EX-4.5



 Exhibit 4.5 
  





 
 Management’s Discussion & Analysis 

As at May 9, 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 first quarter of 2016 relative to 2015; and its financial position as at
March 31, 2016 relative to December 31, 2015. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is also 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 unaudited condensed consolidated interim financial statements and supporting notes as at and for the three months ended March 31, 2016; and the Emera Incorporated annual
MD&A and 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 and investments 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, Dominica (“IRC”)

		
	 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 the Emera Maine and Emera Caribbean sections of the
MD&A, which are reported in US dollars (“USD”), unless otherwise stated. 

  
 1 








 Additional information related to Emera, including the Company’s Annual Information Form, can be found on
SEDAR at www.sedar.com. 
 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; 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;
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, 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”);


  

	 	•	 	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 in NSPML and LIL; 

  

	 	•	 	Emera Reinsurance Limited; 

  

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

  

	 	•	 	Other investments 

 The Liquidity and Capital Resources, including Consolidated Cash Flow Highlights, Outlook,
Transactions with Related Parties, Risk Management and 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, 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 is targeting eight-per-cent annual dividend growth through 2019. 

Regulated utilities are the foundation of Emera’s business, providing the Company with strong and consistent earnings. At the core of Emera’s
utilities strategy is identifying opportunities to invest in the transition from higher-carbon methods of electricity generation to lower-carbon alternatives. NSPI has invested in wind energy, biomass and hydroelectricity and is on track to meet a
minimum 40 per cent renewable standard by 2020. In the Caribbean, Emera is similarly focused on introducing cleaner generation alternatives, with an emphasis on affordability and fuel cost stability for its customers. 

Emera is investing in electricity transmission to help deliver new renewable energy to market. Emera’s ownership in the Maritime Link Project will
contribute to the transformation of the electricity market in the Atlantic Provinces, enabling growth in the availability of clean, renewable energy for the region. In addition, the Atlantic Provinces will be connected to the northeastern United
States, providing potential for excess renewable energy to be delivered throughout that region. 

  
 3 








 Since its formation in 2003, Emera Energy has become an active participant in the northeastern United States
electricity and natural gas market. It has built a strong marketing, trading and asset management business, based on comprehensive market knowledge, focus on customer service and robust risk management. The integration and performance of the three
New England Gas Generating Facilities purchased in 2013 has contributed significantly to the success of Emera Energy. 
 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. At the core of Emera’s strategy is the ability to leverage these particular linkages and adjacencies to create solutions for customers and investment opportunities for the Company. 

The foundation of Emera’s strategy is its collaborative approach to strategic partnerships, its ability to find creative solutions to work within and
across multiple jurisdictions, and its experience dealing with complex projects and investment structures. The Company will continue to make investments in its regulated utilities to benefit customers and focus on providing rate stability for
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 adjusted net income and cash flows, Emera employs operating and governance models that focus on safety and 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
which is reflective of the Company’s risk tolerance. 
 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 Company’s strategic target. Specifically, the lower percentage of adjusted net income was 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. It was not the result of a change in Emera’s risk tolerance, nor is it from additional capital allocations to non-regulated businesses.
Rather, it was the result of strong operating and financial performance of existing non-regulated investments and businesses. Following the close of the pending TECO Energy acquisition, the Company is expected to achieve its adjusted net income
target. 
 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 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-

  
 4 








 
market adjustments 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 an adjusted net income measure by excluding the effect of: 
  

	 	•	 	the mark-to-market adjustments related to Emera’s held-for-trading (“HFT”) derivative instruments, including adjustments related to the price differential between the point where natural gas is sourced
and where it is delivered; 

  

	 	•	 	the mark-to-market adjustments included in Emera’s equity income related to the business activities of Bear Swamp; 

  

	 	•	 	the amortization of transportation capacity recognized as a result of certain Emera Energy marketing and trading 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 pending TECO Energy acquisition related USD-denominated currency and forward contracts. These contracts were put in place to
economically hedge the anticipated proceeds from the 2015 sale of $2.1 billion four per cent convertible unsecured subordinated debentures represented by instalment receipts (“the Debenture Offering” or “Debentures” or
“Convertible Debentures”) 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 and the ongoing operations of the business, and allows investors to better understand
and evaluate the business. Management and the Board of Directors use this non-GAAP measure for evaluation of performance and incentive compensation. 

Mark-to-market adjustments are further discussed in the Consolidated Financial Highlights section, Emera Energy – Review of 2016, Pipelines – Review
of 2016 and Corporate and Other – Review of 2016. 

  
 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	  	Three months ended March 31	 
	 millions of Canadian dollars (except per share amounts)
	  	2016	 	  	2015	 
	 Net income attributable to common shareholders
	  	$	44.3	  	  	$	160.1	  
	 After-tax mark-to-market gain (loss)
	  	$	(75.9	) 	  	$	(11.5	) 
	 Adjusted net income attributable to common shareholders
	  	$	120.2	  	  	$	171.6	  
	 Earnings per common share – basic
	  	$	0.30	  	  	$	1.10	  
	 Adjusted earnings per common share – basic
	  	$	0.81	  	  	$	1.18	  

 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. EBITDA is useful to assess Emera’s operating performance and indicates the Company’s ability to service or incur debt, make capital expenditures and finance
working capital requirements. 
 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	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 	  	2016	 	  	2015	 
	 Net income
	  	$	54.8	  	  	$	174.1	  
	 Interest expense, net
	  	 	75.2	  	  	 	44.4	  
	 Income tax expense (recovery)
	  	 	26.8	  	  	 	61.4	  
	 Depreciation and amortization
	  	 	87.5	  	  	 	82.8	  
	 EBITDA
	  	 	244.3	  	  	 	362.7	  
	 Mark-to-market gain (loss), excluding income tax and interest
	  	 	(75.1	) 	  	 	(21.5	) 
		  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	319.4	  	  	$	384.2	  
		  	  
	  
	 	  	  
	  
	 

 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
these 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. 

  
 6 








 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 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 
 2016 

After-Tax Mark-to-Market Losses 
 After-tax mark-to-market
losses increased $64.4 million to $75.9 million in Q1 2016 compared to $11.5 million in Q1 2015 primarily due to reversal of the 2015 gain on USD-denominated currency and forward contracts related to the financing of the pending TECO Energy
acquisition and the amortization of 2015 Emera Energy gas transportation assets. This increase was partially offset by the reversal of 2015 mark-to-market losses and changes in gas and power contract positions at Emera Energy. 

Acquisition Related Costs 
 Emera incurred after-tax costs
of $17.5 million ($0.12 per common share) in Q1 2016 (2015 – nil) related to its pending acquisition of TECO Energy, including legal, advisory, and financing costs. 

As discussed and included above in “After-Tax Mark-to-Market Losses”, the foreign currency earnings effect related to the Debenture Offering USD
cash balance and the forward contracts were recorded as a mark-to-market after-tax loss of $121.1 million in “Other income (expenses), net” in Q1 2016 (2015 – nil). 

2015 
 Sale of Northeast Wind Partnership II, LLC
(“NWP”) 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. 

CONSOLIDATED FINANCIAL REVIEW 
 In Q1 2016, Emera
affiliates in the northeastern United States and Atlantic Canada experienced less demand for electricity as a result of unseasonably warm weather. Specifically, NSPI, Emera Maine and Emera Energy’s New England Gas Generating Facilities results
were affected. Below is a table highlighting significant changes between adjusted net income from 2015 to 2016. 

  
 7 









					
	For the	 	Three months ended	 
	 millions of Canadian dollars
	 	March 31	 
	 Adjusted net income – 2015
	 	$	171.6	  
	 Emera Energy (largely due to New England Gas Generation Facilities) (1)
	 	 	(17.0	) 
	 Acquisition and financing costs relating to the pending acquisition of TECO Energy (1)
	 	 	(17.5	) 
	 NSPI
	 	 	(15.5	) 
	 2015 gain on the sale of NWP
	 	 	(11.5	) 
	 Increased equity earnings from NSPML and LIL
	 	 	3.8	  
	 Other (1)
	 	 	6.3	  
		 	  
	  
	 
	 Adjusted net income – 2016
	 	$	120.2	  
		 	  
	  
	 

  

	(1)	These numbers include the impact of the stronger USD. 

 Consolidated Financial Highlights 

 

									
	For the	  	Three months ended March 31	 
	 millions of Canadian dollars (except per share amounts)
	  	2016	 	  	2015	 
	 Operating revenues
	  	$	877.0	  	  	$	888.5	  
	 Income from operations
	  	 	270.0	  	  	 	232.1	  
	 Net income attributable to common shareholders
	  	 	44.3	  	  	 	160.1	  
	 After-tax mark-to-market gain (loss)
	  	 	(75.9	) 	  	 	(11.5	) 
	 Adjusted net income attributable to common shareholders
	  	 	120.2	  	  	 	171.6	  
	 Earnings per common share – basic
	  	$	0.30	  	  	$	1.10	  
	 Earnings per common share – diluted
	  	$	0.30	  	  	$	1.09	  
	 Adjusted earnings per common share – basic
	  	$	0.81	  	  	$	1.18	  
		  	  
	  
	 	  	  
	  
	 
	 Dividends per common share declared
	  	$	0.4750	  	  	$	0.3875	  
		  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	319.4	  	  	$	384.2	  
		  	  
	  
	 	  	  
	  
	 
		
	For the	  	Three months ended March 31	 
	 millions of Canadian dollars (except per share amounts)
	  	2016	 	  	2015	 
	 Operating Unit Contributions to Adjusted Net Income
	  				  			
	 NSPI
	  	$	52.5	  	  	$	68.0	  
	 Emera Maine
	  	 	9.3	  	  	 	11.5	  
	 Emera Caribbean
	  	 	9.8	  	  	 	8.8	  
	 Pipelines
	  	 	9.7	  	  	 	9.9	  
	 Emera Energy
	  	 	47.9	  	  	 	76.4	  
	 Corporate and Other
	  	 	(9.0	) 	  	 	(3.0	) 
	 Adjusted net income attributable to common shareholders
	  	$	120.2	  	  	$	171.6	  
	 After-tax mark-to-market gain (loss)
	  	 	(75.9	) 	  	 	(11.5	) 
		  	  
	  
	 	  	  
	  
	 
	 Net income attributable to common shareholders
	  	$	44.3	  	  	$	160.1	  
		  	  
	  
	 	  	  
	  
	 
		
	For the	  	Three months ended March 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Operating cash flow before changes in working capital
	  	$	232.4	  	  	$	257.5	  
	 Change in working capital
	  	 	(51.8	) 	  	 	(137.9	) 
	 Operating cash flow
	  	$	180.6	  	  	$	119.6	  
	 Investing cash flow
	  	$	(139.3	) 	  	$	195.9	  
		  	  
	  
	 	  	  
	  
	 
	 Financing cash flow
	  	$	(45.8	) 	  	$	(259.3	) 
		  	  
	  
	 	  	  
	  
	 
			
	As at	  	March 31	 	  	December 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Working capital
	  	$	580.3	  	  	$	599.2	  
	 Total assets
	  	$	11,448.6	  	  	$	11,950.0	  


  
 8 








 Q1 Consolidated Income Statement and Operating Cash Flow Highlights 

Operational Results 
 Income from operations increased
$37.9 million to $270.0 million in Q1 2016 compared to $232.1 million in Q1 2015 primarily due to mark-to-market increases of $91.7 million, the impact of a stronger USD and increased marketing and trading margin at Emera Energy. This was partially
offset by decreased margin at the New England Gas Generating Facilities and decreased income from operations at NSPI. 
 Details of the operating revenues
and operating expenses line item variances are described below: 
 Total operating revenues decreased 1.3 per cent to $877.0 million in Q1 2016
compared to $888.5 million in Q1 2015 primarily due to: 
  

	 	•	 	mark-to-market changes increased operating revenues by $95.9 million. 

  

	 	•	 	a $60.1 million decrease at the New England Gas Generating Facilities reflecting lower hedged and market commodity prices and decreased sales volumes due to weather; 


 

	 	•	 	a $49.0 million decrease in NSPI revenues as a result of lower sales volumes due to weather; 

  

	 	•	 	a $10.5 million decrease at Bayside primarily due to lower power prices; 

  

	 	•	 	a $10.4 million increase at Emera Maine primarily due to the impact of a stronger USD; 

  

	 	•	 	an $8.1 million increase in marketing and trading margin at Emera Energy primarily due to the impact of a stronger USD and growth in the volume of business. 


Total operating expenses decreased 7.5 per cent to $607.0 million in Q1 2016 compared to $656.4 million in Q1 2015. This was primarily the result of
decreased fuel costs at NSPI and New England Gas Generating Facilities reflecting lower commodity prices and decreased sales volumes due to weather, partially offset by higher operating, maintenance and general expenses (“OM&G”) at
NSPI reflecting increased storm costs, and the impact of a stronger USD. 
 Other income (expenses), net 

Other income decreased $161.1 million to $(139.2) million in Q1 2016 compared to $21.9 million in Q1 2015. This was primarily due to mark-to-market losses
relating to the effect of USD-denominated currency and forward contracts put into place to economically hedge anticipated proceeds from the Debenture Offering financing and the 2015 gain on the sale of NWP. 

Interest expense, net 
 Interest expense increased $30.8
million to $75.2 million in Q1 2016 compared to $44.4 million in Q1 2015 primarily due to interest on convertible debentures represented by instalment receipts related to the pending acquisition of TECO Energy. 

Income tax expense (recovery) 
 Income tax expense
decreased $34.6 million to $26.8 million in Q1 2016 compared to $61.4 million in Q1 2015. This was primarily due to decreased income before provision for income taxes including mark-to-market adjustments, partially offset by the non-deductible
portion of TECO Energy related mark-to-market losses on USD-denominated currency and forward contracts related to the pending acquisition. 

  
 9 








 Operating Activities 

Net cash provided by operating activities increased $61.0 million to $180.6 million in Q1 2016 compared to $119.6 million in Q1 2015. Cash from operations
before changes in working capital decreased by $25.1 million primarily due to decreased margin at the New England Gas Generating Facilities and the payment of financing costs related to the pending acquisition of TECO Energy. 

Changes in working capital increased operating cash flows by $86.1 million primarily due to favourable changes in accounts receivable reflecting lower sales
volumes at NSPI and favourable changes in inventory reflecting the purchase of emission credits by the New England Gas Generating Facilities in 2015. 

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)
	  	Q1 2016 vs Q1 2015	 	  	Q1 2015 vs Q1 2014	 
	 Impact on income from continuing operations
	  				  			
	 Total operating revenues
	  	$	48.5	  	  	$	43.3	  
	 Total operating expenses
	  	 	(25.7	) 	  	 	(32.5	) 
	 Net income
	  	 	15.8	  	  	 	9.2	  
	 Adjusted net income
	  	 	7.2	  	  	 	11.0	  
	 Impact on earnings per share
	  				  			
	 Basic
	  	$	0.11	  	  	$	0.06	  
	 Basic -adjusted
	  	$	0.05	  	  	$	0.08	  

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

 

													
	 	  	Three months ended March 31	 
	 Average equivalent of $1.00 USD
	  	2016	 	  	2015	 	  	2014	 
	 CAD
	  	 	1.38	  	  	 	1.24	  	  	 	1.10	  


  
 10 








 Consolidated Balance Sheets Highlights 

Significant changes in the consolidated balance sheets between December 31, 2015 and March 31, 2016 include: 

 

							
	 	  	Increase	 	 	 
	 millions of Canadian dollars
	  	(Decrease)	 	 	 Explanation

	Assets	  				 	
	Cash and cash equivalents	  	$	(73.9	) 	 	Decreased primarily due to the impact of a stronger CAD
	Receivables, net	  	 	32.9	  	 	Increased due to seasonal trends of business at NSPI and Emera Energy
	Inventory	  	 	(53.5	) 	 	Decreased primarily due to lower fuel inventory volumes as a result of consumption and lower commodity pricing at NSPI
	Derivative instruments (current and long-term)	  	 	(239.3	) 	 	Decreased primarily due to the effect of a stronger CAD and settlements of derivative instruments at Emera Energy and NSPI
	Prepaid expenses	  	 	22.1	  	 	Increased primarily due to timing of provincial grants in lieu of taxes and insurance payments at NSPI
	Property, plant and equipment, net of accumulated depreciation	  	 	(173.1	) 	 	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries and depreciation, offset by additions
	Investments subject to significant influence	  	 	64.4	  	 	Increased primarily due to increased investments in LIL and NSPML
	Other assets (current and long-term)	  	 	(70.2	) 	 	Decreased primarily due to the amortization of transportation/storage capacity assets at Emera Energy
	Liabilities and Equity	  				 	
	Short-term debt and long-term debt (including current portion)	  	 	(27.5	) 	 	Decreased primarily due to the effect of a stronger CAD on debt held by foreign subsidiaries
	Accounts payable	  	 	(22.7	) 	 	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries
	Derivative instruments (current and long-term)	  	 	(218.2	) 	 	Decreased primarily due to settlements of natural gas and power contracts at Emera Energy
	Regulatory liabilities (current and long-term)	  	 	(74.4	) 	 	Decreased primarily due to changes in regulated derivatives, partially offset by an increased FAM regulatory liability at NSPI
	Other liabilities (current and long-term)	  	 	(47.8	) 	 	Decreased primarily due to the effect of a stronger CAD on the Bear Swamp investment, payment of restructuring costs at Emera Caribbean and timing of accruals
	Common stock	  	 	41.5	  	 	Increased primarily due to issuance of common stock for the dividend reinvestment program
	Accumulated other comprehensive income	  	 	(130.7	) 	 	Decreased primarily due to the effect of a stronger CAD on the translation of Emera’s foreign subsidiaries
	Retained earnings	  	 	(25.7	) 	 	Decreased due to dividends payments in excess of net income
	Non-controlling interest in subsidiaries	  	 	(28.8	) 	 	Decreased due to increased ownership by Emera in ECI

 Developments 
 Emera

 Pending Acquisition of TECO Energy 
 On
September 4, 2015, the Company announced a definitive agreement (“the acquisition agreement”) for Emera to acquire TECO Energy (NYSE:TE) (“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. 

  
 11 








 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., a regulated gas distribution utility which serves more than 515,000 customers across New Mexico. 
 The
Transaction is expected to close mid-2016. Closing of the pending acquisition remains 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 New Mexico Gas Co. 

The Stipulation Agreement sets out a number of Emera’s commitments including honouring commitments made by TECO Energy in its 2014 acquisition case,
investing in the expansion of the natural gas system to underserved communities and the Mexican border, and providing resources to support certain economic growth projects and programs. The Stipulation Agreement is subject to review and approval by
the NMPRC. The hearing for Emera’s pending acquisition of TECO Energy occurred on May 2, 2016. A decision is expected mid-2016. 
 On
March 23, 2016, The Committee on Foreign Investment in the United States approval was received. 
 ECI Amalgamation 

On February 24, 2016, the common shareholders of ECI approved an amalgamation transaction, which resulted in an Emera wholly owned subsidiary owning all
common shares of ECI. Prior to this, Emera held 95.5 per cent of ECI’s common shares.
 To effect the amalgamation, all issued and
outstanding common shares of ECI were converted to Class A redeemable preferred shares. In Q1 2016, the Class A redeemable preferred shares of ECI not owned were redeemed. Minority ECI shareholders could elect to receive $23.26 ($33.30
Barbadian dollars (“BBD”)) in cash per common share (“Cash Offer”) or 2.1 Depositary Receipts (“DR”) per common share, with each DR representing one quarter of a common share of Emera (“DR Offer”); or a
combination of the two offers. The total consideration paid to redeem the minority interest was $15.3 million ($23.4 million BBD), consisting of $14.4 million of the Cash Offer ($22.0 million BBD) and $0.9 million of the DR Offer ($1.4 million
BBD). The amalgamated entity retained the name Emera (Caribbean) Incorporated. 
 Recent Financing Activity 

NSPI 
 On April 28, 2016, NSPI increased its committed
syndicated revolving bank line of credit to $600 million from $500 million. The increase will support ongoing business requirements and general corporate purposes. 

  
 12 








 OUTSTANDING COMMON STOCK DATA 
  

									
	Common stock	  	millions of	 	  	millions of Canadian	 
	 Issued and outstanding:
	  	shares	 	  	dollars	 
	 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	  
	 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 stock option plan
	  	 	0.50	  	  	 	13.6	  
	 Employee Share Purchase Plan
	  	 	—  	  	  	 	0.2	  
		  	  
	  
	 	  	  
	  
	 
	 March 31, 2016
	  	 	148.35	  	  	$	2,199.0	  
		  	  
	  
	 	  	  
	  
	 

  

	1)	During the three months ended March 31 2016, Emera issued 0.06 million (2015 - 1.25 million) common shares to facilitate the creation and issuance of an additional 0.2 million (2015 - 5 million)
depositary receipts in connection with the ECI amalgamation transaction. The depositary receipts are listed on the Barbados Stock Exchange. 


As at April 25, 2016, the amount of issued and outstanding common shares was 148.4 million. 

The weighted average shares of common stock outstanding – basic, which includes both issued, outstanding common stock and outstanding deferred share
units, for the three months ended March 31, 2016 was 148.7 million (2015 – 144.9 million). 

  
 13 








 NSPI 

Overview 
 NSPI is a fully-integrated regulated electric
utility with assets of approximately $4.6 billion. It is the primary electricity supplier in Nova Scotia providing electricity generation, transmission and distribution services to approximately 507,000 customers. NSPI’s target regulated return
on equity (“ROE”) range is currently 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. 

Review of 2016 
 NSPI Net Income 

 

									
	For the	  	Three months ended
March 31	 
	 millions of Canadian dollars (except per share amounts)
	  	2016	 	  	2015	 
	 Operating revenues – regulated
	  	$	397.5	  	  	$	446.5	  
	 Regulated fuel for generation and purchased power (1)
	  	 	141.5	  	  	 	189.4	  
	 Regulated fuel adjustment mechanism and fixed cost deferrals
	  	 	17.6	  	  	 	(7.2	) 
	 Operating, maintenance and general
	  	 	87.4	  	  	 	79.6	  
	 Provincial grants and taxes
	  	 	9.7	  	  	 	9.6	  
	 Depreciation and amortization
	  	 	48.4	  	  	 	51.5	  
	 Total operating expenses
	  	 	304.6	  	  	 	322.9	  
	 Income from operations
	  	 	92.9	  	  	 	123.6	  
	 Other expenses, net
	  	 	1.3	  	  	 	3.8	  
	 Interest expense, net
	  	 	31.0	  	  	 	28.8	  
	 Income before provision for income taxes
	  	 	60.6	  	  	 	91.0	  
	 Income tax expense (recovery)
	  	 	8.1	  	  	 	21.0	  
	 Net income of Nova Scotia Power Inc.
	  	 	52.5	  	  	 	70.0	  
	 Preferred stock dividends
	  	 	—  	  	  	 	2.0	  
	 Contribution to consolidated net income
	  	$	52.5	  	  	$	68.0	  
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share
	  	$	0.35	  	  	$	0.47	  
		  	  
	  
	 	  	  
	  
	 
	 EBITDA
	  	$	140.0	  	  	$	171.3	  
		  	  
	  
	 	  	  
	  
	 

  

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


In Q1 2016, NSPI’s contribution to consolidated net income decreased $15.5 million to $52.5 million compared to $68.0 million in Q1 2015. 

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

					
	For the	 	Three months ended	 
	 millions of Canadian dollars
	 	March 31	 
	 Contribution to consolidated net income – 2015
	 	$	68.0	  
	 Decreased electric margin (see Electric Margin section below for explanation)
	 	 	(19.5	) 
	 Increased operating, maintenance and general (“OM&G”) expenses primarily due to
higher maintenance and storm costs, partially offset by decreased demand side management (“DSM”) program costs
	 	 	(7.8	) 
	 Decreased fixed cost deferrals primarily due to 2015 DSM regulatory deferral, partially offset by
a reduction in the amount of non-fuel revenues deferred
	 	 	(5.6	) 
	 Decreased income taxes primarily due to decreased income before provision for income
taxes
	 	 	12.9	  
	 Decreased depreciation and amortization primarily due to a lower regulatory amortization as a
result of a fixed cost deferral from 2012 being fully amortized in 2015
	 	 	3.1	  
	 Other, net (1)
	 	 	1.4	  
		 	  
	  
	 
	 Contribution to consolidated net income – 2016
	 	$	52.5	  
		 	  
	  
	 

  

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


  
 14 








 Operating Revenues – Regulated 

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

 

									
	For the	  	Three months ended March 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Electric revenues
	  	$	391.7	  	  	$	440.0	  
	 Other revenues
	  	 	5.8	  	  	 	6.5	  
		  	  
	  
	 	  	  
	  
	 
	 Operating revenues – regulated
	  	$	397.5	  	  	$	446.5	  
		  	  
	  
	 	  	  
	  
	 

 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: 
  

													
	 Q1 Electric Sales Volumes

Gigawatt hours (“GWh”)
	  	 	 	  	 	 	  	 	 
	 	  	2016	 	  	2015	 	  	2014	 
	 Residential
	  	 	1,431	  	  	 	1,589	  	  	 	1,568	  
	 Commercial
	  	 	840	  	  	 	919	  	  	 	883	  
	 Industrial
	  	 	578	  	  	 	602	  	  	 	601	  
	 Other
	  	 	79	  	  	 	111	  	  	 	90	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	2,928	  	  	 	3,221	  	  	 	3,142	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

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

 

													
	Q1 Electric Revenues	 
	 millions of Canadian dollars
	  	 	 	  	 	 	  	 	 
	 	  	2016	 	  	2015	 	  	2014	 
	 Residential
	  	$	223.4	  	  	$	248.2	  	  	$	232.8	  
	 Commercial
	  	 	109.2	  	  	 	119.4	  	  	 	109.1	  
	 Industrial
	  	 	48.1	  	  	 	57.9	  	  	 	55.8	  
	 Other
	  	 	11.0	  	  	 	14.5	  	  	 	13.3	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	391.7	  	  	$	440.0	  	  	$	411.0	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 


  
 15 








 Electric revenues decreased $48.3 million to $391.7 million in Q1 2016 compared to $440.0 million in Q1 2015.
Highlights of the changes are summarized in the following table: 
  

					
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 Electric revenues – 2015
	  	$	440.0	  
	 Decreased fuel related electricity pricing effective January 1, 2016
	  	 	(3.8	) 
	 Decreased commercial and residential sales volume due to weather
	  	 	(31.5	) 
	 Decreased industrial sales volume
	  	 	(9.6	) 
	 Other
	  	 	(3.4	) 
		  	  
	  
	 
	 Electric revenues – 2016
	  	$	391.7	  
		  	  
	  
	 

 Regulated Fuel for Generation and Purchased Power 

 

													
	Q1 Production Volumes	 
	 GWh
	  	 	 	  	 	 	  	 	 
	 	  	2016	 	  	2015	 	  	2014	 
	 Coal and petroleum coke (“petcoke”)
	  	 	1,688	  	  	 	2,248	  	  	 	2,273	  
	 Natural gas
	  	 	285	  	  	 	164	  	  	 	179	  
	 Oil
	  	 	141	  	  	 	249	  	  	 	135	  
	 Purchased power – other
	  	 	95	  	  	 	87	  	  	 	47	  
	 Total non-renewables
	  	 	2,209	  	  	 	2,748	  	  	 	2,634	  
	 Wind and hydro – renewables
	  	 	406	  	  	 	384	  	  	 	416	  
	 Purchased power – renewables, including IPP and COMFIT
	  	 	469	  	  	 	317	  	  	 	254	  
	 Biomass – renewables
	  	 	70	  	  	 	52	  	  	 	53	  
	 Total renewables
	  	 	945	  	  	 	753	  	  	 	723	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total production volumes
	  	 	3,154	  	  	 	3,501	  	  	 	3,357	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
				
	 Q1 Average Fuel Costs
	  	 	 	  	 	 	  	 	 
	 	  	2016	 	  	2015	 	  	2014	 
	 Dollars per megawatt hour (“MWh”) produced
	  	$	45	  	  	$	54	  	  	$	51	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Average unit fuel costs decreased in Q1 2016 compared to Q1 2015 primarily due to decreased commodity pricing and decreased
load, requiring less generation to be sourced from higher cost alternatives. 
 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 (“IPP”), including Community Feed-In Tariff
(“COMFIT”) participants), such that the incremental cost of production generally 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. 
 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, including IPP and COMFIT, which typically
has a higher cost per MWh. 

  
 16 








 Regulated fuel for generation and purchased power decreased $47.9 million to $141.5 million in Q1 2016 compared
to $189.4 million in Q1 2015. Highlights of the changes are summarized in the following table: 
  

					
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 Regulated fuel for generation and purchased power – 2015
	  	$	189.4	  
	 Change in generation mix
	  	 	11.2	  
	 Decreased commodity prices
	  	 	(38.2	) 
	 Decreased sales volumes
	  	 	(18.3	) 
	 Other
	  	 	(2.6	) 
		  	  
	  
	 
	 Regulated fuel for generation and purchased power – 2016
	  	$	141.5	  
		  	  
	  
	 

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

Regulated Fuel Adjustment Mechanism and FAM Regulatory Deferral 

NSPI has a Fuel Adjustment Mechanism which enables it to seek recovery of Fuel Costs through regularly scheduled rate adjustments. Differences between actual
Fuel Costs and amounts recovered from customers through electricity rates in a given year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent year.

The FAM is subject to an incentive, with NSPI retaining or absorbing 10 per cent of the over or under-recovered 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. 
 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 $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. 
 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 and 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 otherwise have been required. This amount totals $4.6 million. Therefore, as at December 31, 2015, NSPI had 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 as a result of applying the tax benefits associated with the South Canoe and Sable Wind Projects, as directed by the Electricity Plan Act. 

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.


  
 17 








 The FAM included in the Statements of Income includes the effect of 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, net of the incentive component, is deferred to a FAM regulatory asset in “Regulatory assets” or a
FAM regulatory liability in “Regulatory liabilities” on the Balance Sheets; 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 “Regulatory liabilities” on the Consolidated Balance Sheets, are summarized in the following table: 

 

					
	 millions of Canadian dollars
	  	2016	 
	 FAM regulatory liability – Balance as at January 1
	  	$	(28.3	) 
	 Under (over) recovery of current period Fuel Costs
	  	 	(10.0	) 
	 Rebate to (recovery from) customers of prior years’ Fuel Costs
	  	 	(3.8	) 
	 Interest on FAM balance
	  	 	(0.7	) 
	 Application of non-fuel revenues
	  	 	(3.8	) 
		  	  
	  
	 
	 FAM regulatory liability – Balance as at March 31
	  	$	(46.6	) 
		  	  
	  
	 

 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 related revenues (Fuel Electric Revenues) do not have a material effect on NSPI’s electric margin or net income, with the exception of the incentive component of the FAM,
whereby NSPI retains or absorbs 10 per cent of the over or under recovered amount to a maximum of $5 million. 
 Electric margin is influenced
primarily by revenues relating to non-fuel costs. NSPI’s customer classes contribute differently to NSPI’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 revenues available to cover these costs, has increased in a corresponding manner. 

  
 18 








 Operating revenues are summarized in the following table: 

 

									
	For the	  	Three months ended March 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Fuel electric revenues – current year
	  	$	152.0	  	  	$	165.7	  
	 Fuel electric revenues – recovery of preceding years
	  	 	3.8	  	  	 	18.2	  
	 Non-fuel electric revenues
	  	 	235.9	  	  	 	256.1	  
	 Other revenues
	  	 	5.8	  	  	 	6.5	  
		  	  
	  
	 	  	  
	  
	 
	 Operating revenues
	  	$	397.5	  	  	$	446.5	  
		  	  
	  
	 	  	  
	  
	 

 Electric margin is summarized in the following table: 

 

									
	 Fuel electric revenues – current year
	  	$	 152.0	  	  	$	 165.7	  
	 Fuel electric revenues – recovery of preceding years
	  	 	3.8	  	  	 	18.2	  
	 Total fuel electric revenues
	  	 	155.8	  	  	 	183.9	  
	 Regulated fuel for generation and purchased power
	  	 	(141.5	) 	  	 	(189.4	) 
	 Regulated fuel adjustment mechanism
	  	 	(13.8	) 	  	 	5.4	  
	 Fuel-related foreign exchange gain (loss) (1)
	  	 	0.2	  	  	 	0.1	  
	 Net fuel revenue (expense) (2)
	  	 	0.7	  	  	 	—  	  
	 Non-fuel electric revenues
	  	 	235.9	  	  	 	256.1	  
		  	  
	  
	 	  	  
	  
	 
	 Electric margin
	  	$	236.6	  	  	$	256.1	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	As reported in “Other expenses, net” on the Consolidated Statements of Income. 


	(2)	Net fuel revenue is a result of the FAM incentive. 

 NSPI’s electric margin decreased $19.5 million to
$236.6 million in Q1 2016 compared to $256.1 million in Q1 2015 due to decreased non-fuel electric revenues primarily due to decreased residential and commercial sales reflecting decreased load, primarily due to weather. 

 

													
	 Q1 Average Electric Margin/MWh
	 
	 	  	2016	 	  	2015	 	  	2014	 
	 Dollars per MWh sold
	  	$	81	  	  	$	80	  	  	$	80	  

 NSPI’s electric margin per MWh is consistent period over period. 

  
 19 








 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. 
  

									
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 	  	2016	 	  	2015	 
	 Income from operations
	  	$	92.9	  	  	$	123.6	  
	 Less:
	  				  			
	 Fuel electric revenue
	  	 	155.8	  	  	 	183.9	  
	 Other revenue
	  	 	5.8	  	  	 	6.5	  
	 Add back:
	  				  			
	 Regulated fuel for generation and purchased power
	  	 	141.5	  	  	 	189.4	  
	 Operating, maintenance and general
	  	 	87.4	  	  	 	79.6	  
	 Provincial grants and taxes
	  	 	9.7	  	  	 	9.6	  
	 Depreciation and amortization
	  	 	48.4	  	  	 	51.5	  
	 Regulated fuel adjustment mechanism and fixed cost deferrals
	  	 	17.6	  	  	 	(7.2	) 
	 Other fuel related costs
	  	 	0.7	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 
	 Electric margin
	  	$	236.6	  	  	$	256.1	  
		  	  
	  
	 	  	  
	  
	 

 EMERA MAINE 
 Overview

 Emera Maine is a transmission and distribution electric utility with assets of approximately $1.1 billion, serving 158,000 customers in the State of
Maine in the United States. 
 Emera Maine’s electric revenue is comprised of distribution operations, local and regional transmission operations and
stranded cost recoveries. The rates for each element are established in distinct regulatory proceedings.
  

	 	•	 	Emera Maine’s distribution rates are set on a 9.55 per cent ROE, with a common equity component of 49 per cent.

  

	 	•	 	For local transmission operations, the rate for the Bangor Hydro District is set on a 10.57 per cent ROE. For the Maine Public Service District, the rate is set on a 10.2 per cent ROE effective June 1 for
wholesale and July 1 for retail customers. The Bangor Hydro District’s bulk transmission assets are managed by ISO-New England as part of a region-wide pool of assets and have a ROE range of 11.07 per cent to 11.74 per cent. The
common equity component is based upon the average balances in the prior calendar year.

  

	 	•	 	For stranded cost recoveries, the rate for the Bangor Hydro District is set on a 5.9 per cent ROE, with a common equity component of 48 per cent and for the Maine Public Service District it is set on
6.75 per cent ROE with a common equity component of 48 per cent. 

 Emera Maine operates under a traditional cost-of-service
regulatory structure. All amounts are reported in USD, unless otherwise stated. 

  
 20 








 Review of 2016 

Emera Maine Net Income 
  

									
	For the	  	Three months ended March 31	 
	 millions of US dollars (except per share amounts)
	  	2016	 	  	2015	 
	 Operating revenues – regulated
	  	$	57.7	  	  	$	55.8	  
	 Operating revenues – non-regulated
	  	 	0.2	  	  	 	—  	  
	 Total operating revenues
	  	 	57.9	  	  	 	55.8	  
	 Regulated fuel for generation and purchased power
	  	 	7.8	  	  	 	7.7	  
	 Transmission pool expense (1)
	  	 	6.3	  	  	 	6.1	  
	 Operating, maintenance and general
	  	 	15.9	  	  	 	13.2	  
	 Provincial, state and municipal taxes
	  	 	3.6	  	  	 	3.5	  
	 Depreciation and amortization
	  	 	10.7	  	  	 	8.8	  
	 Total operating expenses
	  	 	44.3	  	  	 	39.3	  
	 Income from operations
	  	 	13.6	  	  	 	16.5	  
	 Other income (expenses), net
	  	 	0.2	  	  	 	1.1	  
	 Interest expense, net
	  	 	3.6	  	  	 	3.4	  
	 Income before provision for income taxes
	  	 	10.2	  	  	 	14.2	  
	 Income tax expense (recovery)
	  	 	3.4	  	  	 	4.9	  
	 Contribution to consolidated net income – USD
	  	$	6.8	  	  	$	9.3	  
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income – CAD
	  	$	9.3	  	  	$	11.5	  
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share – CAD
	  	$	0.06	  	  	$	0.08	  
		  	  
	  
	 	  	  
	  
	 
	 Net income weighted average foreign exchange rate – CAD/USD
	  	$	1.37	  	  	$	1.24	  
		  	  
	  
	 	  	  
	  
	 
	 EBITDA – USD
	  	$	24.5	  	  	$	26.4	  
		  	  
	  
	 	  	  
	  
	 
	 EBITDA – CAD
	  	$	33.5	  	  	$	32.8	  
		  	  
	  
	 	  	  
	  
	 

  

	(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 in Q1 2016 decreased by $2.5 million to $6.8 million compared to $9.3 million in Q1 2015.
Highlights of the USD net income changes are summarized in the following table: 
  

					
	For the	 	Three months ended	 
	 millions of US dollars
	 	March 31	 
	 Contribution to consolidated net income – 2015
	 	$	9.3	  
	 Increased operating revenues – (see Operating Revenues – Regulated Section
below)
	 	 	1.9	  
	 Increased OM&G primarily due to decreased capitalized construction overheads as a result of
lower capital spending and storm costs
	 	 	(2.7	) 
	 Increased depreciation and amortization primarily due to higher plant in service
	 	 	(1.9	) 
	 Other
	 	 	0.2	  
		 	  
	  
	 
	 Contribution to consolidated net income – 2016
	 	$	6.8	  
		 	  
	  
	 

 Emera Maine’s CAD contribution to consolidated net income decreased in Q1 2016 by $2.2 million to $9.3 million from $11.5
million in Q1 2015. The impact of a stronger USD, quarter-over-quarter, increased CAD earnings by $0.9 million for the three months ended March 31, 2016. 

  
 21 








 Operating Revenues – Regulated 

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

 

									
	For the	  	Three months ended March 31	 
	 millions of US dollars
	  	2016	 	  	2015	 
	 Electric revenues
	  	$	41.7	  	  	$	40.0	  
	 Transmission pool revenues
	  	 	11.6	  	  	 	12.2	  
	 Resale of purchased power
	  	 	4.4	  	  	 	3.6	  
		  	  
	  
	 	  	  
	  
	 
	 Operating revenues – regulated
	  	$	57.7	  	  	$	55.8	  
		  	  
	  
	 	  	  
	  
	 

 Electric Revenues 

Electric sales volume is primarily driven by general economic conditions, population and weather. 

 

													
	 Q1 Electric Sales Volumes
	 
	 GWh
	  	2016	 	  	2015	 	  	2014	 
	 Residential
	  	 	218	  	  	 	235	  	  	 	232	  
	 Commercial
	  	 	198	  	  	 	207	  	  	 	206	  
	 Industrial
	  	 	81	  	  	 	101	  	  	 	105	  
	 Other
	  	 	4	  	  	 	3	  	  	 	4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	501	  	  	 	546	  	  	 	547	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

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

 

													
	 Q1 Electric Revenues

millions of US dollars
	 
	 	  	2016	 	  	2015	 	  	2014	 
	 Residential
	  	$	20.7	  	  	$	21.6	  	  	$	20.7	  
	 Commercial
	  	 	14.8	  	  	 	14.3	  	  	 	14.9	  
	 Industrial
	  	 	3.2	  	  	 	3.3	  	  	 	4.1	  
	 Other (1)
	  	 	3.0	  	  	 	0.8	  	  	 	2.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	41.7	  	  	$	40.0	  	  	$	42.4	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

  

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


Electric revenues increased $1.7 million to $41.7 million in Q1 2016 compared to $40.0 million in Q1 2015. Highlights of the changes are summarized in the
following table: 
  

					
	For the	  	Three months ended	 
	 millions of US dollars
	  	March 31	 
	 Electric revenues – 2015
	  	$	40.0	  
	 Increased due to rate changes
	  	 	3.3	  
	 Decreased sales volume primarily due to weather
	  	 	(3.4	) 
	 Increased due to FERC transmission rate refund reserves
	  	 	1.2	  
	 Amortization of transmission revenue adjustments
	  	 	0.6	  
		  	  
	  
	 
	 Electric revenues – 2016
	  	$	41.7	  
		  	  
	  
	 

  

													
	 Q1 Average Electric Revenue / MWh
	 
	 US dollars
	  	2016	 	  	2015	 	  	2014	 
	 Dollars per MWh
	  	$	83	  	  	$	73	  	  	$	78	  

 The change in average electric revenue per MWh in Q1 2016 compared to Q1 2015 reflects increased transmission rates and sales
mix. 

  
 22 








 Transmission Pool Revenues and Expenses 

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

									
	For the	  	Three months ended	 
	 millions of US dollars
	  	March 31	 
	 	  	2016	 	  	2015	 
	 Transmission pool revenues
	  	$	11.6	  	  	$	12.2	  
	 Transmission pool expenses
	  	 	6.3	  	  	 	6.1	  
		  	  
	  
	 	  	  
	  
	 
	 Net transmission pool revenues
	  	$	5.3	  	  	$	6.1	  
		  	  
	  
	 	  	  
	  
	 

 Emera Maine’s net transmission pool revenues decreased $0.8 million to $5.3 million in Q1 2016 compared to $6.1 million
in Q1 2015 primarily due to changes in the level of investment in regionally funded transmission assets and the effect of weather. 
 EMERA CARIBBEAN

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

	 	•	 	100.0 per cent (December 31, 2015 – 95.5 per cent) investment in ECI and its wholly owned subsidiary BLPC, a vertically integrated utility which is the provider of electricity on the island of Barbados.
BLPC serves 126,000 customers and is regulated by the Fair Trading Commission, Barbados. BLPC’s approved regulated return on rate base for 2016 is 10.0 per cent. A fuel pass-through mechanism provides the opportunity to recover all fuel
costs in a timely manner. Emera completed the purchase of the remaining 4.5 per cent of common shares from minority shareholders of ECI 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 GBPC, which is a vertically integrated utility and a sole
provider of electricity on Grand Bahama Island. GBPC serves 19,000 customers and is regulated by the GBPA. Effective February 1, 2016, the GBPA approved GBPC’s regulated return on rate base of 8.8 per cent applicable for the 2016
through 2018 period. A fuel pass-through mechanism provides the opportunity to recover all fuel costs in a timely manner. 

  

	 	•	 	51.9 per cent (December 31, 2015 – 49.6 per cent indirect controlling interest), through ECI, in Domlec, an integrated utility on the island of Dominica. Domlec serves 36,000 customers and is regulated by
the IRC. Domlec’s approved allowable regulated return on rate base for 2016 is 15.0 per cent. A fuel pass-through mechanism provides the opportunity to recover substantially all fuel costs in a timely manner. 


Equity Investment 
  

	 	•	 	19.1 per cent (December 31, 2015 – 18.2 per cent indirect interest), through ECI, in 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. 


  
 23 








 Review of 2016 

Emera Caribbean Net Income 
  

									
	For the	  	Three months ended March 31	 
	 millions of US dollars (except per share amounts)
	  	2016	 	  	2015	 
	 Operating revenues – regulated
	  	$	71.0	  	  	$	83.1	  
	 Operating revenues – non-regulated
	  	 	—  	  	  	 	1.9	  
	 Total operating revenues
	  	 	71.0	  	  	 	85.0	  
	 Regulated fuel for generation and purchased power
	  	 	26.7	  	  	 	39.1	  
	 Non-regulated direct costs
	  	 	—  	  	  	 	1.8	  
	 Operating, maintenance and general
	  	 	21.6	  	  	 	22.8	  
	 Property taxes (1)
	  	 	0.6	  	  	 	0.4	  
	 Depreciation and amortization
	  	 	9.4	  	  	 	8.6	  
	 Total operating expenses
	  	 	58.3	  	  	 	72.7	  
	 Income from operations
	  	 	12.7	  	  	 	12.3	  
	 Income from equity investment
	  	 	0.4	  	  	 	0.5	  
	 Other income (expenses), net
	  	 	0.3	  	  	 	1.5	  
	 Interest expense, net
	  	 	2.8	  	  	 	2.7	  
	 Income before provision for income taxes
	  	 	10.6	  	  	 	11.6	  
	 Income tax expense (recovery)
	  	 	1.0	  	  	 	1.0	  
	 Net income
	  	 	9.6	  	  	 	10.6	  
	 Non-controlling interest in subsidiaries
	  	 	1.2	  	  	 	2.2	  
	 Preferred stock dividends (2)
	  	 	1.3	  	  	 	1.3	  
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income – USD
	  	$	7.1	  	  	$	7.1	  
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income – CAD
	  	$	9.8	  	  	$	8.8	  
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share – CAD
	  	$	0.07	  	  	$	0.06	  
		  	  
	  
	 	  	  
	  
	 
	 Net income weighted average foreign exchange rate – CAD/USD
	  	$	1.38	  	  	$	1.24	  
		  	  
	  
	 	  	  
	  
	 
	 EBITDA – USD
	  	$	22.8	  	  	$	22.9	  
		  	  
	  
	 	  	  
	  
	 
	 EBITDA – CAD
	  	$	31.5	  	  	$	28.3	  
		  	  
	  
	 	  	  
	  
	 

  

	(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 did not change in Q1 2016 compared to Q1 2015. 

Emera Caribbean’s CAD contribution to consolidated net income increased by $1.0 million to $9.8 million in Q1 2016 compared to $8.8 million in Q1 2015 as
a result of a stronger USD. 
 Operating Revenues – Regulated 

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

 

									
	For the	  	Three months ended March 31	 
	 millions of US dollars
	  	2016	 	  	2015	 
	 Electric revenues – base rates
	  	$	44.0	  	  	$	43.6	  
	 Fuel charge
	  	 	26.1	  	  	 	38.6	  
	 Total electric revenues
	  	 	70.1	  	  	 	82.2	  
	 Other revenues
	  	 	0.9	  	  	 	0.9	  
		  	  
	  
	 	  	  
	  
	 
	 Operating revenues – regulated
	  	$	71.0	  	  	$	83.1	  
		  	  
	  
	 	  	  
	  
	 


  
 24 








 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. 
  

													
	Q1 Electric Sales Volumes	 
	 GWh
	  	 	 	  	 	 	  	 	 
	 	  	2016	 	  	2015	 	  	2014	 
	 Residential
	  	 	109	  	  	 	105	  	  	 	104	  
	 Commercial
	  	 	179	  	  	 	179	  	  	 	177	  
	 Industrial
	  	 	23	  	  	 	27	  	  	 	24	  
	 Other
	  	 	6	  	  	 	6	  	  	 	7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	317	  	  	 	317	  	  	 	312	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

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

 

													
	Q1 Electric Revenues	 
	 millions of US dollars
	  	 	 	  	 	 	  	 	 
	 	  	2016	 	  	2015	 	  	2014	 
	 Residential
	  	$	22.5	  	  	$	25.9	  	  	$	31.2	  
	 Commercial
	  	 	39.3	  	  	 	46.1	  	  	 	58.5	  
	 Industrial
	  	 	6.8	  	  	 	8.6	  	  	 	8.4	  
	 Other
	  	 	1.5	  	  	 	1.6	  	  	 	1.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	$	70.1	  	  	$	82.2	  	  	$	99.8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Electric revenues decreased $12.1 million to $70.1 million in Q1 2016 compared to $82.2 million in Q1 2015. Highlights of the
changes are summarized in the following table: 
  

					
	For the	  	Three months ended	 
	 millions of US dollars
	  	March 31	 
	 Electric revenues – 2015
	  	$	82.2	  
	 Decreased fuel charge primarily due to lower fuel prices
	  	 	(12.5	) 
	 Increased due to higher sales volumes at BLPC
	  	 	0.4	  
		  	  
	  
	 
	 Electric revenues – 2016
	  	$	70.1	  
		  	  
	  
	 

  

													
	Q1 Average Electric Revenue/MWh	 
	 US dollars
	  	2016	 	  	2015	 	  	2014	 
	 Dollars per MWh
	  	$	221	  	  	$	259	  	  	$	320	  

 The change in average electric revenues per MWh in Q1 2016 compared to Q1 2015 was the 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. 

  
 25 








 Electric margin is summarized in the following table: 

 

									
	For the	  	Three months ended March 31	 
	 millions of US dollars
	  	2016	 	  	2015	 
	 Operating revenues – regulated
	  	$	71.0	  	  	$	83.1	  
	 Less: Other revenues
	  	 	(0.9	) 	  	 	(0.9	) 
		  	  
	  
	 	  	  
	  
	 
	 Total electric revenues
	  	$	70.1	  	  	$	82.2	  
		  	  
	  
	 	  	  
	  
	 

 Total electric revenues are broken down as follows: 

 

									
	 Electric revenues – base rate
	  	$	44.0	  	  	$	43.6	  
	 Fuel charge
	  	 	26.1	  	  	 	38.6	  
	 Total electric revenues
	  	 	70.1	  	  	 	82.2	  
	 Regulated fuel for generation and purchased power
	  	 	26.7	  	  	 	39.1	  
	 Regulatory amortization (1)
	  	 	0.6	  	  	 	0.7	  
		  	  
	  
	 	  	  
	  
	 
	 Electric margin
	  	$	42.8	  	  	$	42.4	  
		  	  
	  
	 	  	  
	  
	 

  

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

  

													
	 Q1 Average Electric Margin /MWh
	 
	 US dollars
	  	2016	 	  	2015	 	  	2014	 
	 Dollars per MWh
	  	$	135	  	  	$	134	  	  	$	133	  

 Electric margin and average electric margin/MWh is consistent quarter over quarter. 

Regulated Fuel for Generation and Purchased Power 
  

													
	 Q1 Production Volumes
	 
	 GWh 
	  	 	 	  	 	 	  	 	 
	 	  	2016	 	  	2015	 	  	2014	 
	 Oil
	  	 	337	  	  	 	335	  	  	 	330	  
	 Hydro
	  	 	9	  	  	 	7	  	  	 	8	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Total
	  	 	346	  	  	 	342	  	  	 	338	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 

 Regulated fuel for generation and purchased power decreased $12.4 million to $26.7 million in Q1 2016 compared to $39.1
million in Q1 2015 primarily due to lower fuel prices. 
  

													
	 Q1 Average Fuel Costs/MWh
	  	 	 	  	 	 	  	 	 
	 US dollars
	  	2016	 	  	2015	 	  	2014	 
	 Dollars per MWh
	  	$	77	  	  	$	114	  	  	$	170	  

 The change in average fuel costs in Q1 2016 compared to Q1 2015 was the result of lower fuel prices. 

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. Management believes measuring electric margin shows the portion of revenues managed through fuel adjustment mechanism,
which have a minimal impact on income. This measure is not intended to replace “Income from operations” which, as determined in accordance with GAAP, is an indicator of operating performance. 

  
 26 









									
	For the	  	Three months ended	 
	 millions of US dollars
	  	March 31	 
	 	  	2016	 	  	2015	 
	 Income from operations
	  	$	12.7	  	  	$	12.3	  
	 Less:
	  				  			
	 Operating revenues – non-regulated
	  	 	—  	  	  	 	1.9	  
	 Other revenue
	  	 	0.9	  	  	 	0.9	  
	 Add back:
	  				  			
	 Non-regulated direct costs
	  	 	—  	  	  	 	1.8	  
	 Operating, maintenance and general
	  	 	21.6	  	  	 	22.8	  
	 Property taxes
	  	 	0.6	  	  	 	0.4	  
	 Depreciation and amortization (1)
	  	 	8.8	  	  	 	7.9	  
		  	  
	  
	 	  	  
	  
	 
	 Electric margin
	  	$	42.8	  	  	$	42.4	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	Depreciation and amortization excludes $0.6 million of regulatory amortization in Q1 2016 (2015 – $0.7 million). 


  
 27 








 PIPELINES 

Overview 
 Pipelines is comprised of 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
2016 
 Pipelines’ Adjusted Net Income 
  

									
	For the	  	Three months ended March 31	 
	 millions of Canadian dollars (except per share amounts)
	  	2016	 	  	2015	 
	 Operating revenues – regulated
	  	$	12.9	  	  	$	13.1	  
	 Operating maintenance and general
	  	 	0.1	  	  	 	0.2	  
	 Accretion (1)
	  	 	0.1	  	  	 	0.1	  
	 Income from equity investment
	  	 	5.9	  	  	 	5.9	  
	 Other income (expenses), net
	  	 	(0.2	) 	  	 	0.7	  
	 Interest expense, net (2)
	  	 	5.7	  	  	 	6.2	  
	 Adjusted Income before provision for income taxes
	  	 	12.7	  	  	 	13.2	  
	 Income tax expense (recovery)
	  	 	3.0	  	  	 	3.3	  
	 Adjusted contribution to consolidated net income
	  	$	9.7	  	  	$	9.9	  
	 After-tax derivative mark-to-market gain (loss)
	  	 	(0.3	) 	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income
	  	$	9.4	  	  	$	9.9	  
		  	  
	  
	 	  	  
	  
	 
	 Adjusted contribution to consolidated earnings per common share
	  	$	0.07	  	  	$	0.07	  
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share
	  	$	0.06	  	  	$	0.07	  
		  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	18.5	  	  	$	19.5	  
		  	  
	  
	 	  	  
	  
	 

  

	(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 loss of $0.3 million in Q1 2016 compared to nil for the same period in 2015. 


Pipelines’ contribution to consolidated net income in Q1 2016 is consistent with Q1 2015. 

  
 28 








 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”), 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 investment in a 50.0 per cent joint venture ownership of Bear Swamp, a 600 MW pumped storage hydroelectric facility in northwestern Massachusetts. 


Wholly owned investments are consolidated. The investment in Bear Swamp is accounted for on an equity basis. 

Mark-to-Market Adjustments 
 Emera Energy’s
“Marketing and trading 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 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 counterparties, including local gas distribution utilities, power utilities,
and natural gas producers in the northeast. The AMAs involve Emera Energy buying or selling gas for a specific term, and the corresponding release of the counterparties’ 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 value of the corresponding gas
transportation asset, which is amortized over the term of the AMA contract.
 Subsequent changes in gas price differentials, to the extent they are not
offset by the accounting amortization of the gas transportation asset, will result in MTM gains or losses recorded in income. MTM adjustments may be substantial during the term of the contract, specifically in the winter months of a contract
when delivered volumes and market volatility are usually at peak levels. As a contract is realized, and volumes reduce, MTM volatility is expected to decrease. Ultimately, the gas 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.

  
 29 








 Review of 2016 

Emera Energy Adjusted Contribution to Consolidated Net Income 
  

									
	For the	  	Three months ended
March 31	 
	 millions of Canadian dollars (except per share amounts)
	  	2016	 	  	2015	 
	 Marketing and trading margin (1)
	  	$	46.9	  	  	$	38.8	  
	 Electricity sales (2)
	  	 	180.1	  	  	 	250.9	  
	 Total operating revenues – non-regulated
	  	 	227.0	  	  	 	289.7	  
	 Non-regulated fuel for generation and purchased power (3)
	  	 	114.1	  	  	 	159.9	  
	 Operating, maintenance and general
	  	 	25.3	  	  	 	20.1	  
	 Provincial, state and municipal taxes
	  	 	0.9	  	  	 	1.4	  
	 Depreciation and amortization
	  	 	10.9	  	  	 	9.3	  
	 Total operating expenses
	  	 	151.2	  	  	 	190.7	  
	 Adjusted income (loss) from operations
	  	 	75.8	  	  	 	99.0	  
	 Income from equity investments (4)
	  	 	3.8	  	  	 	4.0	  
	 Other income (expenses), net
	  	 	(2.6	) 	  	 	22.2	  
	 Interest expense, net
	  	 	6.2	  	  	 	1.0	  
	 Adjusted income (loss) before provision for income taxes
	  	 	70.8	  	  	 	124.2	  
	 Income tax expense (recovery) (5)
	  	 	22.9	  	  	 	47.8	  
	 Adjusted contribution to consolidated net income (loss)
	  	$	47.9	  	  	$	76.4	  
		  	  
	  
	 	  	  
	  
	 
	 After-tax derivative mark-to-market gain (loss)
	  	$	45.5	  	  	$	(11.5	) 
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated net income
	  	$	93.4	  	  	$	64.9	  
		  	  
	  
	 	  	  
	  
	 
	 Adjusted contribution to consolidated earnings per common share – basic
	  	$	0.32	  	  	$	0.53	  
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share – basic
	  	$	0.63	  	  	$	0.45	  
		  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	87.9	  	  	$	134.5	  
		  	  
	  
	 	  	  
	  
	 

  

	(1)	Marketing and trading margin excludes a pre-tax mark-to-market gain of $72.3 million for the quarter ended March 31, 2016 (2015 - $13.9 million gain). 


	(2)	Electricity sales exclude a pre-tax mark-to-market loss of $8.3 million for the quarter ended March 31, 2016 (2015 - $45.8 million loss). 


	(3)	Non-regulated fuel for generation and purchased power excludes a pre-tax mark-to-market gain of $2.8 million for the quarter ended March 31, 2016 (2015 - $7.0 million gain). 


	(4)	Income from equity investments excludes a pre-tax mark-to-market loss of $2.4 million for the quarter ended March 31, 2016 (2015 - $3.4 million gain). 


	(5)	Income tax expense (recovery) excludes an $18.9 million expense relating to mark-to-market gains for the quarter ended March 31, 2016 (2015 - $10.0 million recovery). 


Emera Energy’s contribution to consolidated net income increased $28.5 million to $93.4 million in Q1 2016 compared to $64.9 million in Q1 2015.
Highlights of the net income changes are summarized in the following table: 

  
 30 









					
	 For the
millions of Canadian dollars
	  	Three months ended
March 31	 
	 Contribution to consolidated net income – 2015
	  	$	64.9	  
	 Increased marketing and trading margin – See Marketing and Trading Margin below
	  	 	8.1	  
	 Decreased electricity sales primarily due to lower hedged and market power prices at the New
England Gas Generating Facilities, lower market prices at Bayside Power, and decreased sales volumes at the New England Gas Generating Facilities driven by weather, partially offset by a stronger USD
	  	 	(70.8	) 
	 Decreased non-regulated fuel for generation and purchased power mainly due to lower hedged and
market commodity prices at the New England Gas Generating Facilities, lower market commodity prices at Bayside Power, and decreased purchase volumes at the New England Gas Generating Facilities driven by weather, partially offset by a stronger
USD
	  	 	45.8	  
	 Increased OM&G primarily due to a stronger USD and increased performance-based compensation
resulting from increased marketing and trading margin
	  	 	(5.2	) 
	 Decreased other income primarily due to a gain on the sale of NWP in 2015
	  	 	(24.8	) 
	 Increased interest expense, net primarily due to higher interest rates on internal
financing
	  	 	(5.2	) 
	 Decreased income tax expense primarily due to decreased income before provision for income taxes,
changes in the proportion of income earned in higher tax rate foreign jurisdictions and a stronger CAD
	  	 	24.9	  
	 Increased mark-to-market, net of tax primarily due to the reversal of 2015 mark-to-market losses
and changes in gas and power contract positions, partially offset by amortization of 2015 gas transportation assets
	  	 	57.0	  
	 Other
	  	 	(1.3	) 
		  	  
	  
	 
	 Contribution to consolidated net income – 2016
	  	$	93.4	  
		  	  
	  
	 

 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 CAD earnings by $5.3 million in Q1 2016 compared to Q1 2015. 
 Emera Energy
Services 
 Adjusted EBITDA 
 Adjusted EBITDA for
Emera Energy Services is summarized in the following table: 
  

									
	 For the
millions of Canadian dollars
	  	Three months ended
March 31	 
	 	  	2016	 	  	2015	 
	 Marketing and trading margin
	  	$	46.9	  	  	$	38.8	  
	 OM&G
	  	 	10.4	  	  	 	7.5	  
	 Other income (expenses), net
	  	 	(3.7	) 	  	 	3.5	  
		  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	32.8	  	  	$	34.8	  
		  	  
	  
	 	  	  
	  
	 

 Marketing and Trading Margin 

Marketing and trading margin increased $8.1 million to $46.9 million in Q1 2016 compared to $38.8 million in Q1 2015. This increase is primarily due to a
stronger USD and growth in the volume of business, including investment in transportation capacity, which offset the impact of sustained low pricing and volatility in several of Emera Energy’s markets in Q1 2016, largely the result of weather.

 Other Income 
 Other income decreased $7.2 million to
$(3.7) million in Q1 2016 compared to $3.5 million in Q1 2015. This decrease is primarily due to foreign exchange losses recorded in 2016 as a result of the stronger CAD since December 31, 2015. 

  
 31 








 Emera Energy Generation 

Adjusted EBITDA 
 Adjusted EBITDA for Emera Energy
Generation is summarized in the following table: 
  

																									
	 	  	Three months ended March 31	 
	For the	  	New England	 	  	Maritime Canada	 	 	Total	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 	  	2016	 	  	2015	 	 	2016	 	  	2015	 
	 Energy sales
	  	$	139.3	  	  	$	201.3	  	  	$	28.3	  	  	$	39.0	  	 	$	167.6	  	  	$	240.3	  
	 Capacity and other
	  	 	12.5	  	  	 	10.6	  	  	 	—  	  	  	 	—  	  	 	 	12.5	  	  	 	10.6	  
	 Electricity sales
	  	$	151.8	  	  	$	211.9	  	  	$	28.3	  	  	$	39.0	  	 	$	180.1	  	  	$	250.9	  
	 Non-regulated fuel for generation and purchased power
	  	 	94.1	  	  	 	133.4	  	  	 	18.3	  	  	 	28.6	  	 	 	112.4	  	  	 	162.0	  
	 Non-regulated electric margin
	  	$	57.7	  	  	$	78.5	  	  	$	10.0	  	  	$	10.4	  	 	$	67.7	  	  	$	88.9	  
	 Provincial taxes
	  	 	0.7	  	  	 	1.1	  	  	 	0.2	  	  	 	0.3	  	 	 	0.9	  	  	 	1.4	  
	 OM&G
	  	 	9.0	  	  	 	7.3	  	  	 	5.5	  	  	 	4.5	  	 	 	14.5	  	  	 	11.8	  
	 Other income (expenses), net
	  	 	—  	  	  	 	1.3	  	  	 	1.1	  	  	 	(1.3	) 	 	 	1.1	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	48.0	  	  	$	71.4	  	  	$	5.4	  	  	$	4.3	  	 	$	53.4	  	  	$	75.7	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	  	  
	  
	 

 Adjusted EBITDA decreased $22.3 million to $53.4 million in Q1 2016 from $75.7 million in Q1 2015 primarily due to lower
margins realized in the New England Gas Generating Facilities, reflecting less favourable short-term economic hedges and fewer optimization opportunities driven by weather across the northeastern United States. This was partially offset by the
stronger USD, which contributed $4.7 million. 
 Operating Statistics 
  

																									
	 For the
	  	Three months ended March 31	 
	 	  	Sales Volumes (GWh) (1)	 	  	Plant Availability (%) (2)	 	 	Net Capacity Factor (%) (3)	 
	 	  	2016	 	  	2015	 	  	2016	 	 	2015	 	 	2016	 	 	2015	 
	 New England
	  	 	1,299	  	  	 	1,410	  	  	 	96.1	% 	 	 	98.0	% 	 	 	54.6	% 	 	 	60.8	% 
	 Maritime Canada
	  	 	518	  	  	 	483	  	  	 	95.8	% 	 	 	99.2	% 	 	 	75.9	% 	 	 	70.0	% 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
	 Total
	  	 	1,817	  	  	 	1,893	  	  	 	96.0	% 	 	 	98.3	% 	 	 	59.3	% 	 	 	63.1	% 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	(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 economic vis-à-vis
the market. 

 Sales volumes and net capacity factor decreased quarter-over-quarter at the New England Gas Generating Facilities primarily due
to the impact of weather across the northeastern United States. 
 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 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. 

  
 32 








 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
March 31	 
	 	  	2016	 	  	2015	 
	 Bear Swamp
	  	$	3.8	  	  	$	2.1	  
	 NWP
	  	 	—  	  	  	 	1.9	  
		  	  
	  
	 	  	  
	  
	 
	 Adjusted income from equity investments
	  	$	3.8	  	  	$	4.0	  
		  	  
	  
	 	  	  
	  
	 

 Income from equity investments decreased $0.2 million to $3.8 million in Q1 2016 compared to $4.0 million in Q1 2015, largely
due to the sale of NWP in Q1 2015 and higher interest costs at Bear Swamp as a result of its Q4 2015 refinancing, largely offset by favourable pricing at Bear Swamp and the effect of a stronger USD. 

CORPORATE AND OTHER 
 Corporate 

Corporate encompasses certain corporate-wide functions including executive management, strategic planning, treasury services, legal, 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 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 certain of 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 19.4 per cent (December 31, 2015 – 19.6 per cent) investment in APUC. APUC is a diversified generation, transmission and distribution utility traded on the Toronto Stock Exchange
(“TSX”) under the symbol “AQN”. 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 March 31, 2016, Emera owned 50.1 million common shares, 12.9 million outstanding subscription receipts and dividend equivalents, at an average conversion price of $9.19. The outstanding
subscription receipts and dividend equivalents 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. The subscription receipts and dividend
equivalents are included in “Investments subject to significant influence” on the Consolidated Balance Sheets. 


  
 33 









	•	 	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 59.0 per cent (December 31, 2015 - 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 Energy to complete
construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon 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. 

  

	•	 	Other investments. 

 Mark-to-Market Adjustments 

Specific to the pending TECO Energy acquisition, Emera has recorded after-tax mark-to-market losses of $121.1 million for the three months ended March 31,
2016 (2015 – 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 to close
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. 

  
 34 








 Review of 2016 

Corporate and Other 
  

									
	For the	  	Three months ended
March 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Intercompany revenue (1)
	  	$	9.9	  	  	$	5.3	  
	 Non-regulated operating revenue
	  	 	8.4	  	  	 	8.8	  
	 Non-regulated direct costs
	  	 	8.2	  	  	 	9.7	  
	 Operating, maintenance and general
	  	 	13.7	  	  	 	12.7	  
	 Depreciation and amortization
	  	 	0.7	  	  	 	0.3	  
	 Total operating expenses
	  	 	22.6	  	  	 	22.7	  
	 Income (loss) from operations
	  	 	(4.3	) 	  	 	(8.6	) 
	 Income (loss) from equity earnings
	  	 	18.1	  	  	 	11.9	  
	 Other income (expenses), net (2)
	  	 	3.6	  	  	 	(0.2	) 
	 Interest expense
	  	 	33.1	  	  	 	6.3	  
	 Adjusted income (loss) before provision for income taxes
	  	 	(15.7	) 	  	 	(3.2	) 
	 Income tax expense (recovery) (3)
	  	 	(13.7	) 	  	 	(7.9	) 
	 Preferred stock dividends
	  	 	7.0	  	  	 	7.7	  
	 Adjusted contribution to consolidated net income
	  	$	(9.0	) 	  	$	(3.0	) 
	 After-tax mark-to-market gain (loss)
	  	 	(121.1	) 	  	 	—  	  
	 Contribution to consolidated net income
	  	 	(130.1	) 	  	 	(3.0	) 
	 Adjusted contribution to consolidated earnings per common share – basic
	  	 	(0.06	) 	  	 	(0.02	) 
		  	  
	  
	 	  	  
	  
	 
	 Contribution to consolidated earnings per common share – basic
	  	$	(0.87	) 	  	$	(0.02	) 
		  	  
	  
	 	  	  
	  
	 
	 Adjusted EBITDA
	  	$	18.1	  	  	$	3.4	  
		  	  
	  
	 	  	  
	  
	 

  

	(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 loss of $139.5 million in Q1 2016 compared to nil for the same period in 2015. 


	(3)	Income tax expense (recovery), excludes an $18.4 million recovery relating to mark-to-market losses in Q1 2016 compared to nil for the same period in 2015. 


Corporate and Other’s contribution to consolidated net income decreased $127.1 million to $(130.1) million in Q1 2016 compared to $(3.0) million in Q1
2015. Highlights of the income changes are summarized in the following table: 
  

					
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 Contribution to consolidated net income – 2015
	  	$	(3.0	) 
	 Increased intercompany revenue primarily due to the issuance of a loan to Emera Energy
Generation
	  	 	4.6	  
	 Income from equity investments - see table below for highlights
	  	 	6.2	  
	 Increased interest expense primarily due to interest on the pending TECO Energy acquisition
related convertible debentures represented by instalment receipts
	  	 	(26.8	) 
	 Increased income tax recovery primarily due to decreased income before provision for income
taxes
	  	 	5.8	  
	 After-tax mark-to-market gain (loss) - see After-Tax Mark-to-Market Gain (Loss) section
below
	  	 	(121.1	) 
	 Other
	  	 	4.2	  
		  	  
	  
	 
	 Contribution to consolidated net income – 2016
	  	$	(130.1	) 
		  	  
	  
	 


  
 35 








 Acquisition Related Costs 

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

 

									
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 	  	2016	 	  	2015	 
	 Operating, maintenance, and general
	  	$	0.1	  	  	$	—  	  
	 Interest expense, net
	  	 	25.5	  	  	 	—  	  
	 Income tax expense (recovery)
	  	 	(8.1	) 	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 
	 Acquisition related costs
	  	$	17.5	  	  	$	—  	  
		  	  
	  
	 	  	  
	  
	 

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

The foreign currency earnings impact related to the translation from the convertible debenture USD cash balance and the mark-to-market adjustments from forward
contracts from economically hedging the Debenture Offering are recorded as a mark-to-market adjustment. These pre-tax losses totaled $139.5 million in Q1 2016 and are recorded in “Other income (expenses), net” on the Consolidated
Statements of Income ($121.1 million after-tax loss). These losses offset a pre-tax mark-to-market gain of $118.9 million ($100.5 million after-tax gain) recorded in Q4 2015. The after-tax mark-to-market gain (loss) is summarized in the following
table: 
  

									
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 	  	2016	 	  	2015	 
	 Foreign exchange on USD cash
	  	$	(44.7	) 	  	$	—  	  
	 Mark-to-market adjustment on USD forward contracts
	  	 	(94.8	) 	  	 	—  	  
	 Income tax (expense) recovery
	  	 	18.4	  	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 
	 After-tax mark-to-market gain (loss)
	  	$	(121.1	) 	  	$	—  	  
		  	  
	  
	 	  	  
	  
	 

 Income from Equity Investments 

Income from equity investments are summarized in the following table: 
  

									
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 	  	2016	 	  	2015	 
	 APUC
	  	$	9.0	  	  	$	6.6	  
	 NSPML
	  	 	4.4	  	  	 	3.6	  
	 LIL
	  	 	4.7	  	  	 	1.7	  
		  	  
	  
	 	  	  
	  
	 
	 Income from equity investments
	  	$	18.1	  	  	$	11.9	  
		  	  
	  
	 	  	  
	  
	 

 Income from equity investments increased $6.2 million to $18.1 million in Q1 2016 compared to $11.9 million in Q1 2015.
Highlights of the changes are summarized in the following table: 
  

					
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 Income from equity investments – 2015
	  	$	11.9	  
	 APUC – Higher equity earnings and the reclassification of APUC subscription receipts
	  	 	2.4	  
	 NSPML – AFUDC earnings as a result of increased investment
	  	 	0.8	  
	 LIL – AFUDC earnings as a result of increased investment
	  	 	3.0	  
		  	  
	  
	 
	 Income from equity investments – 2016
	  	$	18.1	  
		  	  
	  
	 


  
 36 








 NSPML has invested $796.7 million as at March 31, 2016 of equity, debt and working capital, including $90.3
million of AFUDC, in the development of the Maritime Link Project. Project to date, Emera has invested a total of $206.4 million in equity, which is comprised of $169.3 million in equity contributed and $37.1 million of accumulated retained
earnings, with the remaining costs being funded with working capital and debt. The debt 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 target debt to equity ratio reached 70 per cent to 30 per cent respectively, in Q4 2015. From that point forward, project costs are
being funded with debt and equity at a 70 per cent and 30 per cent ratio, with equity contributions of $14.4 million in Q1 2016. 
 Emera has
invested $250.4 million in the LIL as at March 31, 2016, which is comprised of $224.5 million in equity contributed and $25.9 million of accumulated equity earnings. Equity earnings are being recorded based on an annual rate 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 markets served by Emera, 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. 
 Consolidated Cash Flow Highlights 

Significant changes in the statements of cash flows between the three months ended March 31, 2016 and 2015 include: 

 

													
	 millions of Canadian dollars
	  	2016	 	  	2015	 	  	$ Change	 
	 Cash and cash equivalents, beginning of period
	  	$	1,073.4	  	  	$	221.1	  	  	$	852.3	  
	 Provided by (used in):
	  				  				  			
	 Operating cash flow before change in working capital
	  	 	232.4	  	  	 	257.5	  	  	 	(25.1	) 
	 Change in working capital
	  	 	(51.8	) 	  	 	(137.9	) 	  	 	86.1	  
	 Operating activities
	  	 	180.6	  	  	 	119.6	  	  	 	61.0	  
	 Investing activities
	  	 	(139.3	) 	  	 	195.9	  	  	 	(335.2	) 
	 Financing activities
	  	 	(45.8	) 	  	 	(259.3	) 	  	 	213.5	  
	 Effect of exchange rate changes on cash and cash equivalents
	  	 	(69.4	) 	  	 	28.0	  	  	 	(97.4	) 
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 
	 Cash and cash equivalents, end of period
	  	$	999.5	  	  	$	305.3	  	  	$	694.2	  
		  	  
	  
	 	  	  
	  
	 	  	  
	  
	 


  
 37 








 Operating Cash Flows 

Refer to Consolidated Income Statement and Operating Cash Flow Highlights for details. 

Investing Cash Flows 
 Net cash used in investing
activities increased $335.2 million to $139.3 million for the three months ended March 31, 2016 compared to net cash provided by investing activities of $195.9 million for the same period in 2015. The increase was primarily due to proceeds from
the sale of NWP in 2015 and increased investments in NSPML and LIL in 2016. 
 Capital expenditures for the three months ended March 31, 2016,
including AFUDC and net of proceeds from disposal of assets, were $87 million compared to $83 million during the same period in 2015. Details of the capital spend are shown below: 

 

	 	•	 	$48 million at NSPI (2015 – $51 million); 

  

	 	•	 	$9 million at Emera Maine (2015 – $19 million); 

  

	 	•	 	$22 million at Emera Caribbean (2015 – $9 million); 

  

	 	•	 	$6 million at Emera Energy (2015 – $2 million); 

  

	 	•	 	$2 million in Corporate and Other (2015 – $2 million) 

 Financing Cash Flows 

Net cash used in financing activities decreased $213.5 million to $45.8 million for the three months ended March 31, 2016 compared to $259.3 million for
the same period in 2015. The decrease was primarily due to the repayment of debt in 2015, partially offset by the 2015 proceeds of the long-term debt issuance by Brunswick Pipeline. 

  
 38 








 Contractual Obligations 

As at March 31, 2016, contractual 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
	 	$	268.8	  	 	$	49.5	  	 	$	23.8	  	 	$	610.1	  	 	$	748.5	  	 	$	2,301.2	  	 	$	4,001.9	  
	 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	  
	 Pension and post-retirement obligations (2)
	 	 	11.1	  	 	 	19.2	  	 	 	19.8	  	 	 	20.2	  	 	 	20.9	  	 	 	716.7	  	 	 	807.9	  
	 Asset retirement obligations
	 	 	5.1	  	 	 	4.0	  	 	 	4.3	  	 	 	4.2	  	 	 	1.7	  	 	 	317.2	  	 	 	336.5	  
	 Interest payment obligations (3)
	 	 	140.0	  	 	 	177.4	  	 	 	175.1	  	 	 	167.7	  	 	 	138.8	  	 	 	2,244.7	  	 	 	3,043.7	  
	 Convertible debentures represented by instalment
receipts (4)
	 	 	727.6	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	727.6	  
	 Interest obligations on the first instalment of convertible debentures represented by instalment
receipts (4)
	 	 	54.1	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	54.1	  
	 Transportation (5)
	 	 	188.9	  	 	 	118.6	  	 	 	78.2	  	 	 	43.2	  	 	 	41.1	  	 	 	86.3	  	 	 	556.3	  
	 Long-term service agreements (6)
	 	 	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 (7)
	 	 	356.0	  	 	 	183.0	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	539.0	  
	 Leases and other (8)
	 	 	18.9	  	 	 	9.9	  	 	 	9.0	  	 	 	8.4	  	 	 	7.3	  	 	 	19.0	  	 	 	72.5	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 
		 	$	2,191.4	  	 	$	956.3	  	 	$	595.5	  	 	$	1,099.6	  	 	$	1,173.9	  	 	$	8,267.7	  	 	$	14,284.4	  
		 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 	 	  
	  
	 

  

	(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)	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’s 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. 


	(3)	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 March 31, 2016, including any expected required payment under associated swap agreements. 


	(4)	In 2015, to finance a portion of the pending acquisition of TECO Energy, Emera completed the sale of $2.185 billion aggregate principal amount of four per cent convertible unsecured subordinated debentures. The
Debentures were sold on an instalment basis, with 1/3 paid on closing of the Debenture Offering, and the remaining payable on a date to be fixed following satisfaction of conditions precedent to the closing of the acquisition of TECO Energy.



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


	(6)	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.



	(7)	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. 


	(8)	Operating lease agreements for office space, land, plant fixtures and equipment, telecommunications services, rail cars and vehicles. 


Other Contractual Obligations 
 On September 4, 2015,
the Company announced a definitive agreement for Emera to acquire TECO Energy for $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. Further information on the pending acquisition of TECO Energy is discussed in the Developments section. 

  
 39 








 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 per the table below. NSPI has an active commercial paper program for up to $400 million, of which the full amount outstanding is backed by NSPI’s operating credit facility referred to below. The amount of
commercial paper issued results in an equal amount of its operating credit facility being considered drawn and unavailable. 
 As at March 31, 2016,
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	  	  	$	276	  	  	$	424	  
	 NSPI – Operating credit facility
	  	 	October 2020 – Revolver	  	  	 	500	  	  	 	386	  	  	 	114	  
	 Emera Maine – in USD – Operating credit facility
	  	 	September 2019 – Revolver	 	  	 	80	  	  	 	21	  	  	 	59	  
	 Other – in USD – Operating credit facilities
	  	 	Various	  	  	 	32	  	  	 	2	  	  	 	30	  

 Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the
Company is in compliance with covenant requirements as at March 31, 2016. 
 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. 
 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 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’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, 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. 

  
 40 








 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 recent financing activity is discussed further in the Developments section.

 Guarantees and Letters of Credit 
 There were no
changes in Emera’s standby letters of credit since its year end disclosure at December 31, 2015. 
 OUTLOOK 

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 in recent years, 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 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 also take into account the changing energy landscape. Gas extraction from the Marcellus Shale region of the United
States, major new hydro developments in Newfoundland and Labrador, and development of new 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 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 or ‘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, like wind turbine technology, 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 customer expectations that they will be 

  
 41 








 
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. 
 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 in itself. 

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. Approximately 95 per cent of the expected foreign exchange exposure to close the pending acquisition has been effectively hedged. 

Emera’s operations are affected by the US dollar relative to the Canadian dollar. With the 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. 
 While NSPI has experienced an unseasonably warm heating season with increased storm activity, NSPI anticipates earning within its allowed
ROE range in 2016 and expects its earnings and rate base to be generally consistent with prior years. 
 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 investment in renewable energy sources and purchasing third party renewable energy. 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. In accordance with the Electricity Plan Act, NSPI filed a three-year
rate plan with the UARB for Fuel Costs in Q1 2016, which requested average annual rate increases of 1.3 per cent for 2017 through 2019. NSPI also announced that it will not file a general rate application for non-fuel costs for the 2017 to 2019
period. This was a result of NSPI continuing to work towards rate stability for customers through a focused effort on operating costs, productivity levels and service improvements. 

In 2015, NSPI filed an application with the UARB for the introduction of a regulatory framework to enable the purchase by retail customers of renewable
low-impact electricity generated in Nova Scotia from retail suppliers licensed by the UARB. In Q1 2016, The UARB issued a decision affirming NSPI’s proposed framework subject to small revisions. It is expected the market implementation
process will be completed by the end of 2016. 

  
 42 








 Capital expenditures for 2016, including AFUDC are forecasted to be $282.5 million (2015 - $274.0 million
actual). 
 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 and earnings are expected to be generally 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 to southern New England markets. As part of this agreement, Emera Maine and Central Maine Power
Company jointly responded in Q1 2016 to a request for proposals from Massachusetts, Connecticut and Rhode Island. The demand for new renewable energy, and the infrastructure to deliver that energy to market, is growing as a result of increasing
renewable portfolio requirements of the southern New England states. 
 There are three outstanding pending complaints, with the FERC, to challenge the
ISO-New England Open Access Transmission Tariff-allowed base ROE. On March 22, 2016, the Administrative Law Judge (“ALJ”) issued a recommended decision to the FERC with respect to the first two outstanding ROE complaints. The ALJ
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. A reserve was
calculated on a 10.57 per cent base and represents Emera Maine’s best estimate of the probable outcome for the two outstanding complaints, and no update was made to the reserve based on the ALJ recommendation, as it is pending approval by
the FERC and considered uncertain until that time. 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. No reserve has been made as
a result of this complaint, as the outcome is considered uncertain. 
 In 2016, Emera Maine expects to invest approximately $89.5 million (2015 - $66
million actual), including approximately $42.9 million for transmission projects. 
 Emera Caribbean 

Earnings from Emera Caribbean are most directly impacted by the combined impacts of the range of rates of return on rate base approved by their regulators,
capital structure, 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 is forecasted to grow modestly in 2016. With oil being the predominant fuel source for generation of electricity in the
Caribbean, reduced oil prices may result in an economic benefit on the island in decreased cost of electricity to ratepayers. 
 The economy of Grand Bahama
is highly correlated to the United States economy. In 2015, the economy of Grand Bahama exhibited signs of improving with economic growth in the industrial sector and weather related growth in the residential sector. 2016 sales are expected to be
flat compared to 2015. 

  
 43 








 Overall, Emera Caribbean earnings and rate base are expected to be generally consistent with prior years.
GBPC’s 2016 earnings will reflect its 8.8 per cent allowable return on rate base. 
 Emera Caribbean plans to invest approximately $125.2 million
in capital programs in 2016 (2015 - $44.0 million actual). This increase is due to spending on a new solar facility in Barbados. 
 Pipelines 

The timing of the income from Pipelines is predominately a result of capital lease accounting treatment of the Emera Brunswick Pipeline, which yields declining
earnings over the life of the asset. 
 Pipelines’ 2016 earnings are expected to be lower than 2015 as a result of less favourable foreign exchange
exposure and higher OM&G costs. 
 Emera Energy 

Emera Energy Services 
 Emera Energy Services, Emera Energy’s
marketing and trading business, is generally dependent on market conditions. In particular, volatility in electricity and natural gas markets, which can be influenced by weather, local supply constraints and other supply/demand factors, can provide
higher levels of margin opportunity. 
 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 United States over the next few years could reduce the degree of
volatility recently experienced in the market, all other things being equal. This could negatively affect profitability during certain periods. 
 Emera
Energy Generation 
 Earnings from Emera Energy Generation’s assets are largely dependent on market conditions, in particular, the relative pricing of
electricity and natural gas and capacity pricing for the New England Gas Generation Facilities. Efficient operations of the fleet to ensure unit availability, cost management and effective commercial performance are key success factors. 

2016 adjusted earnings from Emera Energy generating assets are expected to be lower than 2015, reflecting lower hedged and expected margins as compared to
2015. 
 In addition to energy margins and ancillary revenue, the 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 2020, 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. 

  
 44 









					
	 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 are expected to be offset by higher capacity revenues. 
 In 2016, Emera Energy expects to invest
approximately $41.0 million (2015 – $42.0 million actual) in capital projects related to its generating assets in order to further improve reliability and increase plant capacity. 

Corporate and Other 
 Corporate and Other is dependent, in
part, on business development and acquisition related initiatives, which in 2016 will include further costs related to the pending TECO Energy acquisition, AFUDC earnings as a result of equity investments in the Maritime Link Project and the
Labrador-Island Link, project-based construction services activity by Emera Utility Services, growth in APUC earnings (which Emera accounts one quarter after APUC reports such earnings), corporate financing costs 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 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 percentage
ownership interest in APUC. 
 In 2016, Corporate and Other expects to invest approximately $8.0 million (2015 - $10.0 million actual). 

ENL 
 NSP Maritime Link Inc. (“NSPML”)

 Through its subsidiary, NSP Maritime Link Inc., ENL had invested at March 31, 2016, approximately $796.7 million of equity, debt and working
capital, including $90.3 million of AFUDC, in the development of the Maritime Link Project. Project to date, ENL has invested $206.4 million in equity, comprised of $169.3 million in equity contributed and $37.1 million of accumulated retained
earnings, with the remaining costs being funded with working capital and debt. The debt 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 amount and 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 2014 were used to fund project costs until the Project’s debt to equity ratio
reached 70 per cent to 30 per cent respectively in Q4 2015. From that point forward, project costs are being funded with debt and equity at a 70 per cent to 30 per cent ratio, with equity contributions of $14.4 million in Q1
2016. 

  
 45 








 Maritime Link Project forecasted equity contributions for 2016 and 2017 are $160 million and $156 million
respectively, with total equity for the Project estimated to be $470.9 million. 
 Labrador Island Link (“LIL”) 

ENL is a limited partner with Nalcor Energy in LIL, currently estimated at approximately $3.1 billion. As at March 31, 2016, ENL has invested $250.4
million, comprised of $224.5 million in equity contributed and $25.9 million of accumulated equity earnings in LIL. 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 filed by another regulated electrical utility in Newfoundland and Labrador, 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. Future earnings are dependent on the amount and timing of additional equity investments and the approved ROE. Total equity contributions for Q1 2016 for LIL were $38.4 million. 

LIL forecasted equity contributions for 2016 and 2017 are $196.0 million and $27.0 million respectively, 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. Below are transactions between
Emera and its associated companies reported in the Consolidated Statements of Income: 
  

													
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	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). 

  
 46 








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

									
	As at	  	March 31	 	  	December 31	 
	 millions of Canadian dollars
	  	2016	 	  	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.
 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS 

Emera’s risk management profile and practices have not changed materially from December 31, 2015. 

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	  	March 31	 	  	December 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Derivative instrument assets (current and other assets)
	  	$	11.7	  	  	$	19.8	  
	 Derivative instrument liabilities (current and long-term liabilities)
	  	 	(28.5	) 	  	 	(46.2	) 
		  	  
	  
	 	  	  
	  
	 
	 Net derivative instrument assets (liabilities)
	  	$	(16.8	) 	  	$	(26.4	) 
		  	  
	  
	 	  	  
	  
	 


  
 47 








 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	  	Three months ended
March 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Operating revenues – regulated
	  	$	(3.2	) 	  	$	(2.1	) 
	 Non-regulated fuel for generation and purchased power
	  	 	4.2	  	  	 	5.6	  
	 Income from equity investments
	  	 	(0.3	) 	  	 	(0.2	) 
		  	  
	  
	 	  	  
	  
	 
	 Effective net gains (losses)
	  	$	0.7	  	  	$	3.3	  
		  	  
	  
	 	  	  
	  
	 

 The effectiveness 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	  	Three months ended
March 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Non-regulated fuel for generation and purchased power
	  	$	(1.0	) 	  	$	(0.6	) 
		  	  
	  
	 	  	  
	  
	 
	 Ineffective gains (losses)
	  	$	(1.0	) 	  	$	(0.6	) 
		  	  
	  
	 	  	  
	  
	 

 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	  	March 31	 	  	December 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Derivative instrument assets (current and other assets)
	  	$	131.3	  	  	$	209.9	  
	 Regulatory assets (current and other assets)
	  	 	51.5	  	  	 	64.3	  
	 Derivative instrument liabilities (current and long-term liabilities)
	  	 	(49.8	) 	  	 	(64.3	) 
	 Regulatory liabilities (current and long-term liabilities)
	  	 	(131.3	) 	  	 	(209.9	) 
		  	  
	  
	 	  	  
	  
	 
	 Net asset (liability)
	  	$	1.7	  	  	$	—  	  
		  	  
	  
	 	  	  
	  
	 

 Regulatory Impact Recognized in Net Income 

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

 

									
	For the	  	Three months ended
March 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Regulated fuel for generation and purchased power (1)
	  	$	3.0	  	  	$	(1.1	) 
		  	  
	  
	 	  	  
	  
	 
	 Net gains (losses)
	  	$	3.0	  	  	$	(1.1	) 
		  	  
	  
	 	  	  
	  
	 

  

	(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. 


  
 48 








 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	  	March 31	 	  	December 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Derivative instruments assets (current and other assets)
	  	$	33.7	  	  	$	95.3	  
	 Derivative instruments liabilities (current and long-term liabilities)
	  	 	(141.8	) 	  	 	(331.9	) 
		  	  
	  
	 	  	  
	  
	 
	 Net derivative instrument assets (liabilities)
	  	$	(108.1	) 	  	$	(236.6	) 
		  	  
	  
	 	  	  
	  
	 

 Held-for-trading Items Recognized in Net Income 

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

 

									
	For the	  	Three months ended
March 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Operating revenues – non-regulated
	  	$	221.6	  	  	$	94.0	  
	 Non-regulated fuel for generation and purchased power
	  	 	(0.7	) 	  	 	0.2	  
		  	  
	  
	 	  	  
	  
	 
	 Net gains (losses)
	  	$	220.9	  	  	$	94.2	  
		  	  
	  
	 	  	  
	  
	 

 Other Derivatives Recognized on the Balance Sheets 

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

 

									
	As at	  	March 31	 	  	December 31	 
	 millions of Canadian dollars
	  	2016	 	  	2015	 
	 Derivative instrument assets (current and other assets)
	  	$	1.1	  	  	$	92.1	  
	 Derivative instrument liabilities (current and long-term liabilities)
	  	 	(7.0	) 	  	 	(2.9	) 
		  	  
	  
	 	  	  
	  
	 
	 Net derivative instrument assets (liabilities)
	  	$	(5.9	) 	  	$	89.2	  
		  	  
	  
	 	  	  
	  
	 

 Other Derivatives Recognized in Net Income 

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

 

									
	For the	  	Three months ended	 
	 millions of Canadian dollars
	  	March 31	 
	 	  	2016	 	  	2015	 
	 Other income (expense)
	  	$	(94.8	) 	  	$	—  	  
	 Interest expense, net
	  	 	(0.3	) 	  	 	—  	  
		  	  
	  
	 	  	  
	  
	 
	 Total gains (losses)
	  	$	(95.1	) 	  	$	—  	  
		  	  
	  
	 	  	  
	  
	 

 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
March 31, 2016 disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”). These terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’
Annual and Interim Filings (“NI 52-109”). 
 There have been no changes in Emera or its consolidated subsidiaries’ ICFR for the three months
ended on March 31, 2016, which has materially affected, or is reasonably likely to materially affect the Company’s ICFR. 
  

  
 49 








 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, including deferred taxes, asset retirement obligations, capitalized overhead and valuation of
derivative instruments. Actual results may differ significantly from these estimates. 
 CHANGES IN ACCOUNTING POLICIES AND PRACTICES 

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. 

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. 

  
 50 








 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. 
 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. 

  
 51 








 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. 

  
 52 








 SUMMARY OF QUARTERLY RESULTS 
  

																																	
	For the quarter ended	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	millions of dollars	 	Q1	 	 	Q4	 	 	Q3	 	 	Q2	 	 	Q1	 	 	Q4	 	 	Q3	 	 	Q2	 
	 (except per share amounts)
	 	2016	 	 	2015	 	 	2015	 	 	2015	 	 	2015	 	 	2014	 	 	2014	 	 	2014	 
	 Operating revenues
	 	$	877.0	  	 	$	731.6	  	 	$	642.3	  	 	$	526.9	  	 	$	888.5	  	 	$	782.7	  	 	$	539.0	  	 	$	566.6	  
	 Net income attributable to common shareholders
	 	 	44.3	  	 	 	192.1	  	 	 	35.0	  	 	 	10.0	  	 	 	160.1	  	 	 	151.2	  	 	 	28.2	  	 	 	24.5	  
	 Adjusted net income attributable to common shareholders
	 	 	120.2	  	 	 	87.1	  	 	 	23.3	  	 	 	48.0	  	 	 	171.6	  	 	 	78.5	  	 	 	49.9	  	 	 	44.2	  
	 Earnings per common share – basic
	 	 	0.30	  	 	 	1.31	  	 	 	0.24	  	 	 	0.07	  	 	 	1.10	  	 	 	1.05	  	 	 	0.20	  	 	 	0.17	  
	 Earnings per common share – diluted
	 	 	0.30	  	 	 	1.30	  	 	 	0.24	  	 	 	0.07	  	 	 	1.09	  	 	 	1.02	  	 	 	0.20	  	 	 	0.17	  
	 Adjusted earnings per common share – basic
	 	 	0.81	  	 	 	0.59	  	 	 	0.16	  	 	 	0.33	  	 	 	1.18	  	 	 	0.54	  	 	 	0.35	  	 	 	0.31	  

 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 in northeastern 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. 

  
 53