribution to Emera’s consolidated net income was $98.9 million in 2015 and $185.7 million in 2014. 

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

Capital Expenditures 
 Emera Energy’s capital
expenditures for the year ended 2015 were approximately $42 million (2014 – $63 million). The 2015 capital expenditures included a Q2 2015 upgrade at the Bridgeport facility that increased the nameplate capacity from 540 MW to 560 MW. The 2014
capital expenditures included a major refit and upgrade at the Bridgeport facility that increased the nameplate capacity from 520 MW to 540 MW. 

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

Pipelines 
 Pipelines consists of Emera’s wholly
owned EBPC and Emera’s 12.9% interest in M&NP. 
 EBPC 

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

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

Contribution to Consolidated Net Income 
 Pipelines’
contribution to Emera’s consolidated net income was $37.5 million in 2015 and $32.7 million in 2014. 
 Environmental Considerations 

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

			
	2015 Annual Information Form	  	
 43

  
  

 Economic Dependence 

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

Corporate and Other’s contribution to Emera’s consolidated net income was $45.3 million in 2015 and $(7.7) million in 2014. Included in the
fiscal 2015 results are acquisition related after-tax costs of $52.8 million and an after-tax mark-to-market gain of $100.5 million related to the effect of USD-denominated currency and forward contracts. These contracts were put in place to
economically hedge the anticipated proceeds from the Debenture Offering for the TECO Transaction. 
 Capital Expenditures 

Corporate and Other capital expenditures for the year ended 2015 were approximately $10.0 million (2014 – $10.0 million). 

Other Emera Environmental Matters 
 Emera’s
activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste. Emera
estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations will be approximately $43.2 million during fiscal 2015 and are estimated to be $63.9 million from 2016 through 2019. The
estimated expenditures do not include: (i) costs related to possible changes in the environmental laws or regulations and enforcement policies that may be enacted in response to issues such as climate change and other pollutant emissions; and (ii)
expenditures related to the addition of renewable or cleaner energy generation. 
 Risk Factors 

See the “Business Risks and Risk Management” section of the MD&A and “Principal Risks and Uncertainties” in the Commitments and
Contingencies note to Emera’s financial statements for the year ended December 31, 2015, which are each incorporated herein by reference. 
 Capital
Structure 
 The authorized capital of Emera consists of an unlimited number of common shares, an unlimited number of first preferred shares and an
unlimited number of second preferred shares. Each class of preferred shares are issuable in series. 
 As at December 31, 2015, 147,205,643 common
shares, 3,864,636 Series A First Preferred Shares, 2,135,364 Series B First Preferred Shares, 10,000,000 Series C First Preferred Shares, 5,000,000 Series E First Preferred Shares and 8,000,000 Series F First Preferred Shares were issued and
outstanding. 

			
	2015 Annual Information Form	  	
 44

  
  

 Common Shares 

The holders of common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Emera, other than separate
meetings of holders of any other class or series of shares, and to one vote in respect of each common share held at such meetings. 
 The holders of common
shares are entitled to dividends on a pro rata basis, as and when declared by the Board. Subject to the rights of the holders of the first preferred shares and second preferred shares, if any, who are entitled to receive dividends in
priority to the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other class of shares of Emera. 

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

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

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

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

	 	•	 	where entitled by law; 

  

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

  

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

In any instance where the holders of Series A First Preferred Shares are entitled to vote, each holder shall have one vote for each Series A Preferred Share,
subject to the restrictions described under “Share Ownership Restrictions” below. 
 The holders of Series A First Preferred Shares were entitled
to receive fixed cumulative preferred cash dividends in the amount of $0.2750 per share per quarter during the five-year period commencing on August 15, 2010 and ending on (and inclusive of) August 14, 2015, as and when declared by the
Board. For each five-year period after this date, the holders of Series A First Preferred Shares will be entitled to receive reset fixed cumulative preferred cash dividends. The reset annual dividends per share will be determined by
multiplying the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 1.84%, by $25.00. The dividend rate for the Series A First Preferred Shares was set at $0.1597 per
share per quarter for the five-year period commencing on August 15, 2015 and ending on (and inclusive of) August 14, 2020. 
 The Series A First Preferred
Shares were not redeemable by Emera prior to August 15, 2015. On that date and on August 15 every five years thereafter, Emera has the right in certain circumstances to redeem for cash all or any part of the then outstanding Series A First
Preferred Shares at a price of $25.00 per share plus any accrued and unpaid dividends up to but excluding the date fixed for redemption. Emera did not exercise its right to redeem all or any part of the outstanding Series A First Preferred
Shares on August 15, 2015. 

			
	2015 Annual Information Form	  	
 45

  
  

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

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

	 	•	 	where entitled by law; 

  

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

  

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

In any instance where the holders of Series B First Preferred Shares are entitled to vote, each holder shall have one vote for each Series B Preferred Share,
subject to the restrictions described under “Share Ownership Restrictions” below. 
 The holders of Series B First Preferred Shares are entitled
to receive floating rate cumulative preferred cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate, which is
the sum of the three-month Government of Canada T-bill Rate on the applicable reset date plus 1.84%, by $25.00. The dividend rate for the Series B First Preferred Shares was set at $0.1508 per share for the quarter commencing on August 15, 2015
and ended on (and inclusive of) November 14, 2015, and was paid on November 15, 2015. The dividend rate for the Series B First Preferred Shares was subsequently reset to $0.1425 per share for the quarter commencing on November 15, 2015 and
ending on (and inclusive of) February 14, 2016. 
 Emera has the right in certain circumstances to redeem for cash all or any part of the outstanding Series
B First Preferred Shares at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on August 15, 2020 and on August 15 every five years thereafter, or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date
after August 15, 2015. 
 Subject to the automatic conversion described below and the right of Emera to redeem the Series B First Preferred Shares, on
August 15, 2020 and on August 15 every five years thereafter, the holders of Series B First Preferred Shares have the right to convert any or all of their Series B First Preferred Shares into an equal number of Series A First Preferred
Shares. In addition, Series B First Preferred Shares may be automatically converted by Emera into Series A First Preferred Shares if Emera determines that there are less than 1,000,000 Series B First Preferred Shares outstanding. 

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

	 	•	 	where entitled by law; 

			
	2015 Annual Information Form	  	
 46

  
  

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

  

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

In any instance where the holders of Series C First Preferred Shares are entitled to vote, each holder shall have one vote for each Series C Preferred Share,
subject to the restrictions described under “Share Ownership Restrictions” below. 
 The holders of Series C First Preferred Shares are entitled
to receive fixed cumulative preferred cash dividends in the amount of $0.25625 per share per quarter during the six-year period commencing on August 15, 2012 and ending on (and inclusive of) August 14, 2018, as and when declared by the
Board. For each five year period after this date, the holders of Series C First Preferred Shares will be entitled to receive reset fixed cumulative preferred cash dividends. The reset annual dividends per share will be determined by
multiplying the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 2.65%, by $25.00.

The Series C First Preferred Shares will not be redeemable by Emera prior to August 15, 2018. On that date and on August 15 every five years
thereafter, Emera has the right in certain circumstances to redeem for cash all or any part of the then outstanding Series C First Preferred Shares at a price equal to $25.00 per share plus all accrued and unpaid dividends up to but excluding the
date fixed for redemption.
 Subject to the automatic conversion described below and the right of Emera to redeem Series C First Preferred Shares, on August
15, 2018 and on August 15 every five years thereafter, the holders of Series C First Preferred Shares have the right to convert any or all of their Series C First Preferred Shares into an equal number of Series D First Preferred Shares. In
addition, Series C First Preferred Shares may be automatically converted by Emera into Series D First Preferred Shares if Emera determines that there are less than 1,000,000 Series C First Preferred Shares outstanding. 

Series D First Preferred Shares 
 As at December
31, 2015, there were no Series D First Preferred Shares issued and outstanding. 
 The holders of Series D First Preferred Shares are not entitled to attend
any meetings of the shareholders of Emera or to vote at any such meeting, except for the following: 
  

	 	•	 	where entitled by law; 

  

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

  

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

In any instance where the holders of Series D First Preferred Shares are entitled to vote, each holder shall have one vote for each Series D Preferred Share,
subject to the restrictions described under “Share Ownership Restrictions” below. 
 The holders of Series D First Preferred Shares will be
entitled to receive floating rate cumulative preferred cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate,
which is the sum of the three-month Government of Canada T-bill Rate on the applicable reset date plus 2.65%, by $25.00. 
 Emera has the right in certain
circumstances to redeem for cash all or any part of the outstanding Series D First Preferred Shares at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case
of redemptions on August 15, 2023 and on August 15 every 5 years 

			
	2015 Annual Information Form	  	
 47

  
  

 
thereafter, or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any other date after August 15,
2018. 
 Subject to the automatic conversion described below and the right of Emera to redeem the Series D First Preferred Shares, on August 15, 2023
and on August 15 every five years thereafter, the holders of Series D First Preferred Shares have the right to convert any or all of their Series D First Preferred Shares into an equal number of Series C First Preferred Shares. In
addition, Series D First Preferred Shares may be automatically converted by Emera into Series C First Preferred Shares if Emera determines that there are less than 1,000,000 Series D First Preferred Shares outstanding. 

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

	 	•	 	where entitled by law; 

  

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

  

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

In any instance where the holders of Series E First Preferred Shares are entitled to vote, each holder shall have one vote for each Series E Preferred Share,
subject to the restrictions described under “Share Ownership Restrictions” below. 
 The holders of Series E First Preferred Shares are entitled
to receive fixed cumulative preferred cash dividends in the amount of $1.125 per share per annum in perpetuity, subject to the Company’s redemption rights. On or after August 15, 2018, the Company may, on not less than 30 nor more than 60
days’ notice, redeem the Series E First Preferred Shares in whole or in part, at the Company’s option, by the payment in cash of $26.00 per Series E First Preferred Share if redeemed prior to August 15, 2019; at $25.75 per Series E First
Preferred Share if redeemed on or after August 15, 2019 but prior to August 15, 2020; at $25.50 per Series E First Preferred Share if redeemed on or after August 15, 2020 but prior to August 15, 2021; at $25.25 per Series E First Preferred Share if
redeemed on or after August 15, 2021 but prior to August 15, 2022; and at $25.00 per Series E First Preferred Share if redeemed on or after August 15, 2022, in each case together with all declared and unpaid dividends up to but excluding the date
fixed for redemption. 
 Series F First Preferred Shares 

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

	 	•	 	where entitled by law; 

  

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

  

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

In any instance where the holders of Series F First Preferred Shares are entitled to vote, each holder shall have one vote for each Series F First Preferred
Share, subject to the restrictions described under “Share Ownership Restrictions” below. 
 The holders of Series F First Preferred Shares are
entitled to receive fixed cumulative preferred cash dividends in the amount of $0.265625 per share per quarter during the period commencing on August 15, 2014 and ending on (and 

			
	2015 Annual Information Form	  	
 48

  
  

 
inclusive of) February 14, 2020, as and when declared by the Board. For each five-year period after this date, the holders of Series F First Preferred Shares will be entitled to receive
reset fixed cumulative preferred cash dividends. The reset annual dividends per share will be determined by multiplying the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset
date plus 2.63%, by $25.00. 
 The Series F First Preferred Shares will not be redeemable by Emera prior to February 15, 2020. On that date and on
February 15 every five years thereafter, Emera has the right in certain circumstances to redeem for cash all or any part of the then outstanding Series F First Preferred Shares, at a price of $25 per share plus any accrued and unpaid dividends
up to but excluding the date fixed for redemption. 
 Subject to the automatic conversion described below and the right of Emera to redeem the Series F
First Preferred Shares, on February 15, 2020 and on February 15 every five years thereafter, the holders of the Series F First Preferred Shares have the right to convert any or all of their Series F First Preferred Shares into an equal number
of Series G First Preferred Shares. In addition, Series F First Preferred Shares may be automatically converted by Emera into Series G First Preferred Shares if Emera determines that there are less than 1,000,000 Series F First Preferred Shares
outstanding. 
 Series G First Preferred Shares 

As at December 31, 2015, there were no Series G First Preferred Shares issued and outstanding. 

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

	 	•	 	where entitled by law; 

  

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

  

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

In any instance where the holders of Series G First Preferred Shares are entitled to vote, each holder shall have one vote for each Series G Preferred Share,
subject to the restrictions described under “Share Ownership Restrictions” below. 
 The holders of Series G First Preferred Shares will be
entitled to receive floating rate cumulative preferred cash dividends, as and when declared by the Board. The dividends are payable quarterly, in the amount per share determined by multiplying the applicable quarterly floating dividend rate,
which is the sum of the three-month Government of Canada T-bill Rate on the applicable reset date plus 2.63%, by $25.00. 
 Emera has the right in certain
circumstances to redeem for cash all or any part of the outstanding Series G First Preferred Shares at a price equal to (i) $25.00 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case
of redemptions on February 15, 2025 and on February 15 every five years thereafter, or (ii) $25.50 per share together with all accrued and unpaid dividends up to but excluding the date fixed for redemption in the case of redemptions on any
other date after February 15, 2020. 
 Subject to the automatic conversion described below and the right of Emera to redeem the Series G First Preferred
Shares, on February 15, 2025 and on February 15 every five years thereafter, the holders of Series G First Preferred Shares have the right to convert any or all of their Series G First Preferred Shares into an equal number of Series F First
Preferred Shares. In addition, Series G First Preferred Shares may be automatically converted by Emera into Series F First Preferred Shares if Emera determines that there are less than 1,000,000 Series G First Preferred Shares outstanding. 

			
	2015 Annual Information Form	  	
 49

  
  

 Series A, B, C, D, E, F, G First Preferred Shares 

The first preferred shares of each series rank on a parity with the first preferred shares of every other series and are entitled to a preference over the
second preferred shares, the common shares, and any other shares ranking junior to the first preferred shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in
the liquidation, dissolution or wind-up, whether voluntary or involuntary. 
 In the event the Company fails to pay, in aggregate, eight quarterly dividends
on any series of the first preferred shares, the holders of the first preferred shares will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of
the total number of directors elected at any such meeting. 
 Emera Second Preferred Shares 

The second preferred shares have special rights, privileges, restrictions and conditions substantially similar to the first preferred shares, except that the
second preferred shares rank junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Emera in the event of liquidation, dissolution or winding-up of Emera. As at
December 31, 2015, Emera had not issued any second preferred shares. 
 Share Ownership Restrictions 

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

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

Emera’s articles of association contain provisions for the enforcement of these constraints on share ownership, including provisions for suspension of
voting rights, forfeiture of dividends, prohibitions of share transfer and issuance, compulsory sale of shares and redemption, and suspension of other shareholder rights. Emera’s Board may require shareholders to furnish statutory declarations
relevant to the enforcement of the restrictions. 
 NSPI Series D First Preferred Shares 

On October 15, 2015, NSPI redeemed all of its outstanding NSPI Series D First Preferred Shares. As a result, zero NSPI Series D First Preferred Shares
were issued and outstanding as of December 31, 2015. 

			
	2015 Annual Information Form	  	
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 Dividends 

Any dividend payments will be at the Board’s discretion based upon earnings and capital requirements and any other factors as the Board may consider
relevant. 
 The Board approved the payment of the following dividends during the last three completed fiscal years: 

 

													
	 Common Shares (1) and (2)
	 
	 Fiscal Year
	  	Record Date	 	  	Date Paid	 	  	Dividend (per share) ($)	 
	 2015
	  	 	November 2	  	  	 	November 16	  	  	 	0.4750	  
		  	 	July 31	  	  	 	August 17	  	  	 	0.4000	  
		  	 	May 1	  	  	 	May 15	  	  	 	0.4000	  
		  	 	February 3	  	  	 	February 17	  	  	 	0.3875	  
	 2014
	  	 	November 3	  	  	 	November 17	  	  	 	0.3875	  
		  	 	July 31	  	  	 	August 15	  	  	 	0.3625	  
		  	 	May 1	  	  	 	May 15	  	  	 	0.3625	  
		  	 	February 3	  	  	 	February 17	  	  	 	0.3625	  
	 2013
	  	 	November 1	  	  	 	November 15	  	  	 	0.3625	  
		  	 	July 31	  	  	 	August 15	  	  	 	0.3500	  
		  	 	May 1	  	  	 	May 15	  	  	 	0.3500	  
		  	 	February 1	  	  	 	February 15	  	  	 	0.3500	  
	
	 Series A First Preferred
Shares
	 
	 Fiscal Year
	  	Record Date	 	  	Date Paid	 	  	Dividend (per share)	 
	 2015
	  	 	November 2	  	  	 	November 15	  	  	 	0.1597	  
		  	 	July 31	  	  	 	August 17	  	  	 	0.2750	  
		  	 	May 1	  	  	 	May 15	  	  	 	0.2750	  
		  	 	February 3	  	  	 	February 17	  	  	 	0.2750	  
	 2014
	  	 	November 3	  	  	 	November 17	  	  	 	0.2750	  
		  	 	July 31	  	  	 	August 15	  	  	 	0.2750	  
		  	 	May 1	  	  	 	May 15	  	  	 	0.2750	  
		  	 	February 3	  	  	 	February 17	  	  	 	0.2750	  
	 2013
	  	 	November 1	  	  	 	November 15	  	  	 	0.2750	  
		  	 	July 31	  	  	 	August 15	  	  	 	0.2750	  
		  	 	May 1	  	  	 	May 15	  	  	 	0.2750	  
		  	 	February 1	  	  	 	February 15	  	  	 	0.2750	  
	
	 Series B First Preferred Shares (3)
	 
	 Fiscal Year
	  	Record Date	 	  	Date Paid	 	  	Dividend (per share)	 
	 2015
	  	 	November 2	  	  	 	November 15	  	  	 	0.1508	  
	
	 Series C First Preferred
Shares
	 
	 Fiscal Year
	  	Record Date	 	  	Date Paid	 	  	Dividend (per share)	 
	 2015
	  	 	November 2	  	  	 	November 15	  	  	 	0.25625	  
		  	 	July 31	  	  	 	August 17	  	  	 	0.25625	  
		  	 	May 1	  	  	 	May 15	  	  	 	0.25625	  
		  	 	February 3	  	  	 	February 17	  	  	 	0.25625	  
	 2014
	  	 	November 3	  	  	 	November 17	  	  	 	0.25625	  
		  	 	July 31	  	  	 	August 15	  	  	 	0.25625	  
		  	 	May 1	  	  	 	May 15	  	  	 	0.25625	  
		  	 	February 3	  	  	 	February 17	  	  	 	0.25625	  

			
	2015 Annual Information Form	  	
 51

  
  

									
	 2013
	  	November 1	  	November 15	  	 	0.25625	  
		  	July 31	  	August 15	  	 	0.25625	  
		  	May 1	  	May 15	  	 	0.25625	  
		  	February 1	  	February 15	  	 	0.25625	  
	
	 Series E First Preferred Shares (4)
	 
	 Fiscal Year
	  	Record Date	  	Date Paid	  	Dividend (per share)	 
	 2015
	  	November 2	  	November 15	  	 	0.28125	  
		  	July 31	  	August 17	  	 	0.28125	  
		  	May 1	  	May 15	  	 	0.28125	  
		  	February 3	  	February 17	  	 	0.28125	  
	 2014
	  	November 3	  	November 17	  	 	0.28125	  
		  	July 31	  	August 15	  	 	0.28125	  
		  	May 1	  	May 15	  	 	0.28125	  
		  	February 3	  	February 17	  	 	0.28125	  
	 2013
	  	November 1	  	November 15	  	 	0.28125	  
		  	July 31	  	August 15	  	 	0.20340	  
	
	 Series F First Preferred Shares (5)
	 
	 Fiscal Year
	  	Record Date	  	Date Paid	  	Dividend (per share)	 
	 2015
	  	November 2	  	November 15	  	 	0.265625	  
		  	July 31	  	August 17	  	 	0.265625	  
		  	May 1	  	May 15	  	 	0.265625	  
		  	February 3	  	February 17	  	 	0.265625	  
	 2014
	  	November 3	  	November 17	  	 	0.265625	  
		  	July 31	  	August 15	  	 	0.195000	  

  

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

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

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

	(4)	The Series E First Preferred Shares were issued June 10, 2013. 

	(5)	The Series F First Preferred Shares were issued June 9, 2014. 

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

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

					
	 	  	 DBRS
	  	 S&P

			
	Corporate	  	BBB (high)	  	BBB +
	Senior unsecured debt program	  	BBB(high)	  	BBB
	First Preferred Shares	  	Pfd-3 (high)	  	P-2 (low)

  

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

			
	2015 Annual Information Form	  	
 52

  
  

 DBRS 

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

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

On March 11, 2015, DBRS removed Emera from “Under Review with Developing Implications” following the closing of the Brunswick Pipeline financing and
the sale of NWP. On the same date, DBRS confirmed Emera’s Issuer Rating and Medium-Term Notes rating at BBB (high) and the Cumulative Preferred Shares Rating at Pfd-3 (high), all with stable trends. 

On September 4, 2015, following the announcement of the TECO Transaction, DBRS placed the ratings of Emera “Under Review with Developing
Implications”. The rating actions reflect DBRS’s view that while the TECO Transaction would have a relatively neutral impact on Emera’s business risk assessment, the impact on the financial risk assessment was uncertain at the time of
the ratings actions, as Emera’s financing plan had not been finalized. DBRS indicated that it will further review Emera’s financing plan when it is finalized. 

S&P 
 S&P’s credit ratings are on a long term
debt scale that ranges from AAA to D, representing the range from highest to lowest quality of such rated securities. The rating of BBB+ obtained from S&P in respect of the corporate rating indicates that the issuer has adequate capacity to meet
its financial commitments and is the fourth highest of ten available rating categories. The rating of BBB from S&P in respect of the senior unsecured debt indicates that the obligation exhibits adequate protection parameters and is the fourth
highest of ten available ratings categories. In each case, however, adverse economic conditions or changing circumstances are more likely to lead to weakened capacity of the obligor to meet its financial commitments on the obligation. The addition
of a “(+)” or “(-)” designation after a rating indicates the relative standing within a particular category. 
 A P-2 (low) rating with
respect to Emera’s Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares and Series F First Preferred Shares is the third lowest of the three sub-categories within the
second highest rating of the eight standard categories of ratings utilized by S&P for preferred shares. 
 On September 8, 2015, S&P revised its
outlook on Emera to negative from stable, while affirming all ratings on Emera, including its ‘BBB+’ long-term corporate rating. S&P indicated that the negative outlook is primarily associated with the Debentures and the risk that they
will not be converted into equity upon successful close of the TECO Transaction. S&P could revise its outlook to stable within a two-year outlook period, if the Debentures are successfully converted. 

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

			
	2015 Annual Information Form	  	
 53

  
  

 Market for Securities 

Trading Price and Volume 
 Emera’s common shares,
Series A First Preferred Shares, Series B First Preferred Shares, Series C First Preferred Shares, Series E First Preferred Shares, Series F First Preferred Shares and instalment receipts are listed and posted for trading on the TSX under the
symbols “EMA”, “EMA.PR.A”, “EMA.PR.B”, “EMA.PR.C”, “EMA.PR.E”, “EMA.PR.F” and “EMA.IR”, respectively. 

The trading volume and high and low price for Emera’s securities for each month of 2015 are set out below: 

 

													
	 Common Shares
	 
	 2015
	  	High($)	 	  	Low($)	 	  	Volume	 
	 January
	  	 	42.21	  	  	 	38.35	  	  	 	7,322,144	  
	 February
	  	 	43.62	  	  	 	40.76	  	  	 	7,339,844	  
	 March
	  	 	42.30	  	  	 	40.03	  	  	 	8,675,504	  
	 April
	  	 	42.15	  	  	 	40.16	  	  	 	4,588,076	  
	 May
	  	 	42.44	  	  	 	40.17	  	  	 	6,405,646	  
	 June
	  	 	42.30	  	  	 	39.12	  	  	 	5,787,706	  
	 July
	  	 	43.83	  	  	 	39.42	  	  	 	5,091,751	  
	 August
	  	 	47.51	  	  	 	41.67	  	  	 	7,641,029	  
	 September
	  	 	45.29	  	  	 	41.49	  	  	 	13,660,371	  
	 October
	  	 	44.69	  	  	 	42.71	  	  	 	8,982,241	  
	 November
	  	 	43.38	  	  	 	42.00	  	  	 	6,464,684	  
	 December
	  	 	44.01	  	  	 	41.32	  	  	 	8,154,464	  

  

													
	 Series B First Preferred
Shares*
	 
	 2015
	  	High($)	 	  	Low($)	 	  	Volume	 
	 January
	  				  				  			
	 February
	  				  				  			
	 March
	  				  				  			
	 April
	  				  				  			
	 May
	  				  				  			
	 June
	  				  				  			
	 July
	  				  				  			
	 August
	  	 	14.50	  	  	 	12.02	  	  	 	14,331	  
	 September
	  	 	13.25	  	  	 	11.85	  	  	 	52,285	  
	 October
	  	 	12.90	  	  	 	10.80	  	  	 	63,456	  
	 November
	  	 	14.31	  	  	 	11.99	  	  	 	108,805	  
	 December
	  	 	14.00	  	  	 	12.10	  	  	 	127,536	  

  

	*	The Series B First Preferred Shares commenced trading on August 19, 2015

													
	 Series A First Preferred
Shares
	 
	 2015
	  	High($)	 	  	Low($)	 	  	Volume	 
	 January
	  	 	21.28	  	  	 	17.02	  	  	 	281,745	  
	 February
	  	 	18.02	  	  	 	17.00	  	  	 	184,479	  
	 March
	  	 	18.70	  	  	 	17.25	  	  	 	193,563	  
	 April
	  	 	18.16	  	  	 	15.50	  	  	 	280,249	  
	 May
	  	 	18.54	  	  	 	17.01	  	  	 	84,954	  
	 June
	  	 	17.87	  	  	 	16.70	  	  	 	111,007	  
	 July
	  	 	16.61	  	  	 	14.50	  	  	 	157,143	  
	 August
	  	 	15.94	  	  	 	14.35	  	  	 	111,229	  
	 September
	  	 	15.69	  	  	 	13.45	  	  	 	96,614	  
	 October
	  	 	14.75	  	  	 	12.61	  	  	 	277,140	  
	 November
	  	 	14.89	  	  	 	13.45	  	  	 	111,698	  
	 December
	  	 	14.26	  	  	 	12.47	  	  	 	173,789	  

  

													
	 Series C First Preferred
Shares
	 
	 2015
	  	High($)	 	  	Low($)	 	  	Volume	 
	 January
	  	 	25.85	  	  	 	22.08	  	  	 	222,362	  
	 February
	  	 	24.90	  	  	 	23.28	  	  	 	184,333	  
	 March
	  	 	24.84	  	  	 	23.46	  	  	 	393,340	  
	 April
	  	 	24.59	  	  	 	21.00	  	  	 	312,749	  
	 May
	  	 	24.49	  	  	 	22.70	  	  	 	151,381	  
	 June
	  	 	23.67	  	  	 	21.75	  	  	 	120,171	  
	 July
	  	 	22.86	  	  	 	19.79	  	  	 	184,954	  
	 August
	  	 	20.80	  	  	 	19.50	  	  	 	140,486	  
	 September
	  	 	20.00	  	  	 	16.35	  	  	 	341,690	  
	 October
	  	 	20.14	  	  	 	16.41	  	  	 	279,608	  
	 November
	  	 	20.30	  	  	 	18.56	  	  	 	320,321	  
	 December
	  	 	19.74	  	  	 	15.80	  	  	 	462,493	  

 
 

			
	2015 Annual Information Form	  	
 54

  
  

 

													
	 Series E First Preferred
Shares
	 
	 2015
	  	High($)	 	  	Low($)	 	  	Volume	 
	 January
	  	 	24.69	  	  	 	22.00	  	  	 	87,660	  
	 February
	  	 	23.80	  	  	 	23.10	  	  	 	136,878	  
	 March
	  	 	24.48	  	  	 	22.81	  	  	 	230,668	  
	 April
	  	 	23.76	  	  	 	23.10	  	  	 	217,778	  
	 May
	  	 	23.75	  	  	 	22.25	  	  	 	52,284	  
	 June
	  	 	23.29	  	  	 	21.52	  	  	 	120,918	  
	 July
	  	 	22.43	  	  	 	21.38	  	  	 	33,039	  
	 August
	  	 	21.25	  	  	 	20.25	  	  	 	31,591	  
	 September
	  	 	21.15	  	  	 	18.96	  	  	 	61,368	  
	 October
	  	 	21.00	  	  	 	19.15	  	  	 	67,754	  
	 November
	  	 	20.94	  	  	 	20.21	  	  	 	62,987	  
	 December
	  	 	20.69	  	  	 	19.20	  	  	 	82,130	  

  

													
	 Debentures – Instalment
Receipts*
	 
	 2015
	  	High($)	 	  	Low($)	 	  	Volume	 
	 January
	  				  				  			
	 February
	  				  				  			
	 March
	  				  				  			
	 April
	  				  				  			
	 May
	  				  				  			
	 June
	  				  				  			
	 July
	  				  				  			
	 August
	  				  				  			
	 September
	  	 	35.50	  	  	 	33.01	  	  	 	1,432,546	  
	 October
	  	 	36.20	  	  	 	33.35	  	  	 	1,396,630	  
	 November
	  	 	34.80	  	  	 	32.02	  	  	 	513,500	  
	 December
	  	 	35.75	  	  	 	30.55	  	  	 	941,485	  

  

	*	The Instalment Receipts commenced trading on September 28, 2015

													
	 Series F First Preferred
Shares
	 
	 2015
	  	High($)	 	  	Low($)	 	  	Volume	 
	 January
	  	 	26.00	  	  	 	24.46	  	  	 	141,646	  
	 February
	  	 	25.39	  	  	 	24.01	  	  	 	102,381	  
	 March
	  	 	25.45	  	  	 	23.53	  	  	 	243,907	  
	 April
	  	 	25.10	  	  	 	21.97	  	  	 	281,340	  
	 May
	  	 	24.70	  	  	 	22.89	  	  	 	63,771	  
	 June
	  	 	23.71	  	  	 	21.84	  	  	 	61,898	  
	 July
	  	 	23.48	  	  	 	21.03	  	  	 	120,376	  
	 August
	  	 	22.09	  	  	 	20.23	  	  	 	130,862	  
	 September
	  	 	21.20	  	  	 	17.43	  	  	 	125,078	  
	 October
	  	 	21.48	  	  	 	17.56	  	  	 	209,786	  
	 November
	  	 	21.50	  	  	 	19.78	  	  	 	230,550	  
	 December
	  	 	20.65	  	  	 	16.74	  	  	 	450,037	  

 
 

  
 Transfer Agent and Registrar 

As of December 31, 2015 Computershare acted as Emera’s transfer agent and registrar. The registers of transfers of securities of Emera were located at
Computershare’s principal offices in Vancouver, Calgary, Toronto, Montreal and Halifax. Effective March 28, 2016, Emera appointed CST to replace Computershare as Emera’s transfer agent and registrar. The registers of transfers of
securities of Emera are located at CST’s principal offices in Vancouver, Calgary, Toronto, Montreal and Halifax. 

			
	2015 Annual Information Form	  	
 55

  
  

 Directors and Officers 

Directors 
 The following information is provided for each
Director of Emera as of December 31, 2015: 
  

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

	 Sylvia D. Chrominska(4) 

Toronto, Ontario
 Canada
	  	Former Group Head of Global Human Resources and Communications for the Bank of Nova Scotia, where she had global responsibility for human resources, corporate communications, government relations, public policy and corporate social
responsibility of the Scotiabank Group. Former Chair of the Board of Scotia Group Jamaica Limited and Former Chair of the Board of Scotiabank Trinidad and Tobago Limited. A director of Wajax Corporation.	  	2010
			
	 Henry E. Demone(4)

Lunenburg, Nova Scotia
 Canada
	  	Chairman of High Liner Foods, the leading North American processor and marketer of value-added frozen seafood. Mr. Demone was President of High Liner Foods since 1989 and its President and Chief Executive Officer from 1992 to May
2015. A director of Saputo Inc.	  	2014
			
	 Allan L. Edgeworth(7) 

Calgary, Alberta
 Canada
	  	Former President of ALE Energy Inc., a private consulting company. Former President and Chief Executive Officer of Alliance Pipeline. Director of AltaGas Ltd.	  	2005
			
	 James D. Eisenhauer
 Lunenburg, Nova
Scotia
 Canada
	  	President and Chief Executive Officer of ABCO Group Limited, which has holdings in manufacturing and distribution activities. Director of NSPI since 2008 and Chair of the NSPI Board of Directors since May 2011.	  	2011
			
	 Christopher G. Huskilson
 Wellington,
Nova Scotia
 Canada
	  	President and Chief Executive Officer of Emera since November 2004. Director and former Chair of Emera Maine, Director of NSPI, Director of APUC and Chair or Director of a number of other Emera affiliated companies. Since June 1980,
Mr. Huskilson has held a number of positions within NSPI and its predecessor, Nova Scotia Power Corporation.	  	2004
			
	 J. Wayne Leonard(2)

New Orleans, Louisiana
 U.S.
	  	Former Chairman and Chief Executive Officer of Entergy Corporation, an integrated electricity producer and retail distributor. Mr. Leonard joined Entergy Corporation as President and Chief Operating Officer in 1998, becoming CEO in
1999. Mr. Leonard serves on the Boards of the Edison Electric Institute and Tidewater, Inc. He has also served on the Board of the Centre for Climate and Energy Solutions.	  	2014
			
	 B. Lynn Loewen, FCA(2)

Westmount, Quebec
 Canada
	  	President of Minogue Medical Inc. a healthcare organization which delivers innovative medical technologies to hospitals and clinics. President of Expertech Network Installation Inc. from 2008 to 2011.	  	2013
			
	 John T. McLennan (3)

Mahone Bay, Nova Scotia
 Canada
	  	Former Chair of the Board from May 2009 to May 2014. Former Board member of Chorus Aviation Inc. from January 2006 to May 2014. Former Chair of the Board of NSPI from May 2006 to May 2009. Former Vice-Chair and Chief
Executive Officer of Allstream Inc. (formerly AT&T Canada). He is presently a Director of Amdocs Ltd.	  	2005
			
	 Donald A. Pether(2)(5) 

Dundas, Ontario
 Canada
	  	Former Chair of the Board and Chief Executive Officer of ArcelorMittal Dofasco Inc., a Canadian steel producer. Director of Samuel, Son & Co. Ltd. and Schlegel Health Care Inc.	  	2008

			
	2015 Annual Information Form	  	
 56

  
  

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

	 Andrea S. Rosen(6) 

Toronto, Ontario
 Canada
	  	Former Vice-Chair of TD Bank Financial Group and President of TD Canada Trust. Director of Alberta Investment Management Corporation and Manulife Financial Corporation.	  	2007
			
	 Richard P. Sergel(3) (4)

Wellesley, Massachusetts
 U.S.
	  	Former President and Chief Executive Officer of the North American Electric Reliability Corporation (NERC). Former President and Chief Executive Officer of National Grid USA from 2000 to 2004. Also former President and
Chief Executive Officer of the New England Electric System. Presently a director of State Street Corporation. Has also served on the boards of the Edison Electric Institute and the Consortium for Energy Efficiency.	  	2010
			
	 M. Jacqueline Sheppard(8) (9) 

Calgary, Alberta
 Canada
	  	Chair of the Board since May 2014. Former Executive Vice President, Corporate and Legal of Talisman Energy Inc. Former Chair of the Research and Development Corporation of the Province of Newfoundland and Labrador, a
provincial Crown Corporation. Founder and Lead Director of Black Swan Energy Inc., an Alberta upstream energy company that is private equity financed. Founder and former Director of Marsa Energy Inc., an oil and gas corporation. Director
of Cairn Energy PLC, a publicly traded UK based international oil and gas producer. Director of the general partner of Pacific NorthWest LNG LP, which was formed for the purpose of constructing, owning and operating an LNG facility in British
Columbia.	  	2009

  

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

	(2)	Denotes member of the Audit Committee; 

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

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

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

	(6)	Denotes Chair of the Audit Committee; 

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

	(8)	Denotes Chair of the Board; 

	(9)	Denotes member of the Board of Directors of ENL. 

 As of
December 31, 2015, the Directors, in total, beneficially owned or controlled, directly or indirectly, approximately 43,439 common shares or less than 1% of the issued and outstanding shares of Emera. 

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

Audit Committee 
 The Audit Committee of Emera is composed
of the following four members, all of whom are independent Directors: Andrea S. Rosen (Chair), Donald A. Pether, J. Wayne Leonard and B. Lynn Loewen. The responsibilities and duties of the Committee are set out in the Audit Committee’s Charter,
a copy of which is attached as Appendix “A” to this AIF. 
 The Board believes that the composition of the Audit Committee reflects a high level
of financial literacy and experience. Each member of the Audit Committee has been determined by the Board to be “financially literate” as such term is defined under Canadian securities laws. The Board has made these determinations based on
the education and breadth and depth of experience of each member of the Audit Committee. The following is a description of the education and experience of each member of the Audit Committee that is relevant to the performance of his or her
responsibilities as a member of the Audit Committee: 

			
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 Andrea S. Rosen, Committee Chair 

Vice-Chair of TD Bank Financial Group and President, TD Canada Trust from 2002 to 2005. From 2001 to 2002, Executive Vice President of TD Commercial Banking
and Vice Chair TD Securities. Before joining TD Bank, was Vice President of Varity Corporation from 1991 to 1994, and worked at Wood Gundy Inc. (later CIBC-Wood Gundy) in a variety of roles from 1981 to 1990, eventually becoming Vice President and
Director. Holds a Bachelor of Laws from Osgoode Hall Law School and a Masters of Business Administration from the Schulich School of Business at York University. Received a Bachelor of Arts from Yale University. Former director and
member of the Audit Committee of Hiscox Ltd., a U.K. reporting issuer listed on the London Stock Exchange, and Director and member of the Audit Committee of Manulife Financial Corporation, an issuer listed on The Toronto Stock Exchange, New York
Stock Exchange, The Stock Exchange of Hong Kong, and the Philippine Stock Exchange. Director of Alberta Investment Management Corporation. 
 Donald
A. Pether 
 Former Chair of the Board and Chief Executive Officer of ArcelorMittal Dofasco Inc. a Canadian steel producer. Held various positions
at Dofasco, including Vice President, Commercial, Executive Vice President Dofasco Inc. & General Manager Dofasco Hamilton and President and Chief Operating Officer prior to appointment in May 2003 as President and Chief Executive Officer and
July 2006 as Chair of the Board. Was Chairman of the Board of Directors of Dofasco de Mexico S.A. de C.V., Dofasco Marion Inc., Powerlasers Limited and Powerlasers Corporation. Served on the board of directors of the International Iron and
Steel Institute, the Automotive Parts Manufacturers Association and the Canadian Steel Trade and Employment Congress. He is a Director of Samuel, Son & Co. Ltd. and Schlegel Health Care Inc., and holds a Bachelor of Science in Metallurgical
Engineering from the University of Alberta and a Doctor of Laws (Hon) from McMaster University. 
 J. Wayne Leonard 

Former Chairman and Chief Executive Officer of Entergy Corporation, an integrated electricity producer and retail distributor. Joined Entergy Corporation
as President and Chief Operating Officer in 1998, becoming CEO in 1999. From 1996 to 1997, President, Energy Commodities Strategic Business Unit and Capital & Trading Group of Cinergy Corporation, and before that its Group Vice President
and Chief Financial Officer from 1994 to 1996. Prior to that, held various senior management roles with PSI Energy, Inc., including its Senior Vice President and Chief Financial Officer from 1987 to 1994. Served as an expert witness in numerous
utility regulatory proceedings on various policies and financial issues, including, cost of capital and incentive regulation. Received Bachelor of Science, Accounting and Political Science from Ball State University in 1973. He is a
Certified Public Accountant (CPA), and obtained MBA from Indiana University in 1987. 
 B. Lynn Loewen, FCPA, FCA 

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

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

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

Auditors’ Fees 
 The aggregate fees billed by Ernst
& Young LLP, the Company’s external auditors, during the fiscal years ended December 31, 2015 and 2014 respectively, were as follows: 
  

									
	 Service Fee
	  	2015 ($)	 	  	2014 ($)	 
	 Audit Fees
	  	 	1,167,187	  	  	 	1,067,993	  
	 Audit-Related Fees
	  	 	242,568	  	  	 	303,764	  
	 Tax Fees
	  	 	544,615	  	  	 	298,531	  
	 Other
	  	 	125,000	  	  	 	38,900	  
		  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	2,079,370	  	  	 	1,709,188	  
		  	  
	  
	 	  	  
	  
	 

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

			
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 Officers 

The Officers of Emera as of December 31, 2015 were as follows: 
  

					
	Christopher G. Huskilson	 	
		
	 President and Chief Executive Officer
  

Wellington, Nova Scotia Canada
	 	President and Chief Executive Officer since November 1, 2004. From July 2003 to November 2004, Chief Operating Officer of Emera. Concurrently held the office of Chief Operating Officer of NSPI until January 2004. Prior
to 2003, actively engaged for more than five years in the affairs of NSPI in various managerial and executive capacities.
	  
 Nancy G. Tower, FCA 

 
	 	  
  

	 Chief Corporate Development Officer
  

Halifax, Nova Scotia Canada
	 	Chief Corporate Development Officer since May 2015. Before that, Executive Vice President Business Development from May 2011 to May 2015. From May 2011 to March 2014 CEO of Emera Newfoundland and Labrador. From November
2005 to May 2011, Executive Vice President and Chief Financial Officer. Prior to 2005, Vice-President Customer Operations for NSPI. From 1997 to 2000, Controller for NSPI.
		
	  
 Scott C. Balfour
(1)
  
	 	  
  

	 Executive Vice President

Chief Financial Officer
  

Halifax, Nova Scotia Canada
	 	 Executive Vice President and Chief Financial Officer since April 16, 2012. From May 2011 to April 2012, President of Ensimian
Capital Corporation. From September 2005 to January 2011, President and Chief Financial Officer of Aecon Group Inc., a Canadian publicly traded construction and infrastructure development company.

		 	  

	 	(1)	  	Effective March 1, 2016, Scott C. Balfour was appointed Chief Operating Officer, Northeast and Caribbean, Gregory W. Blunden was appointed Chief Financial Officer, and Wayne D. O’Connor was appointed Vice-President Corporate
Strategy and Planning.
		
	R. Michael Roberts	 	
		
	 Chief Human Resources Officer
  

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

 

			
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	Bruce A. Marchand	 	
		
	 Chief Compliance Officer and Chief Legal Officer
  

Halifax, Nova Scotia Canada
	 	Chief Compliance Officer since December 1, 2014. Chief Legal Officer since January 2012. Prior to January 2012, Senior Partner at the law firm of McInnes Cooper.
	  
 Daniel P. Muldoon

 
	 	  
  

	 Executive Vice-President Major Renewables and Alternative Energy

 
 Halifax, Nova Scotia Canada
	 	Executive Vice-President, Major Renewables and Alternative Energy since May 1, 2014. From June 16, 2011 to March 31, 2013, President and Chief Operating Officer, Emera Utility Services Inc. Prior to that, General Manager Engineering
& Construction, Emera.
	  
 Stephen D. Aftanas

 
	 	  
  

	 Corporate Secretary
  

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

			
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 As of December 31, 2015, the Directors and Officers, in total, beneficially owned or controlled, directly or
indirectly, approximately 71,882 common shares or less than 1% of the issued and outstanding shares of Emera.
 Certain Proceedings 

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

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

 

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

 

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

  

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

  

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

  

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

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

 No Interest of Management and Others in Material Transactions 

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

			
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 Material Contracts 

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

Material contracts entered into in connection with the TECO Transaction, namely: Instalment Receipt and Pledge Agreement, Trust Indenture, Underwriting
Agreement and Agreement and Plan of Merger, have been filed on SEDAR at www.sedar.com. 
 Experts 

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

ADDITIONAL INFORMATION 
 Additional information relating
to Emera may be found on SEDAR at www.sedar.com or upon request to the Corporate Secretary, Emera Incorporated, P.O. Box 910, Halifax, N.S., B3J 2W5, telephone (902) 428-6096 or fax (902) 428-6171. Additional information, including
Directors’ and Officers’ remuneration and indebtedness, principal holders of Emera’s securities and securities authorized for issuance under equity compensation plans, is contained in Emera’s information circular for the most
recent annual meeting of Emera’s common shareholders. Additional financial information is provided in Emera’s financial statements and MD&A for the year ended December 31, 2015. 

At any time, Emera will provide to any person upon request to the Corporate Secretary, a copy of the Emera Group of Companies’ Standards for Business
Conduct. 

			
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 Appendix “A” 

Emera Incorporated 
 Audit Committee Charter 

 

 

 PART I 

MANDATE AND RESPONSIBILITIES 

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

	•	 	the quality and integrity of Emera’s financial statements; 

  

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

  

	•	 	the internal audit and assurance process; 

  

	•	 	the qualifications, independence and performance of the external auditors; 

  

	•	 	major financial risk exposures; 

  

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

 

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

  

	1.	Financial Reporting 

  

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

 

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

 

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

  

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

  

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

	2.	External Auditors 

  

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

  

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

  

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

 

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

 

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

  

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

  

	3.	Non Audit Services 

  

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

 

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

  

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

  

	4.	Oversight and Monitoring of Audits 

  

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

  

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

  

	c)	The Committee shall discuss with the external auditor any issues that arise with Management or the internal

	 	
auditors during the course of the audit and the adequacy of Management’s responses in addressing audit-related deficiencies. 

 

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

  

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

  

	5.	Oversight and Review of Accounting Principles and Practices 

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

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

  

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

  

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

 

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

  

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

  

	f)	 any reserves, accruals, provisions, estimates or Management programs and policies, including factors that affect
asset and liability carrying values and the 

 

			
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timing of revenue and expense recognition, that may have a material effect upon the financial statements of Emera; 

 

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

  

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

  

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

 

	6.	Hiring Policies 

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

	7.	Pension Plans 

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

	8.	Oversight of Finance Matters 

  

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

 

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

  

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

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

  

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

 

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

  

	9.	Internal Controls 

 The Committee shall oversee: 

 

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

  

	b)	any material or significant weaknesses in the internal control environment; 

  

	c)	management’s compliance with the Company’s processes, procedures and internal controls; and 

  

	d)	the practices and procedures adopted to permit management’s assurance on the underlying controls in respect of the CEO/CFO certificates required under applicable securities regulations, 

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

 The Committee will carry out the following specific duties: 
  

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

  

	f)	 Review disclosures made by Emera’s Chief Executive Officer and Chief Financial Officer during their
certification process for the annual and interim filing with 

 

			
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applicable securities regulatory authorities about any significant deficiencies in the design or operation of internal controls which could adversely affect Emera’s ability to record,
process, summarize and report financial data or any material weaknesses in the internal controls, and any fraud involving management or other employees who have a significant role in the Emera’s internal controls. 

 

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

  

	10.	Internal Auditors 

  

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

  

	 	i.	approve the appointment of; 

  

	 	ii.	review the terms of engagement of; 

  

	 	iii.	be consulted with respect to the compensation payable to, and the replacement or termination of; 

 the lead
internal auditor. The Committee shall review the charter, reporting relationship, activities, staffing, organizational structure, and credentials of the internal audit department. 

 

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

  

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

  

	d)	The Committee shall annually receive and review a report from the internal auditors on executive officers’ compliance with the Company’s Standards of Business Conduct. 

 

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

  

	f)	The Committee may communicate with the internal auditors with respect to their reports and

	 	
recommendations, the extent to which prior recommendations have been implemented and any other matters that the internal auditor brings to the attention of the Committee. 

 

	g)	The Committee shall, annually or more frequently as it deems necessary, evaluate the internal auditors including their activities, organizational structure and qualifications and effectiveness. The internal
auditors shall confirm to the Committee that they are in compliance with their professional standards. 

  

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

  

	11.	Complaints 

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

	12.	Other Responsibilities 

 The Committee shall: 

 

	a)	Annually, review insurance programs; 

  

	b)	Review Management’s process for identifying non-compliance with legal and regulatory requirements. 

  

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

  

	13.	Limitation on Authority 

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

 

			
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 PART II 

COMPOSITION 
  

	14.	Composition 

  

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

  

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

  

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

  

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

 

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

PART III 
 COMMITTEE
PROCEDURE 
  

	15.	Meetings 

  

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

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

 

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

 

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

  

	16.	Separate Sessions 

  

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

  

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

 

	c)	The Committee shall meet periodically without Management present. 

  

	17.	Quorum 

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

	18.	Chair 

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

	19.	Secretary and Minutes 

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

 

			
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	20.	Board Relationships and Reporting 

 The Committee shall: 

 

	a)	Review annually the Committee’s Charter; 

  

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

  

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

  

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

 

	21.	Powers 

 The Committee shall: 
  

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

  

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

  

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

  

	22.	Experts and Advisors 

 The Committee may, in consultation with the Chairman of the Board, engage and
compensate any outside adviser that it determines necessary in order to carry out its duties.EX-4.2

 Exhibit 4.2 
  

EMERA INCORPORATED 
 Consolidated 

Financial Statements 
 December 31, 2015
and 2014 
  
  

  
 1 

 MANAGEMENT REPORT 

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

The consolidated financial statements have been prepared by management in accordance with United States Generally Accepted Accounting Principles. When alternative
accounting methods exist, management has chosen those it deems most appropriate in the circumstances. In preparation of these consolidated financial statements, estimates are sometimes necessary when transactions affecting the current accounting
period cannot be finalized with certainty until future periods. Management represents that such estimates, which have been properly reflected in the accompanying consolidated financial statements, are based on careful judgements and are within
reasonable limits of materiality. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects. Management has prepared the financial
information presented elsewhere in the annual report and has ensured that it is consistent with that in the consolidated financial statements. 
 Emera Incorporated
maintains effective systems of internal accounting and administrative controls, consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate, and that
Emera Incorporated’s assets are appropriately accounted for and adequately safeguarded. 
 The Board is responsible for ensuring that management fulfils its
responsibilities for financial reporting and is ultimately responsible for reviewing and approving the consolidated financial statements. The Board carries out this responsibility principally through its Audit Committee. 

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

The consolidated financial statements have been audited by Ernst & Young LLP, the external auditors, in accordance with Canadian Generally Accepted Auditing
Standards. Ernst & Young LLP has full and free access to the Audit Committee. 
 February 12, 2016 

 

			
	“Christopher Huskilson”	  	“Scott Balfour”
	President and Chief Executive Officer	  	Chief Financial Officer

  
 2 

 INDEPENDENT AUDITORS’ REPORT 

To the Shareholders of Emera Incorporated 
 We have audited the accompanying
consolidated financial statements of Emera Incorporated, which comprise the consolidated balance sheets as at December 31, 2015 and 2014, and the consolidated statements of income, comprehensive income, cash flows and changes in equity for the
years then ended, and a summary of significant accounting policies and other explanatory information. 
 Management’s Responsibility for the Consolidated
Financial Statements 
 Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with United
States generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or
error. 
 Auditors’ Responsibility 
 Our responsibility is to express
an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and
perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. 
 An audit involves
performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement
of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial
statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the
appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. 

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

Opinion 
 In our opinion, the consolidated financial statements present
fairly, in all material respects, the financial position of Emera Incorporated as at December 31, 2015 and 2014, and its financial performance and its cash flows for the years then ended in accordance with United States generally accepted
accounting principles. 
  

			
	Halifax, Canada	  	“Ernst & Young LLP”
	February 12, 2016	  	Chartered accountants

  
 3 

 Emera Incorporated 

Consolidated Statements of Income 
  

									
	For the	 	Year ended December 31	 
	 millions of Canadian dollars (except per share amounts)
	 	2015	 	 	2014	 
	 Operating revenues
	 				 			
	 Regulated
	 	$	2,192.9	  	 	$	2,113.1	  
	 Non-regulated
	 	 	596.4	  	 	 	825.5	  
		 	  
	  
	 	 	  
	  
	 
	 Total operating revenues
	 	 	2,789.3	  	 	 	2,938.6	  
		 	  
	  
	 	 	  
	  
	 
	 Operating expenses
	 				 			
	 Regulated fuel for generation and purchased power
	 	 	814.5	  	 	 	844.3	  
	 Regulated fuel adjustment mechanism and fixed cost deferrals (note 5)
	 	 	41.6	  	 	 	46.6	  
	 Non-regulated fuel for generation and purchased power
	 	 	335.7	  	 	 	401.1	  
	 Non-regulated direct costs
	 	 	19.5	  	 	 	31.3	  
	 Operating, maintenance and general
	 	 	666.8	  	 	 	560.8	  
	 Provincial, state, and municipal taxes
	 	 	63.6	  	 	 	58.2	  
	 Depreciation and amortization
	 	 	339.9	  	 	 	329.0	  
		 	  
	  
	 	 	  
	  
	 
	 Total operating expenses
	 	 	2,281.6	  	 	 	2,271.3	  
		 	  
	  
	 	 	  
	  
	 
	 Income from operations
	 	 	507.7	  	 	 	667.3	  
			
	 Income from equity investments (note 6)
	 	 	108.6	  	 	 	66.6	  
	 Other income (expenses), net (note 7)
	 	 	141.1	  	 	 	12.3	  
	 Interest expense, net (note 8)
	 	 	212.6	  	 	 	179.8	  
		 	  
	  
	 	 	  
	  
	 
	 Income before provision for income taxes
	 	 	544.8	  	 	 	566.4	  
			
	 Income tax expense (recovery) (note 9)
	 	 	92.4	  	 	 	113.6	  
		 	  
	  
	 	 	  
	  
	 
	 Net income
	 	 	452.4	  	 	 	452.8	  
			
	 Non-controlling interest in subsidiaries
	 	 	24.9	  	 	 	19.9	  
		 	  
	  
	 	 	  
	  
	 
	 Net income of Emera Incorporated
	 	 	427.5	  	 	 	432.9	  
			
	 Preferred stock dividends
	 	 	30.3	  	 	 	26.2	  
		 	  
	  
	 	 	  
	  
	 
	 Net income attributable to common shareholders
	 	$	397.2	  	 	$	406.7	  
		 	  
	  
	 	 	  
	  
	 
			
	 Weighted average shares of common stock outstanding (in millions)
	 				 			
		 	  
	  
	 	 	  
	  
	 
	 Basic
	 	 	145.8	  	 	 	143.2	  
		 	  
	  
	 	 	  
	  
	 
	 Diluted
	 	 	146.4	  	 	 	147.0	  
		 	  
	  
	 	 	  
	  
	 
			
	 Earnings per common share (note 10)
	 				 			
	 Basic
	 	$	2.72	  	 	$	2.84	  
		 	  
	  
	 	 	  
	  
	 
	 Diluted
	 	$	2.71	  	 	$	2.82	  
		 	  
	  
	 	 	  
	  
	 
			
	 Dividends per common share declared
	 	$	1.6625	  	 	$	1.4750	  
		 	  
	  
	 	 	  
	  
	 

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

  
 4 

 Emera Incorporated 

Consolidated Statements of Comprehensive Income 
  

									
	 For the

millions of Canadian dollars
	 	Year ended December 31	 
	 	2015	 	 	2014	 
	 Net income
	 	$	452.4	  	 	$	452.8	  
		 	  
	  
	 	 	  
	  
	 
	 Other comprehensive income (loss), net of tax
	 				 			
	 Foreign currency translation adjustment (1)
	 	 	434.6	  	 	 	165.2	  
	 Cash flow hedges
	 				 			
	 Net derivative gains (losses) (2)
	 	 	(33.5	) 	 	 	(7.7	) 
	 Less: reclassification adjustment for losses (gains) included in income (3)
	 	 	6.5	  	 	 	3.6	  
	 Net effects of cash flow hedges
	 	 	(27.0	) 	 	 	(4.1	) 
	 Unrealized gains on available-for-sale investment
	 				 			
	 Unrealized gain (loss) arising during the period
	 	 	(2.6	) 	 	 	0.2	  
	 Net unrealized holding gains (losses)
	 	 	(2.6	) 	 	 	0.2	  
	 Net change in unrecognized pension and post-retirement benefit obligation (4)
	 	 	107.1	  	 	 	(71.3	) 
	 Other comprehensive income (loss) (5)
	 	 	512.1	  	 	 	90.0	  
		 	  
	  
	 	 	  
	  
	 
	 Comprehensive income (loss)
	 	 	964.5	  	 	 	542.8	  
		 	  
	  
	 	 	  
	  
	 
	 Comprehensive income (loss) attributable to non-controlling interest
	 	 	52.8	  	 	 	31.6	  
		 	  
	  
	 	 	  
	  
	 
	 Comprehensive Income of Emera Incorporated
	 	$	911.7	  	 	$	511.2	  
		 	  
	  
	 	 	  
	  
	 

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

 

	1)	Net of tax expense of $6.6 million (2014 – $2.3 million tax expense) for the year ended December 31, 2015. 

	2)	Net of tax expense of $1.0 million (2014 – $3.7 million tax expense) for the year ended December 31, 2015. 

	3)	Net of tax recovery of $1.7 million (2014 – $0.1 million tax recovery) for the year ended December 31, 2015. 

	4)	Net of tax expense of $8.5 million (2014 – $13.6 million tax recovery) for the year ended December 31, 2015. 

	5)	Net of tax expense of $14.4 million (2014 – $7.7 million tax recovery) for the year ended December 31, 2015. 

  
 5 

 Emera Incorporated 

Consolidated Balance Sheets 
  

									
	As at	  	December 31	 
	 millions of Canadian dollars
	  	2015	 	  	2014	 
	 Assets
	  				  			
	 Current assets
	  				  			
	 Cash and cash equivalents
	  	$	1,073.4	  	  	$	221.1	  
	 Restricted cash (note 12)
	  	 	19.3	  	  	 	15.9	  
	 Receivables, net (note 13)
	  	 	578.1	  	  	 	514.2	  
	 Income taxes receivable
	  	 	12.1	  	  	 	4.8	  
	 Inventory (note 14)
	  	 	314.3	  	  	 	294.5	  
	 Derivative instruments (notes 15 and 16)
	  	 	249.5	  	  	 	136.5	  
	 Regulatory assets (notes 5 and 17)
	  	 	94.2	  	  	 	115.0	  
	 Prepaid expenses
	  	 	18.3	  	  	 	24.7	  
	 Due from related parties (note 18)
	  	 	1.6	  	  	 	3.5	  
	 Other current assets (note 19)
	  	 	234.8	  	  	 	80.6	  
		  	  
	  
	 	  	  
	  
	 
	 Total current assets
	  	 	2,595.6	  	  	 	1,410.8	  
		  	  
	  
	 	  	  
	  
	 
	 Property, plant and equipment, net of accumulated depreciation of $3,732.4 and $3,362.0, respectively
(note 20)
	  	 	6,188.0	  	  	 	5,610.2	  
		  	  
	  
	 	  	  
	  
	 
	 Other assets
	  				  			
	 Income taxes receivable
	  	 	48.7	  	  	 	28.9	  
	 Deferred income taxes (note 9)
	  	 	32.2	  	  	 	57.8	  
	 Derivative instruments (notes 15 and 16)
	  	 	167.6	  	  	 	92.0	  
	 Pension and post-retirement asset (note 21)
	  	 	8.7	  	  	 	5.9	  
	 Regulatory assets (notes 5 and 17)
	  	 	605.3	  	  	 	487.7	  
	 Net investment in direct financing lease (note 22)
	  	 	480.1	  	  	 	484.5	  
	 Investments subject to significant influence (note 6)
	  	 	1,145.3	  	  	 	1,027.6	  
	 Available-for-sale investments (note 23)
	  	 	116.0	  	  	 	84.4	  
	 Goodwill (note 24)
	  	 	264.1	  	  	 	221.5	  
	 Intangibles, net of accumulated amortization of $92.8 and $88.3,

respectively
	  	 	191.9	  	  	 	134.3	  
	 Due from related parties (note 18)
	  	 	2.5	  	  	 	2.5	  
	 Other long-term assets (note 25)
	  	 	166.3	  	  	 	205.3	  
		  	  
	  
	 	  	  
	  
	 
	 Total other assets
	  	 	3,228.7	  	  	 	2,832.4	  
		  	  
	  
	 	  	  
	  
	 
	 Total assets
	  	$	12,012.3	  	  	$	9,853.4	  
		  	  
	  
	 	  	  
	  
	 

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

  
 6 

 Emera Incorporated 

Consolidated Balance Sheets – Continued 
  

									
	As at	  	December 31	 
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 Liabilities and Equity
	  				 			
	 Current liabilities
	  				 			
	 Short-term debt (note 26)
	  	$	15.9	  	 	$	257.6	  
	 Current portion of long-term debt
	  	 	274.0	  	 	 	94.5	  
	 Accounts payable
	  	 	394.2	  	 	 	370.7	  
	 Income taxes payable
	  	 	8.1	  	 	 	33.8	  
	 Convertible debentures represented by instalment receipts (note 30)
	  	 	727.6	  	 	 	—  	  
	 Derivative instruments (notes 15 and 16)
	  	 	349.2	  	 	 	127.4	  
	 Regulatory liabilities (note 17)
	  	 	98.9	  	 	 	43.0	  
	 Pension and post-retirement liabilities (note 21)
	  	 	7.0	  	 	 	7.5	  
	 Due to related party (note 18)
	  	 	2.1	  	 	 	1.6	  
	 Other current liabilities (note 27)
	  	 	204.3	  	 	 	186.8	  
		  	  
	  
	 	 	  
	  
	 
	 Total current liabilities
	  	 	2,081.3	  	 	 	1,122.9	  
		  	  
	  
	 	 	  
	  
	 
	 Long-term liabilities
	  				 			
	 Long-term debt (note 28)
	  	 	3,750.8	  	 	 	3,660.3	  
	 Deferred income taxes (note 9)
	  	 	761.7	  	 	 	613.3	  
	 Derivative instruments (notes 15 and 16)
	  	 	96.1	  	 	 	77.4	  
	 Regulatory liabilities (note 17)
	  	 	271.7	  	 	 	158.9	  
	 Asset retirement obligations (note 29)
	  	 	114.7	  	 	 	106.2	  
	 Pension and post-retirement liabilities (note 21)
	  	 	303.4	  	 	 	360.7	  
	 Other long-term liabilities (note 31)
	  	 	298.5	  	 	 	48.3	  
		  	  
	  
	 	 	  
	  
	 
	 Total long-term liabilities
	  	 	5,596.9	  	 	 	5,025.1	  
		  	  
	  
	 	 	  
	  
	 
	 Commitments and contingencies (note 32)
	  				 			
	 Equity
	  				 			
	 Common stock, no par value, unlimited shares authorized, 147.21 million and 143.78 million shares
issued and outstanding, respectively (note 33)
	  	 	2,157.5	  	 	 	2,016.4	  
	 Cumulative preferred stock, Series A, B, C, E and F, par value $25 per share; unlimited shares authorized,
3.9 million, 2.1 million, 10 million, 5 million, and 8 million shares issued and outstanding, respectively (note 34)
	  	 	709.5	  	 	 	709.5	  
	 Contributed surplus
	  	 	28.8	  	 	 	8.8	  
	 Accumulated other comprehensive income (loss) (note 11)
	  	 	136.5	  	 	 	(347.6	) 
	 Retained earnings
	  	 	1,167.8	  	 	 	1,011.7	  
		  	  
	  
	 	 	  
	  
	 
	 Total Emera Incorporated equity
	  	 	4,200.1	  	 	 	3,398.8	  
	 Non-controlling interest in subsidiaries (note 35)
	  	 	134.0	  	 	 	306.6	  
		  	  
	  
	 	 	  
	  
	 
	 Total equity
	  	 	4,334.1	  	 	 	3,705.4	  
		  	  
	  
	 	 	  
	  
	 
	 Total liabilities and equity
	  	$	12,012.3	  	 	$	9,853.4	  
		  	  
	  
	 	 	  
	  
	 

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

Approved on behalf of the Board of Directors 
  

			
	 “M. Jacqueline Sheppard”

 
	 	 “Christopher G. Huskilson”
  

	 Chair of the Board
	 	President and Chief Executive Officer

  
 7 

 Emera Incorporated 

Consolidated Statements of Cash Flows 
  

									
	For the	 	Year ended December 31	 
	 millions of Canadian dollars
	 	2015	 	 	2014	 
	 Operating activities
	 				 			
	 Net income
	 	$	452.4	  	 	$	452.8	  
	 Adjustments to reconcile net income to net cash provided by operating activities:
	 				 			
	 Depreciation and amortization
	 	 	352.2	  	 	 	341.5	  
	 Income from equity investments, net of dividends
	 	 	(34.1	) 	 	 	4.8	  
	 Allowance for equity funds used during construction
	 	 	(2.3	) 	 	 	(9.5	) 
	 Deferred income taxes, net
	 	 	20.4	  	 	 	39.9	  
	 Net change in pension and post-retirement liabilities
	 	 	37.3	  	 	 	4.1	  
	 Regulated fuel adjustment mechanism and fixed cost deferrals
	 	 	38.8	  	 	 	40.3	  
	 Net change in fair value of derivative instruments
	 	 	95.9	  	 	 	(99.8	) 
	 Net change in regulatory assets and liabilities
	 	 	(6.3	) 	 	 	(14.5	) 
	 Net change in capitalized transportation capacity
	 	 	(133.3	) 	 	 	(40.3	) 
	 Unrealized foreign exchange gains
	 	 	(26.8	) 	 	 	—  	  
	 Other operating activities, net
	 	 	(18.4	) 	 	 	(3.0	) 
	 Changes in non-cash working capital:
	 				 			
	 Receivables, net
	 	 	(19.0	) 	 	 	54.2	  
	 Income taxes receivable
	 	 	(21.6	) 	 	 	(2.9	) 
	 Inventory
	 	 	(2.1	) 	 	 	(41.8	) 
	 Prepaid expenses
	 	 	8.4	  	 	 	0.9	  
	 Due from related party
	 	 	1.9	  	 	 	(3.5	) 
	 Other current assets
	 	 	(1.6	) 	 	 	(0.8	) 
	 Accounts payable
	 	 	(44.9	) 	 	 	(0.1	) 
	 Income taxes payable
	 	 	(31.7	) 	 	 	0.1	  
	 Other current liabilities
	 	 	9.0	  	 	 	40.1	  
		 	  
	  
	 	 	  
	  
	 
	 Net cash provided by operating activities
	 	 	674.2	  	 	 	762.5	  
		 	  
	  
	 	 	  
	  
	 
	 Investing activities
	 				 			
	 Additions to property, plant and equipment
	 	 	(369.2	) 	 	 	(433.7	) 
	 (Increase) decrease in restricted cash
	 	 	(0.7	) 	 	 	7.4	  
	 Net purchase of investments subject to significant influence, inclusive of acquisition costs
	 	 	(136.1	) 	 	 	(155.2	) 
	 Retirement spending, net of salvage
	 	 	(8.0	) 	 	 	(7.5	) 
	 Purchase of subscription receipts
	 	 	—  	  	 	 	(110.5	) 
	 Proceeds on sale of investment subject to significant influence
	 	 	282.3	  	 	 	—  	  
	 Proceeds on distribution of investment subject to significant influence
	 	 	178.7	  	 	 	—  	  
	 Additions to intangible assets
	 	 	(58.0	) 	 	 	(16.6	) 
	 Other investing activities
	 	 	(12.7	) 	 	 	5.2	  
		 	  
	  
	 	 	  
	  
	 
	 Net cash used in investing activities
	 	 	(123.7	) 	 	 	(710.9	) 
		 	  
	  
	 	 	  
	  
	 

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

  
 8 

 Emera Incorporated 

Consolidated Statements of Cash Flows – Continued 
  

									
	For the	 	Year ended December 31	 
	 millions of Canadian dollars
	 	2015	 	 	2014	 
	 Financing activities
	 				 			
	 Change in short-term debt, net
	 	 	(261.8	) 	 	 	(214.3	) 
	 Proceeds from convertible debentures represented by instalment receipts, net of issuance costs (note
30)
	 	 	681.4	  	 	 	—  	  
	 Retirement of long-term debt
	 	 	(90.2	) 	 	 	(308.9	) 
	 Proceeds from long-term debt
	 	 	446.5	  	 	 	302.2	  
	 Net borrowings (repayments) under committed credit facilities
	 	 	(201.3	) 	 	 	27.5	  
	 Issuance of common stock, net of issuance costs
	 	 	87.4	  	 	 	310.0	  
	 Issuance of preferred stock, net of issuance costs
	 	 	—  	  	 	 	193.9	  
	 Dividends on common stock
	 	 	(240.4	) 	 	 	(210.0	) 
	 Dividends on preferred stock
	 	 	(30.3	) 	 	 	(26.2	) 
	 Dividends paid by subsidiaries to non-controlling interest
	 	 	(14.1	) 	 	 	(13.5	) 
	 Redemption of preferred shares by subsidiary
	 	 	(135.0	) 	 	 	—  	  
	 Other financing activities
	 	 	(21.1	) 	 	 	(2.5	) 
		 	  
	  
	 	 	  
	  
	 
	 Net cash provided by financing activities
	 	 	221.1	  	 	 	58.2	  
		 	  
	  
	 	 	  
	  
	 
	 Effect of exchange rate changes on cash and cash equivalents
	 	 	80.7	  	 	 	10.5	  
		 	  
	  
	 	 	  
	  
	 
	 Net increase in cash and cash equivalents
	 	 	852.3	  	 	 	120.3	  
	 Cash and cash equivalents, beginning of period
	 	 	221.1	  	 	 	100.8	  
		 	  
	  
	 	 	  
	  
	 
	 Cash and cash equivalents, end of period
	 	$	1,073.4	  	 	$	221.1	  
		 	  
	  
	 	 	  
	  
	 
	 Cash and cash equivalents consists of:
	 				 			
	 Cash
	 	$	995.8	  	 	$	160.2	  
	 Short-term investments
	 	 	77.6	  	 	 	60.9	  
		 	  
	  
	 	 	  
	  
	 
	 Cash and cash equivalents
	 	$	1,073.4	  	 	$	221.1	  
		 	  
	  
	 	 	  
	  
	 
	 Supplemental disclosure of cash paid (received):
	 				 			
	 Interest
	 	$	196.4	  	 	$	184.7	  
		 	  
	  
	 	 	  
	  
	 
	 Income taxes
	 	$	124.2	  	 	$	64.8	  
		 	  
	  
	 	 	  
	  
	 

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

  
 9 

 Emera Incorporated 

Consolidated Statements of Changes in Equity 
  

																																	
	 	 	 	 	 	 	 	 	 	 	 	Accumulated	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	 	Other	 	 	 	 	 	Emera	 	 	Non-	 	 	 	 
	 	 	Common	 	 	Preferred	 	 	Contributed	 	 	Comprehensive	 	 	Retained	 	 	Total	 	 	Controlling	 	 	Total	 
	 millions of Canadian dollars
	 	Stock	 	 	Stock	 	 	Surplus	 	 	Income (“AOCI”)	 	 	Earnings	 	 	Equity	 	 	Interest	 	 	Equity	 
	 2015
	 				 				 				 				 				 				 				 			
	 Balance, December 31, 2014
	 	$	2,016.4	  	 	$	709.5	  	 	$	8.8	  	 	$	(347.6	) 	 	$	1,011.7	  	 	$	3,398.8	  	 	$	306.6	  	 	$	3,705.4	  
	 Net income of Emera Incorporated
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	427.5	  	 	 	427.5	  	 	 	24.9	  	 	 	452.4	  
	 Other comprehensive income (loss), net of tax expense of $14.4 million
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	484.2	  	 	 	—  	  	 	 	484.2	  	 	 	27.9	  	 	 	512.1	  
	 Dividends declared on preferred stock (note 34)
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(30.3	) 	 	 	(30.3	) 	 	 	—  	  	 	 	(30.3	) 
	 Dividends declared on common stock ($1.6625/share)
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(240.4	) 	 	 	(240.4	) 	 	 	—  	  	 	 	(240.4	) 
	 Dividends paid and payable by subsidiaries to non-controlling interests
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(3.1	) 	 	 	(3.1	) 
	 Common stock issued under purchase plan
	 	 	84.2	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	84.2	  	 	 	—  	  	 	 	84.2	  
	 Senior management stock options exercised
	 	 	2.3	  	 	 	—  	  	 	 	(0.2	) 	 	 	—  	  	 	 	—  	  	 	 	2.1	  	 	 	—  	  	 	 	2.1	  
	 Stock option expense
	 	 	—  	  	 	 	—  	  	 	 	1.5	  	 	 	—  	  	 	 	—  	  	 	 	1.5	  	 	 	—  	  	 	 	1.5	  
	 Employee Share Purchase Plan
	 	 	0.9	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	.	  	 	 	0.9	  	 	 	—  	  	 	 	0.9	  
	 Preferred dividends paid and payable by subsidiaries to non-controlling interests
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(11.9	) 	 	 	(11.9	) 
	 Redemption of preferred shares by subsidiary
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 				 	 	—  	  	 	 	(132.2	) 	 	 	(132.2	) 
	 Acquisition of non-controlling interest of ECI
	 	 	53.7	  	 	 	—  	  	 	 	18.9	  	 	 	—  	  	 	 	—  	  	 	 	72.6	  	 	 	(77.7	) 	 	 	(5.1	) 
	 Equity method investments
	 	 	—  	  	 	 	—  	  	 	 	(0.2	) 	 	 	(0.1	) 	 	 	(0.7	) 	 	 	(1.0	) 	 	 	—  	  	 	 	(1.0	) 
	 Other
	 	 	—  	  	 	 	—  	  	 				 				 	 	—  	  	 	 	—  	  	 	 	(0.5	) 	 	 	(0.5	) 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, December 31, 2015
	 	$	2,157.5	  	 	$	709.5	  	 	$	28.8	  	 	$	136.5	  	 	$	1,167.8	  	 	$	4,200.1	  	 	$	134.0	  	 	$	4,334.1	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

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

  
 10 

 Emera Incorporated 

Consolidated Statements of Changes in Equity – Continued 
  

																																	
	 	 	 	 	 	 	 	 	 	 	 	Accumulated	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	 	Other	 	 	 	 	 	Emera	 	 	Non-	 	 	 	 
	 	 	Common	 	 	Preferred	 	 	Contributed	 	 	Comprehensive	 	 	Retained	 	 	Total	 	 	Controlling	 	 	Total	 
	 millions of Canadian dollars
	 	Stock	 	 	Stock	 	 	Surplus	 	 	Income (“AOCI”)	 	 	Earnings	 	 	Equity	 	 	Interest	 	 	Equity	 
	 2014
	 				 				 				 				 				 				 				 			
	 Balance, December 31, 2013
	 	$	1,703.0	  	 	$	514.0	  	 	$	4.1	  	 	$	(430.1	) 	 	$	817.2	  	 	 	2,608.2	  	 	$	289.0	  	 	$	2,897.2	  
	 Net income of Emera Incorporated
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	432.9	  	 	 	432.9	  	 	 	19.9	  	 	 	452.8	  
	 Other comprehensive income (loss), net of tax recovery of $7.7 million
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	78.3	  	 	 	—  	  	 	 	78.3	  	 	 	11.7	  	 	 	90.0	  
	 Issuance of common stock, net of after-tax issuance costs
	 	 	242.8	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	242.8	  	 	 	—  	  	 	 	242.8	  
	 Dividends declared on preferred stock (note 34)
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(26.2	) 	 	 	(26.2	) 	 	 	—  	  	 	 	(26.2	) 
	 Dividends declared on common stock ($1.4750/share)
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(210.0	) 	 	 	(210.0	) 	 	 	—  	  	 	 	(210.0	) 
	 Dividends paid by subsidiaries to non-controlling interest
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(2.3	) 	 	 	(2.3	) 
	 Issuance of preferred shares, net of after-tax issuance costs
	 	 	—  	  	 	 	195.5	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	195.5	  	 	 	—  	  	 	 	195.5	  
	 Common stock issued under purchase plan
	 	 	63.6	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	63.6	  	 	 	—  	  	 	 	63.6	  
	 Senior management stock options exercised
	 	 	6.2	  	 	 	—  	  	 	 	(0.5	) 	 	 	—  	  	 	 	—  	  	 	 	5.7	  	 	 	—  	  	 	 	5.7	  
	 Stock option expense
	 	 	—  	  	 	 	—  	  	 	 	1.2	  	 	 	—  	  	 	 	—  	  	 	 	1.2	  	 	 	—  	  	 	 	1.2	  
	 Employee Share Purchase Plan
	 	 	0.8	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	0.8	  	 	 	—  	  	 	 	0.8	  
	 Preferred dividends paid by subsidiaries to non-controlling interest
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(10.7	) 	 	 	(10.7	) 
	 Equity method investments
	 	 	—  	  	 	 	—  	  	 	 	4.0	  	 	 	4.2	  	 	 	(2.2	) 	 	 	6.0	  	 	 	—  	  	 	 	6.0	  
	 Other
	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(1.0	) 	 	 	(1.0	) 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, December 31, 2014
	 	$	2,016.4	  	 	$	709.5	  	 	$	8.8	  	 	$	(347.6	) 	 	$	1,011.7	  	 	 	3,398.8	  	 	$	306.6	  	 	$	3,705.4	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

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

  
 11 

 Emera Incorporated 
 Notes to
the Consolidated Financial Statements 
 As at December 31, 2015 and 2014 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
 The significant accounting
policies for both the regulated and non-regulated operations of Emera Incorporated are as follows: 
 A. Nature of Operations 

Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and
distribution, as well as gas transmission and utility energy services. 
 Emera’s primary rate-regulated subsidiaries and investments at December 31, 2015
included the following: 
  

	 	•	 	Nova Scotia Power Inc. (“NSPI”), which is a fully integrated electric utility and the primary electricity supplier in Nova Scotia, serving approximately 506,000 customers; 

 

	 	•	 	Emera Maine provides electric transmission and distribution services to approximately 158,000 customers in the State of Maine in the United States; 

 

	 	•	 	a 95.5 per cent interest in Emera (Caribbean) Incorporated (“ECI”), the parent of The Barbados Light & Power Company Limited (“BLPC”), which is a vertically integrated utility and sole
provider of electricity on the island of Barbados, serving approximately 126,000 customers; a 49.6 per cent indirect interest, through ECI’s 51.9 per cent controlling interest, in Dominica Electricity Services Ltd.
(“Domlec”), an integrated utility on the island of Dominica, serving approximately 36,000 customers; and a 18.2 per cent indirect interest, through ECI, in St. Lucia Electricity Services Limited (“Lucelec”), which is a
vertically integrated regulated electric utility in St. Lucia; 

  

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

  

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

  

	 	•	 	Emera Newfoundland & Labrador Holdings Inc. (“ENL”), focused on two transmission investments related to the development of an 824 megawatt (“MW”) hydroelectric generating facility at Muskrat
Falls on the Lower Churchill River in Labrador, scheduled to be in service in 2017. ENL’s two investments are: 

  

	 	•	 	100 per cent interest in NSP Maritime Link Inc. (“NSPML”), which is developing the Maritime Link Project, a $1.56 billion transmission project, including two 170-kilometre sub-sea cables, between the
island of Newfoundland and Nova Scotia; 

  

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

  

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

  
 12 

 Emera Incorporated and its subsidiaries also own investments in other energy-related companies, including: 

 

	 	•	 	Emera Energy Inc. (“Emera Energy”), includes: 

  

	 	•	 	Emera Energy Services (“EES”), a physical energy business that purchases and sells natural gas and electricity and provides related energy asset management services; 

 

	 	•	 	Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating Facilities”), comprising 1,090 MW of combined-cycle gas-fired electricity generating capacity in the northeastern United States;

  

	 	•	 	Bayside Power Limited Partnership (“Bayside Power”), which is a 290 MW electricity generating facility in Saint John, New Brunswick; 

 

	 	•	 	Brooklyn Power Corporation (“Brooklyn Energy”), which is a 30 MW biomass co-generation merchant electricity facility in Brooklyn, Nova Scotia. Brooklyn Energy has a long-term purchase power agreement with
NSPI; 

  

	 	•	 	a 50.0 per cent joint venture interest in Bear Swamp Power Company LLC (“Bear Swamp”), which is a 600 MW pumped storage hydroelectric facility in northern Massachusetts; 

 

	 	•	 	a 49.0 per cent interest in Northeast Wind Partners II, LLC (“NWP”), a 419 MW portfolio of wind energy projects in the northeastern United States, which was sold on January 29, 2015;

  

	 	•	 	Emera Reinsurance Limited, which is a captive insurance company providing insurance and reinsurance to Emera and certain affiliates, to enable more cost efficient management of risk and deductible levels across Emera;

  

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

  

	 	•	 	Emera Utility Services (Bahamas) Limited (“EUS Bahamas”) provides utility construction services and plant operation services in The Bahamas; 

 

	 	•	 	a 23.4 per cent investment in Algonquin Power & Utilities Corp. (“APUC”), which is a public company traded on the Toronto Stock Exchange under the symbol “AQN”; 

 

	 	•	 	a 3.3 per cent investment in OpenHydro Group Ltd. (“Open Hydro”); 

  

	 	•	 	and other investments. 

 Pending acquisition 

On September 4, 2015, Emera entered into an Agreement and Plan of Merger pursuant to which, Emera US Inc., a wholly owned indirect subsidiary of Emera, will merge
with and into TECO Energy, Inc. (“TECO Energy”), and TECO Energy will survive the merger and become a wholly owned indirect subsidiary of Emera. TECO Energy shareholders will receive $27.55 USD per common share in cash, which represents an
aggregate purchase price of approximately $10.4 billion USD, when including assumption of approximately $3.9 billion USD of debt. 
 The closing of the acquisition,
which is expected to occur mid-2016, is subject to certain regulatory and government approvals, including approval by the New Mexico Public Regulation Commission, the Committee on Foreign Investment in the United States, and the satisfaction of
closing conditions. TECO Energy shareholder approval was received on December 3, 2015. On December 14, 2015, the New Mexico Public Regulation Commission established hearing to begin May 23, 2016 for the joint application for approval
of the change in control of New Mexico Gas Co. effected by the Transaction. On January 21, 2016, the FERC approved the Transaction. On February 8, 2016, the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, waiting period
expired. 
 TECO Energy is an energy-related holding company with regulated electric and gas utilities in Florida and New Mexico. TECO Energy’s holdings include:
Tampa Electric, an integrated regulated electric utility which serves more than 700,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution utility which serves more than 350,000 customers across Florida; and New
Mexico Gas 

  
 13 

 
Co., also a regulated gas distribution utility which serves more than 510,000 customers across New Mexico. 

B. Basis of Presentation 
 These consolidated financial statements are
prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). In the opinion of management, these consolidated financial statements include all adjustments that are of a recurring nature and
necessary to fairly state the financial position of Emera Incorporated. 
 All dollar amounts are presented in Canadian dollars, unless otherwise indicated. 

C. Principles of Consolidation 
 The consolidated financial statements of
Emera Incorporated include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity where Emera is the primary beneficiary, as discussed in Note 37. Inter-company balances and inter-company transactions
have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which
would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non-regulated operating revenues, with an offset to property, plant and equipment, regulated fuel for generation and purchased power, or
operating, maintenance and general, depending on the nature of the transaction. 
 D. Use of Management Estimates 

The preparation of consolidated financial statements in accordance with United States generally accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an
ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Significant estimates are included in
unbilled revenue, allowance for doubtful accounts, inventory, valuation of derivative instruments, capitalized overhead, depreciation, amortization, regulatory assets and regulatory liabilities (including the determination of the current portion),
income taxes (including deferred income taxes), pension and post-retirement benefits, asset retirement obligations (“AROs”), goodwill impairment assessments, valuation of investments and contingencies. Actual results may differ
significantly from these estimates. 
 E. Regulatory Matters 
 Regulatory
accounting applies where rates are established by, or subject to approval by, an independent third party regulator; are designed to recover the costs of providing the regulated products or services; and it is reasonable to assume rates are set at
levels such that the costs can be charged to and collected from customers. 
 Regulatory assets represent incurred costs that have been deferred because it is
probable that they will be recovered through future rates or tolls collected from customers. Management believes that existing regulatory assets are probable for recovery either because the Company received specific approval from the appropriate
regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income. 

  
 14 

 Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous
collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income. 
 For regulatory assets and
liabilities that are amortized, the amortization is as approved by the respective regulator. 
 F. Foreign Currency Translation 

Monetary assets and liabilities, denominated in foreign currencies, are converted to Canadian dollars at rates of exchange prevailing at the balance sheet date. The
resulting differences between the translation at the original transaction date and the balance sheet date are included in income. 
 Assets and liabilities of
self-sustaining foreign operations are translated using the exchange rates in effect at the balance sheet date and the results of operations at the average rates for the period. The resulting exchange gains and losses on the assets and liabilities
are deferred on the balance sheet in AOCI. 
 G. Revenue Recognition 

Operating revenues are recognized when electricity is delivered to customers or when products are delivered and services are rendered. Regulated revenues are recognized
on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the respective regulator and recorded based on meter readings and estimates, which occur on a systematic
basis throughout a month. At the end of each month, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The accuracy of the unbilled revenue estimate is affected by energy
demand, weather, line losses and changes in the composition of customer classes. 
 Non-regulated revenues are recorded when products have been delivered or services
have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. 
 The Company records the net investment in a lease
under the direct finance method, which consists of the sum of the minimum lease payments and residual value net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item for a
direct financing lease is recorded as unearned income at the inception of the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. 

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

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

  
 15 

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

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

Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. Total short-term investments of $77.6
million have an effective interest rate of 0.6 per cent at December 31, 2015 (2014 – $60.9 million with an effective interest rate of 1.0 per cent). 

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

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit risk assessments are conducted on all new customers and deposits are
requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis. 
 Management estimates
uncollectible accounts receivable after considering historical loss experience, current events and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate
to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. 
 M. Inventory 

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

Emission credits inventory are measured using the first-in-first-out method. Emission credits inventory is recognized in inventory when purchased, or allocated by the
respective government agency. 

  
 16 

 N. Property, Plant and Equipment 

Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”) or capitalized interest, net of
contributions received in aid of construction. 
 The cost of additions, including betterments and replacements of units of property, plant and equipment are included
in “Property, plant and equipment”. When units of regulated property, plant and equipment are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no
gain or loss reflected in income. Where a disposition of non-regulated property, plant and equipment occurs, gains and losses are included in income as the dispositions occur. 

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

The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for
non-regulated property, AROs and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and executive, along with other costs related to support functions, employee benefits,
insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have future economic benefit. 

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

Q. Intangible Assets 
 Intangible assets consist primarily of computer
software, land rights and naming rights with definite lives. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. The service lives of regulated intangible assets
require the appropriate regulatory approval. 
 The estimated useful lives, in years, for each major category of intangibles with definite lives consist of the
following: 
  

					
	 Computer software
	  	 	3 to 15	  
	 Land rights
	  	 	50 to 143	  
	 Naming rights
	  	 	1 to 24	  
		  	  
	  
	 

 The estimated average amortization for each of the next five fiscal years is as follows: 

 

																					
	 millions of Canadian dollars
	  	2016	 	  	2017	 	  	2018	 	  	2019	 	  	2020	 
	 Computer software
	  	$	12.1	  	  	$	11.9	  	  	$	11.6	  	  	$	11.3	  	  	$	11.9	  
	 Land rights
	  	 	2.0	  	  	 	2.0	  	  	 	2.0	  	  	 	2.0	  	  	 	2.0	  
	 Naming rights
	  	 	0.4	  	  	 	0.2	  	  	 	0.2	  	  	 	0.2	  	  	 	0.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	$	14.5	  	  	$	14.1	  	  	$	13.8	  	  	$	13.5	  	  	$	14.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  
 17 

 R. Asset Impairment 
 Goodwill

 Goodwill is not amortized, but is subject to an annual impairment test. Emera’s reporting units containing goodwill assess qualitative factors to determine
whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount during the fourth quarter of each year, and interim impairment tests are performed when impairment indicators are present. If it is more
likely than not that a reporting unit’s fair value is less than its carrying amount, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the
carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. 

Long-Lived Assets 
 Other long-lived assets require an impairment review when;
based on the qualitative assessment, there is more than 50 per cent likelihood that the indefinite-lived intangible asset’s fair value is less than its carrying amount. Emera bases its evaluation of other long-lived assets on the presence
of impairment indicators, such as the future economic benefit of the assets, any historical or future profitability measurements, and other external market conditions or factors. 

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

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

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

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

The Company capitalizes the external costs of obtaining debt financing and includes them as “Other assets” on the Consolidated Balance Sheets. The deferred
charge is amortized over the life of the related debt on an effective interest basis and included in “Interest expense, net” on the Consolidated Statements of Income. 

  
 18 

 T. Income Taxes and Investment Tax Credits 

Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax
returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets and their respective tax bases using enacted tax rates in effect for
the year in which the differences are expected to reverse. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. If management subsequently determines that it is likely that some or all
of a deferred income tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized. 
 Generally,
investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned by Emera Maine on regulated assets are
deferred and amortized over the estimated service lives of the related properties, as required by United State tax laws and Maine regulatory practices. 

Emera’s rate-regulated subsidiaries recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to
customers in future rates, unless specifically directed otherwise by a regulator. 
 Emera classifies interest and penalties associated with unrecognized tax benefits
as interest and operating expense, respectively. 
 U. Asset Retirement Obligations 

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

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit adjusted risk-free rate. The
amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives and governmental regulatory requirements. The present value
of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is
accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is deferred to a regulatory asset in “Property, plant
and equipment” and included in the next depreciation study. 
 Some transmission and distribution assets may have conditional AROs, which are required to be
estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control
of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined. 
 V. Derivatives and Hedging
Activities 
 Emera’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk
management policies and practices are overseen by the Board of Directors. The Company has established a number of processes and practices to identify, monitor, report on and mitigate material risks to the Company. This includes establishment of the
Enterprise Risk Management Committee, whose responsibilities include preparing and updating a “Risk Dashboard” for the Board of Directors on a quarterly basis. Furthermore, a corporate team independent from operations is responsible for
tracking and reporting on market and credit risks. 

  
 19 

 The Company manages its exposure to normal operating and market risks relating to commodity prices, foreign exchange and
interest rates through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of foreign exchange forwards and swaps, interest rate options and swaps, and coal, oil and gas futures,
options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as held-for-trading (“HFT”). Collectively, these contracts are
considered “derivatives”. 
 The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that
meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or
controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. Emera continually assesses contracts designated under the
NPNS exception and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. 
 Derivatives qualify for hedge
accounting if they meet stringent documentation requirements, and can be proven to effectively hedge the identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, the effective portion of the
change in the fair value of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Any ineffective portion of the change in the fair value of the cash flow hedges is recognized in net income
in the reporting period. 
 Where the documentation or effectiveness requirements are not met, the derivatives are recognized at fair value, with any changes in fair
value recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. 
 Derivatives entered into by NSPI and GBPC that are
documented as economic hedges, and for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The
change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes that any gains or losses resulting from
settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. 
 Derivatives
that do not meet any of the above criteria are designated as HFT derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period, unless deferred as a result of regulatory accounting. The
Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. 
 Emera classifies gains and
losses on derivatives as a component of fuel for generation and purchased power, other expenses, inventory and property, plant and equipment, depending on the nature of the item being economically hedged. Transportation capacity arising as a result
of trading and marketing transactions is recognized as an asset in “Other” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged
within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. 

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

  
 20 

 X. Fair Value Measurement 
 The
Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (refer to notes 15 and 16), and uses a market approach to do so. Fair value is the price that would be received to sell an asset or
paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect the assumptions that market participants would use in pricing an asset or
liability based on the best available information, including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. The Company uses a fair value hierarchy, based on the
relative objectivity of the inputs used to measure fair value, with Level 1 representing the highest. 
 The three levels of the fair value hierarchy are defined
as follows: 
 Level 1 Valuations – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active
markets (“quoted prices”) for identical assets and liabilities. 
 Level 2 Valuations – Where quoted prices for identical assets and liabilities
are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter
clearing houses. 
 Level 3 Valuations – Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be
valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows: 
  

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

 

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

  

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

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

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

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

Assets designated as available-for-sale are non-derivative financial assets (equity and debt securities) intended to be held for an indefinite period of time, and may be
sold in response to needs for liquidity or changes in interest rates, exchange rates or equity prices. 
 Regular purchases and sales of financial assets are
recognized at fair value, including transaction costs, on the trade date, the date on which the Company commits to purchase or sell the asset and subsequently carried at fair value based on current bid prices on the market. Unrealized gain and
losses 

  
 21 

 
arising from changes in the fair value of available-for-sale assets are recognized in AOCI until the financial asset is sold, or otherwise disposed of, or until the financial investment is
determined to be impaired, at which time the cumulative gain or loss will be included in income for the period. 
 Interest on available-for-sale debt securities is
calculated using the effective interest method and is recognized on the Consolidated Statements of Income in “Other income (expenses), net”. Dividends on available-for-sale equity securities are recognized on the Consolidated Statements of
Income in “Other income (expenses), net”. 
 2. CHANGE IN ACCOUNTING POLICY 

Business Combinations – Simplifying the Accounting for Measurement-Period Adjustments, Accounting Standard Update (“ASU”) Number (“No.”)
2015-16 
 In September 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-16, Business Combinations –Simplifying the
Accounting for Measurement-Period Adjustments. The amendment applies to entities that have reported provisional amounts related to a business combination for which the accounting is incomplete by the end of the reporting period and have an
adjustment to provisional amounts previously recognized during a later measurement period. Changes in provisional amounts recorded for acquired assets and liabilities are to be adjusted in the period the adjustment is known, with a corresponding
adjustment booked to goodwill. The acquirer is no longer required to revise comparative information from prior years for the effect of changes in provisional amounts. The Company has adopted ASU 2015-16 effective Q3 2015, with no impact on the
consolidated financial statements as a result of implementation of this standard. 
 Income Taxes – Balance Sheet Classification of Deferred Taxes, ASU
2015-17 
 In November 2015, the FASB issued ASU 2015-17, Income Taxes – Balance Sheet Classification of Deferred Taxes, which simplifies the
presentation of deferred income taxes. The amendment requires that deferred tax assets and liabilities be classified as noncurrent on the Consolidated Balance Sheets, regardless of whether the deferred income taxes are expected to be recovered
or settled within the next twelve months. ASU-2015-17 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2016. Early adoption is permitted for any interim or annual
financial statements that have not yet been issued.
 The Company has early adopted ASU 2015-17 effective December 31, 2015, and 2014 balances have been
retrospectively restated. This change decreased the current deferred income tax asset and liability by $49.2 million and $4.1 million respectively on the Consolidated Balance Sheets as at December 31, 2015 (2014 – $27.9 million and
$15.7 million respectively). As a result of the change the long-term deferred income tax asset increased by $15.2 million (2014 – $24.1 million) and the long-term deferred income tax liability decreased by $29.9 million (2014 – increased
by $11.9 million) on the Consolidated Balance Sheets as at December 31, 2015. 
 This change also reclassified a $11.9 million current deferred income tax
regulatory liability (2014 – $8.0 million) to the long-term deferred income tax regulatory asset on the Consolidated Balance Sheets as at December 31, 2015. 

Fair Value Measurement Disclosures for Investments in Certain Entities That Calculate Net Asset Value (“NAV”) per Share (or Its Equivalent), ASU
No. 2015-07 
 In May 2015, the FASB issued ASU 2015-07 removing the requirement to categorize and disclose, within the fair value hierarchy, all investments
for which fair value is measured using the net asset value per share as a practical expedient. The Company has early adopted ASU No. 2015-07 effective December 31, 2015 and 2014. The adoption of this update resulted in disclosure of all
investments for which fair value is measured using the net asset value per share methodology being disclosed outside of the fair-value hierarchy. As at December 31, 2015, total investments measured using the net asset value per share were
$672.4 million (December 31, 2014 – $635.7 million). 

  
 22 

 3. FUTURE ACCOUNTING PRONOUNCEMENTS 

Revenue from Contracts with Customers, ASU No. 2014-09 
 In May 2014, the
FASB issued ASU 2014-09, Revenue from Contracts with Customers, which creates a new, principle-based revenue recognition framework and a new topic in the Accounting Standards Codification (“ASC”), Topic 606. ASC 606 also
changes the basis for determining when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific aspects of revenue recognition and expands revenue disclosures. On July 9, 2015, the FASB deferred
the effective date by one year. This standard will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017. 

The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. 

Income Statement – Extraordinary and Unusual Items, ASU No. 2015-01 

In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items, which simplifies the income statement presentation
requirements by eliminating the concept of extraordinary items. ASU No. 2015-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an
impact on the Company’s consolidated financial statements. 
 Consolidation, ASU No. 2015-02 

In February 2015, the FASB issued ASU 2015-02, Consolidation, which changes the analysis a reporting entity must perform to determine whether it should
consolidate certain types of legal entities. All legal entities are subject to re-evaluation under the revised consolidation model. ASU No. 2015-02 is effective for fiscal years, and interim periods
within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements. 

Interest – Imputation of Interest, No. ASU 2015-03 
 In April 2015, the
FASB issued ASU 2015-03, Interest – Imputation of Interest, which simplifies the presentation of debt issuance costs. The amendments require debt issuance costs be presented in the balance sheet as a direct deduction from the
carrying amount of debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs is not affected by the amendments in the update. ASU No. 2015-03 is effective for annual
reporting periods, including interim reporting within those periods, beginning after December 15, 2015. The adoption of this update will result in the reclassification of debt issuance costs from “Other long-term assets” to
“Long-term debt” and “Convertible debentures represented by instalment receipts” on the Company’s consolidated balance sheets. As at December 31, 2015, debt issuance costs included in “Other long-term assets were
$66.8 million (December 31, 2014 – $18.8 million). 
 In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest –
Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, which clarifies that the guidance in ASU No. 2015-03 does not apply to line-of-credit arrangements. ASU No. 2015-15 permits an
entity to defer and present debt issuance costs as an asset and subsequently amortize these costs ratably over the time of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.
ASU No. 2015-15 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2015. As at December 31, 2015, debt issuance costs associated with line-of-credit arrangements
included in “Other long-term assets” were $4.0 million (December 31, 2014 – $4.1 million) on the Company’s Consolidated Balance Sheets. 

  
 23 

 Compensation – Retirement Benefits, ASU No. 2015-04 

In April 2015, the FASB issued ASU 2015-04, Compensation – Retirement Benefits, which is part of FASB’s initiative to reduce complexity in accounting
standards. This standard provides certain practical expedients for defined benefit pension or other post-retirement benefit plan measurement dates. ASU No. 2015-04 is effective for fiscal years, and interim periods within those fiscal
years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements. 

Intangibles – Goodwill and Other – Internal-Use Software, ASU No. 2015-05 

In April 2015, the FASB issued ASU 2015-05, Intangibles – Goodwill and Other – Internal-Use Software, which provides
guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement
consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for
a customer’s accounting for service contracts. ASU No. 2015-05 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on
the Company’s consolidated financial statements. 
 Technical Corrections and Improvements, ASU No. 2015-10 

In June 2015, the FASB issued ASU 2015-10, Technical Corrections and Improvements, covering a wide range of topics in the codification to correct unintended
application of guidance, or make minor improvements to the Codification that are not expected to have a significant effect on current accounting practice or create a significant administrative cost. ASU No. 2015-10 is effective for fiscal
years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this standard will not have an impact on the Company’s consolidated financial statements. 

Inventory – Simplifying the Measurement of Inventory, ASU No. 2015-11 

In July 2015, the FASB issued ASU 2015-11, Inventory – Simplifying the Measurement of Inventory. The amendments require an entity to measure
inventory at the lower of cost or net realizable value, whereas previously, inventory was measured at the lower of cost or market. ASU No. 2015-11 is effective for annual reporting periods, including interim reporting within those periods,
beginning after December 15, 2016. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. 

Financial Instruments – Recognition and Measurement of Financial Assets and Financial Liabilities, ASU No. 2016-01 

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Recognition and Measurement of Financial Assets and Financial
Liabilities. The standard provides guidance for the recognition, measurement, presentation and disclosure of financial assets and liabilities. ASU No. 2016-01 is effective for annual reporting periods, including interim reporting
within those periods, beginning after December 15, 2017. The Company is currently in the process of evaluating the impact of adoption of this standard on its consolidated financial statements. 

  
 24 

 4. SEGMENT INFORMATION 
 Emera
manages its reportable segments separately due to their different geographical, operating and regulatory environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and
total assets. 
 As at December 31, 2015, Emera has six reportable segments, specifically: 

 

	 	•	 	NSPI; 

  

	 	•	 	Emera Maine; 

  

	 	•	 	Emera Caribbean (ECI and its subsidiaries including BLPC, Domlec, GBPC, EUS Bahamas and an equity investment in Lucelec); 

  

	 	•	 	Pipelines (Brunswick Pipeline and an equity investment in M&NP); 

  

	 	•	 	Emera Energy (Emera Energy Services, New England Gas Generating Facilities, Bayside Power, Brooklyn Energy, equity investments in Bear Swamp and NWP for January 1, 2015 to January 29, 2015, when Emera sold its
interest in NWP); and 

  

	 	•	 	Corporate and Other (Emera Utility Services, ENL, Corporate, other strategic investments (including APUC) and holding companies. 

  
 25 

																																	
	 millions of Canadian dollars
	  	NSPI	 	  	Emera
Maine	 	  	Emera
Caribbean	 	  	Pipelines	 	 	Emera
Energy	 	 	Corporate
and Other	 	 	Inter-
segment
Eliminations	 	 	Total	 
	 For the year ended December 31, 2015
	  				  				  				  				 				 				 				 			
	 Operating revenues from external customers (1)
	  	$	1,417.3	  	  	$	284.1	  	  	$	442.5	  	  	$	52.1	  	 	$	578.0	  	 	$	16.1	  	 	$	(2.4	) 	 	$	2,787.7	  
	 Inter-segment revenues (1)
	  	 	—  	  	  	 	—  	  	  	 	7.5	  	  	 	—  	  	 	 	11.9	  	 	 	24.0	  	 	 	(41.8	) 	 	 	1.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total operating revenues
	  	 	1,417.3	  	  	 	284.1	  	  	 	450.0	  	  	 	52.1	  	 	 	589.9	  	 	 	40.1	  	 	 	(44.2	) 	 	 	2,789.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Allowance for funds used during construction – debt and equity
	  	 	4.5	  	  	 	1.6	  	  	 	0.1	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	6.2	  
	 Regulated fuel and fixed cost deferral adjustments
	  	 	41.6	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	41.6	  
	 Depreciation and amortization
	  	 	206.5	  	  	 	46.6	  	  	 	44.1	  	  	 	0.4	  	 	 	40.6	  	 	 	1.7	  	 	 	—  	  	 	 	339.9	  
	 Interest expense
	  	 	119.6	  	  	 	18.8	  	  	 	14.0	  	  	 	9.7	  	 	 	0.7	  	 	 	47.7	  	 	 	—  	  	 	 	210.5	  
	 Interest revenue
	  	 	4.8	  	  	 	0.4	  	  	 	—  	  	  	 	—  	  	 	 	0.7	  	 	 	0.1	  	 	 	—  	  	 	 	6.0	  
	 Internally allocated interest (2)
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	(16.5	) 	 	 	(17.7	) 	 	 	34.2	  	 	 	—  	  	 	 	—  	  
	 Income from equity investments
	  	 	—  	  	  	 	0.5	  	  	 	3.1	  	  	 	23.0	  	 	 	20.7	  	 	 	61.3	  	 	 	—  	  	 	 	108.6	  
	 Income tax expense (recovery)
	  	 	23.4	  	  	 	26.7	  	  	 	3.3	  	  	 	11.2	  	 	 	49.5	  	 	 	(21.7	) 	 	 	—  	  	 	 	92.4	  
	 Capital expenditures
	  	 	270.6	  	  	 	64.6	  	  	 	44.0	  	  	 	—  	  	 	 	98.0	  	 	 	9.5	  	 	 	—  	  	 	 	486.7	  
	 Net income attributable to common shareholders
	  	 	129.9	  	  	 	45.1	  	  	 	40.5	  	  	 	37.5	  	 	 	98.9	  	 	 	45.3	  	 	 	—  	  	 	 	397.2	  
	 As at December 31, 2015
	  				  				  				  				 				 				 	 	—  	  	 			
	 Total assets
	  	 	4,641.6	  	  	 	1,559.8	  	  	 	1,406.8	  	  	 	804.5	  	 	 	1,918.5	  	 	 	1,906.4	  	 	 	(225.3	) 	 	 	12,012.3	  
	 Investments subject to significant influence
	  	 	—  	  	  	 	12.7	  	  	 	39.4	  	  	 	188.7	  	 	 	—  	  	 	 	904.5	  	 	 	—  	  	 	 	1,145.3	  
	 Goodwill
	  	 	—  	  	  	 	158.2	  	  	 	105.5	  	  	 	—  	  	 	 	—  	  	 	 	0.4	  	 	 	—  	  	 	 	264.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 For the year ended December 31, 2014
	  				  				  				  				 				 				 				 			
	 Operating revenues from external customers (1)
	  	$	1,348.2	  	  	$	242.6	  	  	$	477.1	  	  	$	48.8	  	 	$	789.4	  	 	$	31.4	  	 	$	(3.1	) 	 	$	2,934.4	  
	 Inter-segment revenues (1)
	  	 	—  	  	  	 	—  	  	  	 	8.8	  	  	 	—  	  	 	 	11.5	  	 	 	17.3	  	 	 	(33.4	) 	 	 	4.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total operating revenues
	  	 	1,348.2	  	  	 	242.6	  	  	 	485.9	  	  	 	48.8	  	 	 	800.9	  	 	 	48.7	  	 	 	(36.5	) 	 	 	2,938.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Allowance for funds used during construction – debt and equity
	  	 	5.9	  	  	 	5.6	  	  	 	0.2	  	  	 	—  	  	 	 	—  	  	 	 	2.4	  	 	 	—  	  	 	 	14.1	  
	 Regulated fuel and fixed cost deferral adjustments
	  	 	46.6	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	46.6	  
	 Depreciation and amortization
	  	 	204.0	  	  	 	47.9	  	  	 	36.8	  	  	 	0.3	  	 	 	37.7	  	 	 	2.3	  	 	 	—  	  	 	 	329.0	  
	 Interest expense
	  	 	112.1	  	  	 	14.4	  	  	 	12.8	  	  	 	—  	  	 	 	6.3	  	 	 	30.6	  	 	 	—  	  	 	 	176.2	  
	 Interest revenue
	  	 	7.6	  	  	 	0.5	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	0.1	  	 	 	—  	  	 	 	8.2	  
	 Internally allocated interest (2)
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	(26.0	) 	 	 	—  	  	 	 	26.0	  	 	 	—  	  	 	 	—  	  
	 Gain on acquisition
	  	 	—  	  	  	 	—  	  	  	 	2.8	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	2.8	  
	 Income from equity investments
	  	 	—  	  	  	 	0.4	  	  	 	2.4	  	  	 	18.4	  	 	 	(0.9	) 	 	 	46.3	  	 	 	—  	  	 	 	66.6	  
	 Income tax expense (recovery)
	  	 	19.7	  	  	 	19.5	  	  	 	3.1	  	  	 	8.4	  	 	 	83.5	  	 	 	(20.6	) 	 	 	—  	  	 	 	113.6	  
	 Capital expenditures
	  	 	274.1	  	  	 	79.2	  	  	 	29.4	  	  	 	0.5	  	 	 	63.0	  	 	 	7.3	  	 	 	—  	  	 	 	453.5	  
	 Net income attributable to common shareholders
	  	 	124.9	  	  	 	42.4	  	  	 	28.7	  	  	 	32.7	  	 	 	185.7	  	 	 	(7.7	) 	 	 	—  	  	 	 	406.7	  
	 As at December 31, 2014
	  				  				  				  				 				 				 				 			
	 Total assets
	  	 	4,318.1	  	  	 	1,292.6	  	  	 	1,149.3	  	  	 	783.2	  	 	 	1,645.2	  	 	 	817.7	  	 	 	(152.7	) 	 	 	9,853.4	  
	 Investments subject to significant influence
	  	 	—  	  	  	 	7.6	  	  	 	31.7	  	  	 	171.8	  	 	 	237.1	  	 	 	579.4	  	 	 	—  	  	 	 	1,027.6	  
	 Goodwill
	  	 	—  	  	  	 	132.7	  	  	 	88.4	  	  	 	—  	  	 	 	—  	  	 	 	0.4	  	 	 	—  	  	 	 	221.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

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

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

  
 26 

 Geographical Information 

Revenues (1): 
  

									
	For the	  	Year ended December 31	 
	 millions of Canadian dollars
	  	2015	 	    	2014	 
	 Canada
	  	$	1,546.1	  	    	$	1,510.9	  
	 United States
	  	 	785.7	  	    	 	933.8	  
	 Barbados
	  	 	258.9	  	    	 	306.2	  
	 The Bahamas
	  	 	154.3	  	    	 	146.0	  
	 Dominica
	  	 	44.3	  	    	 	41.7	  
		  	  
	  
	 	    	  
	  
	 
		  	$	2,789.3	  	    	$	2,938.6	  
		  	  
	  
	 	    	  
	  
	 

  

	(1)	Revenues are based on country of origin of the product or service sold 

 Property Plant and Equipment: 

 

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Canada
	  	$	3,482.4	  	  	$	3,397.6	  
	 United States
	  	 	1,946.6	  	  	 	1,577.3	  
	 Barbados
	  	 	398.7	  	  	 	332.4	  
	 The Bahamas
	  	 	298.6	  	  	 	252.0	  
	 Dominica
	  	 	61.7	  	  	 	50.9	  
		  	  
	  
	 	  	  
	  
	 
		  	$	6,188.0	  	  	$	5,610.2	  
		  	  
	  
	 	  	  
	  
	 

 5. REGULATED FUEL ADJUSTMENT MECHANISM AND FIXED COST DEFERRALS 

Regulated fuel adjustment mechanism and fixed cost deferrals over (under) recovery consists of the following: 

 

									
	For the	  	Year ended December 31	 
	 millions of Canadian dollars
	  	2015	 	    	2014	 
	 Regulated fuel adjustment mechanism (see chart below)
	  	$	31.9	  	    	$	6.4	  
	 Application of non-fuel revenues
	  	 	44.7	  	    	 	40.2	  
	 Fixed cost deferral related to 2015 demand side management (“DSM”)
	  	 	(35.0	) 	    	 	—  	  
		  	  
	  
	 	    	  
	  
	 
		  	$	41.6	  	    	$	46.6	  
		  	  
	  
	 	    	  
	  
	 

 Regulated Fuel Adjustment Mechanism 
 The
regulated fuel adjustment mechanism (“FAM”) included in the Consolidated Statements of Income includes the effect of prudently incurred fuel for generation and purchased power and certain fuel related costs (“Fuel Costs”) in both
the current and preceding years, specifically, and as detailed in the table below: 
  

	 	•	 	The difference between actual Fuel Costs and amounts recovered from customers in the current year. This amount is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in
“Regulatory liabilities” on the Consolidated Balance Sheets; and 

  

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

 The regulated fuel
adjustment mechanism on the Consolidated Statements of Income consisted of the following: 

  
 27 

									
	 For the

millions of Canadian dollars
	 	Year ended December 31	 
	 	2015	 	 	2014	 
	 Over (Under) recovery of current period Fuel costs
	 	$	(24.1	) 	 	$	1.3	  
	 Recovery from (rebate to) customers of prior years’ Fuel costs
	 	 	56.0	  	 	 	—  	  
	 FAM audit disallowance
	 	 	—  	  	 	 	5.1	  
		 	  
	  
	 	 	  
	  
	 
	 Regulated fuel adjustment mechanism
	 	$	31.9	  	 	$	6.4	  
		 	  
	  
	 	 	  
	  
	 

 The deferred FAM amounts are recognized as a “Regulatory asset” or “Regulatory liability” on the Consolidated
Balance Sheets. The FAM regulatory liability balance of $28.3 million is disclosed in Note 17 and includes associated interest that is recorded as “Interest expense, net” on the Consolidated Statements of Income. 

Pursuant to the FAM Plan of Administration, NSPI’s fuel costs are subject to independent audit. On January 20, 2015, the UARB disallowed $6.0 million of 2012
and 2013 fuel-related costs, which includes interest of $0.9 million. The disallowances resulted in a reduction in the amount of the FAM deferral as at December 31, 2014 and resulted in an after-tax impact to 2014 net income of $3.3 million.

 On December 21, 2015, the UARB approved NSPI’s setting of the 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as
submitted in NSPI’s August and November 2015 filings. The recovery of these costs will begin January 1, 2016. The approved customer rates reset the base cost of fuel rate for 2016 and seek to recover $13.7 million of prior years’
unrecovered Fuel Costs in 2016. This decision results in a combined average rate decrease for customers of approximately 1 per cent. 
 On December 18,
2015, the Electricity Plan Implementation (2015) Act (the “Electricity Plan Act”) was enacted by the Province of Nova Scotia. The Electricity Plan Act requires NSPI to file a three-year rate plan for Fuel Costs in Q1 2016 and to file
a three-year general rate application to change non-fuel rates by April 30, 2016, if required by NSPI. A primary goal of the Electricity Plan Act is to provide rate stability over those years. Differences between actual Fuel Costs and amounts
recovered from customers through electricity rates during this period will be deferred to a FAM regulatory asset or liability and recovered from or returned to customers subsequent to 2019. 

The Electricity Plan Act also directs NSPI to apply non-fuel revenues in excess of NSPI’s approved range of return in 2015 and 2016 to the FAM, which will be
reserved to be applied in the 2017 to 2019 period. In addition, the financial benefit resulting from a change in the recognition of tax benefits for the South Canoe and Sable Wind Projects is to be reserved to be applied to the FAM in the 2017 to
2019 period. The exception to this direction is to apply a sufficient amount of non-fuel revenues to offset potential fuel related rate increases for certain customer classes in 2016 that would have been otherwise required. This amount totals $4.6
million. As a result, as at December 31, 2015, NSPI has deferred $4.6 million of excess non-fuel revenues to 2016 and $40.1 million of excess non-fuel revenues for the periods 2017 to 2019. 

A settlement agreement, approved by the UARB in November 2014, resulted in approximately $56.0 million of the outstanding FAM balance as at December 31, 2014 being
collected in 2015. The settlement agreement also reduced the FAM regulatory asset at the end of 2014 of $86.1 million by $38.2 million via an offset from the liability balance in the Rate Stabilization deferral account, such that at
December 31, 2014 the FAM regulatory asset was $47.9 million. 
 Through a related settlement agreement with stakeholders in December 2014, NSPI agreed to apply
non-fuel revenues above that required to achieve its approved range of return to reduce the FAM deferral account. This was effective as of January 1, 2015, and remains until the next General Rate Application (“GRA”) approval or
similar process where non-fuel rates are adjusted. This settlement agreement required NSPI to contribute a minimum of $41.3 million to the FAM deferral account by the end of 2015. As at December 31, 2015, NSPI had exceeded the minimum required
contribution through the $38.2 million in 2014 referred to above and an additional $26.4 million in 2015. In 2015, NSPI applied $44.7 

  
 28 

 
million in excess non-fuel revenues against the FAM; $18.3 million was the result of the change to South Canoe and Sable Wind Projects tax treatment. 

Regulated Fixed Cost Deferrals 
 NSPI has the following regulatory assets
arising from UARB approved fixed cost deferral mechanisms: 
 DSM Deferral 

In April 2014, the Government of Nova Scotia announced new energy efficiency legislation to remove a previous charge for conservation and efficiency programs from power
bills of Nova Scotia customers effective January 1, 2015. In addition, the legislation requires NSPI to purchase electricity efficiency and conservation activities (“Program Costs”) from EfficiencyOne, the provincially appointed
franchisee to deliver energy efficiency programs to Nova Scotians. The Program Costs were set for 2015 at $35.0 million and have been deferred as a regulatory asset and recoverable from customers over an eight-year period beginning in 2016. In
August 2015, the UARB approved a budget of $102.0 million for the three-year period of 2016 through 2018. The Electricity Plan Act has placed a cap of $34.0 million on the 2019 DSM spending. The 2016 DSM cost of $24.7 million will not be deferred. A
decision of the timing of the cost recovery for 2017 through 2019 will be made at a future date. 
 The Program Costs are recorded in “OM&G”, with an
offsetting credit in “Regulated fuel adjustment mechanism and fixed cost deferrals” on Emera’s Consolidated Income Statements, with no effect on net earnings, with the exception of interest on the balance. 

The deferred DSM amounts are recognized as a “Regulatory asset” on the Consolidated Balance Sheets. The DSM regulatory asset balance of $36.4 million is
disclosed in Note 17 and includes associated interest that is recorded as “Interest expense, net” on the Consolidated Statements of Income. 
 2013/2014
Rate Stabilization Fixed Cost Recovery Deferral 
 In December 2012, the UARB approved a deferral of recovery of certain fixed costs for fiscal 2013 and 2014 as
part of a rate stabilization plan. As previously noted above under the Regulated Fuel Adjustment Mechanism, the resulting regulatory liability at the end of 2014 of $38.2 million was applied against the FAM regulatory asset balance in 2014 and is
included in the application of non-fuel revenues line in the table above. 

  
 29 

 6. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME 

Investments subject to significant influence consisted of the following: 
  

																					
	 	  	 	 	  	 	 	  	Equity Income	 	 	 	 
	 millions of Canadian dollars
	  	Carrying Value
As at December 31	 	  	For the year ended
December 31	 	 	Percentage
of Ownership	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	 	2015	 
	 APUC (1) (2)
	  	$	503.7	  	  	$	336.4	  	  	$	36.9	  	  	$	30.4	  	 	 	23.4	  
	 LIL (3)
	  	 	208.1	  	  	 	80.1	  	  	 	9.5	  	  	 	6.4	  	 	 	55.1	  
	 M&NP (4)
	  	 	188.7	  	  	 	171.8	  	  	 	23.0	  	  	 	18.4	  	 	 	12.9	  
	 NSPML (5)
	  	 	187.6	  	  	 	159.3	  	  	 	14.9	  	  	 	9.5	  	 	 	100.0	  
	 Lucelec (4)
	  	 	39.4	  	  	 	31.7	  	  	 	3.1	  	  	 	2.4	  	 	 	18.2	  
	 Maine Electric Power Company Inc.
	  	 	7.0	  	  	 	2.9	  	  	 	0.5	  	  	 	0.4	  	 	 	21.7	  
	 Chester Static Var Compensator
	  	 	5.3	  	  	 	4.4	  	  	 	—  	  	  	 	—  	  	 	 	50.0	  
	 Cape Sharp Tidal Venture Ltd.
	  	 	5.1	  	  	 	3.6	  	  	 	—  	  	  	 	—  	  	 	 	20.0	  
	 Maine Yankee Atomic Power Company (4)
	  	 	0.4	  	  	 	0.3	  	  	 	—  	  	  	 	—  	  	 	 	12.0	  
	 Bear Swamp (6)
	  	 	—  	  	  	 	—  	  	  	 	16.4	  	  	 	16.4	  	 	 	50.0	  
	 NWP (7)
	  	 	—  	  	  	 	237.1	  	  	 	4.3	  	  	 	(17.3	) 	 	 	49.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 			
		  	$	1,145.3	  	  	$	1,027.6	  	  	$	108.6	  	  	$	66.6	  	 			
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 			

  

	(1)	As at December 31, 2015, the market price/share was $10.91 (December 31, 2014 – $9.64), which indicates a fair market value of this investment of $684.5 million (December 31, 2014 – $483.2 million). Emera
holds 50.1 million shares and 12.6 million outstanding subscription receipts and dividend equivalents as at December 31, 2015 at an average book value of $8.03 per share. Carrying value reflects a cash cost of $371.2 million, plus
non-cash gains recognized on conversion of subscriptions receipts into common shares, dilution gains or losses, and equity income or loss, less dividends received. In Q4 2015, Emera reclassified outstanding subscription receipts from “Other
long-term assets” to Investments subject to significant influence as they became eligible for conversion into APUC common shares. 

  

	(2)	Emera’s Strategic Investment Agreement with APUC and a ruling by the Maine Public Utilities (“MPUC”) limits Emera’s ownership in APUC to 25 per cent of APUC’s voting securities. The MPUC
also stipulated Emera’s dollar investment in APUC cannot exceed 5 per cent of Emera’s total assets. As at December 31, 2015, Emera is in compliance with both of these requirements. 

 

	(3)	Emera indirectly owns 100 per cent of the Class B units, which comprises 24.9 per cent of the total units issued. Emera’s share of the total partnership capital is 55.1 per cent. 

 

	(4)	Although Emera’s ownership percentage of these entities is relatively low, it is considered to have significant influence over the operating and financial decisions of these companies through Board representation.
Therefore, Emera records its investment in these entities using the equity method. This is consistent with industry practice for similar investments with significant influence. 

 

	(5)	Until Emera achieved certain critical milestones, including its financing and approvals to enable it to proceed to full construction, Emera recorded the Maritime Link Project development and engineering costs in
“Property, plant and equipment” on its Consolidated Balance Sheets. In Q2 2014, when the critical milestones were achieved, and Nalcor Energy was deemed the beneficiary of the asset for financial reporting purposes, Emera began recording
the Maritime Link Project as an equity investment, with equity earnings equal to the return on equity component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017. At that time, Emera will
record equity earnings equal to 100 per cent of NSPML net earnings. 

  

	(6)	As at December 31, 2015 and 2014, the credit investment balance has been reclassified to “Other Long-term liabilities” on the Consolidated Balance Sheets. The 2015 and 2014 carrying value has been
restated. 

  

	(7)	On January 29, 2015, Emera completed the sale of its 49 per cent interest in NWP for proceeds of $282.3 million ($223.3 million USD). 

Equity investments include a $145.0 million difference between the cost and the underlying fair value of the investees’ assets as at the date of acquisition. The
excess is attributable to goodwill. 

  
 30 

 Emera accounts for its variable interest investment in NSPML as an equity investment (note 37). NSPML’s consolidated
summarized balance sheet are illustrated as follows: 
  

									
	 As at
	 	December 31	 
	 millions of Canadian dollars
	 	2015	 	 	2014	 
	 Balance Sheet
	 				 			
	 Current assets
	 	$	438.7	  	 	$	388.4	  
	 Property, plant and equipment
	 	 	647.7	  	 	 	319.3	  
	 Non-current assets
	 	 	565.6	  	 	 	865.5	  
		 	  
	  
	 	 	  
	  
	 
	 Total assets
	 	$	1,652.0	  	 	$	1,573.2	  
		 	  
	  
	 	 	  
	  
	 
	 Current liabilities
	 	$	129.8	  	 	$	100.4	  
	 Non-current liabilities
	 	 	1,334.6	  	 	 	1,313.5	  
	 Equity
	 	 	187.6	  	 	 	159.3	  
		 	  
	  
	 	 	  
	  
	 
	 Total liabilities and equity
	 	$	1,652.0	  	 	$	1,573.2	  
		 	  
	  
	 	 	  
	  
	 

 Bear Swamp 
 As at December 31, 2015, the
investment balance in Bear Swamp was a credit of $225.0 million (2014 – credit of $20.8 million). The credit investment balance is primarily a result of distributions received in excess of the original cost and earnings. This credit investment
balance is recorded as a long-term liability on the Consolidated Balance Sheets (note 31). 
 On October 8, 2015, Bear Swamp refinanced its $125 million USD
bank debt that was due to mature in 2017 and issued $400 million USD in senior secured 10-year bonds, with $375 million USD at a fixed rate of 4.89 per cent, and $25 million USD at a floating rate of LIBOR plus 2.70 per cent. The
proceeds of this financing were used to repay existing debt and provide working capital to the joint venture, with the remainder shared equally between Emera and its joint venture partner. After fees and expenses, Emera received a $178.7
million ($137.3 million USD) non-taxable distribution in Q4 2015. 
 7. OTHER INCOME (EXPENSES), NET 

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

									
	For the	 	Year ended December 31	 
	 millions of Canadian dollars
	 	2015	 	 	2014	 
	 Foreign exchange gains (losses) and mark-to-market adjustments related to the pending TECO Energy
acquisition
	 	$	118.9	  	 	$	—  	  
	 Gain on sale of NWP investment
	 	 	18.6	  	 	 	—  	  
	 Foreign exchange gains (losses)—Other
	 	 	3.8	  	 	 	2.6	  
	 Allowance for equity funds used during construction
	 	 	2.3	  	 	 	9.5	  
	 Investment income
	 	 	1.2	  	 	 	1.6	  
	 Amortization of defeasance costs
	 	 	(6.7	) 	 	 	(7.9	) 
	 Other
	 	 	3.0	  	 	 	6.5	  
		 	  
	  
	 	 	  
	  
	 
		 	$	141.1	  	 	$	12.3	  
		 	  
	  
	 	 	  
	  
	 

  
 31 

 8. INTEREST EXPENSE, NET 

Interest expense, net consisted of the following: 
  

									
	For the	  	Year ended December 31	 
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 Interest on debt
	  	$	192.8	  	 	$	186.2	  
	 Interest on convertible debentures represented by instalment receipts
	  	 	22.7	  	 	 	—  	  
	 Allowance for borrowed funds used during construction
	  	 	(3.9	) 	 	 	(4.6	) 
	 Interest revenue
	  	 	(6.0	) 	 	 	(8.2	) 
	 Other
	  	 	7.0	  	 	 	6.4	  
		  	  
	  
	 	 	  
	  
	 
		  	$	212.6	  	 	$	179.8	  
		  	  
	  
	 	 	  
	  
	 

 9. INCOME TAXES 
 The income tax provision,
for the years ended December 31, differs from that computed using the statutory income tax rate for the following reasons: 
  

									
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 Income before provision for income taxes
	  	$	544.8	  	 	$	566.4	  
		  	  
	  
	 	 	  
	  
	 
	 Statutory income tax rate
	  	 	31.0%	  	 	 	31.0%	  
		  	  
	  
	 	 	  
	  
	 
	 Income taxes, at statutory income tax rates
	  	 	168.9	  	 	 	175.6	  
	 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities
	  	 	(31.3	) 	 	 	(33.6	) 
	 Non-taxable portion of mark-to-market gains related to pending TECO Energy acquisition
	  	 	(18.4	) 	 	 	—  	  
	 Tax effect of equity earnings
	  	 	(11.3	) 	 	 	(8.4	) 
	 Other
	  	 	(15.5	) 	 	 	(20.0	) 
		  	  
	  
	 	 	  
	  
	 
	 Income tax expense (recovery)
	  	$	92.4	  	 	$	113.6	  
		  	  
	  
	 	 	  
	  
	 
	 Effective income tax rate
	  	 	17.0%	  	 	 	20.1%	  
		  	  
	  
	 	 	  
	  
	 

 The 2015 and 2014 statutory income tax rate of 31.0 per cent represents the combined Canadian federal and Nova Scotia provincial
income tax rates, which are the relevant tax jurisdictions for Emera. 
 The following reflects the composition of taxes on income from continuing operations for the
years ended December 31: 
  

									
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 Income tax expense (recovery) – current
	  				 			
	 Domestic
	  	$	41.3	  	 	$	56.4	  
	 Foreign
	  	 	30.7	  	 	 	17.3	  
	 Income tax expense (recovery) – deferred
	  				 			
	 Domestic
	  	 	(3.8	) 	 	 	(16.7	) 
	 Foreign
	  	 	(81.7	) 	 	 	55.3	  
	 Operating loss carry forwards
	  				 			
	 Domestic
	  	 	10.5	  	 	 	35.4	  
	 Foreign
	  	 	95.4	  	 	 	(34.1	) 
		  	  
	  
	 	 	  
	  
	 
	 Income tax expense (recovery)
	  	$	92.4	  	 	$	113.6	  
		  	  
	  
	 	 	  
	  
	 

 The following reflects the composition of income before provision for income taxes for the years ended December 31, 2015. 

 

									
	 millions of Canadian dollars
	  	2015	 	  	2014	 
	 Domestic
	  	$	349.1	  	  	$	390.9	  
	 Foreign
	  	 	195.7	  	  	 	175.5	  
		  	  
	  
	 	  	  
	  
	 
	 Income before provision for income taxes
	  	$	544.8	  	  	$	566.4	  
		  	  
	  
	 	  	  
	  
	 

  
 32 

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

 

									
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 Deferred income tax assets:
	  				 			
	 Derivative instruments
	  	$	191.5	  	 	$	128.2	  
	 Pension and post-retirement liabilities
	  	 	128.9	  	 	 	156.2	  
	 Regulatory liabilities
	  	 	106.7	  	 	 	54.5	  
	 Tax loss carry forwards
	  	 	72.6	  	 	 	161.0	  
	 Asset retirement obligations
	  	 	48.7	  	 	 	45.5	  
	 Intangibles
	  	 	31.8	  	 	 	36.4	  
	 Other
	  	 	98.0	  	 	 	77.8	  
		  	  
	  
	 	 	  
	  
	 
	 Total deferred income tax assets before valuation allowance
	  	 	678.2	  	 	 	659.6	  
	 Valuation allowance
	  	 	(18.2	) 	 	 	(19.2	) 
		  	  
	  
	 	 	  
	  
	 
	 Total deferred income tax assets after valuation allowance
	  	$	660.0	  	 	$	640.4	  
		  	  
	  
	 	 	  
	  
	 
	 Deferred income tax liabilities:
	  				 			
	 Property, plant and equipment
	  	$	920.0	  	 	$	841.7	  
	 Derivative instruments
	  	 	251.2	  	 	 	176.7	  
	 Net investment in direct financing lease
	  	 	88.4	  	 	 	82.1	  
	 Other
	  	 	129.9	  	 	 	95.4	  
		  	  
	  
	 	 	  
	  
	 
	 Total deferred income tax liabilities
	  	$	1,389.5	  	 	$	1,195.9	  
		  	  
	  
	 	 	  
	  
	 
	 Consolidated Balance Sheets presentation:
	  				 			
	 Long-term deferred income tax assets
	  	 	32.2	  	 	 	57.8	  
	 Long-term deferred income tax liabilities
	  	 	(761.7	) 	 	 	(613.3	) 
		  	  
	  
	 	 	  
	  
	 
	 Net deferred income tax liabilities
	  	$	(729.5	) 	 	$	(555.5	) 
		  	  
	  
	 	 	  
	  
	 

 For regulated entities, to the extent deferred income taxes are expected to be recovered from or returned to customers in future rates,
a regulatory asset or liability is recognized, unless specifically directed otherwise by a regulator. These amounts include a gross up to reflect the income tax associated with future revenues required to fund these deferred income tax liabilities,
and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets. 
 The following table summarizes as at
December 31, 2015 the net operating loss (“NOL”), capital loss and tax credit carryovers and the associated carryover periods, and the valuation allowances for amounts which Emera has determined that realization is uncertain: 

 

																	
	 millions of Canadian dollars
	  	Deferred Tax
Asset	 	  	Valuation
Allowance	 	 	Net Deferred
Tax Asset	 	  	Expiration Period	 
	 NOL
	  	$	54.0	  	  	$	(2.7	) 	 	$	51.3	  	  	 	2016 – 2035	  
	 Capital loss
	  	 	18.6	  	  	 	(15.0	) 	 	 	3.6	  	  	 	2018 – Indefinite	  
	 Tax credit
	  	 	1.9	  	  	 	—  	  	 	 	1.9	  	  	 	2028 – Indefinite	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 

 As at December 31, 2015, Emera had a gross NOL carryover of $389.0 million (2014 – $1,074.1 million), capital
loss carryover of $88.0 million (2014 – $79.1 million), and a tax credit carryover of $25.0 million (2014 – $4.4 million). 

Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that Emera is more likely than not to
realize all recorded deferred income tax assets, except for the losses noted above and unrealized capital losses on certain investments. A valuation allowance has been recorded as at December 31, 2015 related to these losses and investments.

  
 33 

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

									
	 millions of Canadian dollars
	  	2015	 	  	2014	 
	 Balance, January 1
	  	$	4.8	  	  	$	5.2	  
	 Increases due to tax positions related to current year
	  	 	0.5	  	  	 	0.1	  
	 Increases due to tax positions related to a prior year
	  	 	0.8	  	  	 	1.7	  
	 Decreases due to tax positions related to a prior year
	  	 	—  	  	  	 	(1.2	) 
	 Decreases due to expiration of statute of limitations
	  	 	—  	  	  	 	(1.0	) 
		  	  
	  
	 	  	  
	  
	 
	 Balance, December 31
	  	$	6.1	  	  	$	4.8	  
		  	  
	  
	 	  	  
	  
	 

 The total amount of unrecognized tax benefits as at December 31, 2015 was $6.1 million (2014 – $4.8 million),
which would affect the effective tax rate if recognized. The total amount of accrued interest with respect to unrecognized tax benefits was $0.6 million (2014 – $0.8 million). No penalties have been accrued. The balance in
unrecognized tax benefits could change up to $4.9 million in the next twelve months as a result of settlements of Canada Revenue Agency (“CRA”) audits of NSPI. 

The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, US and non-US income and withholding taxes for which deferred taxes
might otherwise be required have not been provided for on a cumulative amount of temporary differences related to investments in foreign subsidiaries of approximately $669.4 million as at December 31, 2015 (2014 –
$555.4 million). It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred. 

Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, St. Lucia
and Dominica income tax returns. As at December 31, 2015, the Company’s tax years still open to examination by taxing authorities include 2006 and subsequent years. 

NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for its 2006 through 2010 taxation years. The ultimate permissibility
of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $62.3 million, including taxes and interest. NSPI has prepaid $22.7 million of the amount in dispute, as
required by CRA. 
 Should NSPI be successful in defending its position, all payments including applicable interest will be refunded with respect to NSPI’s
deductions. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the excess, if any, owing to CRA. The related tax deductions will be
available in subsequent years. 
 In Q2 2015, CRA commenced audit of NSPI’s 2011 through 2013 taxation years. Should NSPI receive notices of reassessment for
those years, and should the 2014 and 2015 taxation years be similarly reassessed, further payments will be required; however, the ultimate permissibility of the deductions is similarly not in dispute. 

NSPI and its advisors believe that NSPI has reported its tax position appropriately and NSPI is disputing the reassessments through the CRA Appeal process. The outcome
of this process is not determinable at this time. 

  
 34 

  
 10. EARNINGS
PER SHARE 
 The following table reconciles the computation of basic and diluted earnings per share: 

 

									
	For the	  	Year ended December 31	 
	 millions of Canadian dollars (except per share amounts)
	  	2015	 	  	2014	 
	 Numerator
	  				  			
	 Net income attributable to common shareholders
	  	$	397.2	  	  	$	406.7	  
	 Preferred stock dividends of subsidiary (1)
	  	 	—  	  	  	 	7.7	  
		  	  
	  
	 	  	  
	  
	 
	 Diluted numerator
	  	 	397.2	  	  	 	414.4	  
		  	  
	  
	 	  	  
	  
	 
	 Denominator
	  				  			
	 Weighted average shares of common stock outstanding
	  	 	144.9	  	  	 	142.4	  
	 Weighted average deferred share units outstanding
	  	 	0.9	  	  	 	0.8	  
		  	  
	  
	 	  	  
	  
	 
	 Weighted average shares of common stock outstanding – basic
	  	 	145.8	  	  	 	143.2	  
		  	  
	  
	 	  	  
	  
	 
	 Effect of dilutive securities (1)
	  	 	—  	  	  	 	3.5	  
	 Stock-based compensation
	  	 	0.6	  	  	 	0.3	  
		  	  
	  
	 	  	  
	  
	 
	 Weighted average shares of common stock outstanding – diluted
	  	 	146.4	  	  	 	147.0	  
		  	  
	  
	 	  	  
	  
	 
	 Earnings per common share
	  				  			
	 Basic
	  	$	2.72	  	  	$	2.84	  
		  	  
	  
	 	  	  
	  
	 
	 Diluted (1)
	  	$	2.71	  	  	$	2.82	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	On October 15, 2015, NSPI redeemed all of its outstanding Cumulative Redeemable First Preferred Shares. Therefore, the preferred shares are excluded from the calculation of diluted earnings per share as at
December 31, 2015. 

 Convertible Debentures Effect on EPS 

Following the satisfaction of all conditions precedent to the closing of the acquisition of TECO Energy, at the option of holders and provided that payment of the final
installment has been made, each Debenture will be convertible into common shares of Emera at any time after the Final Instalment Date, but prior to maturity or redemption by the Company at a conversion price of $41.85 per common share, being a
conversion rate of 23.8949 common shares per $1,000 principal amount of Debentures (note 30). Accordingly, a total of approximately 52.2 million common shares could be issued to convert the Debentures into common shares. When the conditions for
closing the acquisition are met, the Debentures will be included as a component of the Company’s diluted EPS. 

  
 35 

 11. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) 

The components of accumulated other comprehensive income are as follows: 
  

																					
	 millions of Canadian dollars
	  	(Losses) gains
on derivatives
recognized as
cash flow
hedges	 	 	Net change in
unrecognized
pension and
post-retirement
benefit costs	 	 	Net change on
available-for-sale
investments	 	 	Unrealized (loss)
gain on translation
of self-sustaining
foreign operations	 	 	Total AOCI	 
	 For the year ended December 31, 2015
	  				 				 				 				 			
	 Balance, January 1, 2015
	  	$	(7.9	) 	 	$	(424.7	) 	 	$	2.6	  	 	$	82.4	  	 	$	(347.6	) 
	 Other comprehensive income (loss) before reclassifications
	  	 	(33.5	) 	 	 	—  	  	 	 	(2.3	) 	 	 	406.5	  	 	 	370.7	  
	 Amounts reclassified from accumulated other comprehensive income loss
	  	 	6.5	  	 	 	107.1	  	 	 	—  	  	 	 	—  	  	 	 	113.6	  
	 Net current period other comprehensive income (loss)
	  	 	(27.0	) 	 	 	107.1	  	 	 	(2.3	) 	 	 	406.5	  	 	 	484.3	  
	 Other
	  	 	(0.2	) 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(0.2	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, December 31, 2015
	  	$	(35.1	) 	 	$	(317.6	) 	 	$	0.3	  	 	$	488.9	  	 	$	136.5	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
						
	 millions of Canadian dollars
	  	(Losses) gains
on derivatives
recognized as
cash flow
hedges	 	 	Net change in
unrecognized
pension and
post-retirement
benefit costs	 	 	Net change on
available-for-sale
investments	 	 	Unrealized (loss)
gain on translation
of self-sustaining
foreign operations	 	 	Total AOCI	 
	 For the year ended December 31, 2014
	  				 				 				 				 			
	 Balance, January 1, 2014
	  	$	(4.2	) 	 	$	(353.4	) 	 	$	2.4	  	 	$	(74.9	) 	 	$	(430.1	) 
	 Other comprehensive income (loss) before reclassifications
	  	 	(7.7	) 	 	 	—  	  	 	 	0.2	  	 	 	153.5	  	 	 	146.0	  
	 Amounts reclassified from accumulated other comprehensive income loss (gain)
	  	 	3.6	  	 	 	(71.3	) 	 	 	—  	  	 	 	—  	  	 	 	(67.7	) 
	 Net current period other comprehensive income (loss)
	  	 	(4.1	) 	 	 	(71.3	) 	 	 	0.2	  	 	 	153.5	  	 	 	78.3	  
	 Other
	  	 	0.4	  	 	 	—  	  	 	 	—  	  	 	 	3.8	  	 	 	4.2	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, December 31, 2014
	  	$	(7.9	) 	 	$	(424.7	) 	 	$	2.6	  	 	$	82.4	  	 	$	(347.6	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  
 36 

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

 

											
	For the	  	 	  	Year ended December 31	 
	 millions of Canadian dollars
	  	 	  	2015	 	    	2014	 
		  	Affected line item in the Consolidated Statements of Income	  	 
 	Amounts reclassified
from AOCI	  
  
		  	  
	  	  
	  
	 
	 Losses (gain) on derivatives recognized as cash flow hedges
	  		  				    			
	 Power and gas swaps
	  	Non-regulated fuel for generation and purchased power	  	$	(4.8	) 	    	$	(0.9	) 
	 Interest rate swaps
	  	Income from equity investments	  	 	0.6	  	    	 	0.5	  
	 Interest rate swaps
	  	Interest expense, net	  	 	—  	  	    	 	0.2	  
	 Foreign exchange forwards
	  	Operating revenue – regulated	  	 	9.0	  	    	 	3.7	  
		  		  	  
	  
	 	    	  
	  
	 
	 Total before tax
	  		  	 	4.8	  	    	 	3.5	  
		  	Income tax expense	  	 	1.7	  	    	 	0.1	  
		  		  	  
	  
	 	    	  
	  
	 
	 Total net of tax
	  		  	$	6.5	  	    	$	3.6	  
		  		  	  
	  
	 	    	  
	  
	 
	 Net change in unrecognized pension and post-retirement benefit costs
	  		  				    			
	 Actuarial losses (gains)
	  	OM&G	  	$	50.4	  	    	$	33.4	  
	 Past service costs (gains)
	  	OM&G	  	 	(7.1	) 	    	 	(2.5	) 
	 Amounts reclassified into obligations
	  	Pension and post-retirement benefits	  	 	72.3	  	    	 	(115.8	) 
		  		  	  
	  
	 	    	  
	  
	 
	 Total before tax
	  		  	 	115.6	  	    	 	(84.9	) 
		  		  	  
	  
	 	    	  
	  
	 
		  	Income tax expense (recovery)	  	 	(8.5	) 	    	 	13.6	  
		  		  	  
	  
	 	    	  
	  
	 
	 Total net of tax
	  		  	$	107.1	  	    	$	(71.3	) 
		  		  	  
	  
	 	    	  
	  
	 
	 Total reclassifications out of AOCI, net of tax, for the period
	  		  	$	113.6	  	    	$	(67.7	) 
		  		  	  
	  
	 	    	  
	  
	 

 12. RESTRICTED CASH 
 Restricted cash
consisted of the following: 
  

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Restricted cash – BLPC
	  	$	14.8	  	  	$	14.9	  
	 Restricted cash – Brunswick Pipeline
	  	 	3.4	  	  	 	—  	  
	 Restricted cash – Other
	  	 	1.1	  	  	 	1.0	  
		  	  
	  
	 	  	  
	  
	 
		  	$	19.3	  	  	$	15.9	  
		  	  
	  
	 	  	  
	  
	 

 13. RECEIVABLES, NET 
 Receivables, net
consisted of the following: 
  

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	 	December 31
2014	 
	 Customer accounts receivable – billed
	  	$	407.0	  	 	$	356.0	  
	 Customer accounts receivable – unbilled
	  	 	144.2	  	 	 	141.1	  
	 Total customer accounts receivable
	  	 	551.2	  	 	 	497.1	  
	 Allowance for doubtful accounts
	  	 	(12.6	) 	 	 	(11.1	) 
	 Customer accounts receivable, net
	  	 	538.6	  	 	 	486.0	  
	 Other
	  	 	39.5	  	 	 	28.2	  
		  	  
	  
	 	 	  
	  
	 
		  	$	578.1	  	 	$	514.2	  
		  	  
	  
	 	 	  
	  
	 

  
 37 

 14. INVENTORY 
 Inventory
consisted of the following: 
  

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Fuel
	  	$	185.3	  	  	$	185.7	  
	 Materials
	  	 	100.4	  	  	 	87.9	  
	 Emission credits (1)
	  	 	28.6	  	  	 	20.9	  
		  	  
	  
	 	  	  
	  
	 
		  	$	314.3	  	  	$	294.5	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	The New England Gas Generating Facilities are subject to the Acid Rain Program for sulphur dioxide emissions and the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions. In addition,
Bridgeport Energy is subject to the Clean Air Interstate Rule for ozone season nitrogen dioxide emission allowances. The emissions credits inventory balance represents the credits purchased to offset the liabilities (note 31) associated with
these programs. 

  
 38 

 15. DERIVATIVE INSTRUMENTS 

Derivative assets and liabilities relating to the foregoing categories consisted of the following: 

 

																	
	 	  	Derivative Assets	 	 	Derivative Liabilities	 
	As at	  	December 31	 	 	December 31	 
	 millions of Canadian dollars
	  	2015	 	 	2014	 	 	2015	 	 	2014	 
	 Current
	  				 				 				 			
	 Cash flow hedges
	  				 				 				 			
	 Power swaps
	  	$	7.9	  	 	$	8.4	  	 	$	0.5	  	 	$	0.5	  
	 Foreign exchange forwards
	  	 	—  	  	 	 	0.1	  	 	 	14.4	  	 	 	4.5	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	7.9	  	 	 	8.5	  	 	 	14.9	  	 	 	5.0	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	  				 				 				 			
	 Commodity swaps and forwards
	  				 				 				 			
	 Coal purchases
	  	 	—  	  	 	 	—  	  	 	 	11.7	  	 	 	5.4	  
	 Natural gas purchases and sales
	  	 	1.5	  	 	 	0.8	  	 	 	0.7	  	 	 	1.4	  
	 Heavy fuel oil purchases
	  	 	—  	  	 	 	—  	  	 	 	20.5	  	 	 	12.6	  
	 Foreign exchange forwards
	  	 	85.3	  	 	 	36.0	  	 	 	10.5	  	 	 	—  	  
	 Physical natural gas purchases and sales
	  	 	1.8	  	 	 	0.1	  	 	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	88.6	  	 	 	36.9	  	 	 	43.4	  	 	 	19.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	  				 				 				 			
	 Power swaps and physical contracts
	  	 	150.8	  	 	 	138.1	  	 	 	118.5	  	 	 	74.1	  
	 Foreign exchange options
	  	 	98.6	  	 	 	—  	  	 	 	2.1	  	 	 	—  	  
	 Natural gas swaps, futures, forwards, physical contracts
	  	 	—  	  	 	 	86.4	  	 	 	358.8	  	 	 	162.3	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	249.4	  	 	 	224.5	  	 	 	479.4	  	 	 	236.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Other derivatives
	  				 				 				 			
	 Foreign exchange forwards
	  	 	92.1	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	92.1	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total gross current derivatives
	  	 	438.0	  	 	 	269.9	  	 	 	537.7	  	 	 	260.8	  
	 Impact of master netting agreements with intent to settle net or simultaneously
	  	 	(188.5	) 	 	 	(133.4	) 	 	 	(188.5	) 	 	 	(133.4	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total current derivatives
	  	 	249.5	  	 	 	136.5	  	 	 	349.2	  	 	 	127.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Long-term
	  				 				 				 			
	 Cash flow hedges
	  				 				 				 			
	 Power swaps
	  	 	11.6	  	 	 	14.5	  	 	 	4.1	  	 	 	3.7	  
	 Foreign exchange forwards
	  	 	0.3	  	 	 	—  	  	 	 	27.2	  	 	 	10.5	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	11.9	  	 	 	14.5	  	 	 	31.3	  	 	 	14.2	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	  				 				 				 			
	 Commodity swaps and forwards
	  				 				 				 			
	 Coal purchases
	  	 	—  	  	 	 	—  	  	 	 	4.4	  	 	 	4.8	  
	 Heavy fuel oil purchases
	  	 	—  	  	 	 	—  	  	 	 	16.6	  	 	 	12.9	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Foreign exchange forwards
	  	 	121.4	  	 	 	61.5	  	 	 	—  	  	 	 	3.9	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	121.4	  	 	 	61.5	  	 	 	21.0	  	 	 	21.6	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	  				 				 				 			
	 Power swaps and physical contracts
	  	 	12.9	  	 	 	18.5	  	 	 	28.2	  	 	 	22.2	  
	 Natural gas swaps, futures, forwards and physical contracts
	  	 	72.3	  	 	 	31.7	  	 	 	62.6	  	 	 	53.6	  
	 Foreign exchange options
	  	 	0.4	  	 	 	—  	  	 	 	1.4	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	85.6	  	 	 	50.2	  	 	 	92.2	  	 	 	75.8	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Other derivatives
	  				 				 				 			
	 Interest rate swap
	  	 	—  	  	 	 	—  	  	 	 	2.9	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	—  	  	 	 	—  	  	 	 	2.9	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total gross long-term derivatives
	  	 	218.9	  	 	 	126.2	  	 	 	147.4	  	 	 	111.6	  
	 Impact of master netting agreements with intent to settle net or simultaneously
	  	 	(51.3	) 	 	 	(34.2	) 	 	 	(51.3	) 	 	 	(34.2	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total long-term derivatives
	  	 	167.6	  	 	 	92.0	  	 	 	96.1	  	 	 	77.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total derivatives
	  	$	417.1	  	 	$	228.5	  	 	$	445.3	  	 	$	204.8	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

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

  
 39 

 Details of master netting agreements, shown net on the Consolidated Balance Sheets, are summarized in the following table:

  

																	
	 	  	Derivative Assets	 	  	Derivative Liabilities	 
	As at	  	December 31	 	  	December 31	 
	 millions of Canadian dollars
	  	2015	 	  	2014	 	  	2015	 	    	2014	 
	 Regulatory deferral
	  	$	0.1	  	  	$	0.7	  	  	$	0.1	  	    	$	0.7	  
	 HFT derivatives
	  	 	239.7	  	  	 	166.9	  	  	 	239.7	  	    	 	166.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	    	  
	  
	 
	 Total impact of master netting agreements with intent to settle net or simultaneously
	  	$	239.8	  	  	$	167.6	  	  	$	239.8	  	    	$	167.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	    	  
	  
	 

 Cash Flow Hedges 
 The Company enters into
various derivatives designated as cash flow hedges. Emera enters into power swaps to limit Bear Swamp’s exposure to purchased power prices. Emera also enters into interest rate swaps to fix Bear Swamp’s cost of debt. The Company also
enters into foreign exchange forwards to hedge the currency risk for revenue streams denominated in foreign currency for Brunswick Pipeline. 
 As previously noted,
the effective portion of the change in fair value of these derivatives is included in AOCI, until the hedged transactions are recognized in income. The ineffective portion is recognized in income of the period. The amounts related to cash flow
hedges recorded in income and AOCI consisted of the following: 
  

																									
	For the	  	Year ended December 31	 
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 	  	Power
swaps	 	 	Interest
rate
swaps	 	 	Foreign
exchange
forwards	 	 	Power
swaps	 	  	Interest
rate
swaps	 	 	Foreign
exchange
forwards	 
	 Unrealized gain (loss) in non-regulated fuel for generation and purchased power – ineffective
portion
	  	$	(0.1	) 	 	$	—  	  	 	$	—  	  	 	$	2.7	  	  	$	—  	  	 	$	—  	  
	 Realized gain (loss) in non-regulated fuel for generation and purchased power
	  	 	4.8	  	 	 	—  	  	 	 	—  	  	 	 	0.9	  	  	 	—  	  	 	 	—  	  
	 Realized gain (loss) in operating revenue – Regulated
	  	 	—  	  	 	 	—  	  	 	 	(9.0	) 	 	 	—  	  	  	 	—  	  	 	 	(3.7	) 
	 Realized gain (loss) in income from equity investments
	  	 	—  	  	 	 	(0.6	) 	 	 	—  	  	 	 	—  	  	  	 	(0.5	) 	 	 	—  	  
	 Realized gain (loss) in interest expense, net
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	  	 	(0.2	) 	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Total gains (losses) in Net income
	  	$	4.7	  	 	$	(0.6	) 	 	$	(9.0	) 	 	$	3.6	  	  	$	(0.7	) 	 	$	(3.7	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		
	As at	  	December 31	 
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 	  	Power
swaps	 	 	Interest
rate
swaps	 	 	Foreign
exchange
forwards	 	 	Power
swaps	 	  	Interest
rate
swaps	 	 	Foreign
exchange
forwards	 
	 Total unrealized gain (loss) in AOCI – effective portion, net of tax
	  	$	3.5	  	 	$	(1.1	) 	 	$	(41.7	) 	 	$	5.2	  	  	$	(1.4	) 	 	$	(14.9	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 

 The Company expects $13.3 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve
months, as the underlying hedged transactions settle. 

  
 40 

 As at December 31, 2015, the Company had the following notional volumes of outstanding derivatives designated as cash
flow hedges that are expected to settle as outlined below: 
  

																					
	 millions
	  	2016	 	  	2017	 	  	2018	 	  	2019	 	  	2020	 
	 Power swaps (megawatt hours (“MWh”)) purchases
	  	 	0.3	  	  	 	0.3	  	  	 	0.3	  	  	 	0.3	  	  	 	0.3	  
	 Foreign exchange forwards (USD) sales
	  	$	53.4	  	  	$	53.4	  	  	$	44.8	  	  	$	30.0	  	  	$	30.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Foreign exchange forwards (EURO) purchases
	  	 	—  	  	  	 	2.6	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Regulatory Deferral 
 As previously noted,
NSPI and GBPC defer gains and losses on certain derivatives documented as economic hedges, including certain physical contracts that do not qualify for the NPNS exemption. 

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

 

																									
	For the	  	Year ended December 31	 
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 	  	Commodity
swaps and
forwards	 	 	Physical
natural gas
purchases
and sales	 	 	Foreign
exchange
forwards	 	 	Commodity
swaps and
forwards	 	 	Physical
natural gas
purchases
and sales	 	 	Foreign
exchange
forwards	 
	 Unrealized gain (loss) in regulatory assets
	  	$	(24.0	) 	 	$	—  	  	 	$	(7.0	) 	 	$	14.3	  	 	$	—  	  	 	$	(4.6	) 
	 Unrealized gain (loss) in regulatory liabilities
	  	 	1.4	  	 	 	8.8	  	 	 	172.7	  	 	 	7.8	  	 	 	2.4	  	 	 	75.9	  
	 Realized (gain) loss in regulatory assets
	  	 	(3.3	) 	 	 	—  	  	 	 	—  	  	 	 	3.3	  	 	 	—  	  	 	 	—  	  
	 Realized (gain) loss in property, plant and equipment
	  	 	—  	  	 	 	—  	  	 	 	(1.0	) 	 	 	—  	  	 	 	—  	  	 	 	(0.1	) 
	 Realized (gain) loss in inventory (1)
	  	 	11.5	  	 	 	—  	  	 	 	(43.9	) 	 	 	4.3	  	 	 	—  	  	 	 	(16.3	) 
	 Realized (gain) loss in regulated fuel for generation and purchased power (2)
	  	 	(15.9	) 	 	 	(7.1	) 	 	 	(18.2	) 	 	 	(9.7	) 	 	 	(2.3	) 	 	 	(5.7	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total change derivative instruments
	  	$	(30.3	) 	 	$	1.7	  	 	$	102.6	  	 	$	20.0	  	 	$	0.1	  	 	$	49.2	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	(1)	Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed. 

	(2)	Realized (gains) losses on derivative instruments settled and consumed in the period; hedging relationships that have been terminated or the hedged transaction is no longer probable. 

Commodity Swaps and Forwards 
 As at December 31, 2015, the Company had
the following notional volumes of commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below: 
  

													
	 	  	2016	 	  	2017	 	  	2018	 
	 millions
	  	Purchases	 	  	Purchases	 	  	Purchases	 
	 Coal (metric tonnes)
	  	 	0.3	  	  	 	0.7	  	  	 	0.7	  
	 Natural Gas (mmbtu)
	  	 	3.2	  	  	 	—  	  	  	 	—  	  
	 Heavy fuel oil (bbls)
	  	 	0.4	  	  	 	0.2	  	  	 	0.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  
 41 

 Foreign Exchange Swaps and Forwards 

As at December 31, 2015, the Company had the following notional volumes of foreign exchange swaps and forward contracts related to commodity contracts that are
expected to settle as outlined below: 
  

																	
	 	 	2016	 	 	2017	 	 	2018	 	 	2019	 
	 Fuel purchases exposure (millions of US dollars)
	 	$	200.4	  	 	$	222.3	  	 	$	143.0	  	 	$	96.5	  
	 Weighted average rate
	 	 	1.0257	  	 	 	1.0707	  	 	 	1.1053	  	 	 	1.1265	  
	 % of USD requirements
	 	 	79	% 	 	 	93	% 	 	 	68	% 	 	 	46	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 Held-for-Trading Derivatives 
 In the ordinary
course of its business, Emera enters into physical contracts for the purchase and sale of natural gas, as well as power and natural gas swaps, forwards and futures to economically hedge those physical contracts. These derivatives are all considered
HFT. 
 The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives: 

 

									
	 For the
 millions of Canadian dollars
	 	Year ended December 31	 
	 	2015	 	 	2014	 
	 Power swaps and physical contracts in non-regulated operating revenues
	 	$	9.8	  	 	$	6.4	  
	 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues
	 	 	4.6	  	 	 	264.0	  
	 Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and
purchased power
	 	 	(3.1	) 	 	 	(5.2	) 
	 Foreign exchange options in other income (expenses), net
	 	 	(0.8	) 	 	 	—  	  
		 	  
	  
	 	 	  
	  
	 
		 	$	10.5	  	 	$	265.2	  
		 	  
	  
	 	 	  
	  
	 

 As at December 31, 2015, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle
as outlined below: 
  

																					
	 millions
	 	2016	 	 	2017	 	 	2018	 	 	2019	 	 	2020	 
	 Natural gas purchases (Mmbtu)
	 	 	211.3	  	 	 	65.5	  	 	 	49.9	  	 	 	43.9	  	 	 	43.9	  
	 Natural gas sales (Mmbtu)
	 	 	151.0	  	 	 	35.1	  	 	 	5.4	  	 	 	5.1	  	 	 	4.4	  
	 Power purchases (MWh)
	 	 	1.6	  	 	 	0.6	  	 	 	0.6	  	 	 	0.6	  	 	 	0.6	  
	 Power sales (MWh)
	 	 	2.7	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Foreign exchange options (USD)
	 	$	20.3	  	 	$	12.5	  	 	$	4.1	  	 	 	—  	  	 	 	—  	  
	 Foreign exchange forwards (EURO) purchases
	 	 	—  	  	 	 	—  	  	 	 	0.2	  	 	 	—  	  	 	 	—  	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

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

																	
	 For the

millions of Canadian dollars
	 	Year ended December 31	 
	 	2015	 	 	2014	 
	 	 	Interest
rate
swaps	 	 	Foreign
exchange
forwards	 	 	Interest
rate
swaps	 	 	Foreign
exchange
forwards	 
	 Unrealized gain (loss) in other income (expense)
	 	$	 	  	 	$	92.1	  	 	$	—  	  	 	$	—  	  
	 Unrealized gain (loss) in interest expense, net
	 	 	(2.9	) 	 	 	—  	  	 	 	—  	  	 	 	—  	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total gains (losses) in net income
	 	$	(2.9	) 	 	$	92.1	  	 	$	—  	  	 	$	—  	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  
 42 

 As at December 31, 2015, the Company had interest rate swaps in place for the $250 million non-revolving term
credit facility in Brunswick Pipeline for interest payments until the debt matures in 2019. 
 As at December 31, 2015, the Company had a foreign exchange
forwards in place for $1,121.7 million USD in 2016 to economically hedge the anticipated proceeds from the Debenture Offering for the pending TECO Energy acquisition. 

Credit Risk 
 The Company is exposed to credit risk with respect to amounts
receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for
counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high risk accounts. 

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

As at December 31, 2015, the maximum exposure the Company has to credit risk is $901.0 million (2014 – $707.3 million), which includes accounts
receivable net of collateral/deposits and assets related to derivatives. 
 It is possible that volatility in commodity prices could cause the Company to have
material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as
part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of
the credit limit where contractually required. The total cash deposits/collateral on hand as at December 31, 2015 was $94.2 million (2014 – $55.3 million), which mitigates the Company’s maximum credit risk exposure. The
Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company. 

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company
generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute agreements. The Company believes that
entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default. 
 As at
December 31, 2015, the Company had $83.2 million (2014 – $79.9 million) in financial assets, considered to be past due, which have been outstanding for an average 80.5 days. The fair value of these financial assets is
$71.5 million (2014 – $70.3 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric revenue. 

  
 43 

 Concentration Risk 
 The
Company’s concentrations of risk consisted of the following: 
  

																	
	 As at
	 	December 31, 2015	 	 	December 31, 2014	 
	 	 	millions of
Canadian
dollars	 	 	% of total
exposure	 	 	millions of
Canadian
dollars	 	 	% of total
exposure	 
	 Receivables, net
	 				 				 				 			
	 Regulated utilities
	 				 				 				 			
	 Residential
	 	$	189.3	  	 	 	20	% 	 	$	195.1	  	 	 	26	% 
	 Commercial
	 	 	102.4	  	 	 	10	% 	 	 	104.1	  	 	 	14	% 
	 Industrial
	 	 	29.2	  	 	 	3	% 	 	 	26.3	  	 	 	4	% 
	 Other
	 	 	52.8	  	 	 	5	% 	 	 	39.7	  	 	 	5	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	373.7	  	 	 	38	% 	 	 	365.2	  	 	 	49	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Trading group
	 				 				 				 			
	 Credit rating of A- or above
	 	 	31.4	  	 	 	3	% 	 	 	13.5	  	 	 	2	% 
	 Credit rating of BBB- to BBB+
	 	 	22.1	  	 	 	2	% 	 	 	29.0	  	 	 	4	% 
	 Not rated
	 	 	30.8	  	 	 	3	% 	 	 	44.8	  	 	 	6	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	84.3	  	 	 	8	% 	 	 	87.3	  	 	 	12	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Other accounts receivable
	 	 	120.1	  	 	 	12	% 	 	 	61.7	  	 	 	8	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	578.1	  	 	 	58	% 	 	 	514.2	  	 	 	69	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Derivative Instruments (current and long-term)
	 				 				 				 			
	 Credit rating of A- or above
	 	 	340.1	  	 	 	34	% 	 	 	203.2	  	 	 	27	% 
	 Credit rating of BBB- to BBB+
	 	 	69.4	  	 	 	7	% 	 	 	14.1	  	 	 	2	% 
	 Not rated
	 	 	7.6	  	 	 	1	% 	 	 	11.2	  	 	 	2	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	417.1	  	 	 	42	% 	 	 	228.5	  	 	 	31	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	$	995.2	  	 	 	100	% 	 	$	742.7	  	 	 	100	% 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 Cash Collateral 
 Derivatives, as reflected on
the Consolidated Balance Sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are
recognized in “Accounts payable”. 
 The Company’s cash collateral positions consisted of the following: 

 

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Cash collateral provided to others
	  	$	106.9	  	  	$	45.8	  
	 Cash collateral received from others
	  	 	28.5	  	  	 	2.9	  
		  	  
	  
	 	  	  
	  
	 

 Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured
credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a
material adverse event resulted in the senior unsecured debt to fall below investment grade, the counterparties to such derivatives could request ongoing full collateralization. 

As at December 31, 2015, the total fair value of these derivatives, in a liability position, was $445.3 million (December 31, 2014 – $204.8
million). If the credit ratings of the Company were reduced below investment grade the full value of the net liability position could be required to be posted as collateral for these derivatives. 

  
 44 

 16. FAIR VALUE MEASUREMENTS 
 The
following tables set out the classification of the methodology used by the Company to fair value its derivatives: 
  

																	
	As at	 	December 31, 2015	 
	 millions of Canadian dollars
	 	Level 1	 	 	Level 2	 	 	Level 3	 	 	Total	 
	 Assets
	 				 				 				 			
	 Cash flow hedges
	 				 				 				 			
	 Power swaps
	 	$	19.5	  	 	$	—  	  	 	$	—  	  	 	$	19.5	  
	 Foreign exchange forwards
	 	 	—  	  	 	 	0.3	  	 	 	—  	  	 	 	0.3	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	19.5	  	 	 	0.3	  	 	 	—  	  	 	 	19.8	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	 				 				 				 			
	 Commodity swaps and forwards
	 				 				 				 			
	 Coal purchases
	 	 	—  	  	 	 	1.4	  	 	 	—  	  	 	 	1.4	  
	 Foreign exchange forwards
	 	 	—  	  	 	 	206.7	  	 	 	—  	  	 	 	206.7	  
	 Physical natural gas purchases and sales
	 	 	—  	  	 	 	—  	  	 	 	1.8	  	 	 	1.8	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	—  	  	 	 	208.1	  	 	 	1.8	  	 	 	209.9	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	 				 				 				 			
	 Power swaps and physical contracts
	 	 	38.3	  	 	 	—  	  	 	 	(7.8	) 	 	 	30.5	  
	 Foreign exchange options
	 	 	—  	  	 	 	0.4	  	 	 	—  	  	 	 	0.4	  
	 Natural gas swaps, futures, forwards, physical contracts and related transportation
	 	 	(0.3	) 	 	 	7.9	  	 	 	56.8	  	 	 	64.4	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	38.0	  	 	 	8.3	  	 	 	49.0	  	 	 	95.3	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Other derivatives
	 				 				 				 			
	 Foreign exchange forwards
	 	 	—  	  	 	 	92.1	  	 	 	—  	  	 	 	92.1	  
		 	 	—  	  	 	 	92.1	  	 	 	—  	  	 	 	92.1	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total assets
	 	 	57.5	  	 	 	308.8	  	 	 	50.8	  	 	 	417.1	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Liabilities
	 				 				 				 			
	 Cash flow hedges
	 				 				 				 			
	 Power swaps
	 	 	4.6	  	 	 	—  	  	 	 	—  	  	 	 	4.6	  
	 Foreign exchange forwards
	 	 	—  	  	 	 	41.6	  	 	 	—  	  	 	 	41.6	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	4.6	  	 	 	41.6	  	 	 	—  	  	 	 	46.2	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	 				 				 				 			
	 Commodity swaps and forwards
	 				 				 				 			
	 Coal purchases
	 	 	—  	  	 	 	16.1	  	 	 	—  	  	 	 	16.1	  
	 Heavy fuel oil purchases
	 	 	—  	  	 	 	37.1	  	 				 	 	37.1	  
	 Natural gas purchases and sales
	 	 	0.6	  	 	 	—  	  	 	 	—  	  	 	 	0.6	  
	 Foreign exchange forwards
	 				 	 	10.5	  	 	 	—  	  	 	 	10.5	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	0.6	  	 	 	63.7	  	 	 	—  	  	 	 	64.3	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	 				 				 				 			
	 Power swaps and physical contracts
	 	 	15.2	  	 	 	—  	  	 	 	(2.0	) 	 	 	13.2	  
	 Foreign exchange options
	 	 	—  	  	 	 	3.5	  	 	 	—  	  	 	 	3.5	  
	 Natural gas swaps, futures, forwards and physical contracts
	 	 	14.4	  	 	 	22.0	  	 	 	278.8	  	 	 	315.2	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	29.6	  	 	 	25.5	  	 	 	276.8	  	 	 	331.9	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Other derivatives
	 				 				 				 			
	 Interest rate swap
	 	 	—  	  	 	 	2.9	  	 	 	—  	  	 	 	2.9	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	 	—  	  	 	 	2.9	  	 	 	—  	  	 	 	2.9	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total liabilities
	 	 	34.8	  	 	 	133.7	  	 	 	276.8	  	 	 	445.3	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net assets (liabilities)
	 	$	22.7	  	 	$	175.1	  	 	$	(226.0	) 	 	$	(28.2	) 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  
 45 

																	
	 As at

millions of Canadian dollars
	  	December 31, 2014	 
	  	Level 1	 	 	Level 2	 	  	Level 3	 	 	Total	 
	 Assets
	  				 				  				 			
	 Cash flow hedges
	  				 				  				 			
	 Power swaps
	  	$	14.2	  	 	$	—  	  	  	$	8.7	  	 	$	22.9	  
	 Foreign exchange forwards
	  	 	—  	  	 	 	0.1	  	  	 	—  	  	 	 	0.1	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	14.2	  	 	 	0.1	  	  	 	8.7	  	 	 	23.0	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	  				 				  				 			
	 Commodity swaps and forwards
	  				 				  				 			
	 Natural gas purchases and sales
	  	 	0.1	  	 	 	—  	  	  	 	—  	  	 	 	0.1	  
	 Foreign exchange forwards
	  	 	—  	  	 	 	97.5	  	  	 	—  	  	 	 	97.5	  
	 Physical natural gas purchases and sales
	  	 	—  	  	 	 	—  	  	  	 	0.1	  	 	 	0.1	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	0.1	  	 	 	97.5	  	  	 	0.1	  	 	 	97.7	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	  				 				  				 			
	 Power swaps and physical contracts
	  	 	66.3	  	 	 	—  	  	  	 	(3.4	) 	 	 	62.9	  
	 Natural gas swaps, futures, forwards and physical contracts
	  	 	(1.8	) 	 	 	22.3	  	  	 	24.4	  	 	 	44.9	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	64.5	  	 	 	22.3	  	  	 	21.0	  	 	 	107.8	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Total assets
	  	 	78.8	  	 	 	119.9	  	  	 	29.8	  	 	 	228.5	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Liabilities
	  				 				  				 			
	 Cash flow hedges
	  				 				  				 			
	 Power swaps
	  	$	1.0	  	 	$	—  	  	  	$	3.2	  	 	$	4.2	  
	 Foreign exchange forwards
	  	 	—  	  	 	 	15.0	  	  	 	—  	  	 	 	15.0	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	1.0	  	 	 	15.0	  	  	 	3.2	  	 	 	19.2	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	  				 				  				 			
	 Commodity swaps and forwards
	  				 				  				 			
	 Coal purchases
	  	 	—  	  	 	 	10.2	  	  	 	—  	  	 	 	10.2	  
	 Natural gas purchases and sales
	  	 	0.7	  	 	 	—  	  	  	 	—  	  	 	 	0.7	  
	 Heavy fuel oil purchases
	  	 	—  	  	 	 	25.5	  	  	 	—  	  	 	 	25.5	  
	 Foreign exchange forwards
	  	 	—  	  	 	 	3.9	  	  	 	—  	  	 	 	3.9	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	0.7	  	 	 	39.6	  	  	 	—  	  	 	 	40.3	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	  				 				  				 			
	 Power swaps and physical contracts
	  	 	1.3	  	 	 	—  	  	  	 	1.5	  	 	 	2.8	  
	 Natural gas swaps, futures, forwards and physical contracts
	  	 	13.5	  	 	 	12.0	  	  	 	117.0	  	 	 	142.5	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	14.8	  	 	 	12.0	  	  	 	118.5	  	 	 	145.3	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Total liabilities
	  	 	16.5	  	 	 	66.6	  	  	 	121.7	  	 	 	204.8	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Net assets (liabilities)
	  	$	62.3	  	 	$	53.3	  	  	$	(91.9	) 	 	$	23.7	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 

 The change in the fair value of the Level 3 financial assets for the year ended December 31, 2015 was as follows: 

 

																	
	 	  	Regulatory Deferral	 	 	Cash Flow Hedges and HFT
Derivatives	 
	 millions of Canadian dollars
	  	Physical natural gas
purchases and sales	 	 	Power	 	 	Natural
gas	 	 	Total	 
	 Balance, January 1, 2015
	  	$	0.1	  	 	$	5.3	  	 	$	24.4	  	 	$	29.8	  
	 Increase (reduction) in benefit included in regulated fuel for generation and purchased power
	  	 	(7.1	) 	 	 	—  	  	 	 	—  	  	 	 	(7.1	) 
	 Increase (reduction) in benefit included in non-regulated fuel for generation and purchased power
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Unrealized gains (losses) included in regulatory assets or liabilities
	  	 	8.8	  	 	 	—  	  	 	 	—  	  	 	 	8.8	  
	 Total realized and unrealized gains (losses) included in non-regulated operating revenues
	  	 	—  	  	 	 	(8.8	) 	 	 	32.4	  	 	 	23.6	  
	 Net transfers out of Level 3
	  	 	—  	  	 	 	(4.3	) 	 	 	—  	  	 	 	(4.3	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, December 31, 2015
	  	$	1.8	  	 	$	(7.8	) 	 	$	56.8	  	 	$	50.8	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  
 46 

 The change in the fair value of the Level 3 financial liabilities for the year ended December 31, 2015 was as follows:

  

																	
	 	  	Regulatory Deferral	 	 	Cash Flow Hedges and
HFT Derivatives	 
	 millions of Canadian dollars
	  	Physical natural gas
purchases and sales	 	 	Power	 	 	Natural
gas	 	 	Total	 
	 Balance, January 1, 2015
	  	$	—  	  	 	$	4.7	  	 	$	117.0	  	 	$	121.7	  
	 Increase (reduction) in benefit included in regulated fuel for generation and purchased power
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Increase (reduction) in benefit included in non-regulated fuel for generation and purchased power
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Unrealized gains (losses) included in regulatory assets or liabilities
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Total realized and unrealized gains (losses) included in non-regulated operating revenues
	  	 	—  	  	 	 	(2.3	) 	 	 	161.8	  	 	 	159.5	  
	 Net transfers out of Level 3
	  	 	—  	  	 	 	(4.4	) 	 	 	—  	  	 	 	(4.4	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, December 31, 2015
	  	$	—  	  	 	$	(2.0	) 	 	$	278.8	  	 	$	276.8	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The Company evaluate the observable input of market data on a quarterly basis in order to determine if transfers between levels is
appropriate. For the year ended December 31, 2015, transfer from Level 3 to Level 1 were a result of an increase in observable inputs. 
 Emera’s Enterprise
Risk Management group is responsible for valuation policies, processes and the measurement of fair value. Fair value accounting rules provide a three level hierarchy that prioritizes the inputs used to measure fair value. When possible,
determining fair value is based primarily on observable market inputs in active markets. 
 Contracts with quoted prices available in active markets and exchanges for
identical assets or liabilities are classified as level 1 in the hierarchy. For those contracts whereby pricing inputs are either directly or indirectly observable through markets, exchanges or third party sources, but do not qualify as level 1, are
classified as level 2 in the hierarchy. For a level 3 classification, the processes and methods of measurement for third-party pricing information and illiquid markets are developed with input and using the market knowledge of the trading operations
within Emera and its affiliates. 
 Significant unobservable inputs used in the fair value measurement of Emera’s natural gas and power derivatives includes
third-party-sourced pricing for instruments based on illiquid markets; internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a
quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Where possible, Emera also sources multiple broker prices in an effort to evaluate and substantiate these unobservable inputs. Discount
rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar
industry practices and in discussion with industry peers. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measurement. 

  
 47 

  
 The following
table outlines quantitative information about the significant unobservable inputs used in the fair value measurements categorized within Level 3 of the fair value hierarchy: 
  

																			
	As at	  	December 31, 2015	 
	 millions of Canadian dollars
	  	Fair
Value	 	 	Valuation
Technique	 	  	 Unobservable Input
	  	Range	 	 	Weighted
average	 
	 Assets
	  				 				  		  				 			
	 Regulatory deferral – Physical
	  	$	1.8	  	 	 	Modelled pricing	  	  	Third-party pricing	  	$	5.15 - $6.21	  	 	$	5.72	  
	 natural gas purchases and sales
	  				 				  	Probability of default	  	 	0.01%	  	 	 	0.01%	  
						
	 HFT derivatives –
	  	 	(7.8	) 	 	 	Modelled pricing	  	  	Third-party pricing	  	$	26.27 - $129.20	  	 	$	70.45	  
	 Power swaps and
	  				 				  	Correlation factor	  	 	0.98% - 1.00%	  	 	 	0.99%	  
	 physical contracts
	  				 				  	Probability of default	  	 	0.00% - 0.02%	  	 	 	0.00%	  
		  				 				  	Discount rate	  	 	0.00% - 0.15%	  	 	 	0.01%	  
						
	 HFT derivatives –
	  	 	54.2	  	 	 	Modelled pricing	  	  	Third-party pricing	  	$	1.13 - $9.12	  	 	$	3.26	  
	 Natural gas swaps,
	  				 				  	Probability of default	  	 	0.00% - 0.10%	  	 	 	0.01%	  
	 futures, forwards,
	  				 				  	Discount rate	  	 	0.00% - 0.33%	  	 	 	0.04%	  
	 physical contracts
	  	 	2.6	  	 	 	Modelled pricing	  	  	Third-party pricing	  	$	1.25 - $15.74	  	 	$	6.19	  
	 and related transportation
	  				 				  	Basis adjustment	  	 	(0.06)% - 0.95%	  	 	 	0.68%	  
		  				 				  	Probability of default	  	 	0.00% - 0.09%	  	 	 	0.00%	  
		  				 				  	Discount rate	  	 	0.00% - 0.08%	  	 	 	0.00%	  
		  	  
	  
	 	 				  		  				 			
	 Total assets
	  	 	50.8	  	 				  		  				 			
		  	  
	  
	 	 				  		  				 			
	 Liabilities
	  				 				  		  				 			
	 HFT derivatives –
	  	$	(2.0	) 	 	 	Modelled pricing	  	  	Third-party pricing	  	$	26.27-$129.20	  	 	$	70.82	  
	 Power swaps and
	  				 				  	Correlation factor	  	 	0.98%-1.00%	  	 	 	0.99%	  
	 physical contracts
	  				 				  	Own credit risk	  	 	0.00%-0.02%	  	 	 	0.00%	  
		  				 				  	Discount rate	  	 	0.00%-0.15%	  	 	 	0.01%	  
						
	 HFT derivatives –
	  	 	278.8	  	 	 	Modelled pricing	  	  	Third-party pricing	  	$	0.74- $10.59	  	 	$	5.58	  
	 Natural gas swaps, futures,
	  				 				  	Probability of default	  	 	0.00%-0.03%	  	 	 	0.00%	  
	 forwards and physical contracts
	  				 				  	Discount rate	  	 	0.00%-0.12%	  	 	 	0.01%	  
	 Total liabilities
	  	 	276.8	  	 				  		  				 			
		  	  
	  
	 	 				  		  				 			
	 Net assets (liabilities)
	  	$	(226.0	) 	 				  		  				 			
		  	  
	  
	 	 				  		  				 			

  
 48 

																	
	As at	  	December 31, 2014	 
	 millions of Canadian dollars
	  	Fair
Value	 	 	Valuation
Technique	  	 Unobservable Input
	  	Range	 	 	Weighted
average	 
	 Assets
	  				 		  		  				 			
	 Cash flow hedges –
	  	$	8.7	  	 	Modelled pricing	  	Third-party pricing	  	$	23.23 - $114.99	  	 	$	53.97	  
	 Power and gas swaps
	  				 		  	Probability of default	  	 	0.05% - 0.06%	  	 	 	0.05%	  
		  				 		  	Discount rate	  	 	5.06% - 7.53%	  	 	 	6.06%	  
						
	 Regulatory deferral – Physical
	  	 	0.1	  	 	Modelled pricing	  	Third-party pricing	  	$	9.52 - $12.94	  	 	$	9.52	  
	 natural gas purchases and sales
	  				 		  	Probability of default	  	 	0.05%	  	 	 	0.05%	  
						
	 HFT derivatives –
	  	 	(4.4	) 	 	Modelled pricing	  	Third-party pricing	  	$	46.65 - $103.27	  	 	$	70.69	  
	 Power swaps and
	  				 		  	Probability of default	  	 	0.06% - 0.06%	  	 	 	0.06%	  
	 physical contracts
	  				 		  	Discount rate	  	 	0.00% - 4.15%	  	 	 	0.47%	  
		  	 	1.0	  	 	Modelled pricing	  	Third-party pricing	  	$	27.61 - $127.96	  	 	$	62.04	  
		  				 		  	Correlation factor	  	 	0.99% - 1.0%	  	 	 	0.99%	  
		  				 		  	Probability of default	  	 	0.04% - 0.39%	  	 	 	0.14%	  
		  				 		  	Discount rate	  	 	0.00% - 48.63%	  	 	 	11.87%	  
						
	 HFT derivatives –
	  	 	24.4	  	 	Modelled pricing	  	Third-party pricing	  	$	1.19 - $11.36	  	 	$	5.56	  
	 Natural gas swaps,
	  				 		  	Probability of default	  	 	0.01% - 2.26%	  	 	 	0.46%	  
	 futures, forwards and
	  				 		  	Discount rate	  	 	0.00% - 67.72%	  	 	 	5.28%	  
		  	  
	  
	 	 		  		  				 			
	 Total assets
	  	 	29.8	  	 		  		  				 			
		  	  
	  
	 	 		  		  				 			
	 Liabilities
	  				 		  		  				 			
	 Cash flow hedges –
	  	$	3.2	  	 	Modelled pricing	  	Third-party pricing	  	$	23.23 - $114.99	  	 	$	53.97	  
	 Power and gas swaps
	  				 		  	Own credit risk	  	 	0.06% - 0.06%	  	 	 	0.06%	  
		  				 		  	Discount rate	  	 	5.06% - 7.53%	  	 	 	6.06%	  
						
	 HFT derivatives –
	  	 	1.2	  	 	Modelled pricing	  	Third-party pricing	  	$	32.99 - $127.96	  	 	$	74.58	  
	 Power swaps and
	  				 		  	Correlation factor	  	 	0.99% - 1.00%	  	 	 	0.99%	  
	 physical contracts
	  				 		  	Own credit risk	  	 	0.06% - 0.06%	  	 	 	0.06%	  
		  				 		  	Discount rate	  	 	0.00% - 48.63%	  	 	 	15.37%	  
		  	 	0.3	  	 	Modelled pricing	  	Third-party pricing	  	$	46.45 - $103.27	  	 	$	70.69	  
		  				 		  	Own credit risk	  	 	0.06% - 0.06%	  	 	 	0.06%	  
		  				 		  	Discount rate	  	 	0.00% - 4.15%	  	 	 	0.47%	  
						
	 HFT derivatives –
	  	 	117.0	  	 	Modelled pricing	  	Third-party pricing	  	$	1.60 - $14.13	  	 	$	3.81	  
	 Natural gas swaps,
	  				 		  	Basis adjustment	  	 	(0.01)% - 0.66%	  	 	 	0.21%	  
	 futures, forwards and
	  				 		  	Own credit risk	  	 	0.06% - 0.06%	  	 	 	0.06%	  
	 physical contracts
	  				 		  	Discount rate	  	 	0.00% - 31.53%	  	 	 	3.52%	  
		  	  
	  
	 	 		  		  				 			
	 Total liabilities
	  	 	121.7	  	 		  		  				 			
		  	  
	  
	 	 		  		  				 			
	 Net assets (liabilities)
	  	$	(91.9	) 	 		  		  				 			
		  	  
	  
	 	 		  		  				 			

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

																	
	 As at

millions of Canadian dollars
	  	December 31, 2015	 	  	December 31, 2014	 
	  	Carrying
Amount	 	  	Fair Value	 	  	Carrying
Amount	 	  	Fair Value	 
	 Long-term debt (including current portion)
	  	$	4,024.8	  	  	$	4,486.7	  	  	$	3,754.8	  	  	$	4,382.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 The fair values of long-term debt instruments, classified as level 3 in the fair value hierarchy, are estimated based on the quoted
market price for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturity, without considering the effect of third party credit enhancements. 

All other financial assets and liabilities, such as cash and cash equivalents, restricted cash, accounts receivable, short-term debt and accounts payable, are carried
at cost. The carrying value approximates fair value due to the short-term nature of these financial instruments. 

  
 49 

 17. REGULATORY ASSETS AND LIABILITIES 

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

NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provide an
appropriate return to investors. NSPI’s target regulated return on equity (“ROE”) range for 2015 and 2014 was 8.75 per cent to 9.25 per cent based on an actual average regulated common equity component of up to 40 per
cent. NSPI has a FAM, which enables it to seek recovery of Fuel Costs through regularly scheduled rate adjustments. Differences between actual Fuel Costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM
regulatory asset or liability and recovered from or returned to customers in a subsequent year. 
 On December 21, 2012, the UARB approved a General Rate
Application (“GRA”) settlement agreement between NSPI and customer representatives which resulted in an average net rate increase of 3 per cent by customer class effective January 1, 2013 and January 1, 2014. To achieve the
net 3 per cent increase in rates, the UARB approved a rate stabilization plan under which a portion of non-fuel costs from 2013 and 2014 could be deferred for future recovery. NSPI committed to $27.5 million in non-fuel cost savings over a
two-year period beginning in fiscal 2013. 
 As at December 2014, NSPI had under recovered approximately $86.1 million in Fuel Costs. Pursuant to NSPI’s FAM Plan
of Administration, this amount would be recovered commencing in 2015. On November 25, 2014, the UARB approved a settlement agreement that resulted in approximately $56.0 million of the 2014 outstanding FAM balance being collected in 2015. In
addition, the UARB directed NSPI to transfer $38.2 million of the payable balance of the rate stabilization deferral account to reduce the FAM balance of $86.1 million, resulting in a revised balance of $47.9 million at December 31, 2014. 

Through a related settlement agreement with stakeholders approved in December 2014, NSPI agreed to apply non-fuel revenues above that required to achieve its approved
range of return to reduce the FAM deferral account. This was effective as of January 1, 2015, until the next GRA approval or similar process where non-fuel rates are adjusted. This settlement agreement required NSPI to contribute a minimum of
$41.3 million to the FAM deferral account by the end of 2015. 
 As at December 31, 2015, NSPI had exceeded the minimum required contribution of $41.3 million
through the $38.2 million contributed in 2014 referred to above and an additional $44.7 million applied in 2015. Of the $44.7 million applied in 2015, $18.3 million relates to changes to South Canoe and Sable Wind Projects tax treatment. 

On December 21, 2015, the UARB approved NSPI’s setting of the 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as
submitted in NSPI’s August and November 2015 filings. The recovery of these costs will begin January 1, 2016. The approved customer rates seek to recover $13.7 million of prior years’ unrecovered Fuel Costs in 2016 and the current FAM
asset on the balance sheet. This results in a combined average rate decrease for customers of approximately 1 per cent. 
 The excess non-fuel revenues in 2015
include a benefit of $18.3 million which is the result of the changes to South Canoe and Sable Wind Projects tax treatments, as legislated by the Electricity Plan Act. The Electricity Plan Act also directs NSPI to apply sufficient 2015 excess
non-fuel revenues, so as to offset 2016 fuel rate increases in certain classes. This amount totals $4.6 million and is included in the $13.7 million current FAM asset on the Consolidated Balance Sheets. The remaining 2015 excess non-fuel 

  
 50 

 
revenues of $40.1 million, plus interest, have been deferred for future periods beyond 2016, as further directed by the Electricity Plan Act and are classified as long-term FAM liability on the
Consolidated Balance Sheets. 
 Emera Maine 
 Emera Maine’s core
businesses are the transmission and distribution of electricity, with distribution operations and stranded cost recoveries regulated by the Maine Public Utilities Commission (“MPUC”). The transmission operations are regulated by the
Federal Energy Regulatory Commission (“FERC”). The rates for these three elements are established in distinct regulatory proceedings.
 Distribution
Operations 
 Emera Maine’s distribution businesses operate under a traditional cost-of-service regulatory structure, and distribution rates are set by the
MPUC. Prior to July 1, 2014, the allowed ROE was 10.2 per cent, on a common equity component of 50 per cent. 
 On July 1, 2014, Emera
Maine’s distribution rates increased by nine per cent, including the recovery, over five years, of approximately $5 million USD of costs associated with a major ice storm in Maine in late December 2013. Also, effective July 1, 2014, the
allowed ROE became 9.55 per cent, on a common equity component of 49 per cent. 
 Transmission Operations 

There are two transmission districts in Emera Maine, corresponding to the service territories of the two pre-merger entities. 

Bangor Hydro District 
 Transmission rates for Bangor Hydro District’s
(the franchise electric service territory associated with the former Bangor Hydro Electric Company in portions of the Maine counties of Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook) are regulated by the FERC and set annually on
June 1, based on a formula utilizing prior year actual transmission investments, adjusted for current year forecasted transmission investments. The allowed ROE up to October 15, 2014, for these local transmission investments was
11.14 per cent. Effective October 16, 2014, the allowed ROE changed to 10.57 per cent, pending two outstanding complaints filed with the FERC to challenge the ISO-New England Open Access Transmission Tariff-allowed base ROE of
11.14 per cent. The common equity component is based upon the prior calendar year actual average balances. Effective June 1, 2015, transmission rates for the Bangor Hydro district increased by approximately 21 per cent in connection
with its annual transmission formula rate filing (2014 – increased by 13 per cent). The increase is associated primarily with the under-recovery of prior year regional transmission revenues collected in local rates, as well as the recovery
of increased transmission plant in service. 
 Bangor Hydro District’s bulk transmission assets are managed by ISO-New England (“ISO-NE”) as part of a
region-wide pool of assets. ISO-NE manages the region’s bulk power generation and transmission systems and administers the open access transmission tariff. Currently, the Bangor Hydro District, along with all other participating transmission
providers, recovers the full cost of service for its transmission assets from the customers of participating transmission providers in New England, based on a regional FERC approved formula that is updated June 1 each year. This formula is
based on prior year regionally funded transmission investments, adjusted for current year forecasted investments. Until October 15, 2014, Bangor Hydro District’s allowed ROE for these transmission investments ranged from 11.64 per
cent to 12.64 per cent. Effective October 16, 2014, the transmission investments allowed ROE changed to a range from 11.07 per cent to 11.74 per cent, pending the two aforementioned complaints filed with FERC. The common equity
component is based upon the prior calendar year average balances. The participating transmission providers are also required to contribute to the cost of service of such 

  
 51 

 
transmission assets on a ratable basis according to the proportion of the total New England load that their customers represent. 

On June 1, 2015, Bangor District’s regionally recoverable transmission investments and expenses decreased by 6 per cent (2014 – increased by
7 per cent). 
 MPS District 
 Local transmission rates for MPS
District’s (the franchise electric service territory associated with the former Maine Public Service Company in northern Maine) are regulated by the FERC and are set annually on June 1 for wholesale and July 1 for retail customers
based on a formula utilizing prior year actual transmission investments and expenses, adjusted for current year forecasted investments. The current allowed ROE for transmission operations is 10.2 per cent. The common equity component is
based upon the prior calendar year actual average balances. Effective June 1, 2015 the transmission rates for the Maine Public Service district decreased by approximately 24 per cent for wholesale customers (2014 -increased by
2 per cent) and on July 1, 2015 decreased by 22 per cent for retail customers (2014—increased by 11 per cent) in connection with its annual transmission formula rate filing. These decreases were primarily due to an increase
in wholesale transmission revenue that allows for a decrease in local customer transmission rates. 
 The MPS District electric service territory is not connected to
the New England bulk power system and it is not a member of ISO-NE. MPS District is not a party to the previously discussed ROE complaints at the FERC. 

Stranded Cost Recoveries 
 Stranded cost recoveries in Maine are set by the
MPUC. Electric utilities are permitted to recover all prudently incurred stranded costs resulting from the restructuring of the industry in 2000 that could not be mitigated or that arose as a result of rate and accounting orders issued by the MPUC.
Unlike transmission and distribution operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to income and recovered through
rates. Generally, regulatory rates to recover stranded costs are set every three years, determined under a traditional cost-of-service approach and are fully recoverable. Each year on July 1, stranded cost rates in the Bangor District are
adjusted to reflect recovery of cost deferrals for the prior stranded costs rate year under the full recovery mechanism, as well as factor in any new stranded cost information. 

Bangor District 
 Bangor District’s net regulatory assets primarily
include the costs associated with the restructuring of an above-market power purchase contract and deferrals associated with reconciling stranded costs. These net regulatory assets total approximately $19.7 million as at December 31, 2015 (2014
– $25.1 million) or 1.8 per cent of Emera Maine’s net asset base (2014 – 2.3 per cent). 
 On July 1, 2014, the Bangor District stranded
cost rates decreased by 10 per cent. Earlier, on March 1, 2014, stranded costs rates had increased by 20 per cent. The allowed ROE used in setting the new rates on July 1, 2014, and March 1, 2014, was 5.9 per cent, with
a common equity component of 48 per cent. This July 1, 2014 rate decrease remained in effect for all of 2015 and there was no rate change on July 1, 2015. 

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

  
 52 

 MPS District 
 Effective
January 1, 2015, the stranded cost rates for the Maine Public Service district decreased by approximately 150 per cent. This was principally due to the flow-back to customers of certain benefits received by Emera Maine from Maine Yankee
associated with litigation with the United States Department of Energy on nuclear waste disposal. The allowed ROE used in setting the new rates on January 1, 2015 was 6.75 per cent, with a common equity component of 48 per
cent. The reduced stranded cost revenues are offset by reductions in expense and do not affect earnings. This January 1, 2015, rate decrease remained in effect for all of 2015 and there was no rate change on July 1, 2015. 

The Barbados Light & Power Company Limited 
 BLPC is a
vertically integrated utility and provider of electricity on the island of Barbados. 
 BLPC is subject to regulation under the Utilities Regulation (Procedural)
Rules 2003 by Fair Trading Commission (“The Rules”), Barbados, an independent regulator. The Rules give the Fair Trading Commission, Barbados utility regulation functions, which include establishing principles for arriving at rates to be
charged, monitoring the rates charged to ensure compliance, and setting the maximum rates for regulated utility services. The government of Barbados has granted BLPC a franchise to generate, transmit and distribute electricity on the island until
2028. 
 BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and
provide an appropriate return to investors. BLPC’s approved regulated return on rate base for 2015 and 2014 was 10 per cent. 
 All BLPC fuel costs are
passed to customers through the fuel pass-through mechanism which provides the opportunity to recover all fuel costs in a timely manner. The Fair Trading Commission, Barbados has approved the calculation of the fuel charge, which is adjusted on a
monthly basis. 
 Dominica Electricity Services Ltd 
 Domlec is an
integrated utility on the island of Dominica and is regulated by the Independent Regulatory Commission, Dominica 
 On October 7, 2013, the Independent
Regulatory Commission, Dominica issued a Transmission, Distribution & Supply License and a Generation License, both of which came into effect on January 1, 2014, for a period of 25 years. Domlec’s approved allowable regulated
return on rate base for 2015 and 2014 was 15 per cent. 
 Domlec fuel costs are passed to customers through a fuel pass-through mechanism which provides the
opportunity to recover substantially all fuel costs in a timely manner. 
 Grand Bahama Power Company Limited 

GBPC is a vertically integrated utility and sole provider of electricity on Grand Bahama Island. The Grand Bahama Port Authority (“GBPA”) regulates the utility
and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policy to ensure that fuel costs are
recovered and a reasonable return earned. GBPC’s approved regulated return on rate base for 2015 and 2014 was 10 per cent. 
 For the years ended
December 31, 2015 and 2014, all GBPC fuel costs are passed to customers through a fuel pass-through mechanism which provides the opportunity to recover substantially all fuel costs in a timely manner. 

  
 53 

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

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

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

 

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Regulatory assets
	  				  			
	 Deferred income tax regulatory assets
	  	$	431.3	  	  	$	340.1	  
	 Deferrals related to derivative instruments
	  	 	67.7	  	  	 	45.6	  
	 Unamortized defeasance costs
	  	 	45.7	  	  	 	52.5	  
	 Demand side management deferral (note 5)
	  	 	36.4	  	  	 	—  	  
	 Stranded cost recovery
	  	 	28.5	  	  	 	24.9	  
	 Fuel adjustment mechanism (note 5)
	  	 	13.7	  	  	 	47.9	  
	 Pension and post-retirement medical plan
	  	 	11.9	  	  	 	10.4	  
	 Hydro-Quebec Obligation
	  	 	7.6	  	  	 	6.8	  
	 Stranded cost revenue & purchase power reconciliation deferrals
	  	 	6.1	  	  	 	8.0	  
	 2014 Maine storm
	  	 	6.1	  	  	 	5.3	  
	 Purchase power contracts
	  	 	5.9	  	  	 	7.0	  
	 Large industrial customers fixed cost deferral (note 5)
	  	 	—  	  	  	 	15.8	  
	 Other
	  	 	38.6	  	  	 	38.4	  
		  	  
	  
	 	  	  
	  
	 
		  	$	699.5	  	  	$	602.7	  
		  	  
	  
	 	  	  
	  
	 
	 Current
	  	$	94.2	  	  	$	115.0	  
	 Long-term
	  	 	605.3	  	  	 	487.7	  
		  	  
	  
	 	  	  
	  
	 
	 Total regulatory assets
	  	$	699.5	  	  	$	602.7	  
		  	  
	  
	 	  	  
	  
	 
	 Regulatory liabilities
	  				  			
	 Deferrals related to derivative instruments
	  	$	209.9	  	  	$	97.7	  
	 Self-Insurance Fund
	  	 	86.8	  	  	 	72.8	  
	 Fuel adjustment mechanism (note 5)
	  	 	42.0	  	  	 	—  	  
	 Deferred income tax regulatory liabilities
	  	 	17.6	  	  	 	17.7	  
	 Other
	  	 	14.3	  	  	 	13.7	  
		  	  
	  
	 	  	  
	  
	 
		  	$	370.6	  	  	$	201.9	  
		  	  
	  
	 	  	  
	  
	 
	 Current
	  	$	98.9	  	  	$	43.0	  
	 Long-term
	  	 	271.7	  	  	 	158.9	  
		  	  
	  
	 	  	  
	  
	 
	 Total regulatory liabilities
	  	$	370.6	  	  	$	201.9	  
		  	  
	  
	 	  	  
	  
	 

  

  
 54 

 Deferred Income Tax Regulatory Asset and Liability 

To the extent deferred income taxes are expected to be recovered from or returned to customers in future rates, a regulatory asset or liability is recognized, unless
specifically directed otherwise by a regulator. 
 Deferrals Related to Derivative Instruments 

NSPI and GBPC defers changes in fair value of derivatives that are documented as economic hedges or that do not qualify for normal purchase normal sale
(“NPNS”) exemption, as a regulatory asset or liability. The realized gain or loss is recognized when the hedged item settles in fuel for generation and purchased power or inventory, depending on the nature of the item being economically
hedged. 
 Unamortized Defeasance Costs 
 Upon privatization in 1992, NSPI
became responsible for managing a portfolio of defeasance securities held in trust that provide the principal and interest streams to match the related defeased debt, which as at December 31, 2015, totaled $0.8 billion (2014 – $0.7
billion). The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amortized over the life of the defeased debt as approved by the UARB. 

2015 DSM Deferral 
 As discussed in Note 5, following the new energy
efficiency legislation, the UARB approved the implementation of the 2015 DSM deferral set at $35 million for 2015 and recoverable from customers over an eight year period beginning in 2016. The change in the 2015 DSM regulatory asset balance for the
year ended December 31 consisted of the following: 
  

					
	 millions of Canadian dollars
	  	2015	 
	 DSM regulatory asset – Balance as at January 1
	  	$	—	  
	 Current period Program Costs
	  	 	35.0	  
	 Interest on DSM balance
	  	 	1.4	  
		  	  
	  
	 
	 DSM regulatory asset – Balance as at December 31
	  	$	36.4	  
		  	  
	  
	 

 Stranded Cost Recovery 
 Due to the
decommissioning of a steam turbine in GBPC during 2012, the GBPA approved the recovery of a $21.4 million USD stranded cost through future electricity rates. These amounts are scheduled to be recovered beginning January 1, 2016. 

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

									
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 FAM regulatory asset – Balance as at January 1
	  	$	 47.9	  	 	$	 86.4	  
	 Under (over) recovery of current year Fuel Costs
	  	 	24.1	  	 	 	(1.3	) 
	 Rebate to (recovery from) customers of prior years’ Fuel Costs
	  	 	(56.0	) 	 	 	—  	  
	 FAM audit disallowance, including interest adjustment
	  	 	—  	  	 	 	(6.0	) 
	 Application of non-fuel revenues
	  	 	(44.7	) 	 	 	(38.2	) 
	 Interest on FAM balance
	  	 	0.4	  	 	 	7.0	  
		  	  
	  
	 	 	  
	  
	 
	 FAM regulatory asset (liability) – Balance as at December 31
	  	$	(28.3	) 	 	$	47.9	  
		  	  
	  
	 	 	  
	  
	 

  
 55 

 Details of the changes are discussed further in note 5. The FAM balance is recorded on the balance sheet as a current FAM
asset of $13.7 million, to be recovered in 2016 and a long-term FAM liability of $42.0 million to be applied during 2017 through 2019 as legislated. 
 Pension and
Post-Retirement Medical Plan 
 As a result of purchase accounting, all unrecognized actuarial gains and losses, prior service cost, and the net transition
asset/liability associated with the pension and post-retirement medical benefit plans were eliminated as a result of the Bangor Hydro Electric Company and Maine Public Service Company mergers. As a result, a regulatory asset of $30 million, equal to
these unrecognized amounts, was established at the merger dates. Emera Maine is amortizing the regulatory asset balance over the same period at which the corresponding gains and losses were being amortized when they were a component of pension and
post-retirement benefit expense. 
 Hydro-Quebec Obligation 
 The obligation
associated with Hydro-Quebec represents the estimated present value of Emera Maine’s estimated future payments for net costs associated with ownership and operation of the Hydro-Quebec intertie between the New England utilities and
Hydro-Quebec. The obligation has been recognized in other liabilities and the MPUC has permitted recovery of this obligation. The regulatory asset and obligation are being reduced as expenses are incurred, with the reduction of the regulatory asset
amortized to purchase power expense. 
 Stranded Cost Revenue & Purchased Power Reconciliation Deferral 

Emera Maine has full recovery of stranded cost revenues and expenses, with deferral of variances between actual amounts and those used to set rates. Stranded cost rates
are adjusted periodically to recover these cost deferrals. 
 2014 Maine Storm 

In early November 2014, Emera Maine experienced a major storm in its service territory, with over one-third of the Company’s customers experiencing power outages at
the peak of storm. Due to the volume of power outages and significant damage to the electrical system, numerous external resources were utilized to assist with the restoration of electrical service. The total incremental costs associated
with the service restoration during the storm event amounted to approximately $5.3 million ($4.6 million USD), and the Company has recorded this amount as a regulatory asset on its consolidated balance sheets as of December 31,
2014. During Q2 2015, the Company made a request to the MPUC for a $5.4 million USD recovery of costs associated with this storm, as well as two other major storms that were expensed in 2014. In June 2015, Emera Maine reached agreement with the
MPUC to recover $4.1 million USD of the $5.4 million USD being sought. Emera Maine is recording carrying costs on this deferral retroactive to January 1, 2015 and going forward until the $4.1 million USD is included in rates. The difference
between $5.4 million USD originally requested for approval and the $4.1 million USD approved by the MPUC was expensed in Q2 2015. 
 Purchase Power Contracts

 Emera Maine has power purchase contracts, which it was required to negotiate when oil prices were high, with several independent power producers. Bangor Hydro
Electric Company attempted to alleviate the adverse impact of these high-cost contracts and in doing so incurred costs to restructure certain of the contracts. The MPUC has allowed Emera Maine to defer these costs and recover them in stranded cost
rates. The contract restructuring costs are being recovered over a 20-year period ending in June 2018. In 2011, Bangor Hydro Electric Company entered into a 20-year power purchase contract with a 60-MW wind
farm to purchase 20 per cent of the energy generated. Also in 2011, Bangor Hydro Electric Company entered into a 20-year power purchase contract with a 1-MW biomass generator to purchase 

  
 56 

 
100 per cent of the energy generated. As with the Company’s other power purchase contracts, the MPUC has allowed Bangor Hydro Electric Company full cost recovery for these contracts.

 Large Industrial Customers Fixed Cost Deferral 
 The UARB approved a FCR
for 2012 to address uncertainty associated with the operations of two large industrial customers who experienced financial challenges and idled their mills. Where actual sales to these customers in 2012 was less than expected when rates were set,
the resultant shortfall in contribution toward non-fuel costs was deferred as a regulatory asset for future recovery. The 2013 GRA settlement agreement, approved on December 21, 2012 by the UARB, allowed recovery of this deferral from customers
over a three-year period commencing January 1, 2013. 
 The change in the large industrial customers regulatory asset balance for the years ended
December 31 consisted of the following table: 
  

									
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 Large industrial customers regulatory asset – Balance as at January 1
	  	$	15.8	  	 	$	33.0	  
	 Recovery of regulatory asset recorded as regulatory amortization
	  	 	(16.4	) 	 	 	(19.1	) 
	 Interest on large industrial customers FCR balance
	  	 	0.6	  	 	 	1.9	  
		  	  
	  
	 	 	  
	  
	 
	 Large industrial customers regulatory asset – Balance as at December 31
	  	$	—  	  	 	$	15.8	  
		  	  
	  
	 	 	  
	  
	 

 Self-Insurance Fund 
 ECI has established a
SIF primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF, for which it was determined that ECI was the
primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that in substance the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC
and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF
Fund assets by the Company would be subject to existing regulations. 
 18. RELATED PARTY TRANSACTIONS 

In the ordinary course of business, Emera provides energy, construction and other services and enters into transactions with its subsidiaries, associates and other
related companies on terms similar to those offered to non-related parties. Inter-company balances and inter-company transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and
regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in
non-regulated operating revenues, with an offset to property, plant and equipment, regulated fuel for generation and purchased power, or operating, maintenance and general, depending on the nature of the transaction. 2014 balances have been
retrospectively restated, consistent with this approach. Below are transactions between Emera and its associated companies reported in the Consolidated Statements of Income: 

  
 57 

													
	 For the

millions of Canadian dollars
	  	Year ended
December 31	 
	 	  	 	  	 	  	2015	 	 	2014	 
	 	  	 Nature of Service
	  	 Presentation
	  	 	 	 	 	 
	 Sales to:
	  		  		  				 			
	 APUC

subsidiary
	  	 Net sale of natural gas and

transportation
	  	 Operating revenue –

non-regulated
	  	$	3.0	  	 	$	4.4	  
	 NWP
	  	 Energy management

services
	  	 Operating revenue –

regulated
	  	 	0.3	  	 	 	1.1	  
	 Purchases from:
	  		  		  				 			
	 M&NP
	  	 Natural gas transportation

capacity
	  	 Regulated fuel for generation

and purchased power
	  	 	4.5	  	 	 	3.6	  
	 M&NP
	  	 Natural gas transportation

capacity
	  	 Operating revenue –

non-regulated
	  	 	(23.4	) 	 	 	(23.8	) 
	 NWP
	  	 Purchase of power
	  	 Regulated fuel for generation

and purchased power
	  	$	0.3	  	 	$	1.9	  

 Operating revenue – non-regulated includes intercompany profit relating to the sale of natural gas, sale of power, construction,
operations management and engineering services, and hedging services to rate-regulated subsidiaries of Emera totaling $1.6 million for the year ended December 31, 2015 (2014 – $4.2 million). 

Amounts reported on Emera’s Consolidated Balance Sheets due (to) from its equity investments are summarized in the following table: 

 

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	 	December 31
2014	 
	 Due from related parties:
	  				 			
	 Subsidiary of APUC – current (1)
	  	$	0.7	  	 	$	—  	  
	 NSPML – current
	  	 	1.6	  	 	 	3.5	  
	 M&NP – loan receivable – long-term
	  	 	2.5	  	 	 	2.5	  
		  	  
	  
	 	 	  
	  
	 
	 Due to related parties:
	  				 			
		  	  
	  
	 	 	  
	  
	 
	 M&NP – current
	  	 	(2.1	) 	 	 	(1.6	) 
		  	  
	  
	 	 	  
	  
	 
	 Net due from (to) related parties
	  	$	2.7	  	 	$	4.4	  
		  	  
	  
	 	 	  
	  
	 

  

	(1)	Amount due from a subsidiary of APUC is included in accounts receivable. 

 All amounts are under normal interest and
credit terms, except for a loan receivable from M&NP bearing interest at 1 per cent per annum maturing on November 30, 2019.
 19. OTHER CURRENT
ASSETS 
 Other current assets consisted of the following: 
  

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Net investment in direct financing lease
	  	$	5.4	  	  	$	5.1	  
	 Dividend receivable
	  	 	6.7	  	  	 	5.0	  
	 Capitalized transportation capacity (1)
	  	 	222.7	  	  	 	70.5	  
		  	  
	  
	 	  	  
	  
	 
		  	$	234.8	  	  	$	80.6	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	Capitalized transportation capacity represents the value of transportation received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract.

  
 58 

 20. PROPERTY, PLANT AND EQUIPMENT 

Property, plant and equipment consisted of the following regulated and non-regulated assets: 
  

													
	 As at

millions of Canadian dollars
	  	Estimated useful life	 	  	December 31
2015	 	 	December 31
2014	 
	 Generation
	  	 	3 to 131	  	  	$	4,957.0	  	 	$	4,415.5	  
	 Transmission
	  	 	10 to 65	  	  	 	1,508.2	  	 	 	1,331.1	  
	 Distribution
	  	 	11 to 80	  	  	 	2,461.7	  	 	 	2,182.9	  
	 General plant and other
	  	 	5 to 57	  	  	 	786.9	  	 	 	722.5	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Total cost
	  				  	 	9,713.8	  	 	 	8,652.0	  
	 Less: Accumulated depreciation
	  				  	 	(3,732.4	) 	 	 	(3,362.0	) 
		  				  	  
	  
	 	 	  
	  
	 
		  				  	 	5,981.4	  	 	 	5,290.0	  
	 Construction work in progress
	  				  	 	206.6	  	 	 	320.2	  
		  				  	  
	  
	 	 	  
	  
	 
	 Net book value
	  				  	$	6,188.0	  	 	$	5,610.2	  
		  				  	  
	  
	 	 	  
	  
	 

 For the year ended December 31, 2015, AFUDC of $6.6 million (2014 – $12.0 million) was capitalized to
“Property, plant and equipment”. 
 As a result of regulator-approved accounting policies and depreciation rates, NSPI, Emera Maine and GBPC defer certain
costs within “Property, plant and equipment” that would not otherwise be deferred in the absence of rate regulation. Cumulative differences between items recognized for rate regulatory purposes and applicable USGAAP accounting
standards including depreciation rates, AFUDC and overhead costs, cannot be separately determined. Cumulative deferred accretion expense related to AROs was $7.9 million as at December 31, 2015 (2014 – $10.3 million).

 21. EMPLOYEE BENEFIT PLANS 
 Emera maintains a number of contributory
defined-benefit and defined-contribution pension plans, which cover substantially all of its employees; and plans providing non-pension benefits for its retirees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Maine, Connecticut, Rhode
Island, Barbados, Dominica and Grand Bahama Island. 
 Effective April 1, 2015, Emera Maine amended certain post-retirement medical benefits which resulted in a
reduction in the pension and post-retirement benefits liability. 
 Benefit Obligation and Plan Assets 

The changes in benefit obligation and plan assets, and the funded status for all plans were as follows: 

  
 59 

																	
	For the	  	Years ended December 31	 
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 Change in Projected Benefit Obligation
 and
Accumulated Post-retirement
 Benefit Obligation
	  	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 
	 Balance, January 1
	  	$	1,469.7	  	 	$	101.9	  	 	$	1,253.3	  	 	$	86.0	  
	 Service cost
	  	 	22.1	  	 	 	2.8	  	 	 	17.1	  	 	 	2.8	  
	 Plan participant contributions
	  	 	7.9	  	 	 	0.3	  	 	 	7.5	  	 	 	0.1	  
	 Interest cost
	  	 	58.7	  	 	 	3.5	  	 	 	61.7	  	 	 	4.2	  
	 Plan amendments
	  	 	—  	  	 	 	(26.7	) 	 	 	—  	  	 	 	—  	  
	 Benefits paid
	  	 	(61.0	) 	 	 	(5.8	) 	 	 	(60.0	) 	 	 	(4.9	) 
	 Actuarial losses
	  	 	(15.4	) 	 	 	1.1	  	 	 	175.1	  	 	 	8.7	  
	 Special termination
	  	 	—  	  	 	 	—  	  	 	 	(0.1	) 	 	 	—  	  
	 Foreign currency translation adjustment
	  	 	37.7	  	 	 	10.4	  	 	 	15.1	  	 	 	5.0	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, December 31
	  	 	1,519.7	  	 	 	87.5	  	 	 	1,469.7	  	 	 	101.9	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Change in Plan assets
	  				 				 				 			
	 Balance, January 1
	  	 	1,204.7	  	 	 	4.6	  	 	 	1,070.0	  	 	 	4.0	  
	 Employer contributions
	  	 	23.0	  	 	 	5.6	  	 	 	52.9	  	 	 	4.8	  
	 Plan participant contributions
	  	 	8.3	  	 	 	—  	  	 	 	7.5	  	 	 	—  	  
	 Benefits paid
	  	 	(61.0	) 	 	 	(5.6	) 	 	 	(60.0	) 	 	 	(4.8	) 
	 Actual return on assets, net of expenses
	  	 	96.3	  	 	 	(0.1	) 	 	 	122.8	  	 	 	0.2	  
	 Foreign currency translation adjustment
	  	 	29.1	  	 	 	0.9	  	 	 	11.5	  	 	 	0.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, December 31
	  	 	1,300.4	  	 	 	5.4	  	 	 	1,204.7	  	 	 	4.6	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Funded Status, end of year
	  	$	(219.3	) 	 	$	(82.1	) 	 	$	(265.0	) 	 	$	(97.3	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 As at December 31, the aggregate financial position for all pension plans where the Projected Benefit Obligation (PBO) or, for
post-retirement benefit plans, the Accumulated Post-retirement Benefit Obligation (APBO), exceeds the plan assets was as follows: 
  

																	
	 Plans with PBO/APBO in excess of Plan assets
	  	 	 	 	 	 
	 	  	2015	 	 	2014	 
	 millions of Canadian dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 
	 PBO/APBO
	  	$	1,489.4	  	 	$	87.5	  	 	$	1,437.9	  	 	$	101.9	  
	 Fair value of Plan Assets
	  	 	1,261.3	  	 	 	5.4	  	 	 	1,167.0	  	 	 	4.6	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Funded Status
	  	$	(228.1	) 	 	$	(82.1	) 	 	$	(270.9	) 	 	$	(97.3	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The Accumulated Benefit Obligation (“ABO”) for the defined benefit pension plans was $1,426.5 million as at
December 31, 2015 (2014 – $1,404.8 million). As at December 31, the aggregate financial position for those plans with an ABO in excess of the Plan assets was as follows: 

 

									
	 Plans with ABO in excess of Plan assets
	  	 	 	 	 	 
	 	  	2015	 	 	2014	 
	 millions of Canadian dollars
	  	Defined benefit
pension plans	 	 	Defined benefit
pension plans	 
	 ABO
	  	$	1,424.1	  	 	$	1,373.8	  
	 Fair value of Plan Assets
	  	 	1,261.3	  	 	 	1,167.0	  
		  	  
	  
	 	 	  
	  
	 
	 Funded Status
	  	$	(162.8	) 	 	$	(206.8	) 
		  	  
	  
	 	 	  
	  
	 

  
 60 

 Balance Sheet 
 The amounts
recognized in the Consolidated Balance Sheets as at December 31 consisted of the following: 
  

																	
	 	  	2015	 	 	2014	 
	 millions of Canadian dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 
	 Current liabilities
	  	$	(3.9	) 	 	$	(3.1	) 	 	$	(3.6	) 	 	$	(3.9	) 
	 Long-term liabilities
	  	 	(224.4	) 	 	 	(79.0	) 	 	 	(267.3	) 	 	 	(93.4	) 
	 Other asset (noncurrent)
	  	 	8.7	  	 	 	—  	  	 	 	5.9	  	 	 	—  	  
	 Amount included in deferred tax asset
	  	 	20.6	  	 	 	(3.2	) 	 	 	22.8	  	 	 	4.1	  
	 AOCI after tax adjustment
	  	 	328.6	  	 	 	(9.2	) 	 	 	420.4	  	 	 	6.3	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net amount recognized at end of year
	  	$	129.6	  	 	$	(94.5	) 	 	$	178.2	  	 	$	(86.9	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI. The following tables
provide detail on the change in AOCI during fiscal 2015 relating to these items; and the composition of the year-end balance: 
  

									
	 Accumulated Other Comprehensive Loss

millions of Canadian dollars
	  	Actuarial losses
(gains)	 	 	Past service
(gains) costs	 
	 Defined Benefit Pension Plans
	  				 			
	 Balance, January 1
	  	$	447.7	  	 	$	(4.5	) 
	 Amortized in current period
	  	 	(47.5	) 	 	 	0.8	  
	 Current year addition to AOCI
	  	 	(47.0	) 	 	 	—  	  
	 Transfer to other regulatory asset (1)
	  	 	(0.1	) 	 	 	—  	  
	 Foreign currency translation adjustment
	  	 	(0.2	) 	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 
	 Balance, December 31
	  	$	352.9	  	 	$	(3.7	) 
		  	  
	  
	 	 	  
	  
	 
	 Non-pension benefits plans
	  				 			
	 Balance, January 1
	  	$	16.8	  	 	$	(6.5	) 
	 Amortized in current period
	  	 	(1.6	) 	 	 	6.3	  
	 Current year addition to AOCI
	  	 	1.3	  	 	 	(27.1	) 
	 Transfer to other regulatory asset (1)
	  	 	(0.1	) 	 	 	(1.5	) 
	 Foreign currency translation adjustment
	  	 	(1.4	) 	 	 	1.4	  
		  	  
	  
	 	 	  
	  
	 
	 Balance, December 31
	  	$	15.0	  	 	$	(27.4	) 
		  	  
	  
	 	 	  
	  
	 

  

	(1)	For Emera Maine, as a result of regulatory accounting, any gain or loss is transferred to regulatory assets and amortized over the same period as the corresponding actuarial gains or losses. 

 

																	
	 	  	2015	 	 	2014	 
	 Accumulated Other Comprehensive Loss

millions of Canadian dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 
	 Actuarial losses
	  	$	352.9	  	 	$	15.0	  	 	$	447.7	  	 	$	16.9	  
	 Past service (gains)
	  	 	(3.7	) 	 	 	(27.4	) 	 	 	(4.5	) 	 	 	(6.5	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total AOCI on a pre-tax basis
	  	 	349.2	  	 	 	(12.4	) 	 	 	443.2	  	 	 	10.4	  
	 Less: Amount included in deferred tax asset
	  	 	(20.6	) 	 	 	3.2	  	 	 	(22.8	) 	 	 	(4.1	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net amount in AOCI after tax adjustment
	  	$	328.6	  	 	$	(9.2	) 	 	$	420.4	  	 	$	6.3	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The amounts in the foregoing table were not recognized in Emera’s net periodic benefit cost as at December 31. 

  
 61 

																	
	 Benefit Cost Components
	  	2015	 	 	2014	 
	 millions of Canadian dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 
	 Service cost
	  	$	22.1	  	 	$	2.8	  	 	$	17.1	  	 	$	2.8	  
	 Interest cost
	  	 	58.7	  	 	 	3.5	  	 	 	61.7	  	 	 	4.2	  
	 Expected return on plan assets
	  	 	(64.6	) 	 	 	(0.3	) 	 	 	(63.2	) 	 	 	(0.2	) 
	 Current year amortization of:
	  				 				 				 			
	 Actuarial losses
	  	 	47.5	  	 	 	1.6	  	 	 	35.9	  	 	 	0.1	  
	 Past service costs (gains)
	  	 	(0.8	) 	 	 	(6.3	) 	 	 	(0.8	) 	 	 	(1.7	) 
	 Special termination
	  	 	—  	  	 	 	—  	  	 	 	(0.1	) 	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total
	  	$	62.9	  	 	$	1.3	  	 	$	50.6	  	 	$	5.2	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The expected return on plan assets is determined based on the market-related value of plan assets of $1,088.7 million as at
January 1, 2015 (2014 – $995.1 million), adjusted for interest on certain cash flows during the year. The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less
than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period. 
 Pension Plan
Asset Allocations 
 Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to
accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to
diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes.
Within each asset class, a further diversification is undertaken through the investment in a broad basket of investment and non-investment grade securities. Emera’s target asset allocation is as follows: 

Canadian Pension Plans 
  

													
	 Asset Class
	  	Target Range at Market	 
	 Short-term securities
	  	 	0%	  	  	 	to	  	  	 	5%	  
	 Fixed income
	  	 	35%	  	  	 	to	  	  	 	50%	  
	 Equities:
	  				  				  			
	 Canadian
	  	 	12%	  	  	 	to	  	  	 	22%	  
	 Non-Canadian (World)
	  	 	36%	  	  	 	to	  	  	 	50%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Non-Canadian Pension Plans 
  

													
	 Asset Class
	  	Target Range at Market
(weighted average)	 
	 Short-term securities
	  	 	0%	  	  	 	to	  	  	 	10%	  
	 Fixed income
	  	 	30%	  	  	 	to	  	  	 	50%	  
	 Equities:
	  				  				  			
	 US
	  	 	24%	  	  	 	to	  	  	 	47%	  
	 Non-US
	  	 	14%	  	  	 	to	  	  	 	26%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 For Emera Maine, the investment of the Non-Canadian pension assets is overseen by the management team. For GBPC, the investment of
Non-Canadian pension assets is overseen by GBPA. 

  
 62 

 The fair values of investments as at December 31, 2015, by asset category, are as follows: 

 

																	
	 	  	December 31, 2015	 
	 millions of Canadian dollars
	  	NAV	 	  	Level 1	 	  	Total	 	  	Percentage	 
	 Cash and cash equivalents
	  				  	$	11.6	  	  	$	11.6	  	  	 	0.9%	  
	 Equity securities:
	  				  				  				  			
	 Canadian equity
	  				  	 	189.8	  	  	 	189.8	  	  	 	14.6%	  
	 US equity
	  				  	 	239.9	  	  	 	239.9	  	  	 	18.4%	  
	 Other equity
	  				  	 	240.0	  	  	 	240.0	  	  	 	18.5%	  
	 Other investments measured at NAV
	  	$	619.1	  	  	 	—  	  	  	 	619.1	  	  	 	47.6%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	619.1	  	  	$	681.3	  	  	$	1,300.4	  	  	 	100.0%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		
	 	  	December 31, 2014	 
	 millions of Canadian dollars
	  	NAV	 	  	Level 1	 	  	Total	 	  	Percentage	 
	 Cash and cash equivalents
	  				  	$	6.3	  	  	$	6.3	  	  	 	0.5%	  
	 Equity securities:
	  				  				  				  			
	 Canadian equity
	  				  	 	125.3	  	  	 	125.3	  	  	 	10.4%	  
	 US equity
	  				  	 	234.5	  	  	 	234.5	  	  	 	19.5%	  
	 Other equity
	  				  	 	234.5	  	  	 	234.5	  	  	 	19.5%	  
	 Other investments measured at NAV
	  	$	604.1	  	  	 	—  	  	  	 	604.1	  	  	 	50.1%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	604.1	  	  	$	600.6	  	  	$	1,204.7	  	  	 	100.0%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Refer to Note 1(Y), “Summary of Significant Accounting Policies – Fair Value Measurement,” for more information on
the fair value hierarchy and inputs used to measure fair value. All investments were deemed Level 1 for the years ended December 31, 2015 and 2014. 

Investments in Emera or NSPI 
 As at December 31, 2015 and 2014, the
pension funds do not hold any material investments in Emera Incorporated or NSPI securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities.

 Canadian Post-Retirement Benefit Plans 
 There are no assets set aside to
pay for the Canadian post-retirement benefit plans. As is common in Canada, post-retirement health benefits are paid from general accounts as required. 
 US
Post-Retirement Benefit Plans 
 Emera’s US subsidiaries currently provide certain post-retirement health care and life insurance benefits for employees
retiring after age 55 who meet eligibility requirements. Post-retirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify plans in whole or in part at any time. 

Emera Maine provides retiree medical benefits to certain groups of employees. The Company’s retiree medical expenses are incorporated into rate filings with its
regulators and are recovered through its electric rates to customers. 
 The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (MMA) added
prescription drug coverage to Medicare, with a 28 per cent tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. Emera’s current retiree medical program for those
eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The Company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit post-retirement
health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D. 

  
 63 

 Emera’s target asset allocation for its US Post-Retirement Benefits Plan is as follows: 

 

													
	 Asset Class
	  	Target Range at Market
(weighted average)	 
	 Short-term securities
	  	 	10%	  	  	 	to	  	  	 	50%	  
	 Fixed income
	  	 	0%	  	  	 	to	  	  	 	40%	  
	 Equities:
	  				  				  			
	 US
	  	 	30%	  	  	 	to	  	  	 	60%	  
	 Non-US
	  	 	0%	  	  	 	to	  	  	 	60%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 The fair values of investments as at December 31, 2015, by asset category, are as follows: 

 

																	
	 	  	December 31,2015	 
	 millions of Canadian dollars
	  	NAV	 	  	Level 1	 	  	Total	 	  	Percentage	 
	 Cash and cash equivalents
	  				  	$	1.4	  	  	$	1.4	  	  	 	25.9%	  
	 Other investments measured at NAV
	  	$	4.0	  	  				  	 	4.0	  	  	 	74.1%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	4.0	  	  	$	1.4	  	  	$	5.4	  	  	 	100.0%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		
	 	  	December 31, 2014	 
	 millions of Canadian dollars
	  	NAV	 	  	Level 1	 	  	Total	 	  	Percentage	 
	 Cash and cash equivalents
	  				  	$	1.2	  	  	$	1.2	  	  	 	26.1%	  
	 Other investments measured at NAV
	  	$	3.4	  	  	 	—  	  	  	 	3.4	  	  	 	73.9%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	3.4	  	  	$	1.2	  	  	$	4.6	  	  	 	100.0%	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Refer to Note 1(X), “Summary of Significant Accounting Policies – Fair Value Measurement,” for more information on
the fair value hierarchy and inputs used to measure fair value. All investments were deemed Level 1 for the years ended December 31, 2015 and 2014. 

Investments in Emera or NSPI 
 As at December 31, 2015 and 2014, the
assets related to the post-retirement benefit plans do not hold any material investments in Emera Incorporated or NSPI securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be
indirect investments in these securities. 
 Cash Flows 
 The following
table shows the expected cash flows for defined benefit pension and other post-retirement benefit plans: 
  

									
	 millions of Canadian dollars
	  	Defined benefit
pension plans	 	  	Non-pension
benefit plans	 
	 Expected employer contributions
	  				  			
	 2016
	  	$	19.7	  	  	$	5.6	  
		  	  
	  
	 	  	  
	  
	 
	 Expected benefit payments
	  				  			
	 2016
	  	 	65.5	  	  	 	5.6	  
	 2017
	  	 	70.6	  	  	 	5.6	  
	 2018
	  	 	75.1	  	  	 	6.1	  
	 2019
	  	 	79.9	  	  	 	6.3	  
	 2020
	  	 	85.2	  	  	 	6.7	  
	 2021 – 2025
	  	 	488.1	  	  	 	35.9	  
		  	  
	  
	 	  	  
	  
	 

  
 64 

 Assumptions 
 The following table
shows the assumptions that have been used in accounting for defined benefit pension and other post-retirement benefit plans: 
  

																	
	 	  	2015	 	  	2014	 
	 (weighted average assumptions)
	  	Defined benefit
pension plans	 	  	Non-pension
benefit plans	 	  	Defined benefit
pension plans	 	  	Non-pension
benefit plans	 
	 Benefit obligation – December 31:
	  				  				  				  			
	 Discount rate
	  	 	4.02%	  	  	 	4.04%	  	  	 	3.99%	  	  	 	3.98%	  
	 Rate of compensation increase
	  	 	3.07%	  	  	 	3.50%	  	  	 	3.07%	  	  	 	3.50%	  
	 Health care trend – initial (next year)
	  	 	—  	  	  	 	5.50%	  	  	 	—  	  	  	 	5.20%	  
	 – ultimate
	  	 	—  	  	  	 	4.20%	  	  	 	—  	  	  	 	4.30%	  
	 – year ultimate reached
	  	 	—  	  	  	 	2020   	  	  	 	—  	  	  	 	2020   	  
	 Benefit cost for year ended December 31:
	  				  				  				  			
	 Discount rate
	  	 	3.99%	  	  	 	3.98%	  	  	 	4.99%	  	  	 	4.90%	  
	 Expected long-term return on plan assets
	  	 	5.91%	  	  	 	—  	  	  	 	6.36%	  	  	 	—  	  
	 Rate of compensation increase
	  	 	3.07%	  	  	 	3.50%	  	  	 	3.29%	  	  	 	3.50%	  
	 Health care trend – initial (current year)
	  	 	—  	  	  	 	5.90%	  	  	 	—  	  	  	 	5.20%	  
	 – ultimate
	  	 	—  	  	  	 	4.30%	  	  	 	—  	  	  	 	4.40%	  
	 – year ultimate reached
	  	 	—  	  	  	 	2020   	  	  	 	—  	  	  	 	2020   	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  
 Figures shown are
weighted averages. Actual assumptions used may differ by plan. 
 The expected long-term rate of return on plan assets is based on historical and projected real rates
of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset
return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. 

The discount rate is based on high-quality long-term Canadian corporate bonds, with maturities matching the estimated cash flows from the pension plan 

Sensitivity Analysis for Non-Pension Benefits Plans 
 The health care cost
trend significantly influences the amounts presented for health care plans. An increase or decrease of one percentage point of the assumed health care cost trend would have had the following impact in 2015: 

 

									
	 millions of Canadian dollars
	  	Increase	 	  	Decrease	 
	 Service cost and interest cost
	  	$	1.1	  	  	$	(1.0	) 
	 Accumulated post-retirement benefit obligation, December 31
	  	 	9.2	  	  	 	(7.5	) 
		  	  
	  
	 	  	  
	  
	 

 Sensitivity Analysis for Defined Benefit Pension Plans 

The impact on the 2015 benefit cost of a 25 basis point change (0.25 per cent) in the discount rate and asset return assumptions is as follows: 

 

									
	 millions of Canadian dollars
	  	Increase	 	 	Decrease	 
	 Discount rate assumption
	  	$	(5.4	) 	 	$	5.4	  
	 Asset rate assumption
	  	 	(2.7	) 	 	 	2.6	  
		  	  
	  
	 	 	  
	  
	 

  
 65 

 Amounts to be Amortized in the Next Fiscal Year 

The following table shows the amounts from the AOCI, which are expected to be recognized as part of the net periodic benefit cost in fiscal 2016: 

 

									
	 	  	2016	 	 	2016	 
	 millions of Canadian dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 
	 Actuarial gains (losses)
	  	$	(41.4	) 	 	$	(2.2	) 
	 Past service gains
	  	 	0.7	  	 	 	8.7	  
		  	  
	  
	 	 	  
	  
	 
	 Total
	  	$	(40.7	) 	 	$	6.5	  
		  	  
	  
	 	 	  
	  
	 

 Defined Contribution Plan 
 Emera also
provides a defined contribution pension plan for certain employees. The Company’s contribution for the year ended December 31, 2015 was $9.0 million (2014 – $9.6 million). 

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

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	 	December 31
2014	 
	 Total minimum lease payments to be received
	  	$	1,201.6	  	 	$	1,263.2	  
	 Less: amounts representing estimated executory costs
	  	 	(212.5	) 	 	 	(222.1	) 
		  	  
	  
	 	 	  
	  
	 
	 Minimum lease payments receivable
	  	$	989.1	  	 	$	1,041.1	  
	 Estimated residual value of leased property (unguaranteed)
	  	 	183.0	  	 	 	183.0	  
	 Less: unearned finance lease income
	  	 	(686.6	) 	 	 	(734.5	) 
		  	  
	  
	 	 	  
	  
	 
	 Net investment in direct financing lease
	  	$	485.5	  	 	$	489.6	  
		  	  
	  
	 	 	  
	  
	 
	 Principal due within one year (included in “Other current assets”)
	  	 	5.4	  	 	 	5.1	  
		  	  
	  
	 	 	  
	  
	 
	 Net investment in direct financing lease – long-term
	  	$	480.1	  	 	$	484.5	  
		  	  
	  
	 	 	  
	  
	 

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

 

																					
	For the	  	Year ended December 31	 
	 millions of Canadian dollars
	  	2016	 	 	2017	 	 	2018	 	 	2019	 	 	2020	 
	 Minimum lease payments to be received
	  	$	61.6	  	 	$	61.6	  	 	$	61.6	  	 	$	61.6	  	 	$	61.6	  
	 Less: amounts representing estimated executory costs
	  	 	(9.8	) 	 	 	(9.9	) 	 	 	(10.1	) 	 	 	(10.3	) 	 	 	(10.5	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Minimum lease payments receivable
	  	$	51.8	  	 	$	51.7	  	 	$	51.5	  	 	$	51.3	  	 	$	51.1	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 23. AVAILABLE-FOR-SALE INVESTMENTS 
 The
available-for-sale investments consist primarily of debt and equity investments held in trust on behalf of BLPC’s Self Insurance Fund (“SIF”) for the purpose of building an insurance fund to cover risk against damage and consequential
loss to certain of BLPC’s generating, transmission and distribution systems. Any withdrawal of SIF Fund assets by the Company would be subject to existing regulations. 

In addition, there are debt and equity investments related to Emera Reinsurance Limited, for captive insurance purposes. 

  
 66 

 Emera has classified these investments as available-for-sale and recorded all such investments at their fair market value
as at December 31, 2015. 
 Available-for-sale financial assets measured at fair value include the following: 

 

																					
	 As at

millions of Canadian dollars
	 	NAV	 	 	Level 1	 	 	Level 2	 	 	Level 3	 	 	December 31
2015	 
	 Common shares
	 	$	—  	  	 	$	16.4	  	 	$	—  	  	 	$	—  	  	 	$	16.4	  
	 Corporate bonds, debentures, short and medium term notes
	 				 	 	—  	  	 	 	34.6	  	 	 	—  	  	 	 	34.6	  
	 Government bonds
	 				 	 	—  	  	 	 	11.7	  	 	 	—  	  	 	 	11.7	  
	 Other investments measured at NAV
	 	 	53.3	  	 				 				 				 	 	53.3	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	$	53.3	  	 	$	16.4	  	 	$	46.3	  	 	$	—  	  	 	$	116.0	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
						
	 As at

millions of Canadian dollars
	 	NAV	 	 	Level 1	 	 	Level 2	 	 	Level 3	 	 	December 31
2014	 
	 Common shares
	 	$	 	  	 	$	13.8	  	 	$	—  	  	 	$	—  	  	 	$	13.8	  
	 Corporate bonds, debentures, short and medium term notes
	 				 	 	—  	  	 	 	36.1	  	 	 	—  	  	 	 	36.1	  
	 Government bonds
	 				 	 	—  	  	 	 	2.8	  	 	 	—  	  	 	 	2.8	  
	 Other investments measured at NAV
	 	 	31.7	  	 				 				 				 	 	31.7	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	$	31.7	  	 	$	13.8	  	 	$	38.9	  	 	$	—  	  	 	$	84.4	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The fair value of financial instruments traded in active markets, and classified as level one, is based on quoted market prices at the
balance sheet date. The quoted market price used for financial assets is the current bid price at the balance sheet date. Fair values within the level two category are determined through the use of quoted prices in active markets for similar assets,
which in some cases, are adjusted for factors specific to the asset. 
 The change in available-for-sale assets is as follows: 

 

									
	 As at

millions of Canadian dollars
	 	December 31
2015	 	 	December 31
2014	 
	 Balance, beginning of the year
	 	$	84.4	  	 	$	74.2	  
	 Additions
	 	 	34.5	  	 	 	30.3	  
	 Disposals
	 	 	(16.5	) 	 	 	(27.1	) 
		 	  
	  
	 	 	  
	  
	 
		 	$	102.4	  	 	$	77.4	  
		 	  
	  
	 	 	  
	  
	 
	 Change in fair value
	 				 			
	 Realized (loss) gain recognized in income
	 	 	—  	  	 	 	(0.8	) 
	 Gain (loss) recognized in other comprehensive income during the period
	 	 	13.6	  	 	 	7.8	  
		 	  
	  
	 	 	  
	  
	 
		 	$	13.6	  	 	$	7.0	  
		 	  
	  
	 	 	  
	  
	 
	 Balance, end of the period
	 	$	116.0	  	 	$	84.4	  
		 	  
	  
	 	 	  
	  
	 

 There were no impairment provisions for available-for-sale investments for the twelve months ended December 31, 2015
(2014 – nil). 
 The maturity profile of debt securities included in the available-for-sale assets is as follows: 

 

									
	 As at

millions of Canadian dollars
	 	December 31
2015	 	 	December 31
2014	 
	 Maturity within 1 year
	 	$	20.0	  	 	$	12.8	  
	 Maturity in 1-5 years
	 	 	26.3	  	 	 	26.1	  
		 	  
	  
	 	 	  
	  
	 
		 	$	46.3	  	 	$	38.9	  
		 	  
	  
	 	 	  
	  
	 

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

  
 67 

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

									
	 millions of Canadian dollars
	  	2015	 	  	2014	 
	 Balance, January 1
	  	$	221.5	  	  	$	206.5	  
	 Impairment (1)
	  	 	—  	  	  	 	(3.3	) 
	 Change in foreign exchange rate
	  	 	42.6	  	  	 	18.3	  
		  	  
	  
	 	  	  
	  
	 
	 Balance, December 31
	  	$	264.1	  	  	$	221.5	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	No goodwill impairment was recorded in 2015. Emera recorded a goodwill impairment charge of $3.3 million in “Operating, maintenance, and general” on the Consolidated Statements of Income during the fourth
quarter of 2014. Emera determined that the operating environment, conditions and performance of the Newfoundland division of Emera Utility Services Inc. could no longer support the related goodwill balance. 

25. OTHER LONG-TERM ASSETS 
 Other long-term assets consisted of the
following: 
  

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Subscription receipts (1)
	  	$	—  	  	  	$	111.7	  
	 Deferred debt financing (2)
	  	 	70.8	  	  	 	23.0	  
	 Capitalized transportation capacity
	  	 	38.7	  	  	 	31.8	  
	 Open Hydro investment
	  	 	10.0	  	  	 	10.0	  
	 Equipment financing receivable
	  	 	28.7	  	  	 	20.5	  
	 Other
	  	 	18.1	  	  	 	8.3	  
		  	  
	  
	 	  	  
	  
	 
		  	$	166.3	  	  	$	205.3	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	In Q4 2015, Emera reclassified outstanding subscription receipts from “Other long-term assets” to Investments subject to significant influence as they became eligible for conversion into APUC common shares.

  

	(2)	As at December 31, 2015, the deferred debt financing asset includes $46.2 million related to the $2.185 billion in Debentures to finance a portion of the pending TECO Energy acquisition. The deferred debt
financing costs related to the Debentures are being amortized over 10 years, the contractual term of the debentures, in Interest expense, net. 

 26.
SHORT-TERM DEBT 
 Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non-revolving credit facilities and
short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of the following: 
  

																	
	 millions of Canadian dollars
	  	2015	 	  	Weighted-
average
interest
rate	 	 	2014	 	  	Weighted-
average
interest
rate	 
	 NSPI
	  				  				 				  			
	 Bank indebtedness
	  	 	15.9	  	  	 	2.70	% 	 	 	2.3	  	  	 	3.00	% 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 GBPC
	  				  				 				  			
	 Bank indebtedness
	  	 	—  	  	  	 	—  	  	 	 	0.1	  	  	 	5.75	% 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Emera Energy
	  				  				 				  			
	 Advances on the non-revolving credit facilities
	  	 	—  	  	  	 	—  	  	 	 	255.2	  	  	 	1.36	% 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Short-term debt
	  	$	15.9	  	  				 	$	257.6	  	  			
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 

  
 68 

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

													
	 millions of Canadian dollars
	  	Maturity	 	  	2015	 	  	2014	 
	 GBPC – revolving credit facility
	  	 	2016	  	  	 	18.0	  	  	 	15.1	  
	 Emera Energy – non-revolving credit facility (1)
	  	 	2014	  	  	 	—  	  	  	 	255.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  				  	 	18.0	  	  	 	270.3	  
		  				  	  
	  
	 	  	  
	  
	 
	 Less:
	  				  				  			
	 Advances under revolving credit facilities
	  				  	 	—  	  	  	 	255.3	  
	 Use of available facilities
	  				  	 	—  	  	  	 	255.3	  
		  				  	  
	  
	 	  	  
	  
	 
	 Available capacity under existing agreements
	  				  	$	18.0	  	  	$	15.0	  
		  				  	  
	  
	 	  	  
	  
	 

  

	(1)	Emera Energy’s non-revolving credit facility was repaid in 2015. 

 The weighted average interest rate on outstanding
short-term debt at December 31, 2015 was 2.70 per cent (2014 – 1.40 per cent). 
 Credit Facilities 

For the purpose of bridge financing for the pending acquisition of TECO Energy, on September 4, 2015, the Company secured an aggregate of US$6.5 billion
non-revolving term credit facilities the (“Acquisition Credit Facilities”) from a syndicate of banks. The non-revolving term credit facilities are comprised of a US$4.3 billion debt bridge facility, repayable in full on the first
anniversary following its advance, and a US$2.2 billion equity bridge facility repayable in full on the first anniversary following its advance. 
 Emera is required
to effect reductions or make prepayments of the Acquisition Credit Facilities in an amount equal to the net cash proceeds from any common equity, preferred equity, bond or other debt offerings and any nonordinary course asset sales by Emera and its
subsidiaries, subject to certain prescribed exceptions and certain other prescribed transactions. Net proceeds from any such offerings, including the net proceeds of the final instalment under the Offering, or from any such non-ordinary course asset
sales or transactions, will be applied to permanently reduce the commitments of the lenders under the Acquisition Credit Facilities or to repay the Acquisition Credit Facilities after they are drawn. On October 16, 2015, Emera permanently
reduced the USD bridge facilities in the amount of $588.3 million USD with the proceeds of the first instalment of the convertible debentures and the proceeds from the Bear Swamp financing. 

The credit agreements pursuant to which the Acquisition Credit Facilities will be extended (the “Acquisition Credit Agreements”) will contain certain
prepayment options in favour of Emera and certain prepayment obligations upon the occurrence of certain events. In particular, the net proceeds of any equity or debt offering by Emera and certain of its subsidiaries (other than certain permitted
equity or debt offerings subject to certain prescribed exceptions) and of any non-ordinary course asset sales (subject to certain prescribed exceptions) and certain other prescribed transactions will be required to be used to prepay the Acquisition
Credit Facilities and any prepayment under the Acquisition Credit Facilities may not be re-borrowed. The Acquisition Credit Agreements will contain customary representations and warranties and affirmative and negative covenants of Emera that will
closely resemble those in Emera’s existing revolving credit facility. 
 Emera has recognized the costs associated with the bridge fees related to the
Acquisition Credit Facilities in “Operating, maintenance and general” on Emera’s Consolidated Statements of Income. 

  
 69 

 27. OTHER CURRENT LIABILITIES 

Other current liabilities consisted of the following: 
  

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Accrued charges
	  	$	130.1	  	  	$	114.1	  
	 Accrued interest on long-term debt
	  	 	44.1	  	  	 	42.4	  
	 Accrued interest on convertible debentures represented by instalment receipts
	  	 	11.2	  	  	 	—  	  
	 Emission credits obligations (1)
	  	 	6.3	  	  	 	20.6	  
	 Sales taxes payable
	  	 	4.2	  	  	 	5.6	  
	 Other
	  	 	8.4	  	  	 	4.1	  
		  	  
	  
	 	  	  
	  
	 
		  	$	204.3	  	  	$	186.8	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for
the related emissions. Emission credits are recorded as inventory (note 14) when purchased and subsequently applied against the emission liabilities at the end of each compliance period. 

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

  
 70 

																					
	 millions of Canadian dollars
	 	Stated
Interest
Rate (1)	 	 	Effective Interest
Rate (2)	 	 	Maturity	 	  	2015	 	  	2014	 
	 Emera
	 				 				 				  				  			
	 Bankers acceptances, LIBOR loans (3)
	 	 	—  	  	 	 	2.00	% 	 	 	2020	  	  	$	239.5	  	  	$	437.2	  
	 Medium-term notes
	 				 				 				  				  			
	 Series G
	 	 	4.83	% 	 	 	4.89	% 	 	 	2019	  	  	 	225.0	  	  	 	225.0	  
	 Series H
	 	 	2.96	% 	 	 	3.05	% 	 	 	2016	  	  	 	250.0	  	  	 	250.0	  
		 				 				 				  	 	475.0	  	  	 	475.0	  
	 Promissory note
	 	 	—  	  	 	 	—  	  	 	 	2016	  	  	 	0.3	  	  	 	0.6	  
	 Capital lease obligations
	 	 	—  	  	 	 	—  	  	 	 	Various	  	  	 	—  	  	  	 	0.2	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
		 				 				 				  	$	714.8	  	  	$	913.0	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
	 NSPI
	 				 				 				  				  			
	 Commercial paper (4)
	 	 	—  	  	 	 	0.85	% 	 	 	2020	  	  	$	369.3	  	  	$	349.1	  
	 Medium-term notes
	 				 				 				  				  			
	 Series F
	 	 	8.85	% 	 	 	8.21	% 	 	 	2025	  	  	 	125.0	  	  	 	125.0	  
	 Series I
	 	 	8.40	% 	 	 	8.43	% 	 	 	2015	  	  	 	—  	  	  	 	70.0	  
	 Series L
	 	 	8.30	% 	 	 	8.88	% 	 	 	2036	  	  	 	60.0	  	  	 	60.0	  
	 Series M (5)
	 	 	8.50	% 	 	 	7.76	% 	 	 	2026	  	  	 	40.0	  	  	 	40.0	  
	 Series N
	 	 	7.60	% 	 	 	7.57	% 	 	 	2097	  	  	 	50.0	  	  	 	50.0	  
	 Series P
	 	 	6.28	% 	 	 	6.28	% 	 	 	2029	  	  	 	40.0	  	  	 	40.0	  
	 Series R
	 	 	7.45	% 	 	 	7.51	% 	 	 	2031	  	  	 	75.0	  	  	 	75.0	  
	 Series S
	 	 	6.95	% 	 	 	7.12	% 	 	 	2033	  	  	 	200.0	  	  	 	200.0	  
	 Series V
	 	 	5.67	% 	 	 	5.71	% 	 	 	2035	  	  	 	150.0	  	  	 	150.0	  
	 Series W
	 	 	5.95	% 	 	 	6.01	% 	 	 	2039	  	  	 	200.0	  	  	 	200.0	  
	 Series X
	 	 	5.61	% 	 	 	5.65	% 	 	 	2040	  	  	 	300.0	  	  	 	300.0	  
	 Series Y
	 	 	4.15	% 	 	 	4.19	% 	 	 	2042	  	  	 	250.0	  	  	 	250.0	  
	 Series Z
	 	 	4.50	% 	 	 	4.57	% 	 	 	2043	  	  	 	300.0	  	  	 	300.0	  
	 Series AA
	 	 	3.61	% 	 	 	3.65	% 	 	 	2045	  	  	 	175.0	  	  	 	—  	  
		 				 				 				  	 	1,965.0	  	  	 	1,860.0	  
	 Debentures – Series 3
	 	 	9.75	% 	 	 	9.99	% 	 	 	2019	  	  	 	95.0	  	  	 	95.0	  
	 Capital lease obligations
	 	 	—  	  	 	 	4.3% & 4.8	% 	 	 	2016 & 2019	  	  	 	0.5	  	  	 	1.0	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
		 				 				 				  	$	2,429.8	  	  	$	2,305.1	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
	 Emera Maine (6)
	 				 				 				  				  			
	 LIBOR loans and demand loans (7)
	 	 	—  	  	 	 	1.71	% 	 	 	2019	  	  	$	31.7	  	  	$	28.7	  
	 General & refunding mortgage bonds (8)
	 				 				 				  				  			
	 $20 million
	 	 	8.98	% 	 	 	8.98	% 	 	 	2022	  	  	 	27.7	  	  	 	23.2	  
	 $30 million
	 	 	10.25	% 	 	 	10.25	% 	 	 	2020	  	  	 	41.5	  	  	 	34.8	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
		 				 				 				  	 	69.2	  	  	 	58.0	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
	 Senior unsecured notes
	 				 				 				  				  			
	 $50 million (9)
	 	 	5.31	% 	 	 	5.31	% 	 	 	2018	  	  	 	18.9	  	  	 	21.1	  
	 $20 million
	 	 	5.87	% 	 	 	5.87	% 	 	 	2017	  	  	 	27.7	  	  	 	23.2	  
	 $110 million
	 	 	4.34	% 	 	 	4.34	% 	 	 	2044	  	  	 	152.2	  	  	 	127.6	  
	 $70 million
	 	 	3.61	% 	 	 	3.61	% 	 	 	2022	  	  	 	96.9	  	  	 	81.2	  
		 				 				 				  	 	295.7	  	  	 	253.1	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
		 				 				 				  	$	396.6	  	  	$	339.8	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
						
	 EBP
	 				 				 				  				  			
	 $250 million
	 	 	3.08	% 	 	 	3.08	% 	 	 	2019	  	  	$	248.5	  	  	$	—  	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
		 				 				 				  	$	248.5	  	  	$	—  	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
	 GBPC (6)
	 				 				 				  				  			
	 Unsecured notes
	 	 	3.44	% 	 	 	3.44	% 	 	 	2022	  	  	$	23.9	  	  	$	23.3	  
	 Unsecured notes
	 	 	3.70	% 	 	 	3.70	% 	 	 	2021	  	  	 	52.5	  	  	 	50.6	  
	 Bond notes
	 	 	6.96	% 	 	 	6.96	% 	 	 	2020	  	  	 	30.4	  	  	 	25.5	  
	 Bond notes
	 	 	7.16	% 	 	 	7.16	% 	 	 	2023	  	  	 	38.8	  	  	 	32.5	  
		 				 				 				  	  
	  
	 	  	  
	  
	 
		 				 				 				  	$	145.6	  	  	$	131.9	  
		 				 				 				  	  
	  
	 	  	  
	  
	 

  
 71 

																					
	 BLPC & ECI
	  				 				 				  				 			
	 Senior secured notes
	  				 				 				  				 			
	 $19.2 million(10)
	  	 	6.50	% 	 	 	7.00	% 	 	 	2021	  	  	$	10.8	  	 	$	10.1	  
	 $20 million(10)
	  	 	6.65	% 	 	 	6.65	% 	 	 	2020	  	  	 	13.8	  	 	 	11.6	  
	 $20 million(10)
	  	 	6.88	% 	 	 	6.88	% 	 	 	2025	  	  	 	13.8	  	 	 	11.6	  
	 $2.0 million(11)
	  	 	5.99	% 	 	 	5.99	% 	 	 	2015	  	  	 	—  	  	 	 	1.2	  
	 $7.1 million(6)(12)
	  	 	2.37	% 	 	 	2.37	% 	 	 	2015	  	  	 	—  	  	 	 	2.8	  
	 $10.1 million(6)(12)
	  	 	4.31	% 	 	 	4.31	% 	 	 	2028	  	  	 	12.0	  	 	 	10.9	  
	 $50.5 million(13)
	  	 	5.75	% 	 	 	5.75	% 	 	 	2021	  	  	 	16.2	  	 	 	15.7	  
	 $16.0 million(6)
	  	 	4.50	% 	 	 	4.58	% 	 	 	2020	  	  	 	22.5	  	 	 	—  	  
		  				 				 				  	  
	  
	 	 	  
	  
	 
	 Other
	  				 				 				  	 	0.3	  	 	 	0.5	  
		  				 				 				  	  
	  
	 	 	  
	  
	 
		  				 				 				  	$	89.4	  	 	$	64.4	  
		  				 				 				  	  
	  
	 	 	  
	  
	 
	 Adjustments
	  				 				 				  				 			
	 Unamortized debt premium – net
	  				 				 				  	 	0.1	  	 	 	0.6	  
	 Amount due within one year
	  				 				 				  	 	(274.0	) 	 	 	(94.5	) 
		  				 				 				  	  
	  
	 	 	  
	  
	 
		  				 				 				  	$	(273.9	) 	 	$	(93.9	) 
		  				 				 				  	  
	  
	 	 	  
	  
	 
	 Long-Term Debt
	  				 				 				  	$	3,750.8	  	 	$	3,660.3	  
		  				 				 				  	  
	  
	 	 	  
	  
	 

  

	(1)	The stated interest rate is the coupon rate for any long term debt issuance. 

	(2)	The effective interest rate is the constant rate which will fully amortize the premium/discount and issuance costs over the life of the associated debt when the rate is applied against the net amount of debt less
unamortized costs. 

	(3)	Emera’s revolving credit facility matures in June 2020, at which point the Company has the intention to renew under similar terms. The credit facility can be extended annually with the approval of the syndicated
banks. 

	(4)	NSPI’s commercial paper is backed by a revolving credit facility, which matures in 2020. 

	(5)	Note is extendable until 2056 at the option of the holders. 

	(6)	Debt issued and payable in USD. 

	(7)	Emera Maine’s revolving credit facility matures in September 2019, at which point the Company has the intention to renew under similar terms. 

	(8)	Secured by property, plant and equipment of Emera Maine. 

	(9)	Sinking fund payments began in 2008. 

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

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

	(12)	Cash security in the form of security deposit. 

	(13)	Issued and payable in East Caribbean dollars. Fixed charge over property of Domlec. 

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

													
	 millions of Canadian dollars
	  	Maturity	 	  	2015	 	  	2014	 
	 Emera – revolving credit facility (1)
	  	 	June 2020	  	  	$	700.0	  	  	$	700.0	  
	 NSPI – revolving credit facility (1)
	  	 	October 2020	  	  	 	500.0	  	  	 	500.0	  
	 Emera Maine – revolving credit facility
	  	 	September 2019	  	  	 	110.7	  	  	 	92.8	  
	 BLPC – revolving credit facility
	  	 	2017-2021	  	  	 	26.3	  	  	 	22.0	  
		  				  	  
	  
	 	  	  
	  
	 
	 Total
	  				  	 	1,337.0	  	  	 	1,314.8	  
		  				  	  
	  
	 	  	  
	  
	 
	 Less:
	  				  				  			
	 Borrowings under credit facilities
	  				  	 	641.3	  	  	 	816.2	  
	 Letters of credit issued inside credit facilities
	  				  	 	33.1	  	  	 	13.4	  
		  				  	  
	  
	 	  	  
	  
	 
	 Use of available facilities
	  				  	 	674.4	  	  	 	829.6	  
		  				  	  
	  
	 	  	  
	  
	 
	 Available capacity under existing agreements
	  				  	$	662.6	  	  	$	485.2	  
		  				  	  
	  
	 	  	  
	  
	 

  

	(1)	Advances on the revolving credit facility can be made by way of overdraft on accounts up to $50 million. 

 Credit
Facilities 
 NSPI 
 On April 30, 2015, NSPI completed the issuance
of $175 million Series AA Medium-Term Notes (“MTN”). The Series AA notes bear interest at a rate of 3.612 per cent per annum until May 1, 2045. The proceeds of the note offering were used for general corporate purposes,
including the repayment of maturing corporate term debt. 

  
 72 

 NSPI Series I $70 million 8.40 per cent MTN matured on October 23, 2015. 

Brunswick Pipeline 
 On February 18, 2015, Brunswick Pipeline completed a
senior secured financing consisting of a $250 million non-revolving term credit facility bearing interest at bankers’ acceptances rates plus 1.75 per cent and expiring on February 18, 2019. The proceeds were used to reduce borrowings
under Emera’s revolver, which was previously used to finance the maturity and repayment of a MTN note in October 2014. 
 Debt Covenants 

Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant
requirements. Emera’s significant covenants are listed below: 
  

									
	 	  	Financial Covenant	  	Requirement	  	As at
December 31, 2015	 
	 Emera
	  		  		  			
	 Syndicated credit facilities
	  	Debt to capital ratio	  	Less than or equal to 0.70 to 1	  	 	0.51:1	  

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

																													
	 millions of Canadian dollars
	  	2016	 	  	2017	 	  	2018	 	  	2019	 	  	2020	 	  	Greater
than
5 years	 	  	Total	 
	 Emera
	  	$	250.3	  	  	$	—  	  	  	$	—  	  	  	$	225.0	  	  	$	239.5	  	  	$	—  	  	  	$	714.8	  
	 NSPI
	  	 	0.3	  	  	 	0.1	  	  	 	0.1	  	  	 	95.0	  	  	 	369.3	  	  	 	1,965.0	  	  	 	2,429.8	  
	 EBP
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	248.5	  	  	 	—  	  	  	 	—  	  	  	 	248.5	  
	 Emera Maine
	  	 	6.3	  	  	 	34.0	  	  	 	6.3	  	  	 	31.7	  	  	 	41.5	  	  	 	276.8	  	  	 	396.6	  
	 GBPC
	  	 	11.8	  	  	 	11.8	  	  	 	11.8	  	  	 	11.8	  	  	 	42.2	  	  	 	56.2	  	  	 	145.6	  
	 BLPC
	  	 	5.3	  	  	 	7.1	  	  	 	7.3	  	  	 	7.6	  	  	 	36.2	  	  	 	25.6	  	  	 	89.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	274.0	  	  	$	53.0	  	  	$	25.5	  	  	$	619.6	  	  	$	728.7	  	  	$	2,323.6	  	  	$	4,024.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 29. ASSET RETIREMENT OBLIGATIONS 
 AROs mostly
relate to the reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets
may have additional ARO that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the fair value of any related ARO cannot be made. 

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

									
	 millions of Canadian dollars
	  	2015	 	 	2014	 
	 Balance, January 1
	  	$	106.2	  	 	$	98.6	  
	 Liabilities settled
	  	 	(1.5	) 	 	 	(1.4	) 
	 Accretion included in depreciation expense
	  	 	7.6	  	 	 	7.6	  
	 Accretion deferred to regulatory asset (included in property, plant and equipment)
	  	 	(2.4	) 	 	 	(2.4	) 
	 Revisions in estimated cash flows
	  	 	4.1	  	 	 	3.6	  
	 Change in foreign exchange rate
	  	 	0.7	  	 	 	0.2	  
		  	  
	  
	 	 	  
	  
	 
	 Balance, December 31
	  	$	114.7	  	 	$	106.2	  
		  	  
	  
	 	 	  
	  
	 

  
 73 

 As at December 31, 2015 and 2014, some of the Company’s transmission and distribution assets may have additional
conditional ARO which are not recognized in the financial statements as the fair value of these obligations could not be reasonably estimated, given there is insufficient information to do so. Management will continue to monitor these obligations
and a liability will be recognized in the period in which an amount becomes determinable. 
 30. CONVERTIBLE DEBENTURES REPRESENTED BY INSTALMENT RECEIPTS 

To finance a portion of the pending acquisition of TECO Energy, Emera, through a direct wholly owned subsidiary (the “Selling Debentureholder”), on
September 28, 2015, completed the sale of $1.9 billion aggregate principal amount of 4.0% convertible unsecured subordinated debentures, represented by instalment receipts (the “Debentures” or the “Debenture Offering”). 

On October 2, 2015, in connection with the Debenture Offering, the underwriters fully exercised an over-allotment option and purchased an additional $285 million
aggregate principal amount of Debentures at the Debenture Offering price. The sale of the additional Debentures brought the aggregate proceeds of the Debenture Offering to $2.185 billion, assuming payment of the final instalment. 

The Debentures were sold on an instalment basis at a price of $1,000 per Debenture, of which 

$333 was paid on closing of the Debenture Offering and the remaining $667 (the “Final Instalment”) is payable on a date (“Final Instalment Date”) to
be fixed following satisfaction of conditions precedent to the closing of the acquisition of TECO Energy. 
 Prior to the Final Instalment Date, the Debentures are
represented by instalment receipts. The instalment receipts began trading on the Toronto Stock Exchange (“TSX”) on September 28, 2015 under the symbol “EMA.IR”. The Debentures will not be listed. The Debentures will mature
on September 29, 2025 and bear interest at an annual rate of four per cent per $1,000 principal amount of Debentures until and including the Final Instalment Date, after which the interest rate will be 0 per cent. Based on the first instalment
of $333 per $1,000 principal amount of Debentures, the effective annual yield to and including the Final Instalment Date is 12 per cent, and the effective annual yield thereafter is 0 per cent. 

If the Final Instalment Date occurs on a day that is prior to the first anniversary of the closing of the Debenture Offering, holders of Debentures who have paid the
final instalment on or before the Final Instalment Date will be entitled to receive, on the business day following the Final Instalment Date, in addition to the payment of accrued and unpaid interest to and including the Final Instalment Date, an
amount equal to the interest that would have accrued from the day following the Final Instalment Date to and including the first anniversary of the closing of the Debenture Offering had the Debentures remained outstanding and continued to accrue
interest until and including such date (the “Make-Whole Payment”). No Make-Whole Payment will be payable if the Final Instalment Date occurs on or after the first anniversary of the closing of the Debenture Offering. Under the terms of the
instalment receipt agreement, Emera agreed that until such time as the Debentures have been redeemed in accordance with the foregoing or the Final Instalment Date has occurred, the Company will at all times hold (on a consolidated basis) short-term
USD investment grade securities or have cash on hand of not less than the aggregate amount of the first instalment paid on the closing of the Debenture Offering and the exercise of the over-allotment option, in the event of a mandatory redemption.

 At the option of the holders and provided that payment of the Final Instalment has been made, each 

Debenture will be convertible into common shares of Emera at any time after the Final Instalment Date, but prior to the earlier of maturity or redemption by the
Company, at a conversion price of $41.85 per common share. This is a conversion rate of 23.8949 common shares per $1,000 principal amount of Debentures, subject to adjustment in certain events. 

Prior to the Final Instalment Date, the Debentures may not be redeemed by the Company, except that Debentures will be redeemed by the Company at a price equal to their
principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions precedent to the 

  
 74 

 
closing of the acquisition of TECO Energy will not be satisfied; (ii) termination of the acquisition agreement; and (iii) April 24, 2017, if notice of the Final Instalment Date has
not been given to holders on or before April 21, 2017. Upon any such redemption, the Company will pay for each Debenture: (i) $333 plus accrued and unpaid interest to the holder of the instalment receipt; and (ii) $667 to the Selling
Debentureholder on behalf of the holder of the instalment receipt in satisfaction of the Final Instalment. In addition, after the Final Instalment Date, any Debentures not converted may be redeemed by Emera at a price equal to their principal amount
plus any unpaid interest which accrued prior to and including the Final Instalment Date. 
 At maturity, Emera will repay the principal amount of any Debentures not
converted and remaining outstanding in cash. Emera has the right to satisfy the obligation to repay the principal amount due in common shares, which will be valued at 95 per cent of the weighted-average trading price on the Toronto Stock
Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date. 
 The proceeds of the first instalment and the overallotment of
the Debenture Offering were $727.6 million, or $681.4 million net of issue costs, and are held and invested in short-term USD investment grade securities. The convertible debentures represented by instalment receipts are classified as a current
liability on the Consolidated Balance Sheets as the pending acquisition of TECO Energy is expected to close in fiscal 2016. The mark-to-market effect related to the translation of the US foreign currency to Canadian currency is recorded in income,
but not reflected in adjusted net income. 
 The net proceeds of the final instalment payment of the Debenture Offering are expected to be, in aggregate,
approximately $1.4 billion and will be used, together with the net proceeds of the first instalment payment, to finance, directly or indirectly, the pending acquisition of TECO Energy and other acquisition related costs. To mitigate the foreign
currency translation risk associated with the final instalment Emera entered into USD denominated forward contracts, which are recorded on the Consolidated Balance Sheets. The mark-to-market effect on these hedges is reported in the income statement
and impacts income, but is not reflected in adjusted income. 
 Approximately $22.1 million ($15.2 million after-tax) in interest expense associated with the
Debentures was recognized in Q4 2015 and $22.7 million ($15.7 million after-tax) was incurred during fiscal 2015 (2014 – nil) (note 8). 
 31. OTHER LONG-TERM
LIABILITIES 
 Other long-term liabilities consisted of the following: 
  

									
	As at	  	December 31	 	  	December 31	 
	 millions of Canadian dollars
	  	2015	 	  	2014	 
	 Funds received in excess of equity investment(1)
	  	$	225.0	  	  	$	20.8	  
	 Long-term service agreements
	  	 	37.7	  	  	 	—  	  
	 Hydro-Quebec obligation
	  	 	7.6	  	  	 	6.8	  
	 Emission credits obligations(2)
	  	 	6.3	  	  	 	—  	  
	 Other
	  	 	21.9	  	  	 	20.7	  
		  	  
	  
	 	  	  
	  
	 
		  	$	298.5	  	  	$	48.3	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	Emera has a 50 per cent investment in Bear Swamp. As at December 31, 2015 and 2014, the investment balance in Bear Swamp was a credit. The 2015 and 2014 balances have been restated. The credit investment
balance is primarily a result of a $178.7 million distribution received in Q4 2015. 

	(2)	Throughout the three-year compliance period associated with the Regional Greenhouse Gas Initiative for carbon dioxide emissions, an obligation is recognized as gas is burned, measured at the cost to acquire credits for
the related emissions. Emission credits are capitalized to inventory (note 14) when purchased and subsequently applied against the emission liabilities at the end of each compliance period. 

  
 75 

 32. COMMITMENTS AND CONTINGENCIES 

A. Commitments 
 As at December 31, 2015, contractual commitments
(excluding pensions and other post-retirement obligations, convertible debentures represented by instalment receipts, long-term debt and AROs) for each of the next five years and in aggregate thereafter consisted of the following: 

 

																													
	 millions of Canadian dollars
	  	2016	 	  	2017	 	  	2018	 	  	2019	 	  	2020	 	  	Thereafter	 	  	Total	 
	 Purchased power (1)
	  	$	221.7	  	  	$	235.0	  	  	$	208.6	  	  	$	203.1	  	  	 	199.4	  	  	$	2,462.8	  	  	$	3,530.6	  
	 Coal, biomass, oil and natural gas supply
	  	 	150.2	  	  	 	82.1	  	  	 	12.2	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	244.5	  
	 DSM (2)
	  	 	24.7	  	  	 	34.0	  	  	 	34.9	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	93.6	  
	 Transportation (3)
	  	 	183.6	  	  	 	72.2	  	  	 	55.8	  	  	 	25.7	  	  	 	20.9	  	  	 	86.9	  	  	 	445.1	  
	 Long-term service agreements (4)
	  	 	56.6	  	  	 	45.0	  	  	 	33.6	  	  	 	55.7	  	  	 	18.4	  	  	 	207.1	  	  	 	416.4	  
	 Capital projects
	  	 	68.9	  	  	 	7.1	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	76.0	  
	 Equity investment commitments (5)
	  	 	379.6	  	  	 	159.0	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	538.6	  
	 Leases and other (6)
	  	 	12.6	  	  	 	11.6	  	  	 	9.5	  	  	 	8.9	  	  	 	7.5	  	  	 	27.5	  	  	 	77.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	$	1,097.9	  	  	$	646.0	  	  	$	354.6	  	  	$	293.4	  	  	$	246.2	  	  	$	2,784.3	  	  	$	5,422.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	(1)	Purchased power: annual requirement to purchase 20–100 per cent of electricity production from independent power producers over varying contract lengths up to 25 years. 

	(2)	DSM: program is expected to continue however no amounts have been committed after 2018. 

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

	(4)	Long-term service agreements: maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and
vegetation management. 

	(5)	Emera has a commitment in connection with the Federal Loan Guarantee (“FLG”) to complete construction of the Maritime Link. Thirty per cent of the financing of this project will come from Emera as equity.
Emera also has a commitment to make equity contributions to the Labrador Island Link Limited Partnership upon draw requests from the general partner. The amounts forecasted are a combination of equity investments for both projects and are subject to
change in both timing and amounts as the projects advance through construction. 

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

B. Legal Proceedings 
 Emera 

Between September 16, 2015 and November 2, 2015, purported shareholders of TECO Energy filed twelve separate complaints styled as class action lawsuits in the
Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County, Florida or the United States District Court for the Middle District of Florida (the “Merger Litigation”). Each complaint alleges, among other things, that
the Board of Directors of TECO Energy breached its fiduciary duties in agreeing to the acquisition agreement and that Emera and/or Emera US Inc. aided and abetted such alleged breaches. The complaints seek to enjoin the merger pursuant to the
acquisition agreement. 
 On November 17, 2015, TECO Energy, Emera, Emera US Inc. and the Board of Directors of TECO Energy entered into a memorandum of
understanding with the shareholder plaintiffs to settle all of the Merger Litigation, subject to negotiation of a stipulation of settlement with the plaintiffs and to court approval. The memorandum of understanding provides for all claims
against the defendants to be released in exchange for TECO Energy making certain additional disclosures to its shareholders related to the proposed merger (which have now been made). 

There is no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to
enter into a stipulation of settlement.

  
 76 

 Emera Maine 
 On
September 30, 2011, a group including the Attorney General of Massachusetts, New England utilities commissions, state public advocates and end users filed a complaint with the Federal Energy Regulatory Commission (“FERC”) alleging
that the 11.14 per cent base return on equity (“ROE”) under the ISO-New England (ISO-NE) Open Access Transmission Tariff (“OATT”) was unjust and unreasonable. On June 19, 2014, the FERC issued an order in
connection with this complaint, changing the methodology used to set the ROE for transmission assets.
 This change would lower the base transmission ROE to
10.57 per cent for the period of October 1, 2011 to December 31, 2012, subject to a further proceeding to finalize the determination of appropriate rates to be used in such calculation. The FERC decision would also lower the cap
on the total ROE (inclusive of incentive adders) for transmission assets to 11.74 per cent. In an order issued on October 16, 2014, the FERC confirmed that the ROE set in its earlier order was appropriate. On March 3, 2015, in
response to requests for rehearing from several parties, FERC affirmed its initial Order, setting of the base ROE of 10.57 per cent and capping the total ROE, including the effect of incentive adders, at 11.74 per cent. Notices of Appeal
to the U.S. Court of Appeals for the DC Circuit were filed by New England Transmission Owners and the Complainants in the case on April 30, 2015. In Q2 2015, Emera Maine began processing the refunds to customers, based on a 10.57 per cent
ROE. By court order dated August 20, 2015, the DC Court of Appeals decided to hold the appeal of this case in abeyance pending the outcome of the consolidated cases (“ENE Case” and “MA AG II Case”) discussed below. 

On December 27, 2012, a second group of consumer advocates, including Environment Northeast, filed a complaint with the FERC on similar grounds, arguing that the
11.14 per cent base ROE under the OATT was unjust and unreasonable (“the ENE Case”). On June 19, 2014, the FERC issued an order in this second ROE case, finding in favour of the complainants and allowing the complaint to proceed.
As a result, a new ROE will be calculated and set by the FERC. This complaint created a new 15-month refund period beginning January 1, 2013 through March 31, 2014. 

On July 31, 2014, a group of state commissions, state public advocates and end users filed a third complaint with the FERC alleging the ROE earned on transmission
investments is unjust and unreasonable and does not reflect current economic conditions (“the MA AG II Case”). Any potential refund arising from this third complaint will relate to the period from July 31, 2014 to
September 30, 2015, and the outcome will set the ROE going forward from the date of decision. 
 On November 24, 2014, the FERC consolidated the ENE Case
and MA AG II Case. A subsequent order by the FERC established a schedule for various procedural matters that turned the case over to an Administrative Law Judge in September 2015. Once that judge’s recommended decision is rendered, parties
may file exceptions, and then the case is set for decision by the FERC. A decision is therefore not expected until Q1 2016 at the earliest. 
 Emera Maine has
recorded a reserve of $6.9 million pre-tax ($5.0 million USD) (2014 – $8.5 million) for the base transmission ROE rate refund complaints for the period of October 1, 2011 to May 31, 2015. The reserves recorded for these
complaints have been recorded as a component of Regulatory Liabilities on the Consolidated Balance Sheets, and the charges to earnings have been a reduction to Operating revenues – regulated on the Consolidated Statements of Income. 

Other Legal Proceedings 
 Emera and its subsidiaries may, from time to time,
be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company. 

  
 77 

 C. Environment 
 Emera’s
activities are subject to a broad range of federal, provincial, state, regional and local laws and environmental regulations, designed to protect, restore and enhance the quality of the environment including air, water and solid waste. Emera
estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations will be approximately $43.2 million during fiscal 2015 and are estimated to be $63.9 million from 2016 through 2019. Amounts
that have been committed to are included in “Capital projects” in the commitments table in note 32A. The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement
policies that may be enacted in response to issues such as climate change and other pollutant emissions. 
 NSPI 

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

Conformance with legislative and NSPI internal requirements is verified through a comprehensive environmental audit program. There were no significant environmental or
regulatory compliance issues identified during the audits completed to December 31, 2015. 
 Emera Energy Emissions 

The New England Gas Generating Facilities are subject to the Regional Greenhouse Gas Initiative (“RGGI”) for carbon dioxide emissions and the Acid Rain Program
for sulphur dioxide emissions. The New England Gas Generating Facilities emit approximately two million tons of carbon dioxide per year. The amount of sulphur dioxide emitted is not considered significant. Changes to these emissions
programs could adversely impact financial and operational performance. 
 Poly Chlorinated Bi-Phenol Transformers 

In response to the Canadian Environmental Protection Act 1999, 2008 Poly Chlorinated Bi-Phenol (“PCB”) Regulations to phase out electrical equipment and
liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other oil-filled electrical equipment on its system that do not meet the 2008 PCB Regulations Standard by the end of 2025. This also includes PCB contaminated pole
mounted transformers. The combined total cost of these projects is estimated to be $40.1 million and, as at December 31, 2015, approximately $19.7 million (December 31, 2014 – $14.8 million) has been spent to date. NSPI has recognized
an ARO of $15.0 million as at December 31, 2015 (December 31, 2014 – $11.8 million) associated with the PCB phase-out program. 
 D. Principal Risks
and Uncertainties 
 In this section, Emera describes some of the principal risks management believes could materially affect Emera’s business, revenues,
operating income, net income, net asset or liquidity or capital resources. The nature of risk is such that no list can be comprehensive, and other risks may arise, or risks not currently considered material may become material in the future. 

Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has a business-wide
risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach. 

  
 78 

 Regulatory and Political Risk 

The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments in a
timely manner. As cost-of-service utilities with an obligation to serve, NSPI, Emera Maine, BLPC, GBPC and Domlec must obtain regulatory approval to change electricity rates and/or riders from their respective regulators. Costs and investments can
be recovered upon the respective regulator’s approval of the recovery in adjustments to rates and/or riders, which normally requires a public hearing process or may be mandated by other governmental bodies. In addition, the commercial and
regulatory frameworks under which Emera and its subsidiaries operate can be impacted by significant shifts in government policy and changes in governments. Emera has certain investments subject to significant influence that are subject to regulatory
risk and include: APUC, M&NP, NSPML, LIL and Lucelec. 
 During public hearing processes, consultants and customer representatives scrutinize the costs, actions
and plans of these subsidiaries and their respective regulators determine whether to allow recovery and to adjust rates based upon the subsidiaries’ evidence and any contrary evidence from other parties. In some circumstances, other government
bodies may influence the setting of rates. The subsidiaries manage this regulatory risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations,
fuel-related audits, rate filings and capital plans. The subsidiaries employ a collaborative regulatory approach through technical conferences and, where appropriate, negotiated settlements. 

In November 2014, the Federal Energy Regulatory Commission (“FERC”) commenced an audit covering the 2013 and 2014 period of Bangor Hydro Electric
Company’s (“BHE”) compliance with conditions established in FERC’s orders authorizing its acquisition of Maine Public Service Company (“MPS”), which occurred on January 1, 2014. These two predecessor companies
formed Emera Maine. The final audit report was released in early January 2016. The findings in the audit report conclude that Emera Maine did not follow the prescribed methodology for the calculation of AFUDC during the audit period and Emera Maine
had included, in rates, costs of the BHE and MPS merger prior to making the required filings. Emera Maine will fully comply with the recommendations in the audit report, including making the required filings for the merger costs and recalculating
AFUDC for 2013 and 2014, as ordered, which resulted in an immaterial impact on the Company’s Consolidated Statements of Income. 
 Brunswick Pipeline entered
into a 25-year firm service agreement with Repsol Energy Canada, which was filed with the NEB. The firm service agreement provides for predetermined toll increases after the fifth and fifteenth year of the contract. As a regulated Group II pipeline,
the tolls of Brunswick Pipeline are regulated by the NEB on a complaint basis. Brunswick Pipeline is required to make copies of tariffs and supporting financial information readily available to interested persons. Persons who cannot resolve traffic,
toll and tariff issues with Brunswick Pipeline may file a complaint with the NEB. In the absence of a complaint, the NEB does not normally undertake a detailed examination of Brunswick Pipeline’s tolls. 

Changes in Environmental Legislation 
 Emera is subject to regulation by
federal, provincial, state, regional and local authorities with regard to environmental matters; primarily related to its utility operations. This includes laws setting greenhouse gas emissions standards and air emissions standards. Emera is also
subject to laws regarding the generation, storage, transportation, use and disposal of hazardous substances and materials. 
 In addition to imposing continuing
compliance obligations, there are permit requirements, laws and regulations authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future
environmental requirements is, and may be, material to Emera. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera. 

New emission reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to greenhouse gas emissions

  
 79 

 
standards and air emissions standards could adversely affect Emera’s operations and financial performance. Stricter environmental laws and enforcement of such laws in the future could
increase Emera’s exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and timing of capital investments. 

Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and with the objective of achieving full compliance
with applicable laws, legislation and company policies and standards. Emera has implemented this policy through the development and application of environmental management systems in its operating subsidiaries. Comprehensive audit programs are also
in place to regularly test compliance with such laws, policies and standards. 
 Commercial Relationships 

The Company is exposed to commercial relationship risk in respect of its reliance on certain key partners, supplies and customers. The company manages its commercial
relationship risk by monitoring credit risk, and monitoring of significant developments with its customers, partners and suppliers. 
 ENL 

Emera and Nalcor Energy executed agreements pertaining to the development and transmission of hydroelectric power from Muskrat Falls in Labrador to the island of
Newfoundland, the Province of Nova Scotia and through to New England. In exchange for the Company’s investment in the Maritime Link Project, estimated to be approximately $1.56 billion, Nalcor has agreed to provide 20 per cent of the
output of the Muskrat Falls generating station. 
 Labour Risk 
 Certain
Emera employees are subject to collective labour agreements; 49 per cent of the full-time and term employees within the Emera group of companies are represented by local unions. 

Approximately 7 per cent of Emera’s work force is included in collective labour agreements which will expire within the next 12 months. 

Interest Rate Risk 
 The Company utilizes a combination of fixed and floating
rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. The Company seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with
staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. 

For the Company’s regulated subsidiaries, the cost of debt is generally passed through to ratepayers. While regulatory ROE rates will generally and indirectly
follow the direction of interest rates, regulatory ROE’s are likely to fall in times of reducing interest rates and raise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory
process. Rising interest rates may also negatively affect the economic viability of project development initiatives. 
 The Company is subject to interest rate risk
relating to certain sources of expected funds to effect the TECO Energy acquisition. Any movement in interest rates could affect the underlying cost of the instrument used to fund the acquisition. The Company may enter into interest rate hedging
contracts to limit its exposure to fluctuations in interest rates. 

  
 80 

 Commodity Prices and Foreign Exchange Rate Fluctuations 

A substantial amount of the Company’s fuel supply comes from international suppliers and is subject to commodity price risk. Fuel contracts may be exposed to
broader global conditions which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts. In addition, the adoption
and implementation of FAMs in certain subsidiaries has further helped manage this risk. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs. 

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

 The cash consideration for the TECO Energy acquisition is required to be paid in US dollars, a portion of which will be raised in Canadian dollars. As a result,
increases in the value of the US dollar versus the Canadian dollar will increase the purchase price translated in Canadian dollars and thereby increase the Canadian dollars required to fund the USD purchase price for the acquisition ultimately
obtained by the Company. 
 The proceeds of the first instalment of the Debenture Offering were invested in short-term US dollar investment grade securities. 

During the month of October 2015, Emera entered into foreign exchange forward contracts to economically hedge an amount equal to the anticipated proceeds from the
second instalment of the Debenture Offering of the pending TECO Energy acquisition of $1.457 billion. These foreign exchange forward contracts are economic hedges and do not qualify for hedge accounting. Therefore, all mark-to-market gains and
losses will be recognized in net income for the period. In addition, the operations of TECO Energy are conducted in US dollars. Following the acquisition, the consolidated net income of Emera will be impacted to a greater extent by movements in the
US dollar relative to the Canadian dollar. 
 E. Guarantees and Letters of Credit 

Emera had outstanding the following guarantees and letters of credit on behalf of third parties which are not included within the Consolidated Balance Sheets as at
December 31, 2015: 
  

	 	•	 	Emera has provided a completion guarantee to the Government of Canada, whereby it has guaranteed the performance of the obligations of NSPML to cause the completion of the Maritime Link Project, subject to certain
conditions set out in that guarantee. The cost of those obligations is estimated to be $1.577 billion, which reduces in the ordinary course as project costs are paid. 

 

	 	•	 	Emera has provided a guarantee to the Long Island Power Authority (“LIPA”) on behalf of Bear Swamp for Bear Swamp’s long-term energy and capacity supply agreement (“PPA”) with LIPA, which
expires on April 30, 2021. The guarantee is for 50 per cent of the relevant obligations under the PPA up to a maximum of $5.1 million USD. As at December 31, 2015, the fair value of the PPA was positive. 

 

	 	•	 	Standby letters of credit in the amount of $20.5 million USD for the benefit of secured parties in connection with a refinancing of the Bear Swamp joint venture and also to third parties that have extended credit to
Emera and its subsidiaries. These letters of credit typically have a one-year term and are renewed annually as required.

  

	 	•	 	A standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2016 and is renewed annually. The amount committed as at December 31, 2015 was
$42.6 million.

  
 81 

	 	•	 	A standby letter of credit to secure obligations under an unfunded pension plan in Emera Maine. The letter of credit expires in October 2016 and is renewed annually. The amount committed as at December 31, 2015 was
$2.7 million USD.

  

	 	•	 	A standby letter of credit was issued to secure the obligations of Emera Reinsurance Limited under reinsurance agreements. The letter of credit expires in February 2016. The amount committed as at
December 31, 2015 was $2.0 million USD. 

 F. Collaborative Arrangements 

NSPI 
 Through NSPI, the Company is a participant in a 23.3 megawatt (“MW”)
wind energy project with Renewable Energy Services Ltd. in Point Tupper, Nova Scotia. Percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets with NSPI
owning 47.4 per cent. NSPI has a power purchase arrangement to purchase the entire net output of the project and, therefore, NSPI’s portion of the revenues are recorded net, within regulated fuel for generation and purchased power.
NSPI’s portion of operating expenses are recorded in operating, maintenance and general (“OM&G”) expenses. In 2015, NSPI recognized $2.8 million net expense (2014 – $3.0 million) in “Regulated fuel for generation
and purchased power” and $0.5 million (2014 – $0.5 million) in “OM&G”. As part of this arrangement, NSPI received a portion of an Eco Energy revenue claim totaling $0.3 million in 2015. 

Through NSPI, the Company is a participant in a 102 MW wind energy project with South Canoe Development Partnership for South Canoe Wind Farm, in New Ross, Nova
Scotia. Percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets, with NSPI owning not more than 49 per cent. NSPI has a power purchase arrangement to
purchase the entire net output of the project and therefore NSPI’s portion of the revenues are recorded net, within “Regulated fuel for generation and purchased power”. NSPI’s portion of operating expenses, are recorded in
“OM&G”. The project went reached commercial operation in Q2 2015. In 2015, NSPI recognized a $6.4 million net expense in “Regulated fuel for generation and purchased power” and $1.1 million in “OM&G”. 

Through NSPI, the Company is a participant in a 13.8 MW wind energy project with Municipality of the District of Guysborough for Sable Wind Farm, near Canso, Nova
Scotia. Percentage ownership of the wind farm will be based on the relative value of each party’s project assets by the total project assets, with NSPI owning not more than 49 per cent. NSPI’s has a power purchase arrangement to
purchase the entire net output of the project and therefore NSPI’s portion of the revenues are recorded net, within “Regulated fuel for generation and purchased power”. NSPI’s portion of operating expenses, are recorded in
“OM&G”. The project went reached commercial operation in Q2 2015. In 2015, NSPI recognized a $1.0 million net expense in “Regulated fuel for generation and purchased power” and $0.1 million in “OM&G”.

 Emera Maine 
 Through Emera Maine, the Company is a party to a collaborative
arrangement with National Grid Transmission Services Corporation to develop the Northeast Energy Link (“NEL”) Project. The cost of development activities, including acquisition of land in the transmission corridor and acquisition of
necessary governmental and regulatory permits and approvals, are shared equally between the Company and National Grid. Emera Maine has deferred $4.6 million ($3.3 million USD) of costs associated with the NEL project as at
December 31, 2015 (December 31, 2014 – $3.6 million), reported in the Consolidated Balance Sheets in “Other” as part of “Other long-term assets”. 

Through Emera Maine, the Company is a party to a collaborative arrangement with EDP Renewables (“EDPR”), Central Maine Power (“CMP”) and Maine
Electric Power Company Inc. (“MEPCO”) related to 

  
 82 

 
construction of an electric transmission line in Northern Maine. Emera Maine and CMP retain an option to buy-back the transmission line as part of a larger solution to collect further quantities
of wind generation being pursued for development in Northern Maine, for delivery into the ISO-NE market. CMP and Emera Maine agreed to pursue this regional solution together per a Memorandum of Understanding (“MOU”) signed in May
2014. As at December 31, 2015, Emera Maine had deferred $1.4 million ($1.0 million USD) (December 31, 2014 – $1.2 million) associated with this development. 

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

																	
	 	  	2015	 	 	2014	 
	 Issued and outstanding:
	  	millions of
shares	 	  	millions of
Canadian
dollars	 	 	millions of
shares	 	  	millions of
Canadian
dollars	 
	 Balance, January 1
	  	 	143.78	  	  	$	2,016.4	  	 	 	132.89	  	  	$	1,703.0	  
	 Issuance of common stock (1)
	  	 	1.25	  	  	 	53.7	  	 	 	8.66	  	  	 	242.8	  
	 Issued for cash under Purchase Plans at market rate
	  	 	2.10	  	  	 	88.3	  	 	 	1.97	  	  	 	66.6	  
	 Discount on shares purchased under Dividend Reinvestment Plan
	  	 	—  	  	  	 	(4.1	) 	 	 	—  	  	  	 	(3.0	) 
	 Options exercised under senior management share option plan
	  	 	0.08	  	  	 	2.3	  	 	 	0.26	  	  	 	6.2	  
	 Employee Share Purchase Plan
	  	 	—  	  	  	 	0.9	  	 	 	—  	  	  	 	0.8	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Balance, December 31
	  	 	147.21	  	  	$	2,157.5	  	 	 	143.78	  	  	$	2,016.4	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 

  

	(1)	On December 17, 2015, Emera issued 1.25 million common shares to facilitate the creation and issuance of 5.0 million depositary receipts in connection with the ECI share acquisition. The depositary
receipts are listed on the Barbados Stock Exchange. 

 As at December 31, 2015, there were the following common shares reserved for issuance:
7.3 million (2014 – 7.3 million) under the senior management stock option plan, 1.6 million (2014 – 1.8 million) under the employee common share purchase plan and 3.3 million (2014 – 5.2 million) under the dividend
reinvestment plan. The issuance of common shares under the current or proposed common share compensation arrangements will not exceed ten per cent of Emera’s outstanding common shares. As at December 31, 2015, Emera is in compliance with
this requirement. 
 34. CUMULATIVE PREFERRED STOCK 
 Authorized:

 Unlimited number of First Preferred shares, issuable in series. 
 Unlimited
number of Second Preferred shares, issuable in series. 
  

																									
	 	  	  
	 	  	  
	 	  	December 31, 2015	 	  	December 31, 2014	 
	 	  	Annual Dividend
Per Share	 	  	Redemption
Price per share	 	  	Issued and
Outstanding	 	  	Net
Proceeds	 	  	Issued and
Outstanding	 	  	Net
Proceeds	 
	 Series A
	  	$	0.6388	  	  	$	25.00	  	  	 	3,864,636	  	  	$	94.5	  	  	 	6,000,000	  	  	$	146.7	  
	 Series B
	  	 	Floating	  	  	$	25.00	  	  	 	2,135,364	  	  	$	52.2	  	  	 	—  	  	  	$	—  	  
	 Series C
	  	$	1.0250	  	  	$	25.00	  	  	 	10,000,000	  	  	$	244.9	  	  	 	10,000,000	  	  	$	244.9	  
	 Series E
	  	$	1.1250	  	  	$	26.00	  	  	 	5,000,000	  	  	$	122.4	  	  	 	5,000,000	  	  	$	122.4	  
	 Series F
	  	$	1.0625	  	  	$	25.00	  	  	 	8,000,000	  	  	$	195.5	  	  	 	8,000,000	  	  	$	195.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 On August 17, 2015, Emera announced that 2,135,364 of its 6,000,000 issues and outstanding Series A Shares were tendered for
conversion, on a one-for-one basis into Cumulative Floating Rate First Preferred Shares, Series B (the “Series B Shares”). As a result of the conversion, Emera has 3,864,636 Series A Shares and 2,135,364 Series B Shares issued and
outstanding. The 2015 dividends for the Series A and Series B shares were $0.98470 and $0.15080 respectively. 

  
 83 

 The First Preferred Shares, Series A, C and F are entitled to receive fixed cumulative cash dividends as and when declared
by the Board of Directors of the Corporation in the amounts of $0.6388, $1.025 and $1.0625 per share per annum, respectively for each year up to and excluding August 15, 2020, August 15, 2018, and February 15, 2020, respectively.
As at August 15, 2020, August 15, 2018, and February 15, 2020, the holders of the First Preferred Shares Series A, C and F, respectively, are entitled to receive reset fixed cumulative cash dividends. The reset annual dividend
per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate of the First Preferred Shares, Series A, C and F, respectively, which is the sum of the five-year Government of Canada Bond Yield on the application reset
date plus 1.84 per cent, 2.65 per cent, and 2.63 per cent, respectively. 
 The First Preferred Shares, Series B, are entitled to receive floating rate
cumulative cash dividends, as and when declared by the Board of Directors in the amount determined by multiplying $25.00 by the three month Government of Canada Treasury Bill rate plus 1.84 per cent. 

The First Preferred Shares, Series E, are entitled to receive fixed rate cumulative cash dividends, as and when declared by the Board of Directors in the amount $1.1250
per annum. 
 The holders of First Preferred Shares, Series A, C and F will have the right, at their option, to convert their shares into an equal number of
Cumulative Floating Rate First Preferred Shares, Series B, D, and G, of the Company, respectively, on August 15, 2020 August 15, 2018, and February 15, 2020, respectively, and every five years thereafter. 

The holders of the First Preferred Shares, Series B will have the right, at their option, to convert their shares into an equal number of Series A shares of the Company
on August 15, 2020 and every five years thereafter. 
 The Company has the right to redeem the outstanding Preferred Shares, Series A, C, and F shares without
the consent of the holder on August 15, 2020, August 15, 2018, and February 15, 2020 respectively and on August 15, August 15 and February 15 respectively every five years thereafter for cash, in whole or in
part at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption. 
 The Company has the right to redeem
the outstanding Preferred Shares, Series B, Series D and Series G shares without the consent of the holder on August 15, 2020, August 15, 2023 and February 15, 2025 respectively and on August 15, August 15 and
February 15 every five years thereafter for cash, in whole or in part at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption and $25.50 per share plus all accrued and unpaid
dividends on any other date after August 15, 2015, August 15, 2018 and February 15, 2020, respectively. 
 The Company has the right to redeem the
outstanding First Preferred Shares, Series E on or after August 15, 2018 in whole or in part, at the Company’s option, by the payment in cash of $26.00 per Series E Preferred Share if redeemed prior to August 15, 2019; at $25.75 per
Series E Preferred Share if redeemed on or after August 15, 2019, but prior to August 15, 2020; at $25.50 per Series E Preferred Share if redeemed on or after August 15, 2020, but prior to August 15, 2021; at $25.25 per Series E
Preferred Share if redeemed on or after August 15, 2021, but prior to August 15, 2022; and at $25.00 per Series E Preferred Share if redeemed on or after August 15, 2022, in each case together with all accrued and unpaid dividends up
to but excluding the date fixed for redemption. 
 As the First Preferred Shares, Series A, B, C, E and F are neither redeemable at the option of the shareholder nor
have a mandatory redemption date, they are classified as equity and the associated dividends will be deducted on the consolidated statements of earnings immediately before arriving at “Net earnings attributable to common shareholders” and
will be shown on the consolidated statement of equity as a deduction from retained earnings. 

  
 84 

 The First Preferred Shares of each series rank on a parity with the First preferred Shares of every other series and are
entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or
return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. 
 In the event the Company fails to pay, in aggregate,
eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares will be entitled to attend any meeting of shareholders of the Company and to vote at any such meeting. 

35. NON-CONTROLLING INTEREST IN SUBSIDIARIES 
 Non-controlling interest in
subsidiaries consisted of the following: 
  

									
	 As at

millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 ICDU
	  	$	51.8	  	  	$	40.9	  
	 ECI (1)
	  	 	48.3	  	  	 	99.6	  
	 Preferred shares of GBPC
	  	 	33.5	  	  	 	33.5	  
	 Preferred shares of Emera Maine
	  	 	0.4	  	  	 	0.4	  
	 Preferred shares of NSPI (2)
	  	 	—  	  	  	 	132.2	  
		  	  
	  
	 	  	  
	  
	 
		  	$	134.0	  	  	$	306.6	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	On December 17, 2015, an indirect wholly-owned subsidiary of Emera acquired approximately 2.6 million ECI shares, increasing its ownership interest from 80.7 per cent to 95.5 per cent.

	(2)	On October 15, 2015, NSPI redeemed all of its outstanding Cumulative Redeemable First Preferred Shares, Series D for a redemption price of $25.00 per share for a total of $135 million. The issuance costs are
treated as a deemed dividend of $2.8 million, recognized when the redemption occurred on October 15, 2015. 

 Preferred shares of NSPI:

 Authorized: 
 Unlimited number of First Preferred shares, issuable in
series. 
 Unlimited number of Second Preferred shares, issuable in series. 
  

																	
	 	  	2015	 	  	2014	 
	 Issued and outstanding:
	  	Millions of
shares	 	  	Millions of
dollars	 	  	Millions of
shares	 	  	Millions of
dollars	 
	 Outstanding as at December 31
	  	 	—  	  	  	$	—	  	  	 	5.4	  	  	$	132.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Preferred shares of GBPC: 
 Authorized:

 35,000 non-voting cumulative redeemable variable perpetual preferred shares 
  

																	
	 	  	2015	 	  	2014	 
	 Issued and outstanding:
	  	number of
shares	 	  	millions of
dollars	 	  	number of
shares	 	  	millions of
dollars	 
	 Outstanding as at December 31
	  	 	35,000	  	  	$	33.5	  	  	 	35,000	  	  	$	33.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  
 85 

 GBPC Non-Voting Cumulative Variable Perpetual Preferred Stock: 

The Preferred Stock is redeemable by GBPC, in whole at any time or in part from time to time, at $1,000 Bahamian per share plus accrued and unpaid dividends. 

The Preferred Stock is entitled to a 7.25 per cent per annum fixed cumulative preferential dividend for years 2013 through 2016, 8.50 per cent per annum fixed
cumulative preferential dividend for years 2017 through 2019 and 10.00 per cent per annum fixed cumulative preferential dividend after 2020, as and when declared by the Board of Directors, accruing from the date of issue. 

The Preferred Shares rank behind all of GBPC’s current and future secured and unsecured debt with any of GBPC’s future preferred stock and ahead of all of
GBPC’s current and future common stock. 
 36. STOCK-BASED COMPENSATION 

EMPLOYEE COMMON STOCK PURCHASE PLAN AND COMMON SHAREHOLDERS DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN 

All employees may participate in Emera’s Employee Common Share Purchase Plan to which employees make cash contributions of a minimum of $25 to a maximum of $8,000
per year for the purpose of purchasing common shares of Emera. The Company also contributes to the plan a percentage of the employees’ contributions. If an employee contributes any amount up to $3,000 to employees plan account, the Company will
contribute 20 per cent of that amount. When an employee contributes any amount over $3,000, up to the $8,000 maximum, the Company will contribute ten per cent of that amount. 

The plan allows the reinvestment of dividends. The maximum aggregate number of Emera common shares reserved for issuance under this plan is 4 million common
shares. 
 The Company also has a Common Shareholders Dividend Reinvestment and Share Purchase Plan (“Dividend Reinvestment Plan”), which provides an
opportunity for shareholders to reinvest dividends and for the purpose of purchasing common shares. The plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares
purchased in connection with the reinvestment of cash dividends under the Plans. 
 Compensation cost for shares issued by Emera for the year ended December 31,
2015 under the Employee Common Share Purchase Plan was $0.9 million (2014 – $0.8 million) and is included in “Operating, maintenance and general” on the Consolidated Statements of Income. 

STOCK-BASED COMPENSATION PLANS 
 Stock Option Plan 

The Company has a stock option plan that grants options to senior management of the Company for a maximum term of ten years. The option price of the stock options is
the closing market price of the stocks on the day before the option is granted. The maximum aggregate number of shares issuable under this plan is 11.7 million shares. 

All options granted to date are exercisable on a graduated basis with up to 25 per cent of options exercisable on the first anniversary date and further
25 per cent increments on each of the second, third and fourth anniversaries of the grant. If an option is not exercised within ten years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a
shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. 

  
 86 

 If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person due to
retirement or termination for other than just cause, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the 24 months following the date the optionee retires, but in any case prior to the
expiry of the option in accordance with its terms. 
 If, before the expiry of an option in accordance with its terms, the optionee ceases to be an eligible person
due to employment termination for just cause, resignation or death, such option may, subject to the terms thereof and any other terms of the plan, be exercised at any time within the six months following the date the optionee is terminated, resigns
or dies, as applicable, but in any case prior to the expiry of the option in accordance with its terms. 
 The Company uses the fair value based method to measure the
compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. The fair value of stock option awards granted was estimated on the date of grant using a Black-Scholes
valuation model. The expected term of the option awards is calculated based on historical exercise behaviour and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the Bank of Canada
five-year government bond yields. The expected dividend yield incorporates current dividend rates as well as historical dividend increase patterns. Emera’s expected stock price volatility was estimated using its five-year historical volatility.

 The following table shows the weighted average fair values per stock option along with the assumptions incorporated into the valuation models for options granted:

  

									
	 For the year ended December 31,
	  	2015	 	  	2014	 
	 Weighted average fair value per option
	  	$	2.66	  	  	$	2.25	  
	 Expected term
	  	 	5 years	  	  	 	5 years	  
	 Risk-free interest rate
	  	 	0.73%	  	  	 	1.68%	  
	 Expected dividend yield
	  	 	3.65%	  	  	 	4.47%	  
	 Expected volatility
	  	 	14.58%	  	  	 	15.77%	  
		  	  
	  
	 	  	  
	  
	 

 The following table summarizes information related to the stock options for 2015: 

 

																	
	 	  	Total Options	 	  	Non-Vested Options(1)	 
	 	  	Number of
Options	 	 	Weighted
average exercise
price per share	 	  	Number of
Options	 	 	Weighted
average grant
date fair-value	 
	 Outstanding as at December 31, 2014
	  	 	2,425,493	  	 	$	30.54	  	  	 	1,319,421	  	 	$	2.66	  
	 Granted
	  	 	581,700	  	 	 	42.71	  	  	 	581,700	  	 	 	2.66	  
	 Exercised
	  	 	(80,125	) 	 	 	26.29	  	  	 	N/A	  	 	 	N/A	  
	 Vested
	  	 	N/A	  	 	 	N/A	  	  	 	(447,635	) 	 	 	2.75	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Options outstanding December 31, 2015
	  	 	2,927,068	  	 	$	33.07	  	  	 	1,453,486	  	 	$	2.64	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Options exercisable December 31, 2015(2)(3)
	  	 	1,473,582	  	 	$	29.13	  	  				 			
		  	  
	  
	 	 	  
	  
	 	  				 			

  

	(1)	As at December 31, 2015 there was $2.5 million of unrecognized compensation related to stock options not yet vested which is expected to be recognized over a weighted average period of approximately
2.3 years (2014 – $2.4 million, 2.5 years). 

	(2)	As at December 31, 2015, the weighted average remaining term of vested options was 5.3 years with an aggregate intrinsic value of $20.8 million (2014: 5.5 years, $12.6 million).

	(3)	As at December 31, 2015 the fair value of options that vested in the year was $1.2 million (2014: $1.1 million). 

Compensation cost recognized for stock options for the year ended December 31, 2015 was $1.4 million (2014 – $1.2 million), which is included
in “Operating, maintenance and general” on the Consolidated Statements of Income. 
 As at December 31, 2015, cash received from option exercises was
$2.1 million (2014 – $5.7 million). The total intrinsic value of options exercised for the year ended December 31, 2015 was $1.3 million (2014 – $4.2 million). The range of exercise prices for the options
outstanding as at December 31, 2015 was $19.88 to $42.71 (2014 – $19.88 to $34.80). 

  
 87 

 Share Unit Plans 
 The Company
has deferred share unit (“DSU”) and performance share unit (“PSU”) plans. The DSU and PSU liabilities are marked-to-market at the end of each period based on the common share price at the end of the period. 

Deferred Share Unit Plans 
 Under the Directors’ DSU plan, Directors of
the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis
and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, referred to as the Dividend Reinvestment Plan
(“DRIP”), the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a
common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the
participant’s account by the average of Emera’s stock closing price during the ten trading days ending on the tenth trading day prior to the payment date. 

Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the
understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50% of the value of their actual annual incentive award (25% in the first year of the program) will be payable in DSUs until the applicable
guidelines are met. 
 When incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common
share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment
or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the
average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee (“MRCC”), payments
may be made in the form of actual shares. 
 In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to
recognize singular achievements or to achieve certain corporate objectives. 
 A summary of the activity related to employee and director DSUs for the year ended
December 31, 2015 is presented in the following table: 
  

																	
	 	  	Employee
DSU	 	 	Weighted
Average
Grant Date
Fair Value	 	  	Director
DSU	 	  	Weighted
Average
Grant Date
Fair Value	 
	 Outstanding as at December 31, 2014
	  	 	511,167	  	 	$	24.38	  	  	 	301,086	  	  	$	29.62	  
	 Granted including DRIP
	  	 	98,442	  	 	 	36.17	  	  	 	61,664	  	  	 	35.14	  
	 Exercised
	  	 	(2,963	) 	 	 	29.12	  	  	 	—  	  	  	 	—  	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Outstanding and exercisable as at December 31, 2015
	  	 	606,646	  	 	$	26.27	  	  	 	362,750	  	  	$	31.36	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  
 88 

 Compensation cost recognized for employee and director DSU for the year ended December 31, 2015 was $8.1 million (2014
– $9.1 million). Tax benefits related to this compensation cost for share units realized for the year ended December 31, 2015 were $2.7 million (2014 – $3.1 million); $0.5 million was offset with regulatory assets and regulatory
liabilities (2014 – $0.6 million). 
 Performance Share Unit Plan 

Under the PSU plan, executive and senior employees are eligible for long-term incentives payable through the PSU plan. PSUs are granted annually for three-year
overlapping performance cycles. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Dividend equivalents are awarded and are used to purchase additional PSUs, also
referred to as DRIP. The PSU value varies according to the Emera common share market price and corporate performance. 
 PSUs vest at the end of the three-year cycle
and will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of retirement, disability or death. 

A summary of the activity related to employee PSUs for the year ended December 31, 2015 is presented in the following table: 

 

													
	 	  	Employee
PSU	 	 	Weighted
Average Grant
Date Fair Value	 	  	Aggregate
intrinsic value	 
	 Outstanding as at December 31, 2014
	  	 	457,582	  	 	$	32.38	  	  	$	17.7	  
	 Granted including DRIP
	  	 	247,937	  	 	 	36.79	  	  			
	 Exercised
	  	 	(204,583	) 	 	 	32.54	  	  			
	 Forfeited
	  	 	(3,440	) 	 	 	33.63	  	  			
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Outstanding as at December 31, 2015
	  	 	497,496	  	 	$	34.50	  	  	$	21.5	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 

 Compensation cost recognized for the PSU plan for the year ended December 31, 2015 was $9.6 million (2014 – $8.9 million). Tax
benefits related to this compensation cost for share units realized for the year ended December 31, 2015 were $3.1 million (2014 – $2.8 million). 
 37.
VARIABLE INTEREST ENTITIES 
 The Company performs ongoing analysis to assess whether it holds any variable interest entities (“VIEs”). To identify
potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities.
 VIEs of which the
Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb
losses of the entity that could potentially be significant to the entity. In circumstances where Emera is not deemed the primary beneficiary, the VIE is accounted for using the equity method. 

For the years ended, December 31, 2015 and 2014, the Company has identified the following significant VIEs: 

Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera was not the primary beneficiary since it does not have the controlling financial
interest of NSPML. In Q2 2014, when the critical milestones were achieved and Nalcor Energy was deemed the beneficiary of the asset for financial reporting purposes as they have authority over the majority of the direct activities that are
expected to most significantly impact the economic performance of the Maritime Link Project. Thus, Emera began recording the Maritime Link Project as an equity investment.

  
 89 

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

The Company has identified certain long-term purchase power agreements that could be defined as variable interests as the Company has to purchase all or a majority of
the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and
make management decisions. 
 As at December 31, 2015, NSPI did not provide a guarantee to RESL (December 31, 2014 – $18.4 million). Until Q4 2015, NSPI
held a variable interest in RESL, a VIE for which it was determined that NSPI was not the primary beneficiary since it did not have the controlling financial interest of RESL and did not have the power to direct the operations of the facility. 

Emera’s consolidated VIE is recorded as an “Available-for-sale investment” and “Restricted cash”. The following table provides information
about Emera’s portion of significant consolidated and unconsolidated VIEs: 
  

																	
	As at	  	December 31, 2015	 	  	December 31, 2014	 
	 	  	Total	 	  	Maximum	 	  	Total	 	  	Maximum	 
	 millions of Canadian dollars
	  	assets	 	  	exposure to loss	 	  	assets	 	  	exposure to loss	 
	 Consolidated VIE
	  				  				  				  			
	 BLPC SIF
	  	$	101.4	  	  	$	101.4	  	  	$	85.0	  	  	$	85.0	  
					
	 Unconsolidated VIEs in which Emera has variable interests
	  				  				  				  			
	 NSPML (equity accounted)
	  	 	187.6	  	  	 	1,007.0	  	  	 	159.3	  	  	 	1,292.1	  
	 RESL
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	18.4	  

 38. COMPARATIVE INFORMATION 
 These financial
statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income. 
 39.
SUBSEQUENT EVENTS 
 On January 25, 2016, Emera announced an indirect wholly-owned subsidiary, Emera (Barbados) Holdings No. 2 Inc., (“EBH2”),
will proceed to acquire the remaining ECI common shares from minority shareholders. Minority ECI shareholders can elect to receive $33.30 Barbadian dollar (“BBD”) in cash per common share (“Cash Offer”) or 2.1 Depositary Receipts
(“DR”) representing common shares of Emera (“DR Offer”) or a combination of the two Offers by way of an amalgamation between ECI and a wholly-owned subsidiary of EBH2. Each Emera DR initially represented one quarter of an
Emera common share.
 ECI is also proposing to amend the terms of its 5.5 per cent cumulative preferred shares to make them redeemable at a 20 per cent
premium to their issuance price. An ECI shareholders’ meeting to vote on the amalgamation and preferred share amendment will take place on February 24, 2016. 

These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 12, 2016, the
date the financial statements were issued. 

  
 90

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