Document:

EX-4.3

 Exhibit 4.3 
  

 
 Management’s Discussion & Analysis 

As at February 12, 2016
 Management’s Discussion &
Analysis (“MD&A”) provides a review of the results of operations of Emera Incorporated and its subsidiaries and investments (“Emera”) during the fourth quarter of 2015 relative to the same quarter in 2014; and the full year
of 2015 relative to 2014 and 2013; and its financial position as at December 31, 2015 relative to December 31, 2014. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is presented.
Throughout this discussion, “Emera Incorporated”, “Emera” and “Company” refer to Emera Incorporated and all of its consolidated subsidiaries and investments. 

This discussion and analysis should be read in conjunction with the Emera Incorporated annual audited consolidated financial statements and supporting notes
as at and for the year ended December 31, 2015. Emera follows United States Generally Accepted Accounting Principles (“USGAAP” or “GAAP”). 

The accounting policies used by Emera’s rate-regulated entities may differ from those used by Emera’s non-rate-regulated businesses with respect to
the timing of recognition of certain assets, liabilities, revenues and expenses. Emera’s rate-regulated subsidiaries include: 
  

			
	 Emera Rate-Regulated Subsidiary or Investment
	  	 Accounting Policies Approved/Examined By

	Subsidiary	  	
	Nova Scotia Power Inc. (“NSPI”)	  	Nova Scotia Utility and Review Board (“UARB”)
	Emera Maine	  	Maine Public Utilities Commission (“MPUC”) and the Federal Energy Regulatory Commission (“FERC”)
	Barbados Light & Power Company Limited (“BLPC”)	  	Fair Trading Commission, Barbados
	Grand Bahama Power Company Limited (“GBPC”)	  	The Grand Bahama Port Authority (“GBPA”)
	Dominica Electricity Services Ltd. (“Domlec”)	  	Independent Regulatory Commission (“IRC”), Dominica
	Emera Brunswick Pipeline Company Limited (“Brunswick Pipeline”)	  	National Energy Board (“NEB”)
	Investment	  	
	NSP Maritime Link Inc. (“NSPML”)	  	UARB
	Maritimes & Northeast Pipeline Limited Partnership and Maritimes & Northeast Pipeline LLC (“M&NP”)	  	NEB and FERC
	Labrador Island Link Limited Partnership (“LIL”)	  	Newfoundland and Labrador Board of Commissioners of Public Utilities
	St. Lucia Electricity Services Limited (“Lucelec”)	  	Government of St. Lucia

 All amounts are in Canadian dollars (“CAD”), except for Emera Maine and Emera Caribbean sections of the MD&A,
which are reported in US dollars (“USD”), unless otherwise stated. 
 Additional information related to Emera, including the Company’s Annual
Information Form, can be found on SEDAR at www.sedar.com. 

  
 1 

 Forward-Looking Information 

This MD&A contains “forward-looking information” and statements which reflect the current view with respect to the Company’s expectations
regarding future growth, results of operations, performance, business prospects and opportunities and may not be appropriate for other purposes within the meaning of applicable Canadian securities laws. All such information and statements are made
pursuant to safe harbor provisions contained in applicable securities legislation. The words “anticipates”, “believes”, “could”, “estimates”, “expects”, “intends”, “may”,
“plans”, “projects”, “schedule”, “should”, “budget”, “forecast”, “might”, “will”, “would”, “targets” and similar expressions are often intended to
identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management’s current beliefs and is based on information currently available to
Emera’s management and should not be read as guarantees of future events, performance or results, and will not necessarily be accurate indications of whether, or the time at which, such events, performance or results will be achieved. 

The forward-looking information is based on reasonable assumptions and is subject to risks, uncertainties and other factors that could cause actual results to
differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ from current expectations are discussed in the Outlook section of the MD&A and may
also include: regulatory risk; operating and maintenance risks; changes in economic conditions; commodity price and availability risk; capital market and liquidity risk; the completion of the TECO Energy, Inc. (“TECO Energy”) acquisition;
uncertainty regarding the length of time required to complete the TECO Energy acquisition; 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 could reduce demand for electricity; 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 and the financing; failure by the Company to repay the acquisition credit
facilities; potential unavailability of the acquisition credit facilities; alternate sources of funding that would be used to replace the acquisition credit facilities may not be available when needed; impact of acquisition related expenses;
interest rate risk; credit risk; commercial relationship risk; disruption of fuel supply; country risks; environmental risks; foreign exchange; regulatory and government decisions, including changes to environmental, financial reporting and tax
legislation; risks associated with pension plan performance and funding requirements; loss of service area; risk of failure of information technology infrastructure and cybersecurity risks; market energy sales prices; labour relations; and
availability of labour and management resources. 
 Readers are cautioned not to place undue reliance on forward-looking information as actual results could
differ materially from the plans, expectations, estimates or intentions and statements expressed in the forward-looking information. All forward-looking information in this MD&A is qualified in its entirety by the above cautionary
statements and, except as required by law, Emera undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise. 

  
 2 

 Structure of MD&A 

This MD&A begins with an Introduction and Strategic Overview; followed by the Consolidated Financial Review and Outstanding Common Stock data; then
presents information specific to Emera’s consolidated subsidiaries and investments: 
  

	 	•	 	NSPI; 

  

	 	•	 	Emera Maine; 

  

	 	•	 	Emera Caribbean includes BLPC and Domlec and their parent company, Emera (Caribbean) Incorporated (“ECI”), GBPC, Emera Utility Services (Bahamas) Limited (“EUS Bahamas”) and Lucelec;

  

	 	•	 	Pipelines includes Brunswick Pipeline and M&NP; 

  

	 	•	 	Emera Energy includes Emera Energy Services (“EES”); Emera Energy Generation (“EEG”) which includes Bridgeport Energy, Tiverton Power and Rumford Power (“New England Gas Generating
Facilities”), Brooklyn Power Corporation (“Brooklyn Energy” or “Brooklyn”) and Bayside Power Limited Partnership (“Bayside Power” or “Bayside”); Bear Swamp Power Company LLC (“Bear Swamp”); and
Northeast Wind Partners II, LLC (“NWP”) until its sale on January 29, 2015; 

  

	 	•	 	Corporate and Other includes: 

  

	 	•	 	Interest revenue on intercompany financings and costs associated with corporate activities that are not directly allocated to the operations of Emera’s consolidated subsidiaries and investments; 

 

	 	•	 	Acquisition costs related to the pending acquisition of TECO Energy; 

  

	 	•	 	Emera Utility Services Inc. (“Emera Utility Services”); 

  

	 	•	 	Emera Newfoundland & Labrador Holdings Inc. (“ENL”) and its investments: 

  

	 	•	 	NSPML; 

  

	 	•	 	LIL; 

  

	 	•	 	Emera Reinsurance Limited; 

  

	 	•	 	Emera’s investment in Algonquin Power & Utilities Corp. (“APUC”); 

  

	 	•	 	Emera’s investment in OpenHydro Group Ltd. (“Open Hydro”); and 

  

	 	•	 	Other investments 

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

INTRODUCTION AND STRATEGIC OVERVIEW 
 Emera Incorporated
is a geographically diverse energy and services company that invests in electricity generation, transmission and distribution, as well as gas transmission and utility services. Emera provides regional energy solutions by connecting its assets,
markets and partners in Canada, the United States, and the Caribbean. 
 Emera seeks to deliver long-term growth to investors and, accordingly, annual
dividend growth, earnings per common share growth and total shareholder return are the primary measures of performance. Emera is targeting eight-per-cent annual dividend growth through 2019. Below are Emera’s one, three and five-year
performance for these metrics: 

  
 3 

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

  

	(1)	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. 

	(2)	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 per cent. The indices are based upon the Global Industry Classification Standards (GICS®). The S&P/TSX Capped Utilities 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 will 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 will make acquisitions, both regulated and unregulated, where the business or asset acquired aligns with Emera’s strategic initiatives and delivers shareholder value. 

To ensure stability in 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 per
cent of its adjusted income (a non-GAAP measure described in the section below) from rate-regulated subsidiaries, which generally contribute strong, predictable income and cash flows that fund dividends, reinvestment and is reflective of the
Company’s risk tolerance. Emera has an annual dividend growth target of eight per cent through 2019. 
 In 2015, approximately 65 per cent of
Emera’s adjusted net income was earned by its rate-regulated subsidiaries, which is lower than previous years and the strategic target. With the pending close of the TECO Energy acquisition, the Company will achieve its adjusted net income
targeted mix. Specifically, this was as the 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 US dollar. The current
percentage from non-regulated businesses 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 and businesses. 
 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 Emera’s recent issue of convertible debentures

  
 4 

 
represented by instalment receipts in relation to the pending TECO Energy acquisition. 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. 

The energy industry is seasonal in nature. Seasonal patterns and other weather events, including the number and severity of storms, can affect demand for
energy and cost of service. Similarly, mark-to-market adjustments arising from commodity purchases or trading activities that do not qualify for hedge accounting or regulatory accounting can have a material impact on the financial results for a
specific period. Results in any one quarter are not necessarily indicative of results in any other quarter, or for the year as a whole. 
 Non-GAAP
Financial Measures 
 Emera uses financial measures that do not have standardized meaning under USGAAP and may not be comparable to similar measures
presented by other entities. Emera calculates the non-GAAP measures by adjusting certain GAAP measures for specific items the Company believes are significant, but not reflective of underlying operations in the period, as detailed below: 

 

			
	 Non-GAAP measure
	  	 GAAP measure

	Adjusted net income attributable to common shareholders or adjusted net income	  	Net income attributable to common shareholders
	Adjusted earnings per common share – basic	  	Earnings per common share – basic
	Adjusted contribution to consolidated net income	  	Contribution to consolidated net income
	Adjusted income before provision for income taxes	  	Income before provision for income taxes
	Adjusted contribution to consolidated earnings per common share – basic	  	Contribution to consolidated earnings per common share – basic
	EBITDA	  	Net income
	Adjusted EBITDA	  	Net income
	Electric margin	  	Income from operations

 Adjusted Net Income 

Emera calculates comparable measures by excluding the effect of: 
  

	 	•	 	the mark-to-market adjustments related to Emera’s held-for-trading (“HFT”) derivative instruments; 

  

	 	•	 	the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp and NWP, until NWP’s sale on January 29, 2015; 

 

	 	•	 	the amortization of transportation capacity recognized as a result of certain trading and marketing transactions; 

  

	 	•	 	the mark-to-market adjustments related to an interest rate swap in Brunswick Pipeline; and 

  

	 	•	 	the mark-to-market adjustments included in Emera’s other income 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 pending TECO Energy acquisition. 

 Management believes excluding from income the effect of these
mark-to-market valuations and changes thereto, until settlement, better aligns the intent and financial effect of these contracts with the underlying cash flows. 

Mark-to-market adjustments are further discussed in the Consolidated Financial Highlights section, Emera Energy – Review of 2015, Pipelines – Review
of 2015 and Corporate and Other – Review of 2015. 

  
 5 

 The following is a reconciliation of reported net income attributable to common shareholders to adjusted net
income attributable to common shareholders, and reported earnings per common share – basic to adjusted earnings per common share – basic: 
  

																					
	 For the millions of Canadian dollars (except per share
amounts)
	  	Three months ended	 	  	Year ended	 
	  	December 31	 	  	December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Net income attributable to common shareholders
	  	$	192.1	  	  	$	151.2	  	  	$	397.2	  	  	$	406.7	  	  	$	217.5	  
	 After-tax mark-to-market gain (loss)
	  	$	105.0	  	  	$	72.7	  	  	$	67.2	  	  	$	87.5	  	  	$	(41.9	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Adjusted net income attributable to common shareholders
	  	$	87.1	  	  	$	78.5	  	  	$	330.0	  	  	$	319.2	  	  	$	259.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Earnings per common share – basic
	  	$	1.31	  	  	$	1.05	  	  	$	2.72	  	  	$	2.84	  	  	$	1.64	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Adjusted earnings per common share – basic
	  	$	0.59	  	  	$	0.54	  	  	$	2.26	  	  	$	2.23	  	  	$	1.96	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 EBITDA and Adjusted EBITDA 

Earnings before interest, income taxes, depreciation and amortization (“EBITDA”) is a non-GAAP financial measure used by Emera. EBITDA is used
by numerous investors and lenders to better understand cash flows and credit quality. 
 Adjusted EBITDA is a non-GAAP financial measure used by
Emera. Similar to Adjusted Net Income calculations, this measure represents EBITDA absent the income effect of Emera’s mark-to-market adjustments, as previously discussed. 

The Company’s EBITDA and Adjusted EBITDA may not be comparable to the EBITDA measures of other companies, but in management’s view appropriately
reflects Emera’s specific financial condition. These measures are not intended to replace “Net income attributable to common shareholders” which, as determined in accordance with GAAP, is an indicator of operating performance. EBITDA
and Adjusted EBITDA are discussed further in the Consolidated Financial Review, NSPI, Emera Maine, Emera Caribbean, Pipelines, Emera Energy, and Corporate and Other sections. 

EBITDA and Adjusted EBITDA Reconciliation 
  

																					
	 For the millions of Canadian dollars
	  	Three months ended	 	  	Year ended	 
	  	December 31	 	  	December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Net income
	  	$	198.6	  	  	$	155.3	  	  	$	452.4	  	  	$	452.8	  	  	$	255.3	  
	 Interest expense, net
	  	 	70.9	  	  	 	44.7	  	  	 	212.6	  	  	 	179.8	  	  	 	172.2	  
	 Income tax expense (recovery)
	  	 	20.7	  	  	 	53.7	  	  	 	92.4	  	  	 	113.6	  	  	 	43.3	  
	 Depreciation and amortization
	  	 	87.9	  	  	 	82.0	  	  	 	339.9	  	  	 	329.0	  	  	 	297.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 EBITDA
	  	 	378.1	  	  	 	335.7	  	  	 	1,097.3	  	  	 	1,075.2	  	  	 	768.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Mark-to-market gain (loss), excluding income tax and interest
	  	 	119.3	  	  	 	107.7	  	  	 	66.1	  	  	 	128.7	  	  	 	(60.9	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	258.8	  	  	$	228.0	  	  	$	1,031.2	  	  	$	946.5	  	  	$	829.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Electric Margin 

“Electric margin” is a non-GAAP financial measure used to show the amounts that NSPI, BLPC, GBPC and Domlec retain to recover non-fuel costs.
Prudently incurred fuel costs are recovered from customers, except in Domlec, where substantially all fuel costs are passed to customers through the fuel pass-through mechanism. Management believes measuring electric margin shows the portion of the
utilities’ revenues that directly contribute to Emera’s income as distinguished from the portion of revenues that are managed through fuel adjustment mechanisms, which have a minimal impact on income. 

Emera Energy also reports “Electric margin” because the sales price of electricity and the cost of natural gas used to generate it are highly
correlated. However, their absolute values can vary materially over time. Emera Energy believes that “Electric margin”, as the net result, provides a meaningful measure of 

  
 6 

 
the business’ performance in addition to the absolute values of sales and fuel expenses, which are also reported. 

Electric margin, as calculated by Emera, may not be comparable to the electric margin measures of other companies, but in management’s view appropriately
reflects Emera’s specific condition. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance. Electric margin is discussed further in the
NSPI – Electric Margin, the Emera Caribbean – Electric Margin and the Emera Energy – Adjusted EBITDA sections. 
 Significant Items
Affecting Earnings 
 2015 
 After-Tax
Mark-to-Market Gains 
 After-tax mark-to-market gains increased $32.3 million to $105.0 million in Q4 2015 compared to $72.7 million in Q4 2014; and
decreased $20.3 million to $67.2 million for the year ended December 31, 2015 compared to $87.5 million in 2014. The increased mark-to-market gains in the quarter are primarily due to the effect of USD-denominated currency and forward contracts
related to the pending TECO Energy acquisition. The increase is partially offset by changes in gas and power contract positions and amortization of transportation assets in Emera Energy. In addition, the reversal of 2013 mark-to-market
losses in 2014 in Emera Energy is primarily responsible for the year-over-year decrease in after-tax mark-to-market gains. 
 Acquisition Related Costs

 Emera incurred after-tax costs of $30.3 million ($0.21 per common share) in Q4 2015 related to its pending acquisition of TECO Energy, including
legal, advisory, and financing costs. For the year ended December 31, 2015, TECO Energy acquisition related costs were $52.8 million after-tax ($0.36 per common share). There were no such TECO Energy acquisition related costs for 2014.

 As discussed and included above in “After-Tax Mark-to-Market Gains”, the foreign currency earnings effect related to the Debenture Offering USD
cash balance and the forward contracts were recorded as a mark-to-market pre-tax gain of $118.9 million in “Other income (expenses), net” in Q4 2015. 

Further information on the pending acquisition of TECO Energy is in the Developments section of the MD&A. 

Gain 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”. The gain was a
result of APUC’s share issuance price being higher than Emera’s pre-issuance average book value. 
 Barbados Light & Power Company Limited
(“BLPC”) Restructuring Costs 
 BLPC recorded severance costs of $7.9 million ($6.4 million USD) relating to corporate restructuring, which was
recorded in Operating, maintenance and general (“OM&G”) in Q2 2015. BLPC sees no requirement to seek regulatory deferral of these costs. The after-tax effect on Emera’s Consolidated Net Income in Q2 2015, at Emera’s then 80.7
per cent ownership of ECI, was $5.4 million ($0.04 per common share). 

  
 7 

 Sale of Northeast Wind Partnership II, LLC Equity Investment 

On January 29, 2015, Emera completed the sale of its 49 per cent interest in NWP for $282.3 million ($223.3 million USD). This sale resulted in a pre-tax gain
of $18.6 million or $0.13 per common share (after-tax gain of $11.5 million or $0.08 per common share), which was recorded in “Other income (expenses), net” in Q1 2015. 

2014 
 After-Tax Mark-to-Market Gains 

After-tax mark-to-market gains (losses) increased $114.7 million to $72.7 million in Q4 2014 compared to $(42.0) million in Q4 2013; and increased $129.4
million to $87.5 million for the year ended December 31, 2014 compared to $(41.9) million in 2013. The increased mark-to-market gains are a result of the reversal of 2013 mark-to-market losses and favourable changes in gas and power contract
positions in 2014 at Emera Energy. 
 Gains on Dilution of APUC Equity Investment 

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”. 

  
 8 

 CONSOLIDATED FINANCIAL REVIEW 

Consolidated Financial Highlights 
  

																					
	 For the millions of Canadian dollars (except per share amounts)
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Operating revenues
	  	$	731.6	  	  	$	782.7	  	  	$	2,789.3	  	  	$	2,938.6	  	  	$	2,230.2	  
	 Income from operations
	  	 	149.0	  	  	 	235.4	  	  	 	507.7	  	  	 	667.3	  	  	 	407.1	  
	 Net income attributable to common shareholders
	  	 	192.1	  	  	 	151.2	  	  	 	397.2	  	  	 	406.7	  	  	 	217.5	  
	 After-tax mark-to-market gain (loss)
	  	 	105.0	  	  	 	72.7	  	  	 	67.2	  	  	 	87.5	  	  	 	(41.9	) 
	 Adjusted net income attributable to common shareholders
	  	 	87.1	  	  	 	78.5	  	  	 	330.0	  	  	 	319.2	  	  	 	259.4	  
	 Earnings per common share – basic
	  	$	1.31	  	  	$	1.05	  	  	$	2.72	  	  	$	2.84	  	  	$	1.64	  
	 Earnings per common share – diluted
	  	$	1.30	  	  	$	1.02	  	  	$	2.71	  	  	$	2.82	  	  	$	1.64	  
	 Adjusted earnings per common share – basic
	  	$	0.59	  	  	$	0.54	  	  	$	2.26	  	  	$	2.23	  	  	$	1.96	  
	 Dividends per common share declared
	  	$	—  	  	  	$	—  	  	  	$	1.6625	  	  	$	1.4750	  	  	$	1.4125	  
						
	 Adjusted EBITDA
	  	$	258.8	  	  	$	228.0	  	  	$	1,031.2	  	  	$	946.5	  	  	$	829.5	  

  

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 Operating Unit Contributions to Adjusted Net Income
	  	2015	 	 	2014	 	  	2015	 	 	2014	 	 	2013	 
	 NSPI
	  	$	40.1	  	 	$	30.1	  	  	$	129.9	  	 	$	124.9	  	 	$	126.0	  
	 Emera Maine
	  	 	5.2	  	 	 	11.7	  	  	 	45.1	  	 	 	42.4	  	 	 	38.4	  
	 Emera Caribbean
	  	 	13.3	  	 	 	6.1	  	  	 	40.5	  	 	 	28.7	  	 	 	33.4	  
	 Pipelines
	  	 	10.1	  	 	 	8.5	  	  	 	39.6	  	 	 	32.7	  	 	 	30.3	  
	 Emera Energy
	  	 	35.4	  	 	 	21.3	  	  	 	130.1	  	 	 	98.2	  	 	 	45.1	  
	 Corporate and Other
	  	 	(17.0	) 	 	 	0.8	  	  	 	(55.2	) 	 	 	(7.7	) 	 	 	(13.8	) 
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Adjusted net income attributable to common shareholders
	  	$	87.1	  	 	$	78.5	  	  	$	330.0	  	 	$	319.2	  	 	$	259.4	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 After-tax mark-to-market gain (loss)
	  	 	105.0	  	 	 	72.7	  	  	 	67.2	  	 	 	87.5	  	 	 	(41.9	) 
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net income attributable to common shareholders
	  	$	192.1	  	 	$	151.2	  	  	$	397.2	  	 	$	406.7	  	 	$	217.5	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

													
	 For the millions of Canadian dollars
	  	Year ended
December 31	 
	 	  	2015	 	 	2014	 	 	2013	 
	 Operating cash flow before changes in working capital
	  	$	775.8	  	 	$	716.3	  	 	$	574.3	  
	 Change in working capital
	  	 	(101.6	) 	 	 	46.2	  	 	 	(10.1	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Operating cash flow
	  	$	674.2	  	 	$	762.5	  	 	$	564.2	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Investing cash flow
	  	$	(123.7	) 	 	$	(710.9	) 	 	$	(921.6	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Financing cash flow
	  	$	221.1	  	 	$	58.2	  	 	$	362.1	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

													
	 	  	December 31	 
	 As at millions of Canadian dollars
	  	2015	 	  	2014	 	  	2013	 
	 Working capital (1)
	  	$	599.2	  	  	$	358.3	  	  	$	372.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total assets (1)
	  	$	12,012.3	  	  	$	9,853.4	  	  	$	8,876.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total long-term liabilities (1)
	  	$	5,596.9	  	  	$	5,025.1	  	  	$	4,449.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	(1) 	These financial statements contain certain reclassifications of prior period amounts to be consistent with the current period presentation, with no effect on net income. 

  
 9 

 REVIEW OF 2015 

Emera Consolidated Statements of Income 
  

																					
	 For the millions of Canadian dollars (except per share amounts)
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Operating revenues – regulated
	  	$	533.8	  	  	$	526.7	  	  	$	2,192.9	  	  	$	2,113.1	  	  	$	2,040.8	  
	 Operating revenues – non-regulated
	  	 	197.8	  	  	 	256.0	  	  	 	596.4	  	  	 	825.5	  	  	 	189.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total operating revenues
	  	 	731.6	  	  	 	782.7	  	  	 	2,789.3	  	  	 	2,938.6	  	  	 	2,230.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Regulated fuel for generation and purchased power
	  	 	199.9	  	  	 	212.9	  	  	 	814.5	  	  	 	844.3	  	  	 	868.4	  
	 Regulated fuel adjustment mechanism and fixed cost deferrals
	  	 	10.3	  	  	 	5.7	  	  	 	41.6	  	  	 	46.6	  	  	 	(40.8	) 
	 Non-regulated fuel for generation and purchased power
	  	 	90.7	  	  	 	78.2	  	  	 	335.7	  	  	 	401.1	  	  	 	89.8	  
	 Non-regulated direct costs
	  	 	4.4	  	  	 	9.7	  	  	 	19.5	  	  	 	31.3	  	  	 	52.4	  
	 Operating, maintenance and general
	  	 	173.6	  	  	 	144.0	  	  	 	666.8	  	  	 	560.8	  	  	 	505.0	  
	 Provincial, state and municipal taxes
	  	 	15.8	  	  	 	14.8	  	  	 	63.6	  	  	 	58.2	  	  	 	50.5	  
	 Depreciation and amortization
	  	 	87.9	  	  	 	82.0	  	  	 	339.9	  	  	 	329.0	  	  	 	297.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total operating expenses
	  	 	582.6	  	  	 	547.3	  	  	 	2,281.6	  	  	 	2,271.3	  	  	 	1,823.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income from operations
	  	 	149.0	  	  	 	235.4	  	  	 	507.7	  	  	 	667.3	  	  	 	407.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income from equity investments
	  	 	26.4	  	  	 	15.4	  	  	 	108.6	  	  	 	66.6	  	  	 	38.1	  
	 Other income (expenses), net
	  	 	114.8	  	  	 	2.9	  	  	 	141.1	  	  	 	12.3	  	  	 	25.6	  
	 Interest expense, net
	  	 	70.9	  	  	 	44.7	  	  	 	212.6	  	  	 	179.8	  	  	 	172.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income before provision for income taxes
	  	 	219.3	  	  	 	209.0	  	  	 	544.8	  	  	 	566.4	  	  	 	298.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income tax expense (recovery)
	  	 	20.7	  	  	 	53.7	  	  	 	92.4	  	  	 	113.6	  	  	 	43.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Net income
	  	 	198.6	  	  	 	155.3	  	  	 	452.4	  	  	 	452.8	  	  	 	255.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Non-controlling interest in subsidiaries
	  	 	6.5	  	  	 	4.1	  	  	 	24.9	  	  	 	19.9	  	  	 	18.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Net income of Emera Incorporated
	  	 	192.1	  	  	 	151.2	  	  	 	427.5	  	  	 	432.9	  	  	 	236.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Preferred stock dividends
	  	 	—  	  	  	 	—  	  	  	 	30.3	  	  	 	26.2	  	  	 	19.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Net income attributable to common shareholders
	  	 	192.1	  	  	 	151.2	  	  	 	397.2	  	  	 	406.7	  	  	 	217.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 After-tax mark-to-market gain (loss)
	  	 	105.0	  	  	 	72.7	  	  	 	67.2	  	  	 	87.5	  	  	 	(41.9	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Adjusted net income attributable to common shareholders
	  	$	87.1	  	  	$	78.5	  	  	$	330.0	  	  	$	319.2	  	  	$	259.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Earnings per common share – basic
	  	$	1.31	  	  	$	1.05	  	  	$	2.72	  	  	$	2.84	  	  	$	1.64	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Earnings per common share – diluted
	  	$	1.30	  	  	$	1.02	  	  	$	2.71	  	  	$	2.82	  	  	$	1.64	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Adjusted earnings per common share – basic
	  	$	0.59	  	  	$	0.54	  	  	$	2.26	  	  	$	2.23	  	  	$	1.96	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Emera Incorporated’s consolidated net income attributable to common shareholders increased $40.9 million to $192.1
million in Q4 2015 compared to $151.2 million for the same period in 2014. For the year ended December 31, 2015, Emera’s consolidated net income attributable to common shareholders decreased $9.5 million to $397.2 million compared to $406.7
million in 2014. 
 Q4 Consolidated Income Statement Highlights 

Operational Results
 Income from operations decreased $86.4
million to $149.0 million in Q4 2015 compared to $235.4 million in the same quarter in 2014 primarily due to negative mark-to-market changes of $101.2 million and $21.0 million in costs related to the pending acquisition of TECO Energy. These
decreases were partially offset by Emera Energy’s increased trading and marketing margin, and increased margin at the New England Gas Generating Facilities. 

  
 10 

 Details of operating revenues and operating expenses line item variances are described below: 

Total operating revenues decreased 6.5 per cent to $731.6 million in Q4 2015 compared to $782.7 million in Q4 2014 primarily due to: 

 

	 	•	 	$113.7 million decrease from changes in mark-to-market impacts; 

  

	 	•	 	$46.0 million increase at the New England Gas Generating Facilities primarily due to major outage work at Bridgeport Energy in 2014 and the effect of a strengthening USD; 

 

	 	•	 	$22.2 million increase in Emera Energy Services reflecting growth in the volume of business and increased investment in transportation capacity; 

 

	 	•	 	$9.5 million decrease at BLPC primarily due to lower fuel revenue reflecting lower fuel prices; 

  

	 	•	 	$6.9 million increase at Emera Maine primarily due to the effect of a strengthening USD, partially offset by decreased sales volumes; 

 

	 	•	 	$5.8 million increase at NSPI as a result of recovery of prior years’ fuel costs from a 2014 UARB settlement agreement, partially offset by decreased sales volumes due to weather. 

Total operating expenses increased 6.4 per cent to $582.6 million in Q4 2015 compared to $547.3 million in Q4 2014, primarily due to the effect of a
strengthening USD, acquisition costs related to the pending TECO Energy acquisition, and increased fuel costs at the New England Gas Generating Facilities reflecting major outage work at Bridgeport Energy in 2014, partially offset by lower fuel
prices at BLPC and changes in mark-to-market impacts. 
 Income from equity investments 

Income from equity investments increased 71.4 per cent in Q4 2015 to $26.4 million compared to $15.4 million in the same period in 2014, primarily due to
higher APUC earnings in 2015 and a higher pre-tax gain on dilution of Emera’s APUC investment in 2015. 
 Other income (expenses), net 

Other income increased $111.9 million to $114.8 million in Q4 2015 compared to $2.9 million in the same period in 2014. This was primarily due to
mark-to-market gains on USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering for the pending TECO Energy acquisition. 

Income tax expense (recovery) 
 Income tax expense
decreased $33.0 million to $20.7 million in Q4 2015 compared to $53.7 million for the same period in 2014 primarily due to decreased income before provision for income taxes including mark-to-market adjustments related to Emera Energy, changes in
the proportion of Emera Energy income earned in higher tax rate foreign jurisdictions, and a legislated change by the Province of Nova Scotia to the deferred tax treatment of two wind farms at NSPI. These decreases were partially offset by the
taxable portion of mark-to-market gains relating 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 pending TECO Energy acquisition. 

  
 11 

 2015 Consolidated Income Statement and Operating Cash Flow Highlights 

Operational Results
 Income from operations decreased
$159.6 million to $507.7 million for the year ended December 31, 2015 compared to $667.3 million in 2014 primarily due to mark-to-market changes of $189.2 million. Increased margin at the New England Gas Generating Facilities, the effect of the
strengthening USD, and increased operating income at NSPI, partially offset by $51.5 million in expenses relating to the pending acquisition of TECO Energy and Emera Energy’s decreased trading and marketing margin. 

Total operating revenues decreased 5.1 per cent to $2,789.3 million for the year ended December 31, 2015 compared to $2,938.6 million in the same period in
2014 primarily due to: 
  

	 	•	 	$203.7 million decrease from changes in mark-to-market impacts 

  

	 	•	 	$47.3 million decrease at BLPC primarily due to lower fuel revenue reflecting lower fuel prices 

  

	 	•	 	$32.6 million decrease in Emera Energy Services reflecting a return to more normal market circumstances following particularly strong market conditions in the northern United States and Ontario in Q1 2014

  

	 	•	 	$69.1 million increase at NSPI as a result of recovery of prior years’ fuel costs from the 2014 UARB settlement agreement and higher sales volumes, primarily due to weather 

 

	 	•	 	$46.3 million increase at the New England Gas Generating Facilities primarily due to higher realized margins, increased generation largely because Bridgeport Energy had a major planned outage in Q4 2014, and the effect
of a strengthening USD 

  

	 	•	 	$41.6 million increase at Emera Maine primarily due to the effect of a strengthening USD, partially offset by decreased sales volumes. 

Total operating expenses increased 0.5 per cent to $2,281.6 million for the year ended December 31, 2015 compared to $2,271.3 million in 2014. This was
primarily due to the effect of a strengthening USD, acquisition costs related to the pending TECO Energy acquisition and increased regulated fuel for generation and purchased power at NSPI, partially offset by decreased fuel costs at the New England
Gas Generating Facilities and BLPC reflecting lower fuel prices and changes in mark-to-market impacts. 
 Income from equity investments 

Income from equity investments increased $42.0 million to $108.6 million for the year ended December 31, 2015 compared to $66.6 million in the same period of
2014. This was primarily due to favourable mark-to-market changes of $7.7 million, NWP losses in 2014, higher APUC equity earnings, increased allowance for funds used during construction (“AFUDC”) earnings by NSPML, and increased
earnings resulting from the increased investment in LIL, partially offset by lower APUC dilution gains in 2015 compared to 2014. 
 Other income
(expenses), net 
 Other income increased $128.8 million to $141.1 million for the year ended December 31, 2015 compared to $12.3 million in the same
period in 2014. This was primarily due to a mark-to-market gains relating to the foreign exchange effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture Offering
for the pending TECO Energy acquisition and the gain on the sale of NWP. 
 Income tax expense (recovery) 

Income tax expense decreased $21.2 million to $92.4 million for the year ended December 31, 2015 compared to $113.6 million in 2014. This was primarily
due to decreased income before provision for income taxes, including mark-to-market adjustments related to Emera Energy, partially offset by the 

  
 12 

 
taxable portion of mark-to-market gains relating to the effect of USD-denominated currency and forward contracts put in place to economically hedge the anticipated proceeds from the Debenture
Offering financing the pending TECO Energy acquisition. 
 Operating Activities 

Net cash provided by operating activities decreased $88.3 million to $674.2 million for the twelve months ended December 31, 2015 compared to $762.5 million
for the same period in 2014. Cash from operations before changes in working capital increased by $62.0 million primarily due to higher margins at the New England Gas Generating Facilities, the effect of a strengthening USD and increased fuel
electric revenues at NSPI, partially offset by lower trading and marketing margin at Emera Energy Services, payment of acquisition costs related to the pending TECO Energy acquisition and the deferral of demand side management (“DSM”)
program costs at NSPI. 
 Changes in working capital decreased operating cash flows by $150.3 million primarily due to increased receivables reflecting
higher posted margin at Emera Energy and increased revenues at NSPI and increased dividends payable, partially offset by favourable changes in fuel inventory at NSPI reflecting increased consumption. 

Effect of Foreign Currency Translation 
 Emera’s
foreign currency-denominated results are affected by exchange rate fluctuations. Revenue, operating expense, net income, and adjusted net income are translated at the weighted average rate of exchange. The amounts in the table below are
calculated by multiplying the current period foreign denominated results by the change in the weighted average foreign exchange from the prior period. The table below shows the estimated effect of foreign currency translation on key income statement
items: 
  

									
	 millions of Canadian dollars (except per share amounts)
	  	Q4 2015 vs Q4 2014	 	  	Q4 2014 vs Q4 2013	 
	 Impact on income from continuing operations
	  				  			
	 Total operating revenues
	  	$	49.1	  	  	$	30.7	  
	 Total operating expenses
	  	 	(42.3	) 	  	 	(15.6	) 
	 Net income
	  	 	4.0	  	  	 	10.4	  
	 Adjusted net income
	  	 	7.0	  	  	 	2.4	  
		  	  
	  
	 	  	  
	  
	 
	 Impact on earnings per share
	  				  			
	 Basic
	  	$	0.03	  	  	$	0.07	  
	 Adjusted
	  	$	0.05	  	  	$	0.02	  
		  	  
	  
	 	  	  
	  
	 
			
	 millions of Canadian dollars (except per share amounts)
	  	2015 vs 2014	 	  	2014 vs 2013	 
	 Impact on income from continuing operations
	  				  			
	 Total operating revenues
	  	$	163.6	  	  	$	98.6	  
	 Total operating expenses
	  	 	(139.4	) 	  	 	(67.0	) 
	 Net income
	  	 	19.2	  	  	 	22.0	  
	 Adjusted net income
	  	 	26.0	  	  	 	12.1	  
		  	  
	  
	 	  	  
	  
	 
	 Impact on earnings per share
	  				  			
	 Basic
	  	$	0.13	  	  	$	0.15	  
	 Adjusted
	  	$	0.18	  	  	$	0.08	  
		  	  
	  
	 	  	  
	  
	 

 Emera’s weighted average foreign exchange rates are shown in the following table:     

 

													
	 	  	Twelve months ended	 
	 	  	December 31	 
	 Average equivalent of $1.00 USD
	  	2015	 	  	2014	 	  	2013	 
	 CAD
	  	$	1.26	  	  	$	1.12	  	  	$	1.03	  

  
 13 

 Consolidated Balance Sheets Highlights 

Significant changes in the consolidated balance sheets between December 31, 2015 and December 31, 2014 include: 

 

							
	 millions of Canadian dollars
	  	Increase
(Decrease)	 	  	 Explanation

	 Assets
	  				  	
	 Cash and cash equivalents
	  	$	852.3	  	  	Increased from proceeds of the convertible debentures and long-term debt and cash from operations, partially offset by increased debt levels, preferred shares repayments and dividends
	 Receivables, net
	  	 	63.9	  	  	Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries and increased cash collateral position on derivative instrument at NSPI
	 Income taxes receivable, net of income taxes payable (current and long-term)
	  	 	52.8	  	  	Increased primarily due to the payment of taxes owing for the 2014 tax year by EES and NSPI’s required prepayment of taxes for reassessments relating to the timing of tax deductions under dispute with the Canada Revenue
Agency
	 Derivative instruments (current and long-term)
	  	 	188.6	  	  	Increased primarily due to favourable changes in USD price positions, partially offset by settlements of derivative instruments at NSPI and Emera Energy
	 Regulatory assets (current and long-term)
	  	 	96.8	  	  	Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries and increased regulatory assets related to deferred income taxes, DSM and regulated derivatives, partially offset by amortization
at NSPI
	 Property, plant and equipment, net of accumulated depreciation
	  	 	577.8	  	  	Increased primarily due to the favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries, increased capital expenditures resulting from major planned outage work at Bridgeport Energy, funding of
capital investments at Tiverton Power for 2016 major outage work and increased capital spending at NSPI, partially offset by depreciation
	 Investments subject to significant influence
	  	 	117.7	  	  	Increased primarily due to reclassification of Bear Swamp investment credit balance to Other Long-Term Liabilities, outstanding APUC subscription receipts which became eligible for conversion in Q4 2015 (originally recorded in Other
Assets), dilution gains in APUC, and increased investments in LIL and M&NP, partially offset by the sale of NWP
	 Available-for-sale investments
	  	 	31.6	  	  	Increased primarily due to investment by Emera Reinsurance Limited and favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries
	 Goodwill
	  	 	42.6	  	  	Increased due to the effect of a stronger USD on the translation of Emera’s foreign subsidiaries
	 Intangibles
	  	 	57.6	  	  	Increased primarily due to investment by Emera Maine in a customer information system and the favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries
	 Other assets (current and long-term)
	  	 	115.2	  	  	Increased primarily due to increase in transportation capacity assets in Emera Energy and increased deferred financing costs related to the pending acquisition of TECO Energy, offset by a decrease in APUC subscription receipts which
became eligible for conversion in Q4 2015 (now recorded as Investments Subject to Significant Influence)
	 Liabilities and Equity
	   
	  	
	 Short-term debt and long-term debt (including current portion)
	  	 	28.3	  	  	Increased primarily due to increased debt levels at NSPI to fund the redemption of preferred stock, issuance of long-term debt by Brunswick Pipeline and the effect of a stronger USD on debt held by foreign subsidiaries, partially
offset by repayment of long-term debt
	 Convertible debentures represented by instalment receipts
	  	 	727.6	  	  	Increased due to the issuance of convertible debentures related to the pending acquisition of TECO Energy

  
 14 

							
	 Deferred income tax liabilities, net of deferred income tax assets
	  	 	174.0	  	  	Increased primarily due to the utilization of non-capital loss carryforwards and accelerated tax deductions related to property, plant and equipment at NSPI and Emera Maine
	 Derivative instruments (current and long-term)
	  	 	240.5	  	  	Increased primarily due to a new asset management agreement and unfavourable changes in commodity pricing at Emera Energy and unfavourable mark-to-market impacts relating to interest rate and foreign exchange hedges at Brunswick
Pipeline
	 Regulatory liabilities (current and long-term)
	  	 	168.7	  	  	Increased primarily due to changes in derivative instruments as a result of favourable USD price positions and increased FAM liability at NSPI, partially offset by settlements of derivative instruments at NSPI
	 Pension and post-retirement liabilities (current and long-term)
	  	 	(57.8	) 	  	Decreased primarily due to improvement in funded position as a result of greater than expected asset return at NSPI
	 Other liabilities (current and long-term)
	  	 	267.7	  	  	Increased primarily due to deferred cost impact of parts and capital work delivered for performance in 2015 by a service provider under long-term service agreements at the New England Gas Generating Facilities, and reclassification
of Bear Swamp investment credit balance from Investments Subject to Significant Influence
	 Common stock
	  	 	141.1	  	  	Increased primarily due to issuance of common stock for the dividend reinvestment program and purchase of additional ECI shares
	 Accumulated other comprehensive loss
	  	 	(484.1	) 	  	Decreased primarily due to the favourable effect of a stronger USD on the translation of Emera’s foreign subsidiaries and the amortization of unrecognized pension and post-retirement benefit costs at NSPI
	 Retained earnings
	  	 	156.1	  	  	Increased due to net income in excess of dividends paid
	 Non-controlling interest in subsidiaries
	  	 	(172.7	) 	  	Decreased due to increased ownership in ECI

 Developments
 Emera

 Purchase of ECI Outstanding Shares
 On November
16, 2015, Emera (Barbados) Holdings No. 2 Inc., (“EBH2”), an indirect wholly-owned subsidiary of Emera, announced its intention to acquire the outstanding shares of ECI. Minority ECI shareholders could elect to receive $23.26 ($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. Each Emera DR
initially represented one quarter of an Emera common share.
 On December 17, 2015, EBH2 acquired approximately 2.6 million ECI Shares, increasing its
ownership in ECI to 95.5 per cent from 80.7 per cent. The total consideration paid was $58.7 million, with 92 per cent of shareholders electing the DR Offer and 8 per cent electing the Cash Offer. 

On January 8, 2016, the DRs began trading on the Barbados Stock Exchange. 

On January 25, 2016, Emera announced EBH2 will 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.
 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. 

  
 15 

 Pending Acquisition of TECO Energy 

On September 4, 2015, the Company announced a definitive agreement (“the acquisition agreement”) for Emera to acquire TECO Energy (“the
Transaction”) (NYSE:TE). 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 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., a regulated gas distribution utility which serves more than 510,000 customers across New Mexico. 
 Upon completion of the Transaction,
Emera will have over $26 billion of assets and more than 2.4 million electric and gas customers. Emera has fully committed $6.5 billion USD bridge facilities in place, and financed a portion of the pending acquisition through the sale of $2.185
billion convertible unsecured subordinated debentures, which are described below. The balance of the permanent financing of the 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. 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 discussed below. 
 The closing of the Transaction is expected to occur mid-2016. It 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. Below is a summary of
the approvals received to date: 
  

	 	•	 	Shareholder approval on December 3, 2015; 

  

	 	•	 	FERC approval on January 21, 2016; 

  

	 	•	 	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 Transaction. 

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 

  
 16 

 
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 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. 

  
 17 

 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). 
 Increase in Common Dividend

 On August 10, 2015, Emera’s Board of Directors approved an increase in the annual common share dividend rate from $1.60 to $1.90. The first
payment was effective November 16, 2015. 
 Maritime Link Project 

On March 6, 2015, NSPML entered into the third of the Maritime Link Project’s three major contracts: construction of approximately 400 kilometres of
transmission lines in the provinces of Newfoundland and Labrador and Nova Scotia. 
 On April 9, 2015, NSPML and the Assembly of Nova Scotia Mi’kmaq
Chiefs signed a Socio-Economic Agreement for the Maritime Link Project. Under this agreement, NSPML 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. 
 Emera Maine 

Return on Equity (“ROE”) Complaints 
 On March 3,
2015, the FERC affirmed its June 19, 2014 order approving an ROE on transmission assets of 10.57 per cent for the period October 1, 2011 to December 31, 2012. This order is in respect of the ROE complaint filed with the FERC by the Attorney
General of Massachusetts and other parties on September 30, 2011. The March 3, 2015 order is subject to appeal, and a decision is not expected until Q1 2016 at the earliest. 

Recent Financing Activity 
 Emera 

On July 3, 2015, Emera announced it would not redeem the 6,000,000 Cumulative 5-Year Rate Reset First Preferred Shares, Series A Shares (“the Series A
Shares”). 
 On August 17, 2015, Emera announced that 2,135,364 of its 6,000,000 issued 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 holders of Series B Shares will be entitled to receive floating rate cumulative preferred cash dividends, as and when declared by the Board of Directors. 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 per cent, by $25.00. 

NSPI 
 NSPI Series I $70 million 8.40 per cent medium-term
notes (“MTN”) matured on October 23, 2015 and were repaid. 
 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. 

  
 18 

 On April 30, 2015, NSPI completed the issuance of $175 million Series AA 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. 

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 an MTN in October 2014. 
 Emera Energy

 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. 

Appointments 
 Executive 

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, Emera Brunswick Pipeline 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. 
 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.

  
 19 

 OUTSTANDING COMMON STOCK DATA 
  

									
	 Common stock

Issued and outstanding:
	 	millions of
shares	 	 	millions of Canadian
dollars	 
	 December 31, 2013
	 	 	132.89	  	 	$	1,703.0	  
	 Issuance of common stock
	 	 	8.66	  	 	 	242.8	  
	 Issued for cash under Purchase Plans at market rate
	 	 	1.97	  	 	 	66.6	  
	 Discount on shares purchased under Dividend Reinvestment Plan
	 	 	—  	  	 	 	(3.0	) 
	 Options exercised under senior management stock option plan
	 	 	0.26	  	 	 	6.2	  
	 Employee Share Purchase Plan
	 	 	—  	  	 	 	0.8	  
		 	  
	  
	 	 	  
	  
	 
	 December 31, 2014
	 	 	143.78	  	 	$	2,016.4	  
	 Issuance of common stock (1)
	 	 	1.25	  	 	 	53.7	  
	 Issued for cash under Purchase Plans at market rate
	 	 	2.10	  	 	 	88.3	  
	 Discount on shares purchased under Dividend Reinvestment Plan
	 	 	—  	  	 	 	(4.1	) 
	 Options exercised under senior management stock option plan
	 	 	0.08	  	 	 	2.3	  
	 Employee Share Purchase Plan
	 	 	—  	  	 	 	0.9	  
		 	  
	  
	 	 	  
	  
	 
	 December 31, 2015
	 	 	147.21	  	 	$	2,157.5	  
		 	  
	  
	 	 	  
	  
	 

  

	(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 January 29, 2016, the amount of issued and outstanding common shares was 147.3 million. 

The weighted average shares of common stock outstanding – basic, which includes both issued and outstanding common stock and outstanding deferred share
units, for the three months ended December 31, 2015 was 146.8 million (2014 – 144.2 million). The weighted average shares of common stock outstanding – basic for the year ended December 31, 2015 was 145.8 million (2014 – 143.2
million). 

  
 20 

 NSPI 

Overview 
 NSPI was created in 1992 through the
privatization of the Crown corporation Nova Scotia Power Corporation (“NSPC”). NSPI is a fully-integrated regulated electric utility and is the primary electricity supplier in Nova Scotia, Canada. NSPI has $4.6 billion of assets and
provides electricity generation, transmission and distribution services to approximately 506,000 customers. NSPI owns 2,483 MW of generating capacity, of which approximately 50 per cent is coal-fired; 28 per cent of which is natural gas and/or oil;
19 per cent of which is hydro and wind and 3 per cent of which is biomass-fueled generation. In addition, NSPI has contracts to purchase renewable energy from independent power producers (“IPP”). These IPPs own and operate 496 MW of wind
and biomass fueled generation capacity, which will increase to 552 MW in 2016. NSPI also owns approximately 5,000 kilometres of transmission facilities and 27,000 kilometres of distribution facilities. NSPI has a workforce of approximately
1,700 people. 
 NSPI is a public utility as defined in the Public Utilities Act (Nova Scotia) (“Act”) and is subject to regulation under
the Act by the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process,
but rather participates in hearings from time to time at its request or at the UARB’s request. 
 NSPI is regulated under a cost-of-service model, with
rates established to recover prudently incurred costs of providing electricity service to customers, and to provide an appropriate return to investors. NSPI’s target regulated return on equity (“ROE”) range for 2015 and 2016 is 8.75
per cent to 9.25 per cent, based on an actual five-quarter average regulated common equity component of up to 40.0 per cent. 
 NSPI has a fuel adjustment
mechanism (“FAM”), approved by the UARB, allowing NSPI to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. Differences between prudently incurred fuel for generation and purchased power and
certain fuel-related costs (“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. 

A settlement agreement, approved by the UARB in November 2014, resulted in approximately $56.0 million of the outstanding FAM regulatory asset balance from
the prior year being collected in 2015. Residential customers did not experience a rate increase in 2015, as the FAM recovery of approximately $56.0 million was offset with the removal of charges previously included in NSPI billings. The
charges were on behalf of Efficiency Nova Scotia, a program run by the Province of Nova Scotia and regulated by the UARB. Certain industrial customer classes experienced rate increases of approximately 1.5 per cent in 2015. 

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 results in a combined rate decrease for customers of approximately 1 per cent. 
 In December 2015, the Electricity
Plan Implementation (2015) Act (“the Electricity Plan Act”) was enacted by the Province of Nova Scotia. Further information is included in the NSPI Regulated Fuel Adjustment Mechanism and Fixed Cost Deferrals Section. 

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

  
 21 

 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 years 2015 through 2019, is 25 per cent of electrical energy which will be derived from renewable sources. This target was met for 2015, with 27 per cent of NSPI’s generation mix derived
from renewable sources. In 2020, the target is 40 per cent of electrical energy to be derived from renewable sources. 
 Review of 2015 

NSPI Net Income 
  

																					
	 For the millions of Canadian dollars (except per share amounts)
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	 	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Operating revenues – regulated
	  	$	338.5	  	 	$	332.7	  	  	$	1,417.3	  	  	$	1,348.2	  	  	$	1,334.9	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Regulated fuel for generation and purchased power (1)
	  	 	132.4	  	 	 	127.4	  	  	 	542.8	  	  	 	511.7	  	  	 	556.9	  
	 Regulated fuel adjustment mechanism and fixed cost deferrals
	  	 	10.3	  	 	 	5.7	  	  	 	41.6	  	  	 	46.6	  	  	 	(40.8	) 
	 Operating, maintenance and general
	  	 	66.2	  	 	 	68.9	  	  	 	298.1	  	  	 	273.6	  	  	 	272.3	  
	 Provincial grants and taxes
	  	 	9.7	  	 	 	9.6	  	  	 	38.5	  	  	 	38.3	  	  	 	37.7	  
	 Depreciation and amortization
	  	 	52.2	  	 	 	53.0	  	  	 	206.5	  	  	 	204.0	  	  	 	213.8	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total operating expenses
	  	 	270.8	  	 	 	264.6	  	  	 	1,127.5	  	  	 	1,074.2	  	  	 	1,039.9	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income from operations
	  	 	67.7	  	 	 	68.1	  	  	 	289.8	  	  	 	274.0	  	  	 	295.0	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Other expenses net (2)
	  	 	—  	  	 	 	0.7	  	  	 	5.7	  	  	 	5.0	  	  	 	7.1	  
	 Interest expense, net
	  	 	31.3	  	 	 	29.9	  	  	 	122.1	  	  	 	116.5	  	  	 	119.6	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income before provision for income taxes
	  	 	36.4	  	 	 	37.5	  	  	 	162.0	  	  	 	152.5	  	  	 	168.3	  
	 Income tax expense (recovery)
	  	 	(6.4	) 	 	 	5.5	  	  	 	23.4	  	  	 	19.7	  	  	 	34.4	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Net income of Nova Scotia Power Inc.
	  	 	42.8	  	 	 	32.0	  	  	 	138.6	  	  	 	132.8	  	  	 	133.9	  
	 Preferred stock dividends (3)
	  	 	2.7	  	 	 	1.9	  	  	 	8.7	  	  	 	7.9	  	  	 	7.9	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income
	  	$	40.1	  	 	$	30.1	  	  	$	129.9	  	  	$	124.9	  	  	$	126.0	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share
	  	$	0.27	  	 	$	0.21	  	  	$	0.89	  	  	$	0.87	  	  	$	0.95	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  				 				  				  				  			
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 EBITDA
	  	$	119.9	  	 	$	120.4	  	  	$	490.6	  	  	$	473.0	  	  	$	501.7	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

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

	(2)	Other expenses, net is included in “Other income (expenses), net” on the Consolidated Statements of Income. 

	(3)	Preferred stock dividends are included in “Non-controlling interest in subsidiaries” on the Consolidated Statements of Income. In Q4 2015, NSPI redeemed its preferred shares. 

NSPI’s contribution to consolidated net income increased $10.0 million to $40.1 million in Q4 2015 compared to $30.1 million in Q4 2014. For the year
ended December 31, 2015, NSPI’s contribution to consolidated net income increased $5.0 million to $129.9 million in 2015 compared to $124.9 million in 2014. 

  
 22 

 Highlights of the changes are summarized in the following table: 

 

									
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 Contribution to consolidated net income – 2013
	  				 	$	126.0	  
	 Increased electric margin primarily due to increased non-fuel electric revenues across all
customers groups as a result of increased electricity pricing, partially offset by the FAM audit disallowance
	  				 	 	15.8	  
	 Decreased fixed cost deferrals primarily due to an increase in the non-fuel revenues and lower
depreciation and amortization
	  				 	 	(43.2	) 
	 Decreased depreciation and amortization primarily due to reductions in regulatory amortization
(see Regulatory Amortization section below for explanation)
	  				 	 	9.8	  
	 Decreased interest expense, net primarily due to lower levels of long-term debt
	  				 	 	3.1	  
	 Decreased income tax expense primarily due to increased tax deductions related to higher pension
contributions for 2014, decreased income before provision for income taxes and decreased non-deductible regulatory amortization, partially offset by a non-recurring change in unrecognized tax benefits in 2013 due to the enactment of tax legislation
related to preferred stock dividends
	  				 	 	14.7	  
	 Other, net (1)
	  				 	 	(1.3	) 
	 Contribution to consolidated net income – 2014
	  	$	30.1	  	 	$	124.9	  
	 Increased electric margin (see Electric Margin section below for explanation)
	  	 	0.5	  	 	 	13.0	  
	 Increased fixed cost deferrals year-over-year primarily due to the new DSM regulatory deferral
commencing in 2015, partially offset by an increase in the amount of non-fuel revenues deferred compared to 2014
	  	 	(1.7	) 	 	 	30.5	  
	 Decreased OM&G expenses quarter-over-quarter primarily due to non-recurring 2014 expenses and
increased overhead credits on capital projects, partially offset by higher pension and DSM costs; year-over-year increase is primarily due to increased DSM program costs as a results of legislation, effective January 1, 2015, requiring NSPI to
purchase electricity efficiency and conservation activities and higher pension costs, partially offset by lower storm costs
	  	 	2.7	  	 	 	(24.5	) 
	 Increased interest expense, net primarily due to lower interest revenues related to FAM and fixed
cost deferrals and higher debt levels
	  	 	(1.4	) 	 	 	(5.6	) 
	 Decreased income tax expense quarter-over-quarter primarily due to a legislated change by the
Province of Nova Scotia to the deferred tax treatment of South Canoe and Sable wind farms resulting in prior period deferred income taxes being recorded as regulatory assets in Q4 2015; year-over-year increase primarily due to increased income
before provision for income taxes
	  	 	11.9	  	 	 	(3.7	) 
	 Other, net (1)
	  	 	(2.0	) 	 	 	(4.7	) 
		  	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2015
	  	$	40.1	  	 	$	129.9	  
		  	  
	  
	 	 	  
	  
	 

  

	(1)	Amounts exclude variances included in the calculation of electric margin. 

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

 

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Electric revenues
	  	$	333.5	  	  	$	324.9	  	  	$	1,389.1	  	  	$	1,319.2	  	  	$	1,304.3	  
	 Other revenues
	  	 	5.0	  	  	 	7.8	  	  	 	28.2	  	  	 	29.0	  	  	 	30.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Operating revenues – regulated
	  	$	338.5	  	  	$	332.7	  	  	$	1,417.3	  	  	$	1,348.2	  	  	$	1,334.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  
 23 

 Electric Revenues 

Electric sales volume is primarily driven by general economic conditions, population, weather, and DSM activities. Residential and commercial electricity
sales are seasonal, with Q1 being the strongest period, reflecting colder weather and fewer daylight hours in the winter. 
 NSPI’s residential load
generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations, large office and commercial complexes, universities and hospitals. Industrial customers include manufacturing facilities and
other large volume operations. Other electric revenues consist primarily of sales to municipal electric utilities and revenues from street lighting. 

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

 

													
	 Q4 Electric Sales Volumes

Gigawatt hours (“GWh”)
	 
	 	 	2015	 	 	2014	 	  	2013	 
	 Residential
	 	 	1,075	  	 	 	1,083	  	  	 	1,173	  
	 Commercial
	 	 	757	  	 	 	767	  	  	 	811	  
	 Industrial
	 	 	592	  	 	 	630	  	  	 	635	  
	 Other
	 	 	82	  	 	 	75	  	  	 	87	  
		 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Total
	 	 	2,506	  	 	 	2,555	  	  	 	2,706	  
		 	  
	  
	 	 	  
	  
	 	  	  
	  
	 

 

													
	 Annual Electric Sales Volumes

GWh
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Residential
	  	 	4,484	  	  	 	4,370	  	  	 	4,394	  
	 Commercial
	  	 	3,134	  	  	 	3,092	  	  	 	3,148	  
	 Industrial
	  	 	2,457	  	  	 	2,513	  	  	 	2,605	  
	 Other
	  	 	337	  	  	 	312	  	  	 	320	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	10,412	  	  	 	10,287	  	  	 	10,467	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 
 

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

 

													
	 Q4 Electric Revenues

millions of Canadian dollars
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Residential
	  	$	170.7	  	  	$	165.7	  	  	$	173.5	  
	 Commercial
	  	 	100.0	  	  	 	97.3	  	  	 	100.1	  
	 Industrial
	  	 	51.1	  	  	 	50.3	  	  	 	55.4	  
	 Other
	  	 	11.7	  	  	 	11.6	  	  	 	13.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	333.5	  	  	$	324.9	  	  	$	342.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 

													
	 Annual Electric Revenues

millions of Canadian dollars
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Residential
	  	$	716.0	  	  	$	669.3	  	  	$	654.0	  
	 Commercial
	  	 	410.0	  	  	 	387.3	  	  	 	383.9	  
	 Industrial
	  	 	213.8	  	  	 	213.9	  	  	 	218.0	  
	 Other
	  	 	49.3	  	  	 	48.7	  	  	 	48.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	1,389.1	  	  	$	1,319.2	  	  	$	1,304.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 
 

  
 Electric revenues increased $8.6 million to
$333.5 million in Q4 2015 compared to $324.9 million in Q4 2014. For the year ended December 31, 2015, electric revenues increased $69.9 million to $1,389.1 million compared to $1,319.2 million in the same period in 2014. Highlights of the
changes are summarized in the following table: 
  

									
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 Electric revenues – 2013
	  				  	$	1,304.3	  
	 Increased electricity pricing effective January 1, 2014
	  				  	 	37.9	  
	 Decreased commercial and residential sales volumes, in part due to weather
	  				  	 	(12.5	) 
	 Decreased industrial sales volume
	  				  	 	(9.4	) 
	 Other
	  				  	 	(1.1	) 
		  	  
	  
	 	  	  
	  
	 
	 Electric revenues – 2014
	  	$	324.9	  	  	$	1,319.2	  
	 Increased fuel related electricity pricing effective January 1, 2015
	  	 	13.4	  	  	 	56.0	  
	 Decreased commercial and residential sales volumes as a result of decreased load
quarter-over-quarter; increased commercial and residential sales volumes year-over-year primarily due to weather and load growth earlier in the year
	  	 	(4.1	) 	  	 	19.9	  
	 Decreased industrial sales volume
	  	 	(0.6	) 	  	 	(5.2	) 
	 Other
	  	 	(0.1	) 	  	 	(0.8	) 
		  	  
	  
	 	  	  
	  
	 
	 Electric revenues – 2015
	  	$	333.5	  	  	$	1,389.1	  
		  	  
	  
	 	  	  
	  
	 

  
 24 

 Regulated Fuel for Generation and Purchased Power 

Capacity 
 To ensure reliability of service, NSPI must
maintain a generating capacity greater than firm peak demand. The total NSPI-owned generation capacity is 2,483 MW, which is supplemented by 496 MW contracted with IPPs and the Community Feed-In Tariff (“COMFIT”) participants. NSPI meets
the planning criteria for reserve capacity established by the Maritime Control Area and the Northeast Power Coordinating Council. 
 NSPI facilities
continue to rank among the best in Canada on performance indicators. The high availability and capability of low cost thermal generating stations provide lower-cost energy to customers. In 2015, thermal plant availability was 87.9 per cent compared
to 84.2 per cent in 2014. NSPI’s four-year average for thermal plant availability is 85.1 per cent. While this availability is in line with industry standards, it is particularly significant, as the NSPI coal fleet has a higher capacity factor
and better forced outage rate than the standard for its class. In addition, the Company has seen performance improvements in 2015, despite the effects of renewable integration. 

 

													
	 Q4 Production Volumes

GWh
	 
	 	 	2015	 	 	2014	 	 	2013	 
	 Coal and petcoke
	 	 	1,534	  	 	 	1,777	  	 	 	1,842	  
	 Natural gas
	 	 	354	  	 	 	186	  	 	 	423	  
	 Oil
	 	 	8	  	 	 	9	  	 	 	33	  
	 Purchased power – other
	 	 	121	  	 	 	126	  	 	 	57	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total non-renewables
	 	 	2,017	  	 	 	2,098	  	 	 	2,355	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Wind and hydro – renewables
	 	 	228	  	 	 	391	  	 	 	333	  
	 Biomass – renewables
	 	 	63	  	 	 	62	  	 	 	67	  
	 Purchased power – renewables
	 	 	434	  	 	 	255	  	 	 	214	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total renewables
	 	 	725	  	 	 	708	  	 	 	614	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total production volumes
	 	 	2,742	  	 	 	2,806	  	 	 	2,969	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	
	 Q4 Average Fuel Costs
	 
	 	 	2015	 	 	2014	 	 	2013	 
	 Dollars per megawatt hour (“MWh”)
	 	$	48	  	 	$	45	  	 	$	49	  

 

													
	 Annual Production Volumes

GWh
	 
	 	 	2015	 	 	2014	 	 	2013	 
	 Coal and petcoke
	 	 	6,364	  	 	 	6,609	  	 	 	7,098	  
	 Natural gas
	 	 	1,302	  	 	 	1,468	  	 	 	1,317	  
	 Oil
	 	 	265	  	 	 	153	  	 	 	89	  
	 Purchased power – other
	 	 	428	  	 	 	353	  	 	 	491	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total non-renewables
	 	 	8,359	  	 	 	8,583	  	 	 	8,995	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Wind and hydro – renewables
	 	 	1,275	  	 	 	1,357	  	 	 	1,234	  
	 Biomass – renewables
	 	 	206	  	 	 	258	  	 	 	130	  
	 Purchased power – renewables
	 	 	1,289	  	 	 	849	  	 	 	845	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total renewables
	 	 	2,770	  	 	 	2,464	  	 	 	2,209	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total production volumes
	 	 	11,129	  	 	 	11,047	  	 	 	11,204	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	
	 Annual Average Fuel Costs
	 
	 	 	2015	 	 	2014	 	 	2013	 
	 Dollars per MWh
	 	$	49	  	 	$	46	  	 	$	50	  

 
 

  
 Average unit Fuel Costs increased in Q4
2015 compared to Q4 2014 primarily due to generation costs associated with the COMFIT program and decreased NSPI-owned hydro generation partially due to the largest hydro site undergoing a planned overhaul this quarter. These costs are
partially offset by favourable commodity pricing. Year-over-year, average unit Fuel Costs increased in 2015 compared to the same period in 2014 primarily due to generation costs associated with the COMFIT program and increased load, partially
offset by favourable commodity pricing. 
 NSPI’s Fuel Costs are affected by commodity prices and generation mix which is largely dependent on economic
dispatch of the generating fleet, bringing the lowest cost options on stream first (after renewable energy from independent power producers, including COMFIT participants), such that the incremental cost of production increases as sales volumes
increase. Generation mix may also be affected by plant outages, availability of renewable generation, plant performance and compliance with environmental standards and regulations. 

  
 25 

 Historically, coal and petcoke have the lowest per unit fuel cost, after NSPI-owned regulated hydro and wind,
which have no fuel cost component. Purchased power, natural gas, oil and biomass have the next lowest fuel cost, depending on the relative pricing of each.

The generation mix is transforming with the addition of new non-dispatchable renewable energy sources such as wind, which typically has a higher cost per
megawatt hour (“MWh”). 
 A large portion of NSPI’s fuel supply comes from international suppliers and is subject to commodity price and
foreign exchange risk. NSPI seeks to manage this risk through the use of financial hedging instruments and physical contracts and utilizes a portfolio strategy for fuel procurement with a combination of long, medium, and short-term supply
agreements. It also provides for supply and supplier diversification. Foreign exchange risk is managed through forward and swap contracts. Fuel contracts may also be exposed to broader global conditions which may include impacts on delivery
reliability and price, despite contracted terms. NSPI has a FAM that enables the Company to seek recovery of Fuel Costs to further manage this risk. 

Regulated fuel for generation and purchased power increased $5.0 million to $132.4 million in Q4 2015 compared to $127.4 million in Q4 2014. For the year
ended December 31, 2015, regulated fuel for generation and purchased power increased $31.1 million to $542.8 million compared to $511.7 million in 2014. Highlights of the changes are summarized in the following table: 

 

									
	 For the millions of Canadian dollars
	 	Three months ended
December 31	 	 	Year ended
December 31	 
	 Regulated fuel for generation and purchased power – 2013
	 				 	$	556.9	  
	 Decreased commodity prices
	 				 	 	(29.0	) 
	 Changes in generation mix and plant performance
	 				 	 	(11.1	) 
	 Decreased sales volumes
	 				 	 	(8.8	) 
	 Increased hydro and NSPI-owned wind production
	 				 	 	(8.1	) 
	 Changes in solid fuel mix
	 				 	 	14.4	  
	 Other
	 				 	 	(2.6	) 
		 	  
	  
	 	 	  
	  
	 
	 Regulated fuel for generation and purchased power – 2014
	 	$	127.4	  	 	$	511.7	  
	 Decreased commodity prices
	 	 	(6.6	) 	 	 	(38.3	) 
	 Changes in generation mix and plant performance
	 	 	8.5	  	 	 	51.1	  
	 Increased (decreased) sales volumes
	 	 	(1.5	) 	 	 	10.6	  
	 Decreased hydro and NSPI-owned wind production
	 	 	5.0	  	 	 	3.0	  
	 Other
	 	 	(0.4	) 	 	 	4.7	  
		 	  
	  
	 	 	  
	  
	 
	 Regulated fuel for generation and purchased power – 2015
	 	$	132.4	  	 	$	542.8	  
		 	  
	  
	 	 	  
	  
	 

 Regulated Fuel Adjustment Mechanism (“FAM”) and Fixed Cost Deferrals 

Regulated Fuel Adjustment Mechanism and FAM Regulatory Deferral 

NSPI has a Regulated Fuel Adjustment Mechanism which enables the Company 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, 2015, the UARB approved NSPI’s setting of the 2016 base cost of fuel rates and its recovery of prior period unrecovered fuel related
costs as submitted in NSPI’s 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 results in a combined average rate decrease for NSPI customers of approximately 1 per cent. 
 On December 18, 2015, 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 

  
 26 

 
three-year general rate application to change non-fuel rates by April 30, 2016, if required by NSPI. The 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 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. 

In November 2014, the UARB approved a settlement agreement that has resulted in $56.0 million of the 2014 outstanding FAM balance being collected in 2015. The
settlement agreement also reduced the outstanding FAM balance of $86.1 million by $38.2 million through an offset from the amount owing to customers as a result of an agreement to allocate non-fuel revenues above NSPI’s allowed range of return
to the FAM balance, such that the December 31, 2014 FAM regulatory asset was $47.9 million. 
 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 the South Canoe and Sable Wind Projects tax treatment. 

Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. On July 2, 2014, the FAM audit findings and
recommendations relating to fiscal 2012 and 2013 were publicly released, and on January 20, 2015, the UARB disallowed $6.0 million of 2012 and 2013 fuel-related costs, which included interest of $0.9 million. The disallowance resulted in a reduction
in the amount of FAM deferral in 2014 and resulted in an after-tax impact to 2014 net income of $3.3 million. The audit for fiscal 2014 and 2015 is currently underway. 

The FAM in the Statements of Income includes the effect of Fuel Costs in both the current and preceding years, specifically: 

 

	 	•	 	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”; and 

  

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

 The FAM
regulatory asset (liability) includes amounts recognized as a regulated fuel adjustment mechanism and associated interest that is included in “Interest expense, net” on the Consolidated Statements of Income. Details of the FAM regulatory
asset (liability), classified in “Regulatory assets or Regulated liabilities” on the Consolidated Balance Sheets, are summarized in the following table: 

  
 27 

									
	 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	  
		  	  
	  
	 	  	  
	  
	 

 Of the $44.7 million non-fuel revenues applied in 2015, $40.1 million is to be applied to the FAM during the 2017 to 2019
period and $4.6 million will be applied in 2016. 
 Regulated Fixed Cost Deferrals and Fixed Cost Recovery Deferral Regulatory Assets 

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. 

Details of the DSM regulatory asset, classified in “Regulatory assets” on the Consolidated Balance Sheets, are summarized in the following table:

  

					
	 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	  
		  	  
	  
	 

 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. 

  
 28 

 Electric Margin 

NSPI distinguishes electric revenues related to the recovery of Fuel Costs (“fuel electric revenues”) from revenues related to the recovery of
non-fuel costs (“non-fuel electric revenues”) because the FAM effectively seeks to recover all prudently incurred fuel costs, and consequently, Fuel Costs and revenues related thereto (Fuel Electric Revenues) do not have a material effect
on NSPI’s electric margin or net income. 
 Electric margin is influenced primarily by revenues relating to non-fuel costs. NSPI’s customer
classes contribute differently to the Company’s non-fuel electric revenues, with residential and commercial customers contributing more than industrial customers under current rates. Accordingly, changes in residential and commercial load,
largely due to the effects of weather, from general economic conditions and from DSM have the largest effect on non-fuel electric revenues and electric margin. Changes in industrial load, which are generally due to economic conditions, have less of
an effect on non-fuel electric revenues than would a similar volume change in residential and commercial load. 
 The addition of new generation sources to
meet legislated greenhouse gas emission reductions and renewable generation requirements is among the drivers increasing NSPI’s fixed costs. Electric margin, which represents the revenues available to cover these costs, has increased in a
corresponding manner. 
 Operating revenues are summarized in the following table: 

 

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014(1)	 	  	2013(1)	 
	 Fuel electric revenues – current year
	  	$	123.7	  	  	$	124.2	  	  	$	518.5	  	  	$	512.5	  	  	$	488.7	  
	 Fuel electric revenues – recovery of preceding years
	  	 	13.4	  	  	 	—  	  	  	 	56.0	  	  	 	—  	  	  	 	29.8	  
	 Non-fuel electric revenues
	  	 	196.4	  	  	 	200.7	  	  	 	814.6	  	  	 	806.7	  	  	 	785.8	  
	 Other revenues
	  	 	5.0	  	  	 	7.8	  	  	 	28.2	  	  	 	29.0	  	  	 	30.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Operating revenues
	  	$	338.5	  	  	$	332.7	  	  	$	1,417.3	  	  	$	1,348.2	  	  	 	1,334.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Electric margin is summarized in the following table: 

 

																					
	 Fuel electric revenues – current year
	  	$	123.7	  	 	$	124.2	  	 	$	518.5	  	 	$	512.5	  	 	$	488.7	  
	 Fuel electric revenues – recovery of preceding years
	  	 	13.4	  	 	 	—  	  	 	 	56.0	  	 	 	—  	  	 	 	29.8	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total fuel electric revenues
	  	 	137.1	  	 	 	124.2	  	 	 	574.5	  	 	 	512.5	  	 	 	518.5	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Regulated fuel for generation and purchased power
	  	 	(132.4	) 	 	 	(127.4	) 	 	 	(542.8	) 	 	 	(511.7	) 	 	 	(556.9	) 
	 Regulated fuel adjustment mechanism
	  	 	(4.4	) 	 	 	(1.5	) 	 	 	(31.9	) 	 	 	(6.4	) 	 	 	37.8	  
	 Fuel-related foreign exchange gain (loss) (2)
	  	 	(0.3	) 	 	 	(0.1	) 	 	 	0.2	  	 	 	0.5	  	 	 	0.6	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net fuel revenue (expense)
	  	 	—  	  	 	 	(4.8	) 	 	 	—  	  	 	 	(5.1	) 	 	 	—  	  
	 Non-fuel electric revenues
	  	 	196.4	  	 	 	200.7	  	 	 	814.6	  	 	 	806.7	  	 	 	785.8	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Electric margin
	  	$	196.4	  	 	$	195.9	  	 	$	814.6	  	 	$	801.6	  	 	$	785.8	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	(1)	NSPI removed “Fixed cost deferrals” from its calculation of electric margin in Q2 2014 as management believed it better reflected its business operations. Prior periods have been retroactively restated.

	(2)	As reported in “Other income (expenses) net”, on the Consolidated Statement of Income. 

 NSPI’s
electric margin increased $0.5 million to $196.4 million in Q4 2015 compared to $195.9 million in Q4 2014 primarily due to a Q4 2014 FAM audit disallowance, partially offset by decreased residential and commercial load. NSPI’s electric margin
for the year ended December 31, 2015 increased $13.0 million to $814.6 million compared to $801.6 million in 2014 primarily due to increased residential load, largely due to weather and a FAM audit disallowance in 2014. 

  
 29 

 

													
	 Q4 Average Electric Margin (Dollars per MWh)
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Dollars per MWh
	  	$	78	  	  	$	77	  	  	$	76	  

 

													
	 Annual Average Electric Margin (Dollars per MWh)
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Dollars per MWh
	  	$	78	  	  	$	78	  	  	$	75	  

 
 

  
 NSPI’s electric margin per MWh is
consistent quarter-over-quarter and year-over-year. 
 Regulatory Amortization 

Regulatory amortization is included in “Depreciation and amortization” on the Consolidated Statements of Income. Highlights of the changes in
regulatory amortization are summarized in the following table: 
  

									
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 Regulatory amortization – 2013
	  	$	 	  	  	$	37.4	  
	 Decreased pre-2003 income tax regulatory asset amortization (1)
	  				  	 	(14.0	) 
	 2012 Large Industrial Customers FCR amortization, which commenced in 2013, following the 2013
General Rate Application settlement agreement
	  				  	 	2.4	  
	 Other regulatory amortization
	  				  	 	(0.9	) 
		  	  
	  
	 	  	  
	  
	 
	 Regulatory amortization – 2014
	  	$	8.9	  	  	$	24.9	  
		  	  
	  
	 	  	  
	  
	 
	 Decreased 2012 Large Industrial Customers Fixed Cost Recovery amortization, which commenced in
2013, following the 2013 General Rate Application settlement agreement
	  	 	(2.7	) 	  	 	(2.7	) 
	 Other regulatory amortization
	  	 	(1.6	) 	  	 	(1.4	) 
		  	  
	  
	 	  	  
	  
	 
	 Regulatory amortization – 2015
	  	$	4.6	  	  	$	20.8	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	The UARB’s 2010 ROE decision has allowed NSPI flexibility in the recognition of additional amortization of the pre-2003 income tax regulatory asset in current periods, which accordingly reduces amortization in
future periods resulting in a lower customer rate requirement. 

 Provincial Grants and Taxes 

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

Income Taxes 
 NSPI is subject to corporate income tax at
the statutory rate of 31.0 per cent (combined federal and provincial income tax rate) and Part VI.1 tax relating to preferred stock dividends at the statutory rate of 40.0 per cent. NSPI also receives a reduction in its corporate income tax
otherwise payable related to the Part VI.1 tax deduction of 43.4 per cent of preferred stock dividends. 
 Non-GAAP Measure 

Electric Margin Reconciliation 
 “Electric
margin” is a non-GAAP financial measure used to show the amounts that NSPI retains to recover its non-fuel costs, as effectively all prudently incurred Fuel Costs are recovered through the FAM. NSPI’s electric margin may not be comparable
to other companies’ electric margin measures, but in management’s view appropriately reflects NSPI’s regulatory framework. This measure is not intended to replace “Income from operations” which, as determined in accordance
with GAAP, is an indicator of operating performance. Electric margin was discussed in the Financial Review Electric Margin section above. 

  
 30 

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Income from operations
	  	$	67.7	  	  	$	68.1	  	  	$	289.8	  	  	$	274.0	  	  	$	295.0	  
	 Less:
	  				  				  				  				  			
	 Fuel electric revenues – current and preceding years
	  	 	137.1	  	  	 	124.2	  	  	 	574.5	  	  	 	512.5	  	  	 	518.5	  
	 FAM audit disallowance
	  	 	—  	  	  	 	4.8	  	  	 	—  	  	  	 	5.1	  	  	 	—  	  
	 Other revenues
	  	 	5.0	  	  	 	7.8	  	  	 	28.2	  	  	 	29.0	  	  	 	30.6	  
	 Add back:
	  				  				  				  				  			
	 Regulated fuel for generation and purchased power
	  	 	132.4	  	  	 	127.4	  	  	 	542.8	  	  	 	511.7	  	  	 	556.9	  
	 Operating, maintenance and general
	  	 	66.2	  	  	 	68.9	  	  	 	298.1	  	  	 	273.6	  	  	 	272.3	  
	 Property, state and municipal taxes
	  	 	9.7	  	  	 	9.6	  	  	 	38.5	  	  	 	38.3	  	  	 	37.7	  
	 Depreciation and amortization
	  	 	52.2	  	  	 	53.0	  	  	 	206.5	  	  	 	204.0	  	  	 	213.8	  
	 Regulated fuel adjustment mechanism and fixed cost deferrals
	  	 	10.3	  	  	 	5.7	  	  	 	41.6	  	  	 	46.6	  	  	 	(40.8	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Electric margin
	  	$	196.4	  	  	$	195.9	  	  	$	814.6	  	  	$	801.6	  	  	$	785.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  
 31 

 EMERA MAINE 

Overview 
 Emera Maine is a transmission and distribution
(“T&D”) electric utility with assets of approximately $1.1 billion serving approximately 158,000 customers in the State of Maine in the United States. Effective January 1, 2014, Bangor Hydro Electric Company (“Bangor Hydro”)
and Maine Public Service Company (“MPS”) merged, becoming Emera Maine. 
 Electricity generation is deregulated in Maine, and several suppliers
compete to provide customers with the energy delivered through Emera Maine’s T&D networks. Emera Maine owns and operates approximately 1,700 kilometres of transmission facilities and 15,000 kilometres of distribution facilities. Emera
Maine’s workforce is approximately 400 people. 
 Approximately 55 per cent of Emera Maine’s electric revenue represents distribution operations,
31 per cent is associated with local transmission operations and 14 per cent relates to stranded cost recoveries. The rates for each element 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. 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 

Local transmission rates for Bangor Hydro District (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 (“ISO-NE”) 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. 

  
 32 

 The Bangor Hydro District’s bulk transmission assets are managed by 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 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). 
 As at December 31, 2015, the Company had accrued $5.0 million associated with the FERC ROE complaints (2014 – $7.3 million). 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 

Local transmission rates for MPS District’s (the franchise electric service territory associated with the former Maine Public Service Company in the Maine
counties of Aroostook and a portion of Penobscot) 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 MPS 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 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. 

  
 33 

 Bangor Hydro District 

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 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 Hydro 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.
 MPS District 

Effective January 1, 2015, the stranded cost rates for the MPS 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 income. This January 1, 2015, rate decrease remained in effect for all of 2015 and there was no
rate change on July 1, 2015. 

  
 34 

 Review of 2015 

Emera Maine Net Income 
  

																					
	 For the millions of USD (except per share amounts)
	  	Three months ended
December 31	 	  	For the year ended
December 31	 
	 	  	2015	 	 	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Operating revenues – regulated
	  	$	52.6	  	 	$	55.9	  	  	$	221.6	  	  	$	219.0	  	  	$	211.2	  
	 Operating revenues – non-regulated
	  	 	0.1	  	 	 	—  	  	  	 	0.6	  	  	 	0.5	  	  	 	0.5	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total operating revenues
	  	 	52.7	  	 	 	55.9	  	  	 	222.2	  	  	 	219.5	  	  	 	211.7	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Regulated fuel for generation and purchased power
	  	 	7.5	  	 	 	9.4	  	  	 	28.9	  	  	 	29.7	  	  	 	30.8	  
	 Transmission pool expense (1)
	  	 	6.1	  	 	 	6.0	  	  	 	25.4	  	  	 	23.9	  	  	 	22.9	  
	 Operating, maintenance and general
	  	 	14.2	  	 	 	10.3	  	  	 	49.1	  	  	 	47.0	  	  	 	44.2	  
	 Provincial, state and municipal taxes
	  	 	2.8	  	 	 	3.2	  	  	 	12.8	  	  	 	11.5	  	  	 	10.2	  
	 Depreciation and amortization
	  	 	9.5	  	 	 	9.5	  	  	 	36.5	  	  	 	43.3	  	  	 	35.9	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total operating expenses
	  	 	40.1	  	 	 	38.4	  	  	 	152.7	  	  	 	155.4	  	  	 	144.0	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income from operations
	  	 	12.6	  	 	 	17.5	  	  	 	69.5	  	  	 	64.1	  	  	 	67.7	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Other income (expenses), net
	  	 	(1.9	) 	 	 	0.9	  	  	 	0.8	  	  	 	4.2	  	  	 	3.3	  
	 Interest expense, net
	  	 	3.4	  	 	 	3.5	  	  	 	13.7	  	  	 	12.2	  	  	 	12.2	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income before provision for income taxes
	  	 	7.3	  	 	 	14.9	  	  	 	56.6	  	  	 	56.1	  	  	 	58.8	  
	 Income tax expense (recovery)
	  	 	3.4	  	 	 	4.6	  	  	 	21.0	  	  	 	17.7	  	  	 	21.6	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income – USD
	  	$	3.9	  	 	$	10.3	  	  	$	35.6	  	  	$	38.4	  	  	$	37.2	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income – CAD
	  	$	5.2	  	 	$	11.7	  	  	$	45.1	  	  	$	42.4	  	  	$	38.4	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share – CAD
	  	$	0.04	  	 	$	0.08	  	  	$	0.31	  	  	$	0.30	  	  	$	0.29	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Net income weighted average foreign exchange rate – CAD/USD
	  	$	1.33	  	 	$	1.14	  	  	$	1.27	  	  	$	1.10	  	  	$	1.03	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  				 				  				  				  			
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 EBITDA – USD
	  	$	20.2	  	 	$	27.9	  	  	$	106.8	  	  	$	111.6	  	  	$	106.9	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 EBITDA – CAD
	  	$	26.8	  	 	$	31.8	  	  	$	136.0	  	  	$	123.4	  	  	$	110.3	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

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

Emera Maine’s USD contribution to consolidated net income decreased by $6.4 million to $3.9 million in Q4 2015 compared to $10.3 million in Q4
2014. For the year ended December 31, 2015, Emera Maine’s USD contribution to consolidated net income decreased by $2.8 million to $35.6 million compared to $38.4 million in 2014. Highlights of the USD net income changes are summarized in
the following table: 

  
 35 

									
	 For the millions of US dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 Contribution to consolidated net income – 2013
	  				 	$	37.2	  
	 Increased operating revenues primarily due to rate changes
	  				 	 	7.8	  
	 Decreased regulated fuel for purchased power primarily due to changes in purchased power
contracts
	  				 	 	1.1	  
	 Increased OM&G expenses primarily due to decreased capitalized construction overheads and
increased storm expenses
	  				 	 	(2.8	) 
	 Increased depreciation and amortization primarily due to increased plant in service
	  				 	 	(7.4	) 
	 Decreased income tax expense primarily due to decreased income before provision for income taxes,
a change in estimate of prior year expected benefit of tax deductions and changes in regulatory amortization
	  				 	 	3.9	  
	 Other
	  				 	 	(1.4	) 
		  	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2014
	  	$	10.3	  	 	$	38.4	  
	 (Decreased) increased operating revenues – see Operating Revenues – Regulated section
below
	  	 	(3.3	) 	 	 	2.6	  
	 Increased OM&G primarily due to decreased capitalized construction overheads, partially offset
by changes in pension and retiree medical expenses
	  	 	(3.9	) 	 	 	(2.1	) 
	 Decreased depreciation and amortization due to lower depreciation rates as a result of a 2014
depreciation study and lower regulatory amortization; no change quarter-over-quarter as lower depreciation rates are offset by increased regulatory amortization
	  	 	—  	  	 	 	6.8	  
	 Decreased other income primarily due to AFUDC adjustments recognized as a result of a FERC
audit
	  	 	(2.8	) 	 	 	(3.4	) 
	 Decreased income tax expense quarter-over-quarter primarily due to lower income before provision
for income taxes, partially offset by AFUDC adjustments recorded as a result of a FERC audit; year-over-year increase primarily due to decrease in regulatory amortization and AFUDC adjustments recorded as a result of a FERC audit
	  	 	1.2	  	 	 	(3.3	) 
	 Other
	  	 	2.4	  	 	 	(3.4	) 
		  	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2015
	  	$	3.9	  	 	$	35.6	  
		  	  
	  
	 	 	  
	  
	 

 Emera Maine’s CAD contribution to consolidated net income decreased by $6.5 million to $5.2 million in Q4 2015 from $11.7
million in Q4 2014. For the year ended December 31, 2015, Emera Maine’s CAD contribution to consolidated net income increased by $2.7 million to $45.1 million from $42.4 million in 2014. The impact of a stronger USD, increased CAD earnings
quarter-over-quarter by $0.7 million for the three months ended December 31, 2015 and year-over-year $6.1 million for the year ended December 31, 2015. 

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

 

													
	 Q4 Operating Revenues – Regulated

millions of US dollars
	 
	 	 	2015	 	 	2014	 	 	2013	 
	 Electric revenues
	 	$	38.0	  	 	$	41.2	  	 	$	39.3	  
	 Transmission pool revenues
	 	 	11.0	  	 	 	11.3	  	 	 	11.3	  
	 Resale of purchased power
	 	 	3.6	  	 	 	3.4	  	 	 	3.5	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Operating revenues – regulated
	 	$	52.6	  	 	$	55.9	  	 	$	54.1	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 

													
	 Annual Operating Revenues – Regulated

millions of US dollars
	 
	 	 	2015	 	 	2014	 	 	2013	 
	 Electric revenues
	 	$	160.0	  	 	$	156.8	  	 	$	146.9	  
	 Transmission pool revenues
	 	 	49.1	  	 	 	49.0	  	 	 	50.7	  
	 Resale of purchased power
	 	 	12.5	  	 	 	13.2	  	 	 	13.6	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Operating revenues – regulated
	 	$	221.6	  	 	$	219.0	  	 	$	211.2	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 
 

  
 36 

 Electric Revenues 

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

 

													
	 Q4 Electric Sales Volumes
	 
	 GWh
	  	2015	 	  	2014	 	  	2013	 
	 Residential
	  	 	199	  	  	 	203	  	  	 	209	  
	 Commercial
	  	 	192	  	  	 	193	  	  	 	198	  
	 Industrial
	  	 	94	  	  	 	104	  	  	 	107	  
	 Other
	  	 	3	  	  	 	4	  	  	 	4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	488	  	  	 	504	  	  	 	518	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 

													
	 Annual Electric Sales Volumes
	 
	 GWh
	  	2015	 	  	2014	 	  	2013	 
	 Residential
	  	 	802	  	  	 	805	  	  	 	801	  
	 Commercial
	  	 	781	  	  	 	788	  	  	 	798	  
	 Industrial
	  	 	423	  	  	 	426	  	  	 	424	  
	 Other
	  	 	14	  	  	 	15	  	  	 	15	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	2,020	  	  	 	2,034	  	  	 	2,038	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 
 

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

 

													
	 Q4 Electric Revenues

millions of US dollars
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Residential
	  	$	19.2	  	  	$	19.8	  	  	$	18.9	  
	 Commercial
	  	 	14.8	  	  	 	14.7	  	  	 	14.2	  
	 Industrial
	  	 	3.2	  	  	 	3.8	  	  	 	3.6	  
	 Other (1)
	  	 	0.8	  	  	 	2.9	  	  	 	2.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	38.0	  	  	$	41.2	  	  	$	39.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 

													
	 Annual Electric Revenues

millions of US dollars
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Residential
	  	$	76.4	  	  	$	75.8	  	  	$	71.7	  
	 Commercial
	  	 	57.9	  	  	 	57.2	  	  	 	54.7	  
	 Industrial
	  	 	14.1	  	  	 	14.2	  	  	 	13.1	  
	 Other (1)
	  	 	11.6	  	  	 	9.6	  	  	 	7.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	160.0	  	  	$	156.8	  	  	$	146.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 
 

  

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

Electric revenues decreased $3.2 million to $38.0 million in Q4 2015 compared to $41.2 million in Q4 2014. For the year ended December 31, 2015,
electric revenues increased $3.2 million to $160.0 million in 2015 compared to $156.8 million in 2014. Highlights of the changes are summarized in the following table: 
  

									
	 For the millions of US dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 Electric revenues – 2013
	  				  	$	146.9	  
	 Decreased sales volumes primarily due to weather
	  				  	 	(0.2	) 
	 Increased primarily due to rate changes
	  				  	 	9.5	  
	 Decreased due to changes in amounts recognized related to the FERC ROE complaints
	  				  	 	(2.6	) 
	 Change in estimate for the transmission revenue
	  				  	 	3.2	  
		  	  
	  
	 	  	  
	  
	 
	 Electric revenues – 2014
	  	$	41.2	  	  	$	156.8	  
	 Decreased sales volumes primarily due to weather
	  	 	(1.2	) 	  	 	(1.1	) 
	 Increased primarily due to rate changes
	  	 	0.5	  	  	 	3.8	  
	 Increased due to FERC transmission rate refund
	  	 	3.9	  	  	 	6.0	  
	 Decreased due to transmission revenue adjustments
	  	 	(6.4	) 	  	 	(5.5	) 
		  	  
	  
	 	  	  
	  
	 
	 Electric revenues – 2015
	  	$	38.0	  	  	$	160.0	  
		  	  
	  
	 	  	  
	  
	 

 

													
	 Q4 Electric Revenue / MWh
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Dollars per MWh
	  	$	78	  	  	$	82	  	  	$	76	  

 

													
	 Annual Average Electric Revenue / MWh
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Dollars per MWh
	  	$	79	  	  	$	77	  	  	$	72	  

 
 

  
 The change in average electric revenue per
MWh in Q4 2015 compared to Q4 2014 and for the year ended December 31, 2015 compared to the same period in 2014 reflects transmission revenue adjustments and changes in the amounts recorded related to the transmission rate refund associated with the
FERC ROE complaints. 

  
 37 

 Transmission Pool Revenues and Expenses 

Transmission pool expenses are recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income. Transmission
pool revenues are recorded in “Operating revenues – regulated” in the Consolidated Statements of Income. 
 Transmission pool revenues and
expenses are summarized in the following table: 
  

																					
	 For the millions of US dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Transmission pool revenues
	  	$	11.0	  	  	$	11.3	  	  	$	49.1	  	  	$	49.0	  	  	$	50.7	  
	 Transmission pool expenses
	  	 	6.1	  	  	 	6.0	  	  	 	25.4	  	  	 	23.9	  	  	 	22.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Net transmission pool revenues
	  	$	4.9	  	  	$	5.3	  	  	$	23.7	  	  	$	25.1	  	  	$	27.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Emera Maine’s net transmission pool revenues decreased $0.4 million to $4.9 million in Q4 2015 compared to $5.3 million
in Q4 2014. For the year ended December 31, 2015, net transmission pool revenues decreased $1.4 million to $23.7 million compared to $25.1 million in 2014 primarily due to changes in the level of investment in regionally funded transmission assets
and the impacts of weather in the New England region. 
 Resale of Purchased Power and Regulated Fuel for Generation and Purchased Power 

Emera Maine has several above-market power purchase contracts with generators in its Bangor District service territory. The power purchased under these
arrangements is resold at market rates significantly below the contract rates. The difference between the cost of the power purchased under these arrangements and the revenue collected is recovered through stranded cost rates under a full
reconciliation rate mechanism. 
 Resale of purchased power increased $0.2 million in Q4 2015 to $3.6 million compared to $3.4 million in Q4 2014, and for
the year ended December 31, 2015 decreased $0.7 million to $12.5 million in 2015 compared to $13.2 million in 2014 primarily due to changes in market rates for electricity in New England in 2015. 

Income Taxes 
 Emera Maine is subject to corporate income
tax at the statutory rate of 40.8 per cent (combined US federal and state income tax rate). 

  
 38 

 EMERA CARIBBEAN 

Overview 
 Emera Caribbean includes the following
consolidated and non-consolidated investments: 
 Consolidated Investments 
  

	 	•	 	95.5 per cent (2014 – 80.6 per cent) investment in Emera (Caribbean) Incorporated (“ECI”) and its wholly owned subsidiary Barbados Light & Power Company Ltd. (“BLPC”), a vertically
integrated utility and the provider of electricity on the island of Barbados, serving approximately 126,000 customers and regulated by the Fair Trading Commission, Barbados. The government of Barbados has granted BLPC a franchise to generate,
transmit and distribute electricity on the island until 2028. BLPC owns 239 MW of oil-fired generation, 116 kilometres of transmission facilities and 2,800 kilometres of distribution facilities. BLPC has a workforce of 330 people. BLPC is regulated
under a cost-of-service model with rates set to recover prudently incurred costs of providing electricity service to customers, and to provide an appropriate return to investors. BLPC’s approved allowed regulated return on rate base for 2015
was 10.0 per cent. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. Emera has initiated a process to purchase the remaining 4.5 per cent of common shares from minority shareholders of ECI, with
anticipated completion in Q1 2016. 

  

	 	•	 	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 Ltd. (“GBPC”), which is a vertically
integrated utility and the sole provider of electricity on Grand Bahama Island. GBPC serves approximately 19,000 customers. GBPC owns 98 MW of oil-fired generation, 138 kilometres of transmission facilities and 850 kilometres of
distribution facilities and has a workforce of 205 people. GBPC is regulated by GBPA, which 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 was 10.0 per cent. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. Effective February 1, 2016, the GBPA approved GBPC’s General Rate
Application applicable for the 2016 through 2018 period. Residential customers will see decreases up to 4.5 per cent, while commercial customers will see an increase of 1.5 per cent. Commercial customers consume approximately 70 per cent of
GBPC’s production. Rates were approved based upon an 8.8 per cent 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. 

  

	 	•	 	49.6 per cent (2014 – 41.8 per cent) indirect controlling interest, through ECI, in Dominica Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica. Domlec serves
approximately 36,000 customers and is regulated by the Independent Regulatory Commission, Dominica. Domlec owns 20 MW of oil-fired generation, 7 MW of hydro production, 452 kilometres of transmission facilities and 640 kilometres of
distribution facilities. Domlec has a workforce of 238 people. 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 was 15 per cent. A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a
timely manner. 

  

	 	•	 	EUS Bahamas, providing utility construction and plant operation services in The Bahamas. 

  
 39 

 Equity Investment 
  

	 	•	 	18.2 per cent indirect interest (2014 – 15.4 per cent), through ECI, in St. Lucia Electricity Services Limited (“Lucelec”), a vertically integrated regulated electric utility on the island of St. Lucia,
which is regulated by the Government of St. Lucia. The investment in Lucelec is accounted for on the equity basis. 

 Review of 2015

 Emera Caribbean Net Income 
  

																					
	 For the millions of USD (except per share amounts)
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Operating revenues – regulated
	  	$	84.3	  	  	$	105.4	  	  	$	346.0	  	  	$	432.1	  	  	$	427.4	  
	 Operating revenues – non-regulated
	  	 	—  	  	  	 	2.2	  	  	 	6.0	  	  	 	8.0	  	  	 	8.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total operating revenues
	  	 	84.3	  	  	 	107.6	  	  	 	352.0	  	  	 	440.1	  	  	 	436.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Regulated fuel for generation and purchased power
	  	 	37.0	  	  	 	60.0	  	  	 	158.1	  	  	 	247.6	  	  	 	248.6	  
	 Non-regulated direct costs
	  	 	0.2	  	  	 	1.8	  	  	 	5.9	  	  	 	7.1	  	  	 	7.6	  
	 Operating, maintenance and general
	  	 	23.7	  	  	 	28.6	  	  	 	101.5	  	  	 	107.3	  	  	 	103.7	  
	 Property taxes (1)
	  	 	0.2	  	  	 	0.4	  	  	 	1.8	  	  	 	1.6	  	  	 	1.5	  
	 Depreciation and amortization
	  	 	8.6	  	  	 	7.7	  	  	 	34.5	  	  	 	33.3	  	  	 	30.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total operating expenses
	  	 	69.7	  	  	 	98.5	  	  	 	301.8	  	  	 	396.9	  	  	 	392.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income from operations
	  	 	14.6	  	  	 	9.1	  	  	 	50.2	  	  	 	43.2	  	  	 	43.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income from equity investment
	  	 	0.6	  	  	 	0.4	  	  	 	2.3	  	  	 	2.1	  	  	 	1.7	  
	 Other income (expenses), net
	  	 	1.9	  	  	 	1.3	  	  	 	4.8	  	  	 	5.7	  	  	 	11.8	  
	 Interest expense, net
	  	 	2.7	  	  	 	2.7	  	  	 	10.8	  	  	 	11.5	  	  	 	11.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income before provision for income taxes
	  	 	14.4	  	  	 	8.1	  	  	 	46.5	  	  	 	39.5	  	  	 	45.6	  
	 Income tax expense (recovery)
	  	 	1.5	  	  	 	0.9	  	  	 	2.4	  	  	 	2.7	  	  	 	3.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Net income
	  	 	12.9	  	  	 	7.2	  	  	 	44.1	  	  	 	36.8	  	  	 	42.4	  
	 Non-controlling interest in subsidiaries
	  	 	2.9	  	  	 	1.9	  	  	 	10.2	  	  	 	8.3	  	  	 	8.9	  
	 Preferred stock dividends (2)
	  	 	—  	  	  	 	—  	  	  	 	2.5	  	  	 	2.5	  	  	 	1.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income – USD
	  	$	10.0	  	  	$	5.3	  	  	$	31.4	  	  	$	26.0	  	  	$	32.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income – CAD
	  	$	13.3	  	  	$	6.1	  	  	$	40.5	  	  	$	28.7	  	  	$	33.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share – CAD
	  	$	0.09	  	  	$	0.04	  	  	$	0.28	  	  	$	0.20	  	  	$	0.25	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Net income weighted average foreign exchange rate – CAD/USD
	  	$	1.33	  	  	$	1.15	  	  	$	1.29	  	  	$	1.10	  	  	$	1.03	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  				  				  				  				  			
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 EBITDA – USD
	  	$	25.7	  	  	$	18.5	  	  	$	91.8	  	  	$	84.3	  	  	$	88.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 EBITDA – CAD
	  	$	34.3	  	  	$	21.0	  	  	$	117.9	  	  	$	93.0	  	  	$	91.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	(1)	Included in “Provincial, state and municipal taxes” on the Consolidated Statements of Income. 

	(2)	Preferred stock dividends are included in “Non-controlling interest in subsidiaries” on the Consolidated Statements of Income. 

Emera Caribbean’s USD contribution to consolidated net income increased by $4.7 million to $10.0 million in Q4 2015 compared to $5.3 million in Q4
2014. For the year ended December 31, 2015, Emera Caribbean’s USD contribution to consolidated net income increased by $5.4 million to $31.4 million compared to $26.0 million in 2014. Highlights of the net income changes are
summarized in the following table: 

  
 40 

									
	 For the millions of US dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 Contribution to consolidated net income – 2013
	  				 	$	32.3	  
	 Increased OM&G expenses due to restructuring costs at ECI, partially offset by operational
cost savings at GBPC
	  				 	 	(0.4	) 
	 Decreased other income (expenses), net primarily due to reduced investment income relating to an
adjustment to ECI’s self-insurance fund
	  				 	 	(3.4	) 
	 Increased preferred dividends due to timing of preferred share issuance
	  				 	 	(1.3	) 
	 Effect of the non-taxable gain on acquisition of Domlec, partially offset by the acquisition of
controlling interest in Domlec on April 10, 2013
	  				 	 	(2.0	) 
	 Other
	  				 	 	0.8	  
		  	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2014
	  	$	5.3	  	 	$	26.0	  
	 Increased Electric Margin – see Electric Margin section
	  	 	1.8	  	 	 	3.7	  
	 Decreased OM&G primarily due to lower pension expense, savings and timing of maintenance
costs, and restructuring payroll savings at BLPC, lower outage costs at GBPC, and the reversal of Domlec regulatory costs; year-over-year restructuring costs at BLPC offset the decreased OM&G
	  	 	4.9	  	 	 	5.8	  
	 Increased non-controlling interest due to increased earnings from ECI, GBPC and Domlec
	  	 	(1.0	) 	 	 	(1.9	) 
	 Other
	  	 	(1.0	) 	 	 	(2.2	) 
		  	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2015
	  	$	10.0	  	 	$	31.4	  
		  	  
	  
	 	 	  
	  
	 

 Emera Caribbean’s CAD contribution to consolidated net income increased by $7.2 million to $13.3 million in Q4 2015
compared to $6.1 million in Q4 2014. For the year ended December 31, 2015, Emera Caribbean’s CAD contribution to consolidated net income increased by $11.8 million to $40.5 million in 2015 compared to $28.7 million in 2014. The impact
of a stronger USD, quarter-over-quarter increased CAD earnings by $1.8 million for the three months ended December 31, 2015 compared to 2014. The impact of a stronger USD year-over-year increased CAD earnings by $6.0 million in 2015 compared to
2014. 
 Operating Revenues – Regulated 
 Emera
Caribbean’s operating revenues – regulated include sales of electricity and other services as summarized in the following table: 

 

													
	Q4 Operating Revenues – Regulated	 
	 millions of US dollars
	 
	 	 	2015	 	 	2014	 	 	2013	 
	 Electric revenues – base rates
	 	$	47.1	  	 	 	45.2	  	 	$	45.4	  
	 Fuel charge
	 	 	36.3	  	 	 	59.4	  	 	 	60.3	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total electric revenues
	 	 	83.4	  	 	 	104.6	  	 	 	105.7	  
	 Other revenues
	 	 	0.9	  	 	 	0.8	  	 	 	0.8	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Operating revenues – regulated
	 	$	84.3	  	 	 	105.4	  	 	$	106.5	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 

													
	Annual Operating Revenues – Regulated	 
	 millions of US dollars
	 
	 	 	2015	 	 	2014	 	 	2013*	 
	 Electric revenues – base rates
	 	$	186.7	  	 	$	182.7	  	 	$	177.0	  
	 Fuel charge
	 	 	155.4	  	 	 	245.2	  	 	 	247.0	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total electric revenues
	 	 	342.1	  	 	 	427.9	  	 	 	424.0	  
	 Other revenues
	 	 	3.9	  	 	 	4.2	  	 	 	3.4	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Operating revenues – regulated
	 	$	346.0	  	 	$	432.1	  	 	$	427.4	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	
	 *  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10,
2013.
	       

 
 

  
 41 

 Electric Revenues 

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

 

													
	Q4 Electric Sales Volumes	 
	 GWh
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Residential
	  	 	115	  	  	 	111	  	  	 	110	  
	 Commercial
	  	 	197	  	  	 	189	  	  	 	191	  
	 Industrial
	  	 	25	  	  	 	26	  	  	 	18	  
	 Other
	  	 	7	  	  	 	7	  	  	 	7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	344	  	  	 	333	  	  	 	326	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

													
	Annual Electric Sales Volumes	 
	 GWh
	 
	 	  	2015	 	  	2014	 	  	2013*	 
	 Residential
	  	 	453	  	  	 	440	  	  	 	428	  
	 Commercial
	  	 	764	  	  	 	751	  	  	 	744	  
	 Industrial
	  	 	104	  	  	 	102	  	  	 	93	  
	 Other
	  	 	24	  	  	 	26	  	  	 	26	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	1,345	  	  	 	1,319	  	  	 	1,291	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	
	 *  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10,
2013.
	       

 
 

  
 Electric volumes increased in Q4 2015
compared to Q4 2014 and for the year ended December 31, 2015 as a result of warmer weather. 
 Electric revenues are
summarized in the following tables by customer class: 

 

													
	Q4 Electric Revenues	 
	 millions of US dollars
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Residential
	  	$	26.9	  	  	$	34.5	  	  	$	33.3	  
	 Commercial
	  	 	47.7	  	  	 	60.7	  	  	 	62.9	  
	 Industrial
	  	 	7.2	  	  	 	7.5	  	  	 	7.6	  
	 Other
	  	 	1.6	  	  	 	1.9	  	  	 	1.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	83.4	  	  	$	104.6	  	  	$	105.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 

													
	Annual Electric Revenues	 
	 millions of US dollars
	 
	 	  	2015	 	  	2014	 	  	2013*	 
	 Residential
	  	$	110.9	  	  	$	142.9	  	  	$	133.2	  
	 Commercial
	  	 	194.8	  	  	 	250.7	  	  	 	251.5	  
	 Industrial
	  	 	30.1	  	  	 	26.9	  	  	 	31.5	  
	 Other
	  	 	6.3	  	  	 	7.4	  	  	 	7.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	342.1	  	  	$	427.9	  	  	$	424.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	
	 *  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10,
2013.
	       

 
 

  
 Electric revenues decreased $21.2 million
to $83.4 million in Q4 2015 compared to $104.6 million in Q4 2014. For the year ended December 31, 2015, electric revenues decreased $85.8 million to $342.1 million compared to $427.9 million in 2014. Highlights of the changes are
summarized in the following table: 
  

									
	 For the millions of US dollars
	 	Three months ended
December 31	 	 	Year ended
December 31	 
	 Electric revenues – 2013
	 				 	$	424.0	  
	 Increased due to acquisition of a controlling interest in Domlec
	 				 	 	8.2	  
	 Decreased fuel charge primarily due to lower fuel prices
	 				 	 	(4.8	) 
	 Increased due to higher sales volumes in GBPC
	 				 	 	0.5	  
		 	  
	  
	 	 	  
	  
	 
	 Electric revenues – 2014
	 	$	104.6	  	 	$	427.9	  
	 Decreased fuel charge primarily due to lower fuel prices
	 	 	(23.1	) 	 	 	(89.8	) 
	 Increased due to higher sales volumes at BLPC and GBPC primarily due to weather
	 	 	1.9	  	 	 	4.0	  
		 	  
	  
	 	 	  
	  
	 
	 Electric revenues – 2015
	 	$	83.4	  	 	$	342.1	  
		 	  
	  
	 	 	  
	  
	 

  
 42 

 

													
	 Q4 Average Electric Revenue/MWh
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Dollars per MWh
	  	$	242	  	  	$	314	  	  	$	324	  

 

													
	 Annual Average Electric Revenue/MWh
	 
	 	  	2015	 	  	2014	 	  	2013*	 
	 Dollars per MWh
	  	$	254	  	  	$	324	  	  	$	328	  
	
	 *  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10,
2013.
	       

 
 

  
 The change in average electric revenues in
Q4 2015 compared to Q4 2014, and for the year ended December 31, 2015 compared to the same period in 2014, is a result of the decreased fuel charge primarily due to lower fuel prices. 

Electric Margin 
 Emera Caribbean distinguishes revenues
related to the recovery of fuel costs through the fuel charge from revenues related primarily to the recovery of non-fuel costs (“base rates”). Emera Caribbean’s electric margin and net income are influenced primarily by base rates,
whereas the fuel charge and fuel costs do not have a material effect on electric margin or net income. Emera Caribbean’s customer classes contribute differently to the Company’s base rate revenue, with residential and commercial customers
contributing more than industrial customers. Residential and commercial load is primarily affected by changes in weather and economic conditions, while industrial load is primarily affected by economic conditions. 

Electric margin is summarized in the following table: 
  

																					
	 For the millions of US dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 	  	2015	 	 	2014	 	 	2015	 	 	2014	 	 	2013(1)	 
	 Operating revenues – regulated
	  	$	84.3	  	 	$	105.4	  	 	$	346.0	  	 	$	432.1	  	 	$	427.4	  
	 Less: Other revenues
	  	 	(0.9	) 	 	 	(0.8	) 	 	 	(3.9	) 	 	 	(4.2	) 	 	 	(3.4	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total electric revenues
	  	 	83.4	  	 	 	104.6	  	 	 	342.1	  	 	 	427.9	  	 	 	424.0	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
						
	 Total electric revenues are broken down as follows:
	  				 				 				 				 			
	 Electric revenues – base rate
	  	$	47.1	  	 	$	45.2	  	 	$	186.7	  	 	$	182.7	  	 	$	177.0	  
	 Fuel charge
	  	 	36.3	  	 	 	59.4	  	 	 	155.4	  	 	 	245.2	  	 	 	247.0	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total electric revenues
	  	 	83.4	  	 	 	104.6	  	 	 	342.1	  	 	 	427.9	  	 	 	424.0	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Regulated fuel for generation and purchased power
	  	 	37.0	  	 	 	60.0	  	 	 	158.1	  	 	 	247.6	  	 	 	248.6	  
	 Regulatory amortization (2)
	  	 	0.7	  	 	 	0.7	  	 	 	2.9	  	 	 	2.9	  	 	 	2.9	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Electric margin
	  	$	45.7	  	 	$	43.9	  	 	$	181.1	  	 	$	177.4	  	 	$	172.5	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	(1)	ECI acquired a 51.9 per cent controlling interest in Domlec on April 10, 2013. 

	(2)	Included in “Depreciation and amortization” on the Consolidated Statements of Income. 

 Emera
Caribbean’s electric margin increased $1.8 million to $45.7 million in Q4 2015 compared to $43.9 million in Q4 2014. For the year ended December 31, 2015, electric margin increased $3.7 million to $181.1 million compared to $177.4 million in
2014 primarily due to increased sales volume at BLPC and GBPC primarily due to weather. 

 

													
	 Q4 Average Electric Margin / MWh
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Dollars per MWh
	  	$	133	  	  	$	132	  	  	$	135	  

 

													
	 Annual Average Electric Margin / MWh
	 
	 	  	2015	 	  	2014	 	  	2013*	 
	 Dollars per MWh
	  	$	135	  	  	$	134	  	  	$	134	  
	
	 *  ECI acquired a 51.9 per cent controlling interest of Domlec on April 10,
2013.
	       

 
 

  
 43 

 Regulated Fuel for Generation and Purchased Power  

 

													
	Q4 Production Volumes	 
	 GWh 
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Oil
	  	 	369	  	  	 	349	  	  	 	345	  
	 Hydro
	  	 	6	  	  	 	8	  	  	 	10	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	375	  	  	 	357	  	  	 	355	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

													
	Annual Production Volumes	 
	 GWh
	 
	 	  	2015	 	  	2014	 	  	2013*	 
	 Oil
	  	 	1,441	  	  	 	1,397	  	  	 	1,371	  
	 Hydro
	  	 	25	  	  	 	31	  	  	 	30	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	1,466	  	  	 	1,428	  	  	 	1,401	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	
	 *  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10,
2013
	
      

 

 

													
	 Q4 Average Fuel Costs/MWh
	 
	 	  	2015	 	  	2014	 	  	2013	 
	 Dollars per MWh
	  	$	99	  	  	$	168	  	  	$	172	  

 

													
	 Annual Average Fuel Costs/MWh
	 
	 	  	2015	 	  	2014	 	  	2013*	 
	 Dollars per MWh
	  	$	108	  	  	$	173	  	  	$	177	  
	
	 *  ECI acquired a 51.9 per cent controlling interest in Domlec on April 10,
2013
	       

 
 

  
 The change in average fuel costs in Q4
2015 compared to Q4 2014 and for the year ended December 31, 2015 compared to the same period in 2014 is a result of lower fuel prices. 
 Regulated fuel
for generation and purchased power decreased $23.0 million to $37.0 million in Q4 2015 compared to $60.0 million in Q4 2014. For the year ended December 31, 2015, regulated fuel for generation and purchased power decreased $89.5 million to
$158.1 million compared to $247.6 million in 2014 primarily due to lower fuel prices. 
 Regulatory Recovery Mechanisms 

BLPC 
 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.

GBPC 
 All GBPC 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 GBPA has approved the calculation of the fuel charge, which is adjusted on a monthly basis. 

As a component of its regulatory agreement with the GBPA, GBPC has an Earnings Share Mechanism to allow for earnings on rate base to be deferred to a
regulatory asset or liability at the rate of 50 per cent of amounts below a nine-per- cent return on rate base and 50 per cent of amounts above 11 per cent return on rate base respectively. 

Domlec 
 Substantially all of Domlec fuel costs are passed
to customers through the fuel pass-through mechanism which provides the opportunity to recover fuel costs in a timely manner. 

  
 44 

 Income Taxes 

Emera Caribbean is subject to corporate income tax at the following statutory rates: 
  

	 	•	 	ECI is subject to corporate income tax at the statutory rate of 25.0 per cent; 

  

	 	•	 	BLPC is subject to corporate income tax at the statutory rate of 15.0 per cent; 

  

	 	•	 	GBPC is not subject to corporate income tax; 

  

	 	•	 	Domlec is subject to corporate income tax at the statutory rate of 28.0 per cent; and 

  

	 	•	 	Lucelec is subject to corporate income tax at the statutory rate of 30.0 per cent. 

 Non-GAAP Measure

 Electric Margin Reconciliation 
 “Electric
margin” is a non-GAAP financial measure used to show the amounts that BLPC, GBPC and Domlec retain to recover their non-fuel costs, as substantially all prudently incurred fuel costs are recovered from customers. 

The companies’ electric margin may not be comparable to electric margin measures of other companies, but in management’s view appropriately reflects
Emera’s specific condition. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance. 

 

																					
	 For the millions of US dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Income from operations
	  	$	14.6	  	  	$	9.1	  	  	$	50.2	  	  	$	43.2	  	  	$	43.8	  
	 less:
	  				  				  				  				  			
	 Operating revenues – non-regulated
	  	 	—  	  	  	 	2.2	  	  	 	6.0	  	  	 	8.0	  	  	 	8.7	  
	 Other revenue
	  	 	0.9	  	  	 	0.8	  	  	 	3.9	  	  	 	4.2	  	  	 	3.4	  
	 Add back:
	  				  				  				  				  			
	 Non-regulated direct costs
	  	 	0.2	  	  	 	1.8	  	  	 	5.9	  	  	 	7.1	  	  	 	7.6	  
	 Operating, maintenance and general
	  	 	23.7	  	  	 	28.6	  	  	 	101.5	  	  	 	107.3	  	  	 	103.7	  
	 Property taxes
	  	 	0.2	  	  	 	0.4	  	  	 	1.8	  	  	 	1.6	  	  	 	1.5	  
	 Depreciation and amortization (1)
	  	 	7.9	  	  	 	7.0	  	  	 	31.6	  	  	 	30.4	  	  	 	28.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Electric margin
	  	$	45.7	  	  	$	43.9	  	  	$	181.1	  	  	$	177.4	  	  	$	172.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	(1)	Depreciation and amortization excludes $0.7 million of regulatory amortization in Q4 2015 (2014 – $0.7 million) and $2.9 million for the year ended December 31, 2015 (2014 – $2.9 million) 

  
 45 

 PIPELINES 

Overview 
 Pipelines comprises Emera’s wholly owned
Brunswick Pipeline and the Company’s 12.9 per cent interest in the M&NP. 
  

	 	•	 	Brunswick Pipeline is a 145-kilometre pipeline delivering re-gasified natural gas from the CanaportTM liquefied natural gas (“LNG”) import terminal near Saint John, New Brunswick, to markets in the
northeastern United States for Repsol Energy Canada under a 25-year firm service agreement which expires in 2034. The NEB, which regulates Brunswick Pipeline, has classified it as a Group II pipeline. The agreement is accounted for as a
direct financing lease. 

  

	 	•	 	M&NP is a 1,400-kilometre transmission pipeline built to transport natural gas from offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. The investment in M&NP is accounted
for on the equity basis. 

 Mark-to-Market Adjustments 

Pipelines’ “Interest expense, net” and “Income tax expense (recovery)” are affected by mark-to-market adjustments on an interest rate
swap. Pipelines’ income table below shows these amounts net of mark-to-market adjustments and details the adjustments in the footnotes. 
 Review of
2015 
 Pipelines’ Adjusted Net Income 
  

																					
	 For the millions of Canadian dollars (except per share amounts)
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	 	2014	 	  	2013	 
	 Operating revenues – regulated
	  	$	13.0	  	  	$	12.4	  	  	$	52.1	  	 	$	48.8	  	  	$	49.9	  
	 Operating maintenance and general
	  	 	0.1	  	  	 	0.1	  	  	 	0.4	  	 	 	0.4	  	  	 	0.1	  
	 Accretion (1)
	  	 	0.1	  	  	 	0.1	  	  	 	0.4	  	 	 	0.3	  	  	 	0.2	  
	 Income from equity investment
	  	 	6.5	  	  	 	5.3	  	  	 	23.0	  	 	 	18.4	  	  	 	14.7	  
	 Other income (expenses), net
	  	 	—  	  	  	 	0.2	  	  	 	0.6	  	 	 	0.6	  	  	 	0.1	  
	 Interest expense, net (2)
	  	 	6.0	  	  	 	6.8	  	  	 	23.3	  	 	 	26.0	  	  	 	27.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted income before provision for income taxes
	  	 	13.3	  	  	 	10.9	  	  	 	51.6	  	 	 	41.1	  	  	 	36.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Income tax expense (recovery) (3)
	  	 	3.2	  	  	 	2.4	  	  	 	12.0	  	 	 	8.4	  	  	 	6.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted contribution to consolidated net income
	  	$	10.1	  	  	$	8.5	  	  	$	39.6	  	 	$	32.7	  	  	$	30.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 After-tax derivative mark-to-market gain (loss)
	  	 	0.2	  	  	 	—  	  	  	 	(2.1	) 	 	 	—  	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income
	  	$	10.3	  	  	$	8.5	  	  	$	37.5	  	 	$	32.7	  	  	$	30.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted contribution to consolidated earnings per common share
	  	$	0.07	  	  	$	0.06	  	  	$	0.27	  	 	$	0.23	  	  	$	0.23	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share
	  	$	0.07	  	  	$	0.06	  	  	$	0.26	  	 	$	0.23	  	  	$	0.23	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
		  				  				  				 				  			
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	19.4	  	  	$	17.8	  	  	$	75.3	  	 	$	67.4	  	  	$	64.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 

  

	(1)	Accretion related to the reclamation of the pipeline is included in “Depreciation and amortization” on the Consolidated Statements of Income. 

	(2)	Interest expense, net excludes a pre-tax mark-to-market gain of $0.2 million in Q4 2015 and $2.9 million loss for the year ended December 31, 2015 compared to nil for the same periods in 2014. 

	(3)	Income tax expense (recovery) excludes a nil expense relating to mark-to-market gains in Q4 2015 and $0.8 million recovery relating to mark-to-market losses for the year ended December 31, 2015 compared to nil for the
same periods in 2014. 

  
 46 

 Pipelines’ contribution to consolidated net income increased by $1.8 million to $10.3 million in Q4 2015
compared to $8.5 million in Q4 2014 and increased $4.8 million to $37.5 million for the year ended December 31, 2015 compared to $32.7 million in 2014. Highlights of the income changes are summarized in the following table: 

 

									
	 For the millions of Canadian dollars
	 	Three months ended
December 31	 	 	Year ended
December 31	 
	 Contribution to consolidated net income – 2013
	 				 	$	30.3	  
		 	  
	  
	 	 	  
	  
	 
	 Increased income from equity investments primarily due to higher equity earnings from
M&NP
	 				 	 	3.7	  
	 Other
	 				 	 	(1.3	) 
		 	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2014
	 	$	8.5	  	 	$	32.7	  
		 	  
	  
	 	 	  
	  
	 
	 Increased regulated operating revenues due to a strengthening USD and increased tolls
	 	 	0.6	  	 	 	3.3	  
	 Increased income from equity investments primarily due to increased interruptible transmission
revenue from M&NP and the strengthening USD
	 	 	1.2	  	 	 	4.6	  
	 Decreased interest expense, net primarily due to a lower interest rate on Brunswick Pipeline
refinancing in Q1 2015
	 	 	0.8	  	 	 	2.7	  
	 Increased income tax expense primarily due to increased income before provision for income
taxes
	 	 	(0.8	) 	 	 	(3.6	) 
	 After-tax mark-to-market gain (loss) on an interest rate swap entered into in Q2 2015
	 	 	0.2	  	 	 	(2.1	) 
	 Other
	 	 	(0.2	) 	 	 	(0.1	) 
		 	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2015
	 	$	10.3	  	 	$	37.5	  
		 	  
	  
	 	 	  
	  
	 

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

Income Taxes 
 Brunswick Pipeline is subject to corporate
income tax at the statutory rate of 27.0 per cent (combined Canadian federal and provincial income tax rate). 

  
 47 

 EMERA ENERGY 

Overview 
 Emera Energy includes the following: 

 

	 	•	 	Emera Energy Services (“EES”), a wholly owned physical energy marketing and trading business; 

  

	 	•	 	Emera Energy Generation (“EEG”), consisting of a wholly owned portfolio of electricity generation facilities in New England and the Maritime provinces of Canada with 1,410 megawatts (“MW”) of total
capacity; 

  

	 	•	 	Equity investments in the following generation facilities: 

  

	 	•	 	Emera’s 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts. 

 

	 	•	 	Emera’s 49.0 per cent investment in NWP, a 419 MW portfolio of wind energy projects in the northeastern United States which on January 29, 2015 sold to 51 per cent partner, First Wind. 

Wholly owned investments are consolidated. The investment in Bear Swamp is accounted for on an equity basis. NWP was accounted for on the equity basis, and
its results were included until its sale on January 29, 2015. The gain on the sale of this asset is recorded in “Other income (expenses), net” on the Consolidated Statements of Income. 

Mark-to-Market Adjustments 
 Emera Energy’s
“Trading and marketing margin”, “Electricity sales”, “Non-regulated fuel for generation and purchased power”, “Income from equity investments” and “Income tax expense (recovery)” are affected by
mark-to-market (“MTM”) adjustments. The Emera Energy income table shows these amounts net of mark-to-market adjustments and details these adjustments in footnotes to the income statement. Management believes that excluding the
effect of mark-to-market valuations, and changes thereto, from income until settlement better matches the financial effect of these contracts with the underlying cash flows. 

Emera Energy has a number of Asset Management Agreements (“AMAs”) with local gas distribution utilities (“LDCs”) in the
northeast. The AMAs involve Emera Energy supplying gas to the LDCs for a specific term, and the corresponding release of utility owned gas transportation/storage capacity to Emera Energy. Mark-to-market adjustments on these AMA’s
arise on the price differential between the point where gas is sourced and where it is delivered. At inception, the MTM adjustment is offset fully by the corresponding transportation asset, which is amortized over the term of the AMA contract.
Subsequent changes in gas price differentials, to the extent not offset by the accounting amortization of the transportation asset, will result in MTM gains or losses recorded in income. MTM adjustments may be substantial in the early months of a
contract when delivered volumes and market volatility are usually at peak levels. As a contract is realized, and volumes reduce, volatility is expected to decrease. Ultimately, the transportation asset and the mark-to-market adjustment
reduce to zero at the end of the contract term. As the business grows, and AMA volumes increase, MTM volatility resulting in gains and losses may also increase.

  
 48 

 Review of 2015 

Emera Energy Adjusted Contribution to Consolidated Net Income 
  

																					
	 For the millions of Canadian dollars (except per share amounts)
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	 	2014	 	  	2013	 
	 Trading and marketing margin (1)
	  	$	38.0	  	  	$	15.8	  	  	$	84.9	  	 	$	117.5	  	  	$	60.3	  
	 Electricity sales (2)
	  	 	142.5	  	  	 	102.4	  	  	 	545.9	  	 	 	520.7	  	  	 	146.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Total operating revenues – non-regulated
	  	 	180.5	  	  	 	118.2	  	  	 	630.8	  	 	 	638.2	  	  	 	206.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Non-regulated fuel for generation and purchased power (3)
	  	 	86.5	  	  	 	61.6	  	  	 	334.9	  	 	 	384.8	  	  	 	97.9	  
	 Operating, maintenance and general
	  	 	25.3	  	  	 	16.6	  	  	 	79.7	  	 	 	78.7	  	  	 	43.6	  
	 Provincial, state and municipal taxes
	  	 	2.3	  	  	 	1.2	  	  	 	6.6	  	 	 	5.5	  	  	 	0.8	  
	 Depreciation and amortization
	  	 	10.8	  	  	 	8.9	  	  	 	40.6	  	 	 	37.7	  	  	 	11.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Total operating expenses
	  	 	124.9	  	  	 	88.3	  	  	 	461.8	  	 	 	506.7	  	  	 	153.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted income (loss) from operations
	  	 	55.6	  	  	 	29.9	  	  	 	169.0	  	 	 	131.5	  	  	 	53.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Income from equity investments (4)
	  	 	3.2	  	  	 	1.6	  	  	 	26.4	  	 	 	12.3	  	  	 	17.1	  
	 Other income (expenses), net
	  	 	1.2	  	  	 	0.8	  	  	 	25.1	  	 	 	2.9	  	  	 	0.2	  
	 Interest expense, net
	  	 	6.1	  	  	 	1.4	  	  	 	19.3	  	 	 	6.2	  	  	 	1.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted income (loss) before provision for income taxes
	  	 	53.9	  	  	 	30.9	  	  	 	201.2	  	 	 	140.5	  	  	 	69.3	  
	 Income tax expense (recovery) (5)
	  	 	18.5	  	  	 	9.6	  	  	 	71.1	  	 	 	42.3	  	  	 	24.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted contribution to consolidated net income (loss)
	  	$	35.4	  	  	$	21.3	  	  	$	130.1	  	 	$	98.2	  	  	$	45.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 After-tax derivative mark-to-market gain (loss)
	  	$	4.3	  	  	$	72.7	  	  	$	(31.2	) 	 	$	87.5	  	  	$	(41.9	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income
	  	$	39.7	  	  	$	94.0	  	  	$	98.9	  	 	$	185.7	  	  	$	3.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted contribution to consolidated earnings per common share – basic
	  	$	0.24	  	  	$	0.15	  	  	$	0.89	  	 	$	0.69	  	  	$	0.34	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share – basic
	  	$	0.27	  	  	$	0.65	  	  	$	0.68	  	 	$	1.30	  	  	$	0.02	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
		  				  				  				 				  			
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	70.8	  	  	$	41.2	  	  	$	261.1	  	 	$	184.4	  	  	$	81.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 

  

	(1)	Trading and marketing margin excludes a pre-tax mark-to-market gain of $37.4 million in Q4 2015 (2014 - $84.6 million gain) and a loss of $1.8 million for the year ended December 31, 2015 (2014 - $119.9 million gain)

	(2)	Electricity sales exclude a pre-tax mark-to-market loss of $21.9 million in Q4 2015 (2014 – $44.6 million gain) and a loss of $39.1 million for the year ended December 31, 2015 (2014 - $42.8 million gain)

	(3)	Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market loss of $5.4 million in Q4 2015 (2014 – $17.9 million loss) and a loss of $6.3 million for the year ended December 31, 2015
(2014 - $20.8 million loss) 

	(4)	Income from equity investments excludes a pre-tax mark-to-market loss of $9.7 million in Q4 2015 (2014 - $3.6 million loss) and a loss of $5.6 million for the year ended December 31, 2015 (2014 - $13.2 million
loss) 

	(5)	Income tax expense (recovery) excludes a $3.9 million recovery relating to mark-to-market gains in Q4 2015 (2014 - $35.0 million expense) and $21.6 million recovery relating to mark-to-market losses for the year ended
December 31, 2015 (2014 - $41.2 million expense) 

 Emera Energy’s contribution to consolidated net income decreased by $54.3 million to
$39.7 million in Q4 2015 compared to $94.0 million in Q4 2014. For the year ended December 31, 2015, Emera Energy’s contribution to consolidated net income decreased $86.8 million to $98.9 million compared to $185.7 million in
2014. Highlights of the income changes are summarized in the following table: 

  
 49 

									
	 For the millions of Canadian dollars
	 	Three months ended
December 31	 	 	Year ended
December 31	 
	 Contribution to consolidated net income – 2013
	 				 	$	3.2	  
	 Increased trading and marketing margin primarily due to very strong market conditions in
northeastern United States and Ontario in Q1 2014 and a stronger USD
	 				 	 	57.2	  
	 Increased electricity sales primarily due to the acquisition of the New England Gas Generating
Facilities in November 2013, higher power prices and increased sales at Bayside Power
	 				 	 	374.5	  
	 Increased non-regulated fuel for generation and purchased power primarily due to the acquisition
of the New England Gas Generating Facilities in November 2013, higher commodity prices and increased generation at Bayside Power
	 				 	 	(286.9	) 
	 Increased OM&G primarily due to the acquisition of the New England Gas Generating Facilities
and increased performance-based compensation accruals resulting from increased trading and marketing margin
	 				 	 	(35.1	) 
	 Increased depreciation and amortization primarily due to the acquisition of the New England Gas
Generating Facilities
	 				 	 	(26.5	) 
	 Income from equity investments reflects a non-recurring gain on the settlement of warranty
obligations related to certain NWP turbines, decreased curtailments at NWP, recognition of business interruption insurance proceeds related to a 2013 outage at Bear Swamp and favourable pricing at Bear Swamp
	 				 	 	(4.8	) 
	 Increased income tax expense primarily due to increased income before provision for taxes
	 				 	 	(18.1	) 
	 Increased mark-to-market gains, net of tax, primarily due to the reversal of 2013 mark-to-market
losses and changes in gas and power contract positions, as well as favourable power contracts at the New England Gas Generating Facilities
	 				 	 	129.4	  
	 Other
	 				 	 	(7.2	) 
		 	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2014
	 	$	94.0	  	 	$	185.7	  
	 Increased (decreased) trading and marketing margin – See Trading and Marketing Margin section
below
	 	 	22.2	  	 	 	(32.6	) 
	 Increased electricity sales quarter-over-quarter primarily due to higher sales volumes, reflecting
reduced generation for planned outage work at Bridgeport in Q4 2014, which reduced generation and a stronger USD; year-over-year is also partially offset by lower power prices
	 	 	40.1	  	 	 	25.2	  
	 Increased non-regulated fuel for generation and purchased power quarter-over-quarter as a result
of higher sales volumes, reflecting reduced generation for planned outage work at Bridgeport in Q4 2014 and a stronger USD; year-over-year reduction is primarily due to lower commodity fuel prices, partially offset by a stronger USD
	 	 	(24.9	) 	 	 	49.9	  
	 Increased OM&G quarter-over-quarter primarily due to timing of maintenance work at the New
England Gas Generating Facilities, the stronger USD and increased performance-based compensation resulting from increased trading and marketing margins; year-over-year primarily due to stronger USD, offset by decreased performance-based compensation
resulting from decreased trading and marketing margins
	 	 	(8.7	) 	 	 	(1.0	) 
	 Increased income from equity investments – See “Equity Investments” below
	 	 	1.6	  	 	 	14.1	  
	 Increased other income (expenses) year-over-year primarily due to a gain on the sale of
NWP
	 	 	0.4	  	 	 	22.2	  
	 Increased interest expense, net primarily due to higher interest rates on internal
financing
	 	 	(4.7	) 	 	 	(13.1	) 
	 Increased income tax expense primarily due to increased income before provision for income taxes;
year-over-year increase also due to changes in the proportion of income earned in higher tax rate foreign jurisdiction and a stronger USD
	 	 	(8.9	) 	 	 	(28.8	) 

  
 50 

									
	 Decreased mark-to-market, net of tax, quarter-over-quarter primarily due to changes in gas and
power contract positions, and amortization of transportation assets; decreased year-over-year also due to the reversal of 2013 mark-to-market losses in 2014
	  	 	(68.4	) 	 	 	(118.7	) 
	 Other
	  	 	(3.0	) 	 	 	(4.0	) 
		  	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2015
	  	$	39.7	  	 	$	98.9	  
		  	  
	  
	 	 	  
	  
	 

 A portion of earnings are exposed to foreign exchange fluctuations thereby impacting adjusted CAD contribution to net
earnings. The impact of a stronger USD, quarter-over-quarter increased earnings in CAD dollars by $3.4 million in Q4 2015 compared to 2014. For the year ended December 31, 2015 the impact of a stronger USD increased earnings in CAD dollars by
$11.9 million compared to the same period in 2014. 
 Energy Services 

Emera Energy Services derives revenue and earnings from the wholesale trading and marketing of natural gas, electricity and other energy-related commodities
and derivatives within the Company’s risk tolerances, including those related to value-at-risk (“VaR”) and credit exposure. 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 trading and
marketing business currently has approximately 80 employees engaged in commercial activities and related back office, legal and other support functions. The primary market for the trading and marketing business is northeastern North America,
including the Marcellus shale gas region, the US Gulf Coast and Central Canada. Its counterparties include electric and gas utilities, natural gas producers, electricity generators and other marketing and trading entities. Trading and marketing
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 manages
its commodity risk by limiting open positions, utilizing financial products to hedge purchases and sales, and investing in transportation capacity rights to enable movement across its portfolio. 

Adjusted EBITDA 
 Adjusted EBITDA for Emera Energy’s
trading and marketing business is summarized in the following table: 
  

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 Trading and marketing margin
	  	$	38.0	  	  	$	15.8	  	  	$	84.9	  	  	$	117.5	  	  	$	60.3	  
	 OM&G
	  	 	7.9	  	  	 	5.0	  	  	 	21.3	  	  	 	24.8	  	  	 	15.2	  
	 Other income (expenses), net
	  	 	1.0	  	  	 	0.8	  	  	 	5.6	  	  	 	2.6	  	  	 	1.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	31.1	  	  	$	11.6	  	  	$	69.2	  	  	$	95.3	  	  	$	46.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  
 51 

 Trading and Marketing Margin 

Trading and marketing margin is comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and
energy asset management services’ revenues. 
 Trading and marketing margin increased $22.2 million to $38.0 million in Q4 2015 compared to $15.8
million in Q4 2014. This reflects growth in the volume of business, including increased investment in transportation capacity, the value of which is primarily realized in the winter months. For the year ended December 31, 2015, trading and
marketing margin decreased $32.6 million to $84.9 million compared to $117.5 million in 2014. Q1 2014 saw sustained high pricing and volatility in several of Emera Energy’s markets, largely the result of cold weather. Subsequently, there
was a return to more normal market conditions. Trading and marketing margins were also favourably affected by the strengthening USD in Q4 2015 and for the year ended December 31, 2015. 

Generation 
 Emera Energy wholly owns and operates a
portfolio of high efficiency, non-utility electricity generating facilities in northeast North America. 
 Information regarding Emera Energy’s wholly
owned generation 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 (“PPA”) November - March; Selling electricity to Maritimes and ISO-NE for remainder of year
	 Brooklyn
	 	Nova Scotia	 	 	30	  	 	1996	 	Biomass	 	Long-term PPA
		 		 	  
	  
	 	 		 		 	
	 Total Maritime Canada
	 	 	320	  	 		 		 	
		 		 	  
	  
	 	 		 		 	
	 Total EEG
	 		 	 	1,410	  	 		 		 	
		 		 	  
	  
	 	 		 		 	

  

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

 Emera Energy has
approximately 125 employees in its generation business. For the portion of output not committed under PPAs, 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. The New England facilities also participate in the regional capacity market and are compensated for being available to provide power. The electricity generation business in the northeast 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. 

  
 52 

 Adjusted EBITDA 

Adjusted EBITDA is summarized in the following table: 
  

																									
	 For the
	  	Three months ended December 31	 
	 	  	New England	 	  	Maritime Canada	 	  	Total	 
	 millions of Canadian dollars
	  	2015	 	  	2014	 	  	2015	 	 	2014	 	  	2015	 	  	2014	 
	 Energy sales
	  	$	110.7	  	  	$	63.3	  	  	$	19.9	  	 	$	25.8	  	  	$	130.6	  	  	$	89.1	  
	 Capacity and other
	  	 	11.9	  	  	 	13.3	  	  	 	—  	  	 	 	—  	  	  	 	11.9	  	  	 	13.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Electricity sales
	  	 	122.6	  	  	 	76.6	  	  	 	19.9	  	 	 	25.8	  	  	 	142.5	  	  	 	102.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Non-regulated fuel for generation and purchased power
	  	 	72.7	  	  	 	44.9	  	  	 	10.9	  	 	 	15.3	  	  	 	83.6	  	  	 	60.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Non-regulated electric margin
	  	 	49.9	  	  	 	31.7	  	  	 	9.0	  	 	 	10.5	  	  	 	58.9	  	  	 	42.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Provincial taxes
	  	 	1.3	  	  	 	0.9	  	  	 	0.2	  	 	 	0.2	  	  	 	1.5	  	  	 	1.1	  
	 OM&G
	  	 	12.4	  	  	 	7.5	  	  	 	4.4	  	 	 	3.7	  	  	 	16.8	  	  	 	11.2	  
	 Other income (expenses), net
	  	 	0.3	  	  	 	—  	  	  	 	(0.1	) 	 	 	—  	  	  	 	0.2	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	36.5	  	  	$	23.3	  	  	$	4.3	  	 	$	6.6	  	  	$	40.8	  	  	$	29.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Adjusted EBITDA is summarized in the following table: 

 

																																					
	 For the
	  	Year ended December 31	 
	 	  	New England (1)	 	  	Maritime Canada (2)	 	 	Total	 
	 millions of Canadian dollars
	  	2015	 	  	2014	 	  	2013	 	  	2015	 	 	2014	 	  	2013	 	 	2015	 	  	2014	 	  	2013	 
	 Energy sales
	  	$	413.9	  	  	$	365.5	  	  	$	64.0	  	  	$	88.3	  	 	$	109.4	  	  	$	77.8	  	 	$	502.2	  	  	$	474.9	  	  	$	141.8	  
	 Capacity and other
	  	 	43.7	  	  	 	45.8	  	  	 	4.4	  	  	 	—  	  	 	 	—  	  	  	 	—  	  	 	 	43.7	  	  	 	45.8	  	  	 	4.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Electricity sales
	  	$	457.6	  	  	$	411.3	  	  	$	68.4	  	  	$	88.3	  	 	$	109.4	  	  	$	77.8	  	 	$	545.9	  	  	$	520.7	  	  	$	146.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Non-regulated fuel for generation and purchased power
	  	 	277.3	  	  	 	311.8	  	  	 	48.6	  	  	 	52.2	  	 	 	73.5	  	  	 	47.3	  	 	 	329.5	  	  	 	385.3	  	  	 	95.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Non-regulated electric margin
	  	 	180.3	  	  	 	99.5	  	  	 	19.8	  	  	 	36.1	  	 	 	35.9	  	  	 	30.5	  	 	 	216.4	  	  	 	135.4	  	  	 	50.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Provincial taxes
	  	 	4.7	  	  	 	4.6	  	  	 	—  	  	  	 	0.9	  	 	 	0.9	  	  	 	0.8	  	 	 	5.6	  	  	 	5.5	  	  	 	0.8	  
	 OM&G
	  	 	37.5	  	  	 	29.9	  	  	 	7.1	  	  	 	18.7	  	 	 	21.3	  	  	 	19.3	  	 	 	56.2	  	  	 	51.2	  	  	 	26.4	  
	 Other income (expenses), net
	  	 	1.6	  	  	 	—  	  	  	 	—  	  	  	 	(0.7	) 	 	 	0.3	  	  	 	(0.8	) 	 	 	0.9	  	  	 	0.3	  	  	 	(0.8	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	139.7	  	  	$	65.0	  	  	$	12.7	  	  	$	15.8	  	 	$	14.0	  	  	$	9.6	  	 	$	155.5	  	  	$	79.0	  	  	$	22.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	(1)	The New England Gas Generating Facilities were acquired in November 2013. 

	(2)	Brooklyn Energy was acquired in July 2013. 

 Adjusted EBITDA increased $10.9 million to $40.8 million in Q4
2015 from $29.9 million compared to Q4 2014 primarily due to increased generation, reflecting a major planned outage at Bridgeport Energy in Q4 2014. For the year ended December 31, 2015, adjusted EBITDA increased $76.5 million to $155.5
million from $79.0 million in 2014, primarily due to higher margins realized in the New England Gas Generating Facilities, reflecting favourable short-term economic hedges, favourable pricing. The strengthening USD contributed $17.6
million.
 Operating Statistics 
  

																									
	 For the
	  	Three months ended December 31	 
	 	  	Sales Volumes (GWh) (1)	 	  	Plant Availability (%) (2)	 	 	Net Capacity Factor (%) (3)	 
	 	  	2015	 	  	2014	 	  	2015	 	 	2014	 	 	2015	 	 	2014	 
	 New England
	  	 	1,194	  	  	 	777	  	  	 	98.9	% 	 	 	62.6	% 	 	 	49.7	% 	 	 	33.4	% 
	 Maritime Canada
	  	 	417	  	  	 	525	  	  	 	89.5	% 	 	 	95.1	% 	 	 	60.5	% 	 	 	76.1	% 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total
	  	 	1,611	  	  	 	1,302	  	  	 	96.8	% 	 	 	70.0	% 	 	 	52.1	% 	 	 	43.2	% 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  
 53 

																									
	 For the
	  	Year ended December 31	 
	 	  	Sales Volumes (GWh) (1)	 	  	Plant Availability (%) (2)	 	 	Net Capacity Factor (%) (3)	 
	 	  	2015	 	  	2014	 	  	2015	 	 	2014	 	 	2015	 	 	2014	 
	 New England
	  	 	4,777	  	  	 	4,375	  	  	 	94.5	% 	 	 	79.9	% 	 	 	50.5	% 	 	 	47.6	% 
	 Maritime Canada
	  	 	1,699	  	  	 	1,910	  	  	 	92.7	% 	 	 	91.4	% 	 	 	61.9	% 	 	 	69.9	% 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total
	  	 	6,476	  	  	 	6,285	  	  	 	94.1	% 	 	 	82.6	% 	 	 	53.0	% 	 	 	52.7	% 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	(1)	Sales volumes represent the actual electricity output of the plants. 

	(2)	Plant availability represents the percentage of time in the period that the plant was available to generate power regardless of whether it was running. Effectively, it represents 100% availability reduced by
planned and unplanned outages. 

	(3)	Net capacity factor is the ratio of the utilization of an asset as compared to its maximum capability, within a particular time frame. It is generally a function of plant availability and plant economics
vis-à-vis the market. 

 Sales volumes and net capacity factor increased quarter-over-quarter primarily due to the impact of a planned
outage and plant upgrade at the Bridgeport facility in Q4 2014; year-over-year increase in sales volumes was primarily due to fewer outage days in 2015 at the New England Gas Generating Facilities.

Upgrades completed in Q2 2015 at the Bridgeport facility, including a new gas turbine rotor and improved combustion system, added 20 MW of capacity, bringing
the plant total to 560 MW. Availability has increased at the New England Gas Generating Facilities due to significant reliability and performance-based investment in 2014. 

The New England Gas Generating Facilities sell into price based competitive markets. The primary reason that the overall capacity factor is lower for New
England Gas Generating Facilities as compared to the Maritime facilities is because the Rumford Power Plant, in particular, generally operates with a capacity factor of approximately 20 per cent, reflecting current electricity and gas supply price
dynamics in its markets. 
 Equity Investments 

Information regarding Emera Energy’s equity investments in generation facilities is summarized below: 

 

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

	 New England

	 Bear Swamp
	  	50 per cent	  	Massachusetts	  	 	600	  	  	Hydro	  	 Long-term PPA and selling electricity and capacity to

ISO-NE

	 NWP (1)
	  	49 per cent	  	Maine	  	 	419	  	  	Wind	  	Long-term PPA and selling electricity to ISO-NE and New York ISO (“NYISO”)
		  		  		  	  
	  
	 	  		  	
	 Total New England
	  		  		  	 	1,019	  	  		  	
		  		  		  	  
	  
	 	  		  	

  

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

  
 54 

 Adjusted income from equity investments 

Adjusted income from equity investments is summarized in the following table: 
  

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 	  	2015	 	  	2014	 	 	2015	 	  	2014	 	 	2013	 
	 Bear Swamp
	  	$	3.2	  	  	$	2.4	  	 	$	24.5	  	  	$	19.2	  	 	$	15.8	  
	 NWP
	  	 	—  	  	  	 	(0.8	) 	 	 	1.9	  	  	 	(6.9	) 	 	 	1.3	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Adjusted income from equity investments
	  	$	3.2	  	  	$	1.6	  	 	$	26.4	  	  	$	12.3	  	 	$	17.1	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 

 Adjusted Income from equity investments increased $1.6 million to $3.2 million in Q4 2015 compared to $1.6 million in Q4 2014
primarily due to transmission line outages that negatively affected power sales at Bear Swamp in 2014, partially offset by higher interest costs as a result of its Q4 2015 refinancing. For the year ended December 31, 2015, adjusted income from
equity investments increased $14.1 million to $26.4 million compared to $12.3 million in 2014. This was primarily due to the resupply of the contracted power sales in Bear Swamp in 2015 that were not delivered in 2014 due to transmission line
outages, NWP losses recorded in 2014 and the strengthening USD. 
 Other Income 

On January 29, 2015, Emera completed the sale of its 49 per cent interest in NWP for $282.3 million ($223.3 million USD). This sale resulted in a pre-tax gain
of $18.6 million or $0.13 per common share (after-tax gain of $11.5 million or $0.08 per common share), which was recorded in “Other income (expenses), net” on the Consolidated Statements of Income in Q1 2015. 

Income Taxes 
 Emera Energy is subject to corporate income
tax at the statutory rate ranging from 39.2 to 41.5 per cent (combined US federal and state income tax rate) on its US sourced income and ranging from 27.0 to 31.0 per cent (combined Canadian federal and provincial income tax rate) on its Canada
sourced income. 
 New England Gas Generating Facilities is subject to corporate income tax at the statutory rate ranging from 35.0 to 40.9 per cent
(combined US federal and state income tax rate). 
 Brooklyn Energy is subject to corporate income tax at the statutory rate of 31.0 per cent (combined
Canadian federal and provincial income tax rate). 
 Bear Swamp Refinancing 

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 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. 

  
 55 

 CORPORATE AND OTHER 

Corporate 
 Corporate includes certain corporate-wide
functions including executive management, strategic planning, treasury services, financial reporting, tax planning, corporate business development, corporate governance, internal audit, investor relations, risk management, insurance, acquisition
related costs and corporate human resource activities. It also includes interest revenue on intercompany financings recorded in “Intercompany revenue” in the table below, and costs associated with corporate activities that are not directly
allocated to the operations of Emera’s consolidated subsidiaries and investments. 
 Other 

Other includes the following consolidated and non-consolidated investments: 

Consolidated Investments 
  

	•	 	Emera Utility Services is a utility services contractor primarily operating in Atlantic Canada (recorded in “Non-regulated operating revenue” in the table below). 

 

	•	 	Emera Reinsurance Limited is a captive insurance company providing insurance and reinsurance to Emera and its affiliates, to enable more cost efficient management of risk and deductible levels across Emera (recorded in
“OM&G” and “Other income (expenses), net” in the table below). 

 Non-consolidated investments (recorded in
“Income (loss) from equity investments” in the table below) 
  

	•	 	Emera’s 23.4 per cent investment in APUC, including outstanding subscription receipts and associated dividend equivalents. APUC is a diversified generation, transmission and distribution utility traded on the
Toronto Stock Exchange (“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. The subscription receipts are now included in “Investments subject to
significant influence” on the Consolidated Balance Sheets. 

  
 56 

	•	 	Emera’s 100 per cent investment in ENL, which holds investments in the following: 

  

	 	•	 	Emera’s 100 per cent investment in NSPML, a $1.56 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 return on equity component of AFUDC. This will continue until the Maritime Link Project goes into service, which is expected in 2017. 

 

	 	•	 	Emera’s 55.1 per cent 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 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. 

 

	•	 	Emera’s 3.3 per cent investment in Open Hydro is accounted for on the cost basis. 

  

	•	 	Other investments. 

 Mark-to-Market Adjustments 

Specific to the pending TECO Energy acquisition, Emera has recorded after-tax mark-to-market gains of $100.5 million for the three months and year ended
December 31, 2015 (2014 – nil) related to the effect of USD-denominated currency and forward contracts put in place to hedge the anticipated proceeds from the second instalment of the Debenture Offering of the pending acquisition, expected
mid-2016. 
 “Other income (expenses), net” and “Income tax expense (recovery)” are affected by the mark-to-market adjustments discussed
above. Corporate and Other’s income table below shows these amounts net of mark-to-market adjustments and details the adjustments in the footnotes. 

  
 57 

 Review of 2015 

Corporate and Other 
  

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 	  	2015	 	 	2014	 	 	2015	 	 	2014	 	 	2013	 
	 Intercompany revenue (1)
	  	$	9.9	  	 	$	6.8	  	 	$	34.2	  	 	$	26.0	  	 	$	38.3	  
	 Non-regulated operating revenue
	  	 	9.9	  	 	 	16.1	  	 	 	40.1	  	 	 	48.7	  	 	 	43.5	  
	 Non-regulated direct costs
	  	 	9.9	  	 	 	15.2	  	 	 	42.4	  	 	 	46.9	  	 	 	44.6	  
	 Operating, maintenance and general
	  	 	32.7	  	 	 	16.8	  	 	 	104.1	  	 	 	46.2	  	 	 	39.0	  
	 Depreciation and amortization
	  	 	0.7	  	 	 	0.5	  	 	 	1.7	  	 	 	2.3	  	 	 	3.8	  
	 Total operating expenses
	  	 	43.3	  	 	 	32.5	  	 	 	148.2	  	 	 	95.4	  	 	 	87.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income (loss) from operations
	  	 	(23.5	) 	 	 	(9.6	) 	 	 	(73.9	) 	 	 	(20.7	) 	 	 	(5.6	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income (loss) from equity earnings
	  	 	25.5	  	 	 	11.6	  	 	 	61.3	  	 	 	46.3	  	 	 	3.3	  
	 Other income (expenses), net (2)
	  	 	(5.0	) 	 	 	(0.1	) 	 	 	(4.3	) 	 	 	3.2	  	 	 	16.9	  
	 Interest expense
	  	 	29.5	  	 	 	6.3	  	 	 	48.1	  	 	 	30.9	  	 	 	37.5	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Adjusted income (loss) before provision for income taxes
	  	 	(32.5	) 	 	 	(4.4	) 	 	 	(65.0	) 	 	 	(2.1	) 	 	 	(22.9	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income tax expense (recovery) (3)
	  	 	(15.5	) 	 	 	(5.2	) 	 	 	(40.1	) 	 	 	(20.6	) 	 	 	(28.4	) 
	 Preferred stock dividends
	  	 	—  	  	 	 	—  	  	 	 	30.3	  	 	 	26.2	  	 	 	19.3	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Adjusted contribution to consolidated net income
	  	$	(17.0	) 	 	$	0.8	  	 	$	(55.2	) 	 	$	(7.7	) 	 	$	(13.8	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 After-tax mark-to-market gain (loss)
	  	 	100.5	  	 	 	—  	  	 	 	100.5	  	 	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income
	  	$	83.5	  	 	$	0.8	  	 	$	45.3	  	 	$	(7.7	) 	 	$	(13.8	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Adjusted contribution to consolidated earnings per common share – basic
	  	$	(0.12	) 	 	$	0.01	  	 	$	(0.38	) 	 	$	(0.05	) 	 	$	(0.10	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated earnings per common share – basic
	  	$	0.57	  	 	$	0.01	  	 	$	0.31	  	 	$	(0.05	) 	 	$	(0.10	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  				 				 				 				 			
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Adjusted EBITDA
	  	$	(2.3	) 	 	$	2.4	  	 	$	(15.2	) 	 	$	31.1	  	 	$	18.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

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

	(2)	Other income (expenses) net, excludes a pre-tax mark-to-market gain of $118.9 million in Q4 2015 and for the year ended December 31, 2015 compared to nil for the same periods in 2014. 

	(3)	Income tax expense (recovery), excludes an $18.4 million expense relating to mark-to-market gains in Q4 2015 and for the year ended December 31, 2015 compared to nil for the same periods in 2014. 

Corporate and Other’s contribution to consolidated net income increased by $82.7 million to $83.5 million in Q4 2015 compared to $0.8 million in Q4 2014.
For the year ended December 31, 2015, Corporate and Other’s contribution to consolidated net income increased $53.0 million to $45.3 million compared to $(7.7) million in 2014. Highlights of the income changes are summarized in the following
table: 

  
 58 

									
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 Contribution to consolidated net income – 2013
	  				 	$	(13.8	) 
	 Decreased intercompany revenue primarily due to lower interest revenue resulting from the
repayment of NWP loan in November 2013
	  				 	 	(12.3	) 
	 Increased OM&G primarily due to higher deferred compensation costs, partially offset by lower
business development costs
	  				 	 	(7.2	) 
	 Income from equity investments – see table below for highlights
	  				 	 	43.0	  
	 Decreased other income primarily due to the 2013 gains on the exchange of APUC subscription
receipts to common shares, partially offset by the 2013 AHI investment impairment
	  				 	 	(13.7	) 
	 Decreased interest expense primarily due to lower short-term debt levels
	  				 	 	6.6	  
	 Increased income tax expense primarily due to increased income before provision for income
taxes
	  				 	 	(7.8	) 
	 Increased preferred stock dividends primarily due to an incremental preferred share
issuance
	  				 	 	(6.9	) 
	 Other
	  				 	 	4.4	  
		  	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2014
	  	$	0.8	  	 	$	(7.7	) 
		  	  
	  
	 	 	  
	  
	 
	 Increased intercompany revenue due to the issuance of a loan to Emera Energy Generation, partially
offset by the repayment of an intercompany loan from Brunswick Pipeline
	  	 	3.1	  	 	 	8.2	  
	 Acquisition costs related to the pending TECO Energy acquisition
	  	 	(21.0	) 	 	 	(51.5	) 
	 Decreased OM&G quarter-over-quarter primarily due to lower performance-based compensation;
increased year-over-year primarily due to business development costs not related to the pending TECO Energy acquisition
	  	 	5.1	  	 	 	(6.4	) 
	 Income from equity investments – see Income from Equity Investments section below
	  	 	13.9	  	 	 	15.0	  
	 Decreased other income quarter-over-quarter due to the reclassification of APUC subscription
receipts; year-over-year due to the losses incurred in Emera Reinsurance from Tropical Storm Erika and the recognition of NSPML as an equity investment in Q2 2014
	  	 	(4.9	) 	 	 	(7.5	) 
	 Increased interest expense primarily due to interest on convertible debentures represented by
installment receipts, partially offset year-over-year by maturity of long-term debt in Q4 2014
	  	 	(23.2	) 	 	 	(17.2	) 
	 Decreased income tax expense primarily due to the decreased income before provision for income
taxes
	  	 	10.3	  	 	 	19.5	  
	 Increased preferred stock dividends year-over-year primarily due to issuance of preferred shares
in Q2 2014
	  	 	—  	  	 	 	(4.1	) 
	 After-tax mark-to-market gain (loss) – see After-Tax Mark-to-Market Gain (Loss) section
below
	  	 	100.5	  	 	 	100.5	  
	 Other
	  	 	(1.1	) 	 	 	(3.5	) 
		  	  
	  
	 	 	  
	  
	 
	 Contribution to consolidated net income – 2015
	  	$	83.5	  	 	$	45.3	  
		  	  
	  
	 	 	  
	  
	 

 
 Acquisition Related Costs 

Highlights of the acquisition related costs summarized in the following table: 
  

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	 	2014	 	  	2015	 	 	2014	 	  	2013	 
	 Operating, maintenance, and general
	  	$	21.0	  	 	$	—  	  	  	$	51.5	  	 	$	—  	  	  	$	—  	  
	 Interest expense, net
	  	 	23.3	  	 	 	—  	  	  	 	23.9	  	 	 	—  	  	  	 	—  	  
	 Income tax expense (recovery)
	  	 	(14.0	) 	 	 	—  	  	  	 	(22.6	) 	 	 	—  	  	  	 	—  	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Acquisition related costs
	  	$	30.3	  	 	$	—  	  	  	$	52.8	  	 	$	—  	  	  	$	—  	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 

  
 59 

 After-Tax Mark-to-Market Gain (Loss) 

The foreign currency earnings impact related to the translation gain from the convertible debenture USD cash balance and the mark-to-market gain from forward
contracts from economically hedging the Debenture Offering are recorded as a mark-to-market adjustment. These pre-tax earnings impacts totaled $118.9 million in “Other income (expenses), net” on the Consolidated Statements of Income
($100.5 million after-tax). The after-tax mark-to-market gain (loss) related to the pending acquisition of TECO Energy is summarized in the following table: 
  

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	 	2014	 	  	2015	 	 	2014	 	  	2013	 
	 Foreign exchange on USD cash
	  	$	26.8	  	 	$	—  	  	  	$	26.8	  	 	$	—  	  	  	$	—  	  
	 Mark-to-market adjustment on USD forward contracts
	  	 	92.1	  	 	 	—  	  	  	 	92.1	  	 	 	—  	  	  	 	—  	  
	 Income tax expense (recovery)
	  	 	(18.4	) 	 	 	—  	  	  	 	(18.4	) 	 	 	—  	  	  	 	—  	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 After-tax mark-to-market gain (loss)
	  	$	100.5	  	 	$	—  	  	  	$	100.5	  	 	$	—  	  	  	$	—  	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 

 Income from Equity Investments 

Income from equity investments are summarized in the following table: 
  

																					
	 For the millions of Canadian dollars
	  	Three months ended
December 31	 	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 	  	2015	 	  	2014	 	  	2013	 
	 APUC
	  	$	18.0	  	  	$	5.6	  	  	$	36.9	  	  	$	30.4	  	  	$	0.4	  
	 NSPML
	  	 	3.8	  	  	 	4.4	  	  	 	14.9	  	  	 	9.5	  	  	 	—  	  
	 LIL
	  	 	3.7	  	  	 	1.6	  	  	 	9.5	  	  	 	6.4	  	  	 	5.2	  
	 AHI
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	(2.3	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Income from equity investments
	  	$	25.5	  	  	$	11.6	  	  	$	61.3	  	  	$	46.3	  	  	$	3.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Income from equity investments increased $13.9 million to $25.5 million in Q4 2015 compared to $11.6 million in Q4
2014. For the year ended December 31, 2015, income from equity investments increased $15.0 million to $61.3 million compared to $46.3 million in 2014. Highlights of the income changes are summarized in the following table: 

  
 60 

									
	 For the millions of Canadian dollars
	 	Three months ended
December 31	 	 	Year ended
December 31	 
	 Income from equity investments – 2013
	 				 	$	3.3	  
	 APUC – Increased due to dilution gains resulting from share issuances, higher earnings and
2013 recognition of discontinued operations of $8.3 million
	 				 	 	30.0	  
	 NSPML – Recognition of the AFUDC earnings of NSPML as income from equity investment
	 				 	 	9.5	  
	 Other
	 				 	 	3.5	  
		 	  
	  
	 	 	  
	  
	 
	 Income from equity investments – 2014
	 	$	11.6	  	 	$	46.3	  
		 	  
	  
	 	 	  
	  
	 
	 APUC – Increased quarter-over-quarter primarily due higher equity earnings in 2015, the
reclassification of APUC subscription receipts in 2015 and a higher dilution gain from the share issuance in Q4 2015 compared to dilution gain from share issuance in Q4 2014; year-over-year due to higher equity earnings in 2015, the reclassification
of APUC subscription receipts in 2015, partially offset by lower dilution on APUC share issuances in 2015 compared to dilutions related to share issuances in 2014
	 	 	12.4	  	 	 	6.5	  
	 NSPML – Increased year-over-year due to the recognition of the AFUDC earnings of NSPML as
income from equity investment
	 	 	(0.6	) 	 	 	5.4	  
	 LIL – Increase in investment
	 	 	2.1	  	 	 	3.1	  
		 	  
	  
	 	 	  
	  
	 
	 Income from equity investments – 2015
	 	$	25.5	  	 	$	61.3	  
		 	  
	  
	 	 	  
	  
	 

 NSPML has cumulatively invested $693.9 million of equity and debt, including $78.1 million of AFUDC, in the development of the
Maritime Link Project. Project to date, ENL has invested a total of $154.9 million in equity, with the 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 per cent. Proceeds 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 per cent to 30 per cent
respectively, which occurred in Q4 2015. From that point forward, project costs are funded with debt and equity at a 70 per cent to 30 per cent ratio, with equity contributions of $13.4 million in Q4 2015. 

Project to date, ENL has invested $207.3 million of equity, including $21.2 million of equity earnings, in LIL. Equity earnings are recorded based on an
annual rate of 8.8 per cent of the equity invested. The rate is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities. 

LIQUIDITY AND CAPITAL RESOURCES 
 The Company generates
cash primarily through its investments in various regulated and non-regulated energy related entities and investments. Utility customer bases are diversified by both sales volumes and revenues among customer classes. Emera’s
non-regulated businesses provide diverse revenue streams and counterparties to the business. Circumstances that could affect the Company’s ability to generate cash include general economic downturns in Emera’s markets, the loss of one or
more large customers, regulatory decisions affecting customer rates and the recovery of regulatory assets and changes in environmental legislation. Emera’s subsidiaries maintain solid credit metrics and are generally in a financial
position to contribute cash dividends to Emera provided they do not breach their debt covenants, where applicable, after giving effect to the dividend payment. 

  
 61 

 Consolidated Cash Flow Highlights 

Significant changes in the statements of cash flows between the years ended December 31, 2015 and 2014 include: 

 

													
	 Year ended December 31 millions of Canadian dollars
	  	2015	 	  	2014	 	  	$ Change	 
	 Cash and cash equivalents, beginning of period
	  	$	221.1	  	  	$	100.8	  	  	$	120.3	  
	 Provided by (used in):
	  				  				  			
	 Operating cash flow before changes in working capital
	  	 	775.8	  	  	 	716.3	  	  	 	59.5	  
	 Change in working capital
	  	 	(101.6	) 	  	 	46.2	  	  	 	(147.8	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Operating activities
	  	 	674.2	  	  	 	762.5	  	  	 	(88.3	) 
	 Investing activities
	  	 	(123.7	) 	  	 	(710.9	) 	  	 	587.2	  
	 Financing activities
	  	 	221.1	  	  	 	58.2	  	  	 	162.9	  
	 Effect of exchange rate changes on cash and cash equivalents
	  	 	80.7	  	  	 	10.5	  	  	 	70.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Cash and cash equivalents, end of period
	  	$	1,073.4	  	  	$	221.1	  	  	$	852.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Operating Cash Flows 

Refer to Consolidated Income Statement Highlights for details. 

Investing Cash Flows 
 Net cash used in investing
activities decreased $587.2 million to $123.7 million for the year ended December 31, 2015 compared to $710.9 million for the year ended December 31, 2014. The decrease was primarily due to proceeds from the sale of NWP in 2015, proceeds from
the Bear Swamp distribution, purchase of APUC subscription receipts in 2014 and higher levels of investment in NSPML and M&NP in 2014, partially offset by increased capital spend and Emera Maine’s investment in a customer information
system. 
 Capital expenditures, including AFUDC and net of proceeds from disposal of assets, for the year ended December 31, 2015 were $436 million
compared to $462 million in 2014 primarily due to decreased capital spending in Emera Energy and Emera Maine, partially offset by increased capital spending at Emera Caribbean. Details of the capital spend are shown below: 

 

	 	•	 	$274 million in NSPI (2014 - $274 million); 

  

	 	•	 	$66 million in Emera Maine (2014 - $85 million); 

  

	 	•	 	$44 million in Emera Caribbean (2014 - $30 million); 

  

	 	•	 	$42 million in Emera Energy (2014 - $63 million); 

  

	 	•	 	$10 million in Corporate and Other (2014 – $10 million) 

 Financing Cash Flows 

Net cash provided by financing activities increased $162.9 million to $221.1 million for the year ended December 31, 2015 compared to $58.2 million in December
31, 2014. The increase was primarily due to the proceeds of convertible debentures represented by instalment receipts related to the pending acquisition of TECO Energy, net of issuance costs, of $681.4 million and the proceeds of the long-term
debt issuance by Brunswick Pipeline and NSPI. This was partially offset by the redemption of NSPI’s preferred shares, repayment of debt in 2015 and the issuance of common and preferred stock in Q1 2014. 

  
 62 

 Working Capital 

As at December 31, 2015, Emera’s cash and cash equivalents were $ 1,073.4 million (2014 – $221.1 million) and Emera’s investment in non-cash
working capital was $599.2 million (2014 – $358.3 million). Of the $ 1,073.4 million of cash and cash equivalents held at December 31, 2015, $727.6 million is from the proceeds from the convertible debentures for the pending TECO Energy
acquisition and are held in USD. Of the remaining cash and cash equivalents, $373.2 million is held by Emera’s foreign subsidiaries (2014 – $206.0 million). A portion of these funds are invested in countries that have certain exchange
controls, required approvals, and processes for repatriation. Such funds remain available to fund local operating and capital requirements unless repatriated. 

Emera’s future liquidity and capital needs will be predominately for working capital requirements and capital expenditures in support of growth
throughout the businesses, as well as acquisitions, dividends and debt servicing. These liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to debt and equity capital
markets. 

  
 63 

 Contractual Obligations 

As at December 31, 2015, commitments 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	 
	 Long-term debt
	  	$	274.0	  	  	$	53.0	  	  	$	25.5	  	  	$	619.6	  	  	$	728.7	  	  	$	2,323.6	  	  	$	4,024.4	  
	 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	  
	 Pension and post-retirement obligations (3)
	  	 	14.8	  	  	 	19.2	  	  	 	19.8	  	  	 	20.2	  	  	 	20.9	  	  	 	716.7	  	  	 	811.6	  
	 Asset retirement obligations
	  	 	5.5	  	  	 	4.0	  	  	 	4.3	  	  	 	4.2	  	  	 	1.7	  	  	 	317.2	  	  	 	336.9	  
	 Interest payment obligations (4)
	  	 	187.7	  	  	 	178.8	  	  	 	176.3	  	  	 	175.3	  	  	 	141.3	  	  	 	2,249.9	  	  	 	3,109.3	  
	 Convertible debentures represented by instalment receipts (5)
	  	 	727.6	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	727.6	  
	 Interest obligations on the first instalment of convertible debentures represented by instalment
receipts (5)
	  	 	75.9	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	75.9	  
	 Transportation (6)
	  	 	183.6	  	  	 	72.2	  	  	 	55.8	  	  	 	25.7	  	  	 	20.9	  	  	 	86.9	  	  	 	445.1	  
	 Long-term service agreements (7)
	  	 	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 (8)
	  	 	379.6	  	  	 	159.0	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	538.6	  
	 Leases and other (9)
	  	 	12.6	  	  	 	11.6	  	  	 	9.5	  	  	 	8.9	  	  	 	7.5	  	  	 	27.5	  	  	 	77.6	  
		  	$	2,383.4	  	  	$	901.0	  	  	$	580.5	  	  	$	1,112.7	  	  	$	1,138.8	  	  	$	8,391.7	  	  	$	14,508.1	  

  

	(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)	Pension and post-retirement obligations: Defined benefit funding contractual obligations were determined based on funding requirements and assuming pension accruals cease as at December 31, 2015. Credited service and
earnings are assumed to be crystallized as at December 31, 2015. The Company contractual obligations for post-retirement (non-pension) benefits assumes members must be age 55 or over as at December 31, 2015 to be eligible. As the defined benefit
pension plans currently undergoes regular reviews to revise contribution requirements and members are still accruing service under the plans, actual future contributions to the plans will differ from the amounts shown. 

	(4)	Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable rates, interest is calculated for all future periods using the rates in
effect at December 31, 2015 including any expected required payment under associated swap agreements. 

	(5)	Convertible debentures: On September 28, 2015, to finance a portion of the pending acquisition of TECO Energy, Emera completed the sale of $1.9 billion principal amount of 4 per cent convertible unsecured subordinated
debentures. On October 2, 2015 the over-allotment option was exercised and $285 million in additional Debentures were sold. The table above shows the obligations as a result of this Debenture Offering. Further information on the Debenture Offering
is in the Developments section. 

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

	(7)	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. 

	(8)	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 LIL 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
amount as the projects advance through construction. 

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

  
 64 

 Forecasted Gross Consolidated Capital Expenditures 

For the year ended December 31, 2016, forecasted gross consolidated capital expenditures are as follows: 

 

																									
	 millions of Canadian dollars
	  	NSPI	 	  	Emera
Maine	 	  	Emera
Caribbean	 	  	Emera
Energy	 	  	Corporate
and Other	 	  	Total	 
	 Generation
	  	$	105.0	  	  	$	—  	  	  	$	17.9	  	  	$	29.9	  	  	$	—  	  	  	$	152.8	  
	 New renewable generation
	  	 	—  	  	  	 	—  	  	  	 	67.3	  	  	 	—  	  	  	 	—  	  	  	 	67.3	  
	 Transmission
	  	 	56.1	  	  	 	33.6	  	  	 	5.9	  	  	 	—  	  	  	 	—  	  	  	 	95.6	  
	 Distribution
	  	 	74.8	  	  	 	34.3	  	  	 	38.3	  	  	 	—  	  	  	 	—  	  	  	 	147.4	  
	 Facilities, equipment, vehicles, and other
	  	 	44.0	  	  	 	17.2	  	  	 	20.1	  	  	 	—  	  	  	 	20.4	  	  	 	101.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	$	279.9	  	  	$	85.1	  	  	$	149.5	  	  	$	29.9	  	  	$	20.4	  	  	$	564.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Debt Management 
 In
addition to funds generated from operations, Emera and its subsidiaries have, in aggregate, access to approximately $1.3 billion committed syndicated revolving bank lines of credit, as discussed in the table below. NSPI has an active commercial
paper program for up to $400 million, of which the full amount outstanding is backed by the Company’s bank line referred to below. The amount of commercial paper issued results in an equal amount of credit being considered drawn and
unavailable. 
 As at December 31, 2015, the Company’s total credit facilities, outstanding borrowings and available capacity were as follows: 

 

																	
	 millions of dollars
	  	Maturity	 	  	Revolving
Credit
Facilities	 	  	Utilized	 	  	Undrawn
and
Available	 
	 Emera – Operating and acquisition credit facility
	  	 	June 2020 – Revolver	  	  	$	700	  	  	$	268	  	  	$	432	  
	 NSPI – Operating credit facility (1)
	  	 	October 2020 – Revolver	  	  	 	500	  	  	 	370	  	  	 	130	  
	 Emera Maine – in USD – Operating credit facility
	  	 	September 2019 – Revolver	  	  	 	80	  	  	 	25	  	  	 	55	  
	 Other – in USD – Operating credit facilities
	  	 	Various	  	  	 	32	  	  	 	—  	  	  	 	32	  

  

	(1)	Extended to October 2020 on December 15, 2015. 

 For the purpose of bridge financing for the pending
acquisition of TECO Energy, on September 4, 2015, the Company secured an aggregate of $6.5 billion USD non-revolving term credit facilities (“Acquisition Credit Facilities”) from a syndicate of banks. The non-revolving term credit
facilities are comprised of a $4.3 billion USD debt bridge facility, repayable in full on the first anniversary following its advance, and a $2.2 billion USD equity bridge facility repayable in full on the first anniversary following its advance. 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
facilities table above does not include the Acquisition Credit Facilities. 

  
 65 

 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. 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 and its subsidiaries’ recent financing activity is discussed further in the Developments section. 

As at December 31, 2015, approximately 84 per cent of Emera’s consolidated debt position is fixed rate in nature, with an average term to maturity of
approximately 17 years. Emera’s scheduled maturities for debt over the next five years are expected to be $274 million, $53 million, $25 million, $588 million and $120 million for 2016 through 2020 respectively. 

Emera’s future liquidity and capital needs, not including the capital needs to fund the pending TECO Energy acquisition, will be predominately for
working capital requirements and capital expenditures in support of growth throughout the businesses, as well as potential new acquisitions, dividends and debt servicing. These liquidity and capital needs will be financed through internally
generated cash flows, short-term credit facilities, and ongoing access to capital markets. 
 The cash purchase price of the pending TECO Energy acquisition
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 second 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 the revolving 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. 
 Emera and its subsidiaries have certain financial and other
covenants associated with their debt and credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements. Emera’s significant covenant is 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	  

  
 66 

 Credit Ratings 

Emera 
 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 Energy
acquisition, DBRS placed the ratings of Emera ‘Under Review with Developing Implications’. The rating actions reflect DBRS’s view that while the TECO Energy acquisition would have a relatively neutral impact on Emera’s business
risk assessment, the impact on the financial risk assessment was at the time of the ratings actions uncertain as Emera’s financing plan had not been finalized. DBRS indicated that it will further review Emera’s financing plan when it
is finalized. 
 On September 8, 2015, Standard and Poor’s (“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 acquisition. S&P could revise its outlook to stable within a two-year outlook period, if the Debentures are successfully converted. 

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

					
	 	  	 DBRS
	  	 S&P

	Long-term corporate	  	N/A	  	BBB+
	Senior unsecured debt	  	BBB (high)	  	BBB

 NSPI 
 On December 18,
2015, DBRS Limited (“DBRS”) affirmed all ratings on NSPI. 
 On September 8, 2015, Standard and Poor’s Rating Services (“S&P”)
affirmed all ratings on NSPI. At the same time it affirmed its rating on Emera and revised Emera’s outlook to negative from stable. The outlook revision for Emera followed Emera’s announcement of the proposed acquisition of TECO
Energy. Per S&P’s group rating methodology criteria, NSPI is subject to Emera’s revised outlook. 
 NSPI’s credit ratings issued by DBRS
and S&P are as follows: 
  

					
	 	  	 DBRS
	  	 S&P

	Corporate	  	N/A	  	BBB+
	Senior unsecured debt	  	A (low)	  	BBB+

 Emera Maine, BLPC, Domlec and GBPC have no public debt, and accordingly have no requirement for public credit
ratings. These utilities believe their credit facilities provide adequate access to capital to support current operations and a base level of capital expenditures. For additional capital needs, these utilities expect to have sufficient
access to competitively priced financing in the unsecured or secured debt markets. 

  
 67 

 Share Capital 

Emera 
 As at December 31, 2015, Emera had 147.21 million
(2014 – 143.78 million) common shares issued and outstanding. For the year ended December 31, 2015, 3.43 million common shares were issued (2014 – 10.89 million) for net proceeds of $141.1 million (2014 – $313.4 million).
The issuance of shares was primarily due to facilitate the creation and issuance of depositary receipts in connection with the ECI share acquisition and the dividend reinvestment program. 

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. 
 As at December 31, 2015, Emera had 29.0 million preferred shares issued and outstanding (2014 – 29.0 million). 

PENSION FUNDING 
 For funding purposes, Emera determines
required contributions to its largest defined benefit pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the impact of investment gains and losses are recognized over a three-year period. The
cash required in 2016 for defined benefit pension plans is expected to be $19.7 million (2015 – $ 23.0 million). All pension plan contributions are tax deductible and will be funded with cash from operations. 

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

To achieve the overall long-term asset allocation, pension assets are managed by external investment managers per the pension plan’s investment policy
and governance framework. The asset allocation includes investments in the assets of Canadian and global equities, domestic and global bonds and short-term investments. Emera reviews investment manager performance on a regular basis and adjusts the
plans’ asset mixes as needed in accordance with the pension plans’ investment policy. 
 Emera’s projected contributions to defined
contribution pension plans are $10.0 million for 2016 (2015 – $9.0 million actual). 
 Defined Benefit Pension Plan Summary 

As at December 31, 2015 
 in millions of Canadian dollars 

 

																	
	 Plans by region
	  	NSPI Pension
Plans	 	  	Emera Maine
Pension Plans	 	  	Caribbean
Plans	 	  	Total	 
	 Assets as at December 31, 2015
	  	$	1,128.6	  	  	$	161.5	  	  	$	10.3	  	  	$	1,300.4	  
	 Accounting obligation at December 31, 2015
	  	 	1,295.8	  	  	 	211.3	  	  	 	12.6	  	  	 	1,519.7	  
	 Accounting expense during fiscal 2015
	  	$	56.1	  	  	$	6.4	  	  	$	0.4	  	  	$	62.9	  

  
 68 

 OFF-BALANCE SHEET ARRANGEMENTS 

Defeasance 
 Upon privatization of the former provincially
owned NSPC in 1992, NSPI became responsible for managing a portfolio of defeasance securities that provide principal and interest streams to match the related defeased debt, which at December 31, 2015 totaled $0.8 billion (2014 – $0.7 billion).
The securities are held in trust for Nova Scotia Power Finance Corporation (“NSPFC”), an affiliate of the Province of Nova Scotia. Approximately 70 per cent of the defeasance portfolio consists of investments in the related debt,
eliminating all risk associated with this portion of the portfolio; the remaining defeasance portfolio has a market value higher than the related debt, reducing the future risk of this portion of the portfolio. 

Under the privatization agreements, NSPI administers the defeasance cash flows and obligations pursuant to a Management and Administration Agreement. The
NSPFC bank accounts are included in NSPI’s pool of bank accounts under a mirror netting agreement and therefore, from time to time, if any cash accumulates in the NSPFC bank account it is available as an offset until that cash is required to
service the defeased NSPC debt. 
 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.

  

	 	•	 	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. 

  
 69 

 OUTLOOK 

General and Market Trends 
 Energy markets across North
America are affected by a number of trends that shape the environment in which energy and utility companies are operating. Some of these trends are short-term or cyclical, while others evolve to have a significant long-term impact on businesses
and stakeholders across the sector.
 Among the key trends influencing Emera’s long-term strategy is the increasing expectation by customers and
policy-makers for a permanent reduction in the carbon equivalent levels of electricity generation. This advocacy drive for cleaner, renewable sources of electricity has become a defining trend in the industry, not just in the markets Emera
serves, but on a global basis. While it is still unclear whether economic volatility and lower fossil fuel prices will slow the pace of this transformation, its impact on the sector continues to be felt in the form of mandated and incented
carbon reductions throughout eastern North America and in the Caribbean. As such, investment in wind, solar and hydro generation, and natural gas infrastructure, is likely to continue across the sector. 

This transformation in generation and fuel selection also has a significant impact on the requirement for new transmission infrastructure. Increasingly,
in addition to the traditional issues of infrastructure life expectancy and changing technology, infrastructure renewal planning must now take into account the changing energy landscape. Gas extraction from the Marcellus Shale region of the
United States, major hydro developments in Newfoundland and Labrador, and wind farms in northern New England and Atlantic Canada (to name a few) require significant new transmission infrastructure to bring this energy to market. 

The capital spending requirements related to this renewal underscore the intense focus placed by customers and regulators on electricity price and
affordability that is required by our franchise agreements and basic rate regulation. Going forward, the ability of energy companies to achieve their growth objectives, environmental targets and other goals, will continue to be a key success
factor. 
 As technology advances, so too does the availability and demand for affordable new mechanisms that allow consumers to have more control over
their energy usage and for utilities to introduce more efficient energy solutions for their customers. This includes grid modernization and ‘smart grid’ advances that, when combined with in-home products such as heat pumps and electric
thermal storage units, have the potential to significantly increase energy efficiency for consumers while allowing utilities to better manage peak load demand. In addition, wind turbine technology and advancements in solar technology have reduced
solar generation costs significantly, bringing them more in line with the cost of fossil fuel generation in some higher-cost jurisdictions. This gives rise to an expectation on the part of customers that they will be able to benefit from options
such as distributed generation. Continued and advancing development of energy storage technology will further transform and support the efficient and practical utilization of renewables. This, in turn, raises new issues related to the role of
the utility, and the appropriate allocation of existing infrastructure and transmission, generation and distribution costs. 
 These and other trends create
opportunities and challenges for businesses, regulators, investors and other stakeholders within the energy sector, and are expected to drive increased regional cooperation and interconnection within the energy industry. Whether it is the need
to transport natural gas and electricity from disparate regions to markets on the eastern seaboard, or the need to gain efficiencies by coordinating electricity generation and dispatch across multiple jurisdictions, inter-regional cooperation has
emerged as an important trend itself. 

  
 70 

 Business Outlook 

The pending TECO Energy acquisition will result in further acquisition costs in 2016. The transaction is expected to be accretive to EPS by approximately 5 per
cent in the first full year following its completion (2017), growing to more than 10 per cent by the third full year (2019) assuming a USD/CAD exchange rate consistent with that at the time of announcement. As well, approximately 95 per cent of the
expected foreign exchange exposure to close the pending acquisition has been actually or effectively hedged. 
 Emera’s operations are affected by the
US dollar relative to the Canadian dollar. With the increasing disparity between the two currencies, the effect on Emera’s income is noteworthy, as approximately 50 per cent of Emera’s adjusted net income was derived from subsidiaries
with a US functional currency. TECO Energy operations are conducted in US dollars and following the pending acquisition, Emera‘s consolidated net income and cash flows will be impacted to a greater extent by movements in the US dollar
relative to the Canadian dollar. 
 NSPI 
 NSPI’s
earnings are most directly impacted 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, the approved recovery of 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 Nova Scotia’s reliance upon high carbon and greenhouse gas emitting sources of energy has resulted in NSPI making a 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 general rate application 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, if required by
NSPI. NSPI will continue to work towards rate stability for customers through a focused effort on operating costs, productivity levels and service improvements to meet the requirements of the legislation.

The Company expects to finance its capital expenditures with funds from operations, credit facilities and continued access to debt capital markets for
long-term financing.
 Emera Maine 
 Emera Maine’s
earnings are most directly impacted 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. 
 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 

  
 71 

 
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 per cent. 

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

Emera Caribbean 
 Earnings from Emera Caribbean are most
directly impacted 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 per cent forecast for 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 to maintain the 2015 cost savings into the future. 

The economy of Grand Bahamas 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 General
Rate Application applicable for the 2016 through 2018 period. Residential customers will see decreases up to 4.5 per cent, while commercial customers will see an increase of 1.5 per cent. Commercial customers consume approximately 70 per cent of
GBPC’s production. Rates were approved based upon an 8.8 per cent return on rate base, reduced from the previous level of 10 per cent. This rate decision 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. 
 Tropical Storm Erika affected the island of Dominica on August 27,
2015 and as a result, weaker economic growth is expected to affect sales into 2016. In connection with its pending rate case, Domlec made a preliminary filing in 2014 requesting that a weighted average cost of capital rate of 11.6 per cent be
used for rate making purposes. In Q2 2015, the IRC set a cost of capital rate of 8.56 per cent, which Domlec unsuccessfully appealed to the IRC. Domlec made a further appeal to the Dominican court. The rate filing and rate case proceedings
will begin after the cost of capital is determined. The cost of capital rate hearing has been delayed, with no new hearing date yet determined due to Tropical Storm Erika. 

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 million standard cubic feet per day (“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. 

  
 72 

 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. 

Emera Energy 
 Emera Energy Services 

Emera Energy Services, Emera Energy’s trading and marketing 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 earnings from trading and marketing, particularly in 2014. 2015 has seen lower market volatility and pricing, and a resulting decrease in trading and marketing 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 Northeast 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 New England Gas Generating Facilities 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 larger of the two 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 the
New England Gas Generating facilities, and Emera Energy’s 50 per cent interest in Bear Swamp. 

  
 73 

							
	 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 per cent 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 

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 pending TECO Energy acquisition, equity investments in the Maritime Link Project and the Labrador-Island Link, 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 pending TECO Energy acquisition. 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. 
 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 will reduce Emera’s ownership interest. 
 ENL 

NSP Maritime Link Inc. (“NSPML”) 
 Through its
subsidiary, NSP Maritime Link Inc., ENL has in total invested approximately $693.9 million of equity and debt, including $78.1 million of AFUDC, in the development of the Maritime Link Project. Project to date, ENL has invested a total of
$154.9 million in equity, with the 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 per cent. 

ENL’s future earnings contribution from the Maritime Link Project will be affected by the timing of capital expenditures for design and construction
activities, which will determine the component of costs to be funded by equity. Proceeds 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
per cent to 30 per cent respectively, which occurred in Q4 2015. From that point forward, project costs are funded with debt and equity at a 70 per cent to 30 per cent ratio, with equity contributions of $13.4 million in Q4 2015. 

Maritime Link Project 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. 

  
 74 

 Labrador Island Link (“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 equity earnings in LIL. Project to date, ENL has invested a total of $186.1 million in equity. Equity earnings are recorded based on an annual rate of 8.8 per cent of the equity
invested. The return on ROE is approved by the Newfoundland and Labrador Board of Commissioners of Public Utilities (“NLPUB”). There is currently an application being heard by the NLPUB which includes a review of ROE. The
NLPUB’s decision on ROE, expected in Q2 2016, will be applicable for all regulated electrical utilities in Newfoundland and Labrador and become the ROE applicable to ENL’s investment in LIL. 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 forecasted equity contributions for 2016 are $223 million, with total equity investment, by Emera, in the Project estimated to be $409.1 million. 

Both the NSPML and LIL investments are recorded as “Investments subject to significant influence” on Emera’s consolidated balance sheets. 

TRANSACTIONS WITH RELATED PARTIES 
 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: 
  

													
	 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	  

  
 75 

 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.
 DIVIDENDS
AND PAYOUT RATIOS 
 Emera Incorporated’s common share dividends paid in 2015 were $1.66 ($0.3875 in Q1, $0.4000 in Q2 and Q3 and $0.4750 in Q4) and
$1.48 ($0.3625 per quarter in Q1, Q2 and Q3 and $0.3875 in Q4) per common share for 2014, representing a payout ratio of 72.8 per cent of adjusted net income in 2015 and 65.8 per cent for 2014. The increase in the payout ratio is primarily due to an
increase in dividends paid greater than growth in adjusted net income. 
 On August 10, 2015, Emera’s Board of Directors approved an increase in the
annual common share dividend rate from $1.60 to $1.90 per common share. 
 ENTERPRISE RISK AND RISK MANAGEMENT 

Emera has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach to risk
management. Certain risk management activities for Emera are overseen by the Enterprise Risk Management Committee to ensure such risks are appropriately assessed, monitored and controlled within predetermined risk tolerances established through
approved policies. 
 The Company’s risk management activities are focused on those areas that most significantly impact profitability, quality of
income and cash flow. These risks include, but are not limited to, exposure to regulatory and political risk, acquisition, weather, changes in environmental legislation, energy consumption, foreign exchange, capital market and liquidity risk,
interest rate, project development and construction risk, cybersecurity, non-regulated plant operational risk, credit, country, commercial relationships, commodity price risk, future employee benefit plan performance and funding, labour, information
technology and un-insured risk. 
 In this section, Emera describes some of the principal risks that management believes could materially affect its
business, revenues, operating income, net income, net assets, or liquidity or capital resources. The nature of risk is such that no list is comprehensive, and other risks may arise or risks not currently considered material may become material
in the future. 

  
 76 

 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 customers, 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 approval by the respective regulator 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’s investments in entities in which it has significant
influence and which are subject to regulatory risk include: NSPML, APUC, M&NP, 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. 

Brunswick Pipeline entered into a 25-year firm service agreement, expiring in 2034, with Repsol Energy Canada (“REC”), 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. 
 Acquisition Risk 

The risks associated with Emera’s acquisition strategy include potential difficulties inherent in acquisitions that may adversely affect the results of an
acquisition and these include delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies from completed transactions. 

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

The closing of the acquisition of TECO Energy is subject to the commercial risks associated with a publicly owned regulated utility acquisition per the terms
negotiated in the acquisition agreement. The acquisition is subject to approval of 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. Shareholder approval of the transaction was received on December 3, 2015. On December 14, 2015, the New Mexico Public Regulation Commission established a hearing to begin on 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. 

  
 77 

 Failure to obtain the required approvals or satisfy or waive the conditions contained in the acquisition
agreement may result in the termination of the acquisition agreement. There is no assurance that such closing conditions will be satisfied or waived. Accordingly, there can be no assurance that Emera will complete the acquisition in the
timeframe or on the basis described herein, if at all. The termination of the acquisition agreement may have a negative effect on the price of the instalment receipts, the Debentures and the common shares and will result in the redemption of
the Debentures. If the closing of the acquisition does not take place as contemplated, the Company could suffer adverse consequences, including the loss of investor confidence. 

A substantial delay in obtaining regulatory approvals or the imposition of unfavourable terms and/or conditions in such approvals could have a material
adverse effect on the Company’s ability to complete the acquisition and on the Company’s or TECO Energy’s business, financial condition or results of operations. In addition, in the event that such regulatory agencies impose
unfavourable terms and/or conditions on Emera or any TECO Energy utility (including the requirement to sell or divest of certain assets or limitations on the future conduct of the individual or combined entities), the Company would still be required
to complete the transaction on the terms set forth in the acquisition agreement. Emera intends to complete the acquisition within three days of obtaining the required TECO Energy shareholder approval and regulatory approvals and satisfaction of
the other required closing conditions. 
 Emera expects the pending acquisition of TECO Energy will provide benefits to the Company, including that the
acquisition will be accretive to Emera’s EPS by approximately five per cent in the first full year following its completion (2017), excluding acquisition related expenses, growing to more than 10 per cent by the third full year (2019), assuming
a USD/CAD exchange rate consistent with that at the time of announcement. As well, approximately 95 per cent of the expected foreign exchange exposure to close the pending acquisition has been actually or effectively hedged. In addition, the
availability of net operating loss carry-forwards and alternative minimum tax credits, if utilized, are expected to provide significant accretion to Emera’s cash position. However, there is a risk that some or all of the expected benefits of
the acquisition may fail to materialize, or may not occur within the time periods anticipated by the Company. The realization of such benefits may be affected by a number of factors, many of which are beyond the control of the Company. The challenge
of combining previously independent businesses makes evaluating the Company’s business and future financial prospects difficult. The past financial performance of the Company may not be indicative of its future financial performance. In
addition, any regulatory approvals required in connection with the acquisition may include terms which could have an adverse effect on the Company’s financial performance, including reduced revenues or investment recovery, increased competition
or costs, or adverse alterations to the rate structure. 
 Failure to realize the anticipated benefits of the acquisition may impact the financial
performance of the Company, the price of its common shares and the ability of Emera to continue to pay dividends on its common shares at current levels or at all. The declaration of dividends by the Company is at the discretion of the Board of
Directors. 
 In addition to the potential liability for damages for breach of the acquisition agreement by Emera, if (i) the acquisition agreement is
terminated by either party due to a failure to obtain the required regulatory approvals by the end date specified in the acquisition agreement, or because there is a final and non-appealable legal restraint that relates to the required regulatory
approvals, or if TECO Energy terminates the acquisition agreement based on a failure by Emera to perform its agreements with respect to the receipt of the required regulatory approvals, and, in each case, at the time of such termination the TECO
Energy shareholder approval shall have been obtained and the other closing conditions on behalf of Emera shall have been satisfied or waived (except for those conditions, that by their nature, are to be satisfied at the closing of the acquisition,
but which conditions would be satisfied, or would be capable of being satisfied, if the closing of the Acquisition were to occur on the date of such termination and those conditions that have not been satisfied as a result of a breach of the
acquisition agreement by Emera), or (ii) TECO Energy terminates the acquisition agreement in the event that all applicable closing conditions have been satisfied or waived and Emera fails to close the acquisition because of a failure of any person
or entity to provide acquisition financing, then Emera will be obligated to pay to TECO Energy a fee of $326.9 million USD in cash. 

  
 78 

 For the purpose of financing the pending acquisition, Emera completed a $2.185 billion Debenture Offering in
September and October 2015, including the exercise of an over-allotment. The Company also obtained a commitment letter for an aggregate of $6.5 billion USD non-revolving credit facilities. 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 commitment of the lenders to enter into the acquisition credit
facilities is subject to certain standard conditions, which may result in such facilities becoming unavailable to Emera in certain circumstances. If the acquisition credit facilities become unavailable to Emera, Emera may not be able to
complete the acquisition. 
 Completion of the acquisition is not conditional on the completion of the Debenture Offering by the Company or on the Company
obtaining financing on favourable terms or at all. If a material amount due on payment of the final instalment is not paid by holders of instalment receipts and the Company is not able to quickly realize on the Debentures pledged to secure the
obligation to pay the final instalment, the Company will not be able to use those proceeds to repay the acquisition credit facilities. As a result, it may take Emera longer than anticipated to repay the acquisition credit facilities which may
have a negative impact on the consolidated capitalization of Emera until such time as the acquisition credit facilities have been repaid by Emera in full. 

There is no guarantee that alternate sources of funding will be available to Emera or its affiliates at the desired time or at all, or on cost-effective
terms. The inability to obtain alternate sources of funding to fund the acquisition or replace the acquisition credit facilities may negatively impact the financial performance of Emera, including the extent to which the acquisition is
accretive. In addition, any movement in interest rates that could affect the underlying cost of these instruments may affect the expected accretion of the acquisition. 

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

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

  
 79 

 Changes in Environmental Legislation 

Emera is subject to regulation by federal, provincial, state, regional and local authorities with regard to environmental matters; primarily related to its
utility operations. This includes laws setting greenhouse gas (“GHG”) emissions standards and air emissions standards. Emera is also subject to laws regarding the generation, storage, transportation, use and disposal of hazardous
substances and materials. 
 In addition to imposing continuing compliance obligations, there are permit requirements, laws and regulations authorizing the
imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is, and may be, material to Emera. Failure to comply with
environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect on Emera. 
 New emission
reductions requirements for the utilities sector are being established by governments in Canada and the United States. Changes to GHG emissions standards and air emissions standards could adversely affect Emera’s operations and financial
performance. Stricter environmental laws and enforcement of such laws in the future could increase Emera’s exposure to additional liabilities and costs. These changes could also affect earnings and strategy by changing the nature and
timing of capital investments. 
 Emera manages its environmental risk by operating in a manner that is respectful and protective of the environment and
with the objective of achieving full compliance with applicable laws, legislation and company policies and standards. Emera has implemented this policy through the development and application of environmental management systems in its operating
subsidiaries. Comprehensive audit programs are also in place to regularly test compliance with such laws, policies and standards. 
 Energy Consumption
Risk 
 Typical of utilities, Emera is affected by demand for energy in the areas in which it operates based upon fluctuations in general economic
conditions, such as changes in employment levels, personal disposable income, energy prices and housing starts. Customers’ focus on energy efficiency could also result in changes in energy consumption. 

Government policies promoting distributed generation (“DG”) and new technology developments enabling those policies, particularly with rooftop
solar, have the potential to impact residential sales and thereby revenues. This could negatively impact operations, net earnings and cash flows. Energy costs and clean energy options have increased demand for products enabling the
consumers’ ability to self-generate.
 Foreign Exchange Risk 

The Company is exposed to foreign currency exchange rate changes. In 2015, approximately 50 per cent of Emera’s adjusted net income was derived from
subsidiaries with US functional currency. As such, its earnings are subject to fluctuations in the Canadian dollar to US dollar exchange rate. As discussed below, the pending acquisition of TECO Energy will increase this percentage
significantly. 
 The Company identifies and hedges significant transactional currency risks in accordance with its policies and procedures. Emera does
not currently hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries are included in accumulated other comprehensive income (loss) (“AOCI”). 

The Company enters into foreign exchange forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases,
revenues streams, capital expenditures and capital projects. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including foreign exchange. 

  
 80 

 Emera does not enter into hedges for its foreign currency translation exposure on its non-Canadian
assets. Any changes in the Canadian exchange rate will affect the equivalent Canadian dollar value of such assets, and the equivalent Canadian dollar value of these assets, revenues and earnings contributions. 

Pending TECO Energy Acquisition 
 The cash consideration for the
acquisition is required to be paid in US dollars, while funds raised in the Debenture Offering or any other Canadian dollar offering, which may constitute a significant portion of the funds ultimately used to finance the acquisition, are denominated
in Canadian dollars. As a result, increases in the value of the US dollar versus the Canadian dollar prior to either the payment of the final instalment or the close of any Canadian dollar offerings will increase the purchase price translated
in Canadian dollars and thereby increase the Canadian dollars required to fund the US dollar purchase price for the acquisition ultimately obtained by Emera. 

The proceeds of the first instalment of the Debenture Offering and the overallotment were converted to US dollars and 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 contracts are economic hedges and do not qualify for hedge accounting. Therefore, all mark-to-market gains and losses related to the forwards and related to the US
denominated cash proceeds will be recognized in net income for the period. Until the hedge settles and the USD denominated cash is used to acquire TECO Energy, foreign exchange fluctuations could create significant mark-to-market adjustments
that may result in volatility in Emera’s earnings. 
 In addition, the operations of TECO Energy are conducted in US dollars. Following the
acquisition, the 
 consolidated net income and cash flows of Emera will be impacted to a greater extent by movements in the US dollar relative to the
Canadian dollar. In particular, decreases in the value of the US dollar versus the Canadian dollar following the acquisition, could negatively impact the Company’s net income as reported in Canadian dollars, which could cause a failure to
realize all or some of the anticipated benefits of the acquisition, including accretion. 
 Capital Market and Liquidity Risk 

Emera’s utility and non-utility operations and projects in development require significant capital investments in property, plant and
equipment. Consequently, Emera is an active participant in the debt and equity markets. Any disruption in capital markets could have a material impact on Emera’s ability to fund its operations. Capital markets are global in
nature and are affected by numerous events throughout the world economy. Capital market disruptions could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. 

Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera forecasts cash requirements
on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs will be financed through internally generated cash flows, short-term credit facilities, and ongoing access to capital markets. The Company
reasonably expects liquidity sources to exceed ordinary course capital needs. 
 Emera is subject to financial risk associated with changes in its credit
ratings. A change to a credit rating could result in higher interest rates in future financings, increase borrowing costs under certain existing credit facilities, limit access to the commercial paper market or limit the availability of
adequate credit support for subsidiary operations. 

  
 81 

 Interest Rate Risk 

Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate
risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter into interest
rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. 
 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. 
 For Emera’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, such that regulatory ROE’s are likely to fall in times of reducing interest rates and raise in times of increasing interest rates,
albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives. 

Project Development and Construction Risk 
 ENL’s
planned investment in the development of the Maritime Link Project has risks commensurate with any large construction project. Risks related to such large projects include impact on costs of schedule delays and risk of cost overruns. Emera has
deployed a robust project and risk management approach to this project, led by a team with extensive experience in large projects. There are also significant contractual terms in place protecting Emera and ENL from any exposure to cost overruns
to either of Nalcor’s projects and with specific provisions for Nalcor sharing in cost overruns of the Maritime Link Project. 
 In February 2015, ENL
entered into a contract with Abengoa S.A., a global Spanish energy company, for the transmission line construction on the Maritime Link Project. On November 25, 2015, Abengoa S.A. filed a notice under Spanish law, which provides for pre
insolvency protection in Spain, giving the company up to four months to reach an agreement with creditors to avoid a full insolvency process. ENL is working closely with Abengoa and the performance bond sureties to minimize project
impacts. Work on the Project continues. 
 Cybersecurity Risk 

Emera’s reliance on information technology to manage its business exposes the Company to potential risks related to cybersecurity attacks and unauthorized
access to the Company’s, customers’, suppliers’, counterparties’ and employees’ sensitive or confidential information, (which may include personally identifiable information and credit information) through hacking, viruses
and otherwise (collectively “cybersecurity threats”). The Company uses information technology systems and network infrastructure, which include controls for interconnected systems of generation, distribution, and transmission, some of
which is shared with third parties for operating purposes. Through the normal course of business, the Company also collects, processes, and retains sensitive and confidential customer, supplier, counter-party and employee information. 

Despite security measures in place, the Company’s systems, assets and information could be vulnerable to cybersecurity attacks and other data security
breaches that could cause system failures, disrupt operations, adversely affect safety, result in loss of service to customers and release of sensitive or confidential information. Should such cybersecurity threats materialize the Company could
suffer costs, losses and damages; all or some of which may not be recoverable through regulatory processes or otherwise. 

  
 82 

 Emera Energy Trading and Marketing 

The majority of Emera’s portfolio of electricity and gas marketing and trading contracts, and in particular its natural gas asset management arrangements,
are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets, in the
event of an operational issue or counterparty default. To measure commodity price risk exposure, Emera employs a number of controls and process, including an estimated value-at-risk (“VaR”) analysis of its exposures. The VaR amount
represents an estimate of the potential change in fair value that could occur from changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to
quantify exposure to market risk associated with physical commodity, primarily in natural gas and power positions. The Company’s commercial arrangements, including the combination of supply and purchase agreements, asset management agreements,
pipeline transportation agreements and financial hedging instruments, as well as its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are all used to manage
and mitigate this risk. 
 Emera Energy Electricity Sales and Non-Regulated Fuel for Generation and Purchased Power 

Emera Energy’s natural gas fired plants in northeastern United States, operating as merchant facilities, are susceptible to the volatility of the New
England electricity market and natural gas prices. Market electricity prices are dependent upon a number of factors, including the projected supply and demand of electricity, natural gas prices, the price of other materials used to generate
electricity, the cost of complying with applicable environmental and other regulatory requirements and weather conditions. A material change in any one of these factors can materially affect the profitability of the facilities. 

Non-Regulated Plant Operational Risk 
 Emera owns three
combined-cycle gas-fired electricity generating facilities in New England (New England Gas Generating Facilities) as well as a gas fired generating facility and biomass fired generating facility in Maritime Canada (Bayside Power and Brooklyn
Energy). Power plant operations involve the risk of outages due to failure of generation equipment, transmission lines, pipelines or other equipment, which could make the affected plant unavailable to provide service. Unplanned outages
could result in lost revenues, increased capital costs and maintenance expenses, payment of cover costs for any hedges in place, and reduced profitability. Insurance is maintained to mitigate operating risks. 

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.

 Country Risk 
 Operating revenues outside of Canada
constituted 45 per cent (28 per cent from the US and 17 per cent from the Caribbean) of Emera’s total operating revenues in 2015 (2014 – 48 per cent, with 31 per cent from the US and 17 per cent from the Caribbean). Emera’s
investments are currently in regions where the political and economic risk levels are considered by the Company to be acceptable. Emera’s operations in some countries may be subject to the following risks: changes in the rate of economic
growth, restrictions on the repatriation of income or capital exchange controls, inflation, the effect of global health, safety and environmental matters or economic conditions and market conditions, and change in financial policy and availability
of credit. 

  
 83 

 Commercial Relationships Risk 

The Company is exposed to commercial relationships risk in respect of its reliance on certain key partners, suppliers and customers. The Company manages
its commercial relationships risk by monitoring credit risk, as discussed below in Credit Risk, and monitoring of significant developments with its customers, partners and suppliers. 

Commodity Price Risk 
 A large portion of the
Company’s fuel supply comes from international suppliers and is subject to commodity price risk. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. Fuel contracts may
be exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts and through
contractual protection with counterparties, where applicable. In addition, the adoption and implementation of fuel adjustment mechanisms in its rate-regulated subsidiaries has further helped manage this risk, as the regulatory framework for the
Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel costs. 
 Future Employee Benefit Plan Performance and Funding
Risk 
 Certain Emera subsidiaries have both defined benefit and defined contribution employee benefit plans that cover their employees and
retirees. All defined benefit plans are closed to new entrants. The cost of providing these benefit plans varies depending on the plan provisions, interest rates, investment performance and actuarial assumptions concerning the
future. Actuarial assumptions include earnings on plan assets, discount rates (interest rates used to determine funding levels and contributions to the plans) and expectations around future salary growth, inflation and mortality. Two of
the largest drivers of cost are investment performance and interest rates, which are affected by global financial and capital markets. Depending on future interest rates and actual versus expected investment performance, Emera could be required
to make larger contributions in the future to fund these plans, which could affect Emera’s cash flows, financial condition and operations. 
 Labour
Risk 
 Certain Emera employees are subject to collective labour agreements. Approximately 49 per cent of the full-time and term employees within
the Emera labour force are represented by local unions. 
 As at December 31, 2015, approximately seven per cent of the entire labour force is covered by
collective labour agreements that will expire within the next 12 months. Emera seeks to manage this risk through ongoing discussions with local unions. The Company maintains contingency plans in each of its operations to manage and reduce
the effect of any potential labor disruption. 
 Information Technology Risk 

Emera relies on various information technology systems to manage operations. This subjects Emera to inherent costs and risks associated with maintaining,
upgrading, replacing and changing these systems. This includes impairment of its information technology, potential disruption of internal control systems, substantial capital expenditures, demands on management time and other risks of delays,
difficulties in upgrading existing systems, transitioning to new systems or integrating new systems into its current systems. 

  
 84 

 Uninsured Risk 

Emera and its subsidiaries maintain insurance to cover accidental loss suffered to its facilities, and to provide indemnity in the event of liability to third
parties. This is consistent with Emera’s risk management policies. There are certain elements of Emera’s operations which are not insured. These include a significant portion of its electric utilities’ transmission and
distribution assets, as is customary in the industry. The cost of this coverage is not economically viable. In addition, Emera accepts deductibles and self-insured retentions under its various insurance policies. Insurance is subject to
coverage limits as well as time sensitive claims discovery and reporting provisions and there can be no assurance that the types of liabilities or losses that may be incurred by the Company and its subsidiaries will be covered by
insurance. Emera’s regulated utilities would likely apply to their respective regulatory authority to recover any loss or liability through increased customer rates, though there is no assurance the regulatory authority would approve such
application in whole or in part.
 The occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by Emera and
its subsidiaries or claims that fall within a significant self-insured retention could have a material adverse effect on Emera’s results of operations, cash flows and financial position, if regulatory recovery is not available. A limited
portion of Emera’s property and casualty insurance is placed with a wholly owned captive insurance company. If a loss is suffered by the captive insurer, it is not able to recover that loss other than through future premiums. 

RISK MANAGEMENT INCLUDING FINANCIAL INSTRUMENTS 

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. 
 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, as well as 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. Collectively, these contracts and financial instruments 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. The Company 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. 

  
 85 

 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 realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased
power, inventory or property, plant and equipment, depending on the nature of the item being economically hedged. Management believes that any gains or losses resulting from settlement of these derivatives be refunded to or collected from
customers in future rates. 
 Derivatives that do not meet any of the above criteria are designated as HFT and are recognized on the balance sheet at fair
value. All gains or losses are recognized in net income of the period unless deferred as a result of regulatory accounting. The Company has not elected to designate any derivatives to be included in the HFT category when another accounting
treatment applies. 
 Hedging Items Recognized on the Balance Sheets 

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

 

									
	 As at millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Derivative instrument assets (current and other assets)
	  	$	19.8	  	  	$	23.0	  
	 Derivative instrument liabilities (current and long-term liabilities)
	  	 	(46.2	) 	  	 	(19.2	) 
		  	  
	  
	 	  	  
	  
	 
	 Net derivative instrument assets (liabilities)
	  	$	(26.4	) 	  	$	3.8	  
		  	  
	  
	 	  	  
	  
	 

 Hedging Impact Recognized in Net Income 

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

 

									
	 For the millions of Canadian dollars
	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 
	 Operating revenues – regulated
	  	$	(9.0	) 	  	$	(3.7	) 
	 Non-regulated fuel for generation and purchased power
	  	 	4.8	  	  	 	0.9	  
	 Income from equity investments
	  	 	(0.6	) 	  	 	(0.5	) 
	 Interest expense, net
	  	 	—  	  	  	 	(0.2	) 
		  	  
	  
	 	  	  
	  
	 
	 Effective net gains (losses)
	  	$	(4.8	) 	  	$	(3.5	) 
		  	  
	  
	 	  	  
	  
	 

 The effective net gains (losses) reflected in the above table would be offset in net income by the hedged item realized in the
period. 
 The Company recognized in net income the following gains (losses) related to the ineffective portion of hedging relationships under the following
categories:
  

									
	 For the millions of Canadian dollars
	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 
	 Non-regulated fuel for generation and purchased power
	  	$	(0.1	) 	  	$	2.7	  
		  	  
	  
	 	  	  
	  
	 
	 Ineffective gains (losses)
	  	$	(0.1	) 	  	$	2.7	  
		  	  
	  
	 	  	  
	  
	 

  
 86 

 Regulatory Items Recognized on the Balance Sheets 

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

 

									
	 As at millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Derivative instrument assets (current and other assets)
	  	$	209.9	  	  	$	97.7	  
	 Regulatory assets (current and other assets)
	  	 	64.3	  	  	 	43.6	  
	 Derivative instrument liabilities (current and long-term liabilities)
	  	 	(64.3	) 	  	 	(40.3	) 
	 Regulatory liabilities (current and long-term liabilities)
	  	 	(209.9	) 	  	 	(97.7	) 
		  	  
	  
	 	  	  
	  
	 
	 Net asset (liability)
	  	$	—  	  	  	$	3.3	  
		  	  
	  
	 	  	  
	  
	 

 Regulatory Impact Recognized in Net Income 

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

 

									
	 For the millions of Canadian dollars
	  	Year ended December 31	 
	  	2015	 	  	2014	 
	 Regulated fuel for generation and purchased power (1)
	  	$	41.2	  	  	$	17.7	  
		  	  
	  
	 	  	  
	  
	 
	 Net gains (losses)
	  	$	41.2	  	  	$	17.7	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	Realized gains (losses) on derivative instruments settled and consumed in the period, hedging relationships that have been terminated or the hedged transaction is no longer probable. Realized gains (losses) recorded in
inventory will be recognized in “Regulated fuel for generation and purchased power” when the hedged item is consumed. 

Held-for-trading Items Recognized on the Balance Sheets 

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

 

									
	 As at millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Derivative instruments assets (current and other assets)
	  	$	95.3	  	  	$	107.8	  
	 Derivative instruments liabilities (current and long-term liabilities)
	  	 	(331.9	) 	  	 	(145.3	) 
		  	  
	  
	 	  	  
	  
	 
	 Net derivative instrument assets (liabilities)
	  	$	(236.6	) 	  	$	(37.5	) 
		  	  
	  
	 	  	  
	  
	 

 Held-for-trading Items Recognized in Net Income 

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

 

									
	 For the millions of Canadian dollars
	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 
	 Non-regulated operating revenues
	  	$	14.4	  	  	$	270.4	  
	 Non-regulated fuel for generation and purchased power
	  	 	(3.1	) 	  	 	(5.2	) 
	 Other income (expenses), net
	  	 	(0.8	) 	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 
	 Net gains (losses)
	  	$	10.5	  	  	$	265.2	  
		  	  
	  
	 	  	  
	  
	 

  
 87 

 Other Derivatives Recognized on the Balance Sheets 

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

 

									
	 As at millions of Canadian dollars
	  	December 31
2015	 	  	December 31
2014	 
	 Derivative instrument assets (current and other assets)
	  	$	92.1	  	  	$	—  	  
	 Derivative instrument liabilities (current and long-term liabilities)
	  	$	(2.9	) 	  	$	—  	  
		  	  
	  
	 	  	  
	  
	 
	 Net derivative instrument assets (liabilities)
	  	$	89.2	  	  	$	—  	  
		  	  
	  
	 	  	  
	  
	 

 Other Derivatives Recognized in Net Income 

The Company recognized in net income the following gains (losses) related to other derivatives:

 

									
	 For the millions of Canadian dollars
	  	Year ended
December 31	 
	 	  	2015	 	  	2014	 
	 Other income (expense)
	  	$	92.1	  	  	$	—  	  
	 Interest expense, net
	  	 	(2.9	) 	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 
	 Total gains (losses)
	  	$	89.2	  	  	$	—  	  
		  	  
	  
	 	  	  
	  
	 

 DISCLOSURE AND INTERNAL CONTROLS 

The Company, under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, has designed as at
December 31, 2015 disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”) as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’
Annual and Interim Filings (“NI 52-109”). 
 The Chief Executive Officer and the Chief Financial Officer have caused to be evaluated under their
supervision, with the assistance of Company employees, the effectiveness of the Company’s DC&P and ICFR, and based on that evaluation, have concluded DC&P and ICFR were effective at December 31, 2015. 

There have been no changes in Emera or its consolidated subsidiaries’ ICFR during the period beginning on January 1, 2015 and ending on December 31,
2015, which have materially affected or are reasonably likely to materially affect ICFR. 
 CRITICAL ACCOUNTING ESTIMATES 

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an
ongoing basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made. Significant areas requiring the use of management estimates relate to rate-regulated assets and
liabilities, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill impairment assessments, income taxes, asset retirement obligations, capitalized overhead and valuation of derivative instruments.
Actual results may differ significantly from these estimates. 

  
 88 

 Rate Regulation 

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

Emera has recorded $699.5 million (2014 - $602.7 million) of regulatory assets and $370.6 million (2014 - $201.9 million) of regulatory liabilities as at
December 31, 2015. 
 Pension and Other Post-Retirement Employee Benefits 

The Company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing these benefits is dependent
upon many factors that result from actual plan experience and assumptions of future experience. 
 The benefit cost and accrued benefit obligation for
employee future benefits included in annual compensation expenses are affected by employee demographics, including age, compensation levels, employment periods, contribution levels and earnings on plan assets. 

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

The pension plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in
interest rates may result in increased or decreased pension costs in future periods.
 Emera’s accounting policy is to amortize the net actuarial gain
or loss, which exceeds 10 per cent of the greater of the projected benefit obligation / accumulated post-retirement benefit obligation (“PBO”) and the market-related value of assets, over active plan members’ average remaining service
period, which is currently nine years. Emera’s use of smoothed asset values further reduces the volatility related to the amortization of actuarial investment experience. As a result, the main cause of volatility in reported pension cost
is the discount rate used to determine the PBO. 
 The discount rate used to determine benefit costs is based on the yield of high quality long-term
corporate bonds in each operating entity’s country. The discount rate is determined with reference to bonds which have the same duration as the PBO as at January 1 of the fiscal year. NSPI rounds its discount rate to the nearest 25 basis
points. Effective January 1, 2014, Bangor Hydro Electric Company and Maine Public Service Company merged to become Emera Maine. The pension plans related to the pre-merger companies have remained separate and are disclosed separately below. For
benefit cost purposes, NSPI’s rate was 4.00 per cent for 2015 (2014 – 5.00 per cent) and Bangor Hydro’s rate was 3.91 per cent for 2015 (2014 – 4.83 per cent), MPS’ rate was 3.77 for 2015 (2014 – 4.59 per cent) and
GBPC’s rate for 2015 was 4.75 per cent (2014 – 5.00 per cent). 
 The expected return on plan assets is based on management’s best estimate
of future returns, considering economic and consensus forecasts. The benefit cost calculations assumed that plan assets would earn a rate of return of 5.75 per cent for 2015 (2014 – 6.25 per cent) for NSPI and 7.50 per cent for 2015 and 2014
for Bangor Hydro and MPS, and 6.00 per cent for both 2015 and 2014 for GBPC. 
 The reported benefit cost for defined benefit and defined contribution plans
in 2015, based on management’s best estimate assumptions, is $73.0 million. While there are numerous assumptions which 

  
 89 

 
are used to determine the benefit cost, the discount rate and asset return assumptions have an impact on the calculations.

The following shows the impact on 2015 benefit cost of a 25 basis point change (0.25 per cent) in the discount rate and asset return assumptions: 

 

																	
	 	  	0.25% Increase	 	  	0.25% Decrease	 
	 millions of dollars
	  	2015	 	  	2014	 	  	2015	 	  	2014	 
	 Discount rate assumption
	  	$	(5.4	) 	  	$	(5.4	) 	  	$	5.4	  	  	$	5.4	  
	 Asset return assumption
	  	$	(2.7	) 	  	$	(2.4	) 	  	$	2.6	  	  	$	2.4	  

 Unbilled Revenue 

Electric revenues are billed on a systematic basis over a one- or two-month period for NSPI and a one-month period for Emera Maine and GBPC. At the end of each
month, the Company must make an estimate of energy delivered to customers since the date their meter was last read and of related revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including current
month’s generation, estimated customer usage by class, weather, line losses and applicable customer rates. EUS Bahamas and Emera Utility Services include an estimate of work completed under contracts but not yet billed at the end of each month.
Based on the extent of the estimates included in the determination of unbilled revenue, actual results may differ from the estimate. As at December 31, 2015, unbilled revenues amount to $144.2 million (2014 – $141.1 million) on a base of annual
operating revenues of approximately $2,789.3 million (2014 – $2,938.6 million). 
 Property, Plant and Equipment 

Property, plant and equipment represents 51.5 per cent of total assets recognized on the Company’s balance sheet. Included in “Property, plant and
equipment” are the generation, transmission and distribution and other assets of the Company. Due to the magnitude of the Company’s property, plant and equipment, changes in estimated depreciation rates can have a material impact on
depreciation expense. 
 Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in
each category. The service lives of regulated property, plant and equipment are determined based on formal depreciation studies and require the appropriate regulatory approval. NSPI’s last depreciation study was completed in 2010 and approved
by the UARB on May 11, 2011. BLPC’s last depreciation study was completed in 2013 and has been submitted for regulatory review. A response time has not been issued. GBPC’s last depreciation study was completed in 2015 and was approved on
January 25, 2016. Emera Maine’s last depreciation study was completed in 2013 and was applied to transmission rates effective January 1, 2014 and distribution rates effective July 1, 2014. 

Depreciation expense was $295.9 million for the year ended December 31, 2015 (2014 – $277.5 million). 

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

Goodwill arose on the acquisitions of GBPC and Emera Maine. At December 31, 2015, this goodwill had a total carrying amount of $264.1 million (December 31,
2014 – $221.5 million) 

  
 90 

 Emera’s reporting units will first assess qualitative factors to determine whether it is more likely than
not that the assets’ fair value is less than the carrying amount, in which case it is necessary to perform the quantitative goodwill impairment test. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the
carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. 

Determining the fair market value of goodwill is susceptible to changes from period to period as assumptions about future cash flows are required.

Emera reviewed the carrying amount of goodwill and no material goodwill impairments existed for the year ended December 31, 2015 or 2014. 

Income Taxes 
 Income taxes are determined based on the
expected tax treatment of transactions recorded in the consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of jurisdictions, the likelihood that deferred tax assets will be recovered from
future taxable income is assessed and assumptions about the expected timing of the reversal of deferred tax assets and liabilities are made. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits
and appeals requires judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the “more likely than not” threshold may be recognized or continue to be
recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of the
Company’s tax returns. 
 Asset Retirement Obligations 

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

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

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.

  
 91 

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

 

																									
	 Asset
	  	Credit-adjusted
risk-free rate	 	 	Estimated undiscounted
future obligation
(millions of dollars)	 	  	Expected
settlement date
(number of years)	 
	 	  	2015	 	 	2014	 	 	2015	 	  	2014	 	  	2015	 	  	2014	 
	 Thermal
	  	 	5.1 – 5.3	% 	 	 	5.2 – 5.3	% 	 	$	142.8	  	  	$	142.8	  	  	 	17 – 28	  	  	 	18 – 29	  
	 Hydro
	  	 	5.1 – 5.3	% 	 	 	5.1 – 5.3	% 	 	 	127.6	  	  	 	127.6	  	  	 	16 – 46	  	  	 	17 – 47	  
	 Wind
	  	 	5.1 – 5.2	% 	 	 	5.1 – 5.2	% 	 	 	27.4	  	  	 	27.4	  	  	 	13 – 20	  	  	 	14 – 21	  
	 Combustion turbines
	  	 	5.1 – 5.3	% 	 	 	5.1 – 5.3	% 	 	 	8.3	  	  	 	8.3	  	  	 	1 – 30	  	  	 	2 – 31	  
	 Transmission & distribution
	  	 	4.3 – 5.8	% 	 	 	4.1 – 5.8	% 	 	 	21.5	  	  	 	16.5	  	  	 	1 – 10	  	  	 	1 – 11	  
	 Pipeline
	  	 	3.80	% 	 	 	3.80	% 	 	 	18.1	  	  	 	18.1	  	  	 	19.5	  	  	 	19.5	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  				 				 	$	345.7	  	  	$	340.7	  	  				  			
		  				 				 	  
	  
	 	  	  
	  
	 	  				  			

 As at December 31, 2015, the AROs recorded on the balance sheet were $114.7 million (2014 – $106.2 million). The Company
estimates the undiscounted amount of cash flow required to settle the obligations is approximately $320.2 million, which will be incurred between 2016 and 2061. The majority of these costs will be incurred between 2032 and 2047. 

Capitalized Overhead 
 As required by their respective
regulators, NSPI, Emera Maine, GBPC, BLPC and Domlec capitalize overhead costs that are not directly attributable to specific utility assets, but to the overall capital expenditure program. The methodology for the calculation of capitalized overhead
is approved by their respective regulator. For the year ended December 31, 2015, $71.6 million (2014 – $68.4 million) of overhead costs were capitalized to capital assets. Any change in the methodology for the calculation and allocation of
overhead costs could have a material impact on the amounts recognized as expenses versus assets. 
 Financial Instruments 

Emera is required to determine the fair value of all derivatives except those which qualify for the normal purchase, normal sale exception. Fair value is
the price that would be received for the sale of 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.

 Level Determinations and Classifications 
 Emera uses
the Level 1, 2 and 3 classifications in the fair value hierarchy. The fair value measurement of a financial instrument is included in only one of the three levels and is based on the lowest level input significant to the derivation of the fair
value. Fair values are determined, directly or indirectly, using inputs that are unobservable for the asset or liability. In limited circumstances, Emera may enter into commodity transactions involving non-standard features where market
observable data is not available, or contracts with terms that extend beyond five years. 

  
 92 

 CHANGES IN ACCOUNTING POLICIES AND PRACTICES 

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 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). 

  
 93 

 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. 

  
 94 

 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. 

  
 95 

 SUMMARY OF QUARTERLY RESULTS 
  

																																	
	 For the quarter ended millions of dollars (except per share amounts)
	  	Q4
2015	 	  	Q3
2015	 	  	Q2
2015	 	  	Q1
2015	 	  	Q4
2014	 	  	Q3
2014	 	  	Q2
2014	 	  	Q1
2014	 
	 Operating revenues
	  	$	731.6	  	  	$	642.3	  	  	$	526.9	  	  	$	888.5	  	  	$	782.7	  	  	$	539.0	  	  	$	566.6	  	  	$	1,050.3	  
	 Net income attributable to common shareholders
	  	 	192.1	  	  	 	35.0	  	  	 	10.0	  	  	 	160.1	  	  	 	151.2	  	  	 	28.2	  	  	 	24.5	  	  	 	202.8	  
	 Adjusted net income attributable to common shareholders
	  	 	87.1	  	  	 	23.3	  	  	 	48.0	  	  	 	171.6	  	  	 	78.5	  	  	 	49.9	  	  	 	44.2	  	  	 	146.6	  
	 Earnings per common share – basic
	  	 	1.31	  	  	 	0.24	  	  	 	0.07	  	  	 	1.10	  	  	 	1.05	  	  	 	0.20	  	  	 	0.17	  	  	 	1.43	  
	 Earnings per common share – diluted
	  	 	1.30	  	  	 	0.24	  	  	 	0.07	  	  	 	1.09	  	  	 	1.02	  	  	 	0.20	  	  	 	0.17	  	  	 	1.40	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Adjusted earnings per common share – basic
	  	 	0.59	  	  	 	0.16	  	  	 	0.33	  	  	 	1.18	  	  	 	0.54	  	  	 	0.35	  	  	 	0.31	  	  	 	1.03	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Quarterly operating revenues and net income attributable to common shareholders are affected by seasonality. The first quarter
is generally the strongest because a significant portion of the Company’s operations are located in northeast North America, where winter is the peak electricity season. As the energy industry is seasonal in nature for companies like Emera,
seasonal and other weather patterns, as well as the number and severity of storms, can affect the demand for energy and the cost of service. Quarterly results could be affected by items outlined in the Significant Items section and
mark-to-market adjustments. 

  
 96 

 OPERATING STATISTICS 

FIVE-YEAR SUMMARY 
  

																					
	 Year ended December 31
	  	2015	 	  	2014	 	  	2013	 	  	2012	 	  	2011	 
	 Electric energy sales (GWh)
	  				  				  				  				  			
	 Residential
	  	 	5,740.5	  	  	 	5,615.7	  	  	 	5,623.6	  	  	 	5,372.2	  	  	 	5,458.9	  
	 Commercial
	  	 	11,153.9	  	  	 	10,989.6	  	  	 	7,156.9	  	  	 	6,174.7	  	  	 	6,562.3	  
	 Industrial
	  	 	2,984.1	  	  	 	2,970.8	  	  	 	3,067.4	  	  	 	2,678.7	  	  	 	3,988.5	  
	 Other
	  	 	373.6	  	  	 	385.3	  	  	 	357.9	  	  	 	371.2	  	  	 	347.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total electric energy sales
	  	 	20,252.1	  	  	 	19,961.4	  	  	 	16,205.8	  	  	 	14,596.8	  	  	 	16,356.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Sources of energy (GWh)
	  				  				  				  				  			
	 Thermal – coal
	  	 	6,364.0	  	  	 	6,609.0	  	  	 	7,098.0	  	  	 	6,223.0	  	  	 	6,848.0	  
	 – oil
	  	 	1,668.4	  	  	 	1,584.5	  	  	 	1,417.5	  	  	 	1,355.1	  	  	 	1,070.8	  
	 – natural gas
	  	 	7,782.3	  	  	 	7,691.7	  	  	 	3,685.9	  	  	 	3,726.0	  	  	 	4,304.7	  
	 Biomass
	  	 	272.3	  	  	 	319.8	  	  	 	167.0	  	  	 	—  	  	  	 	—  	  
	 Hydro
	  	 	1,040.4	  	  	 	1,129.6	  	  	 	1,002.6	  	  	 	828.0	  	  	 	1,414.5	  
	 Wind
	  	 	259.0	  	  	 	258.0	  	  	 	261.0	  	  	 	256.0	  	  	 	247.0	  
	 Purchases
	  	 	4,142.3	  	  	 	3,693.1	  	  	 	3,528.0	  	  	 	3,210.2	  	  	 	3,518.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total generation and purchases
	  	 	21,528.7	  	  	 	21,285.7	  	  	 	17,160.0	  	  	 	15,598.3	  	  	 	17,403.3	  
	 Losses and internal use
	  	 	1,276.6	  	  	 	1,324.3	  	  	 	954.2	  	  	 	1,001.5	  	  	 	1,046.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total electric energy sold
	  	 	20,252.1	  	  	 	19,961.4	  	  	 	16,205.8	  	  	 	14,596.8	  	  	 	16,356.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Electric customers
	  				  				  				  				  			
	 Residential
	  	 	747,629	  	  	 	742,110	  	  	 	738,444	  	  	 	702,738	  	  	 	696,970	  
	 Commercial
	  	 	85,480	  	  	 	82,076	  	  	 	83,612	  	  	 	79,613	  	  	 	79,817	  
	 Industrial
	  	 	2,628	  	  	 	2,637	  	  	 	2,711	  	  	 	2,521	  	  	 	2,517	  
	 Other
	  	 	9,432	  	  	 	10,421	  	  	 	10,510	  	  	 	20,230	  	  	 	10,446	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total electric customers
	  	 	845,169	  	  	 	837,244	  	  	 	835,277	  	  	 	805,102	  	  	 	789,750	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Capacity
	  				  				  				  				  			
	 Emera-owned generating nameplate capacity (MW)
	  				  				  				  				  			
	 Coal fired
	  	 	1,243.0	  	  	 	1,243.0	  	  	 	1,243.0	  	  	 	1,243.0	  	  	 	1,243.0	  
	 Dual fired
	  	 	350.0	  	  	 	350.0	  	  	 	350.0	  	  	 	350.0	  	  	 	350.0	  
	 Gas turbines
	  	 	1,819.0	  	  	 	1,799.0	  	  	 	1,796.5	  	  	 	746.5	  	  	 	666.0	  
	 Biomass
	  	 	90.0	  	  	 	90.0	  	  	 	90.0	  	  	 	—  	  	  	 	—  	  
	 Hydroelectric
	  	 	402.0	  	  	 	401.6	  	  	 	401.6	  	  	 	395.0	  	  	 	395.0	  
	 Wind turbines
	  	 	82.0	  	  	 	82.0	  	  	 	82.0	  	  	 	82.0	  	  	 	82.0	  
	 Diesel
	  	 	241.2	  	  	 	241.2	  	  	 	244.6	  	  	 	231.5	  	  	 	173.0	  
	 Steam
	  	 	40.0	  	  	 	40.0	  	  	 	40.0	  	  	 	40.0	  	  	 	47.0	  
	 Independent power producers
	  	 	593.0	  	  	 	370.0	  	  	 	308.0	  	  	 	300.0	  	  	 	264.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	 	4,860.2	  	  	 	4,616.8	  	  	 	4,555.7	  	  	 	3,388.0	  	  	 	3,220.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total number of employees
	  	 	3,454	  	  	 	3,530	  	  	 	3,558	  	  	 	3,374	  	  	 	3,458	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 km of transmission lines
	  	 	7,504	  	  	 	7,215	  	  	 	7,224	  	  	 	6,803	  	  	 	6,800	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 km of distribution lines
	  	 	46,162	  	  	 	44,811	  	  	 	44,771	  	  	 	39,590	  	  	 	41,600	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

																																					
	 REGULATED ELECTRIC
	  	 	 	  	Employee	 	  	Peak
demand	 	  	Energy
sales	 	  	Total
assets	 	  	 Rate

base
	 	  	Income	 	  	Allowable
ROE	 	 	Allowable
ROE	 
	  	Customers	 	  	count	 	  	(MW)	 	  	(Gwh)	 	  	(billions)	 	  	(billions)	 	  	(millions)	 	  	2015	 	 	2014	 
	 NSPI
	  	 	506,452	  	  	 	1,727	  	  	 	1,825	  	  	 	10,412	  	  	 	4.6	  	  	 	3.8	  	  	$	129.9	  	  	 	8.75-9.25	% 	 	 	8.75-9.25	% 
	 Emera Maine
	  	 	157,891	  	  	 	412	  	  	 	388	  	  	 	2,020	  	  	 	1.6	  	  	 	0.9	  	  	 	45.1	  	  	 	10.3	% 	 	 	10.6	% 
	 BLPC (1)
	  	 	126,190	  	  	 	330	  	  	 	149	  	  	 	915	  	  	 	0.5	  	  	 	0.4	  	  	 	29.7	  	  	 	10.0	% 	 	 	10.0	% 
	 GBPC(1)
	  	 	19,104	  	  	 	205	  	  	 	61	  	  	 	335	  	  	 	0.4	  	  	 	0.3	  	  	 	17.8	  	  	 	10.0	% 	 	 	10.0	% 
	 Domlec (1)
	  	 	35,525	  	  	 	238	  	  	 	17	  	  	 	95	  	  	 	0.1	  	  	 	0.1	  	  	 	7.4	  	  	 	15.0	% 	 	 	15.0	% 

  

	(1)	These subsidiaries use return on rate base, as opposed to ROE. 

  
 97 

 FIVE-YEAR FINANCIAL SUMMARY 
  

																					
	 For the year ended December 31
	  	2015	 	  	2014	 	  	2013	 	 	2012	 	 	2011	 
	millions of Canadian dollars	  	 	 	  	 	 	  	 	 	 	 	 	 	 	 
						
	 Consolidated Statements of Income
	  				  				  				 				 			
	 Operating Revenues
	  	$	2,789.3	  	  	$	2,938.6	  	  	$	2,230.2	  	 	$	2,058.6	  	 	$	2,064.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Operating expenses
	  				  				  				 				 			
	 Regulated fuel for generation and purchased power
	  	 	814.5	  	  	 	844.3	  	  	 	868.4	  	 	 	810.5	  	 	 	866.4	  
	 Regulated fuel and fixed cost adjustments
	  	 	41.6	  	  	 	46.6	  	  	 	(40.8	) 	 	 	10.0	  	 	 	(8.5	) 
	 Non-regulated fuel for generation and purchased power
	  	 	335.7	  	  	 	401.1	  	  	 	89.8	  	 	 	44.5	  	 	 	73.9	  
	 Non-regulated direct costs
	  	 	19.5	  	  	 	31.3	  	  	 	52.4	  	 	 	56.6	  	 	 	60.9	  
	 Operating, maintenance and general
	  	 	666.8	  	  	 	560.8	  	  	 	505.0	  	 	 	462.9	  	 	 	453.3	  
	 Provincial, state and municipal taxes
	  	 	63.6	  	  	 	58.2	  	  	 	50.5	  	 	 	49.4	  	 	 	49.2	  
	 Depreciation and amortization
	  	 	339.9	  	  	 	329.0	  	  	 	297.8	  	 	 	278.2	  	 	 	251.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income from operations
	  	 	507.7	  	  	 	667.3	  	  	 	407.1	  	 	 	346.5	  	 	 	317.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income from equity investments and Other income (expenses), net
	  	 	249.7	  	  	 	78.9	  	  	 	63.7	  	 	 	53.8	  	 	 	77.4	  
	 Interest expense, net
	  	 	212.6	  	  	 	179.8	  	  	 	172.2	  	 	 	167.1	  	 	 	159.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Income before provision for income taxes
	  	 	544.8	  	  	 	566.4	  	  	 	298.6	  	 	 	233.2	  	 	 	235.5	  
	 Income tax expense (recovery)
	  	 	92.4	  	  	 	113.6	  	  	 	43.3	  	 	 	(12.4	) 	 	 	(23.9	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net income
	  	 	452.4	  	  	 	452.8	  	  	 	255.3	  	 	 	245.6	  	 	 	259.4	  
	 Non-controlling interest in subsidiaries
	  	 	24.9	  	  	 	19.9	  	  	 	18.5	  	 	 	13.7	  	 	 	11.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net income of Emera Incorporated
	  	 	427.5	  	  	 	432.9	  	  	 	236.8	  	 	 	231.9	  	 	 	247.7	  
	 Preferred stock dividends
	  	 	30.3	  	  	 	26.2	  	  	 	19.3	  	 	 	11.1	  	 	 	6.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net income attributable to common shareholders
	  	 	397.2	  	  	 	406.7	  	  	 	217.5	  	 	 	220.8	  	 	 	241.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 After-tax mark-to-market gain (loss)
	  	 	67.2	  	  	 	87.5	  	  	 	(41.9	) 	 	 	(9.7	) 	 	 	(3.0	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Adjusted net income attributable to common shareholders
	  	 	330.0	  	  	 	319.2	  	  	 	259.4	  	 	 	230.5	  	 	 	244.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Adjusted EBITDA
	  	 	1,031.2	  	  	 	946.5	  	  	 	829.5	  	 	 	693.2	  	 	 	649.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
						
	 Balance Sheets Information
	  				  				  				 				 			
	 Current assets (1)
	  	 	2,595.6	  	  	 	1,410.8	  	  	 	1,152.3	  	 	 	940.2	  	 	 	993.3	  
	 Property, plant and equipment, net of accumulated depreciation
	  	 	6,188.0	  	  	 	5,610.2	  	  	 	5,327.7	  	 	 	4,491.1	  	 	 	4,294.4	  
	 Other assets
	  				  				  				 				 			
	 Income taxes receivable
	  	 	48.7	  	  	 	28.9	  	  	 	27.8	  	 	 	—  	  	 	 	—  	  
	 Deferred income taxes (1)
	  	 	32.2	  	  	 	57.8	  	  	 	67.8	  	 	 	28.9	  	 	 	33.1	  
	 Derivative instruments
	  	 	167.6	  	  	 	92.0	  	  	 	61.6	  	 	 	23.4	  	 	 	39.6	  
	 Pension and post-retirement asset
	  	 	8.7	  	  	 	5.9	  	  	 	0.5	  	 	 	0.1	  	 	 	0.3	  
	 Regulatory assets
	  	 	605.3	  	  	 	487.7	  	  	 	557.8	  	 	 	376.4	  	 	 	312.2	  
	 Net investment in direct financing lease
	  	 	480.1	  	  	 	484.5	  	  	 	487.2	  	 	 	490.0	  	 	 	492.0	  
	 Investments subject to significant influence (2)
	  	 	1,145.3	  	  	 	1,027.6	  	  	 	739.2	  	 	 	536.6	  	 	 	219.8	  
	 Available-for-sale investments
	  	 	116.0	  	  	 	84.4	  	  	 	74.2	  	 	 	141.8	  	 	 	54.6	  
	 Goodwill
	  	 	264.1	  	  	 	221.5	  	  	 	206.5	  	 	 	193.5	  	 	 	197.7	  
	 Intangibles, net of accumulated amortization
	  	 	191.9	  	  	 	134.3	  	  	 	118.4	  	 	 	114.2	  	 	 	100.7	  
	 Due from related parties
	  	 	2.5	  	  	 	2.5	  	  	 	2.5	  	 	 	151.7	  	 	 	2.8	  
	 Other long-term assets
	  	 	166.3	  	  	 	205.3	  	  	 	53.3	  	 	 	48.5	  	 	 	183.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total assets
	  	 	12,012.3	  	  	 	9,853.4	  	  	 	8,876.8	  	 	 	7,536.4	  	 	 	6,923.6	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  
 98 

 FIVE-YEAR FINANCIAL SUMMARY (continued) 

 

																					
	 For the year ended December 31
	  	2015	 	 	2014	 	 	2013	 	 	2012	 	 	2011	 
	millions of Canadian dollars	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 
						
	 Current liabilities
	  	 	2,081.3	  	 	 	1,122.9	  	 	 	1,529.9	  	 	 	951.9	  	 	 	801.7	  
	 Long-term liabilities
	  				 				 				 				 			
	 Long-term debt
	  	 	3,750.8	  	 	 	3,660.3	  	 	 	3,363.7	  	 	 	3,257.4	  	 	 	3,273.5	  
	 Deferred income taxes (1)
	  	 	761.7	  	 	 	613.3	  	 	 	547.7	  	 	 	312.1	  	 	 	228.6	  
	 Derivative instruments
	  	 	96.1	  	 	 	77.4	  	 	 	27.0	  	 	 	22.4	  	 	 	38.7	  
	 Regulatory liabilities
	  	 	271.7	  	 	 	158.9	  	 	 	119.5	  	 	 	92.5	  	 	 	107.1	  
	 Asset retirement obligations
	  	 	114.7	  	 	 	106.2	  	 	 	98.6	  	 	 	95.0	  	 	 	99.9	  
	 Pension and post-retirement liabilities
	  	 	303.4	  	 	 	360.7	  	 	 	256.4	  	 	 	506.4	  	 	 	530.8	  
	 Other long-term liabilities (2)
	  	 	298.5	  	 	 	48.3	  	 	 	36.8	  	 	 	20.9	  	 	 	19.6	  
	 Equity
	  				 				 				 				 			
	 Common stock
	  	 	2,157.5	  	 	 	2,016.4	  	 	 	1,703.0	  	 	 	1,643.7	  	 	 	1,385.0	  
	 Cumulative preferred stock
	  	 	709.5	  	 	 	709.5	  	 	 	514.0	  	 	 	391.6	  	 	 	146.7	  
	 Contributed surplus
	  	 	28.8	  	 	 	8.8	  	 	 	4.1	  	 	 	2.8	  	 	 	3.3	  
	 Accumulated other comprehensive income (loss)
	  	 	136.5	  	 	 	(347.6	) 	 	 	(430.1	) 	 	 	(775.8	) 	 	 	(671.7	) 
	 Retained earnings
	  	 	1,167.8	  	 	 	1,011.7	  	 	 	817.2	  	 	 	788.1	  	 	 	735.9	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total Emera Incorporated equity
	  	 	4,200.1	  	 	 	3,398.8	  	 	 	2,608.2	  	 	 	2,050.4	  	 	 	1,599.2	  
	 Non-controlling interest in subsidiaries
	  	 	134.0	  	 	 	306.6	  	 	 	289.0	  	 	 	227.4	  	 	 	224.5	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total equity
	  	 	4,334.1	  	 	 	3,705.4	  	 	 	2,897.2	  	 	 	2,277.8	  	 	 	1,823.7	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total liabilities and equity
	  	 	12,012.3	  	 	 	9,853.4	  	 	 	8,876.8	  	 	 	7,536.4	  	 	 	6,923.6	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
						
	 Statements of Cash Flow Information
	  				 				 				 				 			
	 Cash provided by operating activities
	  	 	674.2	  	 	 	762.5	  	 	 	564.2	  	 	 	397.6	  	 	 	399.5	  
	 Cash used in investing activities
	  	 	(123.7	) 	 	 	(710.9	) 	 	 	(921.6	) 	 	 	(919.4	) 	 	 	(660.8	) 
	 Cash provided by (used in) financing activities
	  	 	221.1	  	 	 	58.2	  	 	 	362.1	  	 	 	534.2	  	 	 	331.4	  
						
	 Financial ratios ($ per share)
	  				 				 				 				 			
	 Earnings per share
	  	$	2.72	  	 	$	2.84	  	 	$	1.64	  	 	$	1.77	  	 	$	1.99	  
	 Adjusted earnings per share
	  	$	2.26	  	 	$	2.23	  	 	$	1.96	  	 	$	1.85	  	 	$	2.02	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	(1)	Emera early adopted ASU 2015-17 Income Taxes – Balance Sheet Classification of Deferred Taxes, which simplifies the presentation of deferred income taxes effective Q4 2015. The December 31, 2014 and 2015
periods have been restated 

	(2)	As at December 31, 2015 and 2014, the negative investment balance for Bear Swamp has been reclassified to “Other long-term liabilities” on the Consolidated Balance Sheets. The 2014 and 2015 carrying values
have been restated. 

  
 99EX-4.4

 Exhibit 4.4 

EMERA INCORPORATED 
 Unaudited Condensed
Consolidated 
 Interim Financial Statements 

March 31, 2016 and 2015 

  
 1 

 Emera Incorporated 
 Condensed
Consolidated Statements of Income (Unaudited) 
  

									
	 For the

millions of Canadian dollars (except per share amounts)
	 	Three months ended March 31	 
	 	2016	 	 	2015	 
	 Operating revenues
	 				 			
	 Regulated
	 	$	586.6	  	 	$	631.2	  
	 Non-regulated
	 	 	290.4	  	 	 	257.3	  
		 	  
	  
	 	 	  
	  
	 
	 Total operating revenues
	 	 	877.0	  	 	 	888.5	  
		 	  
	  
	 	 	  
	  
	 
	 Operating expenses
	 				 			
	 Regulated fuel for generation and purchased power
	 	 	197.7	  	 	 	255.0	  
	 Regulated fuel adjustment mechanism and fixed cost deferrals (note 5)
	 	 	17.6	  	 	 	(7.2	) 
	 Non-regulated fuel for generation and purchased power
	 	 	109.8	  	 	 	150.4	  
	 Non-regulated direct costs
	 	 	2.3	  	 	 	4.4	  
	 Operating, maintenance and general
	 	 	175.7	  	 	 	155.1	  
	 Provincial, state and municipal taxes
	 	 	16.4	  	 	 	15.9	  
	 Depreciation and amortization
	 	 	87.5	  	 	 	82.8	  
		 	  
	  
	 	 	  
	  
	 
	 Total operating expenses
	 	 	607.0	  	 	 	656.4	  
		 	  
	  
	 	 	  
	  
	 
	 Income from operations
	 	 	270.0	  	 	 	232.1	  
			
	 Income from equity investments (note 6)
	 	 	26.0	  	 	 	25.9	  
	 Other income (expenses), net (note 7)
	 	 	(139.2	) 	 	 	21.9	  
	 Interest expense, net (note 8)
	 	 	75.2	  	 	 	44.4	  
		 	  
	  
	 	 	  
	  
	 
	 Income before provision for income taxes
	 	 	81.6	  	 	 	235.5	  
			
	 Income tax expense (recovery) (note 9)
	 	 	26.8	  	 	 	61.4	  
		 	  
	  
	 	 	  
	  
	 
	 Net income
	 	 	54.8	  	 	 	174.1	  
			
	 Non-controlling interest in subsidiaries
	 	 	3.5	  	 	 	6.3	  
		 	  
	  
	 	 	  
	  
	 
	 Net income of Emera Incorporated
	 	 	51.3	  	 	 	167.8	  
			
	 Preferred stock dividends
	 	 	7.0	  	 	 	7.7	  
		 	  
	  
	 	 	  
	  
	 
	 Net income attributable to common shareholders
	 	$	44.3	  	 	$	160.1	  
		 	  
	  
	 	 	  
	  
	 
			
	 Weighted average shares of common stock outstanding (in millions)
	 				 			
	 Basic
	 	 	148.7	  	 	 	144.9	  
		 	  
	  
	 	 	  
	  
	 
	 Diluted
	 	 	149.3	  	 	 	148.8	  
		 	  
	  
	 	 	  
	  
	 
			
	 Earnings per common share (note 10)
	 				 			
	 Basic
	 	$	0.30	  	 	$	1.10	  
		 	  
	  
	 	 	  
	  
	 
	 Diluted
	 	$	0.30	  	 	$	1.09	  
		 	  
	  
	 	 	  
	  
	 
			
	 Dividends per common share declared
	 	$	0.4750	  	 	$	0.3875	  
		 	  
	  
	 	 	  
	  
	 

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

  
 2 

 Emera Incorporated 
 Condensed
Consolidated Statements of Comprehensive Income (Unaudited) 
  

									
	 For the

millions of Canadian dollars
	 	Three months ended March 31	 
	 	2016	 	 	2015	 
	 Net income
	 	$	54.8	  	 	$	174.1	  
		 	  
	  
	 	 	  
	  
	 
	 Other comprehensive income (loss), net of tax
	 				 			
	 Foreign currency translation adjustment (1)
	 	 	(161.5	) 	 	 	189.4	  
	 Cash flow hedges
	 				 			
	 Net derivative gains (losses) (2)
	 	 	14.1	  	 	 	(15.9	) 
	 Less: reclassification adjustment for losses (gains) included in income (3)
	 	 	0.9	  	 	 	(1.1	) 
	 Net effects of cash flow hedges
	 	 	15.0	  	 	 	(17.0	) 
	 Unrealized gains on available-for-sale investment
	 				 			
	 Unrealized gain (loss) arising during the period
	 	 	0.4	  	 	 	0.4	  
	 Net unrealized holding gains (losses)
	 	 	0.4	  	 	 	0.4	  
	 Net change in unrecognized pension and post-retirement benefit obligation (4)
	 	 	8.6	  	 	 	10.6	  
	 Other comprehensive income (loss) (5)
	 	 	(137.5	) 	 	 	183.4	  
		 	  
	  
	 	 	  
	  
	 
	 Comprehensive income (loss)
	 	 	(82.7	) 	 	 	357.5	  
		 	  
	  
	 	 	  
	  
	 
	 Comprehensive income (loss) attributable to non-controlling interest
	 	 	(3.3	) 	 	 	19.5	  
		 	  
	  
	 	 	  
	  
	 
	 Comprehensive Income of Emera Incorporated
	 	$	(79.4	) 	 	$	338.0	  
		 	  
	  
	 	 	  
	  
	 

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

 

	1)	Net of tax expense of $1.8 million (2015 – $0.1 million tax expense) for the three months ended March 31, 2016. 

	2)	Net of tax expense of $0.1 million (2015 – $0.2 million tax expense) for the three months ended March 31, 2016. 

	3)	Net of tax recovery of $1.6 million (2015 – $2.2 million tax recovery) for the three months ended March 31, 2016. 

	4)	Net of tax expense of nil (2015 – $0.6 million tax expense) for the three months ended March 31, 2016. 

	5)	Net of tax expense of $0.3 million (2015 – $1.3 million tax recovery) for the three months ended March 31, 2016. 

  
 3 

 Emera Incorporated 
 Condensed
Consolidated Balance Sheets (Unaudited) 
  

									
	As at	 	March 31	 	 	December 31	 
	 millions of Canadian dollars
	 	2016	 	 	2015	 
	 Assets
	 				 			
	 Current assets
	 				 			
	 Cash and cash equivalents
	 	$	999.5	  	 	$	1,073.4	  
	 Restricted cash
	 	 	22.2	  	 	 	19.3	  
	 Receivables, net (note 12)
	 	 	610.3	  	 	 	577.4	  
	 Income taxes receivable
	 	 	15.8	  	 	 	12.1	  
	 Inventory (note 13)
	 	 	260.8	  	 	 	314.3	  
	 Derivative instruments (notes 14 and 15)
	 	 	92.4	  	 	 	249.5	  
	 Regulatory assets (notes 5 and 16)
	 	 	78.2	  	 	 	94.2	  
	 Prepaid expenses
	 	 	40.4	  	 	 	18.3	  
	 Due from related parties (note 17)
	 	 	1.5	  	 	 	2.3	  
	 Other current assets (note 18)
	 	 	168.3	  	 	 	234.8	  
		 	  
	  
	 	 	  
	  
	 
	 Total current assets
	 	 	2,289.4	  	 	 	2,595.6	  
		 	  
	  
	 	 	  
	  
	 
			
	 Property, plant and equipment, net of accumulated depreciation of $3,723.0 and $3,732.4, respectively

	 	 	6,014.9	  	 	 	6,188.0	  
		 	  
	  
	 	 	  
	  
	 
			
	 Other assets
	 				 			
	 Income taxes receivable
	 	 	48.3	  	 	 	48.7	  
	 Deferred income taxes
	 	 	47.0	  	 	 	32.2	  
	 Derivative instruments (notes 14 and 15)
	 	 	85.4	  	 	 	167.6	  
	 Pension and post-retirement asset (note 19)
	 	 	8.6	  	 	 	8.7	  
	 Regulatory assets (notes 5 and 16)
	 	 	619.1	  	 	 	605.3	  
	 Net investment in direct financing lease
	 	 	478.7	  	 	 	480.1	  
	 Investments subject to significant influence (note 6)
	 	 	1,209.7	  	 	 	1,145.3	  
	 Available-for-sale investments (note 20)
	 	 	106.2	  	 	 	116.0	  
	 Goodwill
	 	 	247.6	  	 	 	264.1	  
	 Intangibles, net of accumulated amortization of $93.8 and $92.8, respectively
	 	 	190.9	  	 	 	191.9	  
	 Due from related parties (note 17)
	 	 	2.5	  	 	 	2.5	  
	 Other long-term assets
	 	 	100.3	  	 	 	104.0	  
		 	  
	  
	 	 	  
	  
	 
	 Total other assets
	 	 	3,144.3	  	 	 	3,166.4	  
		 	  
	  
	 	 	  
	  
	 
			
	 Total assets
	 	$	11,448.6	  	 	$	11,950.0	  
		 	  
	  
	 	 	  
	  
	 

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

  
 4 

 Emera Incorporated 
 Condensed
Consolidated Balance Sheets – (Unaudited) Continued 
  

									
	As at	 	March 31	 	 	December 31	 
	 millions of Canadian dollars
	 	2016	 	 	2015	 
	 Liabilities and Equity
	 				 			
	 Current liabilities
	 				 			
	 Short-term debt
	 	$	10.2	  	 	$	15.9	  
	 Current portion of long-term debt
	 	 	272.6	  	 	 	274.0	  
	 Accounts payable
	 	 	371.5	  	 	 	394.2	  
	 Income taxes payable
	 	 	8.6	  	 	 	8.1	  
	 Convertible debentures represented by instalment receipts (note 22)
	 	 	681.8	  	 	 	681.5	  
	 Derivative instruments (notes 14 and 15)
	 	 	147.9	  	 	 	349.2	  
	 Regulatory liabilities (note 16)
	 	 	75.0	  	 	 	98.9	  
	 Pension and post-retirement liabilities (note 19)
	 	 	7.0	  	 	 	7.0	  
	 Due to related party (note 17)
	 	 	2.3	  	 	 	2.1	  
	 Other current liabilities (note 21)
	 	 	182.7	  	 	 	204.3	  
		 	  
	  
	 	 	  
	  
	 
	 Total current liabilities
	 	 	1,759.6	  	 	 	2,035.2	  
		 	  
	  
	 	 	  
	  
	 
			
	 Long-term liabilities
	 				 			
	 Long-term debt
	 	 	3,714.2	  	 	 	3,734.6	  
	 Deferred income taxes
	 	 	793.6	  	 	 	761.7	  
	 Derivative instruments (notes 14 and 15)
	 	 	79.2	  	 	 	96.1	  
	 Regulatory liabilities (note 16)
	 	 	221.2	  	 	 	271.7	  
	 Asset retirement obligations
	 	 	115.6	  	 	 	114.7	  
	 Pension and post-retirement liabilities (note 19)
	 	 	296.0	  	 	 	303.4	  
	 Other long-term liabilities (note 23)
	 	 	272.3	  	 	 	298.5	  
		 	  
	  
	 	 	  
	  
	 
	 Total long-term liabilities
	 	 	5,492.1	  	 	 	5,580.7	  
		 	  
	  
	 	 	  
	  
	 
			
	 Commitments and contingencies (note 24)
	 				 			
			
	 Equity
	 				 			
	 Common stock, no par value, unlimited shares authorized, 148.35 million and 147.21 million shares
issued and outstanding, respectively (note 25)
	 	 	2,199.0	  	 	 	2,157.5	  
	 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
	 	 	709.5	  	 	 	709.5	  
	 Contributed surplus
	 	 	35.3	  	 	 	28.8	  
	 Accumulated other comprehensive income (loss) (note 11)
	 	 	5.8	  	 	 	136.5	  
	 Retained earnings
	 	 	1,142.1	  	 	 	1,167.8	  
		 	  
	  
	 	 	  
	  
	 
	 Total Emera Incorporated equity
	 	 	4,091.7	  	 	 	4,200.1	  
	 Non-controlling interest in subsidiaries (note 26)
	 	 	105.2	  	 	 	134.0	  
		 	  
	  
	 	 	  
	  
	 
	 Total equity
	 	 	4,196.9	  	 	 	4,334.1	  
		 	  
	  
	 	 	  
	  
	 
	 Total liabilities and equity
	 	$	11,448.6	  	 	$	11,950.0	  
		 	  
	  
	 	 	  
	  
	 

 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

  
 5 

 Emera Incorporated 
 Condensed
Consolidated Statements of Cash Flows (Unaudited)  
  

									
	 For the
 millions of Canadian dollars
	 	Three months ended March 31	 
	 	2016	 	 	2015	 
	 Operating activities
	 				 			
	 Net income
	 	$	54.8	  	 	$	174.1	  
	 Adjustments to reconcile net income to net cash provided by operating activities:
	 				 			
	 Depreciation and amortization
	 	 	90.7	  	 	 	85.6	  
	 Income from equity investments, net of dividends
	 	 	(12.6	) 	 	 	(12.8	) 
	 Allowance for equity funds used during construction
	 	 	(0.9	) 	 	 	(0.3	) 
	 Deferred income taxes, net
	 	 	8.8	  	 	 	12.3	  
	 Net change in pension and post-retirement liabilities
	 	 	6.5	  	 	 	6.3	  
	 Regulated fuel adjustment mechanism and fixed cost deferrals
	 	 	17.4	  	 	 	(8.4	) 
	 Net change in fair value of derivative instruments
	 	 	(28.6	) 	 	 	4.7	  
	 Net change in regulatory assets and liabilities
	 	 	(4.6	) 	 	 	2.2	  
	 Net change in capitalized transportation capacity
	 	 	56.3	  	 	 	15.3	  
	 Unrealized foreign exchange loss
	 	 	44.7	  	 	 	—  	  
	 Other operating activities, net
	 	 	(0.1	) 	 	 	(21.5	) 
	 Changes in non-cash working capital:
	 				 			
	 Receivables, net
	 	 	(53.7	) 	 	 	(92.7	) 
	 Income taxes receivable
	 	 	(6.7	) 	 	 	(13.5	) 
	 Inventory
	 	 	47.9	  	 	 	20.5	  
	 Prepaid expenses
	 	 	(23.3	) 	 	 	(28.0	) 
	 Due from related party
	 	 	0.3	  	 	 	(0.9	) 
	 Other current assets
	 	 	0.2	  	 	 	(0.5	) 
	 Accounts payable
	 	 	(2.3	) 	 	 	(6.7	) 
	 Income taxes payable
	 	 	4.1	  	 	 	1.3	  
	 Other current liabilities
	 	 	(18.3	) 	 	 	(17.4	) 
		 	  
	  
	 	 	  
	  
	 
	 Net cash provided by operating activities
	 	 	180.6	  	 	 	119.6	  
		 	  
	  
	 	 	  
	  
	 
	 Investing activities
	 				 			
	 Additions to property, plant and equipment
	 	 	(77.2	) 	 	 	(81.0	) 
	 Net purchase of investments subject to significant influence, inclusive of acquisition costs
	 	 	(53.1	) 	 	 	—  	  
	 Additions to intangible assets
	 	 	(8.3	) 	 	 	(1.5	) 
	 Proceeds on sale of investment subject to significant influence
	 	 	—  	  	 	 	282.3	  
	 Other investing activities
	 	 	(0.7	) 	 	 	(3.9	) 
		 	  
	  
	 	 	  
	  
	 
	 Net cash (used in) provided by investing activities
	 	 	(139.3	) 	 	 	195.9	  
		 	  
	  
	 	 	  
	  
	 
	 Financing activities
	 				 			
	 Change in short-term debt, net
	 	 	(7.2	) 	 	 	(271.9	) 
	 Retirement of long-term debt
	 	 	(4.0	) 	 	 	(6.5	) 
	 Proceeds from long-term debt
	 	 	—  	  	 	 	250.0	  
	 Net borrowings (repayments) under committed credit facilities
	 	 	20.7	  	 	 	(168.4	) 
	 Issuance of common stock, net of issuance costs (note 25)
	 	 	14.6	  	 	 	2.5	  
	 Dividends on common stock
	 	 	(47.0	) 	 	 	(40.1	) 
	 Dividends on preferred stock
	 	 	(7.0	) 	 	 	(7.7	) 
	 Dividends paid by subsidiaries to non-controlling interest
	 	 	(1.8	) 	 	 	(3.9	) 
	 Other financing activities
	 	 	(14.1	) 	 	 	(13.3	) 
		 	  
	  
	 	 	  
	  
	 
	 Net cash used in financing activities
	 	 	(45.8	) 	 	 	(259.3	) 
		 	  
	  
	 	 	  
	  
	 
	 Effect of exchange rate changes on cash and cash equivalents
	 	 	(69.4	) 	 	 	28.0	  
		 	  
	  
	 	 	  
	  
	 
	 Net (decrease) increase in cash and cash equivalents
	 	 	(73.9	) 	 	 	84.2	  
	 Cash and cash equivalents, beginning of period
	 	 	1,073.4	  	 	 	221.1	  
		 	  
	  
	 	 	  
	  
	 
	 Cash and cash equivalents, end of period
	 	$	999.5	  	 	$	305.3	  
		 	  
	  
	 	 	  
	  
	 
	 Cash and cash equivalents consists of:
	 				 			
	 Cash
	 	$	260.2	  	 	$	235.5	  
	 Short-term investments
	 	 	739.3	  	 	 	69.8	  
		 	  
	  
	 	 	  
	  
	 
	 Cash and cash equivalents
	 	$	999.5	  	 	$	305.3	  
		 	  
	  
	 	 	  
	  
	 
			
	 Supplemental disclosure of non-cash activities:
	 				 			
	 Common share dividends reinvested
	 	$	23.0	  	 	$	15.6	  
		 	  
	  
	 	 	  
	  
	 

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

  
 6 

 Emera Incorporated 
 Condensed
Consolidated Statements of Changes in Equity (Unaudited) 
  

																																	
	 	  	 	 	  	 	 	  	 	 	 	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	 
	 For the three months ended March 31, 2016
	   
	  				 				 				 				 				 			
	 Balance, December 31, 2015
	  	$	2,157.5	  	  	$	709.5	  	  	$	28.8	  	 	$	136.5	  	 	$	1,167.8	  	 	$	4,200.1	  	 	$	134.0	  	 	$	4,334.1	  
	 Net income of Emera Incorporated
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	51.3	  	 	 	51.3	  	 	 	3.5	  	 	 	54.8	  
	 Other comprehensive income (loss), net of tax expense of $0.3 million
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	(130.7	) 	 	 	—  	  	 	 	(130.7	) 	 	 	(6.8	) 	 	 	(137.5	) 
	 Dividends declared on preferred stock (Series A: $0.1597/share, Series B: $0.1425/share, Series C:
$0.25625/share, Series E: $0.28125/share and Series F: $0.265625/share)
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(7.0	) 	 	 	(7.0	) 	 	 	—  	  	 	 	(7.0	) 
	 Dividends declared on common stock ($0.4750/share)
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(70.0	) 	 	 	(70.0	) 	 	 	—  	  	 	 	(70.0	) 
	 Common stock issued under purchase plan
	  	 	25.0	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	25.0	  	 	 	—  	  	 	 	25.0	  
	 Senior management stock options exercised
	  	 	13.6	  	  	 	—  	  	  	 	(1.0	) 	 	 	—  	  	 	 	—  	  	 	 	12.6	  	 	 	—  	  	 	 	12.6	  
	 Stock option expense
	  				  	 	—  	  	  	 	0.4	  	 	 	—  	  	 	 	—  	  	 	 	0.4	  	 	 	—  	  	 	 	0.4	  
	 Employee Share Purchase Plan
	  	 	0.2	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	0.2	  	 	 	—  	  	 	 	0.2	  
	 Preferred dividends paid and payable by subsidiaries to non-controlling interest
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(1.8	) 	 	 	(1.8	) 
	 Acquisition of non-controlling interest of ECI
	  	 	2.7	  	  	 	—  	  	  	 	7.1	  	 	 	—  	  	 	 	—  	  	 	 	9.8	  	 	 	(23.7	) 	 	 	(13.9	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, March 31, 2016
	  	$	2,199.0	  	  	$	709.5	  	  	$	35.3	  	 	$	5.8	  	 	$	1,142.1	  	 	$	4,091.7	  	 	$	105.2	  	 	$	4,196.9	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

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

  
 7 

 Emera Incorporated 
 Condensed
Consolidated Statements of Changes in Equity (Unaudited) – 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	 
	 For the three months ended March 31, 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
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	167.8	  	 	 	167.8	  	 	 	6.3	  	 	 	174.1	  
	 Other comprehensive income (loss), net of tax recovery of $1.3 million
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	170.2	  	 	 	—  	  	 	 	170.2	  	 	 	13.2	  	 	 	183.4	  
	 Dividends declared on preferred stock (Series A: $0.275/share, Series C: $0.25625/share, Series E:
$0.28125/share and Series F: $0.265625/share)
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	(7.7	) 	 	 	(7.7	) 	 	 	—  	  	 	 	(7.7	) 
	 Dividends declared on common stock ($0.3875/share)
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	(55.7	) 	 	 	(55.7	) 	 	 	—  	  	 	 	(55.7	) 
	 Dividends paid by subsidiaries to non-controlling interest
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(0.7	) 	 	 	(0.7	) 
	 Common stock issued under purchase plan
	  	 	17.4	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	17.4	  	 	 	—  	  	 	 	17.4	  
	 Senior management stock options exercised
	  	 	0.6	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	0.6	  	 	 	—  	  	 	 	0.6	  
	 Stock option expense
	  	 	—  	  	  	 	—  	  	  	 	0.3	  	  	 	—  	  	 	 	—  	  	 	 	0.3	  	 	 	—  	  	 	 	0.3	  
	 Other stock-based compensation
	  	 	0.2	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	0.2	  	 	 	—  	  	 	 	0.2	  
	 Preferred dividends paid by subsidiaries to non-controlling interest
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(3.5	) 	 	 	(3.5	) 
	 Other
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(0.1	) 	 	 	(0.1	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, March 31, 2015
	  	$	2,034.6	  	  	$	709.5	  	  	$	9.1	  	  	$	(177.4	) 	 	$	1,116.1	  	 	$	3,691.9	  	 	$	321.8	  	 	$	4,013.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

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

  
 8 

 Emera Incorporated 
 Notes to
the Condensed Consolidated Interim Financial Statements 
 As at March 31, 2016 and 2015 

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, gas transmission and utility energy services. 
 Emera’s primary rate-regulated subsidiaries and investments at March 31, 2016 included the
following: 
  

	 	•	 	Nova Scotia Power Inc. (“NSPI”), which is a fully integrated electric utility and the primary electricity supplier in Nova Scotia, serving 507,000 customers; 

 

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

 

	 	•	 	a 100.0 per cent interest (December 31, 2015 – 95.5 per cent) 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 126,000 customers; a 51.9 per cent interest (December 31, 2015 – 49.6 per cent indirect interest) through ECI in Dominica
Electricity Services Ltd. (“Domlec”), an integrated utility on the island of Dominica, serving 36,000 customers; and a 19.1 per cent indirect interest (December 31, 2015 – 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 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”), which expires in 2034; 

  

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

  

	 	•	 	59.0 per cent investment (December 31, 2015 – 55.1 per cent) 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 Energy 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. 

  
 9 

	 	•	 	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; 

 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; 

 

	 	•	 	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; 

  

	 	•	 	a 19.4 per cent (December 31, 2015 – 19.6 per cent) investment in Algonquin Power & Utilities Corp. (“APUC”), which is a public company traded on the Toronto Stock Exchange under the
symbol “AQN”; 

  

	 	•	 	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 (“the Transaction”). 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 includes the assumption of approximately $3.9 billion USD of debt. 

The closing of the acquisition, expected to occur mid-2016, is subject to approval by the New Mexico Public Regulation Commission (“NMPRC”), and the
satisfaction of customary closing conditions. On April 11, 2016, Emera and TECO Energy filed an unopposed Stipulation Agreement reflecting a settlement reached with intervening parties in the acquisition case pending before the NMPRC for
approval of Emera’s proposed acquisition of TECO Energy and the indirect acquisition of the New Mexico Gas Co. The hearing for Emera’s pending acquisition of TECO Energy occurred on May 2, 2016. A decision is expected mid-2016. 

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 nearly 725,000 customers in West Central Florida; Peoples Gas System, a regulated gas distribution utility which serves nearly 365,000 customers across Florida; and New Mexico Gas Co.,
also a regulated gas distribution utility which serves more than 515,000 customers across New Mexico. 

  
 10 

 B. Basis of Presentation 
 These
unaudited condensed consolidated interim financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”). They do not contain all disclosures required by USGAAP for
annual audited financial statements. Accordingly, the financial statements should be read in conjunction with Emera Incorporated’s annual audited financial statements as at and for the year ended December 31, 2015. 

In the opinion of management, these unaudited condensed consolidated interim financial statements include all adjustments that are of a recurring nature and necessary
to fairly state the financial position of Emera Incorporated. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2016. 

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

C. 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. 

D. Seasonal Nature of Operations 
 Interim results are not necessarily
indicative of results for the full year, primarily due to seasonal factors. Electricity sales and related generation vary significantly over the year; the first quarter is typically the strongest period, reflecting colder weather and fewer daylight
hours in the winter season in northeastern North America, where a substantial portion of Emera’s electricity business is located. Certain quarters may also be impacted by the number and severity of storms. 

2. CHANGE IN ACCOUNTING POLICY 
 The new US GAAP accounting policies that
are applicable to, and were adopted by Emera, effective during 2016, are described as follows: 
 Income Statement – Extraordinary and Unusual Items,
Accounting Standard Update (“ASU”) 2015-01 
 In January 2015, the Financial Accounting Standards Board (“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. The Company has adopted this standard in Q1 2016, with no impact on its
consolidated financial statements. 

  
 11 

 Consolidation, ASU 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. Some of the more notable amendments are
(1) the identification of variable interests when fees are paid to a decision maker or service provider, (2) the variable interest entity (“VIE”) characteristics for a limited partnership or similar entity and (3) the
primary beneficiary determination. All legal entities are subject to re-evaluation under the revised consolidation model. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements. 

Interest – Imputation of Interest, 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 on 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. The Company has adopted this standard effective Q1 2016 and December 31, 2015
balances have been retrospectively restated. This change resulted in $62.3 million of deferred financing costs, as at December 31, 2015, previously presented as other assets, being reclassified as a deduction from the carrying amount of the
related long-term debt and convertible debentures represented by instalment receipts on the Consolidated Balance Sheets. 
 In accordance with ASU 2015-15
Interest: Imputation of Interest, the Company continues to present deferred issuance costs related to its revolving credit facilities and related instruments in other long-term assets on its Consolidated Balance Sheets. 

Compensation – Retirement Benefits, ASU 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. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements. 

Intangibles – Goodwill and Other – Internal-Use Software, ASU 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, the customer would 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 would account for the arrangement as a service contract. The guidance does not change GAAP for a
customer’s accounting for service contracts. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial statements. 

Technical Corrections and Improvements, ASU 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. The Company has adopted this
standard in Q1 2016, with no impact on its consolidated financial statements. 
 Inventory – Simplifying the Measurement of Inventory, ASU 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 2015-11 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 adopted this standard in Q1 2016, with no impact on its consolidated
financial statements. 

  
 12 

 Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,
ASU 2016-05 
 In March 2016, the FASB issued ASU 2016-05, Derivatives and Hedging Effect of Derivative Contract Novations on Existing Hedge Accounting
Relationships. The standard clarifies that a change in the counterparty to a derivative contract, in and of itself, does not require the de-designation of a hedging relationship provided that all other hedge accounting criteria continue to be
met. ASU 2016-05 is effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2017 and early adoption is permitted. The Company has adopted this standard in Q1 2016, with no
impact on its consolidated financial statements. 
 Investments – Equity Method and Joint Ventures, ASU 2016-07 

In March 2016, the FASB issued ASU 2016-07, Investments – Equity Method and Joint Ventures, which is part of FASB’s initiative to reduce complexity
in accounting standards. This standard eliminates the requirements of an investor to retroactively account for an investment under the equity method when an investment qualifies for equity method accounting. ASU 2016-07 is effective for annual
reporting periods, including interim reporting within those periods, beginning after December 15, 2016, with early adoption permitted. The Company has adopted this standard in Q1 2016, with no impact on its consolidated financial
statements. 
 3. FUTURE ACCOUNTING PRONOUNCEMENTS 
 Revenue from
Contracts with Customers, ASU 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. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers: Principal versus Agent Considerations. The
amendments are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU 2016-10 Revenue from Contracts with Customers: Identifying
Performance Obligations and Licensing. The guidance will be effective beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or modified retrospective adoption. The Company is continuing
to evaluate the impact of adoption of these standards on its consolidated financial statements. 
 Financial Instruments – Recognition and Measurement of
Financial Assets and Financial Liabilities, ASU 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 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. 

Leases (Topic 842), ASU 2016-02 
 In February 2016, the FASB issued ASU
2016-02, Leases. The standard increases transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for lease terms of more than 12 months. The effect of leases on the Consolidated
Statements of Income and the Consolidated Statements of Cash Flows is largely unchanged. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. ASU 2016-02 is effective for annual
reporting periods, including interim reporting within those periods, beginning after December 15, 2018. Early adoption is permitted, and will be applied using a modified retrospective approach. The Company is currently in the process of
evaluating the impact of adoption of this standard on its consolidated financial statements. 

  
 13 

 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 March 31, 2016, Emera has six reportable segments, specifically: 
  

	 	•	 	NSPI; 

  

	 	•	 	Emera Maine; 

  

	 	•	 	Emera Caribbean (ECI and its subsidiaries including BLPC, Domlec, GBPC, 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 and an equity investment in Bear Swamp; and 

 

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

  

																																	
	 millions of Canadian dollars
	  	NSPI	 	  	Emera
Maine	 	  	Emera
Caribbean	 	  	Pipelines	 	  	Emera
Energy	 	  	Corporate
and Other	 	 	Inter-
Segment
Eliminations	 	 	Total	 
	 For the three months ended March 31, 2016
	   
	  				  				  				  				  				 				 			
	 Operating revenues from external customers (1)
	  	$	397.5	  	  	$	79.6	  	  	$	97.6	  	  	$	12.9	  	  	$	287.7	  	  	$	2.0	  	 	$	(0.6	) 	 	$	876.7	  
	 Inter-segment revenues (1)
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	3.3	  	  	 	6.4	  	 	 	(9.4	) 	 	 	0.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total operating revenues
	  	 	397.5	  	  	 	79.6	  	  	 	97.6	  	  	 	12.9	  	  	 	291.0	  	  	 	8.4	  	 	 	(10.0	) 	 	 	877.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net income attributable to common shareholders
	  	 	52.5	  	  	 	9.3	  	  	 	9.8	  	  	 	9.4	  	  	 	93.4	  	  	 	(130.1	) 	 	 	—  	  	 	 	44.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 For the three months ended March 31, 2015
	   
	  				  				  				  				  				 				 			
	 Operating revenues from external customers (1)
	  	$	446.5	  	  	$	69.2	  	  	$	103.0	  	  	$	13.1	  	  	$	254.2	  	  	$	3.2	  	 	$	(0.5	) 	 	$	888.7	  
	 Inter-segment revenues (1)
	  	 	—  	  	  	 	—  	  	  	 	2.4	  	  	 	—  	  	  	 	3.6	  	  	 	5.6	  	 	 	(11.8	) 	 	 	(0.2	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total operating revenues
	  	 	446.5	  	  	 	69.2	  	  	 	105.4	  	  	 	13.1	  	  	 	257.8	  	  	 	8.8	  	 	 	(12.3	) 	 	 	888.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Net income attributable to common shareholders
	  	 	68.0	  	  	 	11.5	  	  	 	8.8	  	  	 	9.9	  	  	 	64.9	  	  	 	(3.0	) 	 	 	—  	  	 	 	160.1	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	(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. 

5. REGULATED FUEL ADJUSTMENT MECHANISM AND FIXED COST DEFERRALS 
 NSPI’s
regulated fuel adjustment mechanism and fixed cost deferrals is recognized in the Consolidated Statements of Income and consisted of the following: 
  

									
	 For the

millions of Canadian dollars
	  	Three months ended
March 31	 
	  	2016	 	  	2015	 
	 Regulated fuel adjustment mechanism (see chart below)
	  	$	13.8	  	  	$	(5.4	) 
	 Application of non-fuel revenue
	  	 	3.8	  	  	 	7.0	  
	 Regulated fixed cost deferral related to 2015 demand side management
	  	 	—  	  	  	 	(8.8	) 
		  	  
	  
	 	  	  
	  
	 
		  	$	17.6	  	  	$	(7.2	) 
		  	  
	  
	 	  	  
	  
	 

  
 14 

 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 FAM is subject to an
incentive, with NSPI retaining or absorbing 10 per cent of the over or under-recovered amount to a maximum of $5 million. The incentive was suspended for 2012 to 2015, as a result of UARB approved settlement agreements and is in effect for
2016. 
 The regulated fuel adjustment mechanism on the Consolidated Statements of Income consisted of the following: 

 

									
	 For the

millions of Canadian dollars
	  	Three months
ended March 31	 
	  	2016	 	  	2015	 
	 Over (Under) recovery of current period Fuel Costs
	  	$	10.0	  	  	$	(23.6	) 
	 Recovery from (rebate to) customers of prior years’ Fuel Costs
	  	 	3.8	  	  	 	18.2	  
		  	  
	  
	 	  	  
	  
	 
	 Regulated fuel adjustment mechanism
	  	$	13.8	  	  	$	(5.4	) 
		  	  
	  
	 	  	  
	  
	 

 The deferred FAM amounts are recognized as a “Regulatory asset” or “Regulatory liability” on the Consolidated
Balance Sheets. The FAM regulatory asset balance of $8.5 million and the FAM regulatory liability balance of $55.1 million is disclosed in Note 16 and includes associated interest recorded as “Interest expense, net” on the Consolidated
Statements of Income. 
 In December 2015, the UARB approved NSPI’s 2016 base cost of fuel and its recovery of prior period unrecovered fuel related costs as
submitted in NSPI’s filings. Approved customer rates reset the base cost of fuel rate for 2016 and seek to recover a total of $13.7 million of prior years’ unrecovered Fuel Costs in 2016. Recovery of these costs began January 1, 2016.

 On December 18, 2015, the Electricity Plan Implementation (2015) Act (the “Electricity Plan Act”) was enacted by the Province of Nova Scotia.
In accordance with the Electricity Plan Act, NSPI filed with the UARB, on March 7, 2016, a three-year rate plan for Fuel Costs, requesting an average increase of 1.3 per cent for 2017 through 2019. A hearing is scheduled for June 13,
2016. 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.

 Pursuant to the FAM Plan of Administration, NSPI’s Fuel Costs are subject to independent audit. The audit for fiscal 2014 and 2015 is currently underway. 

Application of Non-Fuel Revenues 
 The Electricity Plan Act further directed
NSPI to apply any 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 to be used in the 2017 to 2019 period. The exception to this direction is application of 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, 

  
 15 

 
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. 

In Q1 2016, NSPI applied $3.8 million of non-fuel revenues to the FAM for periods 2017 to 2019. This was a result of applying the tax benefits associated with the South
Canoe and Sable Wind Projects as directed by the Electricity Plan Act. 
 Fixed Cost Deferral Related to 2015 DSM 

In April 2014, the Government of Nova Scotia announced new energy efficiency legislation to remove a previous charge for conservation and efficiency programs from
electricity 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 million and were 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 placed a cap of $34.0 million on 2019 DSM spending. The 2016 DSM cost of $24.7 million will not be deferred and
will be charged to earnings. 
 The deferred DSM amounts from 2015 are recognized as a “Regulatory asset” on the Consolidated Balance Sheets. The DSM
regulatory asset balance of $35.6 million is disclosed in Note 16 and includes associated interest that is recorded as “Interest expense, net” on the Consolidated Statements of Income. 

 

					
	 For the

millions of Canadian dollars
	  	2016	 
	 DSM regulatory asset – Balance as at January 1
	  	$	36.4	  
	 Recovery of regulatory asset recorded as regulatory amortization
	  	 	(1.5	) 
		  	  
	  
	 
	 Interest on DSM balance
	  	 	0.7	  
		  	  
	  
	 
	 DSM regulatory asset – Balance as at March 31
	  	$	35.6	  
		  	  
	  
	 

  
 16 

 6. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY INCOME 

Investments subject to significant influence consisted of the following: 
  

																					
	 	  	Carrying Value as at	 	  	Equity Income
For the three months ended
March 31	 	  	Percentage
of
Ownership	 
	 	  	March 31	 	  	December 31	 	  	  
	 millions of Canadian dollars
	  	2016	 	  	2015	 	  	2016	 	  	2015	 	  	2016	 
	 APUC (1) (2)
	  	$	520.1	  	  	$	503.7	  	  	$	9.0	  	  	$	6.6	  	  	 	19.4	  
	 LIL (3)
	  	 	251.1	  	  	 	208.1	  	  	 	4.7	  	  	 	1.7	  	  	 	59.0	  
	 NSPML
	  	 	206.4	  	  	 	187.6	  	  	 	4.4	  	  	 	3.6	  	  	 	100.0	  
	 M&NP
	  	 	178.2	  	  	 	188.7	  	  	 	5.9	  	  	 	5.9	  	  	 	12.9	  
	 Lucelec
	  	 	36.8	  	  	 	39.4	  	  	 	0.6	  	  	 	0.6	  	  	 	19.1	  
	 Maine Electric Power Company Inc.
	  	 	6.6	  	  	 	7.0	  	  	 	—  	  	  	 	0.1	  	  	 	21.7	  
	 Cape Sharp Tidal Venture Ltd.
	  	 	5.2	  	  	 	5.1	  	  	 	—  	  	  	 	—  	  	  	 	20.0	  
	 Chester Static Var Compensator
	  	 	4.9	  	  	 	5.3	  	  	 	—  	  	  	 	—  	  	  	 	50.0	  
	 Maine Yankee Atomic Power Company
	  	 	0.4	  	  	 	0.4	  	  	 	—  	  	  	 	—  	  	  	 	12.0	  
	 Bear Swamp (4)
	  	 	—  	  	  	 	—  	  	  	 	1.4	  	  	 	3.1	  	  	 	50.0	  
	 Northeast Wind Partnership II, LLC (“NWP”)
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	4.3	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  			
		  	$	1,209.7	  	  	$	1,145.3	  	  	$	26.0	  	  	$	25.9	  	  			
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  			

  

	(1)	As at March 31, 2016, the market price per share was $10.87 (December 31, 2015 – $10.91), which indicates a fair market value of this investment of $685.4 million (December 31, 2015 – $684.5
million). Emera holds 50.1 million shares and 12.9 million outstanding subscription receipts and dividend equivalents as at March 31, 2016 at an average book value of $8.25 per share. Carrying value reflects a cash cost of $371.2
million, plus non-cash gains recognized on conversion of prior subscriptions receipts into common shares, dilution gains or losses, and equity income or loss, less dividends received. The outstanding subscription receipts, with an average conversion
price of $9.19 will automatically convert to common shares in Q4 2016 if an election is not made. If converted, Emera’s interest would increase to 23.2 per cent. 

	(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 March 31, 2016, 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 59.0 per cent. 

	(4)	Bear Swamp’s credit investment balance is recorded in “Other long-term liabilities” on the Consolidated Balance Sheets. 

Equity investments include a $138.1 million difference between the cost and the underlying fair value of the investees’ assets as at the date of
acquisition. The excess is attributable to goodwill. 
 Emera accounts for its variable interest investment in NSPML as an equity investment (note 27).
NSPML’s consolidated summarized balance sheet is illustrated as follows: 
  

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	  	December 31
2015	 
	 Balance Sheet
	  				  			
	 Current assets
	  	$	501.2	  	  	$	438.7	  
	 Property, plant and equipment
	  	 	750.7	  	  	 	647.7	  
		  	  
	  
	 	  	  
	  
	 
	 Non-current assets
	  	 	466.0	  	  	 	565.6	  
		  	  
	  
	 	  	  
	  
	 
	 Total assets
	  	$	1,717.9	  	  	$	1,652.0	  
		  	  
	  
	 	  	  
	  
	 
	 Current liabilities
	  	$	173.0	  	  	$	129.8	  
	 Non-current liabilities
	  	 	1,338.5	  	  	 	1,334.6	  
	 Equity
	  	 	206.4	  	  	 	187.6	  
		  	  
	  
	 	  	  
	  
	 
	 Total liabilities and equity
	  	$	1,717.9	  	  	$	1,652.0	  
		  	  
	  
	 	  	  
	  
	 

  
 17 

 7. OTHER INCOME (EXPENSES), NET 

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

									
	 For the

millions of Canadian dollars
	  	Three months ended March 31	 
	  	2016	 	 	2015	 
	 Allowance for equity funds used during construction
	  	$	0.9	  	 	$	0.3	  
	 Investment income
	  	 	0.5	  	 	 	0.3	  
	 Foreign exchange gains (losses)
	  	 	(1.5	) 	 	 	1.9	  
	 Amortization of defeasance costs
	  	 	(1.7	) 	 	 	(1.7	) 
	 Foreign exchange gains (losses) and mark-to-market adjustments related to the pending TECO Energy
acquisition
	  	 	(139.5	) 	 	 	—  	  
	 Gain on sale of NWP investment
	  	 	—  	  	 	 	18.6	  
	 Other
	  	 	2.1	  	 	 	2.5	  
		  	  
	  
	 	 	  
	  
	 
		  	$	(139.2	) 	 	$	21.9	  
		  	  
	  
	 	 	  
	  
	 

 8. INTEREST EXPENSE, NET 
 Interest expense,
net consisted of the following: 
  

									
	 For the

millions of Canadian dollars
	  	Three months ended March 31	 
	  	2016	 	 	2015	 
	 Interest on debt
	  	$	48.7	  	 	$	47.3	  
	 Interest on convertible debentures represented by instalment receipts (1)
	  	 	21.9	  	 	 	—  	  
	 Allowance for borrowed funds used during construction
	  	 	(0.7	) 	 	 	(2.2	) 
	 Interest revenue
	  	 	(0.9	) 	 	 	(2.1	) 
	 Other
	  	 	6.2	  	 	 	1.4	  
		  	  
	  
	 	 	  
	  
	 
		  	$	75.2	  	 	$	44.4	  
		  	  
	  
	 	 	  
	  
	 

  

	(1)	In 2015, Emera completed the sale of $2.1 billion four per cent convertible unsecured subordinated debentures represented by instalment receipts (“Debentures” or “the Debenture Offering” or
“Convertible Debentures”). 

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

									
	 For the

millions of Canadian dollars
	  	Three months ended
March 31	 
	 	  	2016	 	 	2015	 
	 Income before provision for income taxes
	  	$	81.6	  	 	$	235.5	  
		  	  
	  
	 	 	  
	  
	 
	 Statutory income tax rate
	  	 	31.0%	  	 	 	31.0%	  
	 Income taxes, at statutory income tax rate
	  	 	25.3	  	 	 	73.0	  
	 Non-deductible portion of mark-to-market losses related to pending TECO Energy acquisition
	  	 	21.6	  	 	 	—  	  
	 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities
	  	 	(13.1	) 	 	 	(9.4	) 
	 Tax effect of equity earnings
	  	 	(2.9	) 	 	 	(2.3	) 
	 Tax effect of foreign exchange
	  	 	(2.3	) 	 	 	2.9	  
	 Other
	  	 	(1.8	) 	 	 	(2.8	) 
		  	  
	  
	 	 	  
	  
	 
	 Income tax expense (recovery)
	  	$	26.8	  	 	$	61.4	  
		  	  
	  
	 	 	  
	  
	 
	 Effective income tax rate
	  	 	32.8%	  	 	 	26.1%	  
		  	  
	  
	 	 	  
	  
	 

 The 2016 and 2015 statutory income tax rate of 31.0 per cent represents the combined Canadian federal and Nova Scotia provincial
corporate income tax rates, which are the relevant tax jurisdictions for Emera. 

  
 18 

 The following reflects the composition of taxes on income from continuing operations presented in the Condensed
Consolidated Statements of Income: 
  

									
	 For the

millions of Canadian dollars
	  	Three months ended
March 31	 
	  	2016	 	  	2015	 
	 Income tax expense (recovery) – current
	  	$	18.0	  	  	$	49.1	  
	 Income tax expense (recovery) – deferred
	  	 	8.8	  	  	 	12.3	  
		  	  
	  
	 	  	  
	  
	 
	 Income tax expense (recovery)
	  	$	26.8	  	  	$	61.4	  
		  	  
	  
	 	  	  
	  
	 

 NSPI and the Canada Revenue Agency (“CRA”) are currently in a dispute with respect to the timing of certain tax deductions for
NSPI’s 2006 through 2010 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $62.3 million, including 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. 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 these 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. 
 10. EARNINGS PER SHARE 

The following table reconciles the computation of basic and diluted earnings per share: 
  

									
	 For the

millions of Canadian dollars (except per share amounts)
	  	Three months ended
March 31	 
	  	2016	 	  	2015	 
	 Numerator
	  				  			
	 Net income attributable to common shareholders
	  	$	44.3	  	  	$	160.1	  
	 Preferred stock dividends of subsidiary
	  	 	—  	  	  	 	2.0	  
		  	  
	  
	 	  	  
	  
	 
	 Diluted numerator
	  	 	44.3	  	  	 	162.1	  
		  	  
	  
	 	  	  
	  
	 
	 Denominator
	  				  			
	 Weighted average shares of common stock outstanding
	  	 	147.7	  	  	 	144.0	  
	 Weighted average deferred share units outstanding
	  	 	1.0	  	  	 	0.9	  
		  	  
	  
	 	  	  
	  
	 
	 Weighted average shares of common stock outstanding – basic
	  	 	148.7	  	  	 	144.9	  
	 Effect of dilutive securities
	  	 	—  	  	  	 	3.3	  
	 Stock-based compensation
	  	 	0.6	  	  	 	0.6	  
		  	  
	  
	 	  	  
	  
	 
	 Weighted average shares of common stock outstanding – diluted
	  	 	149.3	  	  	 	148.8	  
		  	  
	  
	 	  	  
	  
	 
	 Earnings per common share
	  				  			
	 Basic
	  	$	0.30	  	  	$	1.10	  
	 Diluted
	  	$	0.30	  	  	$	1.09	  
		  	  
	  
	 	  	  
	  
	 

  
 19 

 Effect on EPS of Convertible Debentures 

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. This conversion can occur at any time after the Final Instalment Date, but prior to maturity or redemption by the Company. The conversion price is $41.85 per
common share, and the conversion rate is 23.8949 common shares per $1,000 principal amount of Debentures (note 22). 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. 
 11. ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS) 
 The components of accumulated other comprehensive income (loss), net of tax, 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 in
available-for-sale
investments	 	 	Unrealized (loss)
gain on translation
of self-sustaining
foreign operations	 	 	Total AOCI	 
	 For the three months ended March 31, 2016
	 				 				 				 				 			
	 Balance, January 1, 2016
	 	$	(35.1	) 	 	$	(317.6	) 	 	$	0.3	  	 	$	488.9	  	 	$	136.5	  
	 Other comprehensive income (loss) before reclassifications
	 	 	14.1	  	 	 	—  	  	 	 	0.4	  	 	 	(154.7	) 	 	 	(140.2	) 
	 Amounts reclassified from accumulated other comprehensive income loss (gain)
	 	 	0.9	  	 	 	8.6	  	 	 	—  	  	 	 	—  	  	 	 	9.5	  
	 Net current period other comprehensive income (loss)
	 	 	15.0	  	 	 	8.6	  	 	 	0.4	  	 	 	(154.7	) 	 	 	(130.7	) 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, March 31, 2016
	 	$	(20.1	) 	 	$	(309.0	) 	 	$	0.7	  	 	$	334.2	  	 	$	5.8	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
						
	 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 in
available-for-sale
investments	 	 	Unrealized (loss)
gain on translation
of self-sustaining
foreign operations	 	 	Total AOCI	 
	 For the three months ended March 31, 2015
	 				 				 				 				 			
	 Balance, January 1, 2015
	 	$	(7.9	) 	 	$	(424.7	) 	 	$	2.6	  	 	$	82.4	  	 	$	(347.6	) 
	 Other comprehensive income (loss) before reclassifications
	 	 	(15.9	) 	 	 	—  	  	 	 	0.4	  	 	 	176.2	  	 	 	160.7	  
	 Amounts reclassified from accumulated other comprehensive income loss (gain)
	 	 	(1.1	) 	 	 	10.6	  	 	 	—  	  	 	 	—  	  	 	 	9.5	  
	 Net current period other comprehensive income (loss)
	 	 	(17.0	) 	 	 	10.6	  	 	 	0.4	  	 	 	176.2	  	 	 	170.2	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, March 31, 2015
	 	$	(24.9	) 	 	$	(414.1	) 	 	$	3.0	  	 	$	258.6	  	 	$	(177.4	) 
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  
 20 

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

 

											
	 For the

millions of Canadian dollars
	  	 	  	Three months ended
March 31	 
	  	 	  	2016	 	 	2015	 
		  	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	  	$	(4.2	) 	 	$	(5.6	) 
	 Interest rate swaps
	  	Income from equity investments	  	 	0.3	  	 	 	0.2	  
	 Foreign exchange forwards
	  	Operating revenue – regulated	  	 	3.2	  	 	 	2.1	  
		  		  	  
	  
	 	 	  
	  
	 
	 Total before tax
	  		  	 	(0.7	) 	 	 	(3.3	) 
		  		  	  
	  
	 	 	  
	  
	 
		  	Income tax expense (recovery)	  	 	1.6	  	 	 	2.2	  
		  		  	  
	  
	 	 	  
	  
	 
	 Total net of tax
	  		  	$	0.9	  	 	$	(1.1	) 
		  		  	  
	  
	 	 	  
	  
	 
	 Net change in unrecognized pension and post-retirement benefit
costs
	  		  				 			
	 Actuarial losses (gains)
	  	OM&G	  	$	10.9	  	 	$	11.9	  
	 Past service costs (gains)
	  	OM&G	  	 	(2.3	) 	 	 	(0.7	) 
		  		  	  
	  
	 	 	  
	  
	 
	 Total before tax
	  		  	 	8.6	  	 	 	11.2	  
		  		  	  
	  
	 	 	  
	  
	 
		  	Income tax expense (recovery)	  	 	—  	  	 	 	(0.6	) 
		  		  	  
	  
	 	 	  
	  
	 
	 Total net of tax
	  		  	$	8.6	  	 	$	10.6	  
		  		  	  
	  
	 	 	  
	  
	 
	 Net change in available-for-sale investments
	  		  				 			
		  		  	  
	  
	 	 	  
	  
	 
	 Total reclassifications out of AOCI, net of tax, for the period
	  		  	$	9.5	  	 	$	9.5	  
		  		  	  
	  
	 	 	  
	  
	 

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

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	 	December 31
2015	 
	 Customer accounts receivable – billed
	  	$	437.8	  	 	$	406.3	  
	 Customer accounts receivable – unbilled
	  	 	146.6	  	 	 	144.2	  
		  	  
	  
	 	 	  
	  
	 
	 Total customer accounts receivable
	  	 	584.4	  	 	 	550.5	  
	 Allowance for doubtful accounts
	  	 	(12.1	) 	 	 	(12.6	) 
		  	  
	  
	 	 	  
	  
	 
	 Customer accounts receivable, net
	  	 	572.3	  	 	 	537.9	  
	 Other
	  	 	38.0	  	 	 	39.5	  
		  	  
	  
	 	 	  
	  
	 
		  	$	610.3	  	 	$	577.4	  
		  	  
	  
	 	 	  
	  
	 

 13. INVENTORY 
 Inventory consisted of the
following: 
  

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	  	December 31
2015	 
	 Fuel
	  	$	141.1	  	  	$	185.3	  
	 Materials
	  	 	98.8	  	  	 	100.4	  
	 Emission credits (1)
	  	 	20.9	  	  	 	28.6	  
		  	  
	  
	 	  	  
	  
	 
		  	$	260.8	  	  	$	314.3	  
		  	  
	  
	 	  	  
	  
	 

  

	(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 (notes 21 and 23) associated with
these programs. 

  
 21 

 14. DERIVATIVE INSTRUMENTS 
 The
Company enters into futures, forwards, swaps and option contracts as part of its risk management strategy to limit exposure to: 
  

	 	•	 	commodity price fluctuations related to the purchase and sale of commodities in the course of normal operations; 

  

	 	•	 	foreign exchange fluctuations on foreign currency denominated purchases and sales; and 

  

	 	•	 	interest rate fluctuations on debt securities. 

 The Company also enters into physical contracts for energy commodities.
Collectively, these contracts are considered “derivatives”. The Company accounts for derivatives under one of the following four approaches: 
  

	 	1.	Physical contracts that meet the normal purchases normal sales (“NPNS”) exemption are not recognized on the balance sheet; they are recognized in income when they settle. A physical contract generally
qualifies for the NPNS exemption if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive
physical delivery of the commodity, and the Company deems the counterparty credit worthy. The Company continually assesses contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exception if
the criteria are no longer met. 

  

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

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

	 	3.	Derivatives entered into by 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. 

 

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

  
 22 

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

 

																	
	 	  	Derivative Assets	 	 	Derivative Liabilities	 
	As at	  	March 31	 	 	December 31	 	 	March 31	 	 	December 31	 
	 millions of Canadian dollars
	  	2016	 	 	2015	 	 	2016	 	 	2015	 
	 Current
	  				 				 				 			
	 Cash flow hedges
	  				 				 				 			
	 Power swaps
	  	$	5.3	  	 	$	7.9	  	 	$	0.5	  	 	$	0.5	  
	 Foreign exchange forwards
	  	 	0.3	  	 	 	—  	  	 	 	10.2	  	 	 	14.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	5.6	  	 	 	7.9	  	 	 	10.7	  	 	 	14.9	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	  				 				 				 			
	 Commodity swaps and forwards
	  				 				 				 			
	 Coal purchases
	  	 	—  	  	 	 	—  	  	 	 	7.7	  	 	 	11.7	  
	 Natural gas purchases and sales
	  	 	0.7	  	 	 	1.5	  	 	 	2.3	  	 	 	0.7	  
	 Heavy fuel oil purchases
	  	 	—  	  	 	 	—  	  	 	 	16.4	  	 	 	20.5	  
	 Foreign exchange forwards
	  	 	56.2	  	 	 	85.3	  	 	 	7.6	  	 	 	10.5	  
	 Physical natural gas purchases and sales
	  	 	0.8	  	 	 	1.8	  	 	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	57.7	  	 	 	88.6	  	 	 	34.0	  	 	 	43.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	  				 				 				 			
	 Power swaps and physical contracts
	  	 	21.1	  	 	 	150.8	  	 	 	23.7	  	 	 	118.5	  
	 Foreign exchange options
	  	 	0.3	  	 	 	98.6	  	 	 	1.0	  	 	 	2.1	  
	 Natural gas swaps, futures, forwards, physical contracts
	  	 	64.0	  	 	 	—  	  	 	 	132.1	  	 	 	358.8	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	85.4	  	 	 	249.4	  	 	 	156.8	  	 	 	479.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Other derivatives
	  				 				 				 			
	 Foreign exchange forwards
	  	 	1.1	  	 	 	92.1	  	 	 	3.8	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	1.1	  	 	 	92.1	  	 	 	3.8	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total gross current derivatives
	  	 	149.8	  	 	 	438.0	  	 	 	205.3	  	 	 	537.7	  
	 Impact of master netting agreements with intent to settle net or simultaneously
	  	 	(57.4	) 	 	 	(188.5	) 	 	 	(57.4	) 	 	 	(188.5	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total current derivatives
	  	 	92.4	  	 	 	249.5	  	 	 	147.9	  	 	 	349.2	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Long-term
	  				 				 				 			
	 Cash flow hedges
	  				 				 				 			
	 Power swaps
	  	 	5.7	  	 	 	11.6	  	 	 	3.7	  	 	 	4.1	  
	 Foreign exchange forwards
	  	 	0.4	  	 	 	0.3	  	 	 	14.1	  	 	 	27.2	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	6.1	  	 	 	11.9	  	 	 	17.8	  	 	 	31.3	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	  				 				 				 			
	 Commodity swaps and forwards
	  				 				 				 			
	 Coal purchases
	  	 	3.0	  	 	 	—  	  	 	 	4.0	  	 	 	4.4	  
	 Heavy fuel oil purchases
	  	 	—  	  	 	 	—  	  	 	 	13.3	  	 	 	16.6	  
	 Foreign exchange forwards
	  	 	72.0	  	 	 	121.4	  	 	 	—  	  	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	75.0	  	 	 	121.4	  	 	 	17.3	  	 	 	21.0	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	  				 				 				 			
	 Power swaps and physical contracts
	  	 	14.1	  	 	 	12.9	  	 	 	27.5	  	 	 	28.2	  
	 Natural gas swaps, futures, forwards and physical contracts
	  	 	24.2	  	 	 	72.3	  	 	 	47.4	  	 	 	62.6	  
	 Foreign exchange options
	  	 	0.7	  	 	 	0.4	  	 	 	0.7	  	 	 	1.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	39.0	  	 	 	85.6	  	 	 	75.6	  	 	 	92.2	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Other derivatives
	  				 				 				 			
	 Interest rate swap
	  	 	—  	  	 	 	—  	  	 	 	3.2	  	 	 	2.9	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		  	 	—  	  	 	 	—  	  	 	 	3.2	  	 	 	2.9	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total gross long-term derivatives
	  	 	120.1	  	 	 	218.9	  	 	 	113.9	  	 	 	147.4	  
	 Impact of master netting agreements with intent to settle net or simultaneously
	  	 	(34.7	) 	 	 	(51.3	) 	 	 	(34.7	) 	 	 	(51.3	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total long-term derivatives
	  	 	85.4	  	 	 	167.6	  	 	 	79.2	  	 	 	96.1	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total derivatives
	  	$	177.8	  	 	$	417.1	  	 	$	227.1	  	 	$	445.3	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

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

  
 23 

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

  

																	
	 	  	Derivative Assets	 	  	Derivative Liabilities	 
	As at	  	March 31	 	  	December 31	 	  	March 31	 	  	December 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 	  	2016	 	  	2015	 
	 Regulatory deferral
	  	$	1.4	  	  	$	0.1	  	  	$	1.4	  	  	$	0.1	  
	 HFT derivatives
	  	 	90.7	  	  	 	239.7	  	  	 	90.7	  	  	 	239.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total impact of master netting agreements with intent to settle net or simultaneously
	  	$	92.1	  	  	$	239.8	  	  	$	92.1	  	  	$	239.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 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

millions of Canadian dollars
	  	Three months ended March 31	 
	  	2016	 	 	2015	 
	 	  	Power
Swaps	 	 	Interest
Rate
Swaps	 	 	Foreign
Exchange
Forwards	 	 	Power
Swaps	 	 	Interest
Rate
Swaps	 	 	Foreign
Exchange
Forwards	 
	 Unrealized gain (loss) in Non-regulated fuel for generation and purchased power – ineffective
portion
	  	$	(1.0	) 	 	$	—  	  	 	$	—  	  	 	$	(0.6	) 	 	$	—  	  	 	$	—  	  
	 Realized gain (loss) in Non-regulated fuel for generation and purchased power
	  	 	4.2	  	 	 	—  	  	 	 	—  	  	 	 	5.6	  	 	 	—  	  	 	 	—  	  
	 Realized gain (loss) in Operating revenue – Regulated
	  	 	—  	  	 	 	—  	  	 	 	(3.2	) 	 	 	—  	  	 	 	—  	  	 	 	(2.1	) 
	 Realized gain (loss) in Income from equity investments
	  	 	—  	  	 	 	(0.3	) 	 	 	—  	  	 	 	—  	  	 	 	(0.2	) 	 	 	—  	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total gains (losses) in Net income
	  	$	3.2	  	 	$	(0.3	) 	 	$	(3.2	) 	 	$	5.0	  	 	$	(0.2	) 	 	$	(2.1	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
			
	 As at

millions of Canadian dollars
	  	March 31
2016	 	 	December 31
2015	 
	 	  	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
	  	$	0.9	  	 	$	(0.9	) 	 	$	(23.6	) 	 	$	3.5	  	 	$	(1.1	) 	 	$	(41.7	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The Company expects $8.7 million of unrealized losses currently in AOCI to be reclassified into net income within the next twelve
months, as the underlying hedged transactions settle. 

  
 24 

 As at March 31, 2016, 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
	  	 	0.2	  	  	 	0.3	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
	 Foreign exchange forwards (USD) sales
	  	 	40.4	  	  	 	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

millions of Canadian dollars
	  	Three months ended March 31, 2016	 
	 	  	Commodity
swaps and
forwards	 	  	Physical
natural gas
purchases
and sales	 	 	Foreign
exchange
forwards	 
	 Unrealized gain (loss) in regulatory assets
	  	$	4.1	  	  	$	—  	  	 	$	2.9	  
	 Unrealized gain (loss) in regulatory liabilities
	  	 	0.9	  	  	 	(1.0	) 	 	 	(50.4	) 
	 Realized (gain) loss in regulatory assets
	  	 	1.7	  	  	 	—  	  	 	 	—  	  
	 Realized (gain) loss in inventory (1)
	  	 	—  	  	  	 	—  	  	 	 	(19.4	) 
	 Realized (gain) loss in regulated fuel for generation and purchased power (2)
	  	 	5.7	  	  	 	—  	  	 	 	(8.7	) 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Total change in derivative instruments
	  	$	12.4	  	  	$	(1.0	) 	 	$	(75.6	) 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 

  

	(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. 

 

													
	 For the

millions of Canadian dollars
	  	Three months ended March 31, 2015	 
	 	  	Commodity
swaps and
forwards	 	 	Physical
natural gas
purchases
and sales	 	 	Foreign
exchange
forwards	 
	 Unrealized gain (loss) in regulatory assets
	  	$	(8.3	) 	 	$	—  	  	 	$	(2.7	) 
	 Unrealized gain (loss) in regulatory liabilities
	  	 	(0.1	) 	 	 	4.7	  	 	 	92.6	  
	 Realized (gain) loss in regulatory assets
	  	 	3.4	  	 	 	—  	  	 	 	—  	  
	 Realized (gain) loss in inventory (1)
	  	 	(0.7	) 	 	 	—  	  	 	 	(12.7	) 
	 Realized (gain) loss in property, plant and equipment
	  	 	—  	  	 	 	—  	  	 	 	(1.0	) 
	 Realized (gain) loss in regulated fuel for generation and purchased power (2)
	  	 	4.0	  	 	 	(0.1	) 	 	 	(2.8	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total change in derivative instruments
	  	$	(1.7	) 	 	$	4.6	  	 	$	73.4	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	(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. 

  
 25 

 Commodity Swaps and Forwards 
 As
at March 31, 2016, 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	 	  	2017-2019	 
	 millions
	  	Purchases	 	  	Purchases	 
	 Coal (metric tonnes)
	  	 	0.2	  	  	 	2.3	  
	 Natural Gas (mmbtu)
	  	 	3.2	  	  	 	—  	  
	 Heavy fuel oil (bbls)
	  	 	0.5	  	  	 	0.5	  
		  	  
	  
	 	  	  
	  
	 

 Foreign Exchange Swaps and Forwards 
 As at
March 31, 2016, 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	 	 	2017-2019	 
	 Fuel purchases exposure (millions of US dollars)
	 	$	150.8	  	 	$	461.8	  
	 Weighted average rate
	 	 	1.0331	  	 	 	1.0932	  
	 % of USD requirements
	 	 	96	% 	 	 	90	% 
		 	  
	  
	 	 	  
	  
	 

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

 

									
	 For the

millions of Canadian dollars
	 	Three months ended March 31	 
	 	2016	 	 	2015	 
	 Power swaps and physical contracts in non-regulated operating revenues
	 	$	(5.5	) 	 	$	1.5	  
	 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues
	 	 	227.9	  	 	 	92.5	  
	 Natural gas swaps, forwards, futures and physical contracts in non-regulated fuel for generation and
purchased power
	 	 	0.9	  	 	 	(1.8	) 
	 Power swaps, forwards, futures and physical contracts in non-regulated fuel for generation and purchased
power
	 	 	(1.6	) 	 	 	2.0	  
	 Foreign exchange options in non-regulated operating revenue
	 	 	(0.8	) 	 	 	—  	  
		 	  
	  
	 	 	  
	  
	 
		 	$	220.9	  	 	$	94.2	  
		 	  
	  
	 	 	  
	  
	 

 As at March 31, 2016, 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)
	  	 	194.5	  	  	 	60.6	  	  	 	49.9	  	  	 	43.9	  	  	 	43.9	  
	 Natural gas sales (Mmbtu)
	  	 	155.8	  	  	 	33.8	  	  	 	6.1	  	  	 	5.8	  	  	 	5.1	  
	 Power purchases (MWh)
	  	 	0.6	  	  	 	0.6	  	  	 	0.6	  	  	 	0.6	  	  	 	0.6	  
	 Power sales (MWh)
	  	 	1.7	  	  	 	0.3	  	  	 	0.3	  	  	 	0.3	  	  	 	0.3	  
	 Foreign exchange options (USD)
	  	$	14.9	  	  	$	12.5	  	  	$	4.1	  	  	 	—  	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Foreign exchange forwards (EURO) purchases
	  	 	—  	  	  	 	0.2	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  
 26 

 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
	  	Three months ended March 31	 
	  	2016	 	 	2015	 
	 	  	Interest rate
swaps	 	 	Foreign
exchange
forwards	 	 	Interest rate
swaps	 	  	Foreign
exchange
forwards	 
	 Unrealized gain (loss) in other income (expense)
	  	$	 	  	 	$	(94.8	) 	 	$	—	  	  	$	—	  
	 Unrealized gain (loss) in interest expense, net
	  	 	(0.3	) 	 	 	—	  	 	 	—	  	  	 	—	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Total gains (losses) in net income
	  	$	(0.3	) 	 	$	(94.8	) 	 	$	—	  	  	$	—	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	  	  
	  
	 

 As at March 31, 2016, 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 March 31, 2016, 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, recognizes provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to
consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have
credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current
default probability. The Company assesses credit risk internally for counterparties that are not rated. 
 It is possible that volatility in commodity prices could
cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company
transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the
Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the
customer/counterparty where it is no longer required by the Company. 
 The Company enters into commodity master arrangements with its counterparties to manage
certain risks, including credit risk to these counterparties. The Company generally enters into International 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. 

  
 27 

 As at March 31, 2016, the Company had $86.3 million (December 31, 2015 – $83.2 million) in financial assets,
considered to be past due, which have been outstanding for an average 78 days. The fair value of these financial assets is $75.1 million (December 31, 2015 – $71.5 million), the difference of which is included in the allowance for doubtful
accounts. These assets primarily relate to accounts receivable from electric revenue. 
 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
	  	March 31
2016	 	  	December 31
2015	 
	 Cash collateral provided to others
	  	$	124.9	  	  	$	106.9	  
		  	  
	  
	 	  	  
	  
	 
	 Cash collateral received from others
	  	 	1.4	  	  	 	28.5	  
		  	  
	  
	 	  	  
	  
	 

 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 March 31, 2016, the total fair value of these derivatives, in a liability position, was $227.1 million (December 31, 2015 – $445.3 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. 

15. FAIR VALUE MEASUREMENTS 
 The Company is required to determine the fair
value of all derivatives except those which qualify for the NPNS exemption (see note 14), and uses a market approach to do so. The three levels of the fair value hierarchy are defined as follows: 

Level 1 – Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted
prices”) for identical assets and liabilities. 
 Level 2 – Where quoted prices for identical assets and liabilities are not available, the valuation of
certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses. 

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

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

 

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

  
 28 

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

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

The following tables set out the classification of the methodology used by the Company to fair value its derivatives: 

 

																	
	As at	  	March 31, 2016	 
	 millions of Canadian dollars
	  	Level 1	 	 	Level 2	 	  	Level 3	 	 	Total	 
	 Assets
	  				 				  				 			
	 Cash flow hedges
	  				 				  				 			
	 Power swaps
	  	$	11.0	  	 	$	0.2	  	  	$	—  	  	 	$	11.2	  
	 Foreign exchange forwards
	  	 	—  	  	 	 	0.5	  	  	 	—  	  	 	 	0.5	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	11.0	  	 	 	0.7	  	  	 	—  	  	 	 	11.7	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	  				 				  				 			
	 Commodity swaps and forwards
	  				 				  				 			
	 Coal purchases
	  	 	—  	  	 	 	1.7	  	  	 	—  	  	 	 	1.7	  
	 Natural gas purchases and sales
	  	 	—  	  	 	 	0.6	  	  	 	—  	  	 	 	0.6	  
	 Foreign exchange forwards
	  	 	—  	  	 	 	128.2	  	  	 	—  	  	 	 	128.2	  
	 Physical natural gas purchases and sales
	  	 	—  	  	 	 	—  	  	  	 	0.8	  	 	 	0.8	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	—  	  	 	 	130.5	  	  	 	0.8	  	 	 	131.3	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	  				 				  				 			
	 Power swaps and physical contracts
	  	 	(3.7	) 	 	 	0.4	  	  	 	4.8	  	 	 	1.5	  
	 Foreign exchange options
	  	 	—  	  	 	 	1.0	  	  	 	—  	  	 	 	1.0	  
	 Natural gas swaps, futures, forwards, physical contracts and related transportation
	  	 	2.0	  	 	 	8.7	  	  	 	20.5	  	 	 	31.2	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	(1.7	) 	 	 	10.1	  	  	 	25.3	  	 	 	33.7	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Other derivatives
	  				 				  				 			
	 Foreign exchange forwards
	  	 	—  	  	 	 	1.1	  	  	 	—  	  	 	 	1.1	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	—  	  	 	 	1.1	  	  	 	—  	  	 	 	1.1	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Total assets
	  	 	9.3	  	 	 	142.4	  	  	 	26.1	  	 	 	177.8	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Liabilities
	  				 				  				 			
	 Cash flow hedges
	  				 				  				 			
	 Power swaps
	  	 	4.2	  	 	 	—  	  	  	 	—  	  	 	 	4.2	  
	 Foreign exchange forwards
	  	 	—  	  	 	 	24.3	  	  	 	—  	  	 	 	24.3	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	4.2	  	 	 	24.3	  	  	 	—  	  	 	 	28.5	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Regulatory deferral
	  				 				  				 			
	 Commodity swaps and forwards
	  				 				  				 			
	 Coal purchases
	  	 	—  	  	 	 	10.4	  	  	 	—  	  	 	 	10.4	  
	 Heavy fuel oil purchases
	  	 	—  	  	 	 	29.6	  	  	 	—  	  	 	 	29.6	  
	 Natural gas purchases and sales
	  	 	2.1	  	 	 	0.1	  	  	 	—  	  	 	 	2.2	  
	 Foreign exchange forwards
	  				 	 	7.6	  	  	 	—  	  	 	 	7.6	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	2.1	  	 	 	47.7	  	  	 	—  	  	 	 	49.8	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 HFT derivatives
	  				 				  				 			
	 Power swaps and physical contracts
	  	 	12.2	  	 	 	0.9	  	  	 	4.6	  	 	 	17.7	  
	 Foreign exchange options
	  	 	—  	  	 	 	1.7	  	  	 	—  	  	 	 	1.7	  
	 Natural gas swaps, futures, forwards and physical contracts
	  	 	6.9	  	 	 	19.5	  	  	 	96.0	  	 	 	122.4	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	19.1	  	 	 	22.1	  	  	 	100.6	  	 	 	141.8	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Other derivatives
	  				 				  				 			
	 Foreign exchange forwards
	  	 	—  	  	 	 	3.8	  	  	 	—  	  	 	 	3.8	  
	 Interest rate swap
	  	 	—  	  	 	 	3.2	  	  	 	—  	  	 	 	3.2	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
		  	 	—  	  	 	 	7.0	  	  	 	—  	  	 	 	7.0	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Total liabilities
	  	 	25.4	  	 	 	101.1	  	  	 	100.6	  	 	 	227.1	  
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 
	 Net assets (liabilities)
	  	$	(16.1	) 	 	$	41.3	  	  	$	(74.5	) 	 	$	(49.3	) 
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 

  
 29 

																	
	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 forwards
	  	 	—  	  	 	 	0.4	  	  	 	—  	  	 	 	0.4	  
	 Natural gas swaps, futures, forwards and physical contracts
	  	 	(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	  
	 Natural gas purchases and sales
	  	 	0.6	  	 	 	—  	  	  	 	—  	  	 	 	0.6	  
	 Heavy fuel oil purchases
	  	 	—  	  	 	 	37.1	  	  	 	—  	  	 	 	37.1	  
	 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 swaps
	  	 	—  	  	 	 	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	) 
		  	  
	  
	 	 	  
	  
	 	  	  
	  
	 	 	  
	  
	 

 The Company evaluates the observable inputs of market data on a quarterly basis in order to determine if transfers between levels is
appropriate. For the three months ended March 31, 2016, there were no transfers between levels. 

  
 30 

 The change in the fair value of the Level 3 financial assets for the three months ended March 31, 2016 was as follows:

  

																	
	 	  	Regulatory Deferral	 	 	Cash Flow Hedges
and HFT Derivatives	 
	 millions of Canadian dollars
	  	Physical natural
gas purchases and
sales	 	 	Power
Swaps	 	 	Natural
gas	 	 	Total	 
	 Balance, January 1, 2016
	  	$	1.8	  	 	$	(7.8	) 	 	$	56.8	  	 	$	50.8	  
	 Unrealized gains (losses) included in regulatory assets or liabilities
	  	 	(1.0	) 	 	 	—  	  	 	 	—  	  	 	 	(1.0	) 
	 Total realized and unrealized gains (losses) included in non-regulated operating revenues
	  	 	—  	  	 	 	12.6	  	 	 	(36.3	) 	 	 	(23.7	) 
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, March 31, 2016
	  	$	0.8	  	 	$	4.8	  	 	$	20.5	  	 	$	26.1	  
		  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 The change in the fair value of the Level 3 financial liabilities for the three months ended March 31, 2016 was as follows: 

 

																	
	 	  	Regulatory Deferral	 	  	Cash Flow Hedges
and HFT Derivatives	 
	 millions of Canadian dollars
	  	Heavy fuel oil
purchases	 	  	Power	 	 	Natural
gas	 	 	Total	 
	 Balance, January 1, 2016
	  	$	—  	  	  	$	(2.0	) 	 	$	278.8	  	 	$	276.8	  
	 Total realized and unrealized gains (losses) included in non-regulated operating revenues
	  	 	—  	  	  	 	6.6	  	 	 	(182.8	) 	 	 	(176.2	) 
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Balance, March 31, 2016
	  	$	—  	  	  	$	4.6	  	 	$	96.0	  	 	$	100.6	  
		  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 

 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. 

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: 
  

  
 31 

																					
	 As at
	  	March 31, 2016	 
	 millions of Canadian dollars
	  	Fair
Value	 	 	Valuation
Technique	 	  	Unobservable Input	 	  	Range	 	  	Weighted
average	 
	 Assets
	  				 				  				  				  			
	 Regulatory deferral – Physical
	  	$	0.8	  	 	 	Modelled pricing	  	  	 	Third-party pricing	  	  	 	$4.09 - $4.70	  	  	$	4.36	  
	 natural gas purchases and sales
	  	 	 	 	 	 	 	 	  	 	Probability of default	  	  	 	0.07%	  	  	 	0.01%	  
	 HFT derivatives –
	  	 	4.4	  	 	 	Modelled pricing	  	  	 	Third-party pricing	  	  	 	$18.85 - $74.05	  	  	$	30.20	  
	 Power swaps and
	  				 				  	 	Probability of default	  	  	 	0.00% - 0.02%	  	  	 	0.00%	  
	 physical contracts
	  	 	 	 	 	 	 	 	  	 	Discount rate	  	  	 	0.02% - 0.05%	  	  	 	0.03%	  
		  	 	0.4	  	 	 	Modelled pricing	  	  	 	Third-party pricing	  	  	 	$21.51 - $78.42	  	  	$	35.74	  
		  				 				  	 	Correlation factor	  	  	 	0.99% - 0.99%	  	  	 	0.99%	  
		  				 				  	 	Probability of default	  	  	 	0.00% - 0.01%	  	  	 	0.01%	  
	 	  	 	 	 	 	 	 	 	  	 	Discount rate	  	  	 	0.02% - 0.11%	  	  	 	0.06%	  
	 HFT derivatives –
	  	 	11.7	  	 	 	Modelled pricing	  	  	 	Third-party pricing	  	  	 	$1.35 - $7.76	  	  	$	2.63	  
	 Natural gas swaps,
	  				 				  	 	Probability of default	  	  	 	0.00% - 0.03%	  	  	 	0.01%	  
	 futures, forwards,
	  	 	 	 	 	 	 	 	  	 	Discount rate	  	  	 	0.00% - 0.27%	  	  	 	0.05%	  
	 physical contracts
	  	 	8.8	  	 	 	Modelled pricing	  	  	 	Third-party pricing	  	  	 	$1.07 - $7.71	  	  	$	2.66	  
	 and related transportation
	  				 				  	 	Basis adjustment	  	  	 	-0.12% - 0.74%	  	  	 	0.46%	  
		  				 				  	 	Probability of default	  	  	 	0.00% - 0.01%	  	  	 	0.00%	  
	 	  	 	 	 	 	 	 	 	  	 	Discount rate	  	  	 	0.00% - 0.07%	  	  	 	0.00%	  
	 Total assets
	  	 	26.1	  	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Liabilities
	  				 				  				  				  			
	 HFT derivatives –
	  	$	4.4	  	 	 	Modelled pricing	  	  	 	Third-party pricing	  	  	 	$18.85 - $74.05	  	  	$	30.48	  
	 Power swaps and
	  				 				  	 	Own credit risk	  	  	 	0.00% - 0.01%	  	  	 	0.01%	  
	 physical contracts
	  	 	 	 	 	 	 	 	  	 	Discount rate	  	  	 	0.02% - 0.05%	  	  	 	0.03%	  
		  	 	0.2	  	 	 	Modelled pricing	  	  	 	Third-party pricing	  	  	 	$21.51 - $78.42	  	  	$	35.26	  
		  				 				  	 	Correlation factor	  	  	 	0.99% - 0.99%	  	  	 	0.99%	  
		  				 				  	 	Own credit risk	  	  	 	0.00% - 0.01%	  	  	 	0.01%	  
	 	  	 	 	 	 	 	 	 	  	 	Discount rate	  	  	 	0.02% - 0.11%	  	  	 	0.06%	  
	 HFT derivatives –
	  	 	74.7	  	 	 	Modelled pricing	  	  	 	Third-party pricing	  	  	 	$1.04 - $7.76	  	  	$	2.80	  
	 Natural gas swaps, futures,
	  				 				  	 	Own credit risk	  	  	 	0.00% - 0.03%	  	  	 	0.00%	  
	 forwards and physical contracts
	  	 	 	 	 	 	 	 	  	 	Discount rate	  	  	 	0.00% - 0.08%	  	  	 	0.02%	  
		  	 	21.3	  	 	 	Modelled pricing	  	  	 	Third-party pricing	  	  	 	$1.07 - $7.75	  	  	$	2.86	  
		  				 				  	 	Basis adjustment	  	  	 	-0.12% - 0.74%	  	  	 	0.18%	  
		  				 				  	 	Own credit risk	  	  	 	0.00% - 0.25%	  	  	 	0.00%	  
	 	  	 	 	 	 	 	 	 	  	 	Discount rate	  	  	 	0.00% - 0.07%	  	  	 	0.01%	  
	 Total liabilities
	  	 	100.6	  	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Net assets (liabilities)
	  	$	(74.5	) 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 

 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
	  	March 31, 2016	 	  	December 31, 2015	 
	  	Carrying
Amount	 	  	Fair Value	 	  	Carrying
Amount	 	  	Fair Value	 
	 Long-term debt (including current portion)
	  	$	3,986.8	  	  	$	4,579.7	  	  	$	4,008.6	  	  	$	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. 

  
 32 

	16.	 	REGULATORY ASSETS AND LIABILITIES 

 A summary of the Company’s regulatory assets and liabilities is provided
below. For a detailed description of the nature of the Company’s regulatory assets and liabilities, refer to Note 17 in Emera’s 2015 annual audited consolidated financial statements. 

 

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	  	December 31
2015	 
	 Regulatory assets
	  				  			
	 Deferred income tax regulatory asset
	  	$	457.9	  	  	$	431.3	  
	 Deferrals related to derivative instruments
	  	 	54.5	  	  	 	67.7	  
	 Unamortized defeasance costs
	  	 	44.0	  	  	 	45.7	  
	 2015 Demand side management deferral (note 5)
	  	 	35.6	  	  	 	36.4	  
	 Stranded cost recovery
	  	 	27.5	  	  	 	28.5	  
	 Pension and post-retirement medical plan
	  	 	10.8	  	  	 	11.9	  
	 Regulated fuel adjustment mechanism (note 5)
	  	 	8.5	  	  	 	13.7	  
	 Hydro-Quebec obligation
	  	 	7.0	  	  	 	7.6	  
	 2014 Maine storms
	  	 	5.8	  	  	 	6.1	  
	 Asset impairment recovery
	  	 	5.2	  	  	 	5.5	  
	 Purchased power contracts
	  	 	4.9	  	  	 	5.9	  
	 Stranded cost revenue & purchase power reconciliation deferrals
	  	 	4.6	  	  	 	6.1	  
	 Other
	  	 	31.0	  	  	 	33.1	  
		  	  
	  
	 	  	  
	  
	 
		  	$	697.3	  	  	$	699.5	  
		  	  
	  
	 	  	  
	  
	 
	 Current
	  	$	78.2	  	  	$	94.2	  
	 Long-term
	  	 	619.1	  	  	 	605.3	  
		  	  
	  
	 	  	  
	  
	 
	 Total regulatory assets
	  	$	697.3	  	  	$	699.5	  
		  	  
	  
	 	  	  
	  
	 
	 Regulatory liabilities
	  				  			
	 Deferrals related to derivative instruments
	  	$	131.3	  	  	$	209.9	  
	 Self-Insurance Fund
	  	 	81.8	  	  	 	86.8	  
	 Regulated fuel adjustment mechanism (note 5)
	  	 	55.1	  	  	 	42.0	  
	 Deferred income tax regulatory liabilities
	  	 	16.3	  	  	 	17.6	  
	 Other
	  	 	11.7	  	  	 	14.3	  
		  	  
	  
	 	  	  
	  
	 
		  	$	296.2	  	  	$	370.6	  
		  	  
	  
	 	  	  
	  
	 
	 Current
	  	$	75.0	  	  	$	98.9	  
	 Long-term
	  	 	221.2	  	  	 	271.7	  
		  	  
	  
	 	  	  
	  
	 
	 Total regulatory liabilities
	  	$	296.2	  	  	$	370.6	  
		  	  
	  
	 	  	  
	  
	 

 17. 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. Below are transactions between Emera and its associated companies reported in the Consolidated Statements of Income: 

  
 33 

													
	 For the

millions of Canadian dollars
	  	Three months ended
March 31	 
	 	  	 	  	 	  	2016	 	 	2015	 
		  	Nature of Service	  	Presentation	  				 			
	 Sales to:
	  		  		  				 			
	APUC subsidiary	  	Net sale of natural gas and transportation	  	Operating revenue – non-regulated	  	$	2.0	  	 	$	1.6	  
	 Purchases from:
	  		  		  				 			
	M&NP	  	Natural gas transportation capacity	  	Regulated fuel for generation and purchased power	  	 	0.3	  	 	$	0.2	  
	M&NP	  	Natural gas transportation capacity	  	Operating revenue – non-regulated	  	$	(8.1	) 	 	 	(6.3	) 

 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 $0.3 million for the three months ended March 31, 2016 (2015 – $(0.2) 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
	  	March 31
2016	 	  	December 31
2015	 
	 Due from related parties:
	  				  			
	 NSPML – current
	  	$	1.2	  	  	$	1.6	  
		  	  
	  
	 	  	  
	  
	 
	 Subsidiary of APUC – current
	  	 	0.3	  	  	 	0.7	  
	 M&NP – loan receivable – long-term
	  	 	2.5	  	  	 	2.5	  
		  	  
	  
	 	  	  
	  
	 
	 Due to related parties:
	  				  			
	 M&NP – current
	  	 	2.3	  	  	 	2.1	  
		  	  
	  
	 	  	  
	  
	 
	 Net due from (to) related parties
	  	$	1.7	  	  	$	2.7	  
		  	  
	  
	 	  	  
	  
	 

 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.
 18. OTHER CURRENT ASSETS 

Other current assets consisted of the following: 
  

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	  	December 31
2015	 
	 Net investment in direct financing lease
	  	$	5.5	  	  	$	5.4	  
	 Dividend receivable
	  	 	6.5	  	  	 	6.7	  
	 Capitalized transportation capacity (1)
	  	 	156.3	  	  	 	222.7	  
		  	  
	  
	 	  	  
	  
	 
		  	$	168.3	  	  	$	234.8	  
		  	  
	  
	 	  	  
	  
	 

  

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

 19. 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, Massachusetts, Rhode Island, Barbados, Dominica and Grand Bahama Island. 

  
 34 

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

 

									
	 For the

millions of Canadian dollars
	  	Three months ended
March 31	 
	  	2016	 	 	2015	 
	 Defined benefit pension plans
	  				 			
	 Service cost
	  	$	5.5	  	 	$	5.5	  
	 Interest cost
	  	 	15.1	  	 	 	14.6	  
	 Expected return on plan assets
	  	 	(16.8	) 	 	 	(16.0	) 
	 Current year amortization of:
	  				 			
	 Actuarial losses (gains)
	  	 	10.5	  	 	 	11.8	  
	 Past service costs (gains)
	  	 	(0.2	) 	 	 	(0.2	) 
		  	  
	  
	 	 	  
	  
	 
	 Total defined benefit pension plans
	  	 	14.1	  	 	 	15.7	  
		  	  
	  
	 	 	  
	  
	 
	 Non-pension benefits plan
	  				 			
	 Service cost
	  	 	0.7	  	 	 	0.8	  
	 Interest cost
	  	 	0.9	  	 	 	1.0	  
	 Expected return on plan assets
	  	 	(0.1	) 	 	 	—  	  
	 Current year amortization of:
	  				 			
	 Actuarial losses (gains)
	  	 	0.5	  	 	 	0.3	  
	 Past service costs (gains)
	  	 	(2.1	) 	 	 	(0.5	) 
	 Total non-pension benefits plans
	  	 	(0.1	) 	 	 	1.6	  
		  	  
	  
	 	 	  
	  
	 
	 Total defined benefit plans
	  	$	14.0	  	 	$	17.3	  
		  	  
	  
	 	 	  
	  
	 

 20. 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, these investments include debt and equity investments related to Emera Reinsurance Limited, for captive insurance purposes. 

Available-for-sale financial assets are measured at fair value and classified in the fair value hierarchy as follows: 

 

																					
	 As at

millions of Canadian dollars
	  	March 31	 
	  	NAV (1)	 	  	Level 1	 	  	Level 2	 	  	Level 3	 	  	2016	 
	 Common shares
	  	 	—  	  	  	$	15.8	  	  	$	—  	  	  	$	—  	  	  	$	15.8	  
	 Corporate bonds, debentures, short and medium term notes
	  	 	—  	  	  	 	—  	  	  	 	29.1	  	  	 	—  	  	  	 	29.1	  
	 Government bonds
	  	 	—  	  	  	 	—  	  	  	 	10.9	  	  	 	—  	  	  	 	10.9	  
	 Other investments measured at NAV
	  	 	50.4	  	  				  				  				  	 	50.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	$	50.4	  	  	$	15.8	  	  	$	40.0	  	  	$	—  	  	  	$	106.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		
	 As at

millions of Canadian dollars
	  	December 31	 
	  	NAV (1)	 	  	Level 1	 	  	Level 2	 	  	Level 3	 	  	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	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	(1)	Certain investments are permitted to be measured at fair value using the net asset value (“NAV”) per share practical expedient under USGAAP accounting standards. 

  
 35 

 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 2 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 primary pricing inputs in determining the equity and fixed assets mutual
funds are the mutual funds’ NAVs. The funds are open-ended mutual funds, and there are no trading restrictions on the funds. 
 The change in available-for-sale
assets is as follows: 
  

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	 	December 31
2015	 
	 Balance, beginning of the year
	  	$	116.0	  	 	$	84.4	  
	 Additions
	  	 	—  	  	 	 	34.5	  
	 Disposals
	  	 	(3.5	) 	 	 	(16.5	) 
		  	  
	  
	 	 	  
	  
	 
		  	$	112.5	  	 	$	102.4	  
		  	  
	  
	 	 	  
	  
	 
	 Change in fair value
	  				 			
	 Gain (loss) recognized in other comprehensive income during the period
	  	 	(6.3	) 	 	 	13.6	  
		  	  
	  
	 	 	  
	  
	 
		  	$	(6.3	) 	 	$	13.6	  
		  	  
	  
	 	 	  
	  
	 
	 Balance, end of the period
	  	$	106.2	  	 	$	116.0	  
		  	  
	  
	 	 	  
	  
	 

 There were no impairment provisions for available-for-sale investments for the three months ended March 31, 2016 (2015 –
nil). 
 The maturity profile of debt securities included in the available-for-sale assets is as follows: 

 

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	  	December 31
2015	 
	 Maturity within 1 year
	  	$	15.9	  	  	$	20.0	  
	 Maturity in 1-5 years
	  	 	24.1	  	  	 	26.3	  
		  	  
	  
	 	  	  
	  
	 
		  	$	40.0	  	  	$	46.3	  
		  	  
	  
	 	  	  
	  
	 

 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. 
 21. OTHER CURRENT LIABILITIES 

Other current liabilities consisted of the following: 
  

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	  	December 31
2015	 
	 Accrued charges
	  	$	107.3	  	  	$	130.1	  
	 Accrued interest on long-term debt
	  	 	40.8	  	  	 	44.1	  
	 Sales taxes payable
	  	 	13.6	  	  	 	4.2	  
	 Accrued interest on convertible debentures represented by instalment receipts
	  	 	11.2	  	  	 	11.2	  
	 Emission credits obligations (1)
	  	 	1.8	  	  	 	6.3	  
	 Other
	  	 	8.0	  	  	 	8.4	  
		  	  
	  
	 	  	  
	  
	 
		  	$	182.7	  	  	$	204.3	  
		  	  
	  
	 	  	  
	  
	 

  

	(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 13) when purchased and subsequently applied against the emission liabilities at the end of each compliance period. 

  
 36 

 22. 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 per cent convertible unsecured subordinated debentures, represented by instalment receipts. 

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. 

Approximately $21.9 million ($15.1 million after-tax) (2015 – nil) in interest expense associated with the Debentures was recognized in Q1 2016. 

For a detailed description of the terms of the Debentures, refer to Note 30 in Emera’s annual audit consolidated financial statements. 

23. OTHER LONG-TERM LIABILITIES 
 Other long-term liabilities consisted of the
following: 
  

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	  	December 31
2015	 
	 Funds received in excess of equity investment (1)
	  	$	209.5	  	  	$	225.0	  
	 Long-term service agreements
	  	 	30.6	  	  	 	37.7	  
	 Emission credits obligations (2)
	  	 	7.7	  	  	 	6.3	  
	 Other
	  	 	24.5	  	  	 	29.5	  
		  	  
	  
	 	  	  
	  
	 
		  	$	272.3	  	  	$	298.5	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	Emera has a 50 per cent investment in Bear Swamp. The investment balance in Bear Swamp is a credit 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 (“RGGI”) 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 13) when purchased and subsequently applied against the emission liabilities at the end of each compliance period. 

24. COMMITMENTS AND CONTINGENCIES 
 A. Commitments 

As at March 31, 2016, 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: 

  
 37 

																													
	 millions of Canadian dollars
	  	2016	 	  	2017	 	  	2018	 	  	2019	 	  	2020	 	  	Thereafter	 	  	Total	 
	 Purchased power (1)
	  	$	166.5	  	  	$	229.8	  	  	$	204.0	  	  	$	198.7	  	  	 	195.2	  	  	$	2,380.5	  	  	$	3,374.7	  
	 Solid fuel supply
	  	 	114.5	  	  	 	75.7	  	  	 	12.0	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	202.2	  
	 DSM
	  	 	22.1	  	  	 	34.0	  	  	 	34.9	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	91.0	  
	 Transportation (2)
	  	 	188.9	  	  	 	118.6	  	  	 	78.2	  	  	 	43.2	  	  	 	41.1	  	  	 	86.3	  	  	 	556.3	  
	 Long-term service agreements (3)
	  	 	48.6	  	  	 	49.6	  	  	 	34.4	  	  	 	47.1	  	  	 	20.4	  	  	 	202.1	  	  	 	402.2	  
	 Capital projects
	  	 	69.2	  	  	 	5.6	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	74.8	  
	 Equity investment commitments (4)
	  	 	356.0	  	  	 	183.0	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	539.0	  
	 Leases and other (5)
	  	 	18.9	  	  	 	9.9	  	  	 	9.0	  	  	 	8.4	  	  	 	7.3	  	  	 	19.0	  	  	 	72.5	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
		  	$	984.7	  	  	$	706.2	  	  	$	372.5	  	  	$	297.4	  	  	$	264.0	  	  	$	2,687.9	  	  	$	5,312.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

	(1)	Annual requirement to purchase 20 to 100 per cent of electricity production from independent power producers over varying contract lengths up to 25 years. 

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

	(3)	Maintenance of certain generating equipment, services related to a generation facility and wind operating agreements, outsourced management of computer and communication infrastructure and vegetation management.

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

	(5)	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 12 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 sought 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.
 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 

  
 38 

 
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 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. 

On March 22, 2016, the Administrative Law Judge (“ALJ”) issued a recommended decision 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 commencing December 27, 2012 and July 31, 2014 respectively. The recommendation for the ENE Case was a 9.59 per cent base ROE, with a 10.42 per cent maximum
ROE, and the recommendation for MA AG II Case was a 10.90 per cent base ROE, with a 12.19 per cent maximum ROE. 
 On April 29, 2016, an additional
complaint was filed with FERC challenging the ROE under the ISO-NE transmission tariff. The complaint was filed by the Eastern Massachusetts Consumer-Owned Systems (“EMCOS”), a collection of thirteen municipal light departments,
seeking to reduce the base transmission ROE to a maximum of 8.93 per cent and the maximum ROE of 11.24 per cent.
 Emera Maine has recorded a reserve of
$5.8 million pre-tax ($4.5 million USD) (December 31, 2015 – $6.9 million or $5.0 million USD) for the first two base transmission ROE rate refund complaints. 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. The reserve was calculated on a 10.57 per cent base
and represents Emera Maine’s best estimate of the probable outcome. No update has been made to the reserve, as a result of the ALJ recommendation as it is pending approval by the FERC and is considered uncertain until that time. No reserve has
been made as a result of the EMCOS complaint, as the outcome is considered uncertain. 
 Other Legal Proceedings 

Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the
Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company. 
 C. Environment

  
 39 

 
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 $29.4 million during fiscal 2016 and are
estimated to be $55.9 million from 2017 through 2020. Amounts that have been committed to are included in “Capital projects” in the commitments table in note 24A. 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 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 March 31, 2016. 
 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 March 31, 2016, approximately $21.1 million (December 31, 2015 – $19.7 million) has been spent to date. NSPI has recognized an ARO
of $14.9 million as at March 31, 2016 (December 31, 2015 – $15.0 million) associated with the PCB phase-out program. 
 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. 
 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. 
 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 

  
 40 

 
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. 

On April 13, 2016, in association with a distribution rate application, the MPUC ordered an audit of Emera Maine’s implementation of its new customer
information system and customer service performance, including billing and reliability. The audit is expected to commence in Q2 2016 and conclude in the second half of 2016. 

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
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.

  
 41 

 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. 

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 pending 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. 
 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 pending 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 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. 

  
 42 

 E. Guarantees and Letters of Credit 

There were no changes in Emera’s standby letters of credit since December 31, 2015. 

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

									
	 Issued and outstanding:
	  	millions of shares	 	  	millions of
Canadian dollars	 
	 Balance, December 31, 2015
	  	 	147.21	  	  	$	2,157.5	  
	 Issuance of common stock (1)
	  	 	0.06	  	  	 	2.7	  
	 Issued for cash under Purchase Plans at market rate
	  	 	0.58	  	  	 	26.2	  
	 Discount on shares purchased under Dividend Reinvestment Plan
	  	 	—  	  	  	 	(1.2	) 
	 Options exercised under senior management share option plan
	  	 	0.50	  	  	 	13.6	  
	 Stock-based compensation
	  	 	—  	  	  	 	0.2	  
		  	  
	  
	 	  	  
	  
	 
	 Balance, March 31, 2016
	  	 	148.35	  	  	$	2,199.0	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	During the three months ended March 31 2016, Emera issued 0.06 million common shares to facilitate the creation and issuance of 0.2 million depositary receipts in connection with the ECI amalgamation
transaction. The depositary receipts are listed on the Barbados Stock Exchange. 

 26. NON-CONTROLLING INTEREST IN SUBSIDIARIES 

Non-controlling interest in subsidiaries consisted of the following: 
  

									
	 As at

millions of Canadian dollars
	  	March 31
2016	 	  	December 31
2015	 
	 ICDU
	  	$	48.8	  	  	$	51.8	  
	 Preferred shares of GBPC
	  	 	33.5	  	  	 	33.5	  
	 Domlec (1)
	  	 	22.5	  	  	 	48.3	  
	 Preferred shares of Emera Maine
	  	 	0.4	  	  	 	0.4	  
		  	  
	  
	 	  	  
	  
	 
		  	$	105.2	  	  	$	134.0	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	On March 22, 2016, an indirect wholly-owned subsidiary of Emera acquired 0.7 million ECI shares, increasing Emera’s ownership interest from 95.5 to 100 per cent. 

27. VARIABLE INTEREST ENTITIES 
 The Company performs ongoing analysis to
assess whether it holds any 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 three months ended March 31, 2016, 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, 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 records the Maritime Link Project as an equity investment.

  
 43 

 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. 
 Emera’s consolidated VIE in the BLPC SIF 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

millions of Canadian dollars
	  	March 31, 2016	 	  	December 31, 2015	 
	  	Total
assets	 	  	Maximum
exposure to loss	 	  	Total
assets	 	  	Maximum
exposure to loss	 
	 Consolidated VIE
	  				  				  				  			
	 BLPC SIF
	  	$	95.9	  	  	$	95.9	  	  	$	101.4	  	  	$	101.4	  
	 Unconsolidated VIEs in which Emera has variable interests
	  				  				  				  			
	 NSPML (equity accounted)
	  	 	206.4	  	  	 	917.0	  	  	 	187.6	  	  	 	1,007.0	  

 28. 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. 
 29.
SUBSEQUENT EVENTS 
 These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through
May 9, 2016, the date the financial statements were issued. 

  
 44

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