Audited Comparative Financial Statements



 Exhibit 4.1 

 

 

 EMERA INC. 
 Consolidated Financial Statements and Management’s Discussion and Analysis 
 December 31, 2010 and 2009 

  
 1 









 

 

 MANAGEMENT REPORT 
 Management’s Responsibility for Financial Reporting 
 The accompanying consolidated
financial statements of Emera Inc. and the information in this annual report are the responsibility of management and have been approved by the Board of Directors (“Board”). 
 The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. When alternative accounting methods exist, management has
chosen those it deems most appropriate in the circumstances. Nova Scotia Power Inc., one of Emera’s wholly-owned electric utilities and principal subsidiary, is regulated by the Nova Scotia Utility and Review Board, which also examines and
approves NSPI’s accounting policies and practices. Emera’s other wholly-owned electric utility and subsidiaries, Bangor Hydro Electric Company and Maine Public Service Company, are regulated by the Federal Energy Regulatory Commission and
the Maine Public Utilities Commission, which also examine and approve Bangor Hydro Electric Company and Maine Public Service Company’s accounting policies and practices. Emera Brunswick Pipeline Company Ltd., which is wholly-owned, is regulated
by the National Energy Board. 
 In preparation of these consolidated financial statements, estimates are sometimes necessary when transactions
affecting the current accounting period cannot be finalized with certainty until future periods. Management believes that such estimates, which have been properly reflected in the accompanying consolidated financial statements, are based on careful
judgements and are within reasonable limits of materiality. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects. Management has
prepared the financial information presented elsewhere in the annual report and has ensured that it is consistent with that in the consolidated financial statements. 
 Emera Inc. maintains effective systems of internal accounting and administrative controls, consistent with reasonable cost. Such systems are designed to provide reasonable assurance that the financial
information is relevant, reliable and accurate, and that Emera Inc.’s assets are appropriately accounted for and adequately safeguarded. 

The Board is responsible for ensuring that management fulfils its responsibilities for financial reporting and is ultimately responsible for reviewing
and approving the consolidated financial statements. The Board carries out this responsibility principally through its Audit Committee. 
 The
Audit Committee is appointed by the Board, and its members are directors who are not officers or employees of Emera Inc. The Audit Committee meets periodically with management, as well as with the internal auditors and with the external auditors, to
discuss internal controls over the financial reporting process, auditing matters and financial reporting issues, to satisfy itself that each party is properly discharging its responsibilities, and to review the annual report, the consolidated
financial statements and the external auditors’ report. The Audit Committee reports its findings to the Board for consideration when approving the consolidated financial statements for issuance to the shareholders. The Audit Committee also
considers, for review by the Board and approval by the shareholders, the appointment of the external auditors. 
 The consolidated financial
statements have been audited by Ernst & Young LLP, the external auditors, in accordance with Canadian generally accepted auditing standards. Ernst & Young LLP has full and free access to the Audit Committee. 

February 11, 2011 
  

					
			
	  	 		 	  
	“Christopher Huskilson”	 		 	“Nancy Tower, FCA”
	President and Chief Executive Officer	 		 	Chief Financial Officer


  
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 INDEPENDENT AUDITORS’ REPORT 

To the Shareholders of Emera Inc. 
 We have
audited the accompanying consolidated financial statements of Emera Inc., which comprise the consolidated statement of financial position as at December 31, 2010 and 2009, and the consolidated statement of earnings, consolidated statement of
changes in equity and consolidated statement of cash flows for the years then ended, and a summary of significant accounting policies and other explanatory information. 
 Management’s Responsibility for the Consolidated Financial Statements 
 Management is
responsible for the preparation and fair presentation of these financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation
of financial statements that are free from material misstatement, whether due to fraud or error. 
 Auditors’ Responsibility

 Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in
accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audits to obtain reasonable assurance about whether the financial statements are free from
material misstatement. 
 An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial
statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor
considers internal controls relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the entity’s internal controls. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall
presentation of the financial statements. 
 We believe that the audit evidence we have obtained is sufficient and appropriate to provide a
basis for our audit opinion. 
 Opinion 
 In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Emera Inc. as at December 31, 2010 and 2009, and the results of its
operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. 
  

	
	Halifax, Canada
	February 11, 2011
	
	 
	“Ernst & Young LLP”
	Chartered Accountants


  
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 Emera Inc. 
 Consolidated Statements of Earnings 
 Year Ended December 31 

 

									
	 millions of dollars (except earnings per common share)
	  	2010	 	 	2009	 
	 Revenue
	  				 			
	 Electric
	  	$	1,436.1	  	 	$	1,402.0	  
	 Finance income from direct financing lease (note 16)
	  	 	56.5	  	 	 	25.3	  
	 Other
	  	 	61.1	  	 	 	56.2	  
		  	 	 	 	 	 	 	 
		  	 	1,553.7	  	 	 	1,483.5	  
		  	 	 	 	 	 	 	 
	 Cost of operations
	  				 			
	 Fuel for generation and purchased power
	  	 	718.7	  	 	 	583.5	  
	 Fuel adjustment (note 5)
	  	 	(99.0	) 	 	 	8.5	  
	 Operating, maintenance and general
	  	 	336.1	  	 	 	294.4	  
	 Provincial, state, and municipal taxes
	  	 	49.1	  	 	 	49.9	  
	 Depreciation and amortization
	  	 	173.6	  	 	 	164.9	  
	 Regulatory amortization
	  	 	41.3	  	 	 	35.7	  
		  	 	 	 	 	 	 	 
		  	 	1,219.8	  	 	 	1,136.9	  
		  	 	 	 	 	 	 	 
		  	 	333.9	  	 	 	346.6	  
	 Equity earnings (note 7)
	  	 	13.6	  	 	 	14.0	  
	 Financing charges (note 8)
	  	 	168.4	  	 	 	135.3	  
		  	 	 	 	 	 	 	 
	 Earnings before income taxes and non-controlling interest
	  	 	179.1	  	 	 	225.3	  
	 Income taxes (note 9)
	  	 	(12.8	) 	 	 	48.9	  
		  	 	 	 	 	 	 	 
	 Net earnings before non-controlling interest
	  	 	191.9	  	 	 	176.4	  
	 Non-controlling interest (note 18)
	  	 	(2.3	) 	 	 	0.7	  
		  	 	 	 	 	 	 	 
	 Net earnings
	  	 	194.2	  	 	 	175.7	  
	 Preferred share dividends
	  	 	3.1	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Net earnings applicable to common shares
	  	$	191.1	  	 	$	175.7	  
		  	 	 	 	 	 	 	 
	 Earnings per common share – basic (note 11)
	  	$	1.68	  	 	$	1.56	  
		  	 	 	 	 	 	 	 
	 Earnings per common share – diluted (note 11)
	  	$	1.65	  	 	$	1.52	  
		  	 	 	 	 	 	 	 

 See accompanying notes to the consolidated financial statements. 

  
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 Emera Inc. 
 Consolidated Balance Sheets 
 As at December 31 

 

									
	 millions of dollars
	  	2010	 	  	2009	 
	 Assets
	  				  			
	 Current assets
	  				  			
	 Cash and cash equivalents
	  	$	9.4	  	  	$	21.8	  
	 Restricted cash
	  	 	59.6	  	  	 	1.0	  
	 Accounts receivable (note 12)
	  	 	396.5	  	  	 	413.1	  
	 Income tax receivable
	  	 	50.7	  	  	 	11.0	  
	 Inventory (note 13)
	  	 	177.8	  	  	 	174.5	  
	 Prepaid expenses
	  	 	9.8	  	  	 	7.4	  
	 Future income tax assets (note 9)
	  	 	28.2	  	  	 	46.7	  
	 Derivatives in a valid hedging relationship
	  	 	28.4	  	  	 	26.3	  
	 Held-for-trading derivatives
	  	 	22.1	  	  	 	13.1	  
		  	 	 	 	  	 	 	 
		  	 	782.5	  	  	 	714.9	  
		  	 	 	 	  	 	 	 
	 Derivatives in a valid hedging relationship
	  	 	26.1	  	  	 	30.9	  
	 Held-for-trading derivatives
	  	 	15.3	  	  	 	30.7	  
	 Other assets (note 14)
	  	 	652.1	  	  	 	427.4	  
	 Future income tax assets (note 9)
	  	 	12.9	  	  	 	4.4	  
	 Goodwill (note 21)
	  	 	178.9	  	  	 	87.6	  
	 Intangibles (note 15)
	  	 	103.5	  	  	 	92.1	  
	 Investments subject to significant influence (note 7)
	  	 	238.9	  	  	 	218.4	  
	 Available-for-sale investments (note 29)
	  	 	47.0	  	  	 	47.3	  
	 Net investment in direct financing lease (note 16)
	  	 	488.2	  	  	 	476.9	  
	 Property, plant & equipment (note 17)
	  	 	3,450.7	  	  	 	2,933.7	  
	 Construction work in progress
	  	 	333.0	  	  	 	220.2	  
		  	 	 	 	  	 	 	 
		  	 	3,783.7	  	  	 	3,153.9	  
		  	 	 	 	  	 	 	 
		  	$	6,329.1	  	  	$	5,284.5	  
		  	 	 	 	  	 	 	 


  
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 Emera Inc. 
 Consolidated Balance Sheets (continued) 
 As at December 31 

 

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Liabilities and Shareholders’ Equity
	  				 			
	 Current liabilities
	  				 			
	 Current portion of long-term debt (note 24)
	  	$	12.7	  	 	$	108.1	  
	 Short-term debt (note 23)
	  	 	228.1	  	 	 	300.3	  
	 Accounts payable and accrued charges
	  	 	399.6	  	 	 	305.9	  
	 Income tax payable
	  	 	8.4	  	 	 	9.3	  
	 Dividends payable
	  	 	1.8	  	 	 	1.7	  
	 Derivatives in a valid hedging relationship
	  	 	8.6	  	 	 	61.0	  
	 Held-for-trading derivatives
	  	 	31.1	  	 	 	18.6	  
		  	 	 	 	 	 	 	 
		  	 	690.3	  	 	 	804.9	  
		  	 	 	 	 	 	 	 
	 Derivatives in a valid hedging relationship
	  	 	21.3	  	 	 	25.7	  
	 Held-for-trading derivatives
	  	 	18.0	  	 	 	15.8	  
	 Future income tax liabilities (note 9)
	  	 	359.8	  	 	 	194.1	  
	 Asset retirement obligations (note 22)
	  	 	141.8	  	 	 	104.5	  
	 Other liabilities (note 14)
	  	 	161.7	  	 	 	148.1	  
	 Long-term debt (note 24)
	  	 	3,006.9	  	 	 	2,318.4	  
	 Preferred shares issued by subsidiary (note 10)
	  	 	135.0	  	 	 	135.0	  
	 Non-controlling interest (note 18)
	  	 	20.7	  	 	 	32.1	  
	 Shareholders’ equity
	  				 			
	 Common shares (note 25)
	  	 	1,136.5	  	 	 	1,096.7	  
	 Preferred shares (note 26)
	  	 	146.7	  	 	 	—  	  
	 Contributed surplus
	  	 	3.7	  	 	 	3.6	  
	 Accumulated other comprehensive loss
	  	 	(164.7	) 	 	 	(186.7	) 
	 Retained earnings
	  	 	651.4	  	 	 	592.3	  
		  	 	 	 	 	 	 	 
		  	 	1,773.6	  	 	 	1,505.9	  
		  	 	 	 	 	 	 	 
		  	$	6,329.1	  	 	$	5,284.5	  
		  	 	 	 	 	 	 	 

 Change in accounting estimate (note 2), Contingencies (note 31), Commitments (notes 6, 29 and 32), Guarantees (note 33),
Subsequent events (note 35) 
 See accompanying notes to the consolidated financial statements. 

Approved on behalf of the Board of Directors 
  

					
			
	  	 		 	  
	“John McLennan”	 		 	“Christopher Huskilson”
	Chairman	 		 	President and Chief Executive Officer


  
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 Emera Inc. 
 Consolidated Statements of Cash Flows 
 Year Ended December 31 

 

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Operating activities
	  				 			
	 Net earnings
	  	$	194.2	  	 	$	175.7	  
	 Non-cash items:
	  				 			
	 Depreciation and amortization
	  	 	173.6	  	 	 	164.9	  
	 Amortization of other assets
	  	 	16.9	  	 	 	18.8	  
	 Equity earnings
	  	 	(13.6	) 	 	 	(14.0	) 
	 Fuel adjustment (note 5)
	  	 	(99.0	) 	 	 	8.5	  
	 Regulatory amortization
	  	 	41.3	  	 	 	35.7	  
	 Allowance for funds used during construction
	  	 	(22.2	) 	 	 	(28.9	) 
	 Interest (recovery) expense on deferral of FAM
	  	 	(3.8	) 	 	 	1.4	  
	 Future income taxes (note 9)
	  	 	34.7	  	 	 	(2.1	) 
	 Post-retirement benefits
	  	 	(11.4	) 	 	 	(16.4	) 
	 Non-controlling interest
	  	 	(2.3	) 	 	 	0.7	  
	 Changes in fair value of derivatives instruments
	  	 	26.0	  	 	 	(19.8	) 
	 Other non-cash operating items
	  	 	(6.1	) 	 	 	3.4	  
	 Other cash operating items
	  	 	7.8	  	 	 	8.0	  
		  	 	 	 	 	 	 	 
		  	 	336.1	  	 	 	335.9	  
	 Change in non-cash operating working capital (note 27)
	  	 	80.3	  	 	 	(25.7	) 
		  	 	 	 	 	 	 	 
	 Net cash provided by operating activities
	  	 	416.4	  	 	 	310.2	  
		  	 	 	 	 	 	 	 
	 Investing activities
	  				 			
	 Property, plant and equipment
	  	 	(527.2	) 	 	 	(326.6	) 
	 Intangibles
	  	 	(14.2	) 	 	 	(12.5	) 
	 Increase in restricted cash
	  	 	(58.4	) 	 	 	(0.3	) 
	 Retirement spending net of salvage
	  	 	(16.3	) 	 	 	(8.9	) 
	 Acquisitions (note 18)
	  	 	(267.0	) 	 	 	(36.7	) 
	 Net investment in direct financing lease
	  	 	(10.8	) 	 	 	(53.4	) 
	 Investments
	  	 	(0.9	) 	 	 	71.2	  
		  	 	 	 	 	 	 	 
	 Net cash used in investing activities
	  	 	(894.8	) 	 	 	(367.2	) 
		  	 	 	 	 	 	 	 
	 Financing activities
	  				 			
	 Retirements of long-term debt
	  	 	(346.8	) 	 	 	(130.0	) 
	 Issuance of long-term debt
	  	 	542.3	  	 	 	725.0	  
	 Increase (decrease) in short-term debt
	  	 	232.5	  	 	 	(279.6	) 
	 Issuance of common shares
	  	 	39.3	  	 	 	14.9	  
	 Issuance of preferred shares
	  	 	145.2	  	 	 	—  	  
	 Dividends on common shares
	  	 	(132.0	) 	 	 	(115.8	) 
	 Dividends on preferred shares
	  	 	(3.0	) 	 	 	—  	  
	 Redemption of preferred shares issued by a subsidiary
	  	 	—  	  	 	 	(125.0	) 
	 Other financing activities
	  	 	(11.3	) 	 	 	(19.0	) 
		  	 	 	 	 	 	 	 
	 Net cash provided by financing activities
	  	 	466.2	  	 	 	70.5	  
		  	 	 	 	 	 	 	 
	 Effect of exchange rate changes on cash and cash equivalents
	  	 	(0.2	) 	 	 	(3.9	) 
		  	 	 	 	 	 	 	 
	 (Decrease) increase in cash and cash equivalents
	  	 	(12.4	) 	 	 	9.6	  
	 Cash and cash equivalents, beginning of year
	  	 	21.8	  	 	 	12.2	  
		  	 	 	 	 	 	 	 
	 Cash and cash equivalents, end of year
	  	$	9.4	  	 	$	21.8	  
		  	 	 	 	 	 	 	 
	 Cash and cash equivalents consists of:
	  				 			
	 Cash
	  	$	9.4	  	 	$	21.5	  
	 Short-term investments
	  	 	—  	  	 	 	0.3	  
		  	 	 	 	 	 	 	 
	 Cash and cash equivalents, end of year
	  	$	9.4	  	 	$	21.8	  
		  	 	 	 	 	 	 	 
	 Supplemental disclosure of cash paid (recovered):
	  				 			
	 Interest
	  	$	149.7	  	 	$	127.4	  
		  	 	 	 	 	 	 	 
	 Income and capital taxes
	  	$	(2.1	) 	 	$	49.0	  
		  	 	 	 	 	 	 	 

 See accompanying notes to the consolidated financial statements. 

  
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 Emera Inc. 
 Consolidated Statements of Changes in Shareholders’ Equity 
  

																									
	For the year ended December 31, 2010	  	Common	 	  	Preferred	 	  	Contributed	 	 	Accumulated Other
Comprehensive
(Loss) Income	 	 	Retained	 	 	Total
AOCI and
Retained	 
	 millions of dollars
	  	Shares	 	  	Shares	 	  	Surplus	 	 	(“AOCI”)	 	 	Earnings	 	 	Earnings	 
	 Balance, December 31, 2009
	  	$	1,096.7	  	  	 	—  	  	  	$	3.6	  	 	$	(186.7	) 	 	$	592.3	  	 	$	405.6	  
		  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Comprehensive income:
	  				  				  				 				 				 			
	 Net earnings
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	194.2	  	 	 	194.2	  
	 Net gains on derivatives in a valid hedging relationship
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	10.7	  	 	 	—  	  	 	 	10.7	  
	 Reclassification of hedging losses included in income
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	61.5	  	 	 	—  	  	 	 	61.5	  
	 Reclassification of hedging gains included in inventory
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	(17.5	) 	 	 	—  	  	 	 	(17.5	) 
	 Unrealized foreign exchange loss on translation of self-sustaining foreign operations
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	(32.7	) 	 	 	—  	  	 	 	(32.7	) 
		  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total comprehensive income
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	22.0	  	 	 	194.2	  	 	 	216.2	  
		  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Issuance of preferred shares (note 26)
	  	 	—  	  	  	$	146.7	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Dividends declared on common shares
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(132.0	) 	 	 	(132.0	) 
	 Dividends declared on preferred shares
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(3.1	) 	 	 	(3.1	) 
	 Dividends paid by subsidiaries to non-controlling interest
	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Common shares issued under purchase plans
	  	 	32.8	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Senior management stock options exercised
	  	 	6.0	  	  	 	—  	  	  	 	(0.5	) 	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Stock option expense
	  	 	—  	  	  	 	—  	  	  	 	0.6	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Other share-based compensation
	  	 	1.0	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
		  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31, 2010
	  	$	1,136.5	  	  	$	146.7	  	  	$	3.7	  	 	$	(164.7	) 	 	$	651.4	  	 	$	486.7	  
		  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
							
	For the year ended December 31, 2009	  	 	 	  	Common	 	  	Contributed	 	 	 	 	 	Retained	 	 	Total
AOCI and
Retained	 
	 millions of dollars
	  	 	 	  	Shares	 	  	Surplus	 	 	AOCI	 	 	Earnings	 	 	Earnings	 
	 Balance, December 31, 2008
	  				  	$	1,081.4	  	  	$	3.4	  	 	$	(69.2	) 	 	$	532.4	  	 	$	463.2	  
		  				  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Comprehensive income:
	  				  				  				 				 				 			
	 Net earnings
	  				  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	175.7	  	 	 	175.7	  
	 Net losses on derivatives in a valid hedging relationship
	  				  	 	—  	  	  	 	—  	  	 	 	(99.9	) 	 	 	—  	  	 	 	(99.9	) 
	 Reclassification of hedging losses included in income
	  				  	 	—  	  	  	 	—  	  	 	 	33.2	  	 	 	—  	  	 	 	33.2	  
	 Reclassification of hedging losses included in inventory
	  				  	 	—  	  	  	 	—  	  	 	 	29.3	  	 	 	—  	  	 	 	29.3	  
	 Unrealized foreign exchange loss on translation of self-sustaining foreign operations
	  				  	 	—  	  	  	 	—  	  	 	 	(80.4	) 	 	 	—  	  	 	 	(80.4	) 
	 Other
	  				  	 	—  	  	  	 	—  	  	 	 	0.3	  	 	 	—  	  	 	 	0.3	  
		  				  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total comprehensive (loss) income
	  				  	 	—  	  	  	 	—  	  	 	 	(117.5	) 	 	 	175.7	  	 	 	58.2	  
		  				  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Dividends declared on common shares
	  				  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(115.8	) 	 	 	(115.8	) 
	 Dividends paid by subsidiaries to non-controlling interest
	  				  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Common shares issued under purchase plans
	  				  	 	8.7	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Senior management stock options exercised
	  				  	 	5.8	  	  	 	(0.4	) 	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Stock option expense
	  				  	 	—  	  	  	 	0.6	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Other share-based compensation
	  				  	 	0.8	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
		  				  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31, 2009
	  				  	$	1,096.7	  	  	$	3.6	  	 	$	(186.7	) 	 	$	592.3	  	 	$	405.6	  
		  				  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 See accompanying notes to the consolidated financial statements. 

  
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 Emera Inc. 
 Notes to the Consolidated Financial Statements 
 December 31, 2010 and 2009

  

	1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 


Emera Inc. (“Emera” or “the Company”), incorporated in the Province of Nova Scotia, is engaged in the production and sale of electric
energy and transportation of natural gas through its principal subsidiaries, Nova Scotia Power Inc. (“NSPI”), Bangor Hydro Electric Company (“Bangor Hydro”), Maine Public Service Company (“MPS”), Grand Bahama Power
Company Limited (“GBPC”) and Emera Brunswick Pipeline Company Ltd. (“Brunswick Pipeline”). 
 NSPI, created through the
privatization in 1992 of the crown corporation Nova Scotia Power Corporation, is a fully-integrated regulated electric utility and the primary electricity supplier in Nova Scotia. NSPI is a public utility as defined under the Public Utilities Act of
Nova Scotia (“Act”) and is subject to regulation under the Act by the Utility and Review Board (“UARB”). The Act gives the UARB authority over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers
are subject to UARB approval. NSPI is not subject to an annual rate review process, but rather participates in hearings from time to time at NSPI’s or the regulator’s request. 
 NSPI’s accounting policies are subject to examination and approval by the UARB. 
 NSPI is
regulated under a cost-of-service model, with rates set to cover prudently incurred costs of providing electricity service to customers, and provide a reasonable return to investors. NSPI’s regulated return on equity (“ROE”) range for
2010 was 9.1% to 9.6% on an allowed common equity component up to 40% of NSPI’s total regulated capitalization. Beginning January 1, 2009, NSPI implemented a Fuel Adjustment mechanism which allows NSPI to recover all prudent fuel cost from
customers. This allows NSPI risk profile to be reduced as the timeliness and certainty of full fuel recovery is managed. The reduction of the risk due to less fuel volatility has allowed NSPI to manage the non-fuel rate requirement more
strategically. 
 In January 2010, NSPI reached an agreement with stakeholders on its calculation of regulated ROE. The agreement establishes
that NSPI will continue to use actual capital structure, actual equity and actual net earnings to calculate actual annual regulated ROE. The agreement was approved by the UARB. The UARB has set, as a condition, that NSPI will maintain its average
actual regulated annual common equity at a level no higher than 40% beginning in 2010 and until the next general rate case. 
 Bangor
Hydro’s core business is the transmission and distribution (“T&D”) of electricity. Electricity is deregulated in Maine, and several suppliers compete to provide customers with the commodity that is delivered through the Bangor
Hydro T&D network. In addition to the T&D network, Bangor Hydro has certain regulatory assets (stranded costs), which arose through the electricity industry restructuring, and as a result of rate and accounting orders issued by its
regulators. Approximately 44% of Bangor Hydro’s electric rates represent distribution services, 11% relate to stranded costs recoveries, and 45% to transmission service. The rates for each element are established in distinct regulatory
proceedings. The transmission operations are regulated by the Federal Energy Regulatory Commission (“FERC”), and the distribution operations and stranded costs are regulated by the Maine Public Utilities Commission (“MPUC”).
Bangor Hydro’s accounting policies are subject to examination and approval by FERC and the MPUC. 
 Bangor Hydro operates under a
traditional cost-of-service regulatory structure. In December 2007, the MPUC approved an increase of approximately 2% in distribution rates effective January 1, 2008. The allowed ROE used in setting these distribution rates was 10.2%, with a
common equity component of 50%. 
 In December 2007, the MPUC issued an order approving an approximately 39% reduction in stranded cost rates
for the three-year period beginning March 1, 2008. The allowed ROE used in setting the new stranded cost rates is 8.5%. Prior to that, stranded cost rates provided for an allowed ROE of 10%. Transmission rates are set by the FERC annually on
June 1, based upon a formula that utilizes prior year actual transmission investments and expenses, adjusted for current year forecasted transmission investments and expenses. The allowed ROE for transmission operations ranges from 11.14% for
low voltage local transmission up to 12.64% for high voltage regionally-funded transmission developed as a result of the regional system plan. 

  
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 Maine & Maritimes Corporation (“MAM”) was acquired on December 21, 2010. Located
in northern Maine, MAM’s core business is also the transmission and distribution of electricity through its regulated electric utility, MPS. Similar to Bangor Hydro, in addition to its T&D network, MPS has net regulatory assets (stranded
costs). Approximately 57% of MPS’s electric rates represent distribution services, 34% relate to stranded cost recoveries, and 9% to transmission services. The rates for each element are established in distinct regulatory proceedings. The
transmission operations are regulated by FERC, and the distribution operations and stranded costs are regulated by the MPUC. MPS’s accounting policies are subject to examination and approval by FERC and the MPUC. 

MPS operates under a traditional cost-of-service regulatory structure. In July 2006, the MPUC approved an increase of approximately 11% in distribution
rates, effective July 15, 2006. The allowed ROE used in setting these distribution rates was 10.2%, with a common equity component of 50%. 

In March 2010, the MPUC issued an order approving a continuation of the levelized stranded cost rates established in rate orders in 2003 and 2006. These
rates are in effect for the two year rate effective period January 1, 2010 through December 31, 2011. The allowed ROE used in setting the new stranded costs was 9.4% in 2010 and 8.6% in 2011, down from the 10.2% ROE allowed in the 2006
stranded cost rate order. 
 Transmission rates are set annually through the Open Access Transmission Tariff (“OATT”). Rates derived
from the previous calendar year’s results go into effect June 1 for wholesale customers and July 1 for retail customers. The allowed ROE for transmission operations is 10.5%, and is based on the actual common equity. The rates under
the 2010 OATT went into effect June 1, 2010 for wholesale customers and July 1, 2010 for retail customers. However, the 2010 OATT has not yet been settled, and accordingly the actual rates allowed for the 2010-2011 rate effective period
could differ from the rates currently being charged. 
 On December 22, 2010, Emera purchased a 50% interest in GBPC and an additional
10.7% interest in ICD Utilities Limited (“ICDU”), owner of the remaining 50% interest in GBPC, bringing Emera’s total ownership of GBPC to 80.4%. Emera has determined it has control of GBPC through the combination of both direct and
indirect interests. GBPC is an integrated utility with 19,000 customers on Grand Bahama Island and has 137 megawatts (“MW”) of installed oil-fired capacity. The Grand Bahama Port Authority regulates the utility and has granted GBPC a
licensed, regulated and exclusive franchise to produce, transmit, and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policies to ensure that costs are recovered and a reasonable
return earned. GBPC is authorized by the Port Authority to adjust fuel costs included in its rates to the extent the weighted average cost of fuel delivered into GBPC’s power plant storage facilities exceeds or is less than $20 Bahamian dollars
per barrel. 
 Brunswick Pipeline, a $485 million, 145-kilometre pipeline carrying re-gasified liquefied natural gas (“LNG”), delivers
natural gas from the CanaportTM LNG import terminal near Saint John, New Brunswick, to markets in the northeastern United States. The pipeline went into service on July 16, 2009. The pipeline travels through southwest New Brunswick and
connects with the Maritimes and Northeast Pipeline (“M&NP”) at the Canada/US border near Baileyville, Maine. 
 CanaportTM LNG
is a partnership of Repsol YPF, S.A. (“Repsol”) and Irving Oil Limited. Emera has negotiated a 25 year firm service agreement with Repsol Energy Canada to transport natural gas through the Brunswick Pipeline. Toll rates were negotiated to
achieve a return on project equity in the range of 11% to 14%. The National Energy Board (“NEB”), which regulates Brunswick Pipeline, has classified it as a Group 2 pipeline. 
 Emera follows Canadian generally accepted accounting principles (“CGAAP”). The accounting policies approved by the regulators of NSPI, Bangor Hydro, MPS and Brunswick Pipeline may differ from
CGAAP for non rate-regulated companies in that the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under CGAAP. Where the differences between CGAAP and CGAAP for rate-regulated
companies are considered significant, disclosure of the policy has been made in these notes to the consolidated financial statements. 

  
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	 	a.	Consolidation 

 The
consolidated financial statements include the accounts of Emera Inc. and its subsidiaries. Intercompany transactions and accounts have been eliminated. 
  

	 	b.	Measurement Uncertainty 


The preparation of financial statements in accordance with CGAAP 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. Estimates and assumptions are based upon historical experience, current conditions and
assumptions believed to be reasonable at the time the estimate is made. Due to changing circumstances and the inherent uncertainty in making estimates, actual results may differ significantly from current estimates. Estimates are reviewed
periodically, with any resulting adjustments reported in earnings in the period they arise. 
 The most significant estimates
include: measurement property plant and equipment depreciation rates (note 1f), intangible assets amortization rates (note 1g), post-employment benefits (note 4), income taxes (note 9), accounts receivable (note 12), of regulatory assets and
liabilities (note 14), asset retirement obligations (note 22) financial instruments (note 29), and contingencies (note 31). Actual results may differ from these estimates. 

 

	 	c.	Revenue Recognition 

 The
Company’s revenue recognition policy is as follows: 
  

	 	•	 	 Electric: Revenues are recognized on the accrual basis, which includes an estimate of electricity consumed by customers in the year but billed
subsequent to year-end. 


  

	 	•	 	 Finance income from direct financing lease: Under the direct financing lease method, the Company records the net investment in a lease, which consists
of the sum of the minimum lease payments, estimated executory costs less the unearned income. The difference between the gross investment and the cost of the leased item for direct financing lease is recorded as unearned income at the inception of
the lease. The unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. 



 

	 	•	 	 Energy Marketing: Derivatives that are not entered into for hedging purposes are recognized at fair market value at year-end.



  

	 	•	 	 Other: Revenues are recognized on the accrual basis, which includes an estimate for services performed and goods delivered during the year but billed
subsequent to year-end. 


  

	 	•	 	 Unearned revenue is recognized as “Other liabilities”. 



Electric revenues generated by NSPI, Bangor Hydro and MPS are recognized at rates set by their respective regulators. The Company is
unable to determine the effect the absence of rate regulation would have on electric revenue. 
  

	 	d.	Allowance for Funds Used during Construction 

 Accounting for the impact of rate regulation: 
 In accordance with their
rate-regulated accounting policies, NSPI, Bangor Hydro, MPS and Brunswick Pipeline provide for the cost of financing construction work in progress by including an allowance for funds used during construction (“AFUDC”) as an addition to the
cost of property constructed, using a weighted average cost-of-capital. AFUDC is included in “Property, plant and equipment”, “Intangibles”, “Construction work in progress” and “Net investment in direct financing
lease” for financial reporting purposes and is charged to operations through depreciation over the service life of the related assets and recovered through future revenues and through financing income from direct financing lease. Since AFUDC
includes not only an interest component, but also an equity component, it exceeds the amount that could be capitalized in the absence of rate-regulated accounting policies. 

  
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	 	e.	Regulatory Amortization 


Accounting for the impact of rate regulation: 
 In December 2010, the UARB granted NSPI approval to defer certain tax benefits related to renewable energy projects arising in 2010 through an increase in regulatory amortization. The UARB will convene a
proceeding in 2011 to discuss how this deferral will be applied. In the absence of UARB approval, 2010 earnings would have been $14.5 million higher. 
 NSPI has a regulatory asset related to pre-2003 income taxes that have been paid, but not yet recovered from customers. This circumstance arose when NSPI claimed capital cost allowance (“CCA”)
deductions in its income tax returns that were ultimately disallowed by a decision of the Supreme Court of Canada. NSPI applied to the regulator to include recovery of these costs in customer rates. The UARB approved recovery of this regulatory
asset over eight years, commencing April 1, 2007. 
 In January 2010, NSPI reached an agreement with stakeholders on its
calculation of regulated ROE. The agreement includes a provision which provides the Company with flexibility in its amortization of the pre-2003 income taxes to accelerate additional amortization amounts in current periods and subsequently reduce
amounts in future periods. In the absence of UARB approved recovery, the liability would have been expensed when incurred. More details are provided in note 14. 
 The UARB agreed to allow NSPI to defer taxes not reflected in rates for the period January 1, 2005 until April 1, 2005, the date when new rates became effective. The UARB approved recovery of
this regulatory asset over eight years, commencing April 1, 2007. 
 The UARB agreed to allow NSPI to defer demand side
management program expenses for the period January 1, 2008 until December 31, 2009. The UARB approved recovery of this regulatory asset over six years commencing January 1, 2009. 

The UARB agreed to allow NSPI to defer vegetation management spending of $2.0 million in 2008 to be recovered in rates in a future period.
The period of recovery of this asset will be determined during the next general rate case. 
 In the absence of UARB approved
deferrals for taxes, demand side management and vegetation management expenses would have been expensed as incurred. More details are provided in note 14. 
 In accordance with rate and accounting orders issued by the MPUC, Bangor Hydro and MPS have recorded regulatory assets and liabilities on their balance sheets. These regulatory assets and liabilities are
being amortized over varying lives expiring through to 2018 through charges to earnings. These regulatory assets and liabilities are included in “Other assets” and “Other liabilities” and include costs related to restructuring of
purchased power contracts, the Seabrook nuclear project, decommissioning costs for Maine Yankee, obligations to Hydro-Québec, and the stranded cost revenue requirement levelizer, and are described in more detail in note 14. 

 

	 	f.	Property, Plant and Equipment 

 Property, plant and equipment are recorded at original cost, net of contributions in aid of construction including energy tax credits. 

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each
category. The service lives of regulated assets are determined based on formal depreciation studies, which require UARB approval or FERC and MPUC approvals. The estimated weighted average service life for the Company’s unregulated general
assets is 7 years (2009 – 9 years). Unregulated generation assets have an estimated weighted average service life of 35 years (2009 – 33 years). 

  
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 When indicators of impairment exist, the Company determines whether the net carrying
amount of property, plant and equipment is recoverable from future undiscounted cash flows. Factors which could indicate impairment include significant changes in regulation, a change in the Company’s strategy or underperformance relative to
projected future operating results. 
 Accounting for the impact of rate regulation: 

During 2003, following completion of a depreciation study and a negotiated agreement with stakeholders, NSPI’s regulator approved new
depreciation rates which were to be phased in over four years beginning in 2004. In the decision on NSPI’s 2005 rate application, the UARB delayed the phase-in of year-two rates for one year. In the decision on NSPI’s 2006 rate
application, the UARB approved restarting of the phase-in including year-two in 2006 rates. In its February 2007 decision, the UARB postponed the scheduled year-three phase-in of increased depreciation rates until the next rate application. In its
November 2008 decision, the UARB approved the year-three phase-in effective January 1, 2009. 
 Absent consideration of
growth in plant-in-service, the phase-in of new depreciation rates will increase depreciation expense by a cumulative increase of $20 million over the phase-in period. In the absence of UARB approval of depreciation rates, NSPI would be required to
set rates based on management’s best estimates of useful lives. The average rates for the major categories of plant-in-service are summarized as follows: 
  

									
	 Function
	  	2010	 	 	2009	 
	 Generation
	  				 			
	 Thermal
	  	 	2.50	% 	 	 	2.50	% 
	 Gas turbines
	  	 	2.47	% 	 	 	2.47	% 
	 Combustion turbines
	  	 	3.33	% 	 	 	3.33	% 
	 Hydroelectric
	  	 	1.51	% 	 	 	1.51	% 
	 Wind turbines
	  	 	5.00	% 	 	 	5.00	% 
	 Transmission
	  	 	2.76	% 	 	 	2.76	% 
	 Distribution
	  	 	4.15	% 	 	 	4.15	% 
	 General plant
	  	 	7.07	% 	 	 	7.07	% 
	 General plant under capital lease
	  	 	13.18	% 	 	 	14.25	% 
	 Weighted average depreciation rate
	  	 	3.00	% 	 	 	3.13	% 

 Bangor Hydro’s
depreciation is determined by the straight-line method, based on the estimated service lives of the depreciable assets in each category. In 2004, Bangor Hydro implemented the results of a depreciation study that was approved by its regulators.

 The estimated average service lives in years for the major categories of plant-in-service are summarized as follows:

  

									
	 Function
	  	2010	 	  	2009	 
	 Transmission
	  	 	44	  	  	 	45	  
	 Distribution
	  	 	35	  	  	 	35	  
	 Other
	  	 	17	  	  	 	16	  
	 Weighted average service life
	  	 	38	  	  	 	36	  


  
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 MPS’s depreciation is determined by the straight-line method, based on the
estimated service lives of the depreciable assets in each category. In 2007, MPS implemented the results of a depreciation study approved by its regulators. The estimated average service lives in years for the major categories of plant-in-service
are summarized as follows: 
  

					
	 Function
	  	2010	 
	 Transmission
	  	 	46	  
	 Distribution
	  	 	31	  
	 Other
	  	 	28	  
	 Weighted average service life
	  	 	33	  

 In accordance
with regulator-approved accounting policies, when depreciable property, plant and equipment of NSPI, Bangor Hydro and MPS are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated
depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operation in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains
and losses on the disposition of property, plant and equipment would be charged to net earnings as incurred. 
  

	 	g.	Intangible Assets 


Intangible assets consist primarily of land rights and computer software. Amortization is determined by the straight-line method, based on
the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated assets are determined based on formal depreciation studies which require the appropriate regulator’s approval as discussed in
property, plant and equipment in note 1(f). The estimated weighted average service life for the Company’s intangible assets is 54 years (2009 – 57 years). 
 When indicators of impairment exist, the Company determines whether the net carrying amount of the intangible assets is recoverable from future undiscounted cash flows. Factors which could indicate
impairment exists include significant changes in regulation, a change in the Company’s strategy or underperformance relative to projected future operating results. 
 Accounting for the impact of rate regulation: 
 In the absence of UARB
approval of amortization rates, NSPI would be required to set rates based on management’s best estimates of useful lives. The average rates for the major categories are summarized as follows: 

 

									
	 Function
	  	2010	 	 	2009	 
	 Transmission
	  	 	1.21	% 	 	 	1.21	% 
	 Distribution
	  	 	1.57	% 	 	 	1.57	% 
	 Other
	  	 	12.16	% 	 	 	12.03	% 
	 Weighted average amortization rate
	  	 	4.67	% 	 	 	3.66	% 

 In the absence of the
MPUC’s approval of amortization rates, Bangor Hydro would be required to set rates based on management’s best estimates of useful lives. The average rates for the major categories are summarized as follows: 

 

									
	 Function
	  	2010	 	 	2009	 
	 Distribution
	  	 	1.43	% 	 	 	1.41	% 
	 Other
	  	 	14.10	% 	 	 	12.36	% 
	 Weighted average amortization rate
	  	 	9.30	% 	 	 	8.81	% 


  
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 In the absence of the MPUC’s approval of amortization rates, MPS would also be
required to set rates based on management’s best estimates of useful lives. The average rates for the major categories are summarized as follows: 
  

					
	 Function
	  	2010	 
	 Transmission
	  	 	1.20	% 
	 Distribution
	  	 	0.70	% 
	 Other
	  	 	21.76	% 
	 Weighted average amortization rate
	  	 	14.72	% 

  

	 	h.	Capitalization Policy 


Capital assets of the Company include labour, materials, and other non-labour costs directly attributable to the capital activity. In
addition, overhead costs that contribute to the capital program are allocated to capital projects. These costs include corporate costs such as finance, information technology, management and other support functions, employee benefits, insurance,
inventory costs, and fleet operating and maintenance costs. The Company calculates an application rate and only eligible operating expenditures are used in the calculation. The Company applies overhead costs based on direct labour costs. The
application rate varies depending on the type of capital expenditure. In addition, Bangor Hydro and MPS apply inventory overhead based on inventory issued to the project, and Bangor Hydro applies general and administrative overhead based upon
non-labour charges. 
  

	 	i.	Leases 

 Leases that
substantially transfer all the benefits and risks of ownership of property, plant and equipment to the Company, or otherwise meet the criteria for capitalizing a lease under CGAAP, are accounted for as capital leases. An asset is recognized at the
time a capital lease is entered into together with its related long-term obligation. Property, plant and equipment recognized under capital leases are depreciated on the same basis as described in note 1(f). Payments on operating leases are expensed
as incurred. 
  

	 	j.	Income Taxes and Investment Tax Credits 

 Emera follows the future income tax method of accounting for income taxes. The difference between the tax basis of assets and liabilities and their carrying value on the balance sheet is used to calculate
future tax assets and liabilities. The future tax assets and liabilities have been measured using substantively enacted tax rates that will be in effect when the differences are expected to reverse. 

Investment tax credits arise as a result of incurring qualifying scientific research and development expenditures and are recorded in the
year as a reduction from the related expenditures where there is reasonable assurance of collection. 
 Accounting for the
impact of rate regulation: 
 In accordance with rate-regulated accounting, NSPI and Brunswick Pipeline defer any future
income taxes from the statements of earnings and AOCI to a regulatory asset or liability where the future income taxes are expected to be included in future rates and tolls respectively. Bangor Hydro and MPS use the future income tax method where
allowed for ratemaking purposes. NSPI, Bangor Hydro, MPS and Brunswick Pipeline would be required to recognize all future income tax expense and recovery in the absence of their regulator-approved accounting policies. More details are provided in
note 9. 

  
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	 	k.	Employee Future Benefits 


Pension obligations, and obligations associated with non-pension post-retirement benefits such as health benefits to retirees and
retirement awards, are actuarially determined using the projected benefit method prorated on services and management’s best estimate assumptions. The accrued benefit obligation is valued based on market interest rates at the valuation date.

 Pension fund asset values are calculated using market values at year-end. The expected return on pension assets is determined
based on market-related values. The market-related values are determined in a rational and systematic manner so as to recognize investment gains and losses, relative to the assumed rate of return, over a five-year period. 

Adjustments to the accrued benefit obligation arising from plan amendments are amortized on a straight-line basis over the expected years
of future service to the full eligibility date for active employees. 
 For any given year, when the net actuarial gain (loss),
less the actuarial gain (loss) not yet included in the market-related value of plan assets, exceeds 10% of the greater of the accrued benefit obligation and the market-related value of the plan assets, an amount equal to the excess divided by the
average remaining service period (“ARSP”) is amortized on a straight-line basis. For NSPI, the ARSP of the active employees is 9 years as at December 31, 2010 and 2009. For Bangor Hydro, this excess is amortized on a straight-line
basis over the expected ARSP, in accordance with ratemaking purposes, which is 11 years as at December 31, 2010 and 2009. At December 31, 2010, MPS has no actuarial gains or losses not yet included in the market-related value of the plan
assets. For Emera Inc., the ARSP of the active employees is 10 years as at December 31, 2010 (2009 – 11 years). 
 On
January 1, 2000, Emera adopted the accounting standard on employee future benefits using the prospective application method. The transitional obligation (asset) resulting from the initial application is amortized on a linear basis over 13
years, which was the expected ARSP of active employees at the transition date. 
 The difference between benefit cost and pension
funding is recorded as “Other assets” or “Other liabilities” on the balance sheet. 
  

	 	l.	Share-Based Compensation 


The Company has several share-based compensation plans: a common share option plan for senior management, an employee common share
purchase plan, a deferred share unit plan, and a performance share unit plan (formerly called restricted share unit plan). The Company accounts for its plans in accordance with the fair value based method of accounting for share-based compensation.

  

	 	m.	Cash and Cash Equivalents 


Short-term investments, which consist of money market instruments with maturities of three months or less, are considered to be cash
equivalents and are recorded at cost, which approximates current market value. There were no short-term investments outstanding at December 31, 2010. The 2009 effective interest rate was 0.55%. 

 

	 	n.	Inventory 

 Inventories
are measured at the lower of cost and net realizable value. The Company uses the weighted average method to determine the cost of inventory. 

  
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	 	o.	Debt Financing Costs 


Financing costs pertaining to debt issues are amortized over the life of the related debt using the effective interest method. 

 

	 	p.	Derivative Financial & Commodity Instruments 

 The Company classifies financial assets and financial liabilities as held-for-trading, available-for-sale, loans and receivables, other financial liabilities or derivatives in valid hedging relationships.
All financial instruments are initially recorded at fair value on the consolidated statement of financial position. Subsequent measurements of the financial instruments are based on their classification. 

Held-for-trading (“HFT”) derivative financial assets and liabilities consist mainly of foreign exchange forward contracts,
interest caps and collars, coal, oil and gas options; swaps; and natural gas contracts. The Company has not designated any non-derivative financial assets or liabilities as held-for-trading. HFT financial instruments are initially recorded at their
fair value. The Company has classified its derivatives not in valid hedging relationships as held-for-trading and recognizes changes in fair value of its HFT derivatives in earnings of the reporting period. 

The available-for-sale investments are recognized at fair value, with changes in those fair values recorded in “Other comprehensive
income” unless actively quoted prices are not available for fair value measurement, in which case available-for-sale investments are measured at cost. 
 Loans and receivables include cash and cash equivalents and accounts receivable and are measured at amortized cost using the effective interest method. Gains and losses are included in earnings and
recorded in “Operating, maintenance and general expenses”. 
 Other financial liabilities, which include accounts
payable and accrued charges, preferred shares issued by a subsidiary, short-term debt and long-term debt, are recognized at amortized cost. Preferred share dividends paid by a subsidiary are recognized using the effective interest method. Interest
expense and debt financing expenses related to the Company’s long-term debt and short-term debt are recognized using the effective interest method. 
 Derivatives in valid hedging relationships are categorized as cash flow hedges and fair value hedges. The Company uses cash flow hedges to manage changes in commodity prices, foreign exchange rates, and
interest rates. The Company uses fair value hedges to hedge the fair value of commodity positions. 
 The Company uses various
financial instruments to hedge its exposure to foreign exchange, interest rate, and commodity price risks. In addition, the Company has contracts for the physical purchase and sale of natural gas, and physical and financial contracts that are
held-for-trading. Collectively, these contracts are referred to as derivatives. 
 The Company recognizes the fair value of all
its hedges on its balance sheet. 
 Hedging relationships that meet stringent documentation requirements, and can be proven to be
effective both at the inception and over the term of the relationship qualify for hedge accounting. Specifically, in a cash flow hedge, the effective portion of the change in the fair value of hedging derivatives is recorded in AOCI and reclassified
to earnings, inventory or construction work in progress in the same period the related hedged item is realized. Any ineffective portion of the change in fair value of hedging derivatives is recognized in net earnings in the reporting period.

 For fair value hedges, the change in fair value of the hedging derivatives and the hedged item are recorded in net earnings.
Any ineffective portion of the change in fair value is recognized in net earnings in the reporting period. 

  
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 Where documentation and effectiveness requirements are not met, the change in fair value
of the derivative is recognized in earnings in the reporting period. 
 If a cash flow hedge is terminated, the effective portion
of the change in fair value of the hedging derivative up until the date of termination remains in AOCI and is recognized in earnings, inventory or construction work in progress in the same period the related hedged risk is realized. The change in
fair value of the derivative, if retained, would then be recognized in earnings from the termination date onward. 
 Amounts
received or paid related to derivatives used to hedge foreign exchange and commodity price risks on fuel purchases are recognized in “Fuel for generation and purchased power” or “Inventory”. Amounts received or paid related to
derivatives used to hedge foreign exchange on capital purchases are recognized in “Construction work in progress”. Amounts received or paid related to derivatives used to hedge interest rate risks are recognized over the term of the hedged
item in “Financing charges”. 
 Cash flows related to HFT derivatives and derivatives in valid hedging relationships
are reflected in “Operating activities” on the statement of cash flows. 
 Accounting for the impact of rate
regulation: 
 In accordance with Handbook Standard 3865 Hedges, NSPI determined that it cannot meet the probability
requirement of the standard for its derivatives in place to hedge natural gas and heavy fuel oil for its Tufts Cove generating station (“TUC”). This is due to the generating station’s ability to fuel switch and NSPI’s economic
dispatch based on the cost of these two fuels. The UARB has allowed NSPI to apply hedge accounting to these derivatives as long as the other requirements of the Handbook are met. In 2009, the UARB approved an amendment to NSPI’s accounting
practice to include all TUC derivatives which are no longer required. Absent UARB approval, NSPI would be required to recognize the changes in fair value of these derivatives in net earnings of the period. 

NSPI has contracts for the purchase and sale of natural gas at TUC that are considered HFT derivatives and accordingly are recognized on
the balance sheet at fair value. This reflects NSPI’s history of buying and reselling any natural gas not used in the production of electricity at TUC. Changes in fair value of HFT derivatives are normally recognized in net earnings. In
accordance with NSPI’s accounting policy for financial instruments and hedges relating to TUC fuel, NSPI has deferred any changes in fair value to a regulatory asset or liability. 

MPS has two cash flow hedges used to fix the interest rates on two variable-rate debt issues. The MPUC has allowed MPS recovery of the
fixed interest costs in MPS’ rates. The fair value of the interest rate hedges is recognized in “Derivatives in a valid hedging relationship”. 
 Further details on the regulatory assets and liabilities recognized as a result of the above can be found in note 14. 
  

	 	q.	Goodwill 

 Goodwill
represents the excess of the purchase price of an acquired business over the net amount of the fair values assigned to its assets and liabilities and is not subject to amortization. The Company evaluates the carrying value of goodwill for potential
impairment through an annual review and analysis of fair market value. Goodwill is also evaluated for potential impairment between annual tests if events or circumstances occur that more likely than not reduces the fair value of a business below its
carrying value. Fair market value is determined by use of net present value financial models, which incorporate management’s assumptions of future profitability. 

  
 18 











 

 

  


	 	r.	Long-Term Investments 


The Company accounts for certain investments, over which it has joint control, using the proportionate consolidation method, whereby the
Company recognizes its pro-rata share of the jointly controlled assets and the liabilities jointly incurred in the Company’s balance sheet; recognizes its pro-rata share of any revenue and expenses in the Company’s statement of earnings;
and recognizes its pro-rata share of cash flows on the Company’s statement of cash flows. Emera accounts for its investment in Bear Swamp using proportionate consolidation. 

The Company accounts for certain investments, over which it maintains significant influence, but not control, using the equity method,
whereby the amount of the investment is adjusted annually for the Company’s pro-rata share of the net earnings of the investment and reduced by the amount of any dividends received. Emera accounts for its investments in Maritimes &
Northeast Pipeline, Light and Power Holdings, St. Lucia Electricity Services Ltd., Atlantic Hydrogen Inc., Maine Electric Power Company Inc. and Maine Yankee Atomic Power Company using the equity method. 

 

	 	s.	Foreign Currency Translation 

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

	 	t.	Research and Development Costs 

 All research and development costs are expensed in the year incurred unless they qualify for deferral as a part of property, plant and equipment or intangible assets. 

 

	2.	CHANGE IN ACCOUNTING ESTIMATE 

 In 2010, NSPI revised its estimate of the expected benefit from accelerated tax deductions. The impact for the three months and twelve months ended December 31, 2010 was to reduce income tax expense
by approximately $8.0 million and $14.0 million respectively. In accordance with rate-regulated accounting, the future income tax implications of this change in estimate have been deferred to a regulatory asset in “Other assets”. This
change in accounting estimate has been accounted for on a prospective basis. 

  
 19 











 

 

  


	3.	SEGMENT INFORMATION 

 The
Company has three reportable segments which are determined based on Emera’s operating activities: NSPI, engaged in the production and sale of electric energy in Nova Scotia; Bangor Hydro, engaged in the transmission and distribution of electric
energy in central Maine; Brunswick Pipeline, engaged in the transportation of natural gas through its pipeline for Repsol; and Other, including MPS, GBPC, revenue generated from energy marketing margin and electric revenue from the Company’s
investment in Bear Swamp. The Company evaluates performance based on contribution to consolidated net earnings applicable to common shareholders. The accounting policies of the reported segments are the same as those described in the summary of
significant accounting policies. 
  

																					
	 millions of dollars
	  	NSPI	 	 	Bangor
Hydro	 	 	Brunswick
Pipeline	 	 	Other*	 	 	Total	 
	 Year ended December 31, 2010
	  				 				 				 				 			
	 Revenues from external customers
	  	$	1,182.6	  	 	$	155.7	  	 	$	56.5	  	 	$	158.9	  	 	$	1,553.7	  
	 Depreciation and amortization
	  	 	150.8	  	 	 	17.2	  	 	 	0.1	  	 	 	5.5	  	 	 	173.6	  
	 Cost of operations, including depreciation
	  	 	953.0	  	 	 	97.8	  	 	 	0.1	  	 	 	168.9	  	 	 	1,219.8	  
	 Equity earnings
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	13.6	  	 	 	13.6	  
	 Interest expense
	  	 	110.6	  	 	 	11.5	  	 	 	—  	  	 	 	29.1	  	 	 	151.2	  
	 Income taxes
	  	 	(17.4	) 	 	 	18.8	  	 	 	—  	  	 	 	(14.2	) 	 	 	(12.8	) 
	 Net earnings applicable to common shareholders
	  	 	121.3	  	 	 	31.9	  	 	 	25.8	  	 	 	12.1	  	 	 	191.1	  
	 Net inter-segment (expenses) revenues
	  	 	(47.6	) 	 	 	(1.6	) 	 	 	(31.5	) 	 	 	80.7	  	 	 	—  	  
	 Capital expenditures
	  	 	510.5	  	 	 	40.6	  	 	 	12.7	  	 	 	4.6	  	 	 	568.4	  
	 As at December 31, 2010
	  				 				 				 				 			
	 Total assets
	  	 	3,991.3	  	 	 	730.4	  	 	 	502.7	  	 	 	1,104.7	  	 	 	6,329.1	  
	 Investments subject to significant influence
	  	 	—  	  	 	 	0.7	  	 	 	—  	  	 	 	238.2	  	 	 	238.9	  
	 Goodwill
	  	 	—  	  	 	 	82.9	  	 	 	—  	  	 	 	96.0	  	 	 	178.9	  
						
	 millions of dollars
	  	NSPI	 	 	Bangor
Hydro	 	 	Brunswick
Pipeline	 	 	Other*	 	 	Total	 
	 Year ended December 31, 2009
	  				 				 				 				 			
	 Revenues from external customers
	  	$	1,201.9	  	 	$	157.7	  	 	$	25.3	  	 	$	98.6	  	 	$	1,483.5	  
	 Depreciation and amortization
	  	 	143.9	  	 	 	18.3	  	 	 	0.1	  	 	 	2.6	  	 	 	164.9	  
	 Cost of operations, including depreciation
	  	 	935.9	  	 	 	103.0	  	 	 	0.1	  	 	 	97.9	  	 	 	1,136.9	  
	 Equity earnings
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	14.0	  	 	 	14.0	  
	 Interest expense
	  	 	99.2	  	 	 	13.0	  	 	 	—  	  	 	 	21.8	  	 	 	134.0	  
	 Income taxes
	  	 	42.2	  	 	 	15.3	  	 	 	—  	  	 	 	(8.6	) 	 	 	48.9	  
	 Net earnings applicable to common shareholders
	  	 	109.3	  	 	 	27.5	  	 	 	14.0	  	 	 	24.9	  	 	 	175.7	  
	 Net inter-segment revenues (expenses)
	  	 	16.2	  	 	 	(0.9	) 	 	 	(30.5	) 	 	 	15.2	  	 	 	—  	  
	 Capital expenditures
	  	 	263.7	  	 	 	55.9	  	 	 	50.8	  	 	 	22.1	  	 	 	392.5	  
	 As at December 31, 2009
	  				 				 				 				 			
	 Total assets
	  	 	3,465.3	  	 	 	738.0	  	 	 	447.7	  	 	 	633.5	  	 	 	5,284.5	  
	 Investments subject to significant influence
	  	 	—  	  	 	 	2.2	  	 	 	—  	  	 	 	216.2	  	 	 	218.4	  
	 Goodwill
	  	 	—  	  	 	 	87.2	  	 	 	—  	  	 	 	0.4	  	 	 	87.6	  

  

	*	Other includes corporate activities and adjustments to reconcile to consolidated balances. 


  
 20 











 

 

  


	4.	EMPLOYEE FUTURE BENEFITS 


NOVA SCOTIA POWER PLANS 
 NSPI maintains contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees, and plans providing non-pension benefits for its retirees. Certain of
Emera’s corporate employees participate in these plans and Emera Inc. is charged accordingly. 
 Defined benefit pension
plans are based on the years of service and average salary at the time the employee terminates employment and provide annual post-retirement indexing equal to the change in the Consumer Price Index up to a maximum increase of 6% per year.

 Other retirement benefit plans include: unfunded pension arrangements (with the same indexing formula as the funded pension
arrangements), unfunded long service award (which is impacted by expected future salary levels) and contributory health care plan. The unfunded long service award was closed to new entrants effective August 1, 2007. 

The measurement date for the assets and obligations of each benefit plan is December 31, 2010. 

Valuation date for defined-benefit plans 
 NSPI has a December 31 valuation date for accounting purposes. The most recent and the next required actuarial valuation dates for funding purposes are as follows: 

 

									
	 	  	Most recent
actuarial valuation	 	  	Next required
actuarial valuation	 
	 Employee pension plan
	  	 	December 31, 2010	  	  	 	December 31, 2011	  
	 Acquired companies pension plan
	  	 	December 31, 2010	  	  	 	December 31, 2011	  

 Total cash amount

 Total cash amount for 2010, made up of contributions to its funded defined-benefit pension plans, contributions to its
defined-contribution pension plan, employer paid premiums for its post-retirement health care plan, and amounts paid directly to retirees and beneficiaries in other plans, was $40.4 million (2009 – $32.5 million) for NSPI and Emera. 


  
 21 











 

 

  

 Accrued pension and non-pension benefit asset (liability) 

 

																	
	 	  	2010	 	 	2009	 
	 millions of dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefits 
plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefits plans	 
	 Assumptions (weighted average)
	  				 				 				 			
	 Accrued benefit obligation – December 31:
	  				 				 				 			
	 Discount rate
	  	 	5.50	% 	 	 	5.50	% 	 	 	6.50	% 	 	 	6.50	% 
	 Rate of compensation increase
	  	 	3% to 5.5	% 	 	 	3% to 5.5	% 	 	 	3% to 5.5	% 	 	 	3% to 5.5	% 
	 Health care trend - initial (next year)
	  	 	—  	  	 	 	4.00	% 	 	 	—  	  	 	 	5.00	% 
	                      -
ultimate
	  	 	—  	  	 	 	4.00	% 	 	 	—  	  	 	 	4.00	% 
	                      -
year ultimate reached
	  	 	—  	  	 	 	2011	  	 	 	—  	  	 	 	2011	  
	 Benefit cost for year ending December 31:
	  				 				 				 			
	 Discount rate
	  	 	6.50	% 	 	 	6.50	% 	 	 	7.50	% 	 	 	7.50	% 
	 Expected long-term return on plan assets
	  	 	7.25	% 	 	 	7.25	% 	 	 	7.25	% 	 	 	—  	  
	 Rate of compensation increase
	  	 	3% to 5.5%	  	 	 	3% to 5.5%	  	 	 	3% to 5.5%	  	 	 	3% to 5.5%	  
	 Health care trend - initial (current year)
	  	 	—  	  	 	 	5.00	% 	 	 	—  	  	 	 	6.00	% 
	                      -
ultimate
	  	 	—  	  	 	 	4.00	% 	 	 	—  	  	 	 	4.00	% 
	                      -
year ultimate reached
	  	 	—  	  	 	 	2011	  	 	 	—  	  	 	 	2011	  
	 Accrued benefit obligations
	  				 				 				 			
	 Balance, January 1
	  	$	787.8	  	 	$	36.3	  	 	$	669.5	  	 	$	36.1	  
	 Employer current service cost
	  	 	9.5	  	 	 	1.5	  	 	 	6.8	  	 	 	1.4	  
	 Employee contributions
	  	 	5.7	  	 	 	—  	  	 	 	5.4	  	 	 	—  	  
	 Interest cost
	  	 	50.2	  	 	 	2.3	  	 	 	49.1	  	 	 	2.6	  
	 Past service adjustment
	  	 	(1.0	) 	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Actuarial losses
	  	 	122.4	  	 	 	4.1	  	 	 	95.1	  	 	 	0.4	  
	 Benefits paid
	  	 	(39.5	) 	 	 	(4.3	) 	 	 	(38.1	) 	 	 	(4.2	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	935.1	  	 	 	39.9	  	 	 	787.8	  	 	 	36.3	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Fair value of plan assets
	  				 				 				 			
	 Balance, January 1
	  	 	593.1	  	 	 	—  	  	 	 	509.2	  	 	 	—  	  
	 Employer contributions
	  	 	34.7	  	 	 	4.3	  	 	 	27.2	  	 	$	4.2	  
	 Employee contributions
	  	 	5.7	  	 	 	—  	  	 	 	5.4	  	 	 	—  	  
	 Actual return on plan assets
	  	 	55.6	  	 	 	—  	  	 	 	89.4	  	 	 	—  	  
	 Benefits paid
	  	 	(39.5	) 	 	 	(4.3	) 	 	 	(38.1	) 	 	 	(4.2	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	649.6	  	 	 	—  	  	 	 	593.1	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Reconciliation of financial status to accrued benefit asset, December 31
	  				 				 				 			
	 Fair value of plan assets
	  	 	649.6	  	 	 	—  	  	 	 	593.1	  	 	 	—  	  
	 Accrued benefit obligations
	  	 	935.1	  	 	 	39.9	  	 	 	787.8	  	 	 	36.3	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Plan deficit
	  	 	(285.5	) 	 	 	(39.9	) 	 	 	(194.7	) 	 	 	(36.3	) 
	 Unamortized past service (gains) costs
	  	 	(0.3	) 	 	 	1.4	  	 	 	(0.4	) 	 	 	1.6	  
	 Unamortized actuarial losses (gains)
	  	 	364.5	  	 	 	2.1	  	 	 	257.8	  	 	 	(2.2	) 
	 Unamortized transitional obligation
	  	 	(0.9	) 	 	 	4.5	  	 	 	0.1	  	 	 	6.7	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Accrued benefit asset (liability)
	  	$	77.8	  	 	$	(31.9	) 	 	$	62.8	  	 	$	(30.2	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	
	 The amounts recognized in “Other assets” and “Other liabilities” are as follows:
	   

			
	 	  	2010	 	 	2009	 
	 millions of dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefits 
plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefits plans	 
	 Accrued benefit asset
	  	$	110.7	  	 	 	—  	  	 	$	94.4	  	 	 	—  	  
	 Accrued benefit liability
	  	 	(32.9	) 	 	$	(31.9	) 	 	 	(31.6	) 	 	$	(30.2	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Net accrued benefit asset (liability)
	  	$	77.8	  	 	$	(31.9	) 	 	$	62.8	  	 	$	(30.2	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 


  
 22 











 

 

  


																	
	 Defined benefit plans asset allocation

(% of plan assets)
	  	2010	 	 	2009	 
	 	  	Employee
pension plan	 	 	Acquired
companies
pension plan	 	 	Employee
pension plan	 	 	Acquired
companies
pension plan	 
	 Equity securities
	  	 	65	% 	 	 	64	% 	 	 	64	% 	 	 	62	% 
	 Debt securities
	  	 	34	% 	 	 	36	% 	 	 	36	% 	 	 	37	% 
	 Cash
	  	 	1	% 	 	 	—  	  	 	 	—  	  	 	 	1	% 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total
	  	 	100	% 	 	 	100	% 	 	 	100	% 	 	 	100	% 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 As at December 31, 2010, the pension funds do not hold any material investments in Emera Inc. or Nova
Scotia Power Inc. securities. 
 Plans with accrued benefit obligations in excess of assets 

As at December 31, 2010, all post-retirement benefit plans have accrued benefit obligations in excess of assets. 

 

																	
	 Benefits cost components

millions of dollars
	  	2010	 	 	2009	 
	 Defined benefit plan
	  	Defined benefit
pension plans	 	 	Non-pension
benefits plan	 	 	Defined benefit
pension plans	 	 	Non-pension
benefits plan	 
	 Costs arising from events during the year:
	  				 				 				 			
	 Current service costs
	  	$	9.5	  	 	$	1.5	  	 	$	6.8	  	 	$	1.4	  
	 Interest on accrued benefits
	  	 	50.2	  	 	 	2.3	  	 	 	49.1	  	 	 	2.6	  
	 Less: actual return on plan assets
	  	 	(55.6	) 	 	 	—  	  	 	 	(89.4	) 	 	 	—  	  
	 Actuarial losses on accrued benefit obligation
	  	 	122.4	  	 	 	4.1	  	 	 	95.1	  	 	 	0.5	  
	 Past service gains
	  	 	(1.0	) 	 	 	—  	  	 	 	—  	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Future benefit costs before adjustments
	  	 	125.5	  	 	 	7.9	  	 	 	61.6	  	 	 	4.5	  
	 Adjustments to recognize long-term nature of costs:
	  				 				 				 			
	 Difference between expected return on assets and actual return
	  	 	6.0	  	 	 	—  	  	 	 	41.0	  	 	 	—  	  
	 Amortization of transitional obligation
	  	 	—  	  	 	 	2.2	  	 	 	—  	  	 	 	2.2	  
	 Difference between amortization of actuarial gains and actual actuarial gains on accrued benefit obligations
	  	 	(112.8	) 	 	 	(4.3	) 	 	 	(94.6	) 	 	 	(0.8	) 
	 Difference between amortization of past service costs and past service costs for the year
	  	 	1.0	  	 	 	0.2	  	 	 	—  	  	 	 	0.2	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total cost recognized
	  	$	19.7	  	 	$	6.0	  	 	$	8.0	  	 	$	6.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Defined contribution plan
	  				 				 				 			
	 Employer cost
	  	$	1.4	  	 	 	—  	  	 	$	1.1	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 The expected return on plan assets is determined based on the market-related value of plan assets of $685.6
million at January 1, 2010 (2009 – $671.1 million), adjusted for interest on certain cash flows during the year. 

Sensitivity analysis for non-pension benefits plans 
 The health care cost trend significantly influences the amounts presented for health care plans. An increase or decrease of one percentage point of the assumed health care cost trend would have had the
following impact in 2010: 
  

									
	 millions of dollars
	  	Increase	 	  	Decrease	 
	 Current service cost and interest cost
	  	 	—  	  	  	 	—  	  
	 Accrued benefit obligation, December 31
	  	$	1.5	  	  	$	(1.4	) 


  
 23 











 

 

  

 BANGOR HYDRO PLANS 

Bangor Hydro maintains a non-contributory defined-benefit and a contributory defined-contribution pension plan, which cover substantially
all of its employees, and a health care plan for its retirees. The defined benefit pension is based on the years of service and average salary at the time the employee terminates employment and provides no post-employment indexing. The defined
benefit pension plan was closed to new entrants effective February 2006. Employees hired after January 1, 2006 are not eligible for the retiree health care plan. 
 Other retirement benefit plans include an unfunded pension arrangement and a retiree life insurance plan. 
 The measurement date for the assets and obligations of each benefit plan is December 31, 2010. 
 Valuation date for defined-benefit plans 
 Bangor Hydro has a
December 31 valuation date for accounting purposes. The most recent and the next required actuarial valuation dates for funding purposes are the following: 
  

									
	 	  	Most recent
actuarial valuation	 	  	Next required
actuarial valuation	 
	 Employee pension plan
	  	 	December 31, 2009	  	  	 	December 31, 2010	  

 Total cash amount

 Total cash amount for 2010, made up of Bangor Hydro contributions to its funded defined-benefit pension plan,
contributions to its defined contribution pension plan, employer paid premiums for its post-retirement health care plan, and amounts paid directly to retirees and beneficiaries in other plans, was $5.0 million (2009 – $5.2 million). 


  
 24 











 

 

  

 Accrued pension and non-pension benefit liability 

 

																	
	 	  	2010	 	 	2009	 
	 millions of dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefits 
plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefits plans	 
	 Assumptions (weighted average)
	  				 				 				 			
	 Accrued benefit obligation – December 31:
	  				 				 				 			
	 Discount rate
	  	 	5.60	% 	 	 	5.60	% 	 	 	6.00	% 	 	 	6.00	% 
	 Rate of compensation increase
	  	 	3.75	% 	 	 	N/A	  	 	 	3.75	% 	 	 	N/A	  
	 Health care trend - initial (next year)
	  	 	—  	  	 	 	9.25	% 	 	 	—  	  	 	 	10.00	% 
	                      -
ultimate
	  	 	—  	  	 	 	5.00	% 	 	 	—  	  	 	 	5.00	% 
	                      -
year ultimate reached
	  	 	—  	  	 	 	2017	  	 	 	—  	  	 	 	2017	  
	 Benefit cost for year ending December 31:
	  				 				 				 			
	 Discount rate
	  	 	6.00	% 	 	 	6.00	% 	 	 	6.75	% 	 	 	6.75	% 
	 Expected long-term return on plan assets
	  	 	8.00	% 	 	 	5.00	% 	 	 	8.00	% 	 	 	5.00	% 
	 Rate of compensation increase
	  	 	3.75	% 	 	 	N/A	  	 	 	3.75	% 	 	 	N/A	  
	 Health care trend - initial (current year)
	  	 	—  	  	 	 	10.00	% 	 	 	—  	  	 	 	7.60	% 
	                      -
ultimate
	  	 	—  	  	 	 	5.00	% 	 	 	—  	  	 	 	5.00	% 
	
                     - year
ultimate reached
	  	 	—  	  	 	 	2017	  	 	 	—  	  	 	 	2015	  
	 Accrued benefit obligations
	  				 				 				 			
	 Balance, January 1
	  	$	81.8	  	 	$	41.8	  	 	$	84.6	  	 	 	53.6	  
	 Employer current service cost
	  	 	1.4	  	 	 	0.7	  	 	 	1.3	  	 	 	0.6	  
	 Interest cost
	  	 	4.7	  	 	 	2.3	  	 	 	5.1	  	 	 	2.3	  
	 Past service amendments
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(14.5	) 
	 Actuarial losses (gains)
	  	 	4.7	  	 	 	(0.2	) 	 	 	8.3	  	 	 	8.4	  
	 Benefits paid
	  	 	(3.7	) 	 	 	(1.4	) 	 	 	(4.2	) 	 	 	(1.1	) 
	 Foreign currency translation adjustment
	  	 	(4.2	) 	 	 	(2.1	) 	 	 	(13.3	) 	 	 	(7.5	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	84.7	  	 	 	41.1	  	 	 	81.8	  	 	 	41.8	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Fair value of plan assets
	  				 				 				 			
	 Balance, January 1
	  	 	49.8	  	 	 	1.0	  	 	 	47.9	  	 	 	1.2	  
	 Employer contributions
	  	 	3.6	  	 	 	1.4	  	 	 	3.5	  	 	 	1.3	  
	 Actual return on plan assets
	  	 	5.8	  	 	 	—  	  	 	 	10.5	  	 	 	(0.1	) 
	 Benefits paid
	  	 	(3.7	) 	 	 	(1.4	) 	 	 	(4.2	) 	 	 	(1.1	) 
	 Foreign currency translation adjustment
	  	 	(2.7	) 	 	 	(0.1	) 	 	 	(7.9	) 	 	 	(0.3	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	52.8	  	 	 	0.9	  	 	 	49.8	  	 	 	1.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Reconciliation of financial status to accrued benefit asset, December 31
	  				 				 				 			
	 Fair value of plan assets
	  	 	52.8	  	 	 	0.9	  	 	 	49.8	  	 	 	1.0	  
	 Accrued benefit obligations
	  	 	84.7	  	 	 	41.1	  	 	 	81.8	  	 	 	41.8	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Plan deficit
	  	 	(31.9	) 	 	 	(40.2	) 	 	 	(32.0	) 	 	 	(40.8	) 
	 Unamortized past service costs (gains)
	  	 	0.5	  	 	 	(11.2	) 	 	 	0.7	  	 	 	(14.8	) 
	 Unamortized actuarial losses
	  	 	33.2	  	 	 	21.0	  	 	 	33.0	  	 	 	24.2	  
	 Unamortized transitional obligation
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	1.6	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Accrued benefit asset (liability)
	  	$	1.8	  	 	$	(30.4	) 	 	$	1.7	  	 	$	(29.8	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

  

									
	 Defined benefit plans asset allocation

(% of plan assets)
	  	2010	 	 	2009	 
	 	  	Employee
pension 
plan	 	 	Employee
pension plan	 
	 Equity securities
	  	 	65	% 	 	 	65	% 
	 Debt securities
	  	 	34	% 	 	 	34	% 
	 Other
	  	 	1	% 	 	 	1	% 
		  	 	 	 	 	 	 	 
	 Total
	  	 	100	% 	 	 	100	% 
		  	 	 	 	 	 	 	 

 As at December 31, 2010, the pension fund does not directly hold any investments in Emera or Bangor
Hydro securities. However, as a significant portion of assets for the benefit plans are held in mutual funds, there may be indirect investments in these securities. 

  
 25 











 

 

  

 Plans with accrued benefit obligation in excess of assets 

As at December 31, 2010, all post-retirement benefit plans have accrued pension obligations in excess of assets. 

 

																	
	 Benefits cost components

millions of dollars
	  	2010	 	 	2009	 
	 Defined benefit plan
	  	Defined benefit
pension plans	 	 	Non-pension
benefit plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefits plans	 
	 Costs arising from events during the year:
	  				 				 				 			
	 Current service costs
	  	$	1.4	  	 	$	0.7	  	 	$	1.3	  	 	$	0.6	  
	 Interest on accrued benefits
	  	 	4.7	  	 	 	2.3	  	 	 	5.1	  	 	 	2.3	  
	 Less: actual (loss) on plan assets
	  	 	(5.8	) 	 	 	—  	  	 	 	(10.5	) 	 	 	—  	  
	 Actuarial losses (gains) on accrued benefit obligation
	  	 	4.7	  	 	 	(0.2	) 	 	 	8.3	  	 	 	8.4	  
	 Past service amendment
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(14.5	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Future benefit costs before adjustments
	  	 	5.0	  	 	 	2.8	  	 	 	4.2	  	 	 	(3.2	) 
	 Adjustments to recognize long-term nature of costs:
	  				 				 				 			
	 Difference between expected return on assets and actual return
	  	 	1.1	  	 	 	(0.1	) 	 	 	5.5	  	 	 	(0.2	) 
	 Amortization of transitional obligation
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	0.6	  
	 Difference between amortization of actuarial (gains) losses and actual actuarial (gains) losses on accrued benefit
obligations
	  	 	(3.1	) 	 	 	2.1	  	 	 	(7.5	) 	 	 	(7.1	) 
	 Difference between amortization of past service costs and past service costs for the year
	  	 	0.2	  	 	 	(1.3	) 	 	 	0.2	  	 	 	12.7	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total cost recognized
	  	$	3.2	  	 	$	3.5	  	 	$	2.4	  	 	$	2.8	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Defined contribution plan
	  				 				 				 			
	 Employer cost
	  	$	0.4	  	 	 	—  	  	 	$	0.3	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 For the defined benefit pension plan, the expected return on plan assets is determined on the market-related
value of plan assets of $53.4 million at January 1, 2010 (2009 – $58.6 million), adjusted for interest on certain cash flows during the year. 
 Sensitivity analysis for non-pension plans 
 The health care cost trend
significantly influences the amounts presented for health care plans. An increase or decrease of one percentage point of the assumed health care cost trend would have had the following impact in 2010: 

 

									
	 	  	Increase	 	  	Decrease	 
	 Current service cost and interest cost
	  	$	0.5	  	  	$	(0.4	) 
	 Accrued benefit obligation, December 31
	  	$	7.0	  	  	$	(5.6	) 

 Accounting for the
impact of rate regulation: 
 When Bangor Hydro was purchased by Emera, Bangor Hydro received regulatory approval to continue
amortizing certain existing balances over a period of 10 years. Under CGAAP, as a result of the purchase, these unamortized balances would have been recognized immediately in the year Bangor Hydro was purchased. In the absence of the regulatory
policy, Bangor Hydro’s total accrued benefit liability would be $34.9 million (2009 – $38.5 million) and the total defined benefits expense for 2010 would be $5.0 million (2009 – $3.3 million). 

  
 26 











 

 

  

 MAINE & MARITIMES PLANS 

MAM’s subsidiary, MPS, maintains a non-contributory defined-benefit pension plan, and a contributory defined-contribution plan, which
cover substantially all of its employees, and a health care plan for its retirees. The defined benefit pension is based on the years of service and average salary at the time the employee terminates employment and post-employment indexing from time
to time, subject to approval by the MPS Board of Directors. Employees hired after January 1, 2006, are not eligible for participation in the defined benefit pension plan. Effective December 31, 2006, future salary and service accruals
ceased. Employees hired after October 1, 2005, are not eligible for the retiree health care plan. 
 Other retirement
benefit plans include an unfunded supplemental executive plan and an unfunded defined benefit agreement. The estimated liabilities for these plans are approximately $0.2 million. 

The measurement date for the assets and obligations of each benefit plan is December 31, 2010. 

Valuation date for defined-benefit plans 
 MPS has a December 31 valuation date for accounting purposes. The most recent and the next required actuarial valuation dates for funding purposes are the following: 

 

									
	 	  	Most recent
actuarial valuation	 	  	Next required
actuarial valuation	 
	 Employee pension plan
	  	 	December 31, 2009	  	  	 	December 31, 2010	  

 Total cash amount

 Total cash amount for 2010, made up of MPS contributions to its funded defined-benefit pension plan, contributions to its
defined contribution pension plan, employer paid premiums for its post-retirement health care plan, and amounts paid directly to retirees and beneficiaries in other plans, was $2.1 million. 

  
 27 











 

 

  

 Accrued pension and non-pension benefit liability 

 

									
	 	  	2010	 
	 millions of dollars
	  	Defined benefit
pension plan	 	 	Non-pension
benefits
plan	 
	 Assumptions (weighted average)
	  				 			
	 Accrued benefit obligation – December 31:
	  				 			
	 Discount rate
	  	 	5.40	% 	 	 	5.40	% 
	 Rate of compensation increase
	  	 	—  	  	 	 	N/A	  
	 Health care trend - initial (next year)
	  	 	—  	  	 	 	9.00	% 
	                     -
ultimate
	  	 	—  	  	 	 	4.50	% 
	                     - year
ultimate reached
	  	 	—  	  	 	 	2070	  
	 Benefit cost for year ending December 31:
	  				 			
	 Discount rate
	  	 	5.75	% 	 	 	5.85	% 
	 Expected long-term return on plan assets
	  	 	8.50	% 	 	 	8.50	% 
	 Rate of compensation increase
	  	 	—  	  	 	 	N/A	  
	 Health care trend - initial (current year)
	  	 	—  	  	 	 	10.00	% 
	                     -
ultimate
	  	 	—  	  	 	 	5.00	% 
	                     -
year ultimate reached
	  	 	—  	  	 	 	2070	  
	 Accrued benefit obligations
	  				 			
	 Balance, January 1
	  	$	20.0	  	 	$	3.1	  
	 Employer current service cost
	  	 	—  	  	 	 	0.1	  
	 Interest cost
	  	 	1.0	  	 	 	0.2	  
	 Past service amendments
	  	 	—  	  	 	 	—  	  
	 Actuarial losses
	  	 	1.0	  	 	 	2.3	  
	 Benefits paid
	  	 	(1.1	) 	 	 	(0.3	) 
	 Foreign currency translation adjustment
	  	 	(1.0	) 	 	 	(0.2	) 
		  	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	19.9	  	 	 	5.2	  
		  	 	 	 	 	 	 	 
	 Fair value of plan assets
	  				 			
	 Balance, January 1
	  	 	14.7	  	 	 	2.2	  
	 Employer contributions
	  	 	1.0	  	 	 	0.1	  
	 Actual return on plan assets
	  	 	2.2	  	 	 	0.3	  
	 Benefits paid
	  	 	(1.1	) 	 	 	(0.2	) 
	 Foreign currency translation adjustment
	  	 	(0.9	) 	 	 	(0.1	) 
		  	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	15.9	  	 	 	2.3	  
		  	 	 	 	 	 	 	 
	 Reconciliation of financial status to accrued benefit asset, December 31
	  				 			
	 Fair value of plan assets
	  	 	15.9	  	 	 	2.3	  
	 Accrued benefit obligations
	  	 	19.9	  	 	 	5.2	  
		  	 	 	 	 	 	 	 
	 Plan deficit
	  	 	(4.0	) 	 	 	(2.9	) 
	 Unamortized past service gains
	  	 	—  	  	 	 	(6.2	) 
	 Unamortized actuarial losses
	  	 	5.1	  	 	 	5.6	  
	 Unamortized transitional obligation
	  	 	—  	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Accrued benefit asset (liability)
	  	$	1.1	  	 	$	(3.5	) 
		  	 	 	 	 	 	 	 

  

					
	 Defined benefit plans asset allocation

(% of plan assets)
	  	2010	 
	 	  	Employee
pension 
plan	 
	 Equity securities
	  	 	68	% 
	 Debt securities
	  	 	24	% 
	 Other
	  	 	8	% 
		  	 	 	 
	 Total
	  	 	100	% 
		  	 	 	 

 For the defined benefit pension plan, the expected rate of return on plan assets is determined on the
market-related value of plan assets of $14.5 million at January 1, 2010, adjusted for interest on certain cash flows during the year. 
 As at December 31, 2010, the pension fund does not directly hold any investments in Emera, Bangor Hydro or MAM securities. However, as a significant portion of assets for the benefit plans are held
in mutual funds, there may be indirect investments in these securities. 

  
 28 











 

 

  

 Sensitivity analysis for non-pension plans 

The health care cost trend significantly influences the amounts presented for health care plans. An increase or decrease of one percentage
point of the assumed health care cost trend would have had the following impact in 2010: 
  

									
	 	  	Increase	 	  	Decrease	 
	 Current service cost and interest cost
	  	 	—  	  	  	 	—  	  
	 Accrued benefit obligation, December 31
	  	$	0.8	  	  	$	(0.6	) 

 Accounting for the
impact of rate regulation: 
 When MAM was purchased by Emera, MPS recorded a regulatory asset to continue amortizing certain
existing balances over a period of 13 years. Under CGAAP, as a result of the purchase, these unamortized balances would have been recognized immediately in the year MAM was purchased. In the absence of the regulatory policy, MAM’s total accrued
benefit liability would be $6.9 million. 
 GRAND BAHAMA POWER COMPANY LIMITED PLANS 

GBPC maintains a non-contributory defined-benefit pension plan for unionized employees and a separate non-contributory defined-benefit
pension plan for non-union employees. The defined benefit pension plans are based on the years of service and average salary at the time the employee retires. 
 The Company also has gratuity plans for its employees, payable upon retirement. Employees get 2 weeks pay for every year worked, capped at 52 weeks. 

The measurement date for the assets and obligations of each benefit plan is December 31, 2010. 

Valuation date for defined-benefit plans 
 GBPC has a December 31 valuation date for accounting purposes. The most recent and the next required actuarial valuation dates for funding purposes are the following: 

 

									
	 	  	Most recent
actuarial valuation	 	  	Next required
actuarial valuation	 
	 Employee pension plan
	  	 	December 31, 2009	  	  	 	December 31, 2010	  

 Total cash amount

 Total cash amount for 2010, made up of GBPC contributions to its funded defined-benefit pension plan, was $0.4 million.


  
 29 











 

 

  

 Accrued pension and non-pension benefit liability 

 

									
	 	  	2010	 
	 millions of dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefits 
plans	 
	 Assumptions (weighted average)
	  				 			
	 Accrued benefit obligation – December 31:
	  				 			
	 Discount rate
	  	 	6.00	% 	 	 	6.00	% 
	 Rate of compensation increase
	  				 			
	 - Union Plan
	  	 	4.00	% 	 	 	2.00	% 
	 - Non Union Plan
	  	 	5.00	% 	 	 	2.00	% 
	 Benefit cost for year ending December 31:
	  				 			
	 Discount rate
	  	 	6.00	% 	 	 	6.00	% 
	 Expected long-term return on plan assets
	  	 	6.00	% 	 	 	—  	  
	 Rate of compensation increase
	  	 	4.00	% 	 	 	—  	  
	 - Union Plan
	  	 	4.00	% 	 	 	2.00	% 
	 - Non Union Plan
	  	 	5.00	% 	 	 	2.00	% 
	 Accrued benefit obligations
	  				 			
	 Balance, January 1
	  	$	8.4	  	 	 	2.8	  
	 Employer current service cost
	  	 	0.3	  	 	 	—  	  
	 Interest cost
	  	 	0.5	  	 	 	—  	  
	 Actuarial losses
	  	 	(0.1	) 	 	 	—  	  
	 Benefits paid
	  	 	(0.2	) 	 	 	—  	  
	 Foreign currency translation adjustment
	  	 	(0.4	) 	 	 	(0.1	) 
		  	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	8.5	  	 	 	2.7	  
		  	 	 	 	 	 	 	 
	 Fair value of plan assets
	  				 			
	 Balance, January 1
	  	 	5.5	  	 	 	—  	  
	 Employer contributions
	  	 	0.4	  	 	 	—  	  
	 Actual return on plan assets
	  	 	0.1	  	 	 	—  	  
	 Benefits paid
	  	 	(0.2	) 	 	 	—  	  
	 Foreign currency translation adjustment
	  	 	(0.2	) 	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	5.6	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Reconciliation of financial status to accrued benefit asset, December 31
	  				 			
	 Fair value of plan assets
	  	 	5.6	  	 	 	—  	  
	 Accrued benefit obligations
	  	 	8.5	  	 	 	2.7	  
		  	 	 	 	 	 	 	 
	 Plan deficit
	  	 	(2.9	) 	 	 	(2.7	) 
	 Unamortized actuarial losses
	  	 	1.5	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Accrued benefit liability
	  	$	(1.4	) 	 	$	(2.7	) 
		  	 	 	 	 	 	 	 

  

					
	 Defined benefit plans asset allocation
 (union plan)
 (% of plan
assets)
	  	2010	 
	 	  	Employee
pension 
plan	 
	 Equity securities
	  	 	29	% 
	 Debt securities
	  	 	54	% 
	 Other
	  	 	17	% 
		  	 	 	 
	 Total
	  	 	100	% 
		  	 	 	 

  

					
	 Defined benefit plans asset allocation
 (non-union plan)
 (% of plan
assets)
	  	2010	 
	 	  	Employee
pension 
plan	 
	 Equity securities
	  	 	55	% 
	 Debt securities
	  	 	39	% 
	 Other
	  	 	6	% 
		  	 	 	 
	 Total
	  	 	100	% 
		  	 	 	 


  
 30 











 

 

  


	5.	FUEL ADJUSTMENT 

 The UARB
approved the implementation of a Fuel Adjustment Mechanism (“FAM”) for NSPI in the 2009 General Rate Decision effective January 1, 2009. The fuel adjustment related to the FAM includes the effect of fuel costs in both the
current period and the preceding year. The difference between actual fuel costs and amounts recovered from customers in the current period is included in the fuel adjustment. This amount, less the incentive component, is deferred to a FAM
regulatory asset in “Other assets” or a FAM regulatory liability in “Other liabilities”. Also included in the 2010 fuel adjustment is the rebate to customers of over recovered fuel costs from 2009. 

Details of the fuel adjustment related to the FAM are summarized in the following table: 

 

									
	 millions of dollars
	  	2010	 	 	2009	 
	 (Under) over recovery of current period fuel costs
	  	$	(76.6	) 	 	$	8.5	  
	 Rebate to customers from prior year
	  	 	(22.4	) 	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Fuel adjustment
	  	$	(99.0	) 	 	$	8.5	  
		  	 	 	 	 	 	 	 

 The Company has recognized a future income tax expense related to the fuel adjustment based on NSPI’s
applicable statutory income tax rate. The FAM regulatory asset or liability includes amounts recognized as a fuel adjustment and associated interest included in “Financing charges”. As at December 31, 2010, NSPI’s FAM regulatory
asset was $92.9 million (2009 – liability of $9.9 million), and future income tax liability related to the FAM was $29.2 million (2009 – asset of $3.4 million). 
 In the absence of UARB approval, the fuel adjustment would not have been recognized and earnings for the year ended December 31, 2010 would be $80.4 million ($56.3 million after-tax) lower (2009
– $9.9 million or $6.5 million after-tax higher). 
  

	6.	OPERATING LEASES 

 The
Company has entered into operating lease agreements for office space, rail cars, telecommunication services, and certain other equipment, which expire in 2011 to 2020. Future minimum annual lease payments under the leases are as follows: 

 

					
	 millions of dollars
	  	 	 
	 2011
	  	$	2.7	  
	 2012
	  	 	1.1	  
	 2013
	  	 	0.6	  
	 2014
	  	 	0.6	  
	 2015
	  	 	0.6	  
	 Thereafter
	  	 	1.4	  
		  	 	 	 
		  	$	7.0	  
		  	 	 	 

 For the year ended December 31, 2010, the Company recognized $10.1 million (2009 – $9.9 million)
of operating leases in “Operating, maintenance and general expense”. 

  
 31 











 

 

  


	7.	INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY EARNINGS 

 Investments subject to significant influence are comprised of the following: 
  

																	
	 	  	2010	 	 	2009	 
	 millions of dollars
	  	Carrying
value	 	  	Equity
earnings	 	 	Carrying
value	 	  	Equity
earnings	 
	 Maritimes & Northeast Pipeline
	  	$	118.8	  	  	$	9.1	  	 	$	116.8	  	  	$	10.2	  
	 Light and Power Holdings
	  	 	90.2	  	  	 	5.4	  	 	 	—  	  	  	 	—  	  
	 St. Lucia Electricity Services Ltd.
	  	 	25.0	  	  	 	2.1	  	 	 	25.5	  	  	 	2.4	  
	 Atlantic Hydrogen Inc.
	  	 	3.6	  	  	 	(0.4	) 	 	 	—  	  	  	 	—  	  
	 Maine Electric Power Company Inc.
	  	 	0.9	  	  	 	—  	  	 	 	2.0	  	  	 	—  	  
	 Maine Yankee Atomic Power Company
	  	 	0.2	  	  	 	—  	  	 	 	0.2	  	  	 	—  	  
	 Grand Bahama Power Company Limited (1)
	  	 	—  	  	  	 	(2.6	) 	 	 	73.9	  	  	 	1.4	  
	 Other
	  	 	0.2	  	  	 	—  	  	 	 	—  	  	  	 	—  	  
		  	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
		  	$	238.9	  	  	$	13.6	  	 	$	218.4	  	  	$	14.0	  
		  	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 

  

	(1)	As discussed under note 18 Acquisitions, Emera purchased in December 2010 an additional 55.4% of direct and indirect interest in GBPC. The acquisition has been
accounted for under the purchase method of accounting as Emera determined it has control of GBPC. For the quarter and the year ended December 31, 2010 and 2009, equity earnings included Emera’s 25% interest in GBPC.


 Equity investments include a $14.5 million difference between the cost and the underlying net book value of the
investees’ assets as at the date of acquisition. The excess is attributable to goodwill and is therefore not subject to amortization. 
  

	8.	FINANCING CHARGES 


Financing charges consists of the following: 
  

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Interest - long-term debt
	  	$	142.0	  	 	$	115.6	  
	      - short-term debt
	  	 	9.2	  	 	 	18.4	  
	 Preferred share dividends paid by subsidiary (note 10)
	  	 	8.0	  	 	 	9.5	  
	 Amortization of defeasance cost
	  	 	12.1	  	 	 	12.1	  
	 Amortization of debt financing costs
	  	 	3.6	  	 	 	5.4	  
	 Allowance for funds used during construction
	  	 	(22.2	) 	 	 	(28.9	) 
	 Interest (recovery) expense on deferral of FAM
	  	 	(3.8	) 	 	 	1.4	  
	 Foreign exchange losses
	  	 	0.9	  	 	 	0.5	  
	 Foreign exchange losses (gains) recovered through the FAM
	  	 	9.3	  	 	 	(3.0	) 
	 Banking fees and other
	  	 	9.3	  	 	 	4.3	  
		  	 	 	 	 	 	 	 
		  	$	168.4	  	 	$	135.3	  
		  	 	 	 	 	 	 	 

  

	9.	INCOME TAXES 

 The income
tax provision differs from that computed using the statutory rates for the following reasons: 
  

																	
	 millions of dollars
	  	2010	 	 	2009	 
	 Earnings before income taxes
	  	$	179.1	  	 				 	$	225.3	  	 			
		  	 	 	 	 				 	 	 	 	 			
	 Income taxes, at statutory rates
	  	 	60.9	  	 	 	34.0	% 	 	 	78.9	  	 	 	35.0	% 
	 Future income taxes on regulated earnings deferred to regulatory assets
(note 14)
	  	 	(67.5	) 	 	 	(37.7	) 	 	 	(33.5	) 	 	 	(14.9	) 
	 Equity earnings not subject to tax
	  	 	(5.9	) 	 	 	(3.3	) 	 	 	(5.8	) 	 	 	(2.6	) 
	 Change in estimate of prior year expected benefit of tax deductions
	  	 	(4.7	) 	 	 	(2.6	) 	 	 	—  	  	 	 	—  	  
	 Recovery of prior year income taxes
	  	 	(4.4	) 	 	 	(2.5	) 	 	 	—  	  	 	 	—  	  
	 Non-deductible preferred share dividends
	  	 	2.7	  	 	 	1.5	  	 	 	3.3	  	 	 	1.5	  
	 Non-deductible regulatory amortization (note 14)
	  	 	11.8	  	 	 	6.7	  	 	 	9.3	  	 	 	4.1	  
	 Other
	  	 	(5.7	) 	 	 	(3.2	) 	 	 	(3.3	) 	 	 	(1.4	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
		  	 	(12.8	) 	 	 	(7.1	)% 	 	 	48.9	  	 	 	21.7	% 
	 Income taxes – current
	  	 	(47.5	) 	 				 	 	51.0	  	 			
		  	 	 	 	 				 	 	 	 	 			
	 Income taxes – future (note 5)
	  	$	34.7	  	 				 	$	(2.1	) 	 			
		  	 	 	 	 				 	 	 	 	 			


  
 32 











 

 

  

 The future income tax assets and liabilities comprise the following: 

 

																	
	 	  	Current portion	 	  	Long-term portion	 
	 millions of dollars
	  	2010	 	  	2009	 	  	2010	 	 	2009	 
	 Future income tax assets:
	  				  				  				 			
	 Derivatives
	  	$	7.6	  	  	$	25.8	  	  	 	—  	  	 	 	—  	  
	 Tax loss carry forwards
	  	 	7.6	  	  	 	13.3	  	  	$	9.2	  	 	$	2.4	  
	 Property, plant and equipment
	  	 	—  	  	  	 	—  	  	  	 	1.1	  	 	 	0.8	  
	 Other
	  	 	13.0	  	  	 	7.6	  	  	 	2.6	  	 	 	1.2	  
		  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 
		  	$	28.2	  	  	$	46.7	  	  	$	12.9	  	 	$	4.4	  
		  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 
	 Future income tax liabilities:
	  				  				  				 			
	 Property, plant and equipment
	  	 	—  	  	  	 	—  	  	  	$	353.7	  	 	$	233.7	  
	 Net investment in direct financing lease
	  	 	—  	  	  	 	—  	  	  	 	32.0	  	 	 	18.8	  
	 Tax loss carry forwards
	  	 	—  	  	  	 	—  	  	  	 	(24.9	) 	 	 	(27.8	) 
	 Derivatives
	  	 	—  	  	  	 	—  	  	  	 	3.7	  	 	 	3.4	  
	 Asset retirement obligations
	  	 	—  	  	  	 	—  	  	  	 	(63.2	) 	 	 	(45.9	) 
	 Pension
	  	 	—  	  	  	 	—  	  	  	 	9.8	  	 	 	14.9	  
	 Defeasance costs
	  	 	—  	  	  	 	—  	  	  	 	19.2	  	 	 	20.0	  
	 Intangibles
	  	 	—  	  	  	 	—  	  	  	 	(26.9	) 	 	 	(26.4	) 
	 Deferral of FAM
	  	 	—  	  	  	 	—  	  	  	 	29.2	  	 	 	(3.4	) 
	 Other
	  	 	—  	  	  	 	—  	  	  	 	27.2	  	 	 	6.8	  
		  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 
		  	 	—  	  	  	 	—  	  	  	$	359.8	  	 	$	194.1	  
		  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 

 As at December 31, 2010, the Company has tax losses of $128.2 million (2009 – $131.9 million),
which are reflected in future income tax assets or netted against future income tax liabilities as appropriate, and begin to expire in 2014. The Company has recognized a future tax asset for the amount more likely than not to be realized.

 Accounting for the impact of rate regulation: 
 In the absence of rate-regulated accounting, future income tax expenses would have been recorded against net earnings and net earnings would be $73.4 million lower in 2010 (2009 – $20.2 million).

  

	10.	PREFERRED SHARES ISSUED BY SUBSIDIARY 

 Preferred shares issued by subsidiary consist of NSPI’s preferred shares and are classified as a financial liability on the balance sheet. 

Authorized: 
 Unlimited number of First Preferred Shares, issuable in series. 
 Unlimited number
of Second Preferred Shares, issuable in series. 
  

									
	 Issued and outstanding:
	  	Millions of
Shares	 	 	Preferred Share Capital
millions of
dollars	 
	 December 31, 2008
	  	 	10.4	  	 	$	260.0	  
	 Redemption of Series C First Preferred Shares
	  	 	(5.0	) 	 	 	(125.0	) 
	 December 31, 2009
	  	 	5.4	  	 	 	135.0	  
		  	 	 	 	 	 	 	 
	 December 31, 2010
	  	 	5.4	  	 	$	135.0	  
		  	 	 	 	 	 	 	 

 As at December 31, 2010 and 2009, the Company had 5.4 million 5.9% Series D preferred shares with
the following redemption features: 
 Series D First Preferred Shares: 

Each Series D First Preferred Share is entitled to a $1.475 per share per annum fixed cumulative preferential dividend, as and when
declared by the Board of Directors, accruing from the date of issue and payable quarterly on the fifteenth day of January, April, July and October of each year. 
 On and after October 15, 2015, Series D First Preferred Shares are redeemable by NSPI, in whole at any time or in part from time to time at $25 per share plus accrued and unpaid dividends. NSPI also
has the option, commencing October 15, 2015, to exchange the Series D First Preferred Shares into Emera Inc. common shares determined by dividing $25 by the greater of $2 and the market price of the Emera Inc. common shares. 

  
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 Commencing on and after January 15, 2016, with prior notice and prior to any
dividend payment date, each Series D First Preferred Share will be exchangeable at the option of the holder into fully paid and freely tradable Emera Inc. common shares determined by dividing $25 by the greater of $2 and the market price of the
Emera Inc. common shares, subject to the right of NSPI to redeem such shares for cash or to cause the holders of such shares to sell on the exchange date all or any part of such shares to substitute purchasers found by NSPI. NSPI will pay all
accrued and unpaid dividends to the exchange date. 
 Series C First Preferred Shares: 

On April 1, 2009, NSPI redeemed its outstanding Cumulative Redeemable First Preferred Shares, Series C for a redemption price of $25
per share for a total of $125 million. Each share was entitled to a $1.225 per share per annum fixed cumulative preferential dividend, as and when declared by the Board of Directors, accruing from the date of issue and payable quarterly on the first
day of January, April, July and October of each year. 
  

	11.	EARNINGS PER SHARE 


Earnings per share for 2010 are as follows: 
  

													
	 	  	2010	 
	 	  	Net earnings
(millions of 
dollars)	 	  	Weighted average
common shares (millions)	 	  	EPS
($)	 
	 Basic EPS
	  	$	191.1	  	  	 	113.7	  	  	$	1.68	  
	 Series D preferred shares of NSPI
	  	 	7.5	  	  	 	5.1	  	  	 	(0.01	) 
	 Performance share units and deferred share units
	  	 	—  	  	  	 	0.8	  	  	 	(0.01	) 
	 Other share-based compensation
	  	 	—  	  	  	 	0.7	  	  	 	(0.01	) 
		  	 	 	 	  	 	 	 	  	 	 	 
	 Diluted EPS
	  	$	198.6	  	  	 	120.3	  	  	$	1.65	  
		  	 	 	 	  	 	 	 	  	 	 	 

 Earnings per share for 2009 are as follows: 

 

													
	 	  	2009	 
	 	  	Net earnings
(millions of 
dollars)	 	  	Weighted average
common shares 
(millions)	 	  	EPS
($)	 
	 Basic EPS
	  	$	175.7	  	  	 	112.5	  	  	$	1.56	  
	 Series C preferred shares of NSPI
	  	 	1.5	  	  	 	1.5	  	  	 	(0.01	) 
	 Series D preferred shares of NSPI
	  	 	7.8	  	  	 	6.3	  	  	 	(0.02	) 
	 Performance share units and deferred share units
	  	 	—  	  	  	 	0.7	  	  	 	(0.01	) 
	 Other share-based compensation
	  	 	—  	  	  	 	0.3	  	  	 	—  	  
		  	 	 	 	  	 	 	 	  	 	 	 
	 Diluted EPS
	  	$	185.0	  	  	 	121.3	  	  	$	1.52	  
		  	 	 	 	  	 	 	 	  	 	 	 

 Where the exercise price exceeded the average price for the period, senior management share options were
excluded from the above calculation because they did not dilute earnings per share. 
  

	12.	ACCOUNTS RECEIVABLE 

 At
December 31, 2010, the Company had unbilled revenue included in accounts receivable in the amount of $102.7 million (2009 – $98.4 million). The unbilled revenue for NSPI, Bangor, MPS and GBPC is an estimate of the amount of revenue related
to energy delivered to customers since the date their meters were last read. The unbilled revenue related to Brunswick Pipeline is an estimate of toll revenue at the end of each month. Actual results may differ from these estimates. 

NSPI had a natural gas purchase agreement, which settled in November 2010, which included a price adjustment clause covering three years
of natural gas purchases. The clause stated NSPI would pay for all gas purchases at the agreed contract price, but would be entitled to a price rebate on a portion of the volumes, settled in November 2007 and November 2010. At December 31,
2009, the receivable was $82.1 million. 

  
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	13.	INVENTORY 

 The change in
inventory is due to the following: 
  

																	
	 For the year ended
	  	Fuel inventory
December 31	 	 	Materials inventory
December 31	 
	 millions of dollars
	  	2010	 	 	2009	 	 	2010	 	 	2009	 
	 Inventory, beginning of period
	  	$	144.5	  	 	$	101.7	  	 	$	30.0	  	 	$	29.5	  
	 Purchases
	  	 	327.9	  	 	 	362.0	  	 	 	45.7	  	 	 	39.3	  
	 Write-down of inventory to net realizable value
	  	 	—  	  	 	 	—  	  	 	 	(1.2	) 	 	 	(0.7	) 
	 Inventories expensed
	  	 	(346.4	) 	 	 	(319.2	) 	 	 	(22.5	) 	 	 	(22.1	) 
	 Inventories capitalized
	  	 	—  	  	 	 	—  	  	 	 	(26.5	) 	 	 	(23.2	) 
	 Increase in inventory resulting from acquisitions
	  	 	3.1	  	 	 	—  	  	 	 	14.2	  	 	 	—  	  
	 Other
	  	 	—  	  	 	 	—  	  	 	 	9.0	  	 	 	7.2	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Inventory, end of period
	  	$	129.1	  	 	$	144.5	  	 	$	48.7	  	 	$	30.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 The Company has not pledged inventory as security for liabilities. 

 

	14.	OTHER ASSETS AND LIABILITIES 

 Other assets and liabilities, including the impact of rate-regulated accounting policies, include the following: 
  

									
	 millions of dollars
	  	2010	 	  	2009	 
	 Other assets:
	  				  			
	 Regulatory assets:
	  				  			
	 Future income tax regulatory asset
	  	$	199.6	  	  	$	63.6	  
	 Unamortized defeasance costs
	  	 	94.6	  	  	 	106.7	  
	 Deferral of FAM
	  	 	92.9	  	  	 	—  	  
	 Pre-2003 income tax and related interest
	  	 	56.9	  	  	 	75.2	  
	 Costs to restructure purchased power contracts
	  	 	24.3	  	  	 	15.4	  
	 Seabrook nuclear project
	  	 	14.3	  	  	 	10.4	  
	 Deferral of income and capital taxes not included in Q1 2005 rates
	  	 	10.0	  	  	 	11.9	  
	 Deferral of demand side management
	  	 	7.5	  	  	 	9.7	  
	 Hydro-Québec obligation
	  	 	5.7	  	  	 	6.3	  
	 Maine Yankee decommissioning costs
	  	 	3.8	  	  	 	3.5	  
	 Deferral of vegetation management
	  	 	2.0	  	  	 	2.0	  
	 Deferred restructuring costs
	  	 	1.8	  	  	 	2.9	  
	 Stranded cost revenue requirement levelizers
	  	 	1.4	  	  	 	3.5	  
	 Deferral of Tufts Cove derivatives
	  	 	1.3	  	  	 	9.6	  
	 Held-for-trading natural gas contracts
	  	 	—  	  	  	 	3.9	  
	 Other
	  	 	13.9	  	  	 	3.6	  
		  	 	 	 	  	 	 	 
		  	 	530.0	  	  	 	328.2	  
		  	 	 	 	  	 	 	 
	 Non-regulatory assets:
	  				  			
	 Accrued pension asset – NSPI plan (note 4)
	  	 	110.7	  	  	 	94.4	  
	 Accrued pension asset – Bangor Hydro plan (note 4)
	  	 	1.8	  	  	 	1.7	  
	 Accrued pension asset – MPS plan (note 4)
	  	 	1.1	  	  	 	—  	  
	 Other
	  	 	8.5	  	  	 	3.1	  
		  	 	122.1	  	  	 	99.2	  
		  	 	 	 	  	 	 	 
		  	$	652.1	  	  	$	427.4	  
		  	 	 	 	  	 	 	 


  
 35 











 

 

  


									
	 	  	2010	 	  	2009	 
	 Other liabilities:
	  				  			
	 Regulatory liabilities:
	  				  			
	 2010 renewable tax benefits deferral
	  	$	14.5	  	  	 	—  	  
	 Held-for-trading natural gas contracts
	  	 	12.3	  	  	$	4.7	  
	 Deferral of Tufts Cove derivatives
	  	 	2.0	  	  	 	10.4	  
	 Deferral of FAM
	  	 	—  	  	  	 	9.9	  
	 Other
	  	 	4.9	  	  	 	6.6	  
		  	 	 	 	  	 	 	 
		  	 	33.7	  	  	 	31.6	  
		  	 	 	 	  	 	 	 
	 Non-regulatory liabilities:
	  				  			
	 Accrued pension and non-pension benefit liability – NSPI plan (note 4)
	  	 	64.8	  	  	 	61.8	  
	 Accrued non-pension benefit liability – Bangor Hydro plan (note 4)
	  	 	30.4	  	  	 	29.8	  
	 Accrued non-pension benefit liability – MPS plan (note 4)
	  	 	3.5	  	  	 	—  	  
	 Accrued non-pension benefit liability – GBPC plan (note 4)
	  	 	4.1	  	  	 	—  	  
	 Hydro-Québec obligation
	  	 	5.7	  	  	 	6.3	  
	 Maine Yankee decommissioning liability
	  	 	3.8	  	  	 	3.5	  
	 Unearned revenue
	  	 	1.1	  	  	 	1.7	  
	 Other
	  	 	14.6	  	  	 	13.4	  
		  	 	 	 	  	 	 	 
		  	 	128.0	  	  	 	116.5	  
		  	 	 	 	  	 	 	 
		  	$	161.7	  	  	$	148.1	  
		  	 	 	 	  	 	 	 

 Regulatory assets consist of: 

Future Income Tax Regulatory Asset 
 In accordance with the Company’s rate-regulated accounting policies covering income taxes, Emera deferred any future income taxes to a regulatory asset where the future income taxes are expected to
be included in future rates. Absent this accounting policy, Emera’s 2010 net earnings would be $73.4 million lower (2009 – $20.2 million). 
 Unamortized Defeasance Costs 
 Upon privatization in 1992, NSPI became
responsible for managing a portfolio of defeasance securities held in trust, which as at December 31, 2010 and 2009, totaled $1.0 billion. The excess of the cost of defeasance investments over the face value of the related debt is deferred on
the balance sheet and amortized over the life of the defeased debt as permitted by the UARB. In the absence of UARB approval, the losses would have been expensed as incurred and net earnings would be $12.1 million higher in 2010 and 2009.

 Deferral of Fuel Adjustment Mechanism 
 As discussed in Note 5, the UARB approved the implementation of a FAM in NSPI’s 2009 General Rate Decision effective January 1, 2009. 

In the absence of UARB approval, the fuel adjustment would not have been recognized and net earnings for the year ended December 31,
2010 would be $80.4 million ($56.3 million after-tax) lower (2009 – $9.9 million or $6.5 million after-tax higher). 

Pre-2003 Income Tax and Related Interest 
 NSPI has a regulatory asset related to pre-2003 income taxes that have been paid, but not yet recovered from customers. This circumstance arose when NSPI claimed capital cost allowance (“CCA”)
deductions in its corporate income tax returns that were ultimately disallowed by a decision of the Supreme Court of Canada. NSPI applied to the regulator to include recovery of these costs in customer rates. In its February 5, 2007 decision,
the UARB approved recovery of this regulatory asset over eight years, commencing April 1, 2007. 
 In January 2010, NSPI
reached an agreement with stakeholders on its calculation of regulated ROE. The agreement provides the Company with flexibility in amortizing the pre-2003 income tax regulatory asset allowing the Company to recognize additional amortization in
current periods and reducing amounts in future periods. Accordingly, to allow flexibility relating to future customer rate requirements, NSPI recorded an additional discretionary $4.8 million of regulatory amortization expense for the year ended
December 31, 2010 (December 31, 2009 – $10.0 million). In the absence of UARB approved recovery, the liability would have been expensed when incurred, therefore net earnings would be $18.3 million higher in 2010 (2009 – $24.6
million). 

  
 36 











 

 

  

 In 2009, NSPI recorded an income tax recovery of $5.5 million relating to manufacturing
and processing deductions claimed for its 1999-2003 amended corporate income tax returns, which reduced the regulatory asset. 

Costs to Restructure Power Purchase Contracts 
 Bangor Hydro has power purchase contracts, which it was required to negotiate when oil prices were high, with several independent power producers known as small power production facilities. The cost of
power from these facilities is more than Bangor Hydro would incur from other sources if it were not obligated under these contracts. Bangor Hydro attempted to alleviate the adverse impact of these high-cost contracts and in doing so incurred costs
to restructure certain of the contracts. The MPUC has allowed Bangor Hydro to defer these costs and recover them in stranded cost rates. The contract restructuring costs are being recovered over a 20-year period ending in June 2018. The annual
amortization is approximately $2.0 million. In the absence of the MPUC’s approval, these BHE costs would have been expensed as incurred and net earnings would have been $1.8 million ($1.0 million after-tax) higher in 2010 (2009 – $1.9
million or $1.1 million after-tax). 
 MPS also had a similar power purchase contract, which expired December 31, 2006. The
MPUC allowed MPS to defer the cost of the purchased power in excess of the market price at which MPS was able to sell the power. MPS is in the process of recovering this regulatory asset in stranded costs. Recovery of this regulatory asset varies
each year, in accordance with the approved stranded cost rates, in order to maintain levelized stranded cost rates. 

Seabrook Nuclear Project 
 Bangor Hydro and MPS were participants in the Seabrook nuclear project in Seabrook, New Hampshire. On December 31, 1984, Bangor Hydro had almost $87 million invested in Seabrook, but because the
uncertainties arising out of the Seabrook Project were having an adverse impact on Bangor Hydro’s financial condition, an agreement for the sale of Seabrook was reached in mid-1985 and was finalized in November 1986. In 1985, the MPUC issued an
order disallowing recovery of certain Seabrook costs, but provided for the recovery through customer rates of 70% of Bangor Hydro’s year-end 1984 investment in Seabrook Unit 1 over 30 years ending in October 2015. For BHE, in the absence of
MPUC approval, the loss on sale would have been recognized when incurred and net earnings would have been $1.8 million ($1.0 million after-tax) higher in 2010 (2009 – $1.9 million or $1.1 million after-tax). MPS deferred $43.1 million of costs
associated with Seabrook, scheduled for recovery through 2016. 
 Deferral of Income and Capital Taxes Not Included in Q1
2005 Rates 
 The UARB agreed to allow NSPI to defer taxes not reflected in rates for the period January 1, 2005 until
April 1, 2005, the date when new rates became effective. In 2005, NSPI deferred $16.7 million consisting of $4.5 million of provincial and federal grants and $12.2 million in income taxes reflecting increases in these taxes since rates were
last set in 2002. In its February 2007 decision, the UARB approved recovery of this regulatory asset over eight years, commencing April 1, 2007. In the absence of UARB approval, these taxes would not have been deferred and net earnings for 2010
would be $1.9 million higher (2009 – $1.9 million). 
 Deferral of Demand Side Management 

The UARB agreed to allow NSPI to defer up to $12.8 million of demand side management expenditures for the period January 1, 2008,
through December 31, 2009, to be recovered in rates over six years commencing January 1, 2009. In the absence of the UARB’s approval, these costs would not have been deferred and net earnings for 2010 would be $2.2 million higher
(2009 – $9.4 million lower). 
 Hydro-Québec Obligation 

The obligation associated with Hydro-Québec represents the estimated present value of Bangor Hydro’s estimated future payments
for net costs associated with ownership and operation of the Hydro-Québec intertie between the New England utilities and Hydro-Québec. The obligation has been recognized in “Other liabilities” and the MPUC has permitted
recovery of this obligation. The regulatory asset and obligation are being reduced as expenses are incurred with the reduction of the regulatory asset amortized to purchase power expense. In the absence of regulatory approval, 2010 net earnings
would be $0.2 million ($0.1 million after-tax) higher (2009 – $0.4 million or $0.2 million after-tax). 

  
 37 











 

 

  

 Maine Yankee Decommissioning Costs 

Bangor Hydro owns 7% of the common stock of Maine Yankee and MPS owns 5% of the common stock of Maine Yankee. In 1997, Maine Yankee
permanently shut down its nuclear generating plant. Pursuant to a contract with Maine Yankee, Bangor Hydro and MPS are required to pay their pro-rata shares of Maine Yankee’s decommissioning costs. Bangor Hydro’s share of the estimated
decommissioning costs were approximately $2.4 million in 2010 (2009 – $3.8 million). Maine Yankee expense recovery is included in Bangor Hydro’s stranded cost revenues, and along with all stranded cost revenues, purchased power, and
Hydro-Québec costs, are fully recoverable. For any variance between the actual amount of these items and the amounts used in setting rates, a regulatory deferral is recorded with a credit or charge to regulatory amortizations at both Bangor
Hydro and MPS. Any over or under-recovery will be reviewed at future rate proceedings with the MPUC. For BHE, in the absence of regulatory approval, the Maine Yankee decommissioning costs would have been expensed when incurred and net earnings would
have been $1.0 million ($0.6 million after-tax) higher in 2010 (2009 – $0.4 million or $0.2 million after-tax). 

Deferral of Vegetation Management 
 The UARB agreed to allow NSPI to defer up to $2.0 million of vegetation management spending in 2008 to be recovered in rates in a future period. The investment in vegetation management spending was part
of a specific initiative to improve the reliability of service provided to customers. In the absence of UARB approval, these costs would have been expensed as incurred. 
 Deferred Restructuring Costs 
 In conjunction with Bangor Hydro’s
Alternative Rate Plan, Bangor Hydro was provided with accounting orders from the MPUC to defer and amortize over ten years certain employee transition costs. Eligible for deferral were the 2002 and 2003 employee transition costs related to
reductions in the cost of operations and employee transition costs associated with Bangor Hydro’s automated meter reading project and the outsourcing of information technology support in 2004 and 2005. In the absence of regulatory approval,
these costs would have been expensed as incurred and 2010 net earnings would have been $1.0 million ($0.6 million after-tax) higher (2009 – $1.1 million or $0.7 million after-tax). 

Stranded Cost Revenue Requirement Levelizer 
 Bangor Hydro’s stranded cost rates are reset every three years and are designed to recover Bangor Hydro’s cumulative stranded cost revenue requirements over the three-year period. The most
recently approved stranded cost rates are in effect from March 2008 to February 2011. While the stranded cost revenue requirements differ throughout the period due to changes in stranded cost revenues and expenses, the annual stranded cost revenues
are the same during the period. To levelize the impact of the varying revenue requirements, cost or revenue deferrals are recognized. This levelizer is recognized only as result of regulatory accounting and the stranded cost ratemaking process.
Absent regulatory accounting, the levelizer mechanism would not exist, and the methodology for determining Bangor Hydro’s rates associated with stranded costs is not known. In the absence of regulatory approval, net earnings for 2010 would be
$2.0 million ($1.2 million after-tax) higher (2009 – $0.2 million or $0.1 million after-tax). 
 Deferral of Tufts Cove
Derivatives 
 In accordance with Handbook Standard 3865 Hedges, NSPI determined that it could not meet the probability
requirement of the standard for its derivatives in place to hedge natural gas and heavy fuel oil for TUC. This is due to the generating station’s ability to fuel switch and NSPI’s economic dispatch based on the relative cost of these two
fuels. The UARB has allowed NSPI to apply hedge accounting to these derivatives as long as the other requirements of the Handbook are met. This accounting policy permits NSPI to defer the fair value of hedges that are no longer required because of
fuel switching. 
 In 2009, the UARB approved an amendment to NSPI’s accounting practice to include all Tufts Cove financial
commodity hedges which are no longer required. This change in practice will impact the timing of recognition between “Fuel for generation and purchased power” and “Fuel adjustment” as a result of the FAM implemented in 2009. The
change in accounting practice has been applied prospectively, beginning January 1, 2009, as required by the UARB. 

  
 38 











 

 

  

 Absent UARB approval, NSPI would be required to recognize the change in fair value of
these derivatives in “Fuel for generation and purchased power” with an offset to “Fuel adjustment”. However, with the approval of FAM, there would be no material earnings impact. 

Held-for-trading Natural Gas Contracts 
 In accordance with implementing Standard 3855 Financial Instruments – Recognition and Measurement, the Company has contracts for the purchase and sale of natural gas at TUC that are considered HFT
derivatives and accordingly are recognized on the balance sheet at fair value. This reflects NSPI’s history of buying and reselling any natural gas not used in the production of electricity at TUC. Changes in fair value of HFT derivatives are
normally recognized in net earnings. In accordance with NSPI’s rate-regulated accounting policy for financial instruments and hedges relating to TUC fuel, NSPI has deferred any changes in fair value to a regulatory asset or liability. Absent
UARB approval, NSPI would be required to recognize the changes in fair value of these derivatives in earnings. However, with the approval of FAM, there would be no material earnings impact. 

Other 

Bangor Hydro and MPS have other regulatory assets, which are being amortized to net earnings over varying lives. These deferred costs
would have been expensed as incurred in the absence of approval from one of its regulators, and BHE net earnings would have been $7.1 million ($4.2 million after-tax) higher in 2010 (2009 – $2.6 million or $1.6 million after-tax). 

Regulatory liabilities consist of: 
 2010 Renewable Tax Benefit Deferral 
 In 2010, the UARB granted NSPI
approval to defer certain tax benefits related to renewable energy projects arising in 2010. The UARB will convene a proceeding in 2011 to discuss how this deferral will be applied. Absent UARB approval, these benefits would not have been deferred
and net earnings would be $14.5 million higher. 
 Held-for-trading Natural Gas Contracts 

As discussed above, in accordance with NSPI’s accounting policy for financial instruments and hedges relating to TUC fuel, NSPI has
deferred any changes in fair value of its natural gas contracts to a regulatory asset or liability. Absent UARB approval, NSPI would be required to recognize the changes in fair value of these derivatives in earnings. However, with the approval of
FAM, there would be no material earnings impact. 
 Deferral of Tufts Cove Derivatives 

As discussed above, NSPI has an accounting policy that permits NSPI to defer the fair value of any TUC financial commodity hedges that are
no longer required. Absent UARB approval, NSPI would be required to recognize the changes in fair value of these derivatives in earnings. However, with the approval of FAM, there would be no material earnings impact. 

Other 

Bangor Hydro and MPS have other regulatory liabilities, which are being amortized to net earnings over varying lives. These deferred gains
would have been expensed as incurred in the absence of approval from one of its regulators, and net earnings would have been $1.7 million ($1.0 million after-tax) higher in 2010 (2009 – $0.3 million or $0.1 million after-tax). 

  
 39 











 

 

  


	15.	INTANGIBLES 

 Intangibles
are comprised of the following: 
  

													
	 millions of dollars
	  	2010	 
	 	  	Cost	 	  	Accumulated
Amortization	 	  	Net
Book Value	 
	 Transmission
	  	$	74.1	  	  	$	16.8	  	  	$	57.3	  
	 Distribution
	  	 	26.1	  	  	 	6.9	  	  	 	19.2	  
	 Other
	  	 	41.5	  	  	 	14.5	  	  	 	27.0	  
		  	 	 	 	  	 	 	 	  	 	 	 
		  	$	141.7	  	  	$	38.2	  	  	$	103.5	  
		  	 	 	 	  	 	 	 	  	 	 	 
		
	 millions of dollars
	  	2009	 
	 	  	Cost	 	  	Accumulated
Amortization	 	  	Net
Book Value	 
	 Transmission
	  	$	69.4	  	  	$	15.7	  	  	$	53.7	  
	 Distribution
	  	 	23.4	  	  	 	6.6	  	  	 	16.8	  
	 Other
	  	 	41.7	  	  	 	20.1	  	  	 	21.6	  
		  	 	 	 	  	 	 	 	  	 	 	 
		  	$	134.5	  	  	$	42.4	  	  	$	92.1	  
		  	 	 	 	  	 	 	 	  	 	 	 

 Amortization expense for the year ended December 31, 2010 is $5.4 million (2009 – $4.6 million).

  

	16.	NET INVESTMENT IN DIRECT FINANCING LEASE 

 Brunswick Pipeline commenced service on July 16, 2009, transporting re-gasified LNG for Repsol Energy Canada under a 25 year firm service agreement. The agreement meets the definition of a direct
financing capital lease for accounting purposes. The net investment in direct financing lease is the sum of the expected toll revenues, less the estimated operating costs on the pipeline shown net of unearned finance income. The unearned income is
recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. 
  

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Total minimum lease payments to be received
	  	$	1,678.1	  	 	$	1,746.9	  
	 Less: amounts representing estimated executory costs
	  	 	(258.7	) 	 	 	(252.2	) 
	 Minimum lease payments receivable
	  	 	1,419.4	  	 	 	1,494.7	  
	 Less: unearned finance lease income
	  	 	(931.2	) 	 	 	(1,017.8	) 
		  	 	 	 	 	 	 	 
	 Total net investment in direct financing lease
	  	$	488.2	  	 	$	476.9	  
		  	 	 	 	 	 	 	 

 Future minimum lease payments to be received for the next five years: 

 

																					
	 millions of dollars
	  	For the year ended December 31	 
	 	  	2011	 	  	2012	 	  	2013	 	  	2014	 	  	2015	 
	 Minimum lease payments to be received
	  	$	57.9	  	  	$	58.8	  	  	$	58.8	  	  	$	60.0	  	  	$	61.6	  
	 Less: amounts representing estimated executory costs
	  	 	8.9	  	  	 	9.1	  	  	 	9.3	  	  	 	9.4	  	  	 	9.6	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Minimum lease payments receivable
	  	$	49.0	  	  	$	49.7	  	  	$	49.5	  	  	$	50.6	  	  	$	52.0	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 


  
 40 











 

 

  


	17.	PROPERTY, PLANT AND EQUIPMENT 

 Property, plant and equipment is comprised of the following: 
  

													
	 	  	2010	 
	 millions of dollars
	  	Cost	 	  	Accumulated
Depreciation	 	  	Net
Book Value	 
	 Generation
	  				  				  			
	 Thermal
	  	$	1,965.1	  	  	$	827.5	  	  	$	1,137.6	  
	 Diesel & Steam
	  	 	126.9	  	  	 	52.4	  	  	 	74.5	  
	 Gas Turbines
	  	 	89.3	  	  	 	29.8	  	  	 	59.5	  
	 Combustion Turbines
	  	 	83.5	  	  	 	17.6	  	  	 	65.9	  
	 Hydroelectric
	  	 	474.0	  	  	 	154.4	  	  	 	319.6	  
	 Wind Turbines
	  	 	219.7	  	  	 	2.5	  	  	 	217.2	  
	 Transmission
	  	 	922.6	  	  	 	359.6	  	  	 	563.0	  
	 Distribution
	  	 	1,601.2	  	  	 	800.2	  	  	 	801.0	  
	 Other
	  	 	430.4	  	  	 	222.7	  	  	 	207.7	  
	 Other, under capital lease
	  	 	6.8	  	  	 	2.1	  	  	 	4.7	  
		  	 	 	 	  	 	 	 	  	 	 	 
		  	$	5,919.5	  	  	$	2,468.8	  	  	$	3,450.7	  
		  	 	 	 	  	 	 	 	  	 	 	 
		
	 	  	2009	 
	 millions of dollars
	  	Cost	 	  	Accumulated
Depreciation	 	  	Net
Book Value	 
	 Generation
	  				  				  			
	 Thermal
	  	$	1,902.6	  	  	$	796.4	  	  	$	1,106.2	  
	 Gas Turbines
	  	 	85.9	  	  	 	25.0	  	  	 	60.9	  
	 Combustion Turbines
	  	 	78.8	  	  	 	20.4	  	  	 	58.4	  
	 Hydroelectric
	  	 	454.8	  	  	 	148.9	  	  	 	305.9	  
	 Wind Turbines
	  	 	2.1	  	  	 	0.7	  	  	 	1.4	  
	 Transmission
	  	 	811.6	  	  	 	338.1	  	  	 	473.5	  
	 Distribution
	  	 	1,418.0	  	  	 	714.8	  	  	 	703.2	  
	 Other
	  	 	396.6	  	  	 	181.6	  	  	 	215.0	  
	 Other, under capital lease
	  	 	10.7	  	  	 	1.5	  	  	 	9.2	  
		  	 	 	 	  	 	 	 	  	 	 	 
		  	$	5,161.1	  	  	$	2,227.4	  	  	$	2,933.7	  
		  	 	 	 	  	 	 	 	  	 	 	 

  

	18.	ACQUISITIONS 

 Grand
Bahama Power Company Limited 
 On December 22, 2010, Emera purchased a 50% interest in GBPC and an additional 10.7%
interest in ICDU, owner of the remaining 50% interest in GBPC, for $88.1 million USD ($87.7 million CAD), bringing Emera’s total ownership of GBPC to 80.4%. GBPC is an integrated utility with 19,000 customers and has 137 megawatts
(“MW”) of installed oil-fired capacity. The Grand Bahama Port Authority regulates the utility and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit, and distribute electricity on the island until 2054.
There is a fuel pass through mechanism and flexible tariff adjustment policies to ensure that costs are recovered and a reasonable return earned. 
 The acquisition has been accounted for under the purchase method of accounting as Emera has determined it has control of GBPC through the combination of both direct and indirect interests. At
December 31, 2010, the assets and liabilities of GBPC have been consolidated on Emera’s balance sheet and there was no material earnings impact in 2010 related to this transaction. GBPC is included in the segments “Other” in Note
3 Segment Information. The following summarizes the transaction: 
  

					
	 Preliminary purchase price allocation:
	  	millions of dollars	 
	 Net working capital
	  	$	4.0	  
	 Property, plant and equipment
	  	 	96.8	  
	 Goodwill
	  	 	34.2	  
	 Long-term debt
	  	 	(47.3	) 
		  	 	 	 
	 Total net assets
	  	$	87.7	  
		  	 	 	 


  
 41 











 

 

  

 When Emera purchased its 50% interest in ICDU in September 2008, the transaction
included goodwill of $15.2 million CAD. Also included in ICDU was inherent goodwill of $11.5 million CAD from when ICDU purchased its 50% interest in GBPC. As Emera now controls both companies and consolidates both GBPC and ICDU’s assets and
liabilities, all of the goodwill is now recognized in Emera. 
 The purchase price allocation has not yet been finalized as the
Company has not completed the valuation of property, plant and equipment in GBPC and therefore the allocation of the purchase price has been estimated, and is subject to change. 

The purchase price was funded with existing credit facilities. 
 Maine & Maritimes Corporation 
 On December 21, 2010, Emera
purchased all of the outstanding shares of MAM for $80.4 million USD ($81.9 million CAD). MAM is the parent company of MPS, a regulated electric transmission and distribution utility serving approximately 36,000 electricity customers in northern
Maine. 
 The acquisition has been accounted for under the purchase method of accounting as Emera has determined it has control
of MAM. There was no material earnings impact in 2010 related to this transaction. MAM is included in the segments “Other” in Note 3 Segment Information. The following summarizes the transaction: 

 

					
	 Purchase price allocation:
	  	millions of dollars	 
	 Net working capital
	  	$	1.3	  
	 Property, plant and equipment
	  	 	69.4	  
	 Regulatory and other assets
	  	 	34.5	  
	 Goodwill
	  	 	35.9	  
	 Regulatory and other liabilities
	  	 	(36.2	) 
	 Long-term debt
	  	 	(23.0	) 
		  	 	 	 
	 Total net assets
	  	$	81.9	  
		  	 	 	 

 The purchase price allocation has not been finalized. A third party valuation of the assets was not performed
because the fair value of the regulated assets are equal to their rate base since a regulated utility can only recover its cost/book value (i.e. rate base) plus a fair return. 
 The purchase price was funded with existing credit facilities. 
 Barbados
Light & Power Company Limited 
 On May 11, 2010, Emera acquired a 38% interest in Light & Power
Holdings Ltd. (“LPH”), the parent company of Barbados Light & Power Company Limited (“BLPC”), for $85 million USD. BLPC is the sole utility operator on the island of Barbados, serving approximately 120,000 customers.
BLPC has three power generation stations with 239 MW of installed capacity. There is a fuel pass through mechanism to ensure costs are recovered and a reasonable return earned. 
 The acquisition has been accounted for as an equity investment, and accordingly, the investment was initially recorded at cost. Emera’s pro-rata share of the results since acquisition have been
included in the carrying value of the investment and consolidated statements of earnings. Any dividends received or receivable reduces the carrying value of the investment. The carrying value of the investment and equity earnings related to the
investment as at December 31, 2010 were $90.2 million and $5.4 million respectively. LPH is included in the segment “Other” in Note 3 Segment Information. The purchase was financed with existing credit facilities. 

  
 42 











 

 

  

 Bayside Power LP 

On September 1, 2009, Emera’s subsidiary, Emera Energy Inc., purchased 100% interest in the Bayside Power Limited Partnership
(“Bayside”) for $32.9 million cash consideration. Bayside owns a 260-megawatt gas-fired combined cycle electricity generating facility, built in 1999, and located in Saint John, New Brunswick. Bayside has a contract to 2021 to supply
electricity for the months of November through March; and operates as a merchant facility, selling into the Maritimes and northeastern United States markets, for the balance of the year. Bayside can, at its sole option, extend the winter supply
contract for an additional 5 years, through to March 31, 2026. 
 The acquisition has been accounted for under the purchase
method of accounting as Emera Energy Inc. controls Bayside. Accordingly, the results of operations since the date of acquisition have been included in the consolidated statement of earnings. Bayside is included in the segment “Other” in
Note 3 Segment Information. 
 The final fair value based on the purchase price allocation was as follows: 

 

					
	 	  	millions of dollars	 
	 Net working capital
	  	$	2.6	  
	 Property, plant and equipment
	  	 	46.9	  
	 Mark-to-market on long-term gas supply purchase contracts liability
	  	 	(10.7	) 
	 Future income taxes liability
	  	 	(5.9	) 
		  	 	 	 
	 Total net assets
	  	$	32.9	  
		  	 	 	 

 The purchase price was funded with existing credit facilities. 

 

	19.	INTEREST IN JOINT VENTURES 


The following amounts represent the Company’s proportionate interest in its joint ventures’ financial position, operating
results, and cash flows included in the consolidated financial statements: 
  

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Current assets
	  	$	10.6	  	 	$	7.8	  
	 Non-current assets
	  	 	52.8	  	 	 	67.2	  
		  	 	 	 	 	 	 	 
		  	$	63.4	  	 	$	75.0	  
		  	 	 	 	 	 	 	 
	 Current liabilities
	  	$	8.6	  	 	$	13.5	  
	 Non-current liabilities
	  	 	76.1	  	 	 	78.5	  
		  	 	 	 	 	 	 	 
		  	$	84.7	  	 	$	92.0	  
		  	 	 	 	 	 	 	 
	 Revenues
	  	$	28.1	  	 	$	53.4	  
	 Expenses
	  	 	(27.2	) 	 	 	(39.0	) 
		  	 	 	 	 	 	 	 
	 Net earnings
	  	$	0.9	  	 	$	14.4	  
		  	 	 	 	 	 	 	 
	 Cash provided by operations
	  	$	14.7	  	 	$	17.3	  
	 Cash used in investing activities
	  	 	(1.6	) 	 	 	(0.5	) 
	 Cash used in financing activities
	  	 	(12.6	) 	 	 	(16.1	) 
		  	 	 	 	 	 	 	 
	 Increase in cash
	  	$	0.5	  	 	$	0.7	  
		  	 	 	 	 	 	 	 

  

	20.	INTEREST IN JOINTLY CONTROLLED PROJECTS 

 In November 2009, NSPI signed a 20-year operating agreement with Renewable Energy Services Ltd. (“RESL”) for operation of a 23.3 MW wind energy project at Point Tupper, Nova Scotia. NSPI will
acquire and retain title to specific property, plant and equipment, which is less than 50% of the total project combined assets. Each company is entitled to its proportionate share of the net operating revenues based on the relative value of their
assets. 

  
 43 











 

 

  

 NSPI has provided a guarantee for the indebtedness of RESL in connection with the
project. The guarantee is up to a maximum of $25.4 million. NSPI holds a security interest in the assets of RESL, including the project assets. 
 Beginning August 2010, following the commencement of service, NSPI has recorded its share of the net operating revenues of the project. As at December 31, 2010, $25.4 million was included in
“Property, plant and equipment” for NSPI’s portion of the Point Tupper wind energy project. NSPI’s share of the cash flows and the net earnings was immaterial for the year. 

MPS is a party to a collaborative arrangement with Central Maine Power (“CMP”) to develop the Maine Power Connection Project.
The terms of the arrangement were established in the Joint Development Agreement, dated October 1, 2008. The cost of development activities, including acquisition of land in the transmission corridor and acquisition of necessary governmental
and regulatory permits and approvals, are shared between MPS and CMP, with MPS paying 10% of such costs, and CMP 90%. MPS has deferred in “Other assets” $0.9 million of costs associated with the MPC project as of December 31, 2010.

  

	21.	GOODWILL 

 The change in
goodwill is due to the following: 
  

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Balance, beginning of year
	  	$	87.6	  	 	$	102.0	  
	 Acquisitions
	  	 	95.6	  	 	 	—  	  
	 Change in foreign exchange rate
	  	 	(4.3	) 	 	 	(14.4	) 
		  	 	 	 	 	 	 	 
	 Balance, end of year
	  	$	178.9	  	 	$	87.6	  
		  	 	 	 	 	 	 	 

  

	22.	ASSET RETIREMENT OBLIGATIONS 

 Asset retirement obligations (“ARO”) are recognized when incurred and represent the fair value, using the Company’s credit-adjusted risk-free rate, of the Company’s estimated future
cash flows necessary to discharge legal obligations related to reclamation of land at the Company’s thermal, hydro and combustion turbine sites, pipelines, and disposal of polychlorinated biphenyls (“PCBs”) in its transmission and
distribution equipment. Estimated future cash flows are based on the Company’s completed depreciation studies, prior experience, estimated useful lives, and governmental regulatory requirements and the costs of activities such as demolition,
restoration and remedial work based on present-day methods and technologies. Actual results may differ from these estimates. 

The change in ARO is due to the following: 
  

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Balance, beginning of year
	  	$	104.5	  	 	$	88.0	  
	 Accretion included in depreciation expense
	  	 	3.6	  	 	 	3.4	  
	 Accretion deferred to regulatory asset
	  	 	2.1	  	 	 	1.5	  
	 Liabilities settled
	  	 	(1.2	) 	 	 	(1.2	) 
	 Additions
	  	 	32.8	  	 	 	12.8	  
		  	 	 	 	 	 	 	 
	 Balance, end of year
	  	$	141.8	  	 	$	104.5	  
		  	 	 	 	 	 	 	 


  
 44 











 

 

  

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

 

													
	 Asset
	  	Credit-adjusted
risk-free rate	 	 	Estimated undiscounted
future
obligation
(millions of dollars)	 	  	Expected
settlement
date	 
	 Thermal
	  	 	5.30	% 	 	$	258.9	  	  	 	10 – 29 years	  
	 Hydro
	  	 	5.27	% 	 	 	101.4	  	  	 	21 – 51 years	  
	 Wind
	  	 	5.21	% 	 	 	45.5	  	  	 	13 – 20 years	  
	 Combustion turbines
	  	 	5.25	% 	 	 	12.9	  	  	 	1 – 14 years	  
	 Transmission & distribution
	  	 	5.74	% 	 	 	21.6	  	  	 	1 – 15 years	  
	 Pipeline
	  	 	3.80	% 	 	 	11.0	  	  	 	39 years	  
		  				 	 	 	 	  			
		  				 	$	451.3	  	  			
		  				 	 	 	 	  			

 Some of the Company’s hydro, transmission and distribution assets may have additional ARO. As
the Company expects to use the majority of its installed assets for an indefinite period, no removal date can be determined and consequently, a reasonable estimate of the fair value of any related ARO cannot be made at this time. 

Additionally, some of the Company’s transmission and distribution assets may have conditional ARO, the fair value of which cannot be
reasonably estimated as sufficient information does not exist to estimate the obligation. A liability will be recognized in the period in which sufficient information becomes available. 

Accounting for the impact of rate regulation: 
 Any difference between the amount approved by the regulator of NSPI as depreciation expense and the amount that would have been calculated under the accounting standard for ARO is recognized as a
regulatory asset in “Property, plant and equipment”. In the absence of this deferral, net earnings for 2010 would be $2.1 million lower (2009 – $1.5 million). 

 

	23.	SHORT-TERM DEBT 

 For the
year ended December 31, short-term debt consists of: 
  

					
	 millions of dollars
	  	2010	 
	 Short-term discount notes bearing interest at prevailing market rates plus applicable fees, which on December 31, 2010,
averaged 2.20%
	  	$	176.3	  
		  	 	 	 
	 LIBOR loans bearing interest at prevailing market rates plus applicable fees, which on December 31, 2010, averaged
2.01%.
	  	 	19.1	  
	 Advances, which when drawn upon against operating lines of credit, bear interest at the prime rate plus a bank spread, which on
December 31, 2010, was 3.00% in Canada, 3.25% in the US and Bahamian prime of 5.50%.
	  	 	5.0	  
	 Promissory note issued to Algonquin Power & Utilities Corp.
	  	 	27.7	  
		  	 	 	 
		  	$	228.1	  
		  	 	 	 
		
	 millions of dollars
	  	2009	 
	 Short-term discount notes bearing interest at prevailing market rates plus applicable fees, which on December 31, 2009,
averaged 0.35%.
	  	$	193.3	  
	 LIBOR loans bearing interest at prevailing market rates plus applicable fees, which on December 31, 2009, averaged
0.88%.
	  	 	49.4	  
	 Advances, which when drawn upon against operating lines of credit, bear interest at the prime rate plus a bank spread, which on
December 31, 2009, was 2.25% in Canada and 3.25% in the US.
	  	 	29.9	  
	 Promissory note issued to Algonquin Power & Utilities Corp.
	  	 	27.7	  
		  	 	 	 
		  	$	300.3	  
		  	 	 	 

 This short-term debt is unsecured. 

  
 45 











 

 

  


	24.	LONG-TERM DEBT 

 Long-term
debt includes the issuances detailed below. Medium-term notes and debentures are issued under trust indentures at fixed interest rates, and are unsecured unless noted below. Also included are certain bankers’ acceptances and commercial paper
where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year. 
  

																					
	 	  	Effective Average	 	  	 	 	  	 	 	 	 	 
	 	  	Interest Rate %	 	  	 	 	  	Amount Outstanding	 
	 millions of dollars
	  	2010	 	  	2009	 	  	Years of Maturity	 	  	2010	 	 	2009	 
	 Emera
	  				  				  				  				 			
	 Bankers acceptances, LIBOR loans and advances (1)
	  	 	2.82	  	  	 	2.77	  	  	 	3 year renewal	  	  	$	250.0	  	 	$	221.6	  
	 Medium-term notes
	  	 	4.45	  	  	 	4.45	  	  	 	2014 - 2019	  	  	 	475.1	  	 	 	475.0	  
	 Capital lease obligations
	  	 	4.85	  	  	 	4.84	  	  	 	Various	  	  	 	2.5	  	 	 	3.6	  
	 NSPI
	  				  				  				  				 			
	 Medium-term notes (2)
	  	 	6.56	  	  	 	6.60	  	  	 	2011 - 2097	  	  	 	1,610.0	  	 	 	1,410.0	  
	 Debentures
	  	 	9.75	  	  	 	9.75	  	  	 	2019	  	  	 	95.0	  	 	 	95.0	  
	 Short-term discount notes (3)
	  	 	1.07	  	  	 	—  	  	  	 	3 year renewal	  	  	 	241.7	  	 	 	—  	  
	 Capital lease obligations
	  	 	6.30	  	  	 	3.89	  	  	 	Various	  	  	 	0.1	  	 	 	3.7	  
	 Bangor Hydro

(issued and payable in USD)
	  				  				  				  				 			
	 LIBOR loans & demand loans (1)
	  	 	2.26	  	  	 	—  	  	  	 	3 year renewal	  	  	 	38.6	  	 	 	—  	  
	 General & refunding mortgage bonds – secured by property, plant and equipment
	  	 	9.74	  	  	 	9.74	  	  	 	2020 - 2022	  	  	 	49.7	  	 	 	52.3	  
	 Senior unsecured notes
	  	 	5.66	  	  	 	5.64	  	  	 	2011 - 2017	  	  	 	105.8	  	 	 	116.1	  
	 Bear Swamp

(issued and payable in USD)
	  				  				  				  				 			
	 Senior non-revolving credit facility secured by the assets of Bear Swamp
	  	 	1.44	  	  	 	1.00	  	  	 	2012	  	  	 	60.6	  	 	 	65.4	  
	 Maine and Maritimes

(issued and payable in USD)
	  				  				  				  				 			
	 Maine Public Utility Financing Bank Bonds (4)
	  	 	0.32	  	  	 	—  	  	  	 	2021 - 2025	  	  	 	22.4	  	 	 	—  	  
	 LIBOR loans
	  	 	1.38	  	  	 	—  	  	  	 	2011	  	  	 	1.0	  	 	 	—  	  
	 Capital lease obligations
	  	 	7.85	  	  	 	—  	  	  	 	2011 - 2012	  	  	 	0.1	  	 	 	—  	  
	 GBPC

(issued and payable in Bahamian dollars)
	  				  				  				  				 			
	 LIBOR loans
	  	 	5.96	  	  	 	—  	  	  	 	2014	  	  	 	35.5	  	 	 	—  	  
	 Medium-term notes
	  	 	7.07	  	  	 	—  	  	  	 	2020 - 2032	  	  	 	49.7	  	 	 	—  	  
		  				  				  				  	 	3,037.8	  	 	 	2,442.7	  
	 Amount due within one year
	  				  				  				  	 	(12.7	) 	 	 	(108.1	) 
	 Unamortized debt financing costs
	  				  				  				  	 	(18.2	) 	 	 	(16.2	) 
		  				  				  				  	 	 	 	 	 	 	 
		  				  				  				  	$	3,006.9	  	 	$	2,318.4	  
		  				  				  				  	 	 	 	 	 	 	 

  

	(1)	Bankers acceptances, LIBOR loans and advances are drawn against operating credit facilities which mature in 2013. 


	(2)	Included in the medium-term notes above is an NSPI medium-term note of $40.0 million bearing interest at 8.50%, maturing in 2026, and is extendable until 2056 at the
option of the holders. 


	(3)	Short-term discount notes are backed by an operating credit facility which matures in 2013. 


	(4)	The interest on these USD variable rate bonds is fixed through the MPS interest rate swaps. The 1996 Series bonds of $13.6 million, due in 2021, are fixed at 4.42%,
while the 2000 Series bonds of $9.0 million, due in 2025, are fixed at 4.53%. 

 As at December 31, 2010,
long-term debt and obligations under a capital lease are due as follows: 
  

					
	 millions of dollars
	  	 	 
	 Year of Maturity
	  	 	 
	 Three year renewable
	  	$	530.3	  
	 2011
	  	 	12.7	  
	 2012
	  	 	83.6	  
	 2013
	  	 	305.0	  
	 2014
	  	 	304.9	  
	 2015
	  	 	74.7	  
	 Greater than 5 years
	  	 	1,726.6	  
		  	 	 	 
		  	$	3,037.8	  
		  	 	 	 


  
 46 











 

 

  


	25.	COMMON SHARES 


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

 

					
	 Issued and outstanding:
	  	Millions of shares	 
	 December 31, 2008
	  	 	112.21	  
	 Issued for cash under purchase plans
	  	 	0.45	  
	 Options exercised under senior management share option plan
	  	 	0.32	  
		  	 	 	 
	 December 31, 2009
	  	 	112.98	  
	 Issued for cash under purchase plans
	  	 	1.32	  
	 Options exercised under senior management share option plan
	  	 	0.32	  
		  	 	 	 
	 December 31, 2010
	  	 	114.62	  
		  	 	 	 

 As at December 31, 2010, there were 3.8 million (2009 – 4.1 million) common shares reserved
for issuance under the senior management common share option plan, and 0.5 million (2009 – 0.7 million) common shares reserved for issuance under the employee common share purchase plan. 

In February 2010, the Board of Directors approved a quarterly dividend increase to $0.2825 per common share effective May 3, 2010 and
in September 2010 approved a further increase to $0.3250 effective November 1, 2010, reflecting an increase on an annualized basis to $1.30 per common share. 
 DIVIDEND REINVESTMENT AND EMPLOYEE COMMON SHARE PURCHASE PLANS 
 The Company
has a Common Shareholder Dividend Reinvestment Plan, which provides an opportunity for shareholders to reinvest dividends and to make cash contributions for the purpose of purchasing common shares. The Company also has an Employee Common Share
Purchase Plan to which the Company and employees make cash contributions for the purpose of purchasing common shares and which allows reinvestment of dividends. 
 Effective September 25, 2009, Emera changed its Common Shareholders Dividend Reinvestment and Share Purchase Plan (“the Plan”) to provide for a discount of up to 5% from the average market
price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends under the Plan. The Board of Directors of Emera also decided that the discount would be 5% effective on and after the quarterly
dividend payment on November 16, 2009, to shareholders of record on November 2, 2009. 
 SHARE-BASED COMPENSATION
PLAN 
 Common Share Option Plan 
 The Company has a common share option plan that grants options to senior management of the Company for a maximum term of ten years. The option price for these shares is the closing market price of the
shares on the day before the option is granted. 
 All options granted to date are exercisable on a graduated basis with up to 25
percent of options exercisable on the first anniversary date and in further 25 percent increments on each of the second, third and fourth anniversaries of the grant. If an option is not exercised within ten years, it expires and the optionee loses
all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of shares to be optioned to any optionee shall not exceed five percent of the issued and
outstanding common shares on the date the option is granted. 
 If, before the expiry of an option in accordance with its terms,
the optionee ceases to be an eligible person due to retirement or termination for other than just cause, such option may, subject to the terms thereof and any other terms of the plan, be exercised at anytime within the 24 months following the date
the optionee retires, but in any case prior to the expiry of the option in accordance with its terms. 
 If, before the expiry of
an option in accordance with its terms, the optionee ceases to be an eligible person due to employment termination for just cause, resignation or death, such option may, subject to the terms thereof and any other terms of the plan, be exercised at
anytime within the six months following the date the optionee is terminated, resigns, or dies, as applicable, but in any case prior to the expiry of the option in accordance with its terms. 

  
 47 











 

 

  


																	
	 	  	2010	 	  	2009	 
	 	  	Shares under
option	 	 	Weighted
average
exercise
price	 	  	Shares under
option	 	 	Weighted
average
exercise
price	 
	 Outstanding, beginning of year
	  	 	2,082,150	  	 	$	19.99	  	  	 	2,197,725	  	 	$	19.39	  
	 Granted
	  	 	389,378	  	 	 	24.49	  	  	 	375,000	  	 	 	21.99	  
	 Exercised
	  	 	(325,450	) 	 	 	19.29	  	  	 	(322,075	) 	 	 	20.44	  
	 Expired
	  	 	—  	  	 	 	—  	  	  	 	(168,500	) 	 	 	17.34	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 
	 Outstanding, end of year
	  	 	2,146,078	  	 	$	21.02	  	  	 	2,082,150	  	 	$	19.99	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 
	 Exercisable, end of year
	  	 	1,256,550	  	 	$	19.72	  	  	 	1,216,175	  	 	$	19.08	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 

 The weighted average contractual life of options outstanding at December 31, 2010 is 6.7 years (2009
– 6.6 years). The range of exercise prices for the options outstanding at December 31, 2010 is $13.70 to $31.02 (2009 – $13.70 to $22.59). 
 The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for the grants: 

 

									
	 	  	2010	 	 	2009	 
	 Expected dividend yield
	  	 	4.55	% 	 	 	4.92	% 
	 Expected volatility
	  	 	14.00	% 	 	 	13.90	% 
	 Risk-free interest rate
	  	 	3.91	% 	 	 	4.00	% 
	 Expected life
	  	 	7 years	  	 	 	7 years	  
	 Weighted average grant date fair value
	  	$	2.25	  	 	$	1.49	  

 Deferred Share
Unit Plan and Performance Share Unit Plan 
 The Company has deferred share unit (“DSU”) and performance share unit
(“PSU”) (formerly restricted share unit) plans. 
 Under the Directors’ DSU plan, Directors of the Company may
elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value
equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns, or otherwise leaves the
Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. 
 Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the provision that for participants who
are subject to executive share ownership guidelines, a minimum of 50% of the value of their actual annual incentive award (25% in the first year of the program) will be payable in DSUs until the applicable guidelines are met. 

When incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the average fifty day year-end
stock closing share price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common
shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs
in the participant’s account by the then average fifty day stock closing share price of an Emera common share. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee (“MRCC”),
payments may be made in the form of actual shares. Any participant who is a United States taxpayer shall receive payment on the first business day following the six month anniversary of their termination. 

  
 48 











 

 

  

 Under the Directors’ DSU plan on or after January 1, 2010, a United States
taxpayer may elect one of several dates as the payment date for DSUs recorded in the participant’s account provided such elections are made in accordance with the deadlines under the plan for deferral elections and provided the payment dated
elected shall not be a date that falls after December 31 of the calendar year that begins immediately following the termination date. 
 In addition, special DSU awards may be made from time to time by the MRCC to selected executives and senior management to recognize singular achievements or to achieve certain corporate objectives.

 PSUs are granted annually for three-year overlapping performance cycles. The 2010 PSUs were granted based on the average of
Emera’s stock closing price for the fifty trading days prior to December 31 of the prior year and multiplied by a dividend ratio factor of 1.15 and a discount factor of 1.191 for share price appreciation. Dividend equivalents are awarded
and are used to purchase additional PSUs. The PSU value varies according to the Company’s common share market price and corporate performance. 
 PSUs vest at the end of the three-year cycle and will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and
will be pro-rated in the case of retirement, disability or death. 
  

													
	 	  	Employee
DSUs Outstanding	 	 	Employee
PSUs Outstanding	 	 	Director
DSUs Outstanding	 
	 December 31, 2008
	  	 	280,249	  	 	 	283,347	  	 	 	87,202	  
	 Granted
	  	 	59,792	  	 	 	132,916	  	 	 	33,257	  
	 Retirement, termination, disability & death
	  	 	(53,987	) 	 	 	(4,620	) 	 	 	—  	  
	 Payout
	  	 	—  	  	 	 	(73,925	) 	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 
	 December 31, 2009
	  	 	286,054	  	 	 	337,718	  	 	 	120,459	  
	 Granted
	  	 	52,267	  	 	 	112,573	  	 	 	35,605	  
	 Retirement, termination, disability & death
	  	 	—  	  	 	 	(4,370	) 	 	 	—  	  
	 Payout
	  	 	—  	  	 	 	(83,660	) 	 	 	(20,668	) 
		  	 	 	 	 	 	 	 	 	 	 	 
	 December 31, 2010
	  	 	338,321	  	 	 	362,261	  	 	 	135,396	  
		  	 	 	 	 	 	 	 	 	 	 	 

 The Company is using the fair value based method to measure the compensation expense related to its
share-based compensation and employee purchase plan and recognizes the expense over the vesting period on a straight-line basis. The DSU and PSU liabilities are marked-to-market at the end of each period based on the common share price at the end of
the period. For the year ended December 31, 2010, $12.2 million (2009 – $7.3 million) of compensation expense related to options granted, units issued, and shares purchased by employees was recognized in “Operating, maintenance and
general expense”. 
  

	26.	PREFERRED SHARES 


Authorized: 
 Unlimited number of First Preferred Shares, issuable in series. 
  

									
	 Issued and outstanding:
	  	Millions of Shares	 	  	Preferred share capital
millions of dollars	 
	 December 31, 2009
	  	 	—  	  	  	 	—  	  
	 Issuance of First Preferred Shares, Series A
	  	 	6.0	  	  	$	146.7	  
		  	 	 	 	  	 	 	 
	 December 31, 2010
	  	 	6.0	  	  	$	146.7	  
		  	 	 	 	  	 	 	 

 In June 2010, Emera issued six million 4.40% Cumulative Five-Year Rate Reset First Preferred Shares, Series A
(“First Preferred Shares, Series A”). The $150 million First Preferred Shares, Series A were issued at $25.00 per share for net after-tax and transaction costs proceeds of $146.7 million. 

As the First Preferred Shares, Series A are neither redeemable at the option of the shareholder nor have a mandatory redemption date, they
are classified as equity and the associated dividends will be deducted on the consolidated statements of earnings immediately before arriving at “Net earnings applicable to common shares” and will be shown on the consolidated statement of
equity as a deduction from retained earnings. 

  
 49 











 

 

  

 The First Preferred Shares, Series A are entitled to receive fixed cumulative preferred
cash dividends in the amount of $1.10 per share per annum for each year up to and including May 15, 2015. For each five-year period after this date, the holders of First Preferred Shares, Series A are entitled to receive reset fixed cumulative
preferred cash dividends. The reset annual dividends per share will be determined by multiplying the $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date
plus 1.84%. 
 The holders of First Preferred Shares, Series A will have the right, at their option, to convert their shares into
an equal number of Cumulative Floating Rate First Preferred Shares, Series B of the Company on August 15, 2015 and every five years thereafter. 
 The First Preferred Shares, Series B have the same characteristics as the Series A shares, with the exception of the calculation of the floating dividend rate for the Series B shares being the sum of the
T-bill rate plus 1.84%. 
 The holders of the First Preferred Shares, Series B will have the right, at their option, to convert
their shares into an equal number of Series A shares of the Company on August 15, 2020 and every five years thereafter. 

On August 15, 2015 and August 15, 2020 respectively and on August 15 every five years thereafter, the Company has the right
to redeem for cash the outstanding First Preferred Shares, Series A or B in whole or in part at a price of $25 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption. 

 

	27.	SUPPLEMENTAL CASH FLOW INFORMATION 

 The change in non-cash operating working capital consists of the following: 
  

				0,000,00				0,000,00	
	 millions of dollars
	  	2010	 	 	2009	 
	 Decrease (increase) in accounts receivable
	  	$	      25.7	  	 	$	(95.6	) 
	 Decrease (increase) in inventory
	  	 	12.4	  	 	 	(43.9	) 
	 Increase in prepaid expenses
	  	 	(2.0	) 	 	 	(8.4	) 
	 Decrease in contract receivable
	  	 	—  	  	 	 	56.4	  
	 Change in posted margin included in accounts receivable
	  	 	15.6	  	 	 	      56.9	  
	 Increase in other accounts payable and accrued charges
	  	 	65.1	  	 	 	7.1	  
	 Change in heavy fuel oil hedging balance in AOCI
	  	 	3.1	  	 	 	(4.3	) 
	 Change in income tax payable/receivable
	  	 	(39.6	) 	 	 	6.1	  
		  	 	 	 	 	 	 	 
		  	$	80.3	  	 	$	(25.7	) 
		  	 	 	 	 	 	 	 

  

	28.	CAPITAL MANAGEMENT 

 The
Company includes shareholders’ equity (excluding AOCI), short-term and long-term debt, preferred shares issued by subsidiary, non-controlling interest related to Bangor Hydro and ICDU, and cash and cash equivalents in the definition of capital
as follows: 
  

				0,000,00				0,000,00	
	 millions of dollars
	  	2010	 	 	2009	 
	 Shareholders’ equity, excluding AOCI
	  	$	1,938.3	  	 	$	1,692.6	  
	 Debt
	  	 	3,247.7	  	 	 	2,726.8	  
	 Preferred shares issued by subsidiary
	  	 	135.0	  	 	 	135.0	  
	 Non-controlling interest related to Bangor Hydro
	  	 	0.5	  	 	 	0.5	  
	 Non-controlling interest related to ICDU
	  	 	20.2	  	 	 	31.6	  
	 Cash and cash equivalents
	  	 	(9.4	) 	 	 	(21.8	) 
		  	 	 	 	 	 	 	 
		  	$	5,332.3	  	 	$	4,564.7	  
		  	 	 	 	 	 	 	 


  
 50 











 

 

  

 The Company’s objective when managing capital is to ensure sufficient liquidity
exists by maintaining access to capital markets in order to allow the Company to acquire, build and maintain its regulated electric utilities, low risk unregulated generation and energy infrastructure businesses. The Company has a strategy of
managing its capital structure through its various wholly-owned subsidiaries, while ensuring it is in compliance with its debt covenants. This strategy is managed by the Company through the issuance from time to time of common and preferred shares,
bonds, medium-term notes, or other indebtedness. 
 Each of the Company’s regulated utilities maintains a capital structure
based on the structure that is approved by each utility’s regulator and the capital structure is reflected in customer rates. 
 The Company’s short and long-term debt agreements provide that the Company’s consolidated debt cannot exceed 70% of the Company’s capitalization. 

 

	29.	FINANCIAL INSTRUMENTS 


The Company manages its exposure to foreign exchange, interest rate, and commodity risks in accordance with established risk management
policies and procedures. Derivative financial instruments, consisting mainly of foreign exchange forward contracts, interest caps and collars, and oil and gas options and swaps, are used to hedge cash flows. Derivative financial instruments,
consisting of foreign exchange forward contracts, are also used to hedge fair values. 
 Derivative financial instruments involve
credit and market risks. Credit risks arise from the possibility a counterparty will default on its contractual obligations and is limited to those contracts where the Company would incur a loss in replacing the instrument. 

Financial instruments include the following: 
  

																	
	 	  	2010	 	  	2009	 
	 millions of dollars
	  	Carrying
Amount	 	  	Fair
Value	 	  	Carrying
Amount	 	  	Fair
Value	 
	 Cash and cash equivalents
	  	$	9.4	  	  	$	9.4	  	  	$	21.8	  	  	$	21.8	  
	 Restricted cash
	  	 	59.6	  	  	 	59.6	  	  	 	1.0	  	  	 	1.0	  
	 Accounts receivable
	  	 	396.5	  	  	 	396.5	  	  	 	413.1	  	  	 	413.1	  
	 Derivatives held in a valid hedging relationship (current and long-term portion)
	  				  				  				  			
	 Cash flow hedges
	  	 	54.5	  	  	 	54.5	  	  	 	49.2	  	  	 	49.2	  
	 Fair value hedges
	  	 	—  	  	  	 	—  	  	  	 	8.0	  	  	 	8.0	  
	 Held-for-trading derivatives (current and long-term portion)
	  	 	37.4	  	  	 	37.4	  	  	 	43.8	  	  	 	43.8	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Total financial assets
	  	$	557.4	  	  	$	557.4	  	  	$	536.9	  	  	$	536.9	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Accounts payable and accrued charges
	  	$	399.6	  	  	$	399.6	  	  	$	305.9	  	  	$	305.9	  
	 Short-term debt
	  	 	228.1	  	  	 	228.1	  	  	 	300.3	  	  	 	300.3	  
	 Derivatives held in a valid hedging relationship (current and long-term portion)
	  				  				  				  			
	 Cash flow hedges
	  	 	29.9	  	  	 	29.9	  	  	 	86.7	  	  	 	86.7	  
	 Held-for-trading derivatives (current and long-term portion)
	  	 	49.1	  	  	 	49.1	  	  	 	34.4	  	  	 	34.4	  
	 Long-term debt (including current portion)
	  	 	3,019.6	  	  	 	3,434.5	  	  	 	2,426.5	  	  	 	2,661.3	  
	 Preferred shares issued by a subsidiary
	  	 	135.0	  	  	 	152.3	  	  	 	135.0	  	  	 	151.2	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Total financial liabilities
	  	$	3,861.3	  	  	$	4,293.5	  	  	$	3,288.8	  	  	$	3,539.8	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 


  
 51 











 

 

  

 Fair value hierarchy 

A fair value hierarchy is used to categorize valuation techniques used in the determination of fair value. Quoted market prices are Level
1, internal models using observable market information as inputs are Level 2, and internal models without observable market information as inputs are Level 3. 
 The fair value hierarchy of financial assets and liabilities accounted for at fair value at December 31, 2010 are as follows: 

 

																	
	 millions of dollars
	  	Level 1	 	 	Level 2	 	  	Level 3	 	  	Total	 
	 Financial assets:
	  				 				  				  			
	 Cash and cash equivalents
	  	$	9.4	  	 	 	—  	  	  	 	—  	  	  	$	9.4	  
	 Restricted cash
	  	 	59.6	  	 	 	—  	  	  	 	—  	  	  	 	59.6	  
	 Derivatives in a valid hedging relationship (current and long-term portion)
	  				 				  				  			
	 Cash flow hedges
	  	 	41.7	  	 	$	12.8	  	  	 	—  	  	  	 	54.5	  
	 Held-for-trading derivatives (current and long-term portion)
	  	 	1.5	  	 	 	14.6	  	  	$	21.3	  	  	 	37.4	  
		  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 
	 Total financial assets
	  	$	112.2	  	 	$	27.4	  	  	$	21.3	  	  	$	160.9	  
		  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 
	 Financial liabilities:
	  				 				  				  			
	 Derivatives in a valid hedging relationship (current and long-term portion)
	  				 				  				  			
	 Cash flow hedges
	  	$	15.8	  	 	$	14.1	  	  	 	—  	  	  	$	29.9	  
	 Held-for-trading derivatives (current and long-term portion)
	  	 	(0.4	) 	 	 	10.5	  	  	$	39.0	  	  	 	49.1	  
	 Preferred shares issued by subsidiary
	  	 	—  	  	 	 	152.3	  	  	 	—  	  	  	 	152.3	  
		  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 
	 Total financial liabilities
	  	$	15.4	  	 	$	176.9	  	  	$	39.0	  	  	$	231.3	  
		  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 

 Changes in the fair value of financial assets classified as Level 3 in fair value hierarchy of $108.5 million
during the year ended December 31, 2010, were as follows: 
  

																	
	 millions of dollars
	  	Accounts
receivable	 	 	Derivatives in a valid
hedging relationship
– Cash flow hedge	 	 	Held-for-
trading
derivatives	 	 	Total	 
	 Balance at January 1, 2010
	  	$	82.1	  	 	$	1.5	  	 	$	46.2	  	 	$	129.8	  
	 Total (loss) gain realized and unrealized
	  				 				 				 			
	 Included in earnings
	  	 	(5.8	) 	 	 	—  	  	 	 	(22.4	) 	 	 	(28.2	) 
	 Included in AOCI
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Purchases, issuances, settlements
	  	 	(76.3	) 	 	 	(1.5	) 	 	 	(0.7	) 	 	 	(78.5	) 
	 Transfer to Level 2
	  	 	—  	  	 	 	—  	  	 	 	(1.9	) 	 	 	(1.9	) 
	 Transfer to Held-for-trading
	  	 	—  	  	 	 	—  	  	 	 	0.1	  	 	 	0.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance at December 31, 2010
	  	 	—  	  	 	 	—  	  	 	$	21.3	  	 	$	21.3	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 Changes in the fair value of financial liabilities classified as Level 3 in fair value hierarchy of $7.8
million during the year ended December 31, 2010, were as follows: 
  

													
	 millions of dollars
	  	Derivatives in a valid
hedging relationship
– Cash flow hedge	 	 	Held-for-
trading
derivatives	 	 	Total	 
	 Balance at January 1, 2010
	  	$	(2.1	) 	 	$	(29.1	) 	 	$	(31.2	) 
	 Total (loss) gain realized and unrealized
	  				 				 			
	 Included in earnings
	  	 	(0.8	) 	 	 	2.2	  	 	 	1.4	  
	 Included in AOCI
	  	 	11.3	  	 	 	—  	  	 	 	11.3	  
	 Purchases, issuances, settlements
	  	 	(28.3	) 	 	 	6.5	  	 	 	(21.8	) 
	 Transfer from Level 2
	  	 	—  	  	 	 	1.3	  	 	 	1.3	  
	 Transfer to Held-for-trading
	  	 	19.9	  	 	 	(19.9	) 	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 
	 Balance at December 31, 2010
	  	 	—  	  	 	$	(39.0	) 	 	$	(39.0	) 
		  	 	 	 	 	 	 	 	 	 	 	 


  
 52 











 

 

  

 ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE AND ACCRUED CHARGES 

The carrying value of accounts receivable, accounts payable and accrued charges is a reasonable approximation of fair value. Losses
included in earnings and recorded in “Operating, maintenance and general expenses” are $3.8 million (2009 – $6.1 million). 
 The allowance for doubtful accounts was $5.6 million as at January 1, 2010 (2009 – $4.5 million) and $6.9 million as at December 31, 2010 (2009 – $5.6 million). Changes in the
allowance were due to changes in the provision related to specific customers and to changes in mix and volume of accounts receivable. 
 PREFERRED SHARES ISSUED BY A SUBSIDIARY, LONG-TERM DEBT AND SHORT-TERM DEBT 

The fair value of preferred shares issued by a subsidiary is based on market rates. 

The fair value of the Company’s long-term and short-term debt is estimated based on the quoted market prices for the same or similar
issues, or on the current rates offered to the Company, for debt of the same remaining maturities. 
 DERIVATIVES IN VALID
HEDGING RELATIONSHIPS 
 The fair value of derivative financial instruments is estimated by obtaining prevailing market rates
from investment dealers. 
 Gains and losses included in net earnings with respect to derivatives in valid hedging relationships
include the following: 
  

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Financing income increase
	  	$	7.7	  	 	$	2.8	  
	 Fuel and purchased power increase
	  	 	(73.3	) 	 	 	(46.3	) 
	 Financing charges decrease
	  	 	1.8	  	 	$	6.9	  
		  	 	 	 	 	 	 	 
	 Total losses
	  	$	(63.8	) 	 	$	(36.6	) 
		  	 	 	 	 	 	 	 

 The Company recognized total ineffectiveness in net earnings related to cash flow hedges as follows:

  

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Fuel and purchased power increase
	  	$	(1.6	) 	 	$	(14.2	) 
	 Financing charges increase
	  	 	(0.1	) 	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Total losses
	  	$	(1.7	) 	 	$	(14.2	) 
		  	 	 	 	 	 	 	 

 The Company recognized total ineffectiveness in net earnings related to fair value hedges as follows:

  

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Financing charges increase
	  	$	(0.2	) 	 	$	(0.5	) 
		  	 	 	 	 	 	 	 
	 Total losses
	  	$	(0.2	) 	 	$	(0.5	) 
		  	 	 	 	 	 	 	 

 The Company expects to reclassify $4.7 million of losses currently included in AOCI to net earnings over the
next 12 months related to hedged items realized in net earnings. 
 Interest Rates 

The Company maintains a portfolio of debt instruments which includes short-term instruments and long-term instruments with staggered
maturities. The Company uses diversification as a risk management strategy and deals with several counterparties so as to mitigate concentration risk. 
 The Company may enter into interest rate hedging contracts to limit exposure to fluctuations in floating and fixed interest rates on its short-term and long-term debt. 

The Company has two interest rate hedging contracts outstanding as at December 31, 2010. These interest rate hedging contracts are
used to fix the variable interest rates on the two issues of Maine Public Utilities Financing Bank bonds at MPS. MPS’s obligation under these bonds totals $22.6 million USD, $13.6 million USD of which is fixed at 4.42%, and $9.0 million USD of
which is fixed at 4.53%. 

  
 53 











 

 

  

 Commodity Prices 

A substantial amount of NSPI’s fuel supply comes from international suppliers and is subject to commodity price risk. As part of its
fuel management strategy, NSPI manages exposure to commodity price risk utilizing financial instruments providing fixed or maximum prices. 
 The Company enters into natural gas swap contracts to limit exposure to fluctuations in natural gas prices. As at December 31, 2010, the Company had hedged approximately 87% of all natural gas
purchases and sales associated with its forecasted natural gas burn and resale for 2011, and 35% for 2012. 
 The Company enters
into oil swap contracts to limit exposure to fluctuations in world prices of heavy fuel oil. For 2011 and 2012, NSPI currently does not have heavy fuel oil hedging requirements. 

The Company enters into solid fuel swap contracts to limit exposure to fluctuations in world prices of solid fuel. As at December 31,
2010, the Company had hedged approximately 77% of all solid fuel purchases for 2011, 39% for 2012, 24% for 2013 and 9% for 2014. 

The Company enters into power swaps to limit exposure to fluctuations in power prices. At December 31, 2010, the Company has hedged
103% of 2011 requirements, 95% of 2012 requirements, 95% of 2013 requirements and approximately 95% of the requirements for 2014. 
 Foreign Exchange 
 The Company enters into foreign exchange forward and swap
contracts to limit exposure on foreign currency transactions such as fuel purchases, revenue streams and capital expenditures. 

The risk due to fluctuation of the CAD against the USD for fuel purchases in NSPI is measured and managed. In 2011, NSPI expects
approximately 60% of its anticipated net fuel costs to be denominated in USD. USD from sales of surplus natural gas will provide a natural hedge against a portion of USD fuel costs. Forward contracts to buy $225.5 million USD were in place at a
weighted average rate of $0.99, representing 70% of 2011 anticipated USD requirements. Forward contracts to buy $443.0 million USD in 2012 through 2015 at a weighted average rate of $1.03 were in place at December 31, 2010. These contracts
cover 31% of anticipated USD requirements in these years. As at December 31, 2010, there were no fuel-related foreign exchange swaps outstanding. 
 NSPI may use foreign exchange forward contracts to hedge the currency risk for capital projects and receivables denominated in foreign currencies. Forward contracts to buy €1.8 million are in
place at a weighted average rate of $1.56 (versus CAD) for capital projects in 2011. 
 Brunswick Pipeline uses forward contracts
to hedge the currency risk associated with revenue streams denominated in foreign currencies. Forward contracts to sell $52 million USD were in place in 2011 at an average rate of $1.07 and sell $63 million USD in 2012 through 2015 at a weighted
average rate of $1.07. These contracts cover 91% of anticipated USD revenue inflows in 2011 and 27% of anticipated USD revenue inflows in 2012 through 2015. 
 HELD-FOR-TRADING DERIVATIVES 
 Derivatives included in held-for-trading
assets and liabilities are required to be included in this classification in accordance with CGAAP. The Company has not designated any financial instruments to be included in the held-for-trading category. 

The fair value of derivatives is estimated by obtaining prevailing market rates from investment dealers. The Company has a derivative, a
power swap, where no observable market exists, therefore modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices as applicable, to interpolate certain prices. 

  
 54 











 

 

  

 The Company has recognized the following realized and unrealized gains and losses with
respect to HFT derivatives in earnings: 
  

									
	 millions of dollars
	  	2010	 	 	2009	 
	 Electric revenue
	  	$	4.4	  	 	$	0.6	  
	 Other revenue
	  	 	1.8	  	 	 	(5.7	) 
	 Fuel and purchased power
	  	 	(1.3	) 	 	 	12.4	  
	 Financing charges
	  	 	—  	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Held-for-trading derivative gains
	  	$	4.9	  	 	$	7.3	  
		  	 	 	 	 	 	 	 

 Energy marketing assets and liabilities 

On December 31, 2010, the Company held derivative financial and commodity instruments within its trading group. 

Natural gas contracts 
 Nova Scotia Power has contracts for the purchase and sale of natural gas at TUC that are considered HFT derivatives and accordingly are recognized on the balance sheet at fair value. This reflects
NSPI’s history of buying and reselling any natural gas not used in the production of electricity at TUC. 
 Derivatives
not in valid hedging relationships 
 On December 31, 2010, the Company held natural gas, power and oil derivatives,
which were not in valid hedging relationships. This includes a certain swap in place to economically hedge the power necessary to produce the energy requirements of the long-term power supply agreement with the Long Island Power Authority, which is
marked-to-market through earnings as it does not meet the stringent accounting requirements of hedge accounting. 
 RISK
MANAGEMENT 
 Market Risk 
 The Company uses value-at-risk limits to manage its exposure to energy commodities from commercial activities on behalf of third parties such as the purchase and sale of natural gas and electricity, and
related energy management services. These commercial activities are monitored on a daily basis by the Company’s risk management group such that the value-at-risk is not material. 

Market risks associated with derivatives, which includes the Company’s hedges and HFT derivatives, are related to movement in
commodity prices and foreign exchange rates. Market risk associated with short-term debt is related to movement in interest rates. 
 As at December 31, 2010, the Company determined that market risk exposure associated with its financial instruments would affect the Company’s financial results as follows: 

 

									
	 millions of dollars
	  	Net earnings
increase
(decrease)	 	 	AOCI
increase
(decrease)	 
	 $1 per one million British Thermal Unit increase in the price of natural gas*
	  	$	4.4	  	 	 	—  	  
	 $5 per barrel increase in the price of heavy fuel oil
	  	 	—  	  	 	 	—  	  
	 $15 per metric tonne increase in the price of coal
	  	 	—  	  	 	$	29.8	  
	 $0.01 decrease in the strength of the Canadian relative to the US dollar
	  	 	—  	  	 	 	6.1	  
	 100 basis point increase in the central bank interest rates
	  	 	0.1	  	 	 	—  	  
	 $1 per megawatt hour increase in the price of power
	  	 	(0.1	) 	 	 	0.8	  

  

	*	NSPI fuel costs are recoverable through the FAM, thus the above amount is the impact on earnings not related to NSPI. 


The above table illustrates the effect on the Company’s financial results due to a certain fixed price change on the entire portfolio
of financial instruments as at the end of the quarter. The results disclosed in the above table cannot be extrapolated linearly to determine the effect on the Company’s financial results due to varying price changes. 

  
 55 











 

 

  

 Interest Rate Risk 

Emera manages interest rate risk through a combination of fixed and floating borrowing and a hedging program. Floating-rate debt is
estimated to represent approximately 20% of total debt in 2011 (2010 – 24%). The company had two interest rate hedging contracts outstanding as at December 31, 2010 (2009 – nil), fixing the variable interest rates on $22.6 million USD
of Maine Public Utilities Financing Bank bonds at MPS. 
 Credit risk 

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit assessments are conducted on all new
customers and deposits are requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis. With respect to customers other than electric customers, counterparty
creditworthiness is assessed through reports of credit rating agencies or other available financial information. 
 As at
December 31, 2010, the maximum exposure the Company has to credit risk is $488.4 million, which includes accounts receivable, assets related to derivatives in a valid hedging relationship, and held-for-trading derivatives. 

The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and
interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits
from electric customers. The total cash deposits and letters of credit on hand as at December 31, 2010, was $17.5 million (2009 – $30.3 million), which mitigates the Company’s maximum credit risk exposure. The Company uses the cash as
payment for the amount receivable or returns the cash deposit to the counterparty where the credit limit is no longer exceeded or where the customer is no longer considered a high risk account. 

The Company generally considers the credit quality of financial assets that are neither past due nor impaired to be good. The Company
monitors collection performance to ensure payments are received on a timely basis. 
 The Company does not have any financial
assets that would be considered to be impaired. 
 As at December 31, 2010, the Company had $32.3 million (2009 – $34.6
million) in financial assets considered to be past due, which have been outstanding for an average of 70 days. The fair value of these financial assets is $29.8 million (2009 – $30.8 million), the difference of which is included in the
allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric revenue. 

  
 56 











 

 

  

 Concentration risk 

The Company’s concentration of risks as at December 31, 2010, is as follows: 

 

									
	 	  	millions of
dollars	 	  	% of total
exposure	 
	 Accounts receivable
	  				  			
	 Regulated utilities
	  				  			
	 Residential
	  	$	121.2	  	  	 	24.8	% 
	 Commercial
	  	 	62.8	  	  	 	12.9	  
	 Industrial
	  	 	38.8	  	  	 	8.0	  
	 Other
	  	 	16.2	  	  	 	3.3	  
		  	 	 	 	  	 	 	 
		  	 	239.0	  	  	 	49.0	  
		  	 	 	 	  	 	 	 
	 Trading group
	  				  			
	 Credit rating of A- or above
	  	 	—  	  	  	 	—  	  
	 Credit rating of BBB- to BBB+
	  	 	10.2	  	  	 	2.0	  
	 Not rated
	  	 	28.1	  	  	 	5.8	  
	 Fully collateralized
	  	 	82.4	  	  	 	16.9	  
		  	 	 	 	  	 	 	 
		  	 	120.7	  	  	 	24.7	  
		  	 	 	 	  	 	 	 
	 Other accounts receivable
	  	 	36.8	  	  	 	7.5	  
		  	 	 	 	  	 	 	 
		  	 	396.5	  	  	 	81.2	  
		  	 	 	 	  	 	 	 
	 Derivatives (in a valid hedging relationship and held-for-trading; current and long-term portions)
	  				  			
	 Credit rating of A- or above
	  	 	56.5	  	  	 	11.6	  
	 Credit rating of BBB- to BBB+
	  	 	11.8	  	  	 	2.4	  
	 Not rated
	  	 	23.6	  	  	 	4.8	  
		  	 	 	 	  	 	 	 
		  	 	91.9	  	  	 	18.8	  
		  	 	 	 	  	 	 	 
		  	 	488.4	  	  	 	100.0	% 
		  	 	 	 	  	 	 	 

 Liquidity risk 
 Liquidity risk encompasses the risk that the Company cannot meet its financial obligations. 
 Emera’s main sources of liquidity are its cash flows from operations, short-term and long-term debt. Funds are primarily used to finance capital transactions. Some of these instruments are subject to
market risks that the Company may hedge with interest rate swaps, caps, floors, futures and options. 
 Emera manages its
liquidity by holding adequate volumes of liquid assets and maintaining credit facilities in addition to the cash flow generated by its operating businesses. The liquid assets consist of cash and cash equivalents. 

The Company’s financial instrument liabilities mature as follows: 

 

																													
	 	  	3 year
renewable (1)	 	  	2011	 	  	2012	 	  	2013	 	  	2014	 	  	>2014	 	  	Total	 
	 Accounts payable and accrued charges
	  	 	—  	  	  	$	399.6	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	$	399.6	  
	 Short-term debt
	  	 	—  	  	  	 	228.1	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	228.1	  
	 Long-term debt
	  	$	530.3	  	  	 	12.7	  	  	$	83.6	  	  	$	305.0	  	  	$	304.9	  	  	$	1,801.3	  	  	 	3,037.8	  
	 Preferred shares issued by subsidiary
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	135.0	  	  	 	135.0	  
	 Derivatives held in a valid hedging relationship
	  				  				  				  				  				  				  			
	 Cash flow hedge
	  	 	—  	  	  	 	8.6	  	  	 	3.7	  	  	 	8.9	  	  	 	3.4	  	  	 	5.3	  	  	 	29.9	  
	 Held-for-trading derivatives
	  	 	—  	  	  	 	30.7	  	  	 	6.8	  	  	 	3.9	  	  	 	3.1	  	  	 	4.6	  	  	 	49.1	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Total financial liabilities
	  	$	530.3	  	  	$	679.7	  	  	$	94.1	  	  	$	317.8	  	  	$	311.4	  	  	$	1,946.2	  	  	$	3,879.5	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 

  

	(1)	Bankers acceptances, LIBOR loans and advances are drawn against operating credit facilities which mature in 2013. 


  
 57 











 

 

  

 The Company has available the following credit facilities as at December 31, 2010,
for the management of liquidity risk: 
  

															
	 millions of dollars
	  	 Maturity
	  	Credit Line
Committed	 	  	Utilized	 	  	Undrawn and
Available	 
	 Emera – Operating and acquisition credit facility
	  	June 2013 – Revolver	  	$	600	  	  	$	406	  	  	$	194	  
	 NSPI – Operating credit facility
	  	June 2013 – Revolver	  	 	600	  	  	 	289	  	  	 	311	  
	 Bangor Hydro – in USD – Operating credit facility
	  	September 2013 – Revolver	  	 	80	  	  	 	42	  	  	 	38	  
	 Other – in USD – Operating credit facilities
	  	Various	  	 	18	  	  	 	3	  	  	 	15	  

 AVAILABLE-FOR-SALE
INVESTMENTS 
 Available-for-sale investments include the Company’s investment in OpenHydro Group Limited
(“OpenHydro”) and Algonquin Power & Utilities Corp. The investments are recognized at their cost of $47.0 million. The fair value of these investments have not been recognized or disclosed because the shares and subscription
receipts are not actively traded in an open market. The Company does not intend to dispose of the investment in OpenHydro in the near term. The market for any disposition of OpenHydro shares would be with an existing shareholder or a new private
investor. 
  

	30.	RELATED PARTY TRANSACTIONS 


In the ordinary course of business, Emera purchased natural gas transportation capacity totaling $55.1 million (2009 – $47.4 million)
during the year ended December 31, 2010, from the Maritimes & Northeast Pipeline, an investment under significant influence of the Company. The amount is recognized in “Fuel for generation and purchased power” or netted
against energy marketing margin in “Other revenue”, and is measured at the exchange amount. At December 31, 2010, the amount payable to the related party is $3.9 million (2009 – $4.6 million), is non-interest bearing and is under
normal credit terms. 
  

	31.	CONTINGENCIES 

 A number
of individuals who live in proximity to NSPI’s Trenton generating station have filed a statement of claim against NSPI in respect of emissions from the operation of the plant for the period 2001 forward. The Company has filed a defence to
the claim. The plaintiffs claim unspecified damages as a result of interference with enjoyment of, or damage to, their property and adverse health effects they allege were caused by such emissions. The outcome, and therefore an estimate of
any contingent loss, of this litigation are not determinable.
 Bangor Hydro has a potential liability to Great Lake Hydro
America LLC for headwater benefits on the Penobscot River in connection with hydro assets sold to PPL Generation, LLC in 1999. On May 25, 2010, a FERC Administrative Law Judge issued an initial decision ruling that a May 7, 1999 Release
was a valid and enforceable release of liability for headwater benefits received by Bangor Hydro prior to May 7, 1999. The initial decision became final on July 7, 2010, by operation of FERC rules. Any liability of Bangor Hydro
for pre-May 1999 headwater benefits that may not be covered by the Release and for the period after the Release, but prior to the PPL sale, is immaterial. 
 In addition, the Company may, from time to time, be involved in legal proceedings, claims and litigations that arise in the ordinary course of business which the Company believes would not reasonably be
expected to have a material adverse effect on the financial condition of the Company. 

  
 58 











 

 

  


	32.	COMMITMENTS 

 In addition
to commitments outlined elsewhere in these notes, the Company had the following significant commitments at December 31, 2010: 
 Emera 
  

	 	•	 	 The Company has a commitment to purchase approximately 43,000 mmbtu per day of transportation capacity on the US portion of the Maritimes &
Northeast Pipeline, a related party, for the next two years, at an approximate average cost of $9 million per year. 


  

	 	•	 	 The Company has a commitment to purchase 10,000 mmbtu per day of transportation capacity on the US portion of the Maritimes & Northeast
Pipeline, a related party, from Q2 2013 until Q1 2016, at an approximate average cost of $2 million per year. 


  

	 	•	 	 Bayside has a commitment to purchase approximately 36,500 mmbtu of natural gas per day until November 2015 and an additional 7,000 mmbtu per day until
December 2012. 


  

	 	•	 	 Bayside has a commitment to March 31, 2021 to supply approximately 900 GWh of electricity annually for the months of November through March.



  

	 	•	 	 Bayside has a commitment to purchase approximately 43,500 mmbtu per day of transportation capacity on the Canadian portion of the Maritimes &
Northeast Pipeline, a related party, until 2015, at an approximate average cost of $12 million per year. 



NSPI 
  

	 	•	 	 NSPI has an annual requirement to purchase approximately 650 GWh of electricity from independent power producers over varying contract lengths up to 40
years. 


  

	 	•	 	 NSPI has requirements to purchase approximately 15,000 mmbtu of natural gas per day for 22 months; an average of 13,000 mmbtu per day for 28 months;
14,000 mmbtu per day for 10 months and 20,000 mmbtu for two years starting in November 2011. 


  

	 	•	 	 NSPI has commitments to purchase 4,000 mmbtu per day of transportation capacity on the Maritimes and Northeast Pipeline, a related party, for 10
months, 15,000 mmbtu for 22 months, and an average of 13,000 mmbtu for 28 months. These have an approximate cost of $17.6 million through 2013. 


  

	 	•	 	 NSPI has the responsibility for managing a portfolio of approximately $1.0 billion of defeasance securities held in trust. The defeasance securities
must provide the principal and interest payment streams of the related defeased debt. Approximately 73% or $726 million of the defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the
portfolio. 


  

	 	•	 	 NSPI has a commitment to a third party for the unloading and transportation of solid fuel for ten years beginning in late 2002 at an approximate cost
of $16.0 million per year. 


  

	 	•	 	 NSPI has commitments to third parties for the handling and transportation of solid fuel for $7 million in 2011 and $4 million per year from 2012 to
2014. 


  

	 	•	 	 NSPI has commitments to third parties for 2011 to 2014, to purchase and transport 3.8 million metric tons (“mts”) of import coal,
1.7 million mts of domestic coal and 3.2 million mts of marine freight. 


  

	 	•	 	 NSPI has commitments to third parties for construction on capital project in 2011 and 2012 at an approximate cost of $91 million and to purchase other
goods and services in 2011 and 2012 at an approximate cost of $19 million. 


 Bangor Hydro 

 

	 	•	 	 Bangor Hydro has various contract commitments to purchase annually, net of resale revenues, approximately $10 million USD to $12 million USD of
electricity for the period from 2011 to 2018 from independent power producers. These commitments are reduced to less than $2 million USD each year from 2019 to 2026. 



  
 59 











 

 

  


	33.	GUARANTEES 

 Emera had the
following guarantees at December 31, 2010: 
  

	 	•	 	 The Company issued letters of credit totaling $55.7 million, which generally expire annually unless renewed. These letters of credit secure payment to
various vendors, the obligations of NSPI and Bangor Hydro under their unfunded pension plans, and in the case of MPS, secure the Maine Public Utility Financing Bank bonds principal and interest. 



 

	 	•	 	 NSPI has provided a guarantee for the indebtedness of a third party, up to a maximum of $23.5 million, related to future purchased power. NSPI holds a
security interest in the assets of the third party. 


  

	34.	ECONOMIC DEPENDENCE 

 One
of the company’s subsidiaries, Brunswick Pipeline, has an agreement through 2034 for the sale of its product to one customer. For the year ended December 31, 2010, this customer accounted for 13.7% of the consolidated net earnings (2009
– 8.0%). 
  

	35.	SUBSEQUENT EVENTS 

 On
January 1, 2011, Emera and APUC announced the closing of their acquisition of the California-based electricity distribution and related generation assets of NV Energy, Inc. Total consideration for this transaction is $131.8 million USD,
subject to final adjustments. APUC and Emera own respectively a 50.001% and 49.999% interest in California Pacific Utility Ventures, LLC (“CPUV”), which wholly-owns the California-based assets. Also, as an element of the transaction, Emera
exchanged certain previously announced subscription receipts into 8.523 million APUC common shares. 
 On January 25,
2011, subsequent to the offer made on December 20, 2010 to purchase all issued and outstanding common shares from LPH shareholders, Emera purchased 7.2 million shares of LPH at a cash price per share of $25.70 Barbadian dollars
representing an additional interest of 41.6%. With this additional investment of $91.9 million CAD, Emera became the majority shareholder of LPH, with a total interest of 79.9%. 

 

	36.	COMPARATIVE INFORMATION 


Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted for 2010. 


  
 60 











 

 

  

 OPERATING STATISTICS (Unaudited) 
 FIVE-YEAR SUMMARY 
  

																					
	 Year Ended December 31
	  	2010	 	  	2009	 	  	2008	 	  	2007	 	  	2006	 
	 Electric energy sales (GWh)
	  				  				  				  				  			
	 Residential
	  	 	4,738.2	  	  	 	4,819.2	  	  	 	4,769.6	  	  	 	4,738.5	  	  	 	4,516.0	  
	 Commercial
	  	 	5,584.4	  	  	 	3,694.4	  	  	 	3,721.1	  	  	 	3,768.5	  	  	 	3,621.1	  
	 Industrial
	  	 	4,268.2	  	  	 	3,985.3	  	  	 	4,491.5	  	  	 	4,568.4	  	  	 	3,246.7	  
	 Other
	  	 	1,117.1	  	  	 	1,636.9	  	  	 	1,115.2	  	  	 	1,320.4	  	  	 	1,550.8	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Total electric energy sales
	  	 	15,707.9	  	  	 	14,135.8	  	  	 	14,097.4	  	  	 	14,395.8	  	  	 	12,934.6	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Sources of energy (GWh)
	  				  				  				  				  			
	 Thermal  – coal
	  	 	7,838.7	  	  	 	8,177.3	  	  	 	9,008.9	  	  	 	9,561.4	  	  	 	9,128.1	  
	 – oil
	  	 	36.1	  	  	 	306.9	  	  	 	340.7	  	  	 	516.6	  	  	 	431.9	  
	 – natural gas
	  	 	4,183.0	  	  	 	2,141.4	  	  	 	1,257.9	  	  	 	1,057.1	  	  	 	390.3	  
	 Hydro
	  	 	1,023.5	  	  	 	1,101.4	  	  	 	1,102.3	  	  	 	936.8	  	  	 	1,034.7	  
	 Wind
	  	 	25.3	  	  	 	1.8	  	  	 	2.4	  	  	 	2.4	  	  	 	2.4	  
	 Purchases
	  	 	3,633.4	  	  	 	3,444.1	  	  	 	3,493.2	  	  	 	3,534.7	  	  	 	3,144.7	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Total generation and purchases
	  	 	16,740.0	  	  	 	15,172.9	  	  	 	15,205.4	  	  	 	15,609.0	  	  	 	14,132.1	  
	 Losses and internal use
	  	 	1,032.1	  	  	 	1,037.1	  	  	 	1,108.0	  	  	 	1,213.2	  	  	 	1,197.5	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Total electric energy sold
	  	 	15,707.9	  	  	 	14,135.8	  	  	 	14,097.4	  	  	 	14,395.8	  	  	 	12,934.6	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Electric customers
	  				  				  				  				  			
	 Residential
	  	 	588,935	  	  	 	539,333	  	  	 	535,494	  	  	 	530,955	  	  	 	526,014	  
	 Commercial
	  	 	61,620	  	  	 	51,768	  	  	 	54,461	  	  	 	51,083	  	  	 	50,780	  
	 Industrial
	  	 	2,558	  	  	 	2,543	  	  	 	2,541	  	  	 	2,543	  	  	 	2,526	  
	 Other
	  	 	9,422	  	  	 	9,155	  	  	 	9,064	  	  	 	9,574	  	  	 	9,378	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Total electric customers
	  	 	662,535	  	  	 	602,799	  	  	 	601,560	  	  	 	594,155	  	  	 	588,698	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Capacity
	  				  				  				  				  			
	 Generating nameplate capacity (MW)
	  				  				  				  				  			
	 Coal fired
	  	 	1,243	  	  	 	1,243	  	  	 	1,243	  	  	 	1,243	  	  	 	1,243	  
	 Dual fired
	  	 	350	  	  	 	350	  	  	 	365	  	  	 	350	  	  	 	350	  
	 Gas turbines
	  	 	614	  	  	 	579	  	  	 	304	  	  	 	319	  	  	 	323	  
	 Hydroelectric
	  	 	995	  	  	 	995	  	  	 	1,005	  	  	 	1,005	  	  	 	1,005	  
	 Wind turbines
	  	 	76	  	  	 	1	  	  	 	1	  	  	 	1	  	  	 	1	  
	 Diesel
	  	 	46	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
	 Steam
	  	 	51	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
	 Independent power producers
	  	 	347	  	  	 	172	  	  	 	120	  	  	 	120	  	  	 	120	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
		  	 	3,722	  	  	 	3,340	  	  	 	3,038	  	  	 	3,038	  	  	 	3,042	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Total number of employees
	  	 	2,972	  	  	 	2,350	  	  	 	2,215	  	  	 	2,194	  	  	 	2,149	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 km of transmission lines
	  	 	6,700	  	  	 	6,300	  	  	 	6,100	  	  	 	6,200	  	  	 	6,100	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 km of distribution lines
	  	 	40,900	  	  	 	33,800	  	  	 	33,000	  	  	 	32,000	  	  	 	32,000	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 


  
 61 











 

 

  

 FIVE YEAR SUMMARY (Unaudited) 

 

																					
	 Year Ended December 31 (millions of dollars)
	  	2010	 	 	2009	 	 	2008	 	 	2007	 	 	2006	 
	 Statements of Earnings Information
	  				 				 				 				 			
	 Revenue
	  	$	1,553.7	  	 	$	1,483.5	  	 	$	1,331.9	  	 	$	1,339.5	  	 	$	1,166.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Cost of operations
	  				 				 				 				 			
	 Fuel for generation and purchased power
	  	 	718.7	  	 	 	583.5	  	 	 	525.1	  	 	 	494.5	  	 	 	347.7	  
	 Fuel adjustment
	  	 	(99.0	) 	 	 	8.5	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Operating, maintenance and general
	  	 	336.1	  	 	 	294.4	  	 	 	266.8	  	 	 	264.8	  	 	 	255.6	  
	 Provincial, state and municipal taxes
	  	 	49.1	  	 	 	49.9	  	 	 	49.4	  	 	 	47.5	  	 	 	48.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Depreciation and amortization
	  	 	173.6	  	 	 	164.9	  	 	 	151.3	  	 	 	149.3	  	 	 	145.2	  
	 Regulatory amortization
	  	 	41.3	  	 	 	35.7	  	 	 	28.5	  	 	 	31.4	  	 	 	22.8	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
		  	 	1,219.8	  	 	 	1,136.9	  	 	 	1,021.1	  	 	 	987.5	  	 	 	819.3	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
		  	 	333.9	  	 	 	346.6	  	 	 	310.8	  	 	 	352.0	  	 	 	346.7	  
	 Equity earnings
	  	 	13.6	  	 	 	14.0	  	 	 	15.2	  	 	 	12.8	  	 	 	4.9	  
	 Other income
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	8.9	  
	 Financing charges
	  	 	168.4	  	 	 	135.3	  	 	 	123.2	  	 	 	133.2	  	 	 	148.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Earnings before income taxes
	  	 	179.1	  	 	 	225.3	  	 	 	202.8	  	 	 	231.6	  	 	 	212.4	  
	 Income taxes
	  	 	(12.8	) 	 	 	48.9	  	 	 	58.1	  	 	 	80.3	  	 	 	86.6	  
	 Net earnings before non-controlling interest
	  	 	191.9	  	 	 	176.4	  	 	 	144.7	  	 	 	151.3	  	 	 	125.8	  
	 Non-controlling interest
	  	 	(2.3	) 	 	 	0.7	  	 	 	0.6	  	 	 	—  	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Net earnings
	  	 	194.2	  	 	 	175.7	  	 	 	144.1	  	 	 	151.3	  	 	 	125.8	  
	 Preferred share dividends
	  	 	3.1	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Net earnings applicable to common shares
	  	 	191.1	  	 	 	175.7	  	 	 	144.1	  	 	 	151.3	  	 	 	125.8	  
	 Dividends on common and preferred shares
	  	 	135.1	  	 	 	115.8	  	 	 	107.9	  	 	 	99.9	  	 	 	98.3	  
	 Dividends paid by subsidiaries to non-controlling interest
	  	 	—  	  	 	 	—  	  	 	 	1.9	  	 	 	—  	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Earnings retained for use in the Company
	  	$	56.0	  	 	$	59.9	  	 	$	34.3	  	 	$	51.4	  	 	$	27.5	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Cost of fuel for generation – coal
	  	$	327.0	  	 	 	293.9	  	 	$	282.1	  	 	$	276.0	  	 	$	266.2	  
	
                        
    – oil
	  	 	12.2	  	 	 	5.4	  	 	 	17.7	  	 	 	49.7	  	 	 	34.3	  
	
                        
    – natural gas
	  	 	169.3	  	 	 	138.5	  	 	 	92.5	  	 	 	52.0	  	 	 	(41.6	) 
	 Purchased power
	  	 	210.2	  	 	 	145.7	  	 	 	132.8	  	 	 	116.8	  	 	 	88.8	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total cost of fuel for generation and purchased power
	  	$	718.7	  	 	$	583.5	  	 	$	525.1	  	 	$	494.5	  	 	$	347.7	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance Sheets Information
	  				 				 				 				 			
	 Current assets
	  	$	782.5	  	 	$	714.9	  	 	$	681.8	  	 	$	567.0	  	 	$	491.3	  
	 Other assets *
	  	 	932.3	  	 	 	628.3	  	 	 	793.8	  	 	 	600.4	  	 	 	577.3	  
	 Intangibles
	  	 	103.5	  	 	 	92.1	  	 	 	101.8	  	 	 	83.8	  	 	 	92.1	  
	 Investments subject to significant influence
	  	 	238.9	  	 	 	218.4	  	 	 	317.6	  	 	 	124.5	  	 	 	98.5	  
	 Net investment in direct financing lease
	  	 	488.2	  	 	 	476.9	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Property, plant and equipment and construction work in progress
	  	 	3,783.7	  	 	 	3,153.9	  	 	 	3,374.4	  	 	 	2,845.4	  	 	 	2,789.8	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total assets
	  	$	6,329.1	  	 	$	5,284.5	  	 	$	5,269.4	  	 	$	4,221.1	  	 	$	4,049.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Current liabilities
	  	$	690.3	  	 	$	804.9	  	 	$	880.1	  	 	$	506.6	  	 	$	491.0	  
	 Other liabilities *
	  	 	702.6	  	 	 	488.2	  	 	 	509.3	  	 	 	417.7	  	 	 	231.8	  
	 Long-term debt
	  	 	3,006.9	  	 	 	2,318.4	  	 	 	2,159.2	  	 	 	1,676.4	  	 	 	1,657.4	  
	 Preferred shares issued by subsidiary
	  	 	135.0	  	 	 	135.0	  	 	 	135.0	  	 	 	260.0	  	 	 	260.0	  
	 Non-controlling interest
	  	 	20.7	  	 	 	32.1	  	 	 	39.6	  	 	 	0.6	  	 	 	0.7	  
	 Common shares
	  	 	1,136.5	  	 	 	1,096.7	  	 	 	1,081.4	  	 	 	1,066.2	  	 	 	1,055.2	  
	 Preferred shares
	  	 	146.7	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Contributed surplus
	  	 	3.7	  	 	 	3.6	  	 	 	3.4	  	 	 	3.0	  	 	 	2.2	  
	 Accumulated other comprehensive loss
	  	 	(164.7	) 	 	 	(186.7	) 	 	 	(69.2	) 	 	 	(209.0	) 	 	 	(100.2	) 
	 Retained earnings
	  	 	651.4	  	 	 	592.3	  	 	 	530.6	  	 	 	499.6	  	 	 	450.9	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total equity and liabilities
	  	$	6,329.1	  	 	$	5,284.5	  	 	$	5,269.4	  	 	$	4,221.1	  	 	$	4,049.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Statements of Cash Flow Information
	  				 				 				 				 			
	 Cash provided by operating activities
	  	$	416.4	  	 	$	310.2	  	 	$	237.2	  	 	$	351.4	  	 	$	332.5	  
	 Cash used in investing activities
	  	$	894.8	  	 	$	367.2	  	 	$	671.6	  	 	$	288.9	  	 	$	196.9	  
	 Cash provided by (used in) financing activities
	  	$	466.2	  	 	$	70.5	  	 	$	420.2	  	 	$	(55.6	) 	 	$	(143.4	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Financial ratios ($ per common share)
	  				 				 				 				 			
	 Earnings per common share
	  	$	1.68	  	 	$	1.56	  	 	$	1.29	  	 	$	1.36	  	 	$	1.14	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

  

	*	Other assets and liabilities restated to December 31, 2007 only 


  
 62 









 Management’s Discussion & Analysis 

As at February 11, 2011 
 Management’s
Discussion and Analysis (“MD&A”) provides a review of the results of operations of Emera Inc. and its primary subsidiaries and investments during the fourth quarter of 2010 relative to 2009, and the full year 2010 relative to 2009 and
to 2008; and its financial position at December 31, 2010 relative to 2009. To enhance shareholders’ understanding, certain multi-year historical financial and statistical information is presented. 

This discussion and analysis should be read in conjunction with the Emera Inc. annual audited consolidated financial statements and supporting notes.
Emera Inc. follows Canadian Generally Accepted Accounting Principles (“CGAAP”), including the application of rate-regulated accounting policies for Emera Inc.’s rate-regulated subsidiaries. Emera Inc.’s wholly-owned subsidiaries
- Nova Scotia Power Inc. (“NSPI”), Bangor Hydro Electric Company (“Bangor Hydro”), Maine Public Service Company (“MPS”) and Emera Brunswick Pipeline Company Ltd. (“Brunswick Pipeline”) are subject to rate
regulation and the accounting policies used by these entities may differ in regard to the timing of recognition of certain assets, liabilities, revenue and expenses, from those used by Emera Inc.’s non rate-regulated companies. NSPI’s
accounting policies are subject to examination and approval by the Nova Scotia Utility and Review Board (“UARB”). Bangor Hydro and MPS’ accounting policies are subject to examination and approval by the Maine Public Utilities
Commission (“MPUC”) and the Federal Energy Regulatory Commission (“FERC”). 
 Throughout this discussion, “Emera
Inc.”, “Emera” and “company” refer to Emera Inc. and all of its consolidated subsidiaries and affiliates. 
 All
amounts are in Canadian dollars (“CAD”) except for the Bangor Hydro section of the MD&A, which is reported in US dollars (“USD”) unless otherwise stated. 
 Additional information related to Emera, including the company’s Annual Information Form, can be found on SEDAR at www.sedar.com. 
 Forward Looking Information 
 This MD&A contains forward-looking information and
forward-looking statements which reflect the current view with respect to the company’s objectives, plans, financial and operating performance, business prospects and opportunities. Certain factors that may affect future operations and
financial performance are discussed, including information in the Outlook section of the MD&A. Wherever used, the words “may”, “will”, “intend”, “estimate”, “plan”, “believe”,
“anticipate”, “expect”, “project” and similar expressions are intended to identify such forward-looking statements and should not be read as guarantees of future events, performance or results, and will not necessarily
be accurate indications of whether, or the times at which, such events, performance or results will be achieved. 
 Although Emera believes such
statements are based on reasonable assumptions, such statements are subject to certain risks, uncertainties and assumptions pertaining to, but not limited to, operating performance, regulatory requirements, weather, general economic conditions,
commodity prices, interest rates and foreign exchange rates. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary significantly from those expected. Emera disclaims
any intention or obligation to update or revise any forward-looking information or forward-looking statements, whether as a result of new information, future events or otherwise, except as required under applicable securities laws. 

  
  

63 








 Structure of MD&A 
 This MD&A begins with an Introduction and Strategic Overview followed by a consolidated financial review including consolidated statements of earnings, balance sheets and cash flow highlights and
outstanding share data; then presents information on NSPI, Bangor Hydro (includes Maine & Maritimes Corporation (“MAM”)) and Pipelines (includes Brunswick Pipeline and Maritimes & Northeast Pipeline). All other operations
are grouped and discussed under Other, Including Corporate Costs and include Emera Energy (includes Emera Energy Services, Bayside Power Limited Partnership (“Bayside Power”) and Bear Swamp Power Company LLC. (“Bear Swamp”));
Emera Utility Services (“EUS”); Caribbean (includes Grand Bahama Power Company Limited (“GBPC”), Light and Power Holdings (“LPH”), the parent company of Barbados Light and Power Company Limited (“BLPC”); St.
Lucia Electricity Services (“Lucelec”), and ICD Utilities Limited (“ICDU”)); and corporate activities. Outlook, Liquidity and Capital Resources, Pension Funding, Off-Balance Sheet Arrangements, Transactions with Related Parties,
Dividends and Payout Ratios, Risk Management and Financial Instruments, Disclosure and Internal Controls, Significant Accounting Policies and Critical Accounting Estimates, Changes in Accounting Policies and Summary of Quarterly Results are
presented on a consolidated basis. 
 INTRODUCTION AND STRATEGIC OVERVIEW 
 Emera Inc. is an energy and services company with $6.3 billion in assets. The company invests in electricity generation, transmission and distribution as well as gas transmission and utility energy
services. Emera’s strategy is focused on the transformation of the electricity industry to cleaner generation and the delivery of that clean energy to market. Emera has interests throughout northeastern North America, in three Caribbean
countries and in California. 
 Emera’s goal is to deliver annual consolidated earnings growth of 4% to 6%, and to build and diversify its
earnings base with a focus on cleaner energy in its markets. Emera will continue to seek growth from its existing businesses and will leverage its core strength in the electricity business as it pursues both acquisitions and greenfield development
opportunities in regulated electricity transmission and distribution and low risk generation. 
 Over 90% of Emera’s revenues are earned by
regulated entities-NSPI, Bangor Hydro and Brunswick Pipeline. NSPI is a wholly-owned fully integrated regulated utility with $4.0 billion of assets which provides electricity generation, transmission and distribution services to approximately
489,000 customers in the province of Nova Scotia. Bangor Hydro is an electric transmission and distribution company with $730.4 million of assets serving approximately 118,000 customers in eastern Maine. In December 2010, Emera purchased all of the
outstanding shares of Maine and Maritimes Corporation (“MAM”), the parent company of MPS, a regulated electric transmission and distribution utility serving approximately 36,000 electricity customers in northern Maine. At December 31,
2010, MAM’s assets and liabilities have been included on Emera’s consolidated balance sheet. These businesses operate as monopolies in their service territories. Brunswick Pipeline is a 145-kilometre pipeline carrying re-gasified liquefied
natural gas (“LNG”) from the CanaportTM LNG terminal in Saint John, New Brunswick to the United States border. This regulated pipeline operates under a 25-year firm service agreement with Repsol Energy Canada. 

The success of Emera’s primary businesses is integral to the creation of shareholder value, providing strong, predictable earnings and growing cash
flows to fund dividends and reinvestment. 
 Although markets in Nova Scotia and Maine are otherwise mature, the transformation of energy supply
to lower emission sources has created the opportunity for organic growth within NSPI and Bangor Hydro. Both companies expect earnings growth of 3% to 5% annually over the next five years as new investments are made in renewable generation and
transmission. 

  
  

64 








 Emera also has interests in three Caribbean countries. In December 2010, Emera purchased an additional
55.4 % direct and indirect interest in GBPC bringing total ownership to 80.4%. At December 31, 2010, GBPC’s assets and liabilities have been included on Emera’s consolidated balance sheet. Emera also has a 38% interest in LPH,
the parent company of BLPC and a 19% interest in Lucelec, a vertically-integrated electric utility on the Caribbean island of St. Lucia. 

Emera’s remaining revenues are earned by a growing group of strategic investments that are expected to contribute more significantly to Emera’s
earnings in the coming years. These are described in more detail in the relevant sections of the MD&A. 
 Non-GAAP Measures

 Emera uses financial measures that do not have a standardized meaning under CGAAP. 

Emera Energy – Bear Swamp 

“Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment”, “Contribution to consolidated net
earnings, absent the Bear Swamp after-tax mark-to-market adjustment” and “Contribution to consolidated net earnings per common share, absent the Bear Swamp after-tax mark-to-market adjustment” are non-GAAP financial measures used by
Emera. Management discloses these financial measures as it believes the inclusion of the mark-to-market adjustment in Emera Energy’s financial results does not accurately reflect its operational performance. Many investors use this financial
measure to assess Emera’s overall financial performance. The adjustment is discussed further in the Significant Item section and Other, Including Corporate Costs. 
 NSPI 
 “Electric margin”, defined as “Electric revenue” less “Fuel
for generation and purchased power”, net of the “Fuel adjustment” and fuel related foreign exchange losses or gains, is a non-GAAP financial measure used by NSPI. This measure is disclosed as management believes it provides further
information regarding the impact of the fuel adjustment mechanism (“FAM”) on NSPI’s operations. Electric margin is discussed further in the NSPI Review of 2010 section. 

  
  

65 








 CONSOLIDATED FINANCIAL REVIEW 
 Consolidated Financial Highlights 
  

																					
	 millions of dollars
 (except earnings per common share)
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 	  	2010	 	 	2009	 	 	2010	 	 	2009	 	  	2008	 
	 Revenues
	  	$	392.7	  	 	$	406.5	  	 	$	1,553.7	  	 	$	1,483.5	  	  	$	1,331.9	  
	 Net earnings applicable to common shares
	  	 	39.6	  	 	 	37.5	  	 	 	191.1	  	 	 	175.7	  	  	 	144.1	  
	 Earnings per common share – basic
	  	 	0.35	  	 	 	0.33	  	 	 	1.68	  	 	 	1.56	  	  	 	1.29	  
	 Earnings per common share – diluted
	  	 	0.34	  	 	 	0.33	  	 	 	1.65	  	 	 	1.52	  	  	 	1.26	  
	 Cash dividends declared per share
	  	 	—  	  	 	 	0.2725	  	 	 	1.16	  	 	 	1.03	  	  	 	0.97	  
			
	  	  	Three months ended
December
31	 	 	Year ended
December 31	 
	 Operating Unit Contributions
	  	2010	 	 	2009	 	 	2010	 	 	2009	 	  	2008	 
	 NSPI
	  	$	20.7	  	 	$	17.4	  	 	$	121.3	  	 	$	109.3	  	  	$	105.6	  
	 Bangor Hydro
	  	 	7.8	  	 	 	7.0	  	 	 	31.9	  	 	 	27.5	  	  	 	23.1	  
	 Pipelines
	  	 	8.8	  	 	 	8.4	  	 	 	35.0	  	 	 	24.2	  	  	 	15.4	  
	 Other
	  	 	3.3	  	 	 	8.9	  	 	 	16.1	  	 	 	14.3	  	  	 	3.5	  
	 Corporate (costs) recovery and other
	  	 	(1.0	) 	 	 	(4.2	) 	 	 	(13.2	) 	 	 	0.4	  	  	 	(3.5	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
	 Net earnings applicable to common shares
	  	$	39.6	  	 	$	37.5	  	 	$	191.1	  	 	$	175.7	  	  	$	144.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
	 Net earnings applicable to common shares, absent the Bear Swamp after-tax mark-to-market adjustment
	  	$	42.2	  	 	$	34.3	  	 	$	199.7	  	 	$	175.0	  	  	$	148.9	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
	 Earnings per common share – basic
	  	$	0.35	  	 	$	0.33	  	 	$	1.68	  	 	$	1.56	  	  	$	1.29	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
	 Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment
	  	$	0.38	  	 	$	0.30	  	 	$	1.76	  	 	$	1.55	  	  	$	1.33	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
				
	 	  	 	 	 	 	 	 	As at December 31	 
	 	  	 	 	 	 	 	 	2010	 	 	2009	 	  	2008	 
	 Total assets
	  				 				 	$	6,329.1	  	 	$	5,284.5	  	  	$	5,269.4	  
	 Total liabilities
	  				 				 	 	4,555.5	  	 	 	3,778.6	  	  	 	3,723.2	  

 Developments 

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

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


  

	 	•	 	 Emera and Nalcor together develop an estimated $2.1 billion electricity transmission project in Newfoundland and Labrador to enable the movement of the
Muskrat Falls energy between Labrador and the island of Newfoundland (the “Island Link”). Emera invest approximately $600 million in the Island Link. 



  
  

66 









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


 Agreements
resulting from this term sheet will be subject to a number of conditions including final approval of the Boards of Directors of Emera and Nalcor, approval of regulators in the provinces of Nova Scotia and Newfoundland and Labrador and all
environmental approvals. 
 Effective January 24, 2011, Rick Janega, previously the Executive Vice President and Chief Operating Officer of
Nova Scotia Power Inc. assumed the role of President, Emera, Newfoundland and Labrador. In this role, he will report to Nancy Tower when she assumes her role as CEO, Emera, Newfoundland and Labrador effective May 1, 2011. 

Additional Investment in Grand Bahama Power Company Limited 
 On December 22, 2010, Emera purchased an additional 55.4% direct and indirect interest in GBPC for $88.1 million USD ($87.7 million CAD), bringing total ownership to 80.4%. GBPC is an integrated
utility with 19,000 customers and 137-MW of installed oil-fired capacity. The Grand Bahama Port Authority regulates GBPC and has granted the utility a licensed, regulated and exclusive franchise to produce, transmit, and distribute electricity on
the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policies to ensure that costs are recovered and a reasonable return earned. The purchase was funded with existing credit facilities. 

Maine & Maritimes Corporation 

On December 21, 2010, Emera purchased all of the outstanding shares of MAM for $80.4 million USD ($81.9 million CAD). MAM is the parent company of
MPS, a regulated electric transmission and distribution utility serving approximately 36,000 electricity customers in northern Maine. The purchase was funded with existing credit facilities. 
 Strategic Partnership with Algonquin Power & Utilities Corp. 
 On January 1,
2011, Emera and Algonquin Power & Utilities Corp. (“APUC”) closed their acquisition of the California-based electricity distribution and related generation assets of NV Energy, Inc. for total consideration of $131.8 million USD
($134.2 million CAD), subject to final adjustments. Emera and APUC own and operate these assets through a newly formed utility company, California Pacific Electric Company, LLC (“California Pacific”). APUC and Emera own respectively a
50.001% and 49.999% interest in California Pacific Utility Ventures, LLC (“CPUV”), which wholly-owns California Pacific. The amount paid by Emera for its 49.999% equity investment in the common shares of CPUV is $30.9 million USD ($31.5
million CAD).
 In April 2009, Emera entered into a subscription agreement with APUC, giving Emera the right to acquire 8.523 million APUC
common shares, which represented a 9.9% interest in APUC at that time, upon the closing of the California Pacific transaction. Upon the January 1, 2011 closing of the California Pacific transaction, Emera exchanged the subscription receipts it
acquired under the April 2009 subscription agreement into 8.523 million APUC common shares, issued at $3.25 per share. As a result of this transaction, Emera owns an approximate 8.2% equity interest in APUC. Under the April 2009 subscription
agreement, Emera is entitled to purchase additional APUC common equity to bring its interest to 15%. 
 On December 9, 2010, Emera
announced its intention to purchase 12 million subscription receipts from APUC at an issue price of $5.00 each for a total purchase price of $60 million. Emera will issue a promissory note to APUC in the principal amount of $60 million in
exchange for the subscription receipts. The subscription receipts will be convertible to 12 million APUC common shares upon the acquisition by APUC’s regulated subsidiary, Liberty Energy Utilities Co., of all issued and outstanding shares
of Granite State Electric Company and Energy North Natural Gas Inc., two regulated electric utilities, currently owned by National Grid USA. On the closing of the National Grid transaction and following the exercise of Emera’s anti-dilution
rights, Emera’s percentage ownership interest in APUC will be approximately 15%. Proceeds from the subscription receipts will be used by APUC to finance a portion of this acquisition, which is expected to close in late 2011. The purchase of the
subscription receipts has received conditional Toronto Stock Exchange approval. 

  
  

67 








 Barbados Light & Power Company Limited 

On December 20, 2010, Emera offered to purchase all issued and outstanding common shares from LPH shareholders at a cash price of $25.70 Barbadian
dollars. This offer closed on January 24, 2011. On January 25, 2011, Emera purchased 7.2 million shares of LPH at a cash price per share of $25.70 Barbadian dollars representing an additional interest of 41.9%. With this additional
investment of $91.9 million, Emera became the majority shareholder of LPH, with a total interest of 79.9%. 
 Previously, on May 11, 2010,
Emera acquired a 38% interest in LPH, the parent company of BLPC, for $85 million USD. BLPC is the sole utility operator on the island of Barbados, serving 120,000 customers. BLPC has three power generation stations with 239 MW of installed
capacity. A fuel pass through mechanism ensures costs are recovered and a cost-of-service regulation provides for an approved 12.75% return on equity. This transaction was immediately accretive and was financed with existing credit facilities.

 Dividends 
 In February 2010,
the Board of Directors approved a quarterly dividend increase, effective May 3, 2010, to $0.2825 per common share, and in September 2010, approved a further increase to $0.3250 effective November 1, 2010 reflecting an increase on an
annualized basis to $1.30 per common share. 
 Appointments 
 Effective May 1, 2011, Nancy Tower, presently the Executive Vice President and Chief Financial Officer of Emera and Nova Scotia Power Inc., will assume the role of Executive Vice President, Business
Development for Emera Inc. In addition to overall responsibility for business development as previously noted, Ms. Tower will also oversee the Emera partnership with Nalcor including the execution of the Lower Churchill Project as the CEO,
Emera, Newfoundland and Labrador. 
 On September 24, 2010, Sylvia Chrominska and Richard Sergel joined the Emera Board of Directors.

 NSPI 
 Deferral of Certain
Tax Benefits Related to Renewable Energy Projects for Fiscal 2010 
 On December 23, 2010, the UARB granted NSPI approval to defer
certain tax benefits related to renewable energy projects arising in 2010. Accordingly, effective December 31, 2010, NSPI recognized a deferral of $14.5 million through an increase in regulatory amortization. The UARB will convene a proceeding
in 2011 to discuss how this deferral will be applied. 
 UARB Decision on Fuel Adjustment Mechanism 

On December 8, 2010, the UARB approved NSPI’s setting of the 2011 base cost of fuel and its recovery of all unrecovered fuel related costs as
submitted in NSPI’s November 2010 filing. The recovery of these costs will begin January 1, 2011. The UARB approved the recovery of these costs by NSPI over three years, with 50% of the rate increase to be recovered in 2011, 30% in 2012
and 20% in 2013. The decision results in an average rate increase of approximately 4.5% for customers in 2011. Pursuant to the FAM Plan of Administration, NSPI is entitled to earn a return on the unrecovered balance of fuel related costs.


  
  

68 








 Renewable Energy Projects 
 Port Hawkesbury Biomass Project 
 On October 14, 2010, the UARB
approved NSPI’s $208.6 million capital work order request for the Port Hawkesbury biomass project. NSPI will develop this 60-MW co-generating facility at the NewPage Port Hawkesbury Corporation (“NewPage”) site. NSPI will own the
facility while NewPage will construct and operate the plant as well as supply the fuel. This project is expected to be commissioned in 2013 and supply approximately 3% of the province of Nova Scotia’s total electricity needs. 

Point Tupper Wind Development Project 
 On June 14, 2010, the UARB approved NSPI’s $27.8 million capital work order for the Point Tupper Wind Development Project. The Project went into service in August 2010. 

Digby Wind Project. 
 On May 28, 2010, NSPI purchased $30.1 million in wind generation assets under development related to the Digby Wind Project from a subsidiary of Emera. NSPI has requested UARB approval of this
project through the submission of a capital work order. The Project was completed and went into service in December 2010 at a total cost of approximately $80.0 million. The UARB hearing took place in January 2011, and a decision is pending.

 Nova Scotia Provincial Environmental Regulations 
 Renewable Electricity Plan 
 On October 15, 2010, the Nova Scotia
Government enacted regulations under the Electricity Act related to the Province’s Renewable Electricity Plan. These regulations establish the requirement that 25% of electricity be supplied from renewable sources by 2015. These regulations
build on the previously legislated requirements for 2011 and 2013 by adding an additional 5% for 2015. Recent amendments to the Electricity Act, and the new regulations, provide for the appointment, by spring 2011, of a new, independent renewable
electricity administrator to conduct the procurement of at least 300 gigawatt hours (“GWh”) of energy from independent power producers (“IPPs”) to meet the 2015 standard. NSPI is also provided the opportunity to develop 300 GWh
of renewable energy. 
 Mercury Emissions 
 On July 22, 2010, the Province of Nova Scotia announced, for the years 2010 through 2013, allowable mercury emissions would be increased from the previous cap of 65 kg per year. NSPI was requested to
develop a plan of staged mercury emission reductions, for its generation facilities, for the period of 2010 to 2020 and meet an annual cap of 35 kg beginning in 2020. 
 Canadian Federal Environmental Regulations 
 Greenhouse Gas

 On June 23, 2010, the Federal Department of Environment announced its intentions for a new national greenhouse gas
(“GHG”) framework for the electricity sector. This federal framework, if developed further into regulations, would require thermal coal units to meet GHG emission levels equal to, or better than, a natural gas combined cycle generating
unit at a future date. Nova Scotia’s existing GHG regulations require reductions in NSPI’s emissions similar to the intentions of the federal framework. NSPI is reviewing the implications of this federal framework and its alignment with
NSPI’s current operating plans under existing Nova Scotia regulations. 
 US Securities and Exchange Commission Registration

 On July 15, 2010, NSPI registered debt securities with the US Securities and Exchange Commission (“SEC”) under the US
Securities Act of 1933. 

  
  

69 








 Appointments 
 On May 3, 2010, Elaine Sibson and Lee Bragg joined the NSPI Board of Directors. 
 Bangor
Hydro 
 Collective Agreement 

In July 2010, Bangor Hydro reached an agreement with its unionized employees, which will expire in July 2015. 

Keene Road 345 kV Substation Project 
 In
December 2010, Bangor Hydro’s Keene Road 345 kilovolt (“kV”) Substation Project was completed at total cost of approximately $33.0 million USD. 
 Significant Item 
 Bear Swamp Mark-to-Market Adjustment 

As part of its long-term energy and capacity supply agreement, expiring in 2021, with the Long Island Power Authority (“LIPA”), Bear Swamp has
contracted with its joint venture partner to provide the power necessary to produce the requirements of the LIPA contract. One of the contracts between Bear Swamp and Emera’s joint venture partner is marked-to-market through earnings, as it
does not meet the stringent accounting requirements of hedge accounting. 
 As at December 31, 2010, the fair value of the derivative was a
net liability of $8.2 million (December 31, 2009 – $6.2 million net asset). The fair value of this derivative is subject to market volatility of power prices and will reverse over the life of the agreement. 

The mark-to-market adjustment relating to this position was as follows: 
  


																					
	 millions of dollars (except earnings per common share)
	  	Three months ended
December 
31	 	  	Year ended
December 31	 
	 	  	2010	 	 	2009	 	  	2010	 	 	2009	 	  	2008	 
	 Mark-to-market (loss) gain
	  	$	(4.4	) 	 	$	5.5	  	  	$	(14.4	) 	 	$	1.2	  	  	$	(8.1	) 
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
	 After-tax mark-to-market (loss) gain
	  	$	(2.6	) 	 	$	3.2	  	  	$	(8.6	) 	 	 	0.7	  	  	$	(4.8	) 
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
	 Earnings per common share – basic
	  	$	0.35	  	 	$	0.33	  	  	$	1.68	  	 	$	1.56	  	  	$	1.29	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
	 Earnings per common share – basic, absent the Bear Swamp after-tax mark-to-market adjustment
	  	$	0.38	  	 	$	0.30	  	  	$	1.76	  	 	$	1.55	  	  	$	1.33	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 


  
  

70 








 Review of 2010 
 Emera Consolidated Statements of Earnings 
  

																					
	 millions of dollars
 (except earnings per common share)
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 	  	2010	 	 	2009	 	 	2010	 	 	2009	 	  	2008	 
	 Electric revenue
	  	$	362.1	  	 	$	368.1	  	 	$	1,436.1	  	 	$	1,402.0	  	  	$	1,280.8	  
	 Finance income from direct financing lease
	  	 	13.7	  	 	 	15.2	  	 	 	56.5	  	 	 	25.3	  	  	 	—  	  
	 Other revenue
	  	 	16.9	  	 	 	23.2	  	 	 	61.1	  	 	 	56.2	  	  	 	51.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
		  	 	392.7	  	 	 	406.5	  	 	 	1,553.7	  	 	 	1,483.5	  	  	 	1,331.9	  
	 Fuel for generation and purchased power
	  	 	176.8	  	 	 	168.8	  	 	 	718.7	  	 	 	583.5	  	  	 	525.1	  
	 Fuel adjustment
	  	 	(24.0	) 	 	 	(10.6	) 	 	 	(99.0	) 	 	 	8.5	  	  	 	—  	  
	 Operating, maintenance and general
	  	 	92.0	  	 	 	84.5	  	 	 	336.1	  	 	 	294.4	  	  	 	266.8	  
	 Provincial, state, and municipal taxes
	  	 	12.3	  	 	 	12.4	  	 	 	49.1	  	 	 	49.9	  	  	 	49.4	  
	 Depreciation and amortization
	  	 	45.7	  	 	 	42.2	  	 	 	173.6	  	 	 	164.9	  	  	 	151.3	  
	 Regulatory amortization
	  	 	24.6	  	 	 	16.4	  	 	 	41.3	  	 	 	35.7	  	  	 	28.5	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
		  	 	65.3	  	 	 	92.8	  	 	 	333.9	  	 	 	346.6	  	  	 	310.8	  
	 Equity earnings
	  	 	2.3	  	 	 	2.0	  	 	 	13.6	  	 	 	14.0	  	  	 	15.2	  
	 Financing charges
	  	 	43.8	  	 	 	45.1	  	 	 	168.4	  	 	 	135.3	  	  	 	123.2	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
		  	 	23.8	  	 	 	49.7	  	 	 	179.1	  	 	 	225.3	  	  	 	202.8	  
	 Income taxes
	  	 	(13.4	) 	 	 	12.4	  	 	 	(12.8	) 	 	 	48.9	  	  	 	58.1	  
	 Net earnings before non-controlling interest
	  	 	37.2	  	 	 	37.3	  	 	 	191.9	  	 	 	176.4	  	  	 	144.7	  
	 Non-controlling interest
	  	 	(2.4	) 	 	 	(0.2	) 	 	 	(2.3	) 	 	 	0.7	  	  	 	0.6	  
	 Net earnings
	  	 	39.6	  	 	 	37.5	  	 	 	194.2	  	 	 	175.7	  	  	 	144.1	  
	 Preferred share dividends
	  	 	—  	  	 	 	—  	  	 	 	3.1	  	 	 	—  	  	  	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
	 Net earnings applicable to common shares
	  	$	39.6	  	 	$	37.5	  	 	$	191.1	  	 	$	175.7	  	  	$	144.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
	 Earnings per common share – basic
	  	$	0.35	  	 	$	0.33	  	 	$	1.68	  	 	$	1.56	  	  	$	1.29	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
	 Earnings per common share – diluted
	  	$	0.34	  	 	$	0.33	  	 	$	1.65	  	 	$	1.52	  	  	$	1.26	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 

 Emera Inc.’s consolidated net earnings applicable to common shares increased $2.1 million to $39.6 million in Q4 2010
compared to $37.5 million for the same period in 2009. Emera’s annual consolidated net earnings applicable to common shares increased $15.4 million to $191.1 million in 2010 compared to $175.7 million in 2009, and $144.1 million in 2008.


  
  

71 








 Highlights of the changes are summarized in the following table: 

 

									
	 millions of dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 Consolidated net earnings applicable to common shares – 2008
	  				 	$	144.1	  
	 NSPI – Increased net earnings due to an electricity price increase, partially offset by increased fuel expense; operating,
maintenance and general (“OM&G”) expense and depreciation and amortization
	  				 	 	3.7	  
	 Bangor Hydro – Increased net earnings due mainly to a transmission rate increase and a weaker average CAD in
2009
	  				 	 	4.4	  
	 Pipelines – Increased net earnings from Brunswick Pipeline due to allowance for funds used during construction
(“AFUDC”) on construction of the pipeline in the first half of the year and financing income from commencement of pipeline operations in July 2009, partially offset by increased intercompany financing charges related to the financing of
the pipeline
	  				 	 	8.8	  
	 Other – Increased net earnings primarily related to the after-tax mark-to-market adjustments on the favourable commodity
price positions in Bear Swamp and Emera Energy
	  				 	 	10.8	  
	 Corporate costs and other – Decreased due to increased income tax recovery and intercompany financing
revenues
	  				 	 	3.9	  
		  	 	 	 	 	 	 	 
	 Consolidated net earnings applicable to common shares – 2009
	  	$	37.5	  	 	$	175.7	  
		  	 	 	 	 	 	 	 
	 NSPI – Increased net earnings primarily due to decreased income taxes resulting from decreased earnings before income taxes,
deductions related to renewable investments and a change in the expected benefit from other accelerated tax deductions
	  	 	3.3	  	 	 	12.0	  
	 Bangor Hydro – Increased net earnings primarily due to transmission rate increases and increased transmission pool revenue
related to recovery of regionally funded transmission investments, partially offset by a stronger average CAD in 2010
	  	 	0.8	  	 	 	4.4	  
	 Pipelines – Increased net earnings primarily due to Brunswick Pipeline’s service commencement in July 2009 as compared
to a full year in 2010
	  	 	0.4	  	 	 	10.8	  
	 Other – Decreased net earnings in the quarter due primarily to Bear Swamp’s mark-to-market loss, operational issues at
GBPC, partially offset by improved energy marketing results. Year over year increase is due to increased EUS earnings and improved energy marketing results, partially offset by Bear Swamp’s mark-to-market loss
	  	 	(5.6	) 	 	 	1.8	  
	 Corporate costs and other – Decreased in the quarter due to deferral of business development costs. Year over year increase
is primarily due to increased financing charges
	  	 	3.2	  	 	 	(13.6	) 
		  	 	 	 	 	 	 	 
	 Consolidated net earnings applicable to common shares – 2010
	  	$	39.6	  	 	$	191.1	  
		  	 	 	 	 	 	 	 

 Q4 basic earnings per share were $0.35 in 2010 compared to $0.33 in 2009; and $1.68 for the full year 2010 compared to $1.56
in 2009 and $1.29 in 2008. 
 Consolidated Net Earnings History 

 

																									
	 millions of dollars
	  	2010	 	  	2009	 	  	2008	 	  	2007	 	  	2006	 	  	2005	 
	 Net earnings applicable to common shares
	  	$	191.1	  	  	$	175.7	  	  	$	144.1	  	  	$	151.3	  	  	$	125.8	  	  	$	121.2	  
	 Net earnings applicable to common shares, absent the Bear Swamp after-tax mark-to-market adjustment
	  	$	199.7	  	  	$	175.0	  	  	$	148.9	  	  	$	141.9	  	  	$	125.8	  	  	$	121.2	  

 Earnings per Share History

  

																									
	 Dollars
	  	2010	 	  	2009	 	  	2008	 	  	2007	 	  	2006	 	  	2005	 
	 Earnings per share
	  	$	1.68	  	  	$	1.56	  	  	$	1.29	  	  	$	1.36	  	  	$	1.14	  	  	$	1.11	  
	 Earnings per share, absent the Bear Swamp after-tax mark-to-market adjustment
	  	$	1.76	  	  	$	1.55	  	  	$	1.33	  	  	$	1.28	  	  	$	1.14	  	  	$	1.11	  


  
  

72 








 Consolidated Balance Sheets Highlights 
 Significant changes in the consolidated balance sheets between December 31, 2010 and December 31, 2009 include: 
  

							
	 millions of dollars
	  	Increase
(Decrease)	 	 	 Explanation

	 Assets
	  				 	
	 Cash and cash equivalents
	  	$	(12.4	) 	 	See consolidated cash flow highlights section.
	 Restricted cash
	  	 	58.6	  	 	Cash in trust related to purchase of APUC subscription receipts.
	 Accounts receivable
	  	 	(16.6	) 	 	Settlement of a receivable from a natural gas supplier, partially offset by higher posted margin to counterparties and acquisition of MAM and increased investment in
GBPC.
	 Income tax receivable
	  	 	39.7	  	 	Recovery of income taxes due to deductions related to renewable investments and a change in the expected benefit from other accelerated tax deductions.
	 Other Assets
	  	 	224.7	  	 	Increased future income tax (“FIT”) regulatory asset, recognition of the FAM regulatory asset in 2010 and acquisition of MAM, partially offset by regulatory
amortization and decreased regulatory assets related to financial instruments.
	 Future income tax assets

(including long-term portion)
	  	 	(10.0	) 	 	Decreased FIT asset related primarily to derivatives recognized in accumulated other comprehensive loss (“AOCI”) partially offset by increased US mark-to-market losses
on held-for-trading derivatives.
	 Goodwill
	  	 	91.3	  	 	Goodwill on acquisition of MAM and increased investment in GBPC.
	 Intangibles
	  	 	11.4	  	 	Software and land rights acquisitions in NSPI and acquisition of MAM.
	 Investments subject to significant influence
	  	 	20.5	  	 	Primarily the acquisition of a 38% interest in LPH, offset by the consolidation of GBPC since acquiring a controlling interest.
	 Net investment in direct financing lease
	  	 	11.3	  	 	Costs related to direct financing lease of Brunswick Pipeline.
	 Property, plant & equipment
	  	 	517.0	  	 	Capital spending, primarily in NSPI, acquisition of MAM and further investment in GBPC.
	 Construction work in progress
	  	 	112.8	  	 	Capital spending, primarily in NSPI, and a further investment in GBPC.
	 Liabilities and Shareholders’ Equity
	  				 	
	 Accounts payable and accrued charges
	  	 	93.7	  	 	Timing of payments largely associated with capital projects and increased amount of business activity.
	 Derivatives in a valid hedging relationship (including long-term portion)
	  	 	(56.8	) 	 	Favourable commodity price and USD price positions and natural gas derivatives reclassified to “Held-for-trading”. The effective portion of the change is recognized in
AOCI.
	 Held-for-trading derivatives

(including long-term portion)
	  	 	14.7	  	 	Unfavourable commodity price positions in Emera Energy.
	 Future income tax liabilities
	  	 	165.7	  	 	Increased FIT liability on property, plant and equipment, including renewable investments, FAM regulatory asset and FIT in MAM, partially offset by increased FIT asset on asset
retirement obligations. The portion expected to be recovered from customers in future rates is recognized in “Other assets”.
	 Asset retirement obligations
	  	 	37.3	  	 	Recognition of asset retirement obligations in NSPI.
	 Other liabilities
	  	 	13.6	  	 	Acquisitions of MAM and further investment in GBPC.
	 Short-term debt and long-term debt

(including current portion)
	  	 	520.9	  	 	Increased debt levels to fund significant capital programs, acquisition of MAM, further investment in GBPC and investment in LPH.
	 Common shares
	  	 	39.8	  	 	Issuance of common shares.
	 Preferred shares
	  	 	146.7	  	 	Issuance of preferred shares.
	Accumulated other comprehensive loss	  	 	22.0	  	 	Primarily represents the effective portion of favourable commodity price positions, partially offset by the unfavourable effect of the CAD on Emera’s investment in Bangor
Hydro.
	 Retained earnings
	  	 	59.1	  	 	Net earnings in excess of dividends declared.


  
  

73 








 Consolidated Cash Flow Highlights 
 Significant changes in the consolidated cash flow statements between December 31, 2010 and December 31, 2009 include: 

 

											
	 Three months ended December 31

millions of dollars
	  	2010	 	 	2009	 	 	 Explanation

	 Cash and cash equivalents, beginning of period
	  	$	47.5	  	 	$	27.7	  	 	
	 Provided by (used in):
	  				 				 	
	 Operating activities
	  	 	185.5	  	 	 	94.7	  	 	In 2010 and 2009, cash earnings and favourable non-cash operating working capital.
	 Investing activities
	  	 	(442.8	) 	 	 	(163.9	) 	 	In 2010, capital spending, including multi-year projects and renewable investments in NSPI and acquisition of further interest in GBPC and purchase of MAM.
		  				 				 	In 2009, capital spending, including multi-year projects in NSPI and the completion of Brunswick Pipeline.
	 Financing activities
	  	 	219.0	  	 	 	63.8	  	 	In 2010, increased debt levels, partially offset by dividends on common and preferred shares.
		  				 				 	In 2009, increased debt levels, partially offset by dividends on common shares.
	 Foreign currency impact on cash balances
	  	 	0.2	  	 	 	(0.5	) 	 	
		  	 	 	 	 	 	 	 	 	
	 Cash and cash equivalents, end of period
	  	$	9.4	  	 	$	21.8	  	 	
		  	 	 	 	 	 	 	 	 	
				
	 Year ended December 31
 millions of dollars
	  	2010	 	 	2009	 	 	 Explanation

	 Cash and cash equivalents, beginning of year
	  	$	21.8	  	 	$	12.2	  	 	
	 Provided by (used in):
	  				 				 	
	 Operating activities
	  	 	416.4	  	 	 	310.2	  	 	In 2010, cash earnings and favourable non-cash operating working capital.
		  				 				 	In 2009, cash earnings partially offset by unfavourable non-cash working capital.
	 Investing activities
	  	 	(894.8	) 	 	 	(367.2	) 	 	In 2010, capital spending, including multi-year projects and renewable investments in NSPI, investment in LPH, an additional investment in GBPC and purchase of
MAM.
		  				 				 	In 2009, capital spending including multi-year projects in NSPI, Brunswick Pipeline, and acquisition of Bayside, partially offset by a return of capital from
M&NP.
	 Financing activities
	  	 	466.2	  	 	 	70.5	  	 	In 2010, increased debt levels and the issuance of preferred shares, partially offset by dividends on common and preferred shares.
		  				 				 	In 2009, increased long-term debt, partially offset by decreased short-term debt, dividends on common shares and redemption of NSPI’s preferred shares.
	 Foreign currency impact on cash balances
	  	 	(0.2	) 	 	 	(3.9	) 	 	
		  	 	 	 	 	 	 	 	 	
	 Cash and cash equivalents, end of year
	  	$	9.4	  	 	$	21.8	  	 	
		  	 	 	 	 	 	 	 	 	

 Operating activities increased $106.2 million to $416.4 million for the year ended December 31, 2010 compared
to $310.2 million in 2009 primarily due to lower accounts receivable and the settlement of a contract receivable from a natural gas supplier, higher accounts payable and accrued charges, offset by income tax receivable in 2010 compared to income tax
payable in 2009. 

  
  

74 








 Outstanding Share Data 

 

									
	 Issued and Outstanding:
	  	Millions of
Shares	 	  	Common Share Capital
millions of dollars	 
	 December 31, 2008
	  	 	112.21	  	  	$	1,081.4	  
	 Issued for cash under purchase plans
	  	 	0.45	  	  	 	8.7	  
	 Options exercised under senior management share option plan
	  	 	0.32	  	  	 	5.8	  
	 Share-based compensation
	  	 	—  	  	  	 	0.8	  
		  	 	 	 	  	 	 	 
	 December 31, 2009
	  	 	112.98	  	  	$	1,096.7	  
	 Issued for cash under purchase plans
	  	 	1.32	  	  	 	32.8	  
	 Options exercised under senior management share option plan
	  	 	0.32	  	  	 	6.0	  
	 Share-based compensation
	  	 	—  	  	  	 	1.0	  
		  	 	 	 	  	 	 	 
	 December 31, 2010
	  	 	114.62	  	  	$	1,136.5	  
		  	 	 	 	  	 	 	 

 As at January 31, 2011, the number of issued and outstanding common shares was 114.69 million. 

  
  

75 








 NOVA SCOTIA POWER INC. 
 Overview 
 NSPI, created through the privatization in 1992 of the crown corporation Nova
Scotia Power Corporation, is a fully-integrated regulated electric utility and the primary electricity supplier in Nova Scotia. NSPI has $4.0 billion of assets and provides electricity generation, transmission and distribution services to
approximately 489,000 customers. The company owns 2,368 MW of generating capacity, of which approximately 53% is coal-fired; natural gas and/or oil comprise another 27% of capacity; and hydro and wind production total 20%. In addition, NSPI has
contracts to purchase renewable energy from IPPs. These IPPs own 186 MW, increasing to 226 MW in 2011, of wind and biomass fueled generation capacity. A further 85 MW of renewable capacity is being built directly or purchased under long-term
contract by NSPI and is expected to be in service by the end of 2012. NSPI also owns approximately 5,000 kilometers of transmission facilities and 29,000 kilometers of distribution facilities. NSPI has a workforce of approximately 1,900 people.

 NSPI is a public utility as defined in the Public Utilities Act (Nova Scotia) (“Act”) and is subject to regulation under the Act by
the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather
participates in hearings from time to time at NSPI’s or the UARB’s request. 
 NSPI is regulated under a cost-of-service model, with
rates set to recover prudently incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s regulated return on equity (“ROE”) range for 2010 was 9.1% to 9.6%, on an actual
regulated common equity component of up to 40% of average regulated capitalization. 
 In 2009, the UARB approved a FAM, allowing NSPI
to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. In 2010, revenue associated with fuel comprised approximately 45% of total revenue. As the FAM mitigates NSPI’s net earnings’ exposure to fuel
volatility, it facilitates longer planning cycles. This enables NSPI to increase its focus on the impact that non-fuel components of the business have on net earnings, while retaining focus on managing fuel costs for customers. In 2010, tax benefits
associated with renewable energy investments reduced costs and, thus NSPI did not seek a general rate adjustment with the UARB. 
 Review of
2010 
  

																					
	 NSPI
 millions of dollars (except earnings per common share)
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 	  	2010	 	 	2009	 	 	2010	 	 	2009	 	 	2008	 
	 Electric revenue
	  	$	296.4	  	 	$	302.9	  	 	$	1,167.3	  	 	$	1,188.1	  	 	$	1,111.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Fuel for generation and purchased power
	  	 	146.2	  	 	 	138.5	  	 	 	586.7	  	 	 	500.7	  	 	 	471.4	  
	 Fuel adjustment
	  	 	(24.0	) 	 	 	(10.6	) 	 	 	(99.0	) 	 	 	8.5	  	 	 	—  	  
	 Operating, maintenance and general
	  	 	65.0	  	 	 	58.4	  	 	 	237.5	  	 	 	215.1	  	 	 	203.7	  
	 Provincial grants and taxes
	  	 	10.1	  	 	 	10.0	  	 	 	40.1	  	 	 	40.5	  	 	 	41.2	  
	 Depreciation and amortization
	  	 	39.9	  	 	 	36.8	  	 	 	150.8	  	 	 	143.9	  	 	 	133.6	  
	 Regulatory amortization
	  	 	23.7	  	 	 	14.7	  	 	 	36.9	  	 	 	27.2	  	 	 	17.7	  
	 Other revenue
	  	 	(4.7	) 	 	 	(4.0	) 	 	 	(15.4	) 	 	 	(14.0	) 	 	 	(15.5	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Earnings before financing charges and income taxes
	  	 	40.2	  	 	 	59.1	  	 	 	229.7	  	 	 	266.2	  	 	 	259.0	  
	 Financing charges
	  	 	32.8	  	 	 	33.3	  	 	 	125.8	  	 	 	114.7	  	 	 	106.8	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Earnings before income taxes
	  	 	7.4	  	 	 	25.8	  	 	 	103.9	  	 	 	151.5	  	 	 	152.2	  
	 Income taxes
	  	 	(13.3	) 	 	 	8.4	  	 	 	(17.4	) 	 	 	42.2	  	 	 	46.6	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares
	  	$	20.7	  	 	$	17.4	  	 	$	121.3	  	 	$	109.3	  	 	$	105.6	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Contribution to consolidated earnings per common share
	  	$	0.18	  	 	$	0.15	  	 	$	1.07	  	 	$	0.97	  	 	$	0.94	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 


  
  

76 








 NSPI’s contribution to consolidated net earnings applicable to common shares increased $3.3 million to
$20.7 million in Q4 2010, compared to $17.4 million in Q4 2009. Annual contribution to consolidated net earnings applicable to common shares increased $12.0 million to $121.3 million in 2010 compared to $109.3 million in 2009, and $105.6 million in
2008. 
 Highlights of the contribution to consolidated earnings changes are summarized in the following table: 

 

									
	 millions of dollars
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 Contribution to consolidated net earnings applicable to common shares – 2008
	  				 	$	105.6	  
	 Increased electric revenue due to an electricity price increase on January 1, 2009, partially offset by decreased industrial
sales in the year
	  				 	 	77.0	  
	 Increased fuel for generation and purchased power
	  				 	 	(29.3	) 
	 Fuel adjustment related to implementation of the FAM
	  				 	 	(8.5	) 
	 Increased depreciation and amortization primarily due to increased depreciation rates in 2009 as part of the phase-in of
year-three rates as approved by the UARB
	  				 	 	(10.3	) 
	 Increased financing charges
	  				 	 	(7.9	) 
	 Increased regulatory amortization due to additional amortization of pre-2003 income tax regulatory asset
	  				 	 	(9.5	) 
	 Decreased income taxes due to decreased taxable income and lower statutory rate, partially offset by recovery of income taxes in
2008 relating to a prior year
	  				 	 	4.4	  
	 Other
	  				 	 	(0.8	) 
		  	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – 2009
	  	$	17.4	  	 	$	109.3	  
	 Decreased electric margin (see Electric Margin for explanation)
	  	 	(2.0	) 	 	 	(11.6	) 
	 Increased OM&G expenses primarily due to increased pension and storm costs. Year-to-date also reflects increased spending on
customer service initiatives
	  	 	(6.6	) 	 	 	(22.4	) 
	 Increased depreciation and amortization primarily due to increased property, plant and equipment
	  	 	(3.1	) 	 	 	(6.9	) 
	 Increased regulatory amortization due to a deferral of certain tax benefits arising in 2010, partially offset by decreased
amortization of the pre-2003 income tax regulatory asset
	  	 	(9.0	) 	 	 	(9.7	) 
	 Decreased income taxes due to decreased earnings before income taxes, deductions related to renewable investments and a change in
the expected benefit from other accelerated tax deductions
	  	 	21.7	  	 	 	59.6	  
	 Other
	  	 	2.3	  	 	 	3.0	  
		  	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – 2010
	  	$	20.7	  	 	$	121.3	  
		  	 	 	 	 	 	 	 

 Financing charges decreased $0.5 million in the quarter and increased $11.1 million for the year ended December 31,
2010. Foreign exchange gain and losses recovered through the FAM as fuel costs are included in the change in electric margin in the table above. See Electric Margin section for additional explanation. 

  
  

77 








 Electric Revenue 
 NSPI’s electricity rates are set based on a forecast of fuel and non-fuel costs plus a reasonable return to investors. Consequently, the company’s electric revenue is comprised of revenue
related to the recovery of fuel costs (“fuel electric revenue”) and revenue related to the recovery of non-fuel costs (“non-fuel electric revenue”). 
 With the introduction of the FAM, on January 1, 2009, NSPI is able to seek full recovery of fuel costs through regularly scheduled rate adjustments, thus reducing the impact of volatile fuel markets
on NSPI’s earnings. As a result, fuel electric revenue does not have a material impact on net earnings. 
 NSPI’s customer
classes contribute differently to the NSPI’s non-fuel electric revenue. Changes in volume of residential and commercial customers, largely due to weather, have the largest impact on non-fuel electric revenue. Changes in industrial
load, which are generally due to economic conditions, do not have a significant impact on non-fuel electric revenue. 
 The fuel electric
revenue is comprised of the recovery of fuel costs incurred in the current year and the over or under-recovery of fuel costs from the prior year. Since fuel costs are recovered through the FAM, the electric margin is solely influenced by
revenues relating to non-fuel costs and the FAM incentive expense or recovery. Electric revenue is summarized in the following table: 
  

																					
	 millions of dollars
	  	Three months ended
December 
31	 	  	Year ended
December 31	 
	 	  	2010	 	 	2009	 	  	2010	 	 	2009	 	  	2008	 
	 Fuel electric revenue current year
	  	$	129.0	  	 	$	131.4	  	  	$	515.7	  	 	$	511.2	  	  	 	*	  
	 Fuel electric revenue prior year rebate
	  	 	(5.7	) 	 	 	—  	  	  	 	(22.4	) 	 	 	—  	  	  	 	*	  
	 Non-fuel electric revenue
	  	 	173.1	  	 	 	171.5	  	  	 	674.0	  	 	 	676.9	  	  	 	*	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
	 Total electric revenue
	  	$	296.4	  	 	$	302.9	  	  	$	1,167.3	  	 	$	1,188.1	  	  	$	1,111.1	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 

  

	*	Prior to the introduction of the FAM on January 1, 2009, electric revenue was not broken into the components above. 


Electric revenue decreased $6.5 million to $296.4 million in Q4 2010 compared to $302.9 million in Q4 2009. For the year ended December 31, 2010,
NSPI’s electric revenue decreased $20.8 million to $1,167.3 million compared to $1,188.1 million in 2009 and $1,111.1 million in 2008. 

Highlights of the changes are summarized in the following table: 
  

									
	 millions of dollars
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 Electric revenue – 2008
	  				 	$	1,111.1	  
	 Increased electricity pricing effective January 1, 2009
	  				 	 	102.1	  
	 Net change in residential and commercial sales volumes
	  				 	 	4.2	  
	 Decreased industrial sales to several large industrial customers
	  				 	 	(28.3	) 
	 Decreased export sales
	  				 	 	(1.0	) 
		  	 	 	 	 	 	 	 
	 Electric revenue – 2009
	  	$	302.9	  	 	$	1,188.1	  
	 Decreased electricity pricing effective January 1, 2010 related to the FAM rebate (fuel-electric revenue) to customers of
over-recovered fuel costs in 2009
	  	 	(5.7	) 	 	 	(22.4	) 
	 Change in residential and commercial sales volumes due primarily to warmer weather
	  	 	(1.7	) 	 	 	(10.7	) 
	 Increased industrial sales volume from several large industrial customers
	  	 	0.6	  	 	 	13.2	  
	 Other
	  	 	0.3	  	 	 	(0.9	) 
		  	 	 	 	 	 	 	 
	 Electric revenue – 2010
	  	$	296.4	  	 	$	1,167.3	  
		  	 	 	 	 	 	 	 


  
  

78 








 Electric Sales Volumes 

 

																															
	 Q4 Electric Sales Volumes

GWh
	 	  	 	 	 	 Year-to-Date (“YTD”) Electric Sales Volumes

GWh
	 
	 	  	2010	 	  	2009	 	  	2008	 	  	 	 	 	 	  	2010	 	  	2009	 	  	2008	 
	 Residential
	  	 	1,080	  	  	 	1,091	  	  	 	1,093	  	  				 	 Residential
	  	 	4,147	  	  	 	4,228	  	  	 	4,179	  
	 Commercial
	  	 	765	  	  	 	772	  	  	 	770	  	  				 	 Commercial
	  	 	3,088	  	  	 	3,107	  	  	 	3,115	  
	 Industrial
	  	 	957	  	  	 	998	  	  	 	987	  	  				 	 Industrial
	  	 	3,908	  	  	 	3,642	  	  	 	4,144	  
	 Other
	  	 	84	  	  	 	81	  	  	 	84	  	  				 	 Other
	  	 	312	  	  	 	328	  	  	 	334	  
		  	 	 	 	  	 	 	 	  	 	 	 	  				 		  	 	 	 	  	 	 	 	  	 	 	 
	 Total
	  	 	2,886	  	  	 	2,942	  	  	 	2,934	  	  				 	 Total
	  	 	11,455	  	  	 	11,305	  	  	 	11,772	  
		  	 	 	 	  	 	 	 	  	 	 	 	  				 		  	 	 	 	  	 	 	 	  	 	 	 

 Electric sales volume is primarily driven by general economic conditions, population and weather. Residential and commercial
electricity sales are seasonal, with Q1 and Q4 the strongest periods, reflecting colder weather, and fewer daylight hours in the winter season. 

NSPI’s residential load generally comprises individual homes, apartments and condominiums. Commercial customers include small retail operations,
large office and commercial complexes, and the province’s universities and hospitals. Industrial customers include manufacturing facilities and other large volume operations. Other electric consists of export sales, sales to municipal electric
utilities and revenues from street lighting. 
 Electric Margin 
 As noted above, all fuel costs are recoverable from customers through the FAM. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a period are
deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent period. The only effect on net earnings in relation to the recovery of fuel costs is the incentive component of the FAM with NSPI
retaining or absorbing 10% of the over or under-recovered amount less the difference between the incentive threshold and the base amount to a maximum of $5 million.
 NSPI’s electric margin is influenced by non-fuel revenues and the FAM incentive. NSPI’s electric margin is summarized in the following table: 

 

																					
	 millions of dollars
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 	  	2010	 	 	2009	 	 	2010	 	 	2009	 	  	2008	 
	 Electric revenue
	  	$	296.4	  	 	$	302.9	  	 	$	1,167.3	  	 	$	1,188.1	  	  	 	*	  
	 Fuel for generation and purchased power
	  	 	146.2	  	 	 	138.5	  	 	 	586.7	  	 	 	500.7	  	  	 	*	  
	 Fuel adjustment
	  	 	(24.0	) 	 	 	(10.6	) 	 	 	(99.0	) 	 	 	8.5	  	  	 	*	  
	 Fuel related foreign exchange (losses) gains
	  	 	(3.4	) 	 	 	(2.2	) 	 	 	(9.3	) 	 	 	3.0	  	  	 	*	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 
	 Electric margin
	  	$	170.8	  	 	$	172.8	  	 	$	670.3	  	 	$	681.9	  	  	 	*	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 

  

	*	Prior to the introduction of the FAM on January 1, 2009, electric margin was not broken into the components above. 


NSPI’s electric margin decreased $2.0 million to $170.8 million in Q4 2010 compared to $172.8 million in Q4 2009 primarily due to the recognition of
a FAM incentive expense compared to a recovery in 2009. For the year ended December 31, 2010, NSPI’s electric margin decreased $11.6 million to $670.3 million in 2010 compared to $681.9 million in 2009 due to lower residential load related
to warmer weather and the recognition of a FAM incentive expense compared to a recovery in 2009. 
  

																													
	 Q4 Electric Margin / MWh
	 	  	 	 	 YTD Electric Margin / MWh
	 
	 	  	2010	 	  	2009	 	  	2008	 	  	 	 	 	  	2010	 	  	2009	 	  	2008	 
	 Dollars per MWh
	  	$	59	  	  	$	59	  	  	 	*	  	  		 	 Dollars per MWh
	  	$	59	  	  	$	60	  	  	 	*	  

  

	*	Prior to the introduction of the FAM on January 1, 2009, electric margin was not broken into the components above. 


  
  

79 








 The change in average electric margin per MWh in 2010 compared to 2009 reflects a change in sales volume mix
and recognition of a FAM incentive expense compared to a recovery in 2009. 

  
  

80 








 Fuel for Generation and Purchased Power 
 Capacity 
 To ensure reliability of service, NSPI maintains a generating capacity greater
than firm peak demand. The total NSPI-owned generation capacity is 2,368 MW, which is supplemented by 186 MW contracted with IPPs. NSPI meets the planning criteria for reserve capacity established by the Maritime Control Area and the Northeast Power
Coordinating Council. 
 NSPI facilities continue to rank among the best in Canada on capacity related performance indicators. The high
availability and capability of low cost thermal generating stations provide lower cost energy to customers. In 2010, thermal plant availability was 87% compared to 82% in 2009. The increase in availability from 2009 reflects decreased maintenance
outages. Sustained high availability and low forced outage rates on low cost facilities are good indicators of sound maintenance and investment practices. 
 Fuel Expense 
  

																											
	 Q4 Production Volumes

GWh
	 	  	 YTD Production Volumes

GWh
	 
	 	  	2010	 	  	2009	 	  	2008	 	  	 	  	2010	 	  	2009	 	  	2008	 
	 Coal & petcoke
	  	 	2,049	  	  	 	2,069	  	  	 	2,177	  	  	 Coal & petcoke
	  	 	7,839	  	  	 	8,177	  	  	 	9,009	  
	 Natural gas
	  	 	438	  	  	 	534	  	  	 	249	  	  	 Natural gas
	  	 	2,275	  	  	 	1,612	  	  	 	1,258	  
	 Oil & diesel
	  	 	16	  	  	 	16	  	  	 	218	  	  	 Oil & diesel
	  	 	36	  	  	 	307	  	  	 	339	  
	 Renewable
	  	 	340	  	  	 	281	  	  	 	257	  	  	 Renewable
	  	 	1,017	  	  	 	1,065	  	  	 	1,068	  
	 Purchased power*
	  	 	315	  	  	 	335	  	  	 	296	  	  	 Purchased power*
	  	 	997	  	  	 	931	  	  	 	889	  
		  	 	 	 	  	 	 	 	  	 	 	 	  		  	 	 	 	  	 	 	 	  	 	 	 
	 Total
	  	 	3,158	  	  	 	3,235	  	  	 	3,197	  	  	 Total
	  	 	12,164	  	  	 	12,092	  	  	 	12,563	  
		  	 	 	 	  	 	 	 	  	 	 	 	  		  	 	 	 	  	 	 	 	  	 	 	 
		
	 *    Purchased power includes 132 GWh of renewables in 2010 (2009 – 51 GWh; 2008 – 44
GWh).
	       
	  	 *    Purchased power includes 355 GWh of renewables in 2010 (2009 – 149 GWh; 2008 –
148 GWh).
	       

		
	 Q4 Average Unit Fuel Costs
	 	  	 YTD Average Unit Fuel Costs
	 
	 	  	2010	 	  	2009	 	  	2008	 	  	 	  	2010	 	  	2009	 	  	2008	 
	 Dollars per MWh
	  	$	46	  	  	$	43	  	  	$	44	  	  	 Dollars per MWh
	  	$	48	  	  	$	41	  	  	$	38	  
		  	 	 	 	  	 	 	 	  	 	 	 	  		  	 	 	 	  	 	 	 	  	 	 	 

 Solid fuel is NSPI’s dominant fuel source, supplying approximately 64% (2009 – 68%) of NSPI’s annual energy.
Historically, solid fuels have had the lowest per unit fuel cost, after hydro and NSPI-owned wind production, which have no fuel cost component. Natural gas, oil, and purchased power are next, depending on the relative pricing of each. Economic
dispatch of the generating fleet brings the lowest cost options on stream first, with the result that the incremental cost of production increases as sales volume increases. 
 The average unit fuel costs increased in 2010 compared to 2009 mainly as a result of higher priced import coal and solid fuel commodity mix related to emission compliance. 

The average unit fuel costs increased in 2009 compared to 2008 mainly as a result of higher priced commodity contracts for coal and natural
gas.
 A substantial amount of NSPI’s fuel supply comes from international suppliers, and is subject to commodity price and foreign
exchange risk. NSPI manages exposure to commodity price risk utilizing a portfolio strategy, combining physical fixed-price fuel contracts and financial instruments providing fixed or maximum prices. Foreign exchange risk is managed through forward
and option contracts. Further details on NSPI’s fuel cost risk management strategies are included in the Business Risks section. Fuel contracts may be exposed to broader global conditions which may include impacts on delivery reliability and
price, despite contracted terms. 
 For the three months ended December 31, 2010, fuel for generation and purchased power increased $7.7
million to $146.2 million, compared to $138.5 million in Q4 2009. For the year ended December 31, 2010, fuel for generation and purchased power increased $86.0 million to $586.7 million compared to $500.7 million in 2009 and $471.4 million in
2008. 

  
  

81 








 Highlights of the changes are summarized in the following table: 

 

									
	 millions of dollars
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 Fuel for generation and purchased power – 2008
	  				 	$	471.4	  
	 Commodity price increases
	  				 	 	36.2	  
	 Decreased proceeds from the resale of natural gas
	  				 	 	10.3	  
	 Valuation of contract receivable (see discussion below)
	  				 	 	4.5	  
	 Decreased sales volume
	  				 	 	(22.2	) 
	 Mark-to-market on natural gas hedges not required in 2009 primarily due to decreased production volumes
	  				 	 	(0.7	) 
	 Changes in generation mix and plant performance
	  				 	 	(10.2	) 
	 Decreased hydro production
	  				 	 	1.8	  
	 Primarily solid fuel handling costs previously included in OM&G expenses
	  				 	 	10.7	  
	 Other
	  				 	 	(1.1	) 
		  	 	 	 	 	 	 	 
	 Fuel for generation and purchased power – 2009
	  	$	138.5	  	 	$	500.7	  
		  	 	 	 	 	 	 	 
	 Commodity price and volume increases
	  	 	0.4	  	 	 	34.5	  
	 Changes in generation mix and plant performance
	  	 	12.6	  	 	 	24.3	  
	 Solid fuel commodity mix and additives related to emission compliance
	  	 	0.8	  	 	 	25.3	  
	 Increased proceeds from the resale of natural gas
	  	 	(0.8	) 	 	 	(9.8	) 
	 Valuation of contract receivable (see discussion below)
	  	 	6.6	  	 	 	8.7	  
	 (Decreased) increased sales volume
	  	 	(5.1	) 	 	 	2.7	  
	 Increased hydro production
	  	 	(6.2	) 	 	 	(1.1	) 
	 Mark-to-market on natural gas hedges recognized in 2009 as they were no longer required due to decreased 2009 production
volumes
	  	 	1.5	  	 	 	2.2	  
	 Other
	  	 	(2.1	) 	 	 	(0.8	) 
		  	 	 	 	 	 	 	 
	 Fuel for generation and purchased power – 2010
	  	$	146.2	  	 	$	586.7	  
		  	 	 	 	 	 	 	 

 The valuation of the contract receivable from a natural gas supplier required NSPI to utilize a combination of historical
and future natural gas prices. NSPI uses market-based forward indices when determining future prices. Future prices can change from period to period which will cause a corresponding change in the value of the contract receivable. The natural gas
supply contract settled in November 2010. 
 Fuel Adjustment 
 The fuel adjustment related to the FAM includes the effect of fuel costs in both the current period and the preceding year. The difference between actual fuel costs and amounts recovered
from customers in the current period is included in the fuel adjustment. This amount, less the incentive component, is deferred to a FAM regulatory asset in “Other assets” or a FAM regulatory liability in “Other Liabilities”. The
FAM regulatory asset or liability includes amounts recognized as a fuel adjustment and associated interest included in “Financing charges”. Also included in the 2010 fuel adjustment is the rebate to customers of over recovered fuel costs
from 2009. 
 Details of the fuel adjustment deferral related to the FAM are summarized in the following table: 

 

													
	 	  	Year ended
December 31	 
	 millions of dollars
	  	2010	 	 	2009	 	 	2008	 
	 FAM payable – Balance at January 1
	  	$	(9.9	) 	 	 	*	  	 	 	*	  
	 Under (over) recovery of current period fuel costs
	  	 	80.3	  	 	$	(9.9	) 	 	 	*	  
	 Rebate to customers from prior year
	  	 	22.5	  	 	 	—  	  	 	 	*	  
		  	 	 	 	 	 	 	 	 	 	 	 
	 FAM receivable (payable) – Balance at December 31
	  	$	92.9	  	 	$	(9.9	) 	 	 	*	  
		  	 	 	 	 	 	 	 	 	 	 	 

  

	*	The fuel adjustment mechanism came into effect on January 1, 2009. 


  
  

82 








 In December 2010, as part of the FAM regulatory process, the UARB directed NSPI to recover the rate increase
approved by the UARB for the reset of 2011 fuel costs and the projected under recovery from prior years from customers over three years, with 50% of the rate increase to be recovered in 2011, 30% in 2012 and 20% in 2013. 

NSPI has recognized a future income tax expense related to the fuel adjustment based on its applicable statutory income tax rate. The FAM regulatory
asset or liability includes amounts recognized as a fuel adjustment and associated interest included in “Financing charges”. As at December 31, 2010, NSPI’s future income tax liability related to the FAM was $29.2 million (2009
– asset of $3.4 million). 
 Operating, Maintenance and General 
 OM&G expenses increased $6.6 million to $65.0 million in Q4 2010 compared to $58.4 million in Q4 2009 and increased $22.4 million to $237.5 million for the year ended December 31, 2010 compared
to $215.1 million in 2009 primarily due to increased pension and storm costs as well as customer service initiatives. 
 OM&G expenses
increased $11.4 million to $215.1 million for the year ended December 31, 2009 compared to $203.7 million in 2008 primarily due to increased storm costs, system reliability spending and program costs associated with customer and new business
initiatives, partially offset by lower pension expense. 
 Provincial Grants and Taxes 

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

Depreciation and Amortization 

Depreciation and amortization expense increased $3.1 million to $39.9 in Q4 2010 compared to $36.8 million in Q4 2009 and increased $6.9 million to $150.8
for the year ended December 31, 2010 compared to $143.9 million in 2009 primarily due to increased property, plant and equipment. 

Depreciation and amortization expense increased $10.3 million to $143.9 for the year ended December 31, 2009 compared to $133.6 million in 2008
primarily due to the inclusion of year-three depreciation rates commencing on January 1, 2009 as approved by the UARB in its November 5, 2008 decision. 
 Regulatory Amortization 
 Regulatory amortization increased $9.0 million to $23.7 million in
Q4 2010 compared to $14.7 million in Q4 2009 and increased $9.7 million to $36.9 million for the year ended December 31, 2010 compared to $27.2 million in 2009. This increase is due primarily to a $14.5 million deferral of certain tax benefits
arising in 2010 related to renewable energy projects, as approved by the UARB, partially offset by a reduction in amortization of the pre-2003 income tax regulatory asset resulting from the UARB’s 2009 ROE decision of $4.8 million in 2010 (2009
– $10.0 million). The 2009 ROE decision allows NSPI to recognize additional amortization amounts in current periods and to reduce amortization in future periods to provide flexibility relating to customer rate requirements. 

Regulatory amortization increased $9.5 million to $27.2 million for the year ended December 31, 2009 compared to $17.7 million in 2008 due primarily
to additional amortization of the pre-2003 income tax regulatory asset resulting from the UARB’s ROE decision noted above. 
 Other
Revenue 
 Other revenue, which consists of miscellaneous revenues and commercial settlements, has remained relatively unchanged for the
quarter and year ended December 31, 2010 compared to 2009 and 2008. 

  
  

83 








 Financing Charges 
 Financing charges decreased $0.5 million to $32.8 million in Q4 2010 compared to $33.3 million in Q4 2009 and increased $11.1 million to $125.8 million for the year ended December 31, 2010 compared
to $114.7 million in 2009 primarily due to higher foreign exchange costs, recovered through the FAM, and increased borrowing costs, partially offset by increased AFUDC related to increased capital spending. 

Financing charges increased $7.9 million to $114.7 million for the year ended December 31, 2009 compared to $106.8 million in 2008 primarily due to
lower foreign exchange gains in 2009 compared to 2008. In 2009, NSPI recorded income tax refund interest of $3.0 million which was received as a result of NSPI amending its 1999 to 2003 corporate income tax
returns. This refund interest was recorded as a reduction of “Financing charges”. 
 Income Taxes 

NSPI uses the future income tax method of accounting for income taxes. In accordance with NSPI’s rate-regulated accounting policy as approved by the
UARB, NSPI defers any future income taxes to a regulatory asset or liability where the future income taxes are expected to be included in future rates. 
 In 2010, NSPI was subject to provincial capital tax (0.125%), corporate income tax (34%) and Part VI.1 tax relating to preferred dividends (40%). NSPI also receives a reduction in its corporate
income tax otherwise payable related to the Part VI.1 tax deduction (41% of preferred dividends). 
 Income taxes decreased $21.7 million to a
$13.3 million income tax recovery in Q4 2010 compared to $8.4 million income tax expense in Q4 2009 and decreased $59.6 million to a $17.4 million recovery for the year ended December 31, 2010 compared to $42.2 million income tax expense in
2009 primarily due to decreased earnings before income taxes, deductions related to renewable investments and a change in the expected benefit from other accelerated tax deductions. 
 Income taxes decreased $4.4 million to $42.2 million for the year ended December 31, 2009 compared to $46.6 million in 2008 primarily due to decreased taxable income and a lower statutory rate in
2009 compared to 2008, partially offset by a recovery of income taxes in 2008 relating to a prior year. 
 In 2010, NSPI revised its estimate of
the expected benefit from accelerated tax deductions. The impact for the three months and twelve months ended December 31, 2010 was to reduce income tax expense by approximately $8.0 million and $14.0 million respectively. In accordance with
rate-regulated accounting, the future income tax implications of this change in estimate have been deferred to a regulatory asset in “Other assets”. This change in accounting estimate has been accounted for on a prospective basis.


  
  

84 








 BANGOR HYDRO 
 All amounts in the Bangor Hydro section are reported in USD unless otherwise stated. 

Overview 
 Bangor Hydro’s core
business is the transmission and distribution of electricity. Bangor Hydro is the second largest electric utility in Maine. Electricity generation is deregulated in Maine, and several suppliers compete to provide customers with the commodity that is
delivered through the Bangor Hydro T&D network. Bangor Hydro owns and operates approximately 1,000 kilometers of transmission facilities, and 7,200 kilometers of distribution facilities. Bangor Hydro currently has approximately $150 million of
additional transmission development in progress. Bangor Hydro’s workforce is approximately 290 people. 
 In addition to T&D assets,
Bangor Hydro has net regulatory assets (stranded costs), which arose through the restructuring of the electricity industry in the state in the late 1990s, and as a result of rate and accounting orders issued by its regulator. Bangor Hydro’s net
regulatory assets primarily include the costs associated with the restructuring of an above-market power purchase contract, and the unamortized portion on its loss on the sale of its investment in the Seabrook nuclear facility. Unlike T&D
operational assets, which are generally sustained with new investment, the net stranded cost regulatory asset pool diminishes over time as elements are amortized through charges to earnings and recovered through rates. These net regulatory assets
total approximately $77.5 million at December 31, 2010 (2009 – $76.6 million) or 10% of Bangor Hydro’s net asset base (2009 – 11%). 
 Approximately 44% of Bangor Hydro’s electric revenue represents distribution service, 45% is associated with transmission service and 11% relates to stranded cost recoveries. The rates for each
element are established in distinct regulatory proceedings. Bangor Hydro’s distribution operations and stranded costs are regulated by the MPUC. The transmission operations are regulated by the FERC. 

Bangor Hydro operates under a traditional cost-of-service regulatory structure. In December 2007, the MPUC approved an increase of approximately 2% in
distribution rates effective January 1, 2008. The allowed ROE used in setting these distribution rates was 10.2%, with a common equity component of 50%. 
 Transmission rates are set by the FERC annually on June 1, based upon a formula that utilizes prior year actual transmission investments and expenses, adjusted for current year forecasted
transmission investments and expenses. In 2009, Bangor Hydro implemented this forward-looking rate formula for its local transmission investments, replacing an approach which had resulted in a lag in the recovery of transmission investments and
costs. The allowed ROE for transmission operations ranges from 11.14% for low voltage local transmission up to 12.64% for high voltage regionally-funded transmission developed as a result of the regional system plan. 

In December 2007, the MPUC issued an order approving an approximate 39% reduction in stranded cost rates for the three-year period beginning
March 1, 2008. The reduced stranded cost revenues are offset for the most part by decreased regulatory amortizations, decreased purchased power costs, and increased resale of purchased power. The allowed ROE used in setting the new stranded
cost rates was 8.5%. Prior to that, stranded cost rates provided for an allowed ROE of 10%. On June 1, 2009, Bangor Hydro further reduced its stranded cost rates for a one year period by approximately 15% to reflect an over-collection of
certain stranded cost revenues and expenses under a full reconciliation rate mechanism. 

  
  

85 








 Review of 2010 
  

																					
	 Bangor Hydro
 millions of USD (except earnings per common share)
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 	  	2010	 	 	2009	 	 	2010	 	 	2009	 	 	2008	 
	 T&D electric revenues
	  	$	28.7	  	 	$	25.9	  	 	$	109.0	  	 	$	102.8	  	 	$	97.6	  
	 Resale of purchased power
	  	 	4.6	  	 	 	4.9	  	 	 	18.3	  	 	 	18.9	  	 	 	20.4	  
	 Transmission pool revenue
	  	 	4.6	  	 	 	3.0	  	 	 	21.5	  	 	 	14.0	  	 	 	16.5	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total revenue
	  	 	37.9	  	 	 	33.8	  	 	 	148.8	  	 	 	135.7	  	 	 	134.5	  
	 Fuel for generation and purchased power
	  	 	7.9	  	 	 	7.6	  	 	 	31.0	  	 	 	29.4	  	 	 	32.2	  
	 Operating, maintenance and general
	  	 	10.2	  	 	 	7.4	  	 	 	36.3	  	 	 	30.9	  	 	 	28.8	  
	 Property taxes
	  	 	1.6	  	 	 	1.7	  	 	 	6.8	  	 	 	6.3	  	 	 	5.4	  
	 Depreciation
	  	 	4.3	  	 	 	4.0	  	 	 	16.7	  	 	 	16.0	  	 	 	15.3	  
	 Regulatory amortization
	  	 	0.9	  	 	 	1.6	  	 	 	4.2	  	 	 	7.4	  	 	 	10.1	  
	 Other
	  	 	(0.5	) 	 	 	(0.5	) 	 	 	(2.3	) 	 	 	(2.6	) 	 	 	(3.8	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Earnings before financing charges and income taxes
	  	 	13.5	  	 	 	12.0	  	 	 	56.1	  	 	 	48.3	  	 	 	46.5	  
	 Financing charges
	  	 	1.6	  	 	 	2.2	  	 	 	7.0	  	 	 	10.4	  	 	 	11.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Earnings before income taxes
	  	 	11.9	  	 	 	9.8	  	 	 	49.1	  	 	 	37.9	  	 	 	35.4	  
	 Income taxes
	  	 	4.3	  	 	 	3.3	  	 	 	18.2	  	 	 	13.5	  	 	 	13.9	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – USD
	  	$	7.6	  	 	$	6.5	  	 	$	30.9	  	 	$	24.4	  	 	$	21.5	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – CAD
	  	$	7.8	  	 	$	7.0	  	 	$	31.9	  	 	$	27.5	  	 	$	23.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Contribution to consolidated earnings per common share – CAD
	  	$	0.07	  	 	$	0.06	  	 	$	0.28	  	 	$	0.24	  	 	$	0.21	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Net earnings weighted average foreign exchange rate – CAD /USD
	  	$	1.03	  	 	$	1.08	  	 	$	1.03	  	 	$	1.13	  	 	$	1.07	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 Bangor Hydro’s contribution to consolidated net earnings applicable to common shares increased by 

$1.1 million to $7.6 million in Q4 2010 compared to $6.5 million in Q4 2009. Annual contribution to consolidated net earnings applicable to common shares
increased by $6.5 million to $30.9 million compared to $24.4 million in 2009 and $21.5 million in 2008. Highlights of the earnings changes are summarized in the following table: 

 

									
	 millions of dollars
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 Contribution to consolidated net earnings applicable to common shares – 2008
	  				 	$	21.5	  
	 Increased T&D electric revenues due to transmission rate increases and additional transmission revenues from wind
generation
	  				 	 	5.2	  
	 Lower net transmission pool revenue due to increased regional charges
	  				 	 	(2.5	) 
	 Increased OM&G expenses due to increased storm, regulatory and labour costs
	  				 	 	(2.1	) 
	 Decreased financing charges primarily due to lower short-term interest rates
	  				 	 	0.7	  
	 Other
	  				 	 	1.6	  
		  	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – 2009
	  	$	6.5	  	 	$	24.4	  
	 Increased electric operating revenues due primarily to transmission rate increases in 2009 and 2010
	  	 	2.8	  	 	 	6.2	  
	 Higher transmission pool revenue due to the recovery of the increase in regionally-funded transmission
investments
	  	 	1.6	  	 	 	7.5	  
	 Increased OM&G expenses due to higher pension, post-retirement benefits and payroll costs as well as lower capitalized
overheads
	  	 	(2.8	) 	 	 	(5.4	) 
	 Decreased financing charges due to higher AFUDC related to capital investment
	  	 	0.6	  	 	 	3.4	  
	 Increased income taxes due to higher earnings in 2010
	  	 	(1.0	) 	 	 	(4.7	) 
	 Other
	  	 	(0.1	) 	 	 	(0.5	) 
		  	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – 2010
	  	$	7.6	  	 	$	30.9	  
		  	 	 	 	 	 	 	 


  
  

86 








 Bangor Hydro’s contribution to consolidated net earnings applicable to common shares – CAD
decreased $0.4 million in Q4 2010 compared to Q4 2009 and $3.1 million in 2010 compared to 2009 due to the impact of the stronger CAD. 

Electric Revenue 
  

																											
	 Q4 Electric Sales Volumes

GWh
	  	 	 	  	 	 	  	 	 	  	 YTD Electric Sales Volumes
 GWh
	  	 	 	  	 	 	  	 	 
	 	  	2010	 	  	2009	 	  	2008	 	  	 	  	2010	 	  	2009	 	  	2008	 
	 Residential
	  	 	155	  	  	 	154	  	  	 	155	  	  	 Residential
	  	 	591	  	  	 	591	  	  	 	591	  
	 Commercial
	  	 	147	  	  	 	145	  	  	 	145	  	  	 Commercial
	  	 	594	  	  	 	588	  	  	 	604	  
	 Industrial
	  	 	84	  	  	 	78	  	  	 	90	  	  	 Industrial
	  	 	363	  	  	 	342	  	  	 	350	  
	 Other
	  	 	3	  	  	 	3	  	  	 	2	  	  	 Other
	  	 	12	  	  	 	12	  	  	 	10	  
		  	 	 	 	  	 	 	 	  	 	 	 	  		  	 	 	 	  	 	 	 	  	 	 	 
	 Total
	  	 	389	  	  	 	380	  	  	 	392	  	  	 Total
	  	 	1,560	  	  	 	1,533	  	  	 	1,555	  
		  	 	 	 	  	 	 	 	  	 	 	 	  		  	 	 	 	  	 	 	 	  	 	 	 
								
	 Q4 Electric Revenues
 millions of dollars
	  	 	 	  	 	 	  	 	 	  	 YTD Electric Revenues
 millions of dollars
	  	 	 	  	 	 	  	 	 
	 	  	2010	 	  	2009	 	  	2008	 	  	 	  	2010	 	  	2009	 	  	2008	 
	 Residential
	  	$	13.6	  	  	$	12.6	  	  	$	12.8	  	  	 Residential
	  	$	50.6	  	  	$	48.3	  	  	$	47.6	  
	 Commercial
	  	 	10.3	  	  	 	9.1	  	  	 	8.7	  	  	 Commercial
	  	 	39.4	  	  	 	35.9	  	  	 	34.5	  
	 Industrial
	  	 	2.9	  	  	 	2.4	  	  	 	3.0	  	  	 Industrial
	  	 	11.5	  	  	 	10.2	  	  	 	10.0	  
	 Other
	  	 	1.9	  	  	 	1.8	  	  	 	1.4	  	  	Other	  	 	7.5	  	  	 	8.4	  	  	 	5.5	  
		  	 	 	 	  	 	 	 	  	 	 	 	  		  	 	 	 	  	 	 	 	  	 	 	 
	 Total
	  	$	28.7	  	  	$	25.9	  	  	$	25.9	  	  	Total	  	$	109.0	  	  	$	102.8	  	  	$	97.6	  
		  	 	 	 	  	 	 	 	  	 	 	 	  		  	 	 	 	  	 	 	 	  	 	 	 
								
	 Q4 Electric Average Revenue / MWh
	  	 	 	  	 	 	  	 	 	  	 YTD Electric Average Revenue / MWh
	  	 	 	  	 	 	  	 	 
	 	  	2010	 	  	2009	 	  	2008	 	  	 	  	2010	 	  	2009	 	  	2008	 
	 Dollars per MWh
	  	$	74	  	  	$	68	  	  	$	66	  	  	 Dollars per MWh
	  	$	70	  	  	$	67	  	  	$	63	  
		  	 	 	 	  	 	 	 	  	 	 	 	  		  	 	 	 	  	 	 	 	  	 	 	 

 The changes in average revenue per MWh in 2010 compared to 2009 reflect increases in transmission rates on June 1,
2010, November 1, 2009 and June 1, 2009, partially offset by the impact of a stranded cost rate decrease on June 1, 2009. 

Electric sales volume is primarily driven by general economic conditions, population and weather. Electric sales pricing in Maine is regulated, and
therefore changes in accordance with regulatory decisions. 
 Electric revenues increased by $2.8 million to $28.7 million in Q4 2010 compared
to $25.9 million in Q4 2009 and increased $6.2 million to $109.0 million for the year ended December 31, 2010 compared to $102.8 million for 2009 due to increased transmission rates, including the impact of moving to a forward-looking rate
formula, and increased commercial and industrial load, partially offset by a reduction in stranded cost rates. 
 Electric revenues increased
$5.2 million to $102.8 million for the year ended December 31, 2009 compared to $97.6 million for 2008 due to increased transmission rates, including the impact of moving to a forward-looking rate formula in 2009, partially offset by a
reduction in stranded cost rates. 
 Resale of Purchased Power, and Fuel for Generation and Purchased Power 

Bangor Hydro has several above-market purchase power contracts pre-dating the Maine market restructuring. Power purchased under these arrangements is
resold to a third party at market rates as determined through a bid process administered and approved by the MPUC. The difference between the cost of the power purchased under these arrangements and the revenue collected from the third party is
recovered through stranded cost rates under a full reconciliation rate mechanism. 

  
  

87 








 Transmission Pool Revenue 
 Bangor Hydro recovers the cost of its regionally-funded transmission infrastructure investment, through transmission pool revenue based on a regional formula that is updated on June 1 of each year.
Transmission pool revenue, less transmission infrastructure investment charges, is recovered from the customers of member utilities of the New England Power Pool (“NEPOOL”). 
 Transmission pool revenue increased by $1.6 million to $4.6 million in Q4 2010 compared to $3.0 million in Q4 2009 and increased $7.5 million to $21.5 million for the year ended December 31, 2010
compared to $14.0 million for 2009 due primarily to increased revenue received associated with an increase in Bangor Hydro’s regionally funded transmission investments in 2010. 
 Transmission pool revenue decreased $2.5 million to $14.0 million for the year ended December 31, 2009 compared to $16.5 million for 2008 due to greater regional charges related to increased regional
transmission investments. 
 Regulatory Amortization 
 Regulatory amortization has a minimal impact on earnings as a result of the stranded cost regulatory reconciliation mechanism as provided for by a MPUC ruling as noted previously. 

Financing Charges 
 Financing charges
decreased $0.6 million to $1.6 million in Q4 2010 compared to $2.2 million in Q4 2009 and decreased $3.4 million to $7.0 million for the year ended December 31, 2010, compared to $10.4 million in 2009 primarily due to lower short-term interest
rates in 2010 and increased AFUDC. 
 Financing charges decreased $0.7 million to $10.4 million for the year ended December 31, 2009,
compared to $11.1 million in 2008 primarily due to lower short-term interest rates in 2009. 
 Income Taxes 

Bangor Hydro uses the future income tax method of accounting for income taxes. 
 Bangor Hydro is subject to corporate income tax at the statutory rate of 40.8% (combined federal and state income tax rate). 

  
  

88 








 PIPELINES 
 Overview 
 Pipelines is composed of the company’s investments in Brunswick Pipeline, a
wholly-owned subsidiary, along with its 12.9% interest in M&NP. 
 Brunswick Pipeline is a 145-kilometre pipeline delivering natural gas
from the CanaportTM LNG import terminal near Saint John, New Brunswick, to markets in the northeastern United States. The pipeline, which received National Energy Board (“NEB”) approval for shipping gas in January 2009 and went into
service on July 16, 2009, transports re-gasified LNG for Repsol Energy Canada under a 25-year firm service agreement. The NEB, which regulates Brunswick Pipeline, has classified it as a Group 2 pipeline. 

The company acquired a 12.9% interest in M&NP in 1999. M&NP is a $2 billion, 1,400-kilometre pipeline which transports natural gas from offshore
Nova Scotia to markets in Maritime Canada and the northeastern United States. 
 Review of 2010 

 

																					
	 Pipelines
 millions of dollars
	  	Three months ended
December 
31	 	  	Year ended
December 31	 
	 	  	2010	 	  	2009	 	  	2010	 	  	2009	 	  	2008	 
	 Brunswick Pipeline
	  				  				  				  				  			
	 Finance income from direct financing lease
	  	$	13.7	  	  	$	15.2	  	  	$	56.5	  	  	$	25.3	  	  	 	—  	  
	 AFUDC
	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	18.8	  	  	$	15.6	  
	 Financing charges
	  	 	7.8	  	  	 	8.8	  	  	 	30.7	  	  	 	30.1	  	  	 	12.4	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Brunswick Pipeline net earnings
	  	 	5.9	  	  	 	6.4	  	  	 	25.8	  	  	 	14.0	  	  	 	3.2	  
	 M&NP net earnings
	  	 	2.9	  	  	 	2.0	  	  	 	9.2	  	  	 	10.2	  	  	 	12.2	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Contribution to consolidated net earnings applicable to common shares
	  	$	8.8	  	  	$	8.4	  	  	$	35.0	  	  	$	24.2	  	  	$	15.4	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Contribution to consolidated earnings per common share
	  	$	0.08	  	  	$	0.07	  	  	$	0.31	  	  	$	0.22	  	  	$	0.14	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 

 Pipelines’ contribution to consolidated net earnings applicable to common shares increased $0.4 million to $8.8 million
in Q4 2010 compared to $8.4 million in Q4 2009. Annual contribution to consolidated net earnings applicable to common shares increased $10.8 million to $35.0 million in 2010 compared to $24.2 million in 2009 and $15.4 million in 2008. 

  
  

89 








 Highlights of the earnings changes are summarized in the following table: 

 

									
	 millions of dollars
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 Contribution to consolidated net earnings applicable to common shares – 2008
	  				 	$	15.4	  
	 Brunswick Pipeline – Financing income from the pipeline as it became operational in July 2009
	  				 	 	25.3	  
	 Brunswick Pipeline – Increased AFUDC on construction of the pipeline prior to the pipeline commencing
service
	  				 	 	3.2	  
	 Brunswick Pipeline – Increased intercompany financing charges related to capital spending
	  				 	 	(17.7	) 
	 M&NP – Net earnings decrease
	  				 	 	(2.0	) 
		  	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – 2009
	  	$	8.4	  	 	$	24.2	  
	 Brunswick Pipeline – Financing income from the pipeline as it became operational in July 2009
	  	 	(1.5	) 	 	 	31.2	  
	 Brunswick Pipeline – Cessation of AFUDC as the pipeline became operational
	  	 	—  	  	 	 	(18.8	) 
	 M&NP – Net earnings increase (decrease)
	  	 	0.9	  	 	 	(1.0	) 
	 Other
	  	 	1.0	  	 	 	(0.6	) 
		  	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – 2010
	  	$	8.8	  	 	$	35.0	  
		  	 	 	 	 	 	 	 

 Maritimes & Northeast Pipeline 
 Equity earnings for M&NP increased by $0.9 million to $2.9 million in Q4 2010 compared to $2.0 million in Q4 2009. For the year ended December 31, 2010, equity earnings decreased $1.0 million to
$9.2 million compared to $10.2 million in 2009 due to increased financing charges on the US portion of the pipeline as a result of debt recapitalization and the recognition of a portion of the EnCana Marketing (USA) Inc. (“Encana”)
settlement in the first half of 2009, combined with a stronger Canadian dollar in 2010 compared to 2009. 
 In May 2009, M&NP recapitalized
the US portion of the pipeline by issuing a $500 million USD long-term debt. The net proceeds of the debt issuance were distributed to the partners. Emera’s portion of the net proceeds was $64.2 million USD ($73.8 million CAD), and was recorded
as a return of capital from M&NP. 
 Income Taxes 
 Brunswick Pipeline uses the future income tax method of accounting for income taxes. In accordance with rate-regulated accounting, Brunswick Pipeline defers any future income taxes to a regulatory asset
or liability where the future income taxes are expected to be included in the future tolls. M&NP equity earnings are recorded net of tax. 

  
  

90 








 OTHER, INCLUDING CORPORATE COSTS 
 Other, Including Corporate Costs, includes Emera Energy; Emera Utility Services; Caribbean investments; and corporate costs and other. 
 Emera Energy includes: 
  

	 	•	 	 Emera Energy Services Inc., a physical energy business which purchases and sells natural gas and electricity and provides related energy asset
management services. 


  

	 	•	 	 Bayside Power, a 260-MW gas-fired merchant electricity generating facility in Saint John, New Brunswick. 



 

	 	•	 	 Emera’s 50% joint venture ownership of Bear Swamp, a 600-MW pumped storage hydro-electric facility in northern Massachusetts.



 Emera Utility Services is a utility services contractor. 
 Caribbean Investments include: 
  

	 	•	 	 An effective direct interest of 50% in GBPC, a vertically-integrated electric utility on Grand Bahama Island and a 30.4% indirect interest in GBPC
through ICD Utilities Limited. 


  

	 	•	 	 A 38% interest in LPH, the parent company of BLPC, the electric utility on the island of Barbados. In January 2011, Emera’s interest in LPH
increased to 79.9%. 


  

	 	•	 	 A 19% interest in Lucelec, a vertically-integrated electric utility on the island of St. Lucia. 



Corporate and other costs pertain to certain Emera-wide functions such as executive management, strategic planning, treasury services, financial
reporting, tax planning, business development, corporate governance. Corporate and other costs also include financing charges and income taxes associated with corporate activities. 
 Review of 2010 
 Emera Energy and Emera Utility Services’ operations are reported on
earnings before financing charges and income taxes (“EBIT”). Caribbean operations, which include GBPC, LPH and Lucelec, are reported on an equity earnings basis. 

 

																					
	 Other
 millions of dollars (except earnings per common share)
	  	Three months ended
December 
31	 	  	Year ended
December 31	 
	 	  	2010	 	 	2009	 	  	2010	 	 	2009	 	  	2008	 
	 Emera Energy
	  	$	(1.0	) 	 	$	14.8	  	  	$	5.7	  	 	$	20.7	  	  	$	15.0	  
	 Emera Utility Services
	  	 	2.9	  	 	 	0.3	  	  	 	7.0	  	 	 	1.8	  	  	 	3.1	  
	 Caribbean
	  	 	1.7	  	 	 	0.2	  	  	 	7.0	  	 	 	2.9	  	  	 	2.4	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
		  	 	3.6	  	 	 	15.3	  	  	 	19.7	  	 	 	25.4	  	  	 	20.5	  
	 Financing charges
	  	 	1.1	  	 	 	0.8	  	  	 	3.2	  	 	 	5.2	  	  	 	10.3	  
	 Income taxes
	  	 	(0.8	) 	 	 	5.6	  	  	 	0.4	  	 	 	5.9	  	  	 	6.7	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
	 Contribution to consolidated net earnings applicable to common shares
	  	$	3.3	  	 	$	8.9	  	  	$	16.1	  	 	$	14.3	  	  	$	3.5	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
	 Bear Swamp after-tax mark-to-market adjustment
	  	 	(2.6	) 	 	 	3.2	  	  	 	(8.6	) 	 	 	0.7	  	  	 	(4.8	) 
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
	 Contribution to consolidated net earnings, absent the Bear Swamp after-tax mark-to-market adjustment
	  	$	5.9	  	 	$	5.7	  	  	$	24.7	  	 	$	13.6	  	  	$	8.3	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
	 Contribution to consolidated net earnings per common share
	  	 	0.03	  	 	$	0.07	  	  	$	0.14	  	 	$	0.11	  	  	$	0.01	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 
	 Contribution to consolidated net earnings per common share, absent the Bear Swamp after-tax
mark-to-market adjustment
	  	$	0.06	  	 	$	0.04	  	  	$	0.22	  	 	$	0.10	  	  	$	0.06	  
		  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 


  

			
	91









 The total contribution of Other to consolidated net earnings applicable to common shares decreased $5.6
million to $3.3 million in Q4 2010 compared to $8.9 million in Q4 2009. Annual contribution to consolidated net earnings applicable to common shares increased $1.8 million to $16.1 million in 2010 compared to $14.3 million in 2009 and $3.5 million
in 2008. 
 Highlights of the earnings changes are summarized in the following table: 

 

									
	 millions of dollars
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 Contribution to consolidated net earnings applicable to common shares – 2008
	  				 	$	3.5	  
	 Emera Energy – Increased earnings primarily due to favorable changes in Bear Swamp’s mark-to-market, and the
acquisition of Bayside in September 2009, partially offset by higher power costs in Bear Swamp and reduced transportation mitigation opportunities in Energy Services
	  				 	 	5.7	  
	 Emera Utility Services – Decreased earnings reflecting project start dates being delayed into 2010 and unfavourable market
conditions
	  				 	 	(1.3	) 
	 Decreased financing charges primarily due to lower interest rates in Bear Swamp and decreased average external
debt
	  				 	 	5.1	  
	 Other
	  				 	 	1.3	  
		  	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – 2009
	  	$	8.9	  	 	$	14.3	  
	 Emera Energy – Decreased earnings due primarily to Bear Swamp’s mark-to-market loss, its lower earnings and the
stronger CAD, partially offset by improved Emera Energy Services Inc. results
	  	 	(15.8	) 	 	 	(15.0	) 
	 Emera Utility Services – Increased earnings due primarily to the successful completion of large construction projects and
the expansion of the communications business
	  	 	2.6	  	 	 	5.2	  
	 Caribbean – Increased equity earnings due primarily to LPH acquisition in May 2010
	  	 	1.5	  	 	 	4.1	  
	 Decreased financing charges year-to-date due primarily to lower interest expense due to lower LIBOR rates in 2010 and higher
foreign exchange losses in 2009
	  	 	(0.3	) 	 	 	2.0	  
	 Decreased income taxes due primarily to decreased earnings in Emera Energy
	  	 	6.4	  	 	 	5.5	  
		  	 	 	 	 	 	 	 
	 Contribution to consolidated net earnings applicable to common shares – 2010
	  	$	3.3	  	 	$	16.1	  
		  	 	 	 	 	 	 	 

 Bear Swamp Mark-to-Market Adjustment 
 Bear Swamp has an agreement to supply energy and capacity to the Long Island Power Authority (“LIPA”) through to 2021. Bear Swamp has contracted with its joint venture partner to provide the
power necessary to produce the requirements of the LIPA contract. One of the contracts between Bear Swamp and Emera is marked-to-market through earnings, as it does not meet the stringent accounting requirements for hedge accounting. 

  
  

92 








 As at December 31, 2010, the fair value of the contract was a net liability of $8.2 million (December
31, 2009 – $6.2 million net asset). The fair value of this derivative is subject to market volatility of power prices and will reverse over the life of the agreement. 
 Income Taxes 
 GBPC, LPH and Lucelec’s equity earnings are recorded net of tax.
Variations in income tax expense are largely affected by earnings and foreign exchange fluctuations, along with changes in the statutory tax rate. 
 Income taxes decreased $6.4 million to a $0.8 million income tax recovery in Q4 2010 compared to $5.6 million income tax expense in Q4 2009 and decreased $5.5 million to $0.4 million income tax expense
for the year ended December 31, 2010 compared to a $5.9 million income tax expense in 2009 primarily due to a decrease in earnings in Emera Energy. 
 Income taxes decreased $0.8 million to $5.9 million for the year ended December 31, 2009 compared to $6.7 million in 2008. 
 Corporate Costs and Other 
  

																					
	 Corporate costs and other

millions of dollars (except earnings per common share)
	  	Three months ended
December 
31	 	 	Year ended
December 31	 
	 	  	2010	 	 	2009	 	 	2010	 	 	2009	 	 	2008	 
	 Revenue
	  	$	7.7	  	 	$	8.7	  	 	$	30.6	  	 	$	30.0	  	 	$	12.4	  
	 Corporate costs
	  	 	3.8	  	 	 	9.2	  	 	 	22.9	  	 	 	21.8	  	 	 	15.4	  
	 Financing charges
	  	 	8.3	  	 	 	8.8	  	 	 	32.2	  	 	 	22.3	  	 	 	10.5	  
	 Income taxes
	  	 	(3.4	) 	 	 	(5.1	) 	 	 	(14.4	) 	 	 	(14.5	) 	 	 	(10.0	) 
	 Preferred shares dividends
	  	 	—  	  	 	 	—  	  	 	 	3.1	  	 	 	—  	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total corporate (costs) recovery and other
	  	$	(1.0	) 	 	$	(4.2	) 	 	$	(13.2	) 	 	$	0.4	  	 	$	(3.5	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 Revenue 

Revenue, which consists of intercompany interest from Brunswick Pipeline, has remained relatively unchanged for Q4 2010 compared to Q4 2009 and for the
year ended December 31, 2010 compared to 2009. 
 Revenue increased $17.6 million to $30.0 million for the year ended December 31,
2009, compared to $12.4 million in 2008 due to the financing of Brunswick Pipeline. 
 Corporate Costs 

Corporate costs decreased by $5.4 million to $3.8 million in Q4 2010 compared to $9.2 million in Q4 2009 due primarily to deferral of business development
costs, partially offset by an increase in deferred compensation costs. For the year ended December 31, 2010, corporate costs has remained relatively unchanged compared to 2009. 
 Corporate costs increased $6.4 million to $21.8 million for the year ended December 31, 2009 compared to $15.4 million in 2008 due primarily to an increase in business development and deferred
compensation costs. 
 Financing Charges 
 Financing charges decreased $0.5 million to $8.3 million in Q4 2010 compared to $8.8 million in Q4 2009 and increased $9.9 million to $32.2 million for the year ended December 31, 2010 compared to
$22.3 million in 2009 due primarily to higher interest rates and higher debt levels to finance acquisitions. 

  
  

93 








 Financing charges increased $11.8 million to $22.3 million for the year ended December 31, 2009
compared to $10.5 million in 2008 due primarily to increased debt to finance the construction of Brunswick Pipeline. 
 Income Taxes

 All businesses included in Other follow the future income taxes method of accounting for income taxes. Taxes are recognized on pre-tax
income. 
 Income taxes recovery decreased $1.7 million to $3.4 million in Q4 2010 compared to $5.1 million in Q4 2009 primarily due to
decreased corporate costs and remained relatively unchanged for the year ended December 31, 2010 compared to 2009. 
 Income taxes recovery
increased $4.5 million to $14.5 million for the year ended December 31, 2009 compared to $10.0 million in 2008 due to increased corporate costs and financing charges for the year. 
 OUTLOOK 
 Business Environment 

Economic Environment 
 Emera will continue
to pursue investment opportunities related to the transformation of the energy industry to lower emissions and has embarked on a significant capital plan to increase the company’s generation from renewable sources, to improve the
transmission connections within its service territories, and to expand access to natural gas as Emera transitions to a cleaner, greener company. 
 Environmental Regulations 
 NSPI is subject to environmental regulations as set by both the
Province of Nova Scotia and the Government of Canada. NSPI continues to work with officials at both levels of government so as to comply with these regulations in an integrated way. 
 Operating Unit Outlook 
 NSPI 

NSPI anticipates earning a regulated ROE within its allowed range in 2011. NSPI continues to implement its strategy, which is focused on regulated
investments in renewable energy and system reliability projects, with a total capital program budget of approximately $350 million in 2011. NSPI expects to finance its capital expenditures with funds from operations, debt and equity. 

Bangor Hydro 
 Bangor Hydro’s USD
earnings are expected to be slightly higher in 2011 due to the recovery of investments in new transmission assets. Bangor Hydro continues to execute on its transmission development plan, with approximately $150 million USD of large transmission
projects in various stages of development. These projects, recoverable through regional transmission rates, are expected to provide returns on equity of 11.64%. In 2011, Bangor Hydro expects to invest approximately $87 million USD, including
approximately $54 million USD for major transmission projects. Bangor Hydro expects to finance its capital expenditures with funds from operations and debt. 

  
  

94 








 Pipelines 
 Pipelines earnings are expected to be lower in 2011 as a result of less favourable USD hedged exchange rates in 2011 compared to 2010 and as a result of capital lease accounting which yields declining
earnings over the life of the asset. 
 Other, Including Corporate Costs 
 Earnings from Other, Including Corporate Costs, are expected to be higher in 2011 due to increased scale of business, offset by higher financing costs. Emera Newfoundland and Labrador plans to invest
approximately $25 million in the Maritime Link and the Island Link Transmission Projects. 
 Emera expects to invest $115 million in the capital
programs of its Caribbean companies. 

  
  

95 








 LIQUIDITY AND CAPITAL RESOURCES 
 The company generated cash in 2010 mainly through the operations of NSPI and Bangor Hydro, its two primary regulated utilities involved in the generation, transmission and distribution of electricity and
Brunswick Pipeline. NSPI’s and Bangor Hydro’s customer bases are diversified by both sales volumes and revenues among residential, commercial, industrial and other customers. Circumstances that could affect the company’s ability to
generate cash include general economic downturns in its markets, the loss of one or more large customers, regulatory decisions affecting customer rates and changes in environmental legislation. NSPI and Bangor Hydro are each capable of paying
dividends to Emera provided they do not breach their debt to capitalization ratios after giving effect to the dividend payment. 
 In addition
to internally generated funds, Emera and NSPI have in aggregate access to $1.2 billion committed syndicated revolving bank lines of credit, of which $505 million is undrawn and available as at December 31, 2010. Emera and NSPI each have access
to $600 million of this credit. NSPI has an active commercial paper program for up to $400 million, of which outstanding amounts are 100% backed by its bank lines and this results in an equal amount of credit being considered drawn and unavailable.

 In June 2010, Emera’s and NSPI’s revolving bank lines were each renewed for $600 million, for a three-year term maturing in June
2013. NSPI’s bank line was increased by $100 million to $600 million as part of this renewal process. 
 As at December 31, 2010, the
outstanding short-term debt is as follows: 
  

															
	 millions of dollars
	  	 Maturity
	  	Credit Line
Committed	 	  	Utilized	 	  	Undrawn and
Available	 
	 Emera – Operating and acquisition credit facility
	  	June 2013 – Revolver	  	$	600	  	  	$	406	  	  	$	194	  
	 NSPI – Operating credit facility
	  	June 2013 – Revolver	  	 	600	  	  	 	289	  	  	 	311	  
	 Bangor Hydro – in USD – Operating credit facility
	  	September 2013 – Revolver	  	 	80	  	  	 	42	  	  	 	38	  
	 Other – in USD – Operating credit facilities
	  	Various	  	 	18	  	  	 	3	  	  	 	15	  

 Emera and its subsidiaries have debt
covenants associated with their credit facilities. These covenants are tested regularly, and the company is in compliance with the covenant requirements. 
 Debt Management 
 Emera 
 In May 2010, Emera filed a $500 million debt and preferred equity shelf prospectus providing the company with access to long-term debt and equity. 
 In June 2010, Emera issued six million 4.40% Cumulative Five-Year Rate Reset First Preferred Shares, Series A (“First Preferred Shares, Series A”). The $150 million First Preferred Shares,
Series A were issued at $25.00 per share for net after-tax proceeds of $146.7 million. 
 The weighted average coupon rate of Emera’s
outstanding medium-term notes at December 31, 2010 was 4.45% (2009 – 4.45%). All of the outstanding debt matures within the next ten years. The quoted market weighted average interest rate for the same or similar issues of the same
remaining maturities was 3.73% as at December 31, 2010 (2009 – 4.43%). 
 Emera’s credit ratings issued by Dominion Bond Rating
Service (“DBRS”) and Standard & Poor’s (“S&P”) are as follows: 
  

									
	 	  	DBRS	 	  	S&P	 
	 Long-term corporate
	  	 	BBB (high)	  	  	 	BBB+	  
	 Preferred Stock
	  	 	Pfd-3 (high)	  	  	 	P-2 (Low)	  


  
  

96 








 NSPI 
 In May 2010, NSPI redeemed $100 million medium-term notes using short-term credit facilities. 
 In
May 2010, NSPI filed a $500 million debt shelf prospectus providing NSPI with access to long-term debt. 
 In June 2010, NSPI completed a $300
million medium-term note issue, proceeds of which were used to pay down outstanding short-term debt. These notes bear interest at the rate of 5.61% and yield 5.616% per annum until June 15, 2040. 

The weighted average coupon rate on NSPI’s outstanding medium-term and debenture notes at December 31, 2010 was 6.74% (2009 – 6.80%).
Approximately 27% of the debt matures over the next ten years, 70% matures between 2021 and 2040 and $50 million, or 3%, matures in 2097. The quoted market weighted average interest rate for the same or similar issues of the same remaining
maturities was 4.50% as at December 31, 2010 (2009 – 4.87%). 
 NSPI’s credit ratings issued by DBRS and S&P’s are as
follows: 
  

									
	 	  	DBRS	 	 	S&P	 
	 Corporate
	  	 	N/A	  	 	 	BBB+	  
	 Senior unsecured debt
	  	 	A (low	) 	 	 	BBB+	  
	 Preferred stock
	  	 	Pfd-2 (low	) 	 	 	P-2 (low	) 
	 Commercial paper
	  	 	R-1 (low	) 	 	 	A-1 (low	) 

 Bangor Hydro 

In June 2010, Bangor Hydro increased its revolving bank line by $20 million, and renewed it through September 2013. 

The weighted-average coupon rate on Bangor Hydro’s outstanding long-term debt at December 31, 2010, was 6.96% (2009 – 6.92%).
Approximately 87% of the debt matures over the next 10 years; the remaining issue matures in 2022. The quoted market weighted average interest rate for the same or similar issues of the same remaining maturities was 3.81% as of December 31,
2010 (2009 – 5.57%). 
 Bangor Hydro has no public debt, and accordingly has no requirement for public credit ratings. Bangor Hydro
believes that its credit facility provides adequate access to capital to support current operations and a base level of capital expenditures. For additional capital needs, Bangor Hydro expects to have sufficient access to competitively priced funds
in the unsecured debt market. 

  
  

97 








 Contractual Obligations 
 The consolidated contractual obligations over the next five years and thereafter include: 
  

																																	
	 millions of dollars
	  	 	 	  	 	 	  	Payments Due by Period	 
	 	  	Total	 	  	3 year
renewable (1)	 	  	2011	 	  	2012	 	  	2013	 	  	2014	 	  	2015	 	  	After
2015	 
	 Long-term debt
	  	$	3,037.8	  	  	$	530.3	  	  	$	12.7	  	  	$	83.6	  	  	$	305.0	  	  	$	304.9	  	  	$	74.7	  	  	$	1,726.6	  
	 Preferred shares issued by subsidiary
	  	 	135.0	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	135.0	  	  	 	—  	  
	 Operating leases
	  	 	7.0	  	  	 	—  	  	  	 	2.7	  	  	 	1.1	  	  	 	0.6	  	  	 	0.6	  	  	 	0.6	  	  	 	1.4	  
	 Purchase obligations
	  	 	4,247.5	  	  	 	—  	  	  	 	388.4	  	  	 	385.6	  	  	 	306.8	  	  	 	243.1	  	  	 	191.6	  	  	 	2,732.0	  
	 Capital obligations
	  	 	111.5	  	  	 	—  	  	  	 	76.1	  	  	 	33.9	  	  	 	1.5	  	  	 	—  	  	  	 	—  	  	  	 	—  	  
	 Asset retirement obligations
	  	 	451.3	  	  	 	—  	  	  	 	1.7	  	  	 	2.0	  	  	 	1.3	  	  	 	1.3	  	  	 	1.4	  	  	 	443.6	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 
	 Total contractual obligations
	  	$	7,990.1	  	  	$	530.3	  	  	$	481.6	  	  	$	506.2	  	  	$	615.2	  	  	$	549.9	  	  	$	403.3	  	  	$	4,903.6	  
		  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 

  

	(1)	Short-term discount notes utilized against a $600 million operating credit facility which matures in June 2013 are included in long-term debt as the company has the
intention and the unencumbered ability to refinance the obligations for a period greater than one year. 

 Operating lease
obligations: The company’s operating lease obligations consist of operating lease agreements for office space, rail cars, telecommunications services, and certain other equipment. 
 Purchase obligations: The company has purchasing commitments for electricity from IPPs, transportation of coal, natural gas, fuel and transportation capacity on the Maritimes & Northeast
Pipeline. 
 Capital obligations: The company has commitments to third parties for construction on capital projects and other goods and
services. 
 Asset retirement obligations: The company has asset retirement obligations for its generation, transmission and distribution
assets and its pipeline. 
 The company expects to be able to meet its obligations with cash from operations. 

Capital Resources 
 Capital expenditures
for 2010, including AFUDC, were approximately $591 million and included: 
  

	 	•	 	 $527 million in NSPI; 


  

	 	•	 	 $46 million in Bangor Hydro; 


  

	 	•	 	 $13 million in Brunswick Pipeline; and 


  

	 	•	 	 $5 million in Other. 



  
  

98 








 PENSION FUNDING 
 For funding purposes, Emera determines required contributions to its defined benefit pension plans based on smoothed asset values. This reduces volatility in the cash funding requirement as the impact of
investment gains and losses are recognized over a three year period. The cash required in 2011 for defined benefit pension plans will be approximately $39.5 million (2010 – $34.7 million actual). All pension plan contributions are tax
deductible and will be funded with cash from operations. 
 Emera’s defined benefit pension plans are managed with a diversified portfolio
of asset classes, investment managers and geographic investments. Emera reviews the investment managers on a regular basis, and the plans’ asset mixes from time to time. 
 Emera’s projected contributions to defined contribution pension plans are $2.7 million for 2011 (2010 – $1.4 million actual). 
 OFF-BALANCE SHEET ARRANGEMENTS 
 Upon privatization of the former provincially owned Nova
Scotia Power Corporation (“NSPC”) in 1992, NSPI became responsible for managing a portfolio of defeasance securities, which at December 31, 2010, totaled $1.0 billion. The securities are held in trust for Nova Scotia Power Finance
Corporation (“NSPFC”), an affiliate of the Province of Nova Scotia. NSPI is responsible for ensuring the defeasance securities provide the principal and interest streams to match the related defeased NSPC debt. Approximately 73% of the
defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio; the remaining defeasance portfolio has a market value higher than the related debt, reducing the future risk of
this portion of the portfolio. 
 TRANSACTIONS WITH RELATED PARTIES 
 In the ordinary course of business, Emera purchased natural gas transportation capacity totaling $12.8 million (2009 – $12.5 million) during the three months ended December 31, 2010, and $55.1
million (2009 – $47.4 million) during the year ended December 31, 2010, from the Maritimes & Northeast Pipeline, an investment under significant influence of the company. The amount is recognized in “Fuel for generation and
purchased power” or netted against energy marketing margin in “Other revenue”, and is measured at the exchange amount. At December 31, 2010, the amount payable to the related party was $3.9 million (2009 – $4.6 million), is
non-interest bearing and is under normal credit terms. 
 DIVIDENDS AND PAYOUT RATIOS 

In February 2010, the Board of Directors approved a quarterly dividend increase, effective May 3, 2010, to $0.2825 per common share, and in September
2010, approved a further increase to $0.3250 effective November 1, 2010 reflecting an increase on an annualized basis to $1.30 per common share. 

  
  

99 








 Emera Inc.’s common dividend rate was $1.21 ($0.2725 in Q1, $0.2825 in Q2; and $0.3250 per quarter in
Q3 and Q4) per common share in 2010 and $1.03 ($0.2525 per quarter in Q1, Q2 and Q3; and $0.2725 in Q4) for 2009, representing a payout ratio of approximately 70.1% in 2010 and 65.9% in 2009. 
 Effective September 25, 2009, Emera changed its Common Shareholders Dividend Reinvestment and Share Purchase Plan to provide for a discount of up to 5% from the average market price of Emera’s
common shares for common shares purchased in connection with the reinvestment of cash dividends under this Plan. The Board of Directors of Emera also decided on September 25, 2009, that the discount would be 5% effective on and after the
quarterly dividend payment on November 16, 2009, to shareholders of record on November 2, 2009. 

  
  

100 








 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS 
 Financial Risks and Financial Instruments 
 The company manages its exposure to foreign
exchange, interest rate, and commodity risks in accordance with established risk management policies and procedures. The company uses financial instruments consisting mainly of foreign exchange forward contracts, and coal, oil and gas options and
swaps. In addition, the company has contracts for the physical purchase and sale of natural gas, and physical and financial contracts held-for-trading (“HFT”). Collectively these contracts are referred to as derivatives. 

The company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that qualify and are designated
as contracts held for normal purchase or sale. 
 Derivatives that meet stringent documentation requirements, and can be proven to be effective
both at the inception and over the term of the derivative, qualify for hedge accounting. Specifically, for cash flow hedges, the change in the fair value of the effective portion of hedging derivatives is deferred to “AOCI” and recognized
in earnings in the same period that the related hedged item is realized. Any ineffective portion of the change in the fair value of derivatives is recognized in net earnings in the reporting period. 

Where the documentation or effectiveness requirements are not met, the derivative instruments are recognized at fair value with any changes in fair value
recognized in net earnings in the reporting period, unless deferred as a result of regulatory accounting. 
 For fair value hedges, the change
in fair value of the hedging derivatives and the hedged item are recorded in net earnings. Therefore, the change in fair value of the ineffective portion of hedging derivatives will impact net earnings in the reporting period. 

The company’s HFT derivatives are recorded on the balance sheet at fair value, with changes recorded in net earnings in the reporting period, unless
deferred as a result of regulatory accounting. The company has not designated any derivatives to be included in the HFT category. 
 NSPI has
contracts for the purchase and sale of natural gas at its Tufts Cove generating station (“TUC”) that are considered HFT derivatives and accordingly are recognized on the balance sheet at fair value. This reflects NSPI’s history of
buying and reselling any natural gas not used in the production of electricity at TUC. Changes in fair value of HFT derivatives are normally recognized in net earnings. In accordance with NSPI’s accounting policy for financial instruments and
hedges relating to TUC fuel, NSPI has deferred any changes in fair value to a regulatory asset or liability. In 2009, the UARB approved an amendment to NSPI’s accounting practice to include all TUC financial commodity hedges which are no longer
required. This change in practice has impacted the timing of recognition between “Fuel for generation and purchased power” and “Fuel adjustment” as a result of the FAM implemented in 2009. The change in accounting practice was
applied prospectively, beginning in 2009, as required by the UARB. 

  
  

101 








 Hedging Items Recognized on the Balance Sheet 

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

 

									
	 millions of dollars
	  	December 31
2010	 	  	December 31
2009	 
	 Inventory
	  	$	4.7	  	  	$	22.2	  
	 Derivatives in a valid hedging relationship
	  	 	24.6	  	  	 	(29.5	) 
	 Long-term debt
	  	 	—  	  	  	 	0.1	  
		  	 	 	 	  	 	 	 
		  	$	29.3	  	  	$	(7.2	) 
		  	 	 	 	  	 	 	 

 Hedging Impact Recognized in Earnings 
 The company recognized in net earnings the following gains (losses) related to the effective portion of hedging relationships under the following categories: 

 

																	
	 millions of dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 	  	2010	 	 	2009	 	 	2010	 	 	2009	 
	 Finance income from direct financing lease increase
	  	$	1.7	  	 	$	2.2	  	 	$	7.7	  	 	$	2.8	  
	 Fuel and purchased power increase
	  	 	(11.8	) 	 	 	(27.1	) 	 	 	(73.3	) 	 	 	(46.3	) 
	 Financing charges decrease
	  	 	1.2	  	 	 	1.0	  	 	 	1.8	  	 	 	6.9	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Effectiveness losses
	  	$	(8.9	) 	 	$	(23.9	) 	 	$	(63.8	) 	 	$	(36.6	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 The effectiveness gains (losses) reflected in the above table are offset in net earnings by the change in the fair value of
the hedged item realized in the period. 
 The company recognized in net earnings the following gains (losses) related to the ineffective
portion of hedging relationships under the following categories: 
  

																	
	 millions of dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 	  	2010	 	 	2009	 	 	2010	 	 	2009	 
	 Fuel and purchased power increase
	  	$	(0.7	) 	 	$	(1.0	) 	 	$	(1.6	) 	 	$	(14.2	) 
	 Financing charges (increase) decrease
	  	 	(0.1	) 	 	 	0.3	  	 	 	(0.3	) 	 	 	(0.5	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Ineffectiveness losses
	  	$	(0.8	) 	 	$	(0.7	) 	 	$	(1.9	) 	 	$	(14.7	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 HFT Items Recognized on the Balance Sheet 
 The company has recognized on the balance sheet a net HFT derivatives liability of $11.7 million as at December 31, 2010 (2009 – $9.4 million asset). 

  
  

102 








 HFT Derivatives Recognized in Earnings 
 The company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives in earnings: 

 

																	
	 millions of dollars
	  	Three months ended
December 31	 	 	Year ended
December 31	 
	 	  	2010	 	 	2009	 	 	2010	 	 	2009	 
	 Electric revenue
	  	$	(1.9	) 	 	 	—  	  	 	$	4.4	  	 	$	0.6	  
	 Other revenue
	  	 	3.8	  	 	 	—  	  	 	 	1.8	  	 	 	(5.7	) 
	 Fuel and purchased power
	  	 	(1.3	) 	 	$	1.4	  	 	 	(1.3	) 	 	 	12.4	  
	 Financing charges
	  	 	(0.1	) 	 	 	(0.1	) 	 	 	—  	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Held-for-trading derivatives gains (losses)
	  	$	0.5	  	 	$	1.3	  	 	$	4.9	  	 	$	7.3	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 As discussed in note 29 of Emera’s financial statements at the reporting date, various valuation techniques are used to
determine the fair value of derivative instruments. These may include quoted market prices or internal models using observable or non-observable market information. 
 The company has a derivative contract, as discussed in Significant Item, where no observable market exists, therefore modeling techniques are employed using assumptions reflective of current market rates,
yield curves and forward prices, as applicable, to interpolate certain prices. 
 Business Risks 

Measurement of Risk 
 Significant risk
management activities for Emera are overseen by the Enterprise Risk Management Committee to ensure risks are appropriately assessed, monitored and controlled within predetermined risk tolerances established through approved policies. 

The company’s risk management activities are focused on those areas that most significantly impact profitability, quality of earnings and cash flow.
These risks include, but are not limited to, exposure to commodity prices, foreign exchange, interest rates, credit risk, and regulatory risk. 

The UARB approved the implementation of a FAM for NSPI effective January 1, 2009, reducing the utility’s exposure to fuel price volatility by
providing a mechanism for NSPI to recover actual fuel costs. The FAM mitigates the risk to NSPI’s net earnings associated with fluctuations in commodity prices and foreign exchange. 
 Commodity Price Risk 
 Substantially all of the company’s annual fuel requirement is
subject to fluctuation in commodity market prices, prior to any commodity risk management activities. The company utilizes a portfolio strategy for fuel procurement with a combination of long, medium, and short-term supply agreements. It also
provides for supply and supplier diversification. The strategy is designed to reduce the effects from market volatility through agreements with staggered expiration dates, volume options, and varied pricing mechanisms. 

Coal/Petroleum Coke 
 A substantial
portion of NSPI’s coal and petroleum coke (“petcoke”) supply comes from international suppliers, which was contracted at or near the market prices prevailing at the time of contract. The company has entered into fixed-price and index
price contractual arrangements with several suppliers as part of the fuel procurement portfolio strategy. All index-priced contractual arrangements are matched with a corresponding financial instrument to fix the price. The approximate percentage of
coal and petcoke requirements contracted at December 31, 2010 is as follows: 
  

	 	•	 	 2011 – 77% 



  
  

103 









	 	•	 	 2012 – 39% 


  

	 	•	 	 2013 – 24% 


 Heavy
Fuel Oil 
 NSPI manages exposure to changes in the market price of heavy fuel oil through the use of swaps, options, and forward contracts.
For 2011 and 2012, NSPI currently does not have heavy fuel oil hedging requirements. 
 Natural Gas 

NSPI has entered into multi-year contracts to purchase approximately 47,600 mmbtu of natural gas per day in 2011, and 39,300 mmbtu of natural gas per day
in 2012. Volumes exposed to market prices are managed using financial instruments where the fuel is required for NSPI’s generation; and the balance is sold against market prices when available for resale. Gas volumes not required for generation
will be resold into the gas market with the margin hedged using financial instruments. As at December 31, 2010, amounts of natural gas volumes that have been economically and/or financially hedged and contracted are approximately as follows:

  

	 	•	 	 2011 – 87% 


  

	 	•	 	 2012 – 35% 



Purchased Power 
 Emera, along with its
joint venture partner, have entered into a contract with Bear Swamp to fix the price of power necessary to produce the energy requirements of the LIPA contract. As at December 31, 2010, amounts of purchased power Emera has financially
hedged are approximately as follows: 
  

	 	•	 	 2011 – 103% 


  

	 	•	 	 2012 – 95% 


  

	 	•	 	 2013 – 95% 


  

	 	•	 	 2014 – 95% 


  

	 	•	 	 2015 – 94% 



Foreign Exchange Risk 
 The company
enters into foreign exchange forward and swap contracts to limit exposure on foreign currency transactions such as fuel purchases, revenue streams and capital expenditures. 
 The risk due to fluctuation of the CAD against the USD for fuel purchases in NSPI is measured and managed. In 2011, NSPI expects approximately 60% of its anticipated net fuel costs to be denominated in
USD. USD from sales of surplus natural gas will provide a natural hedge against a portion of USD fuel costs. Forward contracts to buy $225.5 million USD were in place at December 31, 2010 at a weighted average rate of $0.99, representing 70% of
2011’s anticipated USD requirements. Forward contracts to buy $443.0 million USD in 2012 through 2015 at a weighted average rate of $1.03 were in place at December 31, 2010. These contracts cover 31% of anticipated USD requirements in
these years. As at December 31, 2010, there were no fuel-related foreign exchange swaps outstanding. 

  
  

104 








 NSPI uses foreign exchange forward contracts to hedge the currency risk for capital projects and receivables
denominated in foreign currencies. Forward contracts to buy €1.8 million were in place at December 31, 2010 at a weighted average rate of $1.56 (versus CAD) for capital projects in 2011. 

Brunswick Pipeline uses forward contracts to hedge the currency risk associated with revenue streams denominated in foreign currencies. Forward contracts
to sell $52 million USD in 2011 were in place at December 31, 2010 at an average rate of $1.07 and sell $63 million USD in 2012 through 2015 at a weighted average rate of $1.07. These contracts cover 91% of anticipated USD revenue inflows in
2011 and 27% of anticipated USD revenue inflows in 2012 through 2015. 
 Interest Rate Risk 

Emera manages interest rate risk through a combination of fixed and floating borrowing and a hedging program. Floating-rate debt is estimated to represent
approximately 20% of total debt in 2011. The company has two interest rate hedging contracts outstanding as at December 31, 2010, fixing the variable interest rates on $22.6 million USD of Maine Public Utilities Financing Bank bonds at MPS.

 Credit Risk 
 Credit risk
arising as a result of contractual obligations between the company and other counterparties is managed by assessing the counterparties’ financial creditworthiness prior to assigning credit limits based on the Board of Directors’ approved
credit policies. The company frequently uses collateral agreements within its negotiated master agreements to further mitigate credit exposure. 

Labour Risk 
 NSPI has a contract with
its union which will expire in April 2012. Bangor Hydro entered into a new collective bargaining agreement in July 2010 which will expire in July 2015. MPS also has a contract with its union, which will expire in October 2013. 

Regulatory Risk 
 NSPI 

NSPI faces risk with respect to the timeliness and certainty of full recovery of costs. The adoption and implementation of the FAM effective
January 1, 2009, has helped NSPI manage that risk. The UARB oversees the FAM, including review of fuel costs, contracts and transactions. The FAM will help ensure customer rates reflect the actual price of the fuel used to make electricity.
Concurrent with the implementation of the FAM in 2009, NSPI’s regulated ROE range was reduced by 0.2%, changing its regulated ROE range to 9.1% to 9.6%, with rates set at 9.35%. 

  
  

105 








 The first rate adjustment under the FAM, effective on January 1, 2010, was approved by the UARB on
December 9, 2009. On December 8, 2010, the UARB approved NSPI’s setting of the 2011 base cost of fuel and its recovery of all unrecovered fuel related costs as submitted in NSPI’s November 2010 filing. The recovery of these costs
will begin January 1, 2011. The UARB approved NSPI’s recovery of these costs over three years, with 50% of the rate increase to be recovered in 2011, 30% in 2012 and 20% in 2013. 
 In December 2010, the UARB granted NSPI approval to defer certain tax benefits related to renewable energy projects arising in 2010. The UARB will convene a proceeding in 2011 to discuss how this deferral
will be applied. 
 Bangor Hydro 

Bangor Hydro’s business consists of three primary components which are each governed by their own regulatory structure. The components include
distribution, transmission and stranded costs. 
 Bangor Hydro’s distribution business operates under the regulation of the MPUC and
operates under a traditional cost-of-service regulatory structure. In late 2007, the MPUC approved a modest increase in distribution rates under the traditional cost-of-service regulatory structure. In the event that costs rise faster than revenues,
Bangor Hydro has the ability to return to the MPUC to request a further increase in rates. 
 Bangor Hydro’s transmission business is
primarily regulated by the FERC. The rates charged are determined by formula and are adjusted on an annual basis. Bangor Hydro is a participating transmission owner within the Regional Transmission Organization for New England, and its operations
are therefore linked with the transmission operations of all of New England. Bangor Hydro’s ROE on its transmission assets, along with added incentives, is determined by FERC, along with the regional transmission owners. 

Bangor Hydro also has the ability to recover stranded costs of both regulatory assets and purchasing power at above-market prices under a full
reconciliation mechanism. This ability eliminates the commodity risk involved with fixed price purchase power contracts. 
 Metering, billing
and settlement services for power suppliers are provided directly by Bangor Hydro within its service territory, and Bangor Hydro is permitted to recover all prudently incurred costs for these services. 

  
  

106 








 MPS 
 Similar to Bangor Hydro, MPS’ business consists of three primary components which are each governed by their own regulatory structure. The components are distribution, transmission and stranded
costs. 
 MPS’ distribution business operates under the regulation of the MPUC and operates under a traditional cost-of-service regulatory
structure. In July 2006, the MPUC approved an increase of approximately 11% in distribution rates, effective July 15, 2006. The allowed ROE used in setting these distribution rates was 10.2%, with a common equity component of 50%. In the event
that costs rise faster than revenues, MPS has the ability to return to the MPUC to request a further increase in rates on January 1, 2012 or any time thereafter. 
 The transmission business of MPS is primarily regulated by the FERC. Transmission rates are set annually through the Open Access Transmission Tariff (“OATT”). Rates derived from the previous
calendar year’s results go into effect June 1 for wholesale customers and July 1 for retail customers. The allowed ROE for transmission operations is 10.5%, and is based on the actual common equity. The allowed ROE is determined by
negotiation with customers in the formula change years of the OATT, which occur every three years. The last OATT formula change year was 2009. 

MPS also has the ability to recover stranded costs of regulatory assets. 
 Metering, billing and settlement services for power suppliers are provided directly by MPS within its service territory and MPS is permitted to recover all prudently incurred costs for these services.

 Environment 
 Corporate
Environmental Governance 
 Emera is committed to operating in a manner that is respectful and protective of the environment, and in full
compliance with legal requirements and company policy. Emera and its wholly-owned subsidiaries have implemented this policy through development and application of environmental management systems (“EMS”). 

Implementation of EMS has provided a systematic focus on environmental issues so risks are identified and managed proactively. All areas of Emera
undertook initiatives in 2010 to reduce potential environmental risks and associated costs. Activities included, but were not limited to, reducing air emissions, protecting water resources, and continued management of PCB contaminated electrical
equipment. 
 Conformance with legislative and company requirements is verified through a comprehensive environmental audit program. There were
no significant environmental or regulatory compliance issues identified during the 2010 audits. Plans are in place to promptly address any audit findings and continually improve the environmental management of the company’s operations.

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

  
  

107 








 NSPI completed an Integrated Resource Plan in 2007 and refreshed it in 2009. The Integrated Resource Plan
includes current environmental requirements and assumptions on future regulations as constraints on possible generation plans. This allows for better generation planning for the future. NSPI stakeholders were engaged in the assumptions and the
scenarios to be modeled. The results of these planning exercises can be found on the NSPI website. 
 In 2007, NSPI was audited by the Canadian
Electricity Association (“CEA”) to verify the quality of its environmental reporting and management systems. The auditor from the CEA concluded that NSPI had “robust programs, environmental leadership and a strong, mature EMS.”

 Regulatory 
 NSPI produces
its electrical energy approximately 64% from coal and 19% from natural gas and/or oil. As such, it is subject to regulation with respect to air pollutants and greenhouse gas emissions. NSPI operates under a cost-of-service regulation model.
Accordingly, all prudently incurred costs, including those capital and operating costs associated with meeting present and future environmental liabilities, can be recovered in rates collected from customers. 

NSPI is subject to environmental regulation as set by both Canadian federal and Nova Scotia provincial governments. NSPI is in material compliance with
current environmental regulations. All required permits are in place for NSPI’s generating stations. These permits are generally for a ten year period but can be subject to review, variation, or suspension by the Minister of Environment of Nova
Scotia. 
 Bangor Hydro and MPS are regulated by the United States Environmental Protection Agency as to compliance with the Federal Water
Pollution Control Act, the Clean Air Act, and other U.S. federal statutes governing the treatment and disposal of hazardous wastes. Bangor Hydro and MPS are also regulated by the Maine Department of Environmental Protection. 

Brunswick Pipeline is a federally regulated undertaking and must operate in accordance with the NEB Act, the Onshore Pipeline Regulations, 1999, and the
Canada Labour Code Part II, the Canadian Environmental Protection Act and any applicable provincial environmental regulations. 
 Climate
Change and Air Emissions 
 Renewable Energy 
 On October 15, 2010, the Nova Scotia Government enacted regulations under the Electricity Act related to the province’s Renewable Electricity Plan. These regulations establish the requirement
that 25% of electricity be supplied from renewable sources by 2015. These regulations build on the previously legislated requirements for 2011 and 2013. Recent amendments to the Electricity Act, and the new regulations, provide for the appointment,
by spring 2011, of a new, independent renewable electricity administrator to conduct the procurement of at least 300 GWh of energy from IPPs to meet the 2015 standard. NSPI is also provided the opportunity to develop 300 GWh of renewable energy.

 In January 2007, the Nova Scotia Government approved the Renewable Energy Standard Regulation (“RES”) to increase the percentage of
renewable energy in the generation mix. In October 2009, the RES was amended. The target date for 5% of electricity to be supplied from post-2001 sources of renewable energy, owned by independent power producers, was extended to 2011 from 2010. The
target for 2013, which requires an additional 5% of renewable energy, is unchanged. 
 Greenhouse Gas Emissions 

NSPI has stabilized, and in recent years, reduced greenhouse gas emissions. This has been achieved by energy efficiency and conservation programs,
increased use of natural gas, improved efficiency of converting natural gas to electricity and adding and contracting for new renewable energy sources to the generation portfolio. 

  
  

108 








 Greenhouse gas emissions from NSPI facilities are capped beginning in 2010 through to 2020. The 2010 to 2015
caps will be achieved by the continued success of energy efficiency and conservation programs and the addition of renewable energy to meet the 2011, 2013 and 2015 provincial renewable energy standards. The regulations also include a transmission
incentive compliance mechanism recognizing expenditures on transmission which facilitates additional renewable energy sources. Up to 3% of the annual cap can be offset in this way to 2019. Further, the 2010 to 2020 period years are combined to form
multi-year compliance periods recognizing the variability in electricity supply sources and demand. 
 Beyond 2015, reduced greenhouse gas
emissions will be achieved through a combination of additional renewable energy, co-firing of biomass in existing coal power plants, import of non-emitting energy and energy efficiency and conservation as per the 2007/2009 Integrated Resource Plan.

 On June 23, 2010, Environment Canada announced its intentions for a new national GHG framework for the electricity sector. This federal
framework, if developed further into regulations, would require thermal coal units to meet GHG emission levels equal to, or better than, a natural gas combined cycle generating unit at a specific anniversary. Nova Scotia’s existing GHG
regulations require reductions in NSPI’s emissions similar to the intentions of the federal framework. NSPI is reviewing the implications of this federal framework and its alignment with NSPI’s current operating plans under existing Nova
Scotia regulations. 
 Mercury 

On July 22, 2010, the Province of Nova Scotia announced, for the years 2010 through 2013, allowable mercury emissions would be increased from the
previous cap of 65 kg per year. NSPI was requested to develop a plan of staged mercury emission reductions for its generation facilities for the period of 2010 to 2020 and to meet an annual cap of 35 kg beginning in 2020. 

In 2008, NSPI carried out extensive testing on mercury abatement technology in its coal power plants. A capital program to add sorbent injection to each
of the seven pulverized fuel coal units was completed in 2009. This allowed NSPI to meet the 2010 mercury emission cap of 65 kg established by the Province. 
 Compared to historical levels, NSPI has reduced mercury emissions by 60%. 
 Nitrogen Oxide and
Sulphur Dioxide Emissions 
 NSPI has completed in 2009 its capital program of retrofitting low nitrogen oxide combustion firing systems on
six of its seven pulverized fuel coal units. NSPI now meets the 2009 nitrogen oxide emission cap of 21,365 tonnes per year established by the province. 
 NSPI continues to meet its emission cap on sulphur dioxide emissions by the use of compliant fuel. 

Compared to historical levels, NSPI has reduced emissions of nitrogen oxide by 40% and sulphur dioxide by 50%. 

Obligations 
 The company recognizes
asset retirement obligations (“ARO”) for property, plant and equipment in the period in which they are incurred if a reasonable estimate of fair value can be determined. Using the company’s credit-adjusted risk-free rate, the fair
value is determined by discounting the company’s estimated future cash flows necessary to discharge legal obligations related to reclamation of land at the company’s thermal, hydro, combustion turbine sites, pipelines and disposal of
polychlorinated biphenyls (“PCBs”) in its transmission and distribution equipment. Estimated future cash flows are based on the company’s completed depreciation studies, prior experience, estimated useful lives of assets, governmental
regulatory requirements and the costs of activities such as demolition, restoration and remedial work based on present-day methods and technologies. Actual results may differ from these estimates. 

  
  

109 








 The UARB included the amount of future expenditures associated with the removal of generation facilities in
the 2003 NSPI depreciation settlement discussed under Property, Plant and Equipment in the Significant Accounting Policies and Critical Accounting Estimates section. NSPI believes that it will continue to be able to recover ARO through rates.
Accordingly, changes to the ARO, or cost recognition attributable to changes in the factors discussed above, should not impact the results of the company’s operations. 
 Some of the company’s hydro, transmission and distribution assets may have additional ARO. As the company expects to use the majority of its installed assets for an indefinite period, no removal date
can be determined and consequently a reasonable estimate of the fair value of any related ARO cannot be made at this time. Additionally, some of the company’s transmission and distribution assets may have conditional ARO, the fair value of
which cannot be reasonably estimated as sufficient information does not exist to estimate the obligations. A liability will be recognized in the period in which sufficient information becomes available. 

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

																									
	 Asset
	  	Credit-adjusted
risk-free rate	 	 	Estimated undiscounted
future
obligation
(millions of dollars)	 	  	Expected
settlement date
(number of years)	 
	 	  	2010	 	 	2009	 	 	2010	 	  	2009	 	  	2010	 	  	2009	 
	 Thermal
	  	 	5.30	% 	 	 	5.31	% 	 	$	258.9	  	  	$	242.3	  	  	 	10 – 29	  	  	 	11 – 30	  
	 Hydro
	  	 	5.27	% 	 	 	5.31	% 	 	 	101.4	  	  	 	60.8	  	  	 	21 – 51	  	  	 	22 – 52	  
	 Wind
	  	 	5.21	% 	 	 	—  	  	 	 	45.5	  	  	 	—  	  	  	 	13 – 20	  	  	 	—  	  
	 Combustion turbines
	  	 	5.25	% 	 	 	5.31	% 	 	 	12.9	  	  	 	5.1	  	  	 	1 – 14	  	  	 	1 – 14	  
	 Transmission & distribution
	  	 	5.74	% 	 	 	5.74	% 	 	 	21.6	  	  	 	18.1	  	  	 	1 – 15	  	  	 	1 – 16	  
	 Pipeline
	  	 	3.80	% 	 	 	3.80	% 	 	 	11.0	  	  	 	11.0	  	  	 	39	  	  	 	40	  
		  				 				 	 	 	 	  	 	 	 	  				  			
		  				 				 	$	451.3	  	  	$	337.3	  	  				  			
		  				 				 	 	 	 	  	 	 	 	  				  			

 As at December 31, 2010, the asset retirement obligations recorded on the balance sheet were $141.8 million
(2009 – $104.5 million). The company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $451.3 million, which will be incurred between 2011 and 2061. The majority of these costs will be incurred
between 2020 and 2041. 
 DISCLOSURE AND INTERNAL CONTROLS 
 Emera’s management is responsible for establishing and maintaining disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICFR”), as
those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings. The objective of this instrument is to improve the quality, reliability and transparency of information that is filed or
submitted under securities legislation. 
 The President and Chief Executive Officer and the Chief Financial Officer have designed, with the
assistance of company employees, DC&P and ICFR to provide reasonable assurance that material information is reported to them on a timely basis; financial reporting is reliable; and financial statements prepared for external purposes are in
accordance with CGAAP. 
 The President and Chief Executive Officer and the Chief Financial Officer have evaluated, with the assistance of
company employees, the effectiveness of Emera and its consolidated subsidiaries’ DC&P and ICFR and based on that evaluation, have concluded DC&P and ICFR were effective at December 31, 2010. 

  
  

110 








 There have been no changes in Emera or its consolidated subsidiaries’ ICFR during the period beginning
on January 1, 2010 and ending on December 31, 2010, which have materially affected, or are reasonably likely to materially affect ICFR. 

  
  

111 








 SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES 

The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and
liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities. Significant areas requiring the use of management estimates relate to rate-regulation, the determination of post-retirement employee
benefits, unbilled revenue, contract receivable, income taxes, asset retirement obligations, useful lives for depreciable assets, and goodwill impairment assessments. Actual results may differ from these estimates. 

Rate Regulation 
 The rate-regulated
accounting policies of NSPI, Bangor Hydro, MPS and Brunswick Pipeline may differ from accounting policies for non-rate-regulated companies. NSPI, Bangor Hydro and MPS accounting policies are subject to examination and approval by their respective
regulators. These accounting policy differences occur when the regulators render their decisions on rate applications or other matters and generally involve a difference in the timing of revenue and expense recognition. The accounting for these
items is based on the expectation of the future actions of the regulators. 
 If the regulators’ future actions are different from their
previous rulings, the timing and amount of the recovery of liabilities and refund of assets, recorded or unrecorded, could be significantly different from that reflected in the financial statements. 

Pension and Other Post-Retirement Employee Benefits 
 The company provides post-retirement benefits to employees, including defined benefit pension plans. The cost of providing these benefits is dependent upon many factors that result from actual plan
experience and assumptions of future experience. 
 The benefit cost and accrued benefit obligation for employee future benefits included in
annual compensation expenses are affected by employee demographics, including age, compensation levels, employment periods, contribution levels and earnings on plan assets. 
 Changes to the provision of the plan may also affect current and future pension costs. Benefit costs may also be affected by changes in key actuarial assumptions, including anticipated rates of return on
plan assets and discount rates used in determining the accrued benefit obligation and benefit costs. 
 The pension plan assets are comprised
primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods. 

  
  

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 Consistent with CGAAP and Emera’s accounting policy, the company amortizes the net actuarial gain or
loss, which exceeds 10% of the greater of the accrued benefit obligation (“ABO”) and the market-related value of assets, over active plan members’ average remaining service period, which is currently 9 years. Emera’s use of
smoothed asset values further reduces the volatility related to the amortization of actuarial investment experience. As a result, the main cause of volatility in reported pension cost is the discount rate used to determine the ABO. 

The discount rate used to determine benefit costs is based on high quality long-term Canadian corporate bonds for NSPI’s pension plan and US
corporate bonds for Bangor Hydro’s pension plan. The discount rate is determined with reference to bonds which have the same duration as the ABO as at January 1 of the fiscal year rounded to the nearest 25 basis points. For benefit cost
purposes, NSPI’s rate was 6.50% for 2010 (2009 – 7.50%) and Bangor Hydro’s rate was 6.00% for 2010 (2009 – 6.75%). MPS’ rate for 2010 was 5.75% for pension plans and 5.85% for non-pension plans and GBPC’s rate was
6.00%. 
 The expected return on plan assets is based on management’s best estimate of future returns, considering economic and consensus
forecasts. The benefit cost calculations assumed that plan assets would earn a rate of return of 7.25% for 2010 and 2009 for NSPI and 8.00% for 2010 (2009 – 8.00%) for Bangor Hydro. The assumed rate of return on plan assets for 2010 was 8.5%
for MPS and 6.00% for GBPC. 
 The reported benefit cost for 2010, based on management’s best estimate assumptions, is $34.1 million. While
there are numerous assumptions which are used to determine the benefit cost, the discount rate and asset return assumptions have an impact on the calculations. 
 The following shows the impact on 2010 benefit cost of a 25 basis point change (0.25%) in the discount rate and asset return assumptions: 

 

																	
	 	  	0.25% Increase	 	 	0.25% Decrease	 
	 millions of dollars
	  	2010	 	 	2009	 	 	2010	 	  	2009	 
	 Discount rate assumption
	  	$	(3.5	) 	 	$	(1.3	) 	 	$	3.6	  	  	$	1.4	  
	 Asset return assumption
	  	$	(1.8	) 	 	$	(1.9	) 	 	$	1.8	  	  	$	1.9	  

 The sensitivity to the discount rate
assumption was significantly higher for 2010 benefit cost than in 2009 because, in 2010, the existing net unamortized gains and losses subject to amortization fell outside the 10% corridor and any additional change impacts the amortization and
expense calculations. 
 Unbilled Revenue 
 Electric revenues are billed on a systematic basis over a one or two-month period for NSPI and a one-month period for Bangor Hydro, MPS and GBPC. At the end of each month, the company must make an
estimate of energy delivered to customers since the date their meter was last read and of related revenues earned but not yet billed. The unbilled revenue is estimated based on several factors, including current month’s generation, estimated
customer usage by class, weather, line losses and applicable customer rates. Brunswick Pipeline also makes an estimate of toll revenues at the end of each month. Based on the extent of the estimates included in the determination of unbilled revenue,
actual results may differ from the estimate. As at December 31, 2010, unbilled revenues amount to $102.7 million (2009 – $98.4 million) on a base of annual electric revenues of approximately $1.4 billion (2009 – $1.4 billion).


  
  

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 Contract Receivable 
 NSPI’s natural gas purchase agreement expired in October 2010. The agreement included a price adjustment clause covering three years of natural gas purchases. The clause stated that NSPI would pay
for all gas purchases at the agreed contract price, but would be entitled to a price rebate on a portion of the volumes. The first settlement took place in November 2007 for purchases to the end of October 2007 and the final settlement took place in
November 2010. 
 Property, Plant and Equipment 
 Property, plant and equipment represents 54.5% of total assets recognized on the company’s balance sheet. Included in “Property, plant and equipment” are the generation, transmission and
distribution and other assets of the company. Due to the magnitude of the company’s property, plant and equipment, changes in estimated depreciation rates can have a material impact on depreciation expense. 

Depreciation is calculated on a straight-line basis over the estimated service life of the asset. The estimated useful lives of the assets are largely
based on formal depreciation studies, which are conducted from time to time. 
 In 2002, NSPI commissioned a depreciation study by an external
consultant. The study was filed with the UARB in 2003. A settlement agreement on the matter was reached with all interveners, which recommended a four-year phase-in of new depreciation rates, which, based on assets in service in the study, would
reach an overall increase in depreciation expense of $20 million by 2007. The UARB approved the settlement. NSPI began phasing in the new rates in 2004. In its rate decision for 2005, the UARB deferred the scheduled phase-in for 2005. In the rate
decision for 2006, the UARB included the phase-in of year-two in rates. In its February 5, 2007 decision, the UARB postponed the phase-in of year-three rates until the next rate application. In its November 5, 2008 decision, the UARB
approved year-three phase-in rates effective January 1, 2009. On October 29, 2010, NSPI filed a depreciation study with the UARB. 

Income Taxes 
 Income taxes are
determined based on the expected tax treatment of transactions recorded in the consolidated financial statements. In determining income taxes, tax legislation is interpreted in a variety of jurisdictions, the likelihood that future tax assets will
be recovered from future taxable income is assessed and assumptions about the expected timing of the reversal of future tax assets and liabilities are made. If interpretations differ from those of tax authorities or if the recovery of future tax
assets or timing of reversals is not as anticipated, the provision for income taxes could increase or decrease in future periods. The amount of any such increase or decrease cannot be reasonably estimated. 

  
  

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 Asset Retirement Obligations 
 The company recognizes ARO’s for property, plant and equipment in the period in which they are incurred if a reasonable estimate of fair value can be determined. The fair value of the liability is
described as the amount at which the liability could be settled in a current transaction between willing parties. Expected values are discounted at the risk-free interest rate adjusted to reflect the market’s evaluation of the company’s
credit standing. Determining ARO’s requires estimating the life of the related asset and the costs of activities such as demolition, restoration and remedial work based on present-day methods and technologies. Actual results may differ from
these estimates. 
 Goodwill Impairment Assessments 
 Goodwill represents the excess of the acquisition purchase price for Bangor Hydro, GBPC, ICDU and MAM over the fair values assigned to individual assets acquired and liabilities assumed. Emera is required
to perform an impairment assessment annually, or in the interim if an event occurs that indicates the fair value of Bangor Hydro, GBPC, ICDU or MAM may be below its carrying value. Emera performs its annual impairment test as at March 31.

 Impairment assessments are based on fair market value assessments. Fair market value is determined by use of net present value financial
models that incorporate management’s assumptions about future profitability. There was no impairment provision required in 2010 or 2009. 

  
  

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 CHANGES IN ACCOUNTING POLICIES 
 Future Accounting Policy Changes 
 Changeover to United States Generally Accepted
Accounting Principles 
 In February 2008, the Canadian Institute of Chartered Accountants (“CICA”) announced CGAAP for publicly
accountable enterprises will be replaced by International Financial Reporting Standards (“IFRS”) for fiscal years beginning on or after January 1, 2011. The company began planning its transition to IFRS in 2008 and transition
activities progressed on schedule through 2009. In Q4 2009, due primarily to the continued uncertainty around the timing and eventual adoption of a rate-regulated accounting (“RRA”) standard under IFRS, management began reviewing the
option of adopting United States Generally Accepted Accounting Principles (“US GAAP”) instead of IFRS. In Q1 2010, Emera’s Board of Directors approved the transition to US GAAP financial reporting standards beginning Q1 2011.

 The adoption of US GAAP in Q1 2011 is expected to result in fewer significant changes in the company’s accounting policies than
would have been experienced with the adoption of IFRS. Management believes this will result in financial information that is more comparable to the company’s prior years’ financial statements prepared under CGAAP, making them easier for
readers to understand. 
 US GAAP reporting is permitted by Canadian securities laws and the Toronto Stock Exchange (“TSX”) for
companies subject to reporting obligations under US securities laws. Emera Inc. plans to file registration statements with the SEC prior to releasing its Q1 2011 financial results. On July 15, 2010, NSPI registered debt securities with the SEC
under the US Securities Act of 1933, thereby becoming subject to US reporting obligations. Registration with the SEC will enhance the company’s ability to access US capital markets in the future. 

The company’s application of CGAAP currently relies on US GAAP for guidance on the application of RRA. RRA allows the economic impact of
regulatory activities to be recognized consistent with the timing that amounts are included in customer rates. The company believes continued recognition of its regulatory assets and liabilities under US GAAP best reflects the effect regulatory
activities have on the company’s financial position. More than 90% of the company’s revenues are earned by its wholly-owned regulated subsidiaries NSPI, Bangor Hydro and Brunswick Pipeline. Without a RRA standard, a transition to IFRS
would likely result in the accounting write-off of the company’s significant regulatory assets and liabilities, and net earnings could be subject to greater volatility on an on-going basis. 

Transition Activities 
 A formal project
was established to transition to US GAAP for 2011, register securities of Emera and NSPI with the SEC and prepare both companies to comply with the on-going reporting requirements of the SEC and requirements of the Sarbanes-Oxley Act
(“SOX”). A four-phased project approach was adopted to manage project activities. The project is proceeding on schedule to achieve its required milestones. The following is a brief overview of the activities of each phase and current
status. An update on the project’s status and achievement of its key milestones are provided to the company’s Audit Committee on a quarterly basis. 

  
  

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 Phase One: Preliminary Assessment and Planning – Completed 

Phase One was substantially completed in May 2010. It involved assessment and planning activities required to develop the initial project plan and
identify resource requirements for the project. Internal resources were dedicated to the project to ensure its completion within the required timeline. KPMG LLP, who was assisting with the company’s changeover to IFRS, was engaged to continue
providing technical advisory services during the company’s transition to US GAAP. In addition to resourcing activities, the Project Charter, Governance Structure and a Project Management Office were established to support the subsequent phases
of the project. 
 Two key assessments were performed in this phase: 

 

	 	•	 	 The first assessment compared the most significant differences between US GAAP and CGAAP to determine which areas were most likely to impact the
company’s accounting policies and financial reporting. The purpose of this assessment was to highlight areas where detailed analysis of GAAP differences was needed to determine and conclude on the nature and extent of impact. Detailed analysis
activities and conclusions on the impact of US GAAP on the company’s accounting policies are discussed under Phase Two. 


  

	 	•	 	 The second assessment compared the requirements of the National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim
Filings” (“NI 52-109”) and those of Sections 302 (“SOX 302”) and 404 (“SOX 404”) of the Sarbanes-Oxley Act. The purpose of this assessment was to identify the impact of SOX 302 and SOX 404 on the
company’s current NI 52-109 program over disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”).



Consistent with NI 52-109, SOX 302 requires certification by the certifying officers of all publicly-traded companies that they have
established, maintained and designed DC&P and ICFR and evaluated DC&P. SOX 302 requires a quarterly evaluation of DC&P while NI 52-109 requires an annual evaluation; however, NSPI and Emera are not required to file quarterly 302
certificates with the SEC. Also consistent with NI 52-109, SOX 404 requires that all publicly-traded companies must establish ICFR; document, test and maintain those controls and procedures to ensure their effectiveness; and management must
report on their evaluation of the effectiveness of ICFR.
 Under SOX 404, the company is required to obtain an external audit
opinion annually on the design and effectiveness of the company’s ICFR which is not required under NI 52-109. This was the only significant difference identified between the requirements of NI 52-109 and SOX 404. The first external
audit on ICFR is required as of December 31, 2011 for NSPI and as of December 31, 2012 for Emera. Activities being performed to prepare the company for SOX 404 attestation are described below. 

Phase Two: Detailed Assessment, Development and SEC Registration – Substantially Completed 

Phase Two commenced in April 2010. This phase involves registering securities of Emera and NSPI with the SEC and addressing all new requirements related
to complying with US GAAP, SOX and SEC reporting obligations. 
 Detailed analysis was performed on those areas identified in Phase One
where significant differences between US GAAP and CGAAP were most likely to impact the company’s accounting policies, financial statements, information systems, internal controls and other business activities. Areas examined included
revenue recognition, hedge accounting, RRA, pension and other post-retirement benefits, income taxes, preferred shares and foreign currency. Where differences were identified, prior period financial information is being restated to US GAAP for
comparative purposes in 2011. Restatement activities are part of Phase Three. 
 The company’s financial statements were drafted or
“mocked-up” in accordance with US GAAP to identify the financial statement and disclosure impact of transitioning to US GAAP. 

  
  

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 NSPI’s regulated accounting policies were updated to reflect the transition to US GAAP. These were
approved by the UARB in December 2010. 
 Based on the work completed in this phase and the company’s conclusion that it is able to
continue with its application of RRA under US GAAP, material adjustments to the company’s reported post-transition net earnings were not identified. The on-going impact of the differences identified between CGAAP and US GAAP are
mostly limited to changes in classification and presentation within the financial statements and in the extent of disclosure requirements. 

Areas where the financial impact of transitioning to US GAAP is more significant are outlined below. These areas do not represent a complete list of
expected changes. The net impact of all adjustments required to restate retained earnings on January 1, 2010 to US GAAP is not expected to be material. However, the net impact of all adjustments required to restate AOCI on January 1,
2010 to US GAAP will be material. The amount of any significant adjustments to retained earnings and AOCI are identified below under the financial statement item to which the adjustments relate. 

Pension and other post-employment benefits – Under US GAAP, the company will recognize its unfunded pension
obligation as a liability in its financial statements and will need to recognize unamortized gains and losses associated with pension and other post-retirement benefits in AOCI in shareholders’ equity. Currently, under CGAAP, the unamortized
amounts together with their impact on the funded status of the pension liability or asset, are disclosed but not recognized. 

Financial impact: Restating the amounts under US GAAP results in a $283 million after-tax unamortized loss recorded in AOCI, a
$308 million increase to pension liability, an $18 million increase to FIT assets, and a $7 million reduction to retained earnings on January 1, 2010. 
 Hedge accounting –The company has determined that certain hedging strategies that qualify for hedge accounting under CGAAP do not qualify for the same treatment under US GAAP
primarily due to differences in effectiveness testing requirements. Effective for hedges put in place beginning in 2010, the company changed its strategies to ensure compliance with US GAAP prospectively. 

Prior to the company’s decision to transition to US GAAP, NSPI, in consultation with interveners and consultants for the UARB,
discussed deferral accounting for all of its economic hedges. Based on these discussions and the company’s decision to adopt US GAAP, NSPI filed an amended accounting policy with the UARB requesting deferral accounting for all of its
economic hedges. The UARB approved the amended regulatory accounting policy in December 2010, resulting in the deferral of the periodic changes in the fair value of these derivatives so that they impact NSPI’s net earnings in a manner
consistent with that achieved if hedge accounting had been applied. 
 Financial impact: NSPI’s amended accounting
policy results in a $44 million increase in AOCI and net regulatory assets to restate its economic hedges on January 1, 2010 to US GAAP. The impact of derecognizing hedge accounting on certain economic hedges under US GAAP related to
Emera’s other affiliates requires a $7 million decrease to AOCI, an $11 million increase to retained earnings and a $4 million increase to investment in direct finance lease on January 1, 2010. 

Income taxes 
 Enacted tax rates 
 US GAAP requires that the enacted tax rate be used
in measuring current taxes and FIT. Under CGAAP, the tax impact of the Part VI.1 tax deduction related to preferred share dividends is recorded at the substantively enacted tax rates, which is consistent with Canada Revenue Agency’s assessing
practice. Under US GAAP, the company will recognize an income tax liability for the difference between the enacted tax rates and the substantively enacted tax rates for the Part VI.1 tax deduction. 

  
  

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 Financial impact: Restating the amounts under US GAAP results in a $9 million
increase to income tax payable and decrease to retained earnings on January 1, 2010. 
 Investment tax credits

 Under CGAAP, certain investment tax credits related to qualifying scientific research and development expenditures are
recorded as a reduction to property, plant and equipment. Under US GAAP, the company will recognize the investment tax credit as a reduction in tax expense. 
 Financial impact: Restating the amounts under US GAAP results in a $4 million increase to property, plant and equipment and retained earnings on January 1, 2010. 

Uncertain tax positions 
 During 2010, the company revised its estimate of the expected benefit from accelerated tax deductions under CGAAP. A portion of the impact of the 2010 revised estimate is related to the US GAAP
guidance for determining the unit of account and resulting expected benefit. As a result, for US GAAP, the company will recognize a portion of the 2010 change in estimate in years prior to January 1, 2010. 

Financial impact: Restating the amounts under US GAAP results in a $4 million decrease in income tax payable and increase
retained earnings on January 1, 2010. 
 US GAAP transition adjustments 

Under US GAAP, the company will recognize the FIT impact on the US GAAP adjustments for pension and other post-employment
benefits and hedge accounting as noted above, and on other US GAAP adjustments to the balance sheet. 
 Financial
impact: As noted above, an $18 million increase to FIT assets is expected as a result of the $301 million ($283 million after-tax) increase in AOCI for pension and post-employment benefits. Other material adjustments are expected to restate FIT
assets and liabilities on January 1, 2010 to US GAAP. The amount of these adjustments is still being determined, however, the impact of a change in FIT expense (recoveries) will be deferred to a regulatory asset or liability where the FIT is
expected to be included in future rates of regulated subsidiaries. Other than the adjustment noted above, the net impact of income tax adjustments under US GAAP required to restate retained earnings and AOCI on January 1, 2010 is not
expected to be material due to rate-regulated accounting. 
 The company has various agreements with external parties that reference CGAAP as
the basis for satisfying financial reporting requirements, including covenant calculations. Emera and NSPI renegotiated their revolving credit facilities with their banking syndicates in June 2010 and in Q4 2010, and both Emera and NSPI reached an
agreement with their trustee to bilaterally amend their respective trust indentures by way of supplemental indentures. These amended agreements each allow for US GAAP as the basis for satisfying financial reporting requirements. 

The impact of the transition to US GAAP on information systems is minimal. 
 All Phase Two activities are complete, with the exception of Emera’s registration with the SEC, which is planned for Q1 2011. NSPI’s registration with the SEC was completed in July 2010.

 Phase Three: Implementation – In-Progress 
 Phase Three began in July 2010 and involves implementing the changes identified and planned in Phase Two that are necessary to comply with US GAAP in 2011, along with SOX and SEC reporting
obligations as they become effective. 

  
  

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2009 and 2010 financial information prepared under CGAAP is being restated to US GAAP for comparative purposes in 2011, with most adjustments now complete and the remainder to be completed
in Q1 2011, including restatement of Q4 2010. Reconciliation of prior period financial information from CGAAP to US GAAP, along with other significant transitional disclosure, will be presented in the 2011 financial statements. 

The company’s financial reporting processes and consolidation software are being reconfigured to support the preparation of US GAAP financial
statements in 2011 and the consolidation of prior period restatements. The required changes are not significant and will be on-going through Q1 2011. 
 As of July 15, 2010, NSPI is an SEC registrant and subject to SEC reporting obligations. NSPI is now required to furnish all filings made with the Canadian securities regulatory authorities
concurrently with the SEC. 
 Changes are being implemented to business processes and ICFR to help ensure an efficient SOX 404 attestation
process. Changes will be completed in Q1 and Q2 2011 for NSPI and Emera, respectively. 
 Education and training activities have occurred
throughout all project phases. In this phase, education activities are focused on ensuring all personnel and senior management impacted by the transition understand the new requirements and have the skills and expertise necessary to ensure the
organization’s on-going ability to report under US GAAP, fulfill its reporting obligations to the SEC and comply with SOX. Members of the company’s Board of Directors participated in education sessions in Q4 2010. Additional education
sessions are planned in Q1 2011, including one for members of the company’s Audit Committee to review the financial impact of the transition, prior period restatements and the company’s transitional disclosure. 

With the exception of the Q4 2010 restatements, the activities of this phase were originally planned to be substantially completed in December 2010,
however, certain implementation activities identified above will be completed in February 2011. These delays do not jeopardize the project’s ability to meet its key milestones, nor the company’s ability to meet its Q1 2011 reporting
obligations. 
 Phase Four: Operational Support – In-Progress 
 Phase Four began January 2011 and is scheduled to be completed by the end of Q2 2011. The impact of transitioning to US GAAP and complying with SEC reporting obligations and SOX requirements will be
fully integrated into the company’s financial reporting processes at that time. 
 Final transitional activities will be completed in this
phase. 
 Following release of the company’s Q1 2011 financial statements, the project will be formally closed and internal resources
currently dedicated to the project will resume responsibility for financial reporting activities within the business. 
 Recently Issued
US GAAP Accounting Standards 
 As indicated above, beginning with its external reporting in Q1 2011, the company will retrospectively
adopt US GAAP as its accounting framework and will no longer prepare its consolidated financial statements under CGAAP. In evaluating the impact of adopting US GAAP, the company has considered US GAAP accounting standards currently in
effect through December 31, 2010. In 2011, additional US GAAP standards will become effective and the company will adopt them in accordance with their individual transition guidelines. The identified issued standards that have effective
dates in 2011 and may be relevant to the company are set out below. 
 Revenue Recognition 

In October 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2009-13, Revenue
Recognition (Topic 605): Multiple-Deliverable Revenue Arrangements. 

  
  

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ASU 2009-13 amends existing US GAAP revenue recognition guidance to eliminate the requirement that all undelivered elements have vendor specific objective evidence of selling price
(“VSOE”) or third party evidence of selling price (“TPE”) before an entity can recognize the portion of an overall arrangement fee that is attributable to items that already have been delivered. In the absence of VSOE and TPE for
one or more delivered or undelivered elements in a multiple-element arrangement, entities will be required to estimate the selling prices of those elements. The overall arrangement fee will be allocated to each element (both delivered and
undelivered items) based on their relative selling prices, regardless of whether those selling prices are evidenced by VSOE or TPE or are based on the entity’s estimated selling price. Application of the “residual method” of
allocating an overall arrangement fee between delivered and undelivered elements will no longer be permitted upon adoption of ASU 2009-13. Additionally, the new guidance will require entities to disclose more information about their multiple-element
revenue arrangements. ASU 2009-13 is effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010. The company will adopt ASU 2009-13 effective January 1, 2011 but
does not expect that its adoption will have a material impact on its consolidated financial statements. 
 Fair Value Measurements

 In January 2010, the FASB issued ASU 2010-06, Improving Disclosures about Fair Value Measurements. ASU 2010-06 amends FASB
Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures, to require reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant
transfers into and out of Level 1 and Level 2 fair-value measurements and information about purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value measurements. The ASU also clarifies existing
fair-value measurement disclosure guidance about the level of disaggregation, inputs, and valuation techniques. Except for the detailed Level 3 roll forward disclosures, the guidance in the ASU was effective for interim and annual reporting periods
beginning after December 15, 2009. The new disclosures about purchases, sales, issuances, and settlements in the roll forward activity for Level 3 fair-value measurements are effective for fiscal years beginning after December 15, 2010.
The company will adopt the disclosure requirements of ASU 2010-06 in its 2011 US GAAP financial reporting but does not expect they will have a material impact on its consolidated financial statements. 

Goodwill Impairment 
 In December 2010,
the FASB issued ASU 2010-28 Intangibles—Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts. ASU 2010-28 amends ASC 350-20 to modify Step 1 of
the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment
exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist consistent with the existing guidance in
US GAAP. ASU 2010-28 is effective for interim periods and fiscal years beginning on or after December 15, 2010. The company will adopt ASU 2010-28 effective January 1, 2011 but does not expect that its adoption will have a material impact
on its consolidated financial statements. 
 SUMMARY OF QUARTERLY RESULTS 
 For the quarter ended 
 millions of dollars (except earnings per common share) 

 

																																	
	 	  	Q4	 	  	Q3	 	  	Q2	 	  	Q1	 	  	Q4	 	  	Q3	 	  	Q2	 	  	Q1	 
	 	  	2010	 	  	2010	 	  	2010	 	  	2010	 	  	2009	 	  	2009	 	  	2009	 	  	2009	 
	 Total revenues
	  	$	392.7	  	  	$	373.5	  	  	$	357.4	  	  	$	430.1	  	  	$	389.1	  	  	$	339.1	  	  	$	333.8	  	  	$	404.1	  
	 Net earnings applicable to common shares
	  	 	39.6	  	  	 	44.8	  	  	 	29.6	  	  	 	77.1	  	  	 	37.5	  	  	 	37.3	  	  	 	38.1	  	  	 	62.8	  
	 Earnings per common share – basic
	  	 	0.35	  	  	 	0.39	  	  	 	0.26	  	  	 	0.68	  	  	 	0.33	  	  	 	0.33	  	  	 	0.34	  	  	 	0.56	  
	 Earnings per common share – diluted
	  	 	0.34	  	  	 	0.39	  	  	 	0.26	  	  	 	0.66	  	  	 	0.33	  	  	 	0.33	  	  	 	0.33	  	  	 	0.53	  


  
  

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 Quarterly total revenues and net earnings applicable to common shares are affected by seasonality, with Q1
and Q4 the strongest periods, reflecting colder weather and fewer daylight hours at those times of year. 

  
  

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