Document:

Audited Annual Financial Statements and MD&A

 Exhibit 4.2 

NOVA SCOTIA POWER INC. 

Financial Statements 

December 31, 2009 and 2008 
  

 1 

 MANAGEMENT REPORT 

Management's Responsibility for Financial Reporting 

The accompanying financial statements of Nova Scotia Power Inc. (“NSPI” or “the Company”) and the information in this annual report
are the responsibility of management and have been approved by the Board of Directors (“Board”). 
 The 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. NSPI is regulated by the Nova Scotia
Utility and Review Board, which also examines and approves NSPI’s accounting policies and practices. In preparation of these 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 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 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 financial statements. 
 NSPI 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 NSPI'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 financial statements. The Board carries out this responsibility principally through its Audit, Nominating & Corporate Governance Committee (“Committee”). 

The Committee is appointed by the Board, and its members are directors who are not officers or employees of NSPI. The 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 financial statements and the external auditors' report. The Committee reports its findings to the Board for consideration when approving the financial statements for issuance to
the shareholders. The Committee also considers, for review by the Board and approval by the shareholders, the appointment of the external auditors. 

The financial statements have been audited by Grant Thornton LLP, the external auditors, in accordance with Canadian generally accepted auditing
standards. Grant Thornton LLP has full and free access to the Committee. 
 February 10, 2010 

 

			
	“Robert R Bennett”	 	“Nancy Tower, FCA”
	President and Chief Executive Officer	 	Chief Financial Officer

  

 2 

 AUDITORS’ REPORT 

To the Shareholders of Nova Scotia Power Inc. 

We have audited the balance sheets of Nova Scotia Power Inc. as at December 31, 2009 and 2008 and the statements of earnings, cash flows, and
changes in shareholders’ equity for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. 

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to
obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. 

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2009
and 2008 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 4, 2010

	
	 “Grant Thornton LLP”

	 Chartered Accountants

  

 3 

 Nova Scotia Power Inc. 

Statements of Earnings 
 Year Ended
December 31 
  

							
	 millions of dollars
	  	2009	  	2008
	 Revenue
	  			  		
	 Electric
	  	$	1,188.1	  	$	1,111.1
	 Other
	  	 	14.0	  	 	15.5
		  	 	 	  	 	 
		  	 	1,202.1	  	 	1,126.6
		  	 	 	  	 	 
	 Cost of operations
	  			  		
	 Fuel for generation and purchased power (note 21)
	  	 	500.7	  	 	471.4
	 Fuel adjustment (note 4)
	  	 	8.5	  	 	—  
	 Operating, maintenance and general (note 21)
	  	 	215.1	  	 	203.7
	 Provincial grants and taxes
	  	 	40.5	  	 	41.2
	 Depreciation and amortization
	  	 	143.9	  	 	133.6
	 Regulatory amortization (note 10)
	  	 	27.2	  	 	17.7
		  	 	 	  	 	 
		  	 	935.9	  	 	867.6
		  	 	 	  	 	 
	 Earnings before financing charges and income taxes
	  	 	266.2	  	 	259.0
	 Financing charges (note 6)
	  	 	114.7	  	 	106.8
		  	 	 	  	 	 
	 Earnings before income taxes
	  	 	151.5	  	 	152.2
	 Income taxes (note 7)
	  	 	42.2	  	 	46.6
		  	 	 	  	 	 
	 Net earnings applicable to common shares
	  	$	109.3	  	$	105.6
		  	 	 	  	 	 

 See accompanying notes to the financial statements. 

 

 4 

 Nova Scotia Power Inc. 

Balance Sheets 
 As at December 31

  

									
	 millions of dollars
	  	2009	 	 	2008
(restated – 
note 2)	 
	 Assets
	  				 			
	 Current assets
	  				 			
	 Cash and cash equivalents
	  	$	0.3	  	 	 	—  	  
	 Accounts receivable (note 8)
	  	 	271.8	  	 	$	210.8	  
	 Due from associated companies (note 21)
	  	 	—  	  	 	 	14.6	  
	 Income tax receivable
	  	 	—  	  	 	 	8.1	  
	 Inventory (note 9)
	  	 	165.6	  	 	 	126.8	  
	 Prepaid expenses
	  	 	7.0	  	 	 	6.2	  
	 Future income tax assets (note 4, 7)
	  	 	34.4	  	 	 	—  	  
	 Derivatives in a valid hedging relationship
	  	 	19.4	  	 	 	47.8	  
	 Held-for-trading derivatives
	  	 	8.9	  	 	 	63.0	  
		  	 	 	 	 	 	 	 
		  	 	507.4	  	 	 	477.3	  
		  	 	 	 	 	 	 	 
	 Long-term receivable (note 8)
	  	 	—  	  	 	 	56.4	  
	 Derivatives in a valid hedging relationship
	  	 	29.8	  	 	 	115.5	  
	 Held-for-trading derivatives
	  	 	6.2	  	 	 	54.0	  
	 Other assets (note 10)
	  	 	339.1	  	 	 	353.7	  
	 Intangibles (note 12)
	  	 	65.7	  	 	 	58.7	  
	 Property, plant and equipment (note 11)
	  	 	2,365.6	  	 	 	2,286.5	  
	 Construction work in progress
	  	 	152.8	  	 	 	88.6	  
		  	 	2,518.4	  	 	 	2,375.1	  
		  	 	 	 	 	 	 	 
		  	$	3,466.6	  	 	$	3,490.7	  
		  	 	 	 	 	 	 	 
	 Liabilities and Shareholders’ Equity
	  				 			
	 Current liabilities
	  				 			
	 Current portion of long-term debt (note 15)
	  	$	100.7	  	 	$	125.1	  
	 Current portion of preferred shares (note 16)
	  	 	—  	  	 	 	125.0	  
	 Short-term debt (note 14)
	  	 	199.5	  	 	 	22.8	  
	 Accounts payable and accrued charges
	  	 	213.9	  	 	 	179.5	  
	 Due to associated companies (note 21)
	  	 	0.7	  	 	 	—  	  
	 Income tax payable
	  	 	1.2	  	 	 	—  	  
	 Dividends payable
	  	 	1.7	  	 	 	3.2	  
	 Derivatives in a valid hedging relationship
	  	 	53.0	  	 	 	104.5	  
	 Held-for-trading derivatives
	  	 	12.2	  	 	 	26.6	  
		  	 	 	 	 	 	 	 
		  	 	582.9	  	 	 	586.7	  
		  	 	 	 	 	 	 	 
	 Derivatives in a valid hedging relationship
	  	 	20.0	  	 	 	51.3	  
	 Held-for-trading derivatives
	  	 	1.3	  	 	 	11.7	  
	 Future income tax liabilities (note 7)
	  	 	52.0	  	 	 	—  	  
	 Asset retirement obligations (note 13)
	  	 	101.5	  	 	 	87.6	  
	 Other liabilities (note 10)
	  	 	91.5	  	 	 	180.3	  
	 Long-term debt (note 15)
	  	 	1,397.0	  	 	 	1,296.7	  
	 Preferred shares (note 16)
	  	 	135.0	  	 	 	135.0	  
	 Shareholders’ equity
	  				 			
	 Common shares (note 17)
	  	 	934.7	  	 	 	930.6	  
	 Accumulated other comprehensive loss
	  	 	(44.0	) 	 	 	(0.6	) 
	 Retained earnings (note 2)
	  	 	194.7	  	 	 	211.4	  
		  	 	 	 	 	 	 	 
		  	 	1,085.4	  	 	 	1,141.4	  
		  	 	 	 	 	 	 	 
		  	$	3,466.6	  	 	$	3,490.7	  
		  	 	 	 	 	 	 	 

 Changes in accounting policies and practices (note 2), Contingencies (note 22), Commitments (notes 5, 20
and 23), Guarantees (note 24) 
 See accompanying notes to the financial statements. 

Approved on behalf of the Board of Directors 
  

									
	 “George Caines”
	 		 		 	“Robert R. Bennett”	 	
	 Chairman
	 		 		 	President and Chief Executive Officer	 	

  

 5 

 Nova Scotia Power Inc. 

Statements of Cash Flows 
 Year Ended
December 31 
  

									
	 millions of dollars
	  	2009	 	 	2008
(restated – 
 note 2)	 
	 Operating activities
	  				 			
	 Net earnings applicable to common shares
	  	$	109.3	  	 	$	105.6	  
	 Non-cash items:
	  				 			
	 Depreciation and amortization
	  	 	143.9	  	 	 	133.6	  
	 Amortization of other assets
	  	 	13.6	  	 	 	13.7	  
	 Regulatory amortization
	  	 	27.2	  	 	 	17.7	  
	 Allowance for funds used during construction
	  	 	(6.4	) 	 	 	(3.2	) 
	 Future income taxes
	  	 	(3.4	) 	 	 	—  	  
	 Post-retirement benefits
	  	 	(17.3	) 	 	 	10.2	  
	 Fuel adjustment
	  	 	8.5	  	 	 	—  	  
	 Changes in fair value of derivative instruments
	  	 	(8.3	) 	 	 	(8.9	) 
	 Other non-cash operating items
	  	 	0.5	  	 	 	(2.0	) 
	 Other cash operating items
	  	 	(6.1	) 	 	 	(3.7	) 
		  	 	 	 	 	 	 	 
		  	 	261.5	  	 	 	263.0	  
	 Change in non-cash operating working capital (note 18)
	  	 	11.2	  	 	 	(88.7	) 
		  	 	 	 	 	 	 	 
	 Net cash provided by operating activities
	  	 	272.7	  	 	 	174.3	  
		  	 	 	 	 	 	 	 
	 Investing activities
	  				 			
	 Property, plant and equipment
	  	 	(253.6	) 	 	 	(155.0	) 
	 Intangibles
	  	 	(10.1	) 	 	 	(3.0	) 
	 Retirement spending net of salvage
	  	 	(4.9	) 	 	 	(5.4	) 
		  	 	 	 	 	 	 	 
	 Net cash used in investing activities
	  	 	(268.6	) 	 	 	(163.4	) 
		  	 	 	 	 	 	 	 
	 Financing activities
	  				 			
	 Retirements of long-term debt
	  	 	(125.0	) 	 	 	(115.0	) 
	 Issuance of long-term debt
	  	 	250.0	  	 	 	150.0	  
	 Increase (decrease) in short-term debt
	  	 	123.8	  	 	 	(44.2	) 
	 Issuance of common shares
	  	 	—  	  	 	 	100.0	  
	 Redemption of preferred shares
	  	 	(125.0	) 	 	 	—  	  
	 Dividends on common shares
	  	 	(126.0	) 	 	 	(75.0	) 
	 Accounts receivable securitization
	  	 	—  	  	 	 	(25.0	) 
	 Other financing activities
	  	 	(1.6	) 	 	 	(3.6	) 
		  	 	 	 	 	 	 	 
	 Net cash used in financing activities
	  	 	(3.8	) 	 	 	(12.8	) 
		  	 	 	 	 	 	 	 
	 Increase (decrease) in cash and cash equivalents
	  	 	0.3	  	 	 	(1.9	) 
	 Cash and cash equivalents, beginning of year
	  	 	—  	  	 	 	1.9	  
		  	 	 	 	 	 	 	 
	 Cash and cash equivalents, end of year
	  	$	0.3	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Cash and cash equivalents consists of:
	  				 			
	 Cash
	  	$	0.3	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Cash and cash equivalents, end of year
	  	$	0.3	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Supplemental disclosure of cash paid:
	  				 			
	 Interest
	  	$	96.4	  	 	$	98.4	  
	 Income and capital taxes
	  	$	37.3	  	 	$	52.1	  
		  	 	 	 	 	 	 	 

 See accompanying notes to the financial statements. 

 

 6 

 Nova Scotia Power Inc. 

Statements of Changes in Shareholders’ Equity 
  

																
	 For the year ended December 31, 2009

millions of dollars
	  	Common
Shares	  	Accumulated Other
Comprehensive
Income (Loss)
(“AOCI”)	 	 	Retained
Earnings	 	 	Total AOCI and
Retained
Earnings	 
	  	  	 	 
	 Balance, December 31, 2008
	  	$	930.6	  	$	(0.6	) 	 	$	211.4	  	 	$	210.8	  
		  	 	 	  	 	 	 	 	 	 	 	 	 	 	 
	 Comprehensive income:
	  			  				 				 			
	 Net earnings applicable to common shares
	  	 	—  	  	 	—  	  	 	 	109.3	  	 	 	109.3	  
	 Net losses on derivatives in a valid hedging relationship
	  	 	—  	  	 	(113.2	) 	 	 	—  	  	 	 	(113.2	) 
	 Reclassification of hedging losses included in income
	  	 	—  	  	 	40.5	  	 	 	—  	  	 	 	40.5	  
	 Reclassification of hedging losses included in inventory
	  	 	—  	  	 	29.3	  	 	 	—  	  	 	 	29.3	  
		  	 	 	  	 	 	 	 	 	 	 	 	 	 	 
	 Total comprehensive (loss) income
	  	 	—  	  	 	(43.4	) 	 	 	109.3	  	 	 	65.9	  
	 Issuance of common shares (note 17)
	  	 	4.1	  	 	—  	  	 	 	—  	  	 	 	—  	  
	 Dividends declared on common shares
	  	 	—  	  	 	—  	  	 	 	(126.0	) 	 	 	(126.0	) 
		  	 	 	  	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31, 2009
	  	$	934.7	  	$	(44.0	) 	 	$	194.7	  	 	$	150.7	  
		  	 	 	  	 	 	 	 	 	 	 	 	 	 	 

  

																
	 For the year ended December 31, 2008

millions of dollars
	  	Common
Shares	  	AOCI	 	 	Retained
Earnings	 	 	Total AOCI and
Retained
Earnings	 
	 Balance, December 31, 2007
	  	$	830.6	  	$	(48.4	) 	 	$	184.1	  	 	$	135.7	  
		  	 	 	  	 	 	 	 	 	 	 	 	 	 	 
	 Accounting policy change
	  	 	—  	  	 	—  	  	 	 	(3.3	) 	 	 	(3.3	) 
	 Comprehensive income:
	  			  				 				 			
	 Net earnings applicable to common shares
	  	 	—  	  	 	—  	  	 	 	105.6	  	 	 	105.6	  
	 Net gain on derivatives in a valid hedging relationship
	  	 	—  	  	 	89.4	  	 	 	—  	  	 	 	89.4	  
	 Reclassification of hedging gains included in income
	  	 	—  	  	 	(26.9	) 	 	 	—  	  	 	 	(26.9	) 
	 Reclassification of hedging gains included in inventory
	  	 	—  	  	 	(14.7	) 	 	 	—  	  	 	 	(14.7	) 
		  	 	 	  	 	 	 	 	 	 	 	 	 	 	 
	 Total comprehensive income
	  	 	—  	  	 	47.8	  	 	 	105.6	  	 	 	153.4	  
	 Issuance of common shares (note 17)
	  	 	100.0	  	 	—  	  	 	 	—  	  	 	 	—  	  
	 Dividends declared on common shares
	  	 	—  	  	 	—  	  	 	 	(75.0	) 	 	 	(75.0	) 
		  	 	 	  	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31, 2008
	  	$	930.6	  	$	(0.6	) 	 	$	211.4	  	 	$	210.8	  
		  	 	 	  	 	 	 	 	 	 	 	 	 	 	 

 See accompanying notes to the financial statements. 

 

 7 

 Nova Scotia Power Inc. 

Notes to the Financial Statements 

December 31, 2009 and 2008 
 1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
 Nova Scotia Power Inc., created following 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 is regulated under a cost of service model, with rates set to cover prudently incurred costs of providing electricity service to customers, and
provide an opportunity to earn an appropriate return to investors. NSPI’s regulated return on equity (“ROE”) range for 2009 is 9.1% to 9.6% (with 9.35% used to set rates) on an allowed common equity component of up to 45% of
NSPI’s total capitalization. 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 have set, as a condition, 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. 
 NSPI’s accounting policies are subject to examination and approval by the UARB. 

NSPI follows Canadian generally accepted accounting principles (“CGAAP”). The accounting policies approved by the regulator of NSPI 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 financial statements. 
  

	 	a.	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
made include: measurement of regulatory assets and liabilities (note 10), property plant and equipment depreciation rates (note 1e), intangible assets amortization rates (note 1f), income taxes (note 7), post-employment benefits (note 3), accounts
receivable (note 8), asset retirement obligations (note 13), commitments (note 22) and contingencies (note 23). Actual results may differ from these estimates. 
  

	 	b.	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. 

  

 8 

	 	•	 	 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 are recognized at rates set by the UARB. The Company is unable to determine the effect the absence of
rate regulation would have on electric revenue. 
  

	 	c.	Allowance for Funds Used during Construction  

Accounting for the impact of rate regulation: 

In accordance with accounting policies determined by the UARB, NSPI provides 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” and
“Construction work in progress” for financial reporting purposes and is charged to operations through depreciation over the service life of the related assets and recovered through future revenues. 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. 
  

	 	d.	Regulatory Amortization 

Accounting for the impact of rate regulation: 

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 10. 

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. In the absence of UARB approved deferral, the taxes would have been expensed in 2005. 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. In the absence of UARB approved
deferral, 2009 expenses incurred would have been expensed in 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 deferral, the vegetation management expenses incurred would have been expensed in 2008. More details are provided in note 10. 

 

	 	e.	Property, Plant and Equipment  

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

 

 9 

 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. 

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
	  	2009	 	 	2008	 
	 Generation
	  			 		
	 Thermal
	  	2.50	% 	 	2.44	% 
	 Gas turbines
	  	2.47	% 	 	2.32	% 
	 Combustion turbines
	  	3.33	% 	 	3.33	% 
	 Hydroelectric
	  	1.51	% 	 	1.39	% 
	 Wind turbines
	  	5.00	% 	 	5.00	% 
	 Transmission
	  	2.76	% 	 	2.80	% 
	 Distribution
	  	4.15	% 	 	4.07	% 
	 General plant
	  	7.07	% 	 	6.85	% 
	 General plant under capital lease
	  	14.25	% 	 	10.95	% 
	 Weighted average depreciation rate
	  	3.13	% 	 	3.04	% 

 In accordance
with regulator-approved accounting policies, when depreciable property, plant and equipment of NSPI 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 are charged to net earnings as incurred. 
  

	 	f.	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 UARB approval. The estimated weighted average service life for
the Company’s intangible assets is 63 years (2008 – 66 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. 
  

 10 

 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
	  	2009	 	 	2008	 
	 Transmission
	  	1.21	% 	 	1.16	% 
	 Distribution
	  	1.57	% 	 	1.57	% 
	 Other
	  	12.03	% 	 	10.45	% 
	 Weighted average amortization rate
	  	3.66	% 	 	3.23	% 

  

	 	g.	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 information technology, executive and other support functions, employee benefits, insurance, 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. 
  

	 	h.	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(e). Payments on operating leases are expensed
as incurred. 
  

	 	i.	Income Taxes and Investment Tax Credits 

NSPI 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 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. For derivatives recorded through AOCI, the future income tax assets and liabilities have been recorded to a regulatory asset or liability where
the future income tax is expected to be included in future rates. More details are provided in note 7. 
  

	 	j.	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.

  

 11 

 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, 2009 (2008 – 9 years). 

On January 1, 2000, NSPI 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. 
  

	 	k.	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 as at December 31, 2009 or 2008. 
  

	 	l.	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. 
  

	 	m.	Debt Financing Costs 

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

 

	 	n.	Derivative Financial & Commodity Instruments  

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 (“HFT”). Collectively, these contracts are referred to as derivatives. 

The Company recognizes the fair value of all its derivatives that are not designated as contracts held for normal purchase or sale 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 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. 

 

 12 

 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. 

Where documentation and effectiveness requirements are not met, the change in fair value of the derivative is recognized in earnings in
the reporting period. The Company also recognizes the change in fair value of its HFT derivatives in earnings of 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 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”. 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”. Amounts received
or paid related to HFT derivatives are reflected in “Other revenue”, unless alternative treatment is available as approved by the UARB. 

Cash flows related to derivatives 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 can not 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 financial
commodity hedges 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. 

Further details on the regulatory assets and liabilities recognized as a result of the above can be found in note 10. 

 

	 	o.	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. 
  

 13 

	 	p.	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 POLICIES AND PRACTICES 

The Canadian Institute of Chartered Accountants (“CICA”) has issued new accounting Standard 3064 Goodwill and Intangibles, various new
accounting standards related to the accounting for rate-regulated operations, Emerging Issues Committee Abstract of Issue Discussed 173 Credit Risk and the Fair Value of Financial Assets and Financial Liabilities (“EIC-173”), and
amendments to Standard 3862 Financial Instruments – Disclosures, which are applicable to NSPI’s 2009 fiscal year. The following provides more information on each change. 

Goodwill and Intangibles: Under Standard 3064, goodwill requirements have not changed. The requirements for intangible assets now clarify that
costs may only be deferred when they relate to an item that meets the definition of an asset. An intangible asset must be identifiable; be a resource over which the Company has control; generate probable future economic benefits; and have a reliably
measurable cost. Further information can be found in note 12. 
 Rate-Regulated Operations: These new standards include removing the
temporary exemption in Standard 1100 Generally Accepted Accounting Principles pertaining to the application of the standard to the recognition and measurement of assets and liabilities arising from rate regulation; and amending Standard 3465 Income
Taxes to require the recognition of future income tax assets and liabilities for the amount of future income taxes expected to be included in future rates and recovered from or paid to future customers. 

As a result of the new standards, NSPI recognized its future income tax assets and liabilities. In accordance with the Company’s rate-regulated
accounting policies covering income taxes, NSPI deferred any future income taxes to a regulatory asset or liability where the future income taxes are expected to be included in future rates. The Company has applied the new standard retrospectively
without restatement of prior periods. Further information can be found in note 7. 
 In accordance with Standard 1100, NSPI determined all of
its regulatory assets and liabilities qualified for recognition under CGAAP as well as US Financial Accounting Standard Board’s Accounting Standard Codification 980, Regulated Operations. 

Financial Instruments: EIC-173 requires that a company take into account its own credit risk and the credit risk of the counterparty in
determining the fair value of financial assets and financial liabilities. The Company has applied the new requirements retrospectively without restatement of prior periods, the effect of which was immaterial. 

Financial Instruments – Disclosures: In June 2009, the CICA issued amendments to Standard 3862 Financial Instruments – Disclosures to
include additional disclosure requirements about the fair value measurement of financial instruments and to enhance liquidity risk disclosures. Further information can be found in note 20. 

The above accounting policy changes did not affect earnings. 

Derivative Financial & Commodity Instruments: 

Accounting for the impact of rate regulation 

The UARB allows NSPI to apply hedge accounting to hedging relationships that do not meet the probability requirement of Standard 3865 Hedges due to
NSPI’s ability to fuel switch at the Tufts Cove generation station. 
  

 14 

 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 between “Fuel for generation and purchased power” and “Fuel adjustment” as a result of the fuel adjustment mechanism
(“FAM”) implemented in 2009. The change in accounting practice is being applied prospectively, beginning in 2009, as required by the UARB. 

At December 31, 2009, the change in accounting practice resulted in $0.4 million additional interest costs in “Financing charges” ($0.3
million after-tax) and $0.4 million increase in the FAM regulatory liability in “Other Liabilities”. 
 Future Accounting Policy
Changes 
 Business Combinations: In January 2009, the CICA issued Standard 1582 Business Combinations (“1582”) together
with Standard 1601 Consolidated Financial Statements (“1601”) and Standard 1602 Non-Controlling Interests (“1602”) applicable to NSPI’s 2011 fiscal year, replacing Standard 1581 Business Combinations and Standard 1600
Consolidated Financial Statements. 
 Adoption of 1582 will change the measurement of non-controlling interest and goodwill for future
acquisitions. Changes also include expensing acquisition-related transaction costs rather than including the costs as part of the purchase price and the disallowing recognition of restructuring accruals by the acquirer. Standard 1582 will affect the
recognition of business combinations completed by the Company on or after January 2011. 
 Standard 1601 establishes standards for the
preparation of consolidated financial statements and Standard 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The adoption of 1601
and 1602 will result in non-controlling interests being presented on the consolidated balance sheet as components of equity rather than as liabilities. Also, net earnings and components of other comprehensive income attributable to the owners of the
parent and to the non-controlling interests are required to be separately disclosed on the statement of earnings. The Company is currently assessing the effect of 1601 and 1602 on its financial statements but does not expect a material impact.

 3. EMPLOYEE FUTURE BENEFITS 

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. 
 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, 2009. 

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, 2009	  	December 31, 2010
	 Acquired companies pension plan
	  	December 31, 2009	  	December 31, 2010

  

 15 

 Total cash amount 

Total cash amount for 2009, 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 $32.1 million (2008 – $16.7 million). 

Accrued pension and non-pension benefit asset (liability) 
  

																	
	 	  	2009	 	 	2008	 
	 millions of dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefits 
plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefits 
plan	 
	 Assumptions (weighted average)
	  				 				 				 			
	 Accrued benefit obligation – December 31:
	  				 				 				 			
	 Discount rate
	  	 	6.50	% 	 	 	6.50	% 	 	 	7.50	% 	 	 	7.50	% 
	 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)
	  	 	—  	  	 	 	5.00	% 	 	 	—  	  	 	 	6.00	% 
	    - ultimate
	  	 	—  	  	 	 	4.00	% 	 	 	—  	  	 	 	4.00	% 
	    - year ultimate reached
	  	 	—  	  	 	 	2011	  	 	 	—  	  	 	 	2011	  
	 Benefit cost for year ending December 31:
	  				 				 				 			
	 Discount rate
	  	 	7.50	% 	 	 	7.50	% 	 	 	5.75	% 	 	 	5.75	% 
	 Expected long-term return on plan assets
	  	 	7.25	% 	 	 	—  	  	 	 	7.50	% 	 	 	—  	  
	 Rate of compensation increase
	  	 	3% to 5.5	% 	 	 	3% to 5.5	% 	 	 	3% to 5.5	% 	 	 	3% to 5.5	% 
	 Health care trend - initial (current year)
	  	 	—  	  	 	 	6.00	% 	 	 	—  	  	 	 	7.00	% 
	    - ultimate
	  	 	—  	  	 	 	4.00	% 	 	 	—  	  	 	 	4.00	% 
	    - year ultimate reached
	  	 	—  	  	 	 	2011	  	 	 	—  	  	 	 	2011	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Accrued benefit obligations
	  				 				 				 			
	 Balance, January 1
	  	$	667.2	  	 	$	36.1	  	 	$	778.3	  	 	$	40.9	  
	 Employer current service cost
	  	 	6.5	  	 	 	1.3	  	 	 	10.4	  	 	 	1.6	  
	 Employee contributions
	  	 	5.2	  	 	 	—  	  	 	 	5.0	  	 	 	—  	  
	 Interest cost
	  	 	49.0	  	 	 	2.6	  	 	 	44.3	  	 	 	2.3	  
	 Actuarial losses (gains)
	  	 	95.4	  	 	 	0.4	  	 	 	(134.8	) 	 	 	(4.7	) 
	 Benefits paid
	  	 	(38.1	) 	 	 	(4.1	) 	 	 	(36.0	) 	 	 	(4.0	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	785.2	  	 	 	36.3	  	 	 	667.2	  	 	 	36.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Fair value of plan assets
	  				 				 				 			
	 Balance, January 1
	  	 	508.8	  	 	 	—  	  	 	 	640.7	  	 	 	—  	  
	 Employer contributions
	  	 	26.9	  	 	 	4.1	  	 	 	11.9	  	 	 	4.0	  
	 Employee contributions
	  	 	5.2	  	 	 	—  	  	 	 	5.0	  	 	 	—  	  
	 Actual return on plan assets
	  	 	89.3	  	 	 	—  	  	 	 	(112.8	) 	 	 	—  	  
	 Benefits paid
	  	 	(38.1	) 	 	 	(4.1	) 	 	 	(36.0	) 	 	 	(4.0	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance, December 31
	  	 	592.1	  	 	 	—  	  	 	 	508.8	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Reconciliation of financial status to accrued benefit asset, December 31
	  				 				 				 			
	 Fair value of plan assets
	  	 	592.1	  	 	 	—  	  	 	 	508.8	  	 	 	—  	  
	 Accrued benefit obligations
	  	 	785.2	  	 	 	36.3	  	 	 	667.2	  	 	 	36.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Plan deficit
	  	 	(193.1	) 	 	 	(36.3	) 	 	 	(158.4	) 	 	 	(36.1	) 
	 Unamortized past service (gains) costs
	  	 	(0.4	) 	 	 	1.6	  	 	 	(0.4	) 	 	 	1.8	  
	 Unamortized actuarial losses (gains)
	  	 	257.0	  	 	 	(2.2	) 	 	 	203.0	  	 	 	(2.9	) 
	 Unamortized transitional obligation
	  	 	0.1	  	 	 	6.7	  	 	 	0.1	  	 	 	9.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Accrued benefit asset (liability)
	  	$	63.6	  	 	$	(30.2	) 	 	$	44.3	  	 	$	(28.2	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

  

 16 

 The amounts recognized in “Other assets” and “Other liabilities” are as follows:

  

																	
	 	  	2009	 	 	2008	 
	 millions of dollars
	  	Defined benefit
pension plans	 	 	Non-pension
benefits 
plans	 	 	Defined benefit
pension plans	 	 	Non-pension
benefits 
plan	 
	 Accrued benefit asset
	  	$	94.2	  	 	 	—  	  	 	$	74.8	  	 	 	—  	  
	 Accrued benefit liability
	  	 	(30.6	) 	 	$	(30.2	) 	 	 	(30.5	) 	 	$	(28.2	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Net accrued benefit asset (liability)
	  	$	63.6	  	 	$	(30.2	) 	 	$	44.3	  	 	$	(28.2	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

  

													
	 Defined benefit plans asset allocation

(% of plan assets)
	  	2009	 	 	2008	 
	  	Employee
pension plan	 	 	Acquired
companies
pension plan	 	 	Employee
pension plan	 	 	Acquired
companies
pension plan	 
	 Equity securities
	  	64	% 	 	62	% 	 	56	% 	 	50	% 
	 Debt securities
	  	36	% 	 	37	% 	 	41	% 	 	47	% 
	 Cash
	  	—  	  	 	1	% 	 	3	% 	 	3	% 
		  	 	 	 	 	 	 	 	 	 	 	 
	 Total
	  	100	% 	 	100	% 	 	100	% 	 	100	% 
		  	 	 	 	 	 	 	 	 	 	 	 

 As at December 31, 2009, 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, 2009, all post-retirement benefit plans have accrued benefit obligations in excess of assets. 

 

																	
	 Benefits cost components

millions of dollars
	  	2009	 	 	2008	 
	 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
	  	$	6.5	  	 	$	1.3	  	 	$	10.4	  	 	$	1.6	  
	 Interest on accrued benefits
	  	 	49.0	  	 	 	2.6	  	 	 	44.3	  	 	 	2.3	  
	 Less: actual return on plan assets
	  	 	(89.3	) 	 	 	—  	  	 	 	112.8	  	 	 	—  	  
	 Actuarial losses (gains) on accrued benefit obligation
	  	 	95.4	  	 	 	0.4	  	 	 	(134.8	) 	 	 	(4.7	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Future benefit costs before adjustments
	  	 	61.6	  	 	 	4.3	  	 	 	32.7	  	 	 	(0.8	) 
	 Adjustments to recognize long-term nature of costs:
	  				 				 				 			
	 Difference between expected return on assets and actual return
	  	 	40.8	  	 	 	—  	  	 	 	(159.6	) 	 	 	—  	  
	 Amortization of transitional obligation
	  	 	—  	  	 	 	2.2	  	 	 	—  	  	 	 	2.2	  
	 Difference between amortization of actuarial (gains) losses and actual actuarial (gains) losses on accrued benefit obligations

	  	 	(94.8	) 	 	 	(0.7	) 	 	 	146.8	  	 	 	4.8	  
	 Difference between amortization of past service costs and past service costs for the year
	  	 	—  	  	 	 	0.2	  	 	 	—  	  	 	 	0.2	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total cost recognized
	  	$	7.6	  	 	$	6.0	  	 	$	19.9	  	 	$	6.4	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Defined contribution plan
	  				 				 				 			
	 Employer cost
	  	$	1.0	  	 	 	—  	  	 	$	0.7	  	 	 	—  	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 The expected return on plan assets is determined based on the market-related value of plan assets of $670.5 million at
January 1, 2009 (2008 – $633.3 million), adjusted for interest on certain cash flows during the year. 
  

 17 

 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 2009: 
  

								
	 millions of dollars
	  	Increase	  	Decrease	 
	 Current service cost and interest cost
	  	$	0.2	  	$	(0.1	) 
	 Accrued benefit obligation, December 31
	  	$	1.6	  	$	(1.4	) 

 4. FUEL ADJUSTMENT 

The UARB approved the implementation of a FAM in NSPI’s 2009 General Rate Decision effective January 1, 2009. The FAM is subject to an incentive
with NSPI retaining or absorbing 10% of the over or under-recovered amount less the difference between the incentive threshold and the base fuel cost to a maximum of $5 million. 

For the year ended December 31, 2009, actual fuel costs were less than amounts recovered from customers. The difference has been recorded as an
expense, and accrued to a FAM regulatory liability in “Other liabilities”. 
 The Company has recognized a future income tax recovery
related to the fuel adjustment based on NSPI’s applicable statutory income tax rate. 
 As at December 31, 2009, NSPI’s FAM
regulatory liability was $9.9 million (2008 – nil), and related future income tax asset was $3.4 million (2008 – nil). The FAM regulatory liability includes amounts recognized as a fuel adjustment and associated interest carrying costs
included in “Financing charges”. The fuel adjustment includes fuel related foreign exchange gains and losses that are reported as part of “Financing charges”. 

In the absence of UARB approval, the fuel adjustment would not have been recognized and earnings for the year ended December 31, 2009 would be $9.9
million ($6.5 million after-tax) higher (2008 – nil). 
 The first rate adjustment under the FAM, effective on January 1, 2010, was
approved by the UARB on December 9, 2009. 
 5. OPERATING LEASES 

The Company has entered into operating lease agreements for office space and telecommunication services, which expire in 2010 and 2011. Future minimum
annual lease payments under the leases are as follows: 
  

				
	 millions of dollars
	  	 
	 2010
	  	$	9.6
	 2011
	  	 	1.1
		  	 	 
		  	$	10.7
		  	 	 

 For the year ended December 31, 2009 the Company recognized $9.5
million (2008 - $9.8 million) of operating leases in “Operating, maintenance and general expense”. 
  

 18 

 6. FINANCING CHARGES 

Financing charges consists of the following: 
  

									
	 millions of dollars
	  	2009	 	 	2008	 
	 Interest - long-term debt
	  	$	98.2	  	 	$	89.8	  
	              - short-term debt
	  	 	3.4	  	 	 	7.7	  
	 Preferred share dividends (note 16)
	  	 	9.5	  	 	 	14.1	  
	 Amortization of defeasance cost (note 10)
	  	 	12.1	  	 	 	12.3	  
	 Amortization of debt financing costs
	  	 	1.8	  	 	 	1.6	  
	 Allowance for funds used during construction
	  	 	(6.4	) 	 	 	(3.2	) 
	 Foreign exchange gains
	  	 	(3.9	) 	 	 	(15.5	) 
		  	 	 	 	 	 	 	 
		  	$	114.7	  	 	$	106.8	  
		  	 	 	 	 	 	 	 

 7. INCOME TAXES 

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

 

															
	 millions of dollars
	  	2009	 	 	2008	 
	 Earnings before income taxes
	  	$	151.5	  	 			 	$	152.2	  	 		
	 Income taxes, at statutory rates
	  	 	53.0	  	 	35.0	% 	 	 	54.0	  	 	35.5	% 
	 Unrecorded future income taxes on regulated earnings (note 10)
	  	 	—  	  	 	—  	  	 	 	(10.8	) 	 	(7.1	)% 
	 Future income taxes on regulated earnings deferred to regulatory assets (note 10)
	  	 	(22.9	) 	 	(15.1	)% 	 	 	—  	  	 	—  	  
	 Non-deductible preferred share dividends
	  	 	3.3	  	 	2.2	% 	 	 	5.0	  	 	3.3	% 
	 Non-deductible regulatory amortization (note 10)
	  	 	9.3	  	 	6.1	% 	 	 	5.8	  	 	3.8	% 
	 Income tax recovery
	  	 	—  	  	 	—  	  	 	 	(6.5	) 	 	(4.3	)% 
	 Other
	  	 	(0.5	) 	 	(0.3	)% 	 	 	(0.9	) 	 	(0.6	)% 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 
		  	$	42.2	  	 	27.9	% 	 	$	46.6	  	 	30.6	% 
	 Income taxes – current
	  	$	45.6	  	 			 	$	46.6	  	 		
		  	 	 	 	 			 	 	 	 	 		
	 Income taxes – future (note 4)
	  	$	(3.4	) 	 			 	 	—  	  	 		
		  	 	 	 	 			 	 	 	 	 		

 The future income tax assets and liabilities comprise the following: 

												
	 	  	Current portion	  	Long-term portion
	 millions of dollars
	  	2009	  	2008	  	2009	 	 	2008
	 Future income tax assets:
	  			  		  				 	
	 Derivatives
	  	$	25.3	  	—  	  	 	—  	  	 	—  
	 Tax loss carry forwards
	  	 	4.1	  	—  	  	 	—  	  	 	—  
	 Other
	  	 	5.0	  	—  	  	 	—  	  	 	—  
		  	 	 	  	 	  	 	 	 	 	 
		  	$	34.4	  	—  	  	 	—  	  	 	—  
		  	 	 	  	 	  	 	 	 	 	 
	 Future income tax liabilities:
	  			  		  				 	
	 Property, plant and equipment
	  	 	—  	  	—  	  	$	82.2	  	 	—  
	 Derivatives
	  	 	—  	  	—  	  	 	3.2	  	 	—  
	 Asset retirement obligations
	  	 	—  	  	—  	  	 	(45.2	) 	 	—  
	 Pension
	  	 	—  	  	—  	  	 	14.9	  	 	—  
	 Defeasance costs
	  	 	—  	  	—  	  	 	20.0	  	 	—  
	 Intangibles
	  	 	—  	  	—  	  	 	(23.2	) 	 	—  
	 Other
	  	 	—  	  	—  	  	 	0.1	  	 	—  
		  	 	 	  	 	  	 	 	 	 	 
		  	 	—  	  	—  	  	$	52.0	  	 	—  
		  	 	 	  	 	  	 	 	 	 	 

 The offset to substantially all of the net future income tax assets
and liabilities noted above have been recorded as a regulatory asset in “Other assets”. These amounts include a gross up to reflect the income tax associated with future revenues required to fund these net future income tax liabilities.
See note 2 for additional information. 
  

 19 

 The Company has applied the amendments of CICA Standard 3465 Income Taxes during 2009. As a result of these
amendments, NSPI recognized future income tax assets and liabilities. The Company has applied the standard retrospectively without restatement of prior periods, which resulted in the following increases: 

 

				
	 As at

millions of dollars
	  	January 1
2009
	 Assets
	  		
	 Current assets
	  		
	 Future income tax assets
	  	$	31.6
	 Other assets
	  	 	16.2
		  	 	 
		  	$	47.8
		  	 	 
	 Liabilities and Shareholders’ Equity
	  		
	 Future income tax liabilities
	  	$	47.8
		  	 	 
		  	$	47.8
		  	 	 

 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 $19.3
million lower in 2009 (2008 – $28.7 million). 
 During 2008, NSPI accelerated the deduction of capitalized expenses pertaining to the 2007
tax year. As a result, in 2008, NSPI recorded an income tax recovery of $6.5 million. Absent NSPI’s regulator approved taxes payable accounting policy, the recovery would have no effect on the total current and future income tax expense and net
earnings would have been $6.5 million lower for the year ended December 31, 2008. 
 8. ACCOUNTS RECEIVABLE 

At December 31, 2009, the Company had unbilled revenue included in accounts receivable in the amount of $85.4 million (2008 – $80.2 million).
The unbilled revenue is an estimate of the amount of revenue related to energy delivered to customers since the date their meters were last read. Actual results may differ from this estimate. 

NSPI’s existing natural gas purchase agreement includes a price adjustment clause covering three years of natural gas purchases. The clause states
that NSPI will pay for all gas purchases at the agreed contract price, but will be entitled to a price rebate on a portion of the volumes, settled in November 2007 and November 2010. In November 2007, NSPI received the first settlement of the
pricing rebate. Management’s best estimate of the price rebate, to be settled in November 2010, based on the contract specifications using actual and forward market pricing, is $82.1 million (2008 – $56.4 million) and is reflected in
“Accounts receivable”, whereas it was reflected in “Long-term receivable” in 2008. 
  

 20 

 9. 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
	  	2009	 	 	2008	 	 	2009	 	 	2008	 
	 Inventory, beginning of period
	  	$	101.6	  	 	$	67.5	  	 	$	25.2	  	 	$	28.6	  
	 Accounting policy change
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(3.3	) 
	 Purchases
	  	 	355.4	  	 	 	359.4	  	 	 	37.1	  	 	 	34.4	  
	 Write-down of inventory to net realizable value
	  	 	—  	  	 	 	—  	  	 	 	(0.7	) 	 	 	(1.1	) 
	 Inventories expensed
	  	 	(317.7	) 	 	 	(325.3	) 	 	 	(21.1	) 	 	 	(15.0	) 
	 Inventories capitalized
	  	 	—  	  	 	 	—  	  	 	 	(21.4	) 	 	 	(20.4	) 
	 Other
	  	 	—  	  	 	 	—  	  	 	 	7.2	  	 	 	2.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Inventory, end of period
	  	$	139.3	  	 	$	101.6	  	 	$	26.3	  	 	$	25.2	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 The Company has not pledged inventory as security for liabilities. 

10. OTHER ASSETS AND LIABILITIES 
 Other
assets and liabilities, including the impact of rate-regulated accounting policies, include the following: 
  

							
	 millions of dollars
	  	2009	  	2008
	 Other assets:
	  			  		
	 Regulatory assets:
	  			  		
	 Unamortized defeasance costs
	  	$	106.7	  	$	118.8
	 Pre-2003 income tax and related interest
	  	 	75.2	  	 	105.3
	 Future income tax regulatory asset
	  	 	25.2	  	 	—  
	 Deferral of income and capital taxes not included in Q1 2005 rates
	  	 	11.9	  	 	13.8
	 Deferral of demand side management
	  	 	9.7	  	 	0.3
	 Deferral of Tufts Cove derivatives
	  	 	9.6	  	 	36.3
	 Held-for-trading natural gas contracts
	  	 	3.9	  	 	1.7
	 Deferral of vegetation management
	  	 	2.0	  	 	2.0
		  	 	 	  	 	 
		  	 	244.2	  	 	278.2
		  	 	 	  	 	 
	 Non-regulatory assets:
	  			  		
	 Accrued pension asset (note 3)
	  	 	94.2	  	 	74.8
	 Other
	  	 	0.7	  	 	0.7
		  	 	 	  	 	 
		  	 	94.9	  	 	75.5
		  	 	 	  	 	 
		  	$	339.1	  	$	353.7
		  	 	 	  	 	 
	 Other liabilities:
	  			  		
	 Regulatory liabilities:
	  			  		
	 Deferral of Tufts Cove derivatives
	  	$	10.4	  	$	49.6
	 Deferral of FAM
	  	 	9.9	  	 	—  
	 Held-for-trading natural gas contracts
	  	 	4.7	  	 	67.5
		  	 	 	  	 	 
		  	 	25.0	  	 	117.1
		  	 	 	  	 	 
	 Non-regulatory liabilities:
	  			  		
	 Accrued pension and non-pension benefit liability (note 3)
	  	 	60.8	  	 	58.7
	 Unearned revenue
	  	 	1.7	  	 	2.2
	 Other
	  	 	4.0	  	 	2.3
		  	 	 	  	 	 
		  	 	66.5	  	 	63.2
		  	 	 	  	 	 
		  	$	91.5	  	$	180.3
		  	 	 	  	 	 

  

 21 

 Regulatory assets consist of: 

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, 2009 totaled $1.0 billion (2008 – $1.1 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 2009 (2008 – $12.3 million). 
 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 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, effective December 31, 2009, NSPI recorded an additional
discretionary $10 million of regulatory amortization expense to allow flexibility relating to future customer rate requirements. 
 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. In the absence of UARB approved recovery,
the liability would have been expensed when incurred, therefore net earnings would be $24.6 million higher in 2009 (2008 – $14.6 million). 

Future Income Tax Regulatory Asset 
 In
accordance with implementing the amendment to Standard 3465 Income taxes as discussed in Note 2, the Company recognized its future income tax assets and liabilities. In accordance with the Company’s regulated accounting policies covering income
taxes, NSPI 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, NSPI’s 2009 net earnings would be $19.3 million lower (2008 –
$28.7 million). 
 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 2009 would be $1.9 million (2008 –
$1.7 million) higher. 
 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 2009 would be $9.4 million lower (2008 –
$0.3 million). 
 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. 

 

 22 

 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 is being applied prospectively beginning January 1, 2009, as required by the UARB. 

Absent this change, NSPI would continue to recognize the change in fair value of these derivatives in “Fuel for generation and purchased power”
with an offset to “Fuel adjustment”. 
 Absent UARB approval, NSPI would be required to recognize the changes in fair value of these
derivatives in earnings and net earnings for 2009 would be $26.7 million higher ($17.4 after-tax) and (2008 – $30.7 million lower or $19.8 million after-tax). 

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 this accounting policy, NSPI’s 2009 net earnings would be $2.2 million ($1.4 million after-tax) lower (2008 – $0.2 million or $0.1 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 not have been deferred and net earnings for 2008 would be $2.0 million lower. 

Regulatory liabilities include: 
 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 and net earnings for 2009 would be $39.2 million ($25.5 million after-tax) lower (2008
– $19.7 million higher or $12.7 million after-tax). 
 Fuel Adjustment Mechanism 

As discussed in Note 4, 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,
2009 would be $9.9 million ($6.5 million after-tax) higher (2008 – nil). 
 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 this accounting policy, NSPI’s 2009 net earnings would be $62.8 million ($40.8 million after-tax) lower (2008 – $7.8 million or $5.0 million
after-tax). 
  

 23 

 11. PROPERTY, PLANT AND EQUIPMENT 

Property, plant and equipment is comprised of the following: 
  

										
	 	  	2009
	 millions of dollars
	  	Cost	  	Accumulated
Depreciation	  	Net
Book Value
	 Generation
	  			  			  		
	 Thermal
	  	$	1,902.6	  	$	796.4	  	$	1,106.2
	 Gas Turbines
	  	 	32.8	  	 	24.0	  	 	8.8
	 Combustion Turbines
	  	 	73.8	  	 	15.1	  	 	58.7
	 Hydroelectric
	  	 	401.7	  	 	144.1	  	 	257.6
	 Wind Turbines
	  	 	2.1	  	 	0.7	  	 	1.4
	 Transmission
	  	 	569.2	  	 	306.6	  	 	262.6
	 Distribution
	  	 	1,141.9	  	 	626.3	  	 	515.6
	 General plant
	  	 	307.9	  	 	156.9	  	 	151.0
	 Capital leases
	  	 	4.1	  	 	0.4	  	 	3.7
		  	 	 	  	 	 	  	 	 
		  	$	4,436.1	  	$	2,070.5	  	$	2,365.6
		  	 	 	  	 	 	  	 	 

  

										
	 	  	2008
	 millions of dollars
	  	Cost	  	Accumulated
Depreciation	  	Net
Book Value
	 Generation
	  			  			  		
	 Thermal
	  	$	1,809.0	  	$	752.1	  	$	1,056.9
	 Gas Turbines
	  	 	32.6	  	 	23.2	  	 	9.4
	 Combustion Turbines
	  	 	73.8	  	 	12.6	  	 	61.2
	 Hydroelectric
	  	 	388.8	  	 	138.0	  	 	250.8
	 Wind Turbines
	  	 	2.1	  	 	0.6	  	 	1.5
	 Transmission
	  	 	555.5	  	 	305.0	  	 	250.5
	 Distribution
	  	 	1,099.6	  	 	596.3	  	 	503.3
	 General plant
	  	 	290.8	  	 	138.3	  	 	152.5
	 Capital leases
	  	 	0.4	  	 	—  	  	 	0.4
		  	 	 	  	 	 	  	 	 
		  	$	4,252.6	  	$	1,966.1	  	$	2,286.5
		  	 	 	  	 	 	  	 	 

 12. INTANGIBLES 

Intangibles are comprised of the following: 
  

										
	 	  	2009
	 millions of dollars
	  	Cost	  	Accumulated
Amortization	  	Net
Book Value
	 Transmission
	  	$	51.7	  	$	15.7	  	$	36.0
	 Distribution
	  	 	17.6	  	 	5.1	  	 	12.5
	 Other
	  	 	30.0	  	 	12.8	  	 	17.2
		  	 	 	  	 	 	  	 	 
		  	$	99.3	  	$	33.6	  	$	65.7
		  	 	 	  	 	 	  	 	 

  

										
	 	  	2008
	 millions of dollars
	  	Cost	  	Accumulated
Amortization	  	Net
Book Value
	 Transmission
	  	$	51.5	  	$	15.1	  	$	36.4
	 Distribution
	  	 	17.0	  	 	4.8	  	 	12.2
	 Other
	  	 	20.6	  	 	10.5	  	 	10.1
		  	 	 	  	 	 	  	 	 
		  	$	89.1	  	$	30.4	  	$	58.7
		  	 	 	  	 	 	  	 	 

 Amortization expense for the year ended December 31, 2009 was
$3.2 million (2008 – $2.8 million). Straight-line amortization method is used. The estimated weighted average amortization period is 63 years. 
  

 24 

 The Company has applied new CICA Standard 3064 retrospectively with restatement of prior periods, which
results in the following reclassifications: 
  

					
	 As at

millions of dollars
	  	December 31, 2008	 
	 Assets
	  			
	 Property, plant and equipment
	  	$	(56.5	) 
	 Construction work in progress
	  	 	(2.2	) 
	 Intangibles
	  	$	58.7	  

 13. ASSET RETIREMENT OBLIGATIONS

 Asset retirement obligations 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, 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. Actual
results may differ from these estimates. 
 The change in asset retirement obligations is due to the following: 

 

									
	 millions of dollars
	  	2009	 	 	2008	 
	 Balance, beginning of year
	  	$	87.6	  	 	$	83.5	  
	 Accretion included in depreciation expense
	  	 	3.3	  	 	 	2.1	  
	 Accretion deferred to regulatory asset
	  	 	1.5	  	 	 	2.3	  
	 Liabilities settled
	  	 	(1.2	) 	 	 	(0.3	) 
	 Additions
	  	 	10.3	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Balance, end of year
	  	$	101.5	  	 	$	87.6	  
		  	 	 	 	 	 	 	 

 The key assumptions used to determine the asset retirement obligations are as follows: 

 

									
	 Asset
	  	Credit-adjusted
risk-free
rate	 	 	Estimated undiscounted
future
obligation
(millions of dollars)	  	Expected
settlement

date
	 Thermal
	  	5.31	% 	 	$	242.3	  	11 – 30 years
	 Hydro
	  	5.31	% 	 	 	60.8	  	22 – 52 years
	 Combustion turbines
	  	5.31	% 	 	 	5.1	  	1 – 14 years
	 Transmission & distribution
	  	5.74	% 	 	 	18.1	  	1 – 16 years
		  			 	 	 	  	
		  			 	$	326.3	  	
		  			 	 	 	  	

 Some of the Company’s hydro, transmission and distribution assets may have additional asset retirement
obligations. 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 asset retirement obligation cannot be
made at this time. 
 Additionally, some of the Company’s transmission and distribution assets may have conditional asset retirement
obligations, the fair value of which can not 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 asset retirement obligations is recognized as a regulatory asset in property, plant and equipment. In the absence of this deferral, net earnings for 2009 would be $1.5 million lower (2008 – $2.3 million). 

 

 25 

 14. SHORT-TERM DEBT 

Short-term debt consists of the following: 
  

				
	 millions of dollars
	  	2009
	 Advances against the operating line of credit, which when drawn upon, bears interest at the prime rate plus 1.25%; the prime rate
on December 31, 2009, was 2.50%.
	  	$	4.9
	 Short-term discount notes issued against a line of credit, which bear interest at prevailing market rates, which on
December 31, 2009, averaged 0.35%.
	  	 	194.6
		  	 	 
		  	$	199.5
		  	 	 
		
	 millions of dollars
	  	2008
	 Advances against the operating line of credit, which when drawn upon, bears interest at the prime rate, which on
December 31, 2008, was 3.50%.
	  	$	3.0
	 Short-term discount notes issued against a line of credit, which bear interest at prevailing market rates, which on
December 31, 2008, averaged 2.13%.
	  	 	19.8
		  	 	 
		  	$	22.8
		  	 	 

 This short-term debt is unsecured. 

15. LONG-TERM DEBT 
 Long-term debt
includes the issues 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 short-term discount notes 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
	  	2009	  	2008	  	Years of Maturity	  	2009	 	 	2008	 
	 Medium-term notes
	  	6.60	  	6.63	  	2010 – 2097	  	$	1,410.0	  	 	$	1,285.0	  
	 Debentures
	  	9.75	  	9.75	  	2019	  	 	95.0	  	 	 	95.0	  
	 Short-term discount notes
	  	—  	  	2.13	  	1 year renewal	  	 	—  	  	 	 	53.0	  
	 Capital lease obligations
	  	3.89	  	6.30	  	—  	  	 	3.7	  	 	 	0.4	  
		  		  		  		  	 	1,508.7	  	 	 	1,433.4	  
	 Amount due within one year
	  		  		  		  	 	(100.7	) 	 	 	(125.1	) 
	 Unamortized debt financing costs
	  		  		  		  	 	(11.0	) 	 	 	(11.6	) 
		  		  		  		  	 	 	 	 	 	 	 
		  		  		  		  	$	1,397.0	  	 	$	1,296.7	  
		  		  		  		  	 	 	 	 	 	 	 

 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. 
 As at December 31, 2009, long-term debt and obligations under a capital
lease are due as follows: 
  

				
	 millions of dollars

Year of Maturity
	  	 
	 One year renewable
	  	 	—  
	 2010
	  	$	100.7
	 2011
	  	 	0.8
	 2012
	  	 	0.7
	 2013
	  	 	300.7
	 2014
	  	 	0.7
	 Greater than 5 years
	  	 	1,105.1
		  	 	 
		  	$	1,508.7
		  	 	 

  

 26 

 16. PREFERRED SHARES 

NSPI’s preferred shares 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, 2007
	  	10.4	  	 	$	260.0	  
	 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	  
		  	 	 	 	 	 	 

 As at December 31, 2009, the Company had 5.4 million 5.9% Series D preferred shares (2008 – 5.0 million
4.9% Series C preferred shares and 5.4 million 5.9% Series D preferred shares) with the following redemption features: 
 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.
 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. 

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. 

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

			
	 Issued and outstanding:
	  	Millions of
shares
	 December 31, 2007
	  	96.8
	 Issued for cash
	  	10.0
		  	 
	 December 31, 2008
	  	106.8
	 Issued for non-cash consideration
	  	0.4
		  	 
	 December 31, 2009
	  	107.2
		  	 

  

 27 

 EMPLOYEE COMMON SHARE PURCHASE PLANS 

Employees may participate in Emera’s Employee Common Share Purchase Plan to which the Company and employees make cash contributions for the purpose
of purchasing common shares of NSPI’s parent company, Emera Inc. (“Emera”), and which allows reinvestment of dividends. 

SHARE-BASED COMPENSATION PLAN 

Deferred Share Unit Plan and Restricted Share Unit Plan 

The Company has deferred share unit (“DSU”) and restricted share unit (“RSU”) 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 understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50% of the value of their actual annual incentive award (25%
in the first year of the program) will be payable in DSUs until the applicable guidelines are met. 
 When incentive awards are determined, the
amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the
dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s
account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are usually made in cash. At the sole
discretion of the Management Resources and Compensation Committee (“MRCC”), payments may be made in the form of actual shares. Any participant who is a United States of America taxpayer shall receive payment on the first business day
following the six month anniversary of their termination. 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. 
 RSUs are granted annually for three-year
overlapping performance cycles. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date and multiplied by a value ratio factor of 1.11. Dividend equivalents are awarded
and are used to purchase additional RSUs. The RSU value varies according to the Emera common share market price and corporate performance. 

RSUs 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. 
  

 28 

									
	  	  	Employee
DSUs 
Outstanding	 	 	Employee
RSUs 
Outstanding	 	 	Director
DSUs 
Outstanding
	  	 	 
	 December 31, 2007
	  	63,665	  	 	118,787	  	 	31,416
	 Granted
	  	23,658	  	 	55,387	  	 	11,373
	 Retirement, termination, disability & death
	  	(6,262	) 	 	(8,833	) 	 	—  
	 Payout
	  	—  	  	 	(47,158	) 	 	—  
		  	 	 	 	 	 	 	 
	 December 31, 2008
	  	81,061	  	 	118,183	  	 	42,789
	 Granted
	  	19,089	  	 	48,812	  	 	9,167
	 Retirement, termination, disability & death
	  	(49,735	) 	 	—  	  	 	—  
	 Payout
	  	—  	  	 	(32,850	) 	 	—  
		  	 	 	 	 	 	 	 
	 December 31, 2009
	  	50,415	  	 	134,145	  	 	51,956
		  	 	 	 	 	 	 	 

 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 RSU 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, 2009, $2.4 million (2008 – $0.7 million) of compensation expense related to units issued and shares purchased by employees was recognized in “Operating,
maintenance and general expense”. 
 18. SUPPLEMENTAL CASH FLOW INFORMATION 

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

 

									
	 millions of dollars
	  	2009	 	 	2008	 
	 (Increase) decrease in accounts receivable and due from associated companies
	  	$	(71.5	) 	 	$	2.7	  
	 Decrease (increase) in long-term receivable
	  	 	56.4	  	 	 	(48.6	) 
	 Increase in inventory
	  	 	(38.8	) 	 	 	(34.0	) 
	 (Increase) decrease in prepaid expenses
	  	 	(0.8	) 	 	 	4.4	  
	 Change in posted margin included in accounts receivable or accounts payable and accrued charges
	  	 	25.1	  	 	 	(36.0	) 
	 Increase in other accounts payable and accrued charges and due to associated companies
	  	 	35.8	  	 	 	28.2	  
	 Change in heavy fuel oil hedging balance in AOCI
	  	 	(4.3	) 	 	 	(6.8	) 
	 Increase in income taxes payable
	  	 	9.3	  	 	 	1.4	  
		  	 	 	 	 	 	 	 
	 Change in non-cash operating working capital
	  	$	11.2	  	 	$	(88.7	) 
		  	 	 	 	 	 	 	 

 19. CAPITAL MANAGEMENT 

The Company includes shareholders’ equity (excluding AOCI), short-term and long-term debt, preferred shares, and cash and cash equivalents in the
definition of capital as follows: 
  

								
	 millions of dollars
	  	2009	 	 	2008
	 Shareholders’ equity, excluding AOCI
	  	$	1,129.4	  	 	$	1,142.0
	 Debt
	  	 	1,697.2	  	 	 	1,444.6
	 Preferred shares
	  	 	135.0	  	 	 	260.0
	 Cash and cash equivalents
	  	 	(0.3	) 	 	 	—  
		  	 	 	 	 	 	 
		  	$	2,961.3	  	 	$	2,846.6
		  	 	 	 	 	 	 

 The Company’s objectives when managing capital are to ensure
sufficient liquidity and ongoing access to capital in order to allow the Company to build and maintain its generation, transmission and distribution systems. The Company’s objectives include ensuring it is in compliance with its debt covenants.
To ensure access to capital, the Company targets a long-term capital structure of 60% debt and 40% common equity. This ratio is maintained by the Company through the issuance from time to time of common shares, medium-term notes, preferred shares,
or other indebtedness. 
  

 29 

 NSPI is subject to regulation by the UARB with an allowed common equity component effective January 1,
2009 of 45% (2008 – 40%). The Company is in compliance with this requirement. 
 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 have set, as a condition, NSPI will maintain its average actual regulated annual common equity at a level no higher than 40% in 2010 and until the next general rate case. 

The Company’s trust indentures, applicable to the senior unsecured debenture and senior unsecured medium-term notes, provide that the Company’s
funded debt cannot exceed 75% of total capitalization as defined in the credit agreements. The Company’s syndicated bank credit facility limits its debt to capitalization ratio to no greater than 0.65:1. The Company is in compliance with all of
its financial debt covenants. 
 20. 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: 
  

													
	 	  	2009	  	2008
	 millions of dollars
	  	Carrying
Amount	  	Fair
Value	  	Carrying
Amount	  	Fair
Value
	 Cash and cash equivalents
	  	$	0.3	  	$	0.3	  	 	—  	  	 	—  
	 Accounts receivable
	  	 	271.8	  	 	271.8	  	$	210.8	  	$	210.8
	 Long-term receivable
	  	 	—  	  	 	—  	  	 	56.4	  	 	56.4
	 Derivatives held in a valid hedging relationship (current and long-term portion)
	  			  			  			  		
	 Cash flow hedges
	  	 	41.2	  	 	41.2	  	 	161.8	  	 	161.8
	 Fair value hedges
	  	 	8.0	  	 	8.0	  	 	1.5	  	 	1.5
	 Held-for-trading derivatives (current and long-term portion)
	  	 	15.1	  	 	15.1	  	 	117.0	  	 	117.0
		  	 	 	  	 	 	  	 	 	  	 	 
	 Total financial assets
	  	$	336.4	  	$	336.4	  	$	547.5	  	$	547.5
		  	 	 	  	 	 	  	 	 	  	 	 
	 Accounts payable and accrued charges
	  	$	213.9	  	$	213.9	  	$	179.5	  	$	179.5
	 Short-term debt
	  	 	199.5	  	 	199.5	  	 	22.8	  	 	22.8
	 Derivatives held in a valid hedging relationship (current and long-term portion)
	  			  			  			  		
	 Cash flow hedges
	  	 	73.0	  	 	73.0	  	 	155.8	  	 	155.8
	 Held-for-trading derivatives (current and long-term portion)
	  	 	13.5	  	 	13.5	  	 	38.3	  	 	38.3
	 Long-term debt (including current portion)
	  	 	1,497.7	  	 	1,712.8	  	 	1,421.8	  	 	1,455.4
	 Preferred shares
	  	 	135.0	  	 	151.2	  	 	260.0	  	 	258.9
		  	 	 	  	 	 	  	 	 	  	 	 
	 Total financial liabilities
	  	$	2,132.6	  	$	2,363.9	  	$	2,078.2	  	$	2,110.7
		  	 	 	  	 	 	  	 	 	  	 	 

  

 30 

 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, 2009 are as follows: 

 

													
	 (millions of dollars)
	  	Level 1	  	Level 2	  	Level 3	  	Total
	 Financial Assets:
	  			  			  			  		
	 Cash and cash equivalents
	  	$	0.3	  	 	—  	  	 	—  	  	$	0.3
	 Accounts receivable
	  	 	189.7	  	 	—  	  	$	82.1	  	 	271.8
	 Derivatives in a valid hedging relationship (current and long-term portion)
	  			  			  			  		
	 Cash flow hedges
	  	 	39.6	  	$	0.1	  	 	1.5	  	 	41.2
	 Fair value hedges
	  	 	8.0	  	 	—  	  	 	—  	  	 	8.0
	 Held-for-trading derivatives (current and long-term portion)
	  	 	—  	  	 	—  	  	 	15.1	  	 	15.1
		  	 	 	  	 	 	  	 	 	  	 	 
	 Total financial assets
	  	$	237.6	  	$	0.1	  	$	98.7	  	$	336.4
		  	 	 	  	 	 	  	 	 	  	 	 
	 Financial liabilities:
	  			  			  			  		
	 Accounts payable and accrued charges
	  	$	213.9	  	 	—  	  	 	—  	  	$	213.9
	 Short-term debt
	  	 	—  	  	$	199.5	  	 	—  	  	 	199.5
	 Derivatives in a valid hedging relationship (current and long-term portion)
	  			  			  			  		
	 Cash flow hedges
	  	 	60.7	  	 	10.2	  	$	2.1	  	 	73.0
	 Held-for-trading derivatives (current and long-term portion)
	  	 	5.7	  	 	—  	  	 	7.8	  	 	13.5
	 Long-term debt (including current portion)
	  	 	—  	  	 	1,709.1	  	 	—  	  	 	1,709.1
	 Capital Leases
	  	 	—  	  	 	3.7	  	 	—  	  	 	3.7
	 Preferred shares
	  	 	—  	  	 	151.2	  	 	—  	  	 	151.2
		  	 	 	  	 	 	  	 	 	  	 	 
	 Total financial liabilities
	  	$	280.3	  	$	2,073.7	  	$	9.9	  	$	2,363.9
		  	 	 	  	 	 	  	 	 	  	 	 

 Changes in the fair value of $70.7 million financial assets classified
as Level 3 in fair value hierarchy during the year ended December 31, 2009, 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, 2009
	  	$	56.4	  	 	 	—  	  	$	113.0	  	 	$	169.4	  
	 Total (loss) gain realized and unrealized
	  				 			  				 			
	 Included in earnings
	  	 	(12.9	) 	 	 	—  	  	 	(42.7	) 	 	 	(55.6	) 
	 Included in AOCI
	  	 	—  	  	 	$	1.5	  	 	—  	  	 	 	1.5	  
	 Purchases, issuances, settlements
	  	 	38.6	  	 	 	—  	  	 	(55.2	) 	 	 	(16.6	) 
		  	 	 	 	 	 	 	  	 	 	 	 	 	 	 
	 Balance at December 31, 2009
	  	$	82.1	  	 	$	1.5	  	$	15.1	  	 	$	98.7	  
		  	 	 	 	 	 	 	  	 	 	 	 	 	 	 

  

 31 

 Changes in the fair value of $44.8 million financial liabilities classified as Level 3 in fair value
hierarchy during the year ended December 31, 2009, were as follows: 
  

													
	 millions of dollars
	  	Derivatives in a 
valid
hedging relationship
– Cash flow hedges	 	 	Held-for-
trading
derivatives
	 	 	Total	 
	 Balance at January 1, 2009
	  	$	(38.6	) 	 	$	(16.1	) 	 	$	(54.7	) 
		  	 	 	 	 	 	 	 	 	 	 	 
	 Total (loss) gain realized and unrealized
	  				 				 			
	 Included in earnings
	  	 	(13.5	) 	 	 	18.1	  	 	 	4.6	  
	 Included in AOCI
	  	 	44.5	  	 	 	—  	  	 	 	44.5	  
	 Purchases, issuances, settlements
	  	 	5.5	  	 	 	(9.8	) 	 	 	(4.3	) 
		  	 	 	 	 	 	 	 	 	 	 	 
	 Balance at December 31, 2009
	  	$	(2.1	) 	 	$	(7.8	) 	 	$	(9.9	) 
		  	 	 	 	 	 	 	 	 	 	 	 

 During 2009, due to a change in natural gas basis pricing methodology, a cash flow hedge derivative moved from Level 2 to
Level 3 in the amount of $2.1 million. 
 ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE AND ACCRUED CHARGES 

The Company’s accounts receivable, accounts payable and accrued charges are recognized at amortized cost. 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 $4.5 million (2008 - $3.8 million). 

The allowance for doubtful accounts was $2.8 million as at January 1, 2009 (2008 - $3.0 million) and $4.0 million as at December 31, 2009 (2008
- $2.8 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, LONG-TERM DEBT AND SHORT-TERM DEBT 

The Company’s preferred shares, long-term debt and short-term debt are measured at amortized cost. Preferred share dividends are recognized using the
effective interest method and are disclosed in note 6. 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 and are included in note 6.

 The fair value of preferred shares 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
	  	2009	 	 	2008
	 Fuel and purchased power (increase) decrease
	  	$	(33.1	) 	 	$	25.6
	 Financing charges decrease
	  	 	6.9	  	 	 	1.0
		  	 	 	 	 	 	 
	 Total (losses) gains
	  	$	(26.2	) 	 	$	26.6
		  	 	 	 	 	 	 

  

 32 

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

  

									
	 millions of dollars
	  	2009	 	 	2008	 
	 Fuel and purchased power increase
	  	$	(12.8	) 	 	$	(0.5	) 
		  	 	 	 	 	 	 	 
	 Total losses
	  	$	(12.8	) 	 	$	(0.5	) 
		  	 	 	 	 	 	 	 

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

 

								
	 millions of dollars
	  	2009	 	 	2008
	 Financing charges (increase) decrease
	  	$	(0.5	) 	 	$	0.7
		  	 	 	 	 	 	 
	 Total (losses) gains
	  	$	(0.5	) 	 	$	0.7
		  	 	 	 	 	 	 

 The Company expects to reclassify $47.9 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 makes use of various financial instruments to hedge against interest rate risk. Additionally, the Company uses diversification as a risk
management strategy. It maintains a portfolio of debt instruments which includes short-term instruments and long-term instruments with staggered maturities. The Company also deals with several counterparties 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 no interest rate hedging contracts outstanding as at December 31, 2009. 

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,
2009, the Company had hedged approximately 94% of all natural gas purchases and sales associated with its forecasted natural gas burn and resale for 2010, and 32% for 2011. 

The Company enters into oil swap contracts to limit exposure to fluctuations in world prices of heavy fuel oil. For 2010 and 2011, 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, 2009, the Company had hedged approximately 84% of all solid fuel purchases for 2010, 34% for 2011, 15% for 2012 and 4% for 2013. 

Foreign Exchange 
 A substantial amount
of NSPI’s fuel supply comes from international suppliers and is subject to foreign exchange risk. As part of its fuel management strategy, NSPI manages exposure to foreign exchange through forward contracts. 

NSPI enters into foreign exchange forward and swap contracts to limit exposure on fuel purchases to currency rate fluctuations. Currency forwards are
used to fix the Canadian dollar (“CAD”) cost to acquire United States dollars (“USD”), reducing exposure to currency rate fluctuations. Forward contracts to buy USD $331.0 million are in place at a weighted average rate of $1.09
representing over 89% of 2010 anticipated USD requirements. Forward contracts to buy USD $471.5 million over 2011 to 2013 at a weighted average rate of $1.01 were outstanding at December 31, 2009 to manage exposure of 42% of anticipated USD
requirements in these years. As at December 31, 2009, there were no fuel-related foreign exchange swaps outstanding. 
  

 33 

 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 USD $0.9 million are in place at a weighted average rate of $1.00 for capital projects in 2010. Forward contracts to sell USD $39.0 million are in place at a weighted average
rate of $1.25 to hedge receivables in 2010. Forward contracts to buy €30.3 million are in place at a weighted average ratio of 1.56 (versus CAD) for capital projects in 2010. 

HELD-FOR-TRADING DERIVATIVES 

Derivatives included in held-for-trading (“HFT”) 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 recognized the following realized and
unrealized gains and losses with respect to HFT derivatives in earnings: 
  

								
	 millions of dollars
	  	2009	  	2008	 
	 Fuel and purchased power
	  	$	13.0	  	$	(0.4	) 
	 Financing charges
	  	 	—  	  	 	(0.5	) 
		  	 	 	  	 	 	 
	 Total gains (losses)
	  	$	13.0	  	$	(0.9	) 
		  	 	 	  	 	 	 

 Natural gas contracts 

Nova Scotia Power has contracts for the purchase and sale of natural gas at its 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, 2009, the Company held natural gas and oil derivatives, which were not in valid hedging relationships. 

RISK MANAGEMENT 
 Market Risk 

 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. Market risk associated with the contract receivable is related to movements in commodity prices and foreign exchange rates.

 As at December 31, 2009, 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
	  	$	1.8	  	 	$	12.7	  
	 $5 per barrel increase in the price of heavy fuel oil
	  	 	0.4	  	 	 	1.2	  
	 $15 per metric tonne increase in the price of coal
	  	 	—  	  	 	 	36.1	  
	 $0.01 decrease in the strength of the Canadian relative to the US dollar
	  	 	0.8	  	 	 	(8.8	) 
	 100 basis point increase in the central bank interest rates
	  	 	(1.2	) 	 	 	—  	  

 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. 
  

 34 

 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, 2009, the maximum
exposure the Company has to credit risk is $336.1 million, which includes accounts receivable, the 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, 2009, was $10.9 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, 2009, the Company had $30.8 million (2008 - $29.1 million) in financial assets considered to be past due,
which have been outstanding for an average of 69 days. The fair value of these financial assets is $27.0 million (2008 - $26.5 million), the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to
accounts receivable from electric revenue. 
 Concentration risk 

The Company’s concentration of risks as at December 31, 2009 is as follows: 

 

							
	 	  	2009
millions of 
dollars	  	% of 
total
exposure	 
	  	  
	 Accounts receivable
	  			  		
	 Residential
	  	$	100.1	  	30	% 
	 Commercial
	  	 	46.4	  	14	% 
	 Industrial
	  	 	31.6	  	9	% 
	 Contract receivable
	  	 	82.1	  	24	% 
	 Other
	  	 	11.6	  	4	% 
		  	 	 	  	 	 
		  	 	271.8	  	81	% 
		  	 	 	  	 	 
	
	 Derivatives (in a valid hedging relationship and held-for-trading;

current and long-term portions)
	   

  

	 Credit rating of A- or above
	  	 	59.6	  	18	% 
	 Not rated
	  	 	4.7	  	1	% 
		  	 	64.3	  	19	% 
		  	 	 	  	 	 
		  	$	336.1	  	100	% 
		  	 	 	  	 	 

  

 35 

 Liquidity risk 

Liquidity risk encompasses the risk that the Company cannot meet its financial obligations. 

NSPI’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. 

NSPI 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: 
  

																			
	 	  	2010	  	2011	  	2012	  	2013	  	2013	  	Total
	 Accounts payable and accrued charges
	  	$	213.9	  	 	—  	  	 	—  	  	 	—  	  	 	—  	  	$	213.9
	 Short-term debt
	  	 	199.5	  	 	—  	  	 	—  	  	 	—  	  	 	—  	  	 	199.5
	 Long-term debt
	  	 	100.7	  	$	0.8	  	$	0.7	  	$	300.7	  	$	1,105.8	  	 	1,508.7
	 Preferred shares
	  	 	—  	  	 	—  	  	 	—  	  	 	—  	  	 	135.0	  	 	135.0
	 Derivatives held in a valid hedging relationship
	  	 	53.0	  	 	15.7	  	 	1.6	  	 	2.7	  	 	—  	  	 	73.0
	 Held-for-trading derivatives
	  	 	12.2	  	 	1.3	  	 	—  	  	 	—  	  	 	—  	  	 	13.5
		  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 
	 Total financial liabilities
	  	$	579.3	  	$	17.8	  	$	2.3	  	$	303.4	  	$	1,240.8	  	$	2,143.6
		  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 

 The Company has available the following credit facilities as at
December 31, 2009 for the management of liquidity risk: 
  

										
	 millions of dollars
	  	Available	  	Used	  	Unused
	 Bank operating and commercial paper
	  	$	500	  	$	235.2	  	$	264.8

 21. RELATED PARTY TRANSACTIONS

 The Company enters into various transactions with its affiliates in the normal course of operations. All transactions are recorded,
subject to terms in the Code of Conduct, at the exchange value, which is generally based on commercial rates or as agreed to by the parties. The Code of Conduct governs transactions between NSPI and its affiliates and is approved by the UARB.

 Due to (from) associated companies represents the total carrying amounts of trade payables (receivables), which are owed from (to) NSPI to
(by) NSPI’s parent company, Emera Inc., and companies wholly-owned by Emera Inc. The terms of repayment are the same as those for non-affiliate trade payables (receivables). 

NSPI had sales and purchases from companies under common control of Emera Inc. as follows: 

 

							
	 millions of dollars
	  	 	  	 
	 Affiliate
	  	 Purpose of Transaction
	  	2009	  	2008
	Sales:	  		  		  	
	Emera Energy Services	  	Net sales of gas	  	$26.2	  	$100.4
	Other	  	Other services provided	  	6.9	  	6.4
	Purchases:	  	Electricity and services purchased	  	$18.8	  	$13.3

 In the ordinary course of business, the Company
purchased natural gas transportation capacity totaling $18.2 million (2008 - $19.0 million) during the year ended December 31, 2009, from the Maritimes & Northeast Pipeline, an investment under significant influence of Emera Inc. The
amount is recognized in “Fuel for generation and purchased power” and is measured at the exchange amount. As at December 31, 2009, the amount payable to the related party is $1.5 million (2008 - $1.6 million), and is under normal
interest and credit terms. 
  

 36 

 During the year ended December 31, 2009, the Company issued a total of 0.4 million (2008 –
10.0 million) common shares to Emera Inc. and an affiliate under common control for total consideration of $4.1 million. 
 22. CONTINGENCIES

 A number of individuals who live in proximity to the Company’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. 

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. 

23. COMMITMENTS 
 In addition to
commitments outlined elsewhere in these notes, NSPI had the following significant commitments as at December 31, 2009: 
  

	 	•	 	 An annual requirement to purchase approximately 961 GWh of electricity from independent power producers over varying contract lengths up to 25 years.

  

	 	•	 	 A requirement to purchase approximately 61,600 mmbtu of natural gas per day for the next ten months (subject to offshore gas production); 15,000 mmbtu
per day beginning November 2010 for two years; an average of 13,000 mmbtu per day beginning November 2010 for three years; and an additional 4,000 mmbtu per day for two years. The commitment of 4,000 mmbtu per day includes renewal rights at the
supplier’s option for two additional five year terms. 

  

	 	•	 	 A commitment to purchase approximately 61,600 mmbtu per day of transportation capacity on the Maritimes and Northeast Pipeline, a related party, for
the next ten months. The approximate cost of the commitment is $15 million. 

  

	 	•	 	 A commitment to purchase an additional 4,000 mmbtu per day of transportation capacity on the Maritimes and Northeast Pipeline, a related party, for two
years. The commitment includes renewal rights at the supplier’s option for two additional five year terms, at an approximate cost of $1 million per year. 

 

	 	•	 	 Responsibility for managing a portfolio of approximately $1 billion of defeasance securities held in trust. The defeasance securities must provide the
principal and interest payment streams of the related defeased debt. Approximately 72% or $733 million of the defeasance portfolio consists of investments in the related debt, eliminating all risk associated with this portion of the portfolio.

  

	 	•	 	 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
million per year. 

  

	 	•	 	 Commitments to third parties for the handling and transportation of solid fuel for $7 million in 2010 and $4 million per year from 2011 to 2015.

  

	 	•	 	 Commitments to third parties for 2010 to 2012, to purchase and transport 3.9 million metric tons (“mts”) of import coal, 240,000 mts of
domestic coal and 4.7 million mts of marine freight. 

  

	 	•	 	 Commitment to third parties to purchase turbines in 2010 at an approximate cost of $92 million and to purchase other goods and services in 2010 and
2011 at an approximate cost of $30 million. 

  

 37 

 24. GUARANTEES 

NSPI had the following guarantees at December 31, 2009: 
  

	 	•	 	 The Company has letters of credit issued totaling $56.2 million that extend to 2010 and/or are renewed annually to secure payments to various vendors,
including counterparties, and to secure obligations under an unfunded pension plan. 

  

	 	•	 	 The Company has provided a limited guarantee for the indebtedness of a third party. The guarantee is up to a maximum of $23.5 million and is
related to future purchased power. NSPI holds a first ranking security interest in the assets of the third party. 

 25.
COMPARATIVE INFORMATION 
 Certain of the comparative figures have been reclassified to conform to the financial statement presentation
adopted for 2009. 
  

 38 

 OPERATING STATISTICS (Unaudited) 

FIVE-YEAR SUMMARY 
  

											
	 Year Ended December 31
	  	2009	  	2008	  	2007	  	2006	  	2005
	 Electric energy sales (GWh)
	  		  		  		  		  	
	 Residential
	  	4,227.7	  	4,178.8	  	4,144.6	  	3,926.9	  	3,999.5
	 Commercial
	  	3,107.3	  	3,114.6	  	3,160.5	  	3,023.0	  	3,003.9
	 Industrial
	  	3,642.4	  	4,144.6	  	4,191.4	  	2,874.4	  	4,196.9
	 Other
	  	328.1	  	334.2	  	365.9	  	681.2	  	436.4
		  	 	  	 	  	 	  	 	  	 
	 Total electric energy sales
	  	11,305.5	  	11,772.2	  	11,862.4	  	10,505.5	  	11,636.7
		  	 	  	 	  	 	  	 	  	 
	 Sources of energy (GWh)
	  		  		  		  		  	
	 Thermal – coal
	  	8,177.3	  	9,008.9	  	9,561.4	  	9,128.1	  	9,116.3
	      – oil
	  	306.9	  	339.6	  	515.3	  	431.4	  	1,580.5
	      – natural gas
	  	1,611.5	  	1,257.9	  	1,057.1	  	390.3	  	194.3
	 Hydro
	  	1,063.4	  	1,065.3	  	908.8	  	995.7	  	1,060.6
	 Wind
	  	1.8	  	2.4	  	2.4	  	2.4	  	1.8
	 Purchases
	  	930.7	  	888.6	  	653.9	  	404.6	  	529.3
		  	 	  	 	  	 	  	 	  	 
	 Total generation and purchases
	  	12,091.6	  	12,562.7	  	12,698.9	  	11,352.5	  	12,482.8
	 Losses and internal use
	  	786.1	  	790.5	  	836.5	  	847.0	  	846.1
		  	 	  	 	  	 	  	 	  	 
	 Total electric energy sold
	  	11,305.5	  	11,772.2	  	11,862.4	  	10,505.5	  	11,636.7
		  	 	  	 	  	 	  	 	  	 
	 Electric customers
	  		  		  		  		  	
	 Residential
	  	439,338	  	435,847	  	431,697	  	427,734	  	423,517
	 Commercial
	  	34,678	  	34,509	  	34,266	  	34,047	  	33,797
	 Industrial
	  	2,499	  	2,496	  	2,503	  	2,487	  	2,475
	 Other
	  	9,153	  	9,062	  	9,572	  	9,376	  	9,092
		  	 	  	 	  	 	  	 	  	 
	 Total electric customers
	  	485,668	  	481,914	  	478,038	  	473,644	  	468,881
		  	 	  	 	  	 	  	 	  	 
	 Capacity
	  		  		  		  		  	
	 Generating nameplate capacity (MW)
	  		  		  		  		  	
	 Coal fired
	  	1,243	  	1,243	  	1,243	  	1,243	  	1,243
	 Dual fired
	  	350	  	350	  	350	  	350	  	350
	 Gas turbines
	  	304	  	304	  	304	  	304	  	304
	 Hydroelectric
	  	395	  	395	  	395	  	395	  	395
	 Wind turbines
	  	1	  	1	  	1	  	1	  	1
	 Independent power producers
	  	137	  	85	  	85	  	79	  	57
		  	 	  	 	  	 	  	 	  	 
		  	2,430	  	2,378	  	2,378	  	2,372	  	2,350
		  	 	  	 	  	 	  	 	  	 
	 Total number of employees
	  	1,865	  	1,791	  	1,740	  	1,698	  	1,623
		  	 	  	 	  	 	  	 	  	 
	 km of transmission lines (69 kV and over)
	  	5,000	  	5,000	  	5,000	  	5,000	  	5,000
		  	 	  	 	  	 	  	 	  	 
	 km of distribution lines (25 kV and under)
	  	27,000	  	26,000	  	25,000	  	25,000	  	25,000
		  	 	  	 	  	 	  	 	  	 

  

 39 

 FIVE YEAR SUMMARY 
  

																					
	 Year Ended December 31 (millions of dollars)
	  	2009	 	 	2008	 	 	2007	 	 	2006	 	 	2005	 
	 Statements of Earnings Information
	  				 				 				 				 			
	 Revenue
	  	$	1,202.1	  	 	$	1,126.6	  	 	$	1,113.7	  	 	$	977.5	  	 	$	963.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Cost of operations
	  				 				 				 				 			
	 Fuel for generation and purchased power
	  	 	500.7	  	 	 	471.4	  	 	 	433.7	  	 	 	292.8	  	 	 	373.8	  
	 Fuel adjustment (note 4)
	  	 	8.5	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Operating, maintenance and general
	  	 	215.1	  	 	 	203.7	  	 	 	206.0	  	 	 	202.5	  	 	 	188.8	  
	 Provincial grants and taxes
	  	 	40.5	  	 	 	41.2	  	 	 	40.4	  	 	 	40.3	  	 	 	40.4	  
	 Provincial tax deferral
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(4.5	) 
	 Depreciation and amortization
	  	 	143.9	  	 	 	133.6	  	 	 	131.1	  	 	 	127.8	  	 	 	119.5	  
	 Regulatory amortization
	  	 	27.2	  	 	 	17.7	  	 	 	17.2	  	 	 	8.6	  	 	 	6.2	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
		  	 	935.9	  	 	 	867.6	  	 	 	828.4	  	 	 	672.0	  	 	 	724.4	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
		  	 	266.2	  	 	 	259.0	  	 	 	285.3	  	 	 	305.5	  	 	 	238.8	  
	 Financing charges
	  	 	114.7	  	 	 	106.8	  	 	 	123.0	  	 	 	130.6	  	 	 	123.1	  
	 Other income
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(8.9	) 	 	 	(8.0	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
		  	 	151.5	  	 	 	152.2	  	 	 	162.3	  	 	 	183.8	  	 	 	123.7	  
	 Income taxes
	  	 	42.2	  	 	 	46.6	  	 	 	62.1	  	 	 	79.5	  	 	 	44.7	  
	 Income taxes deferral
	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(12.2	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Net earnings applicable to common shares
	  	 	109.3	  	 	 	105.6	  	 	 	100.2	  	 	 	104.3	  	 	 	91.2	  
	 Common dividends
	  	 	126.0	  	 	 	75.0	  	 	 	193.0	  	 	 	50.0	  	 	 	91.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Earnings retained for use in Company
	  	$	(16.7	) 	 	$	30.6	  	 	$	(92.8	) 	 	$	54.3	  	 	$	0.2	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Cost of fuel for generation – coal
	  	 	293.9	  	 	$	282.1	  	 	$	276.0	  	 	$	266.2	  	 	$	260.9	  
	 – oil
	  	 	5.4	  	 	 	17.7	  	 	 	49.7	  	 	 	34.2	  	 	 	100.2	  
	 – natural gas
	  	 	138.5	  	 	 	92.5	  	 	 	52.0	  	 	 	(41.6	) 	 	 	(35.4	) 
	 Purchased power
	  	 	62.9	  	 	 	79.1	  	 	 	56.0	  	 	 	34.0	  	 	 	48.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total cost of fuel for generation and purchased power
	  	$	500.7	  	 	$	471.4	  	 	$	433.7	  	 	$	292.8	  	 	$	373.8	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Balance Sheets Information
	  				 				 				 				 			
	 Current assets
	  	$	507.4	  	 	$	477.3	  	 	$	361.7	  	 	$	288.7	  	 	$	186.9	  
	 Long-term receivable
	  	 	—  	  	 	 	56.4	  	 	 	7.7	  	 	 	—  	  	 	 	48.4	  
	 Derivatives in a valid hedging relationship
	  	 	29.8	  	 	 	115.5	  	 	 	10.4	  	 	 	—  	  	 	 	—  	  
	 Held-for-trading derivatives
	  	 	6.2	  	 	 	54.0	  	 	 	47.6	  	 	 	—  	  	 	 	—  	  
	 Other assets*
	  	 	339.1	  	 	 	353.7	  	 	 	358.8	  	 	 	371.8	  	 	 	398.5	  
	 Intangibles
	  	 	65.7	  	 	 	58.7	  	 	 	58.8	  	 	 	58.6	  	 	 	59.9	  
	 Property, plant and equipment and construction work in progress
	  	 	2,518.4	  	 	 	2,375.1	  	 	 	2,337.5	  	 	 	2,342.4	  	 	 	2,370.2	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total assets
	  	$	3,466.6	  	 	$	3,490.7	  	 	$	3,182.5	  	 	$	3,061.5	  	 	$	3,063.9	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Current liabilities
	  	 	582.9	  	 	$	586.7	  	 	$	356.5	  	 	$	205.0	  	 	$	184.6	  
	 Derivatives in a valid hedging relationship
	  	 	20.0	  	 	 	51.3	  	 	 	33.1	  	 	 	—  	  	 	 	—  	  
	 Held-for-trading derivatives
	  	 	1.3	  	 	 	11.7	  	 	 	1.2	  	 	 	—  	  	 	 	—  	  
	 Future income tax liabilities
	  	 	52.0	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  
	 Asset retirement obligations
	  	 	101.5	  	 	 	87.6	  	 	 	83.5	  	 	 	77.7	  	 	 	73.8	  
	 Other liabilities*
	  	 	91.5	  	 	 	180.3	  	 	 	167.6	  	 	 	5.8	  	 	 	4.6	  
	 Long-term debt
	  	 	1,397.0	  	 	 	1,296.7	  	 	 	1,314.3	  	 	 	1,405.5	  	 	 	1,487.7	  
	 Preferred shares
	  	 	135.0	  	 	 	135.0	  	 	 	260.0	  	 	 	260.0	  	 	 	260.0	  
	 Common shares
	  	 	934.7	  	 	 	930.6	  	 	 	830.6	  	 	 	830.6	  	 	 	830.6	  
	 Accumulated other comprehensive loss
	  	 	(44.0	) 	 	 	(0.6	) 	 	 	(48.4	) 	 	 	—  	  	 	 	—  	  
	 Retained earnings
	  	 	194.7	  	 	 	211.4	  	 	 	184.1	  	 	 	276.9	  	 	 	222.6	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Total equity and liabilities
	  	$	3,466.6	  	 	$	3,490.7	  	 	$	3,182.5	  	 	$	3,061.5	  	 	$	3,063.9	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Statements of Cash Flow Information
	  				 				 				 				 			
	 Cash provided by operating activities
	  	$	272.7	  	 	$	174.3	  	 	$	306.4	  	 	$	283.6	  	 	$	129.9	  
	 Cash used in investing activities
	  	$	(268.6	) 	 	$	(163.4	) 	 	$	(124.4	) 	 	$	(101.8	) 	 	$	(104.3	) 
	 Cash used in financing activities
	  	$	(3.8	) 	 	$	(12.8	) 	 	$	(188.3	) 	 	$	(177.1	) 	 	$	(22.1	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

  

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

 

 40 

 Management’s Discussion & Analysis 

As at February 10, 2010 
 Management’s
Discussion and Analysis (“MD&A”) provides a review of the results of operations of Nova Scotia Power Inc. during the fourth quarter of 2009 relative to 2008, and the full year 2009 relative to 2008 and to 2007; and its financial
position at December 31, 2009 relative to 2008. 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 Nova Scotia Power Inc. annual audited financial statements and supporting notes. Nova
Scotia Power Inc. follows Canadian Generally Accepted Accounting Principles (“CGAAP”). Nova Scotia Power Inc.’s accounting policies are subject to examination and approval by the Nova Scotia Utility and Review Board
(“UARB”). The accounting policies of Nova Scotia Power Inc. may differ from CGAAP for non rate-regulated companies. 
 Throughout this
discussion, “Nova Scotia Power” and “NSPI” refer to Nova Scotia Power Inc. 
 All amounts are in Canadian dollars
(“CAD”). 
 Additional information related to Nova Scotia Power 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 NSPI 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. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary significantly from
those expected. NSPI 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. 
 Structure of MD&A 

This MD&A begins with an introduction and strategic overview, followed by a financial review including statements of earnings, balance sheets and cash
flow highlights; then continues with a discussion on liquidity and capital resources, pension funding, off-balance sheet arrangements, outlook, transactions with related parties, risk management and financial instruments, disclosure and internal
controls, significant accounting policies and critical accounting estimates, changes in accounting policies and practices and summary of quarterly results. 
  

 41 

 INTRODUCTION AND STRATEGIC OVERVIEW 

NSPI, created following 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 with $3.5 billion of assets and provides electricity generation transmission and distribution services to approximately 486,000 customers in the province. The Company owns 2,293 megawatt
(“MW”) of generating capacity. Approximately 53% is coal-fired; natural gas and/or oil together comprise another 29% of capacity; and hydro and wind production provide 18%. In addition, NSPI has contracts to purchase renewable energy from
independent power producers (“IPP”). These IPP’s own 137 MW of wind and biomass fueled generation capacity. A further 212 MW of renewable capacity is being built directly or purchased under long-term contracts by NSPI, of which 163 MW
are expected to be in service by the end of 2010. NSPI also owns approximately 5,000 kilometers of transmission facilities, and 27,000 kilometers of distribution facilities. The Company 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. The Company is not subject to a general annual rate review process, but
rather participates in hearings from time to time at the Company’s or the regulator’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 2009 was 9.1% to
9.6%, on a common equity component of 45% of total capitalization. 
 Although the market in Nova Scotia is otherwise mature, the transformation
of energy supply to lower emission sources has created the opportunity for organic growth within NSPI, and the Company expects earnings growth of 2% to 4% annually over the next five years as new investments are made in renewable generation and
transmission. 
 Developments 

Return on Equity Decision 
 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 further provides NSPI with flexibility in amortizing the pre-2003 income tax regulatory asset, allowing NSPI to recognize additional amortization amounts in current periods and reducing amounts in future periods. Accordingly, effective
December 31, 2009, NSPI recognized an additional discretionary $10 million of regulatory amortization expense to allow flexibility relating to future customer rate requirements. The agreement was approved by the UARB. The UARB have set, as a
condition, NSPI will maintain its average regulated annual common equity at a level no higher than 40% in 2010 and until the next general rate case. 

Nova Scotia Renewable Energy Standard Regulation 

In January 2007, the Nova Scotia government approved the Renewable Energy Standard Regulation (“RES”) to increase the percentage of renewable
energy in the Nova Scotia 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. The renewable energy projects owned by independent power producers which are already in service, in combination with those which are scheduled for
completion by the end of 2010, are expected to enable NSPI to be in compliance with the 2011 RES requirement. 
  

 42 

 Point Tupper Wind Development 

In November 2009, to satisfy NSPI’s requirements under the Province’s 2011 Renewable Energy Standards, the Company signed a project operating
agreement with Renewable Energy Services Ltd. (“RESL”), an independent power producer, regarding the construction and operation of a 23 MW wind farm in Richmond County, Nova Scotia. NSPI will own approximately 49% of the wind farm with
RESL constructing, managing, operating and maintaining the site. In order to facilitate this existing project’s advancement, NSPI has provided a limited guarantee for the indebtedness of RESL. The guarantee is up to a maximum of $23.5
million. NSPI holds a first ranking security interest in the assets of RESL and all future assets of the project owned by RESL. NSPI had previously signed a power purchase agreement with RESL relating to the wind farm, which was one of the power
purchase agreements NSPI signed with independent power producers to meet provincial regulations. NSPI is seeking the UARB’s approval to include its portion of the project in regulated rate base. 

Nuttby Mountain Wind Project 
 In April
2009, NSPI purchased the development rights for a proposed 45 MW wind farm located at Nuttby Mountain, Nova Scotia. The Nuttby Mountain project represented one of the power purchase agreements NSPI had signed with independent power producers
previously. The Nuttby Mountain project development rights were owned by EarthFirst Nuttby Inc., a subsidiary of EarthFirst Canada Inc. The development rights included land leases and transmission interconnection rights as well as provincial
environmental approval. As a result of the purchase by NSPI, this particular power purchase agreement is no longer in effect. The UARB approved the development of this project as a capital work order, and it will be included in regulated rate base
at a cost of approximately $120 million. 
 2009 Rate Decision 

In September 2008, NSPI reached a settlement agreement with stakeholders on its 2009 rate application. The UARB approved that settlement agreement in
November 2008 which included an average rate increase of 9.4% for most customer segments effective January 1, 2009. The settlement agreement included a Fuel Adjustment Mechanism (“FAM”), also effective January 1, 2009. The first
rate adjustment under the FAM, effective, on January 1, 2010, was approved by the UARB on December 9, 2009. The UARB oversees the FAM, including review of fuel costs, contracts and transactions. With the implementation of the FAM,
NSPI’s regulated ROE range was established as 9.1% to 9.6% with 9.35% used to set rates. 
 Appointments 

On May 6, 2009, George Caines was named Chairman of NSPI’s Board of Directors, replacing John McLennan. 

 

 43 

 REVIEW OF 2009 
  

																					
	 Net Earnings

millions of dollars
	  	Three months 
ended
December 31	 	 	Year
ended
December 31	 
	  	2009	 	 	2008	 	 	2009	 	 	2008	 	 	2007	 
	 Electric revenue
	  	$	302.9	  	 	$	280.7	  	 	$	1,188.1	  	 	$	1,111.1	  	 	$	1,102.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Fuel for generation and purchased power
	  	 	138.5	  	 	 	139.5	  	 	 	500.7	  	 	 	471.4	  	 	 	433.7	  
	 Fuel adjustment
	  	 	(10.6	) 	 	 	—  	  	 	 	8.5	  	 	 	—  	  	 	 	—  	  
	 Operating, maintenance and general
	  	 	58.4	  	 	 	52.3	  	 	 	215.1	  	 	 	203.7	  	 	 	206.0	  
	 Provincial grants and taxes
	  	 	10.0	  	 	 	10.3	  	 	 	40.5	  	 	 	41.2	  	 	 	40.4	  
	 Depreciation and amortization
	  	 	36.8	  	 	 	33.8	  	 	 	143.9	  	 	 	133.6	  	 	 	131.1	  
	 Regulatory amortization
	  	 	14.7	  	 	 	6.4	  	 	 	27.2	  	 	 	17.7	  	 	 	17.2	  
	 Other revenue
	  	 	(4.0	) 	 	 	(3.5	) 	 	 	(14.0	) 	 	 	(15.5	) 	 	 	(11.7	) 
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
		  	 	59.1	  	 	 	41.9	  	 	 	266.2	  	 	 	259.0	  	 	 	285.3	  
	 Financing charges
	  	 	33.3	  	 	 	20.3	  	 	 	114.7	  	 	 	106.8	  	 	 	123.0	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Earnings before income taxes
	  	 	25.8	  	 	 	21.6	  	 	 	151.5	  	 	 	152.2	  	 	 	162.3	  
	 Income taxes
	  	 	8.4	  	 	 	7.2	  	 	 	42.2	  	 	 	46.6	  	 	 	62.1	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 Net earnings
	  	$	17.4	  	 	$	14.4	  	 	$	109.3	  	 	$	105.6	  	 	$	100.2	  
		  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 

 NSPI’s net earnings increased $3.0 million to $17.4 million in Q4 2009, compared to $14.4 million in Q4 2008. Annual
net earnings increased $3.7 million to $109.3 million in 2009 compared to $105.6 million in 2008, and were $100.2 million in 2007. Highlights of the earnings changes are summarized in the following table: 

 

									
	 millions of dollars
	  	Three months 
ended
December 31	 	 	Year
ended
December 31	 
	 Net earnings – 2007
	  				 	$	100.2	  
	 Increased electric revenue due to an electricity price increase on April 1, 2007
	  				 	 	9.1	  
	 Increased fuel for generation and purchased power due to increased coal prices, changes in generation mix and increased coal
plant maintenance
	  				 	 	(37.7	) 
	 Decreased financing charges due to foreign exchange gains on US dollar (“USD”) denominated monetary net assets compared
to foreign exchange losses; and lower interest costs
	  				 	 	16.2	  
	 Decreased income taxes due to lower taxable income, accelerated deductions for capital items and a lower statutory
rate
	  				 	 	15.5	  
	 Other
	  				 	 	2.3	  
		  				 	 	 	 
	 Net earnings – 2008
	  	$	14.4	  	 	$	105.6	  
	 Increased electric revenue due to an electricity price increase on January 1, 2009 partially offset by decreased industrial
sales in the year
	  	 	22.2	  	 	 	77.0	  
	 Decreased (increased) fuel for generation and purchased power
	  	 	1.0	  	 	 	(29.3	) 
	 Fuel adjustment related to implementation of FAM
	  	 	10.6	  	 	 	(8.5	) 
	 Increased operating, maintenance and general primarily due to increased storm and reliability costs as well as customer service
initiatives partially offset by decreased pension expense
	  	 	(6.1	) 	 	 	(11.4	) 
	 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
	  	 	(3.0	) 	 	 	(10.3	) 
	 Increased financing charges
	  	 	(13.0	) 	 	 	(7.9	) 
	 Increased regulatory amortization due to additional amortization of pre-2003 income tax regulatory asset
	  	 	(8.3	) 	 	 	(9.5	) 
	 (Increased) income taxes in the quarter due to higher taxable income partially offset by lower statutory rate;
year-to-date decrease due to decreased taxable income and lower statutory rate, partially offset by recovery of income taxes in 2008 relating to a prior year
	  	 	(1.2	) 	 	 	4.4	  
	 Other
	  	 	0.8	  	 	 	(0.8	) 
		  	 	 	 	 	 	 	 
	 Net earnings – 2009
	  	$	17.4	  	 	$	109.3	  
		  	 	 	 	 	 	 	 

  

 44 

 Net Earnings History 

 

																			
	 millions of dollars
	  	2009	  	2008	  	2007	  	2006	  	2005	  	2004
	 Net earnings
	  	$	109.3	  	$	105.6	  	$	100.2	  	$	104.3	  	$	91.2	  	$	107.3
		  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 

 Balance Sheets Highlights 

 

										
	 	  	As at December 31
	 millions of dollars
	  	2009	  	2008	  	2007
	 Total assets
	  	$	3,466.6	  	$	3,490.7	  	$	3,182.5
		  	 	 	  	 	 	  	 	 
	 Total long-term liabilities
	  	 	1,798.3	  	 	1,762.6	  	 	1,859.7
		  	 	 	  	 	 	  	 	 

  

 45 

 Significant changes in the balance sheets between December 31, 2009 and December 31, 2008 include:

  

							
	 millions of dollars
	  	Increase
(Decrease)	 	 	 Explanation

	 Assets
	  				 	
	Accounts receivable and due from associated companies	  	$	46.4	  	 	Increased accounts receivable due to contract receivable classified as current from long-term and rate increase effective January 1, 2009; partially offset by lower posted margin to
counterparties, and timing of payments from associated companies.
	Inventory	  	 	38.8	  	 	Increased fuel inventory levels and commodity mix.
	Derivatives in a valid hedging relationship (including long-term portion)	  	 	(114.1	) 	 	Unfavourable USD price positions and additional hedges. The effective portion of the change is recognized in “Accumulated other comprehensive loss”.
	Held-for-trading derivatives (including long-term portion)	  	 	(101.9	) 	 	Unfavorable commodity price positions and recognition of derivatives in earnings. The portion related to regulatory liabilities is recognized in “Other
liabilities”.
	Other assets	  	 	(14.6	) 	 	Decreased regulatory asset related to fuel switching derivatives and pre-2003 income tax and related interest, partially offset by future income tax assets resulting from accounting
standard change.
	Long-term receivable	  	 	(56.4	) 	 	Long-term receivable reclassified to accounts receivable.
	Future income tax assets	  	 	34.4	  	 	Accounting standard change requiring rate-regulated operations to recognize future income tax assets and liabilities effective January 1, 2009.
	Property, plant and equipment and construction work in progress	  	 	143.3	  	 	Net capital additions in excess of depreciation expense.
			
	 Liabilities and Shareholders’ Equity
	  				 	
	Accounts payable and accrued charges and due to associated companies	  	 	35.1	  	 	Timing of payments largely associated with capital projects.
	Derivatives in a valid hedging relationship (including long-term portion)	  	 	(82.8	) 	 	Favorable commodity prices, additional hedges and recognition of derivatives in earnings. The effective portion of the change is recognized in “Accumulated other comprehensive
loss”.
	Held-for-trading derivatives (including long-term portion)	  	 	(24.8	) 	 	Favorable commodity price positions. The portion related to regulatory liabilities is recognized in “Other assets”.
	Future income tax liabilities	  	 	52.0	  	 	Accounting standard change requiring rate-regulated operations to recognize future income tax assets and liabilities effective January 1, 2009. The portion expected to be recovered
from customers in future rates is recognized in “Other assets”.
	Asset retirement obligations	  	 	13.9	  	 	Increase in obligations related to a new environmental regulation.
	Other liabilities	  	 	(88.8	) 	 	Decreased regulatory liability related to financial instruments.
	Short-term and long-term debt (including current portion)	  	 	252.6	  	 	Issuance of debt, largely associated with the redemption of the Series C preferred shares.
	Preferred shares (including current portion)	  	 	(125.0	) 	 	Redemption of Series C preferred shares.
	Accumulated other comprehensive loss	  	 	(43.4	) 	 	Primarily represents effective portion of unfavourable USD hedges.
	Retained earnings	  	 	(16.7	) 	 	Dividends paid in excess of net earnings.

  

 46 

 Cash Flow Highlights 

Significant changes in the cash flow statements between December 31, 2009 and December 31, 2008 include: 

 

											
	 Three months ended December 31

millions of dollars
	  	2009	 	 	2008	 	 	 Explanation

	 Cash and cash equivalents, beginning of period
	  	$	0.3	  	 	 	—  	  	 	
	 Provided by (used in):
	  				 				 	
				
	 Operating activities
	  	 	101.0	  	 	$	(2.9	) 	 	In 2009, increased cash earnings and decreased non-cash working capital.
				
		  				 				 	In 2008, increased non-cash working capital and decreased cash earnings.
				
	 Investing activities
	  	 	(112.3	) 	 	 	(58.2	) 	 	In 2009, capital spending including additions associated with multi-year projects.
		  				 				 	In 2008, capital spending.
				
	 Financing activities
	  	 	11.3	  	 	 	61.1	  	 	In 2009, increased short-term debt partially offset by dividends on common shares.
		  				 				 	In 2008, increased debt levels.
	 Cash and cash equivalents, end of year
	  	$	0.3	  	 	 	—  	  	 	

  

											
	 Year ended December 31

millions of dollars
	  	2009	 	 	2008	 	 	 Explanation

	 Cash and cash equivalents, beginning of period
	  	 	—  	  	 	$	1.9	  	 	
	 Provided by (used in):
	  				 				 	
				
	 Operating activities
	  	$	272.7	  	 	 	174.3	  	 	In 2009, increased cash earnings and decreased non-cash working capital.
		  				 				 	In 2008, cash earnings partially offset by increased non-cash working capital.
				
	 Investing activities
	  	 	(268.6	) 	 	 	(163.4	) 	 	In 2009, capital spending including additions associated with multi-year projects.
		  				 				 	In 2008, capital spending.
				
	 Financing activities
	  	 	(3.8	) 	 	 	(12.8	) 	 	In 2009, dividends on common shares and redemption of preferred shares, partially offset by increased debt levels.
		  				 				 	In 2008, dividends on common shares, decreased debt levels and decreased accounts receivable securitized partially offset by issuance of common shares.
	 Cash and cash equivalents, end of year
	  	$	0.3	  	 	 	—  	  	 	

  

 47 

 Electric Revenue 
  

										
	 Q4 Electric Sales Volumes

Gigawatt hours (“GWh”)

				
	 	  	2009	  	2008	  	2007
	 Residential
	  	 	1,091	  	 	1,093	  	 	1,064
	 Commercial
	  	 	772	  	 	770	  	 	793
	 Industrial
	  	 	998	  	 	987	  	 	1,046
	 Other
	  	 	81	  	 	84	  	 	99
		  	 	 	  	 	 	  	 	 
	 Total
	  	 	2,942	  	 	2,934	  	 	3,002
		  	 	 	  	 	 	  	 	 
	
	 Q4 Electric Revenues

millions of dollars

				
	 	  	2009	  	2008	  	2007
	 Residential
	  	$	140.4	  	$	129.1	  	$	125.7
	 Commercial
	  	 	84.2	  	 	76.9	  	 	78.5
	 Industrial
	  	 	67.3	  	 	64.2	  	 	67.5
	 Other
	  	 	11.0	  	 	10.5	  	 	11.4
		  	 	 	  	 	 	  	 	 
	 Total
	  	$	302.9	  	$	280.7	  	$	283.1
		  	 	 	  	 	 	  	 	 
	
	Q4 Average Electric Revenue / MWh
				
	 	  	2009	  	2008	  	2007
	 Dollars per MWh
	  	$	103	  	$	96	  	$	94
		  	 	 	  	 	 	  	 	 

      

 

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

GWh

				
	 	  	2009	  	2008	  	2007
	 Residential
	  	 	4,228	  	 	4,179	  	 	4,145
	 Commercial
	  	 	3,107	  	 	3,115	  	 	3,161
	 Industrial
	  	 	3,642	  	 	4,144	  	 	4,191
	 Other
	  	 	328	  	 	334	  	 	365
		  	 	 	  	 	 	  	 	 
	 Total
	  	 	11,305	  	 	11,772	  	 	11,862
		  	 	 	  	 	 	  	 	 
	
	 YTD Electric Revenues

millions of dollars

				
	 	  	2009	  	2008	  	2007
	 Residential
	  	$	547.3	  	$	496.3	  	$	485.6
	 Commercial
	  	 	333.9	  	 	305.2	  	 	307.6
	 Industrial
	  	 	263.8	  	 	268.1	  	 	266.6
	 Other
	  	 	43.1	  	 	41.5	  	 	42.2
		  	 	 	  	 	 	  	 	 
	 Total
	  	$	1,188.1	  	$	1,111.1	  	$	1,102.0
		  	 	 	  	 	 	  	 	 
	
	YTD Average Electric Revenue / MWh
				
	 	  	2009	  	2008	  	2007
	 Dollars per MWh
	  	$	105	  	$	94	  	$	93
		  	 	 	  	 	 	  	 	 

  
 The increase in average
revenue per MWh in 2009 compared to 2008 reflects the January 1, 2009, 9.4% rate increase noted above and a change in sales mix. 
 The
average revenue per MWh is higher in 2008 compared to 2007 reflecting the April 1, 2007, 3.8% rate increase noted above. 
 Electric sales
volume is primarily driven by general economic conditions, population and weather. Electricity pricing in Nova Scotia is regulated and changes when new regulatory decisions are implemented. The exceptions are annually adjusted rates, subscribed to
by certain larger industrial customers, and export sales, priced at market, which in recent years comprised less than 2% of NSPI sales volume. 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. 
  

 48 

 For the three months ended December 31, 2009, electric revenue increased $22.2 million to $302.9
million, compared to $280.7 million in Q4 2008. For the year ended December 31, 2009, electric revenue increased $77.0 million to $1,188.1 million compared to $1,111.1 million in 2008 and $1,102.0 million in 2007. Highlights of the changes are
summarized in the following table: 
  

									
	 millions of dollars
	  	Three months 
ended
December 31	 	 	Year ended
December 31
	 
	 Electric revenue – 2007
	  				 	$	1,102.0	  
	 Increased electricity pricing effective April 1, 2007
	  				 	 	12.3	  
	 Net change in residential and commercial sales volumes
	  				 	 	(0.5	) 
	 Decreased industrial sales volumes to several large industrial customers
	  				 	 	(1.5	) 
	 Decreased export sales
	  				 	 	(1.2	) 
		  	 	 	 	 	 	 	 
	 Electric revenue – 2008
	  	$	280.7	  	 	$	1,111.1	  
	 Increased electricity pricing effective January 1, 2009
	  	 	20.4	  	 	 	102.1	  
	 Net change in residential and commercial sales volumes
	  	 	(0.2	) 	 	 	4.2	  
	 Increased (decreased) industrial sales to several large industrial customers
	  	 	2.1	  	 	 	(28.3	) 
	 Decreased export sales
	  	 	(0.1	) 	 	 	(1.0	) 
		  	 	 	 	 	 	 	 
	 Electric revenue – 2009
	  	$	302.9	  	 	$	1,188.1	  
		  	 	 	 	 	 	 	 

 Fuel for Generation and Purchased Power 

Capacity 
 To ensure reliability of
service, NSPI maintains a generating capacity greater than firm peak demand. The total Company-owned generation capacity is 2,293 MW, which is supplemented by 137 MW contracted with independent power producers. NSPI meets the planning criteria for
reserve capacity established by the Maritime Control Area, and the Northeast Power Coordinating Council. 
 Management of capacity and capacity
utilization is a critical element of operating efficiency. The provision of sufficient generating capacity to meet peak demand inevitably results in excess capacity in non-peak periods, which allows for annual maintenance programs to be carried out
without compromising reserve capacity requirements. NSPI’s daily load is generally highest in the early evening and its seasonal load is highest through the winter months. Maximizing capacity utilization can defer investment in additional
generation capacity. Maximizing capacity utilization primarily depends on: 
  

	 	•	 	 Ensuring generating plants are consistently available to service demand – NSPI conducts ongoing planned maintenance programs and has sustained
high availability over the past several years. NSPI maintains low forced and unplanned outage rates compared to North American averages. 

  

	 	•	 	 Moving demand from peak to non-peak periods – NSPI encourages customers to move electricity demand from high cost to lower cost periods by
offering customers various pricing alternatives. NSPI also controls over 400 MW of interruptible electric load; including over 250 MW of energy supplied under real time rates. 

 

	 	•	 	 Export sales – Increasing export sales when margins are satisfactory allows energy from excess capacity to be sold when not required in the
province. NSPI operates a 24-hour marketing desk to optimize commercial opportunities such as export sales. 

 NSPI Thermal
Capacity Utilization 
  

									
	 2009
	  	 2008
	  	 2007
	  	 2006
	  	 2005

	 70%
	  	75%	  	79%	  	71%	  	78%

 NSPI Thermal Capacity Availability

  

									
	 2009
	  	 2008
	  	 2007
	  	 2006
	  	 2005

	 82%
	  	88%	  	91%	  	90%	  	90%

  

 49 

 NSPI’s thermal capacity utilization was 70% in 2009 compared to 75% in 2008. This change was due to
decreased domestic load largely resulting from decreased sales to industrial and commercial customers as a result of the global economic recession. 

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 2009, thermal plant availability was 82%. The decrease in availability from 2008 reflects extended 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
  

	 	  	2009	  	2008	  	2007
	 Coal & petcoke
	  	 	2,069	  	 	2,177	  	 	2,519
	 Natural gas
	  	 	534	  	 	249	  	 	333
	 Oil & diesel
	  	 	16	  	 	218	  	 	45
	 Renewable
	  	 	281	  	 	257	  	 	218
	 Purchased power
	  	 	335	  	 	296	  	 	189
		  	 	 	  	 	 	  	 	 
	 Total
	  	 	3,235	  	 	3,197	  	 	3,304
		  	 	 	  	 	 	  	 	 
	Purchased power includes 51 GWh of renewables in 2009 (2008 – 44 GWh; 2007 – 49 GWh).
	  
 Q4 Average Unit Fuel Costs

 

	 	  	2009	  	2008	  	2007
	Dollars per MWh	  	$	43	  	$	44	  	$	33
		  	 	 	  	 	 	  	 	 

										
	 YTD Production Volumes

GWh
  

	 	  	2009	  	2008	  	2007
	Coal & petcoke	  	 	8,177	  	 	9,009	  	 	9,561
	Natural gas	  	 	1,612	  	 	1,258	  	 	1,057
	Oil & diesel	  	 	307	  	 	339	  	 	515
	Renewable	  	 	1,065	  	 	1,068	  	 	911
	Purchased power	  	 	931	  	 	889	  	 	654
		  	 	 	  	 	 	  	 	 
	Total	  	 	12,092	  	 	12,563	  	 	12,698
		  	 	 	  	 	 	  	 	 
	Purchased power includes 149 GWh of renewables in 2009 (2008 – 148 GWh; 2007 – 161 GWh).
	  
 YTD Average Unit Fuel Costs

 

	 	  	2009	  	2008	  	2007
	Dollars per MWh	  	$	41	  	$	38	  	$	34
		  	 	 	  	 	 	  	 	 

 Solid fuel is NSPI’s dominant fuel source, supplying approximately 68% of the Company’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. Oil, natural gas, 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 2009 compared to 2008 mainly as a result of higher priced commodity contracts for coal and natural
gas.
 The average unit fuel costs increased in 2008 compared to 2007 mainly due to the decreased value of the natural gas supply contract as
reflected in the long-term receivable, and change in generation mix due to lower coal production due to an increase in coal plant maintenance. Increased coal prices were partially offset by the economic use of natural gas and favourable hedge
positions as a result of this fuel switch. 
 A substantial amount of NSPI’s fuel supply comes from international suppliers, and is subject
to commodity price and foreign exchange risk. The Company 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 the Company’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, 2009, fuel for
generation and purchased power decreased $1.0 million to $138.5 million, compared to $139.5 million in Q4 2008. For the year ended December 31, 2009, fuel for generation and purchased power increased $29.3 million to $500.7 million compared to
$471.4 million in 2008 and $433.7 million in 2007. 
  

 50 

 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 – 2007
	  				 	$	433.7	  
	Increased coal prices partially offset by the economic use of natural gas and favourable hedge positions as a result of this fuel switch	  				 	 	18.3	  
	Decreased sales volume	  				 	 	(9.9	) 
	Decreased net proceeds from the resale of natural gas due to the economic decision to use natural gas in the production process	  				 	 	8.8	  
	Increased hydro production	  				 	 	(11.9	) 
	Changes in generation mix due to increased coal plant maintenance	  				 	 	30.7	  
	Other	  				 	 	1.7	  
		  	 	 	 	 	 	 	 
	 Fuel for generation and purchased power – 2008
	  	$	139.5	  	 	$	471.4	  
	Commodity price increases	  	 	14.5	  	 	 	36.2	  
	(Increased) decreased proceeds from the resale of natural gas	  	 	(2.8	) 	 	 	10.3	  
	Valuation of contract receivable (see discussion below)	  	 	(13.0	) 	 	 	4.5	  
	Increased (decreased) sales volume	  	 	4.3	  	 	 	(22.2	) 
	Mark-to-market on natural gas hedges not required in 2009 primarily due to decreased production volumes	  	 	(0.6	) 	 	 	(0.7	) 
	Changes in generation mix and plant performance	  	 	(7.1	) 	 	 	(10.2	) 
	(Increased) decreased hydro production	  	 	(0.6	) 	 	 	1.8	  
	Primarily solid fuel handling costs previously included in “Operating, maintenance and general expenses”	  	 	5.0	  	 	 	10.7	  
	Other	  	 	(0.7	) 	 	 	(1.1	) 
		  	 	 	 	 	 	 	 
	 Fuel for generation and purchased power – 2009
	  	$	138.5	  	 	$	500.7	  
		  	 	 	 	 	 	 	 

 The valuation of the contract receivable from a natural gas supplier requires 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. 

Fuel Adjustment 
 The UARB approved the
implementation of a fuel adjustment mechanism in the Company’s 2009 General Rate Decision effective January 1, 2009. The FAM is subject to an incentive with NSPI retaining or absorbing 10% of the over or under-recovered amount less the
difference between the incentive threshold and the base fuel cost to a maximum of $5 million. 
 For the year ended December 31, 2009,
actual fuel costs were less than amounts recovered from customers. The difference has been recorded as an expense, and accrued to a FAM regulatory liability in “Other liabilities”. As a result of the effective management of fuel on behalf
of customers, NSPI earned a $5 million FAM incentive in 2009. 
 The Company has recognized a future income tax recovery related to the fuel
adjustment based at its applicable statutory income tax rate. 
 As at December 31, 2009, NSPI’s FAM regulatory liability was $9.9
million (2008 – nil), and the related future income tax asset was $3.4 million (2008 – nil). The FAM regulatory liability includes amounts recognized as a fuel adjustment and associated interest carrying costs included in “Financing
charges”. The fuel adjustment includes fuel-related foreign exchange gains and losses that are reported as part of “Financing charges”. 

In December 2009, as part of the FAM regulatory process, customer rates were set for 2010 based on the projected over-recovery of fuel costs in 2009. The
customer “Actual Adjustment” (“AA”) reflects a combination of actual and forecasted fuel costs and customer fuel recoveries for the period. The customer FAM AA rate decrease was set based on a projected over-recovery of fuel
costs of $22.0 million (1.4%). The difference between the actual FAM AA of $9.9 million and the $22.0 million used to set 2010 rates will be recovered in 2011 as part of the FAM Balancing Adjustment (“BA”) along with interest and any
variances in 2010 sales volumes. 
  

 51 

 In the absence of UARB approval, the fuel adjustment would not have been recognized and earnings for the
three months ended December 31, 2009 would be $10.2 million ($6.7 million after-tax) lower (2008-nil) and for the year ended December 31, 2009 would be $9.9 million ($6.5 million after-tax) higher (2008 – nil). 

Operating, Maintenance and General 

Operating, maintenance and general expenses have increased $6.1 million to $58.4 million in Q4 2009 compared to $52.3 million in Q4 2008 and 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.
These cost increases were partially offset by lower pension expense. 
 Operating, maintenance and general expenses remained relatively
unchanged for the year ended December 31, 2008 compared to 2007. 
 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 
 Depreciation expense
increased $3.0 million to $36.8 in Q4 2009 compared to $33.8 million in Q4 2008 and 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. 
 For the year ended
December 31, 2008, depreciation expense increased $2.5 million to $133.6 million compared to $131.1 million in 2007 due to plant additions. 

Regulatory Amortization 
 Regulatory
amortization increased $8.3 million to $14.7 million in Q4 2009 compared to $6.4 million in Q4 2008 and 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 amortization
of the pre-2003 income tax regulatory asset resulting from the UARB’s ROE decision in January 2010. This decision allows NSPI to recognize additional amortization amounts in current periods and to reduce amounts in future periods which provides
flexibility relating to customer rate requirements. 
 For the year ended December 31, 2008, regulatory amortization increased $0.5 million
to $17.7 million compared to $17.2 million in 2007 due to the amortization of the pre-2003 income tax regulatory asset partially offset by the completion of the Glace Bay generating station amortization in 2007. 

Other Revenue 
 Other revenue, which
consists of miscellaneous revenues and commercial settlements, has remained relatively unchanged for the year ended December 31, 2009 compared to 2008. 

For the year ended December 31, 2008, other revenue increased $3.8 million to $15.5 million compared to $11.7 million in 2007 due to increased
commercial settlements received and a reduction in the accounts receivable securitization program which resulted in lower fees. 
  

 52 

 Financing Charges 

Financing charges increased $13.0 million to $33.3 million in Q4 2009 compared to $20.3 million in Q4 2008 and 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 million which was received
as a result of the Company amending its 1999 to 2003 corporate income tax returns. This refund interest was recorded as a reduction of “Financing charges”. 

Financing charges decreased $16.2 million to $106.8 million for the year ended December 31, 2008 compared to $123.0 million in 2007 primarily due to
foreign exchange gains in 2008 partially offset by income tax recovery interest in 2007. In Q4 2007, NSPI recorded income tax refund interest of $8.6 million, $1.8 million of which has been recorded as a reduction of “Other assets”. The
remaining $6.8 million 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 2009, NSPI was subject to provincial capital tax (0.175%), corporate income tax (35%) 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 (42% of preferred dividends). 

During 2008, NSPI accelerated the deduction of capitalized expenses pertaining to the 2007 tax year. As a result, in 2008, NSPI recorded an income tax
recovery of $6.5 million. NSPI continues to use this methodology. 
 OUTLOOK 

Economic Environment 
 The global economy
has experienced the worst economic downturn since the depression of the 1930s. Signs of recovery are now present and the Bank of Canada is predicting modest economic growth for Canada in 2010. Parallel to this economic disruption has been the
continued transformation of the energy industry from high emissions to lower emissions. This transformation provides opportunity for NSPI over the next five years. The Company has embarked upon a capital investment plan to increase the
Company’s generation from renewable sources and to improve the transmission connections within the service territory as it transitions to a cleaner, greener Company. 

Environmental Legislation 
 In August
2009, the province of Nova Scotia enacted limits on greenhouse gas emissions. Caps have been set for years 2010 and 2020 inclusive. The Company has stabilized and reduced emissions; continues to add cleaner, greener sources of
electricity; and works with customers to manage energy usage. The Company will continue to reduce green house gas emissions and comply with the new regulations.

The Canadian federal government has not formalized any greenhouse gas emission reduction regulations and have now signaled alignment with the United
States’ approach, which is tending towards cap and trade in the 2012 – 2014 timeframe for a starting year. The Company continues to provide input to the Canadian federal government through their consultations. 

 

 53 

 Operations 

NSPI anticipates earning a regulated ROE within its allowed range in 2010. NSPI does not plan to file a general rate application in 2010. NSPI continues
to implement its strategy focused on regulated investments in renewable energy and system reliability projects with a capital program budget of approximately $450 million in 2010. The Company expects to finance its capital expenditures with funds
from operations and debt. 
 LIQUIDITY AND CAPITAL RESOURCES 

The Company generates cash mainly through its operations involving the generation, transmission and distribution of electricity. NSPI’s customer base
is diversified by both sales volume and revenues among residential, commercial, industrial and other customers. Circumstances that could affect the Company’s ability to generate cash include general economic downturns, the loss of one or more
large customers, and regulatory decisions affecting customer rates. The UARB approved a FAM that reduces NSPI’s exposure to fuel price volatility. The first rate adjustment under the FAM was approved by the UARB on December 9, 2009 and
effective on January 1, 2010. 
 In addition to internally generated funds, the Company has access to debt capital markets, including $500
million in a committed syndicated revolving bank line of credit, of which approximately $265 million is undrawn and available at December 31, 2009. NSPI has an active commercial paper program for up to $400 million, of which outstanding amounts
are 100% backed by the bank line referred to above and this results in an equal amount of credit being considered drawn and unavailable. 

NSPI’s revolving credit facility was successfully renewed in June 2009 and now matures in June 2010; it can be extended annually with the approval
of the syndicated banks. At each maturity date, NSPI has the option to convert all amounts drawn on the bank credit line to a one year non-revolving term credit. 

As at December 31, 2009, the Company had a debt shelf prospectus in the amount of $400 million that expires in February 2010 and had issued the full
amount of long-term debt allowed under this shelf prospectus. NSPI intends to file a new $500 million shelf prospectus in the first half of 2010. The Company also has access to equity capital markets for preferred shares. 

NSPI has established the following available credit facilities: 
  

						
	 As at December 31, 2009

millions of dollars
	  	Maturity	  	Maximum
amount
	 Operating credit facility
	  	1 Year Revolving	  	$	500.0

 NSPI issues commercial paper, 100%
backed by the syndicated bank line of credit, to finance short-term cash requirements and has accessed the market as required throughout 2009. 

NSPI has debt covenants associated with its credit facilities. These covenants are tested regularly, and the Company is in compliance with the covenant
requirements. 
 Debt Management 

In January 2009, NSPI completed a $50 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 5.75% and yield 5.455% per annum until October 2013. 
 In April 2009, NSPI redeemed the $125 million Series C
preferred shares using short-term credit facilities. 
 In June 2009, NSPI redeemed $125 million long-term notes using short-term credit
facilities. 
  

 54 

 In July 2009, NSPI completed a $200 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 5.95% and yield 5.974% per annum until July 27, 2039. 
 The
weighted average coupon rate on NSPI’s outstanding medium-term and debenture notes at December 31, 2009, was 6.80% (2008 – 6.84%). Approximately 38% of the debt matures over the next ten years; 59% matures between 2020 and 2039; 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 4.87% as at December 31, 2009 (2008 – 6.12%). 

NSPI has the following credit ratings: 
  

							
	 	  	 DBRS
	  	S&P	  	Moody’s
	 Corporate
	  	N/A	  	BBB+	  	Baa1
	 Senior unsecured debt
	  	A (low)	  	BBB+	  	Baa1
	 Preferred stock
	  	Pfd-2 (low)	  	P-2 (low)	  	N/A
	 Commercial paper
	  	R-1 (low)	  	A-1 (low)	  	P-2

 In September 2009, Standard &
Poor’s Rating Services (“S&P”) revised the long-term credit rating to BBB+ from BBB following the implementation of the FAM and improvements in the Company’s liquidity. 

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

																						
	  	  	Payments Due by Period
	 millions of dollars
	  	Total	  	2010	  	2011	  	2012	  	2013	  	2014	  	After 2014
	 Long-term debt
	  	$	1,508.6	  	$	100.7	  	$	0.7	  	$	0.7	  	$	300.7	  	$	0.7	  	$	1,105.1
	 Preferred shares
	  	 	135.0	  	 	—  	  	 	—  	  	 	—  	  	 	—  	  	 	—  	  	 	135.0
	 Operating leases
	  	 	10.7	  	 	9.6	  	 	1.1	  	 	—  	  	 	—  	  	 	—  	  	 	—  
	 Purchase obligations
	  	 	2,451.6	  	 	359.2	  	 	274.5	  	 	219.7	  	 	116.1	  	 	98.8	  	 	1,383.3
	 Capital obligations
	  	 	121.7	  	 	118.1	  	 	3.6	  	 	—  	  	 	—  	  	 	—  	  	 	—  
	 Other long-term obligations
	  	 	326.3	  	 	1.6	  	 	1.8	  	 	1.1	  	 	1.1	  	 	1.1	  	 	319.6
		  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 
	 Total contractual obligations
	  	$	4,553.9	  	$	589.2	  	$	281.7	  	$	221.5	  	$	417.9	  	$	100.6	  	$	2,943.0
		  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 

 Operating lease obligations: NSPI’s operating lease
obligations consist of operating lease agreements for office space and telecommunications services. 
 Purchase obligations: NSPI has
purchasing commitments for electricity from independent power producers, transportation of coal, outsourced management of the Company’s computer infrastructure, natural gas, transportation capacity on the Maritimes & Northeast Pipeline
and fuel. 
 Capital obligations: NSPI has commitments to third parties to purchase turbines and other goods and services. 

Other long-term obligations: The Company has asset retirement and other long-term obligations. 

The Company expects to be able to meet its obligations with cash flows generated from operations. 

Capital Resources 
 Capital expenditures
for 2009, including AFUDC, were approximately $279 million. Significant capital projects included the completion of the pulse air fabric filter baghouse and generator replacement on Trenton Unit 5, the Tuft’s Cove 6 Waste Heat Recovery project,
the Nuttby Mountain Wind project, and the new corporate head office project. 
  

 55 

 PENSION FUNDING 

For funding purposes, NSPI determines required contributions to its defined benefit pension plans based on a smoothed asset value. 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 2010 for defined benefit pension plans will be approximately $36.7 million (2009 – $31.1 million). All
pension plan contributions are tax deductible and will be funded with cash from operations. 
 NSPI’s defined benefit pension plan is
managed with a diversified portfolio of asset classes, investment managers and geographic investments. NSPI reviews the investment managers on a regular basis, and the plan’s asset mix from time to time. 

NSPI’s projected contribution to defined contribution pension plans is $1.2 million for 2010 (2009 – $1.0 million). 

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, 2009 totaled $1.0 billion, 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 72% 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 

The Company enters into various transactions with its affiliates in the normal course of operations. All transactions are recorded, subject to terms in
the Code of Conduct, at the exchange value, which is generally based on commercial rates or as agreed to by the parties. The Code of Conduct governs transactions between NSPI and its affiliates and is approved by the UARB. 

Due to (from) associated companies represents the total carrying amounts of trade payables (receivables), which are owed from (to) NSPI to (by)
NSPI’s parent company, Emera Inc., and companies wholly-owned by Emera Inc. The terms of repayment are the same as those for non-affiliate trade payables (receivables). 

During the quarter, NSPI had sales and purchases from companies under common control of Emera Inc. as follows: 

 

									
	 millions of dollars
	  	 	  	Three months 
ended
December 31
	 Affiliate
	  	 Purpose of Transaction
	  	2009	  	2008
	 Sales:
	  		  			  		
	 Emera Energy Services
	  	 Net sales of gas
	  	$	2.0	  	$	26.1
	 Other
	  	 Other services provided
	  	 	2.0	  	 	2.5
	 Purchases:
	  	 Electricity and services purchased
	  	$	5.0	  	$	4.5

 In the ordinary course of business, the
Company purchased natural gas transportation capacity totaling $4.4 million (2008 - $4.8 million) during the three months ended December 31, 2009 from the Maritimes & Northeast Pipeline, an investment under significant influence of
Emera Inc. 
  

 56 

 For the year ended December 31, 2009, NSPI had sales and purchases from companies under common control
of Emera Inc. as follows: 
  

									
	 millions of dollars
	  	 	  	For the year 
ended
December 31
	 Affiliate
	  	 Purpose of Transaction
	  	2009	  	2008
	 Sales:
	  		  			  		
	 Emera Energy Services
	  	 Net sales of gas
	  	$	26.2	  	$	100.4
	 Other
	  	 Other services provided
	  	 	6.9	  	 	6.4
	 Purchases:
	  	 Electricity and services purchased
	  	$	18.8	  	$	13.3

 In the ordinary course of business,
the Company purchased natural gas transportation capacity totaling $18.2 million (2008 – $19.0 million) during the year ended December 31, 2009 from the Maritimes & Northeast Pipeline, an investment under significant influence of
Emera Inc. The amount is recognized in “Fuel for generation and purchased power” and is measured at the exchange amount. As at December 31, 2009, the amount payable to the related party is $1.5 million (2008 - $1.6 million), and is
under normal interest and credit terms. 
 During the year ended December 31, 2009, the Company issued a total of 0.4 million (2008
– 10.0 million) common shares to Emera Inc. and an affiliate under common control of Emera Inc. for total consideration of $4.1 million (2008 – $100.0 million). 

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, interest rate options and swaps, and coal, oil and gas options and swaps. In addition, the Company has contracts for the physical purchase
and sale of natural gas, 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 effective portion of the change in the fair value of derivatives is deferred to “Other comprehensive loss” and
recognized in earnings in the same period 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. 

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. The Company also recognizes the change in the fair value of its HFT derivative in the income of the reporting period. 

HTF derivatives are recorded on the balance sheet at fair value, with changes normally recorded in near earnings of the period, unless deferred as a
result of regulatory accounting. The Company has not designated any financial instruments to be included in the HFT category. 
  

 57 

 Where the documentation or effectiveness requirements of hedges accounting 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. 
 The Company 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 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
is being applied prospectively, beginning in 2009, as required by the UARB. 
 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 2009	 	 	December 31
2008	 
	 Inventory
	  	$	22.2	  	 	$	(7.1	) 
	 Derivatives in a valid hedging relationship
	  	 	(23.8	) 	 	 	7.5	  
	 Long-term debt
	  	 	0.1	  	 	 	0.4	  
		  	 	 	 	 	 	 	 
		  	$	(1.5	) 	 	$	0.8	  
		  	 	 	 	 	 	 	 

 Hedging Impact Recognized in Earnings 

The Company recognized in net earnings the following gains and losses related to effective portion of hedging relationships under the following
categories: 
  

															
	  	  	Three months ended
December 31	  	Year ended
December 31
	 millions of dollars
	  	2009	 	 	2008	  	2009	 	 	2008
	 Fuel and purchased power (increase) decrease
	  	$	(19.0	) 	 	$	11.8	  	$	(33.1	) 	 	$	25.6
	 Financing charges decrease
	  	 	1.0	  	 	 	1.0	  	 	6.9	  	 	 	1.0
		  	 	 	 	 	 	 	  	 	 	 	 	 	 
	 Effectiveness (losses) gains
	  	$	(18.0	) 	 	$	12.8	  	$	(26.2	) 	 	$	26.6
		  	 	 	 	 	 	 	  	 	 	 	 	 	 

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

																
	  	  	Three months ended
December 31	  	Year ended
December 31	 
	 millions of dollars
	  	2009	 	 	2008	  	2009	 	 	2008	 
	 Fuel and purchased power increase
	  	$	(1.0	) 	 	 	—  	  	$	(12.8	) 	 	 	(0.5	) 
	 Financing charges decrease (increase)
	  	 	0.3	  	 	$	0.7	  	 	(0.5	) 	 	$	0.7	  
		  	 	 	 	 	 	 	  	 	 	 	 	 	 	 
	 Ineffectiveness (losses) gains
	  	$	(0.7	) 	 	$	0.7	  	$	(13.3	) 	 	$	0.2	  
		  	 	 	 	 	 	 	  	 	 	 	 	 	 	 

 Held-for-trading Items Recognized on the Balance Sheet 

The Company has recognized on the balance sheet a net held-for-trading derivatives asset of $1.6 million as at December 31, 2009 (2008 - $78.7
million). 
  

 58 

 Held-for-trading Derivatives Gains (Losses) Recognized in Earnings 

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

 

																
	  	  	Three months ended
December
31	 	 	Year ended
December 31	 
	 millions of dollars
	  	2009	 	 	2008	 	 	2009	  	2008	 
	 Fuel and purchased power
	  	$	1.4	  	 	$	(0.3	) 	 	$	13.0	  	$	(0.4	) 
	 Financing charges
	  	 	(0.1	) 	 	 	(0.1	) 	 	 	—  	  	 	(0.5	) 
		  	 	 	 	 	 	 	 	 	 	 	  	 	 	 
	 Held-for-trading derivatives gains (losses)
	  	$	1.3	  	 	$	(0.4	) 	 	$	13.0	  	$	(0.9	) 
		  	 	 	 	 	 	 	 	 	 	 	  	 	 	 

 As discussed in note 20 of NSPI’s financial statements at the reporting date, various valuation techniques are used to
determine the fair value of derivative instruments. These include may include quoted market prices, internal models using observable or non-observable market information. 

Business Risks 
 Measurement of Risk

 Significant risk management activities for NSPI 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 and quality of earnings. 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 effective January 1, 2009, reducing NSPI’s exposure to price
volatility and providing a mechanism for NSPI to recover actual fuel costs, if different than what is recovered from customers in rates. The FAM mitigates the risk to NSPI’s net earnings associated with fluctuations in commodity prices and
foreign exchange. The first rate adjustment under the FAM was approved by the UARB on December 9, 2009 effective January 1, 2010. 

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, 2009 is as follows: 

 

	 	•	 	 2010 – 84% 

  

	 	•	 	 2011 – 34% 

  

	 	•	 	 2012 – 15% 

  

 59 

 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 2010 and 2011, NSPI
currently does not have heavy fuel oil hedging requirements. 
 Natural Gas 

NSPI has entered into multi-year contracts to purchase approximately 60,000 mmbtu of natural gas per day in 2010, and 38,000 mmbtu of natural gas per day
in 2011. 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. Fixed price gas volumes not required
for generation will be resold into the gas market with the margin hedged using financial instruments. As at December 31, 2009, amounts of natural gas volumes that have been economically and/or financially hedged and contracted are approximately
as follows: 
  

	 	•	 	 2010 – 94% 

  

	 	•	 	 2011 – 32% 

Foreign Exchange Risk 
 The risk due to
fluctuation of the CAD against the USD for the cost of fuel is measured and managed. In 2010, NSPI expects approximately 68% 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. 
 NSPI enters into foreign exchange forward and swap contracts to limit the exposure of currency
rate fluctuations on fuel purchases. Currency forwards are used to fix the CAD cost to acquire USD, reducing exposure to currency rate fluctuations. Forward contracts to buy USD $331.0 million are in place at a weighted average rate of $1.09,
representing 89% of 2010 anticipated USD requirements. Forward contracts to buy USD $471.5 million in 2011 through 2013 at a weighted average rate of $1.01 were in place at December 31, 2009. These contracts cover 42% of anticipated USD
requirements in these years. 
 NSPI uses foreign exchange forward contracts to hedge the currency risk for capital projects and receivables
denominated in foreign currencies. Forward contracts to buy USD $0.9 million are in place at a weighted average rate of $1.00 for capital projects in 2010. Forward contracts to buy €30.3 million are in place at a weighted average rate of
1.56 (versus CAD) for capital projects in 2010. Forward contracts to sell USD $39.0 million are in place at a weighted average rate of $1.25 to hedge a portion of receivables in 2010. 

Interest Rate Risk 
 NSPI manages
interest rate risk through a combination of fixed and floating borrowing and a hedging program. Floating-rate debt is estimated to represent approximately 17% of total debt in 2010. The Company has no interest rate hedging contracts outstanding as
at December 31, 2009. 
 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 2012. 
  

 60 

 Regulatory Risk 

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 first rate adjustment under the FAM, effective on January 1, 2010, was approved by the UARB on
December 9, 2009. 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%. 
 Environment 

Corporate Environmental Governance 
 NSPI
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. NSPI has 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 NSPI undertook initiatives in 2009 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 2009 audits. Plans are in place to promptly address any audit finding and continually improve the environmental
management of the operations. 
 Oversight of environmental matters is carried out by the Board of Directors or committees of the Board of
Directors with specific environmental responsibilities. In addition, an Environmental Council, made up of senior NSPI employees with working accountability for environment, continues to guide the implementation of programs that address key
environmental issues. In addition to programs for employees, the EMS procedures include planning, implementing and monitoring of contractors’ performance. 

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.” 

Climate Change and Air 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. 
 In January 2007, the Nova Scotia government approved the 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. 
 In April 2007, the
province of Nova Scotia enacted an Act Respecting Environmental Goals and Sustainable Prosperity. Within this act, there is an objective to reduce provincial greenhouse gas emissions to 10% below 1990 levels by 2020. In January 2009, the province
released its 2009 Energy Strategy and Climate Change Action Plan. These documents provide the elements of the plan to 

 

 61 

 
achieve this objective. In August 2009, the province enacted regulations to cap green house gas emissions from the electricity sector in Nova Scotia. 

Greenhouse gas emissions from NSPI facilities are capped beginning in 2010 through to 2020. The 2010 to 2012 caps will be achieved by the continued
success of energy efficiency and conservation programs and the addition of renewable energy to meet the 2010 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. 
 It is anticipated that the 2013 – 2015 caps will be achieved by flattening load
growth through successful energy efficiency and conservation programs and adding renewable energy to meet the provincial 2013 renewable energy standards. NSPI has also piloted co-firing of local biomass, which can be a carbon neutral fuel, in the
coal fired power plants. 
 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. 
 The Canadian
federal government has not formalized any greenhouse gas emission reduction regulations and have now signaled alignment with the US approach which is tending towards cap and trade in the 2012 to 2014 timeframe for a starting year. NSPI continues to
provide input to the Canadian federal government as it proceeds with its consultations. 
 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 will allow NSPI to meet the mercury emission cap of 65 kg established by
the province effective 2010. 
 NSPI has completed its capital program of retrofitting low nitrogen oxide combustion firing systems on six of
its seven pulverized fuel coal units. NSPI now meets the nitrogen oxide emission cap of 21,365 tonnes per year established by the province effective 2009. 

NSPI continues to meet its emission cap on sulphur dioxide emissions by the use of compliant fuel. 

Compared to historical levels, NSPI will have reduced sulphur dioxide by 50% effective 2010, nitrogen oxide by 40% effective 2009 and mercury emissions
by 60% effective 2010. 
 DISCLOSURE AND INTERNAL CONTROLS 

NSPI’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 NSPI’s DC&P and ICFR and based on that evaluation have concluded DC&P and ICFR were effective at December 31, 2009. 

 

 62 

 There have been no changes in NSPI’s ICFR during the period beginning on January 1, 2009 and ended
on December 31, 2009, which have materially affected, or are reasonably likely to materially affect ICFR. 
 SIGNIFICANT ACCOUNTING
POLICIES AND CRITICAL ACCOUNTING ESTIMATES 
 The preparation of 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, asset retirement obligations, and useful lives for depreciable assets. Actual results may differ from these estimates. 

Rate Regulation 
 NSPI’s accounting
policies are subject to examination and approval by its regulator. As a result, its rate-regulated accounting policies may differ from accounting policies for non-rate-regulated companies. These differences occur when the regulator renders its
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 regulator’s future actions are different from the regulator’s 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. 

Similar to most North American pension plans, NSPI experienced negative asset returns during 2008 and positive asset returns during 2009. Consistent with
CGAAP and NSPI’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 10 years. NSPI’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. 
  

 63 

 The discount rate used to determine benefit costs is based on high quality long-term Canadian corporate
bonds. 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 7.50% for 2009
(2008 – 5.75%). 
 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 2009 (2008 – 7.50%). 

The reported benefit cost for 2009, based on management’s best estimate assumptions, is $14.6 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 2009 benefit cost of a 25 basis point change (0.25%) in the discount rate and asset return
assumptions: 
  

															
	 	  	2009	 	 	2008	 	 	2009	  	2008
	 millions of dollars
	  	Increase 0.25%	 	 	Increase 0.25%	 	 	Decrease 0.25%	  	Decrease 0.25%
	 Discount rate assumption
	  	$	(0.9	) 	 	$	(3.3	) 	 	$	0.9	  	$	3.4
	 Asset return assumption
	  	$	(1.7	) 	 	$	(1.6	) 	 	$	1.7	  	$	1.6

 The sensitivity to the discount rate
assumption is significantly lower for 2009 benefit cost than in recent years because the net unamortized gains and losses subject to amortization fall within the 10% corridor. As such, for the current year, small changes to the discount rate
assumption do not impact the amount of actuarial gains and losses being amortized and included in the calculation of benefit cost. 

Unbilled Revenue 
 Electric revenues are
billed on a systematic basis over a one or two-month period. 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. 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, 2009, unbilled revenues amount to $85.4 million (2008 – $80.2 million) on a base of annual electric revenues of approximately $1.2 billion
(2008 – $1.1 billion). 
 Contract Receivable 

NSPI’s existing natural gas purchase agreement includes a price adjustment clause covering three years of natural gas purchases. The clause states
that NSPI will pay for all gas purchases at the agreed contract price, but will 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. The next settlement
will be in November 2010. Management has made a best estimate of the price rebate based on the contract specifications using actual and forward market pricing and recorded it in “Accounts receivable”. 

Asset Retirement Obligations 
 The
Company recognizes asset retirement obligations 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 asset
retirement obligations 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. 

 

 64 

 As part of the 2003 NSPI depreciation settlement, the UARB included the amount of future expenditures
associated with the removal of generation facilities. NSPI believes that it will continue to be able to recover asset retirement obligations through rates. Accordingly, changes to the asset retirement obligations, or cost recognition attributable to
changes in the factors discussed above, should not impact the results of operations of the Company. 
 As at December 31, 2009, the asset
retirement obligations recorded on the balance sheet were $101.5 million (2008 – $87.6 million). The Company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $326.3 million, which will be
incurred between 2010 and 2061. The majority of these costs will be incurred between 2020 and 2039. 
 Property, Plant and Equipment 

 Property, plant and equipment represents 73% 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 size of the Company’s property, plant and equipment, changes in estimated depreciation rates can have an 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 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. 
 CHANGES IN ACCOUNTING POLICIES AND PRACTICES 

The Canadian Institute of Chartered Accountants (“CICA”) has issued new accounting Standard 3064 Goodwill and Intangibles, various new
accounting standards related to accounting for rate-regulated operations, Emerging Issues Committee Abstract of Issue Discussed 173 Credit Risk and the Fair Value of Financial Assets and Financial Liabilities (“EIC-173”), and amendments to
Standard 3862 Financial Instruments – Disclosures, which are applicable to NSPI’s 2009 fiscal year. The following provides more information on each change. 

Goodwill and Intangibles 
 Under Standard
3064, goodwill requirements have not changed. The requirements for intangible assets now clarify that costs may only be deferred when they relate to an item that meets the definition of an asset. An intangible asset must be identifiable; be a
resource over which the Company has control; generate probable future economic benefits; and have a reliably measurable cost. Further information can be found in note 12 to the financial statements. 

 

 65 

 The Company has applied the new standard retrospectively with restatement of prior periods, which resulted
in the following reclassifications: 
  

									
	 As at

millions of dollars
	  	December 31
2008	 	 	December 31
2007	 
	 Assets
	  				 			
	 Property, plant and equipment
	  	$	(56.5	) 	 	$	(57.1	) 
	 Construction work in progress
	  	 	(2.2	) 	 	 	(1.6	) 
	 Intangibles
	  	$	58.7	  	 	$	58.7	  

 Rate-Regulated Operations 

 These new standards include removing the temporary exemption in Standard 1100 Generally Accepted Accounting Principles pertaining to the
application of the standard to the recognition and measurement of assets and liabilities arising from rate regulation; and amending Standard 3465 Income Taxes to require the recognition of future income tax assets and liabilities for the amount of
future income taxes expected to be included in future rates and recovered from or paid to future customers. 
 As a result of the new standards,
NSPI recognized its future income tax assets and liabilities. In accordance with the Company’s rate-regulated accounting policies covering income taxes, NSPI deferred any future income taxes to a regulatory asset or liability where the future
income taxes are expected to be included in future rates. Further information can be found in note 7 to the financial statements. The Company has applied the new standard retrospectively without restatement of prior periods, which resulted in the
following increases: 
  

				
	 millions of dollars
	  	January 1
2009
	 Assets
	  		
	 Current assets
	  		
	 Future income tax assets
	  	$	31.6
		  	 	 
	 Other assets
	  	 	16.2
		  	 	 
		  	$	47.8
		  	 	 
	 Liabilities and Shareholders’ Equity
	  		
	 Future income tax liabilities
	  	$	47.8
		  	 	 
		  	$	47.8
		  	 	 

 In accordance with Standard 1100, NSPI determined all of its
regulatory assets and liabilities qualified for recognition under CGAAP as well as US Financial Accounting Standard Board’s Accounting Standard Codification 980, Regulated Operations. 

Financial Instruments 
 EIC-173 requires
that a company take into account its own credit risk and the credit risk of the counterparty in determining the fair value of financial assets and financial liabilities. The Company has applied the new requirements retrospectively without
restatement of prior periods, the effect of which was immaterial. 
 Financial Instruments – Disclosures 

In June 2009, the CICA issued amendments to Standard 3862 Financial Instruments – Disclosures to include additional disclosure requirements about the
fair value measurement of financial instruments and to enhance liquidity risk disclosures. The Company has reflected the additional disclosures in its 2009 annual audited financial statements. The new accounting standard covers disclosure only and
had no effect on the financial results of the company. Further information can be found in note 20 of the financial statements. 
 The
accounting policy changes listed above did not affect earnings. 
  

 66 

 Derivative Financial & Commodity Instruments 

Accounting for the impact of rate regulation 

The UARB allows the Company to apply hedge accounting to hedging relationships that do not meet the probability requirements of Standard 3865 Hedges due
to the Company’s ability to fuel switch at the TUC. Absent UARB approval, NSPI would be required to recognize the change in fair value of these derivatives in net earnings. 

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 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 is being applied
prospectively, beginning in 2009, as required by the UARB. 
 As at December 31, 2009, the change in accounting practice resulted in $0.4
million additional interest costs recognized in “Financing charges” ($0.3 million after-tax) and $0.4 million increase in the FAM regulatory liability in “Other Liabilities”. 

Future Accounting Policy Changes 

Changeover to International Financial Reporting Standards (“IFRS”) 

In February 2008, the CICA announced that Canadian GAAP for publicly accountable enterprises will be replaced by International Financial Reporting
Standards (“IFRS”) for fiscal years beginning on or after January 1, 2011. Accordingly, the conversion from Canadian GAAP to IFRS will be applicable to the Company’s reporting for the first quarter of 2011, for which the current
and comparative information will be prepared in accordance with IFRS. The Company expects the transition to IFRS to impact accounting, financial reporting, internal controls over financial reporting, information systems and processes, and certain
contractual arrangements. The most significant areas of impact are property, plant and equipment (“PP&E”), regulatory assets and liabilities, and employee future benefits. The actual financial impacts on these areas are, however,
dependent on the outcome of the International Accounting Standard Board (“IASB”) Exposure Draft (“ED”) on Rate Regulated Activities (“RRA”) which was issued in July 2009. 

The IASB’s ED on RRA proposes to allow the continued recognition of assets and liabilities arising from certain rate-regulated activities. IFRS does
not currently provide guidance on accounting for the effects of rate regulation and the ED represents a significant change from current IFRS practices. The ED was open to comment until November 20, 2009 and the original timeline proposed a
decision on a new standard in June 2010. The Company believes it is highly unlikely this original time table will be met, based on the volume of comment letters received, varied responses and other factors currently affecting the IASB. 

The outcome of the ED is of particular importance to NSPI given the extent of regulatory assets and liabilities. If recognizing the economic impacts of
regulatory activities is not permitted under IFRS, the financial impact will be significant. It is possible that all its current regulatory assets and liabilities will be written off on transition to IFRS and on an on-going basis net earnings will
be subject to volatility. The uncertainty surrounding the timing and eventual adoption of a RRA standard by the IASB poses a significant challenge in the Company’s adoption of IFRS, but is being managed through our overall approach to the
project and the timing of project activities. 
 Given the significant impact the RRA ED could have on the Company’s financial reporting
and the continued uncertainty around the IASB’s adoption of a RRA standard and the timing of a decision, the Company is considering the option of adopting US GAAP for external financial reporting purposes as part of its contingency
planning. An update on the ED project is expected following the IASB’s scheduled meeting in February 2010. This update will be critical in determining the expected timing and direction of a final decision on the ED and the application of RRA
under IFRS. 
  

 67 

 Transition Activities 

The Company began its IFRS transition activities in 2008. KPMG were engaged in a technical advisory role and a four phased project approach was adopted to
manage a project of this scope and complexity. Currently, 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. 

Phase One: Preliminary Assessment — Completed 

Phase One involved a high-level assessment of the most significant differences between Canadian GAAP and IFRS to determine the areas most likely to impact
the Company. The assessment was completed in 2008 and was critical to establishing the initial project plan and resources required to carry out the activities of the subsequent project phases. Internal resources were dedicated to the project to
ensure its completion within the required timeline. This phase also included the development of the Project Charter, Governance Structure and the Project Management Office to support the subsequent phases. 

Phase Two: Detailed Assessment — Completed 

Phase Two involved further, more detailed assessment of Canadian GAAP – IFRS differences. All accounting and disclosure differences were analyzed to
determine if they resulted in a high/medium/low impact on net earnings, the balance sheet and financial statement disclosures. The level of difficulty to implement changes was also assessed. The areas with the highest potential to affect the Company
are regulatory assets and liabilities, PP&E, employee future benefits, hedge accounting, ARO and IFRS 1. IFRS 1 is the IFRS standard that sets out transitional requirements and exemptions available upon first time adoption of IFRS. 

An Information Technology (“IT”) initiatives assessment and system landscape review was performed as part of this phase, along with the
development of initial IFRS training and communication plans. The Detailed Assessment phase was completed in March 2009 and provided information required to create a more detailed project plan. 

Phase Three: Design — In Progress 
 Phase
Three began in Q2 of 2009 with the preparation of technical papers that further analyzed the differences between NSPI’s current accounting treatments and those required under IFRS to determine impacts on financial reporting processes, IT
systems, and disclosure and internal controls over financial reporting. Technical papers support approval of the Company’s new accounting policies under IFRS and while significant progress has been made on these papers, final decisions on those
accounting policy changes most likely to have a significant impact, cannot be finalized as a result of the uncertainty of the adoption of the IASB ED. The ED impacts the extent of accounting differences and choices available in these areas and as a
result, the specific financial impacts of such policy changes are not yet determinable. Implementation of accounting policies not impacted by the ED are not expected to result in material changes. 

Despite the lack of certainty regarding the IASB ED, detailed design activities have commenced for known financial reporting process and system changes.
This has involved the development of an “IT Solutions Strategy” and “January 2010 Readiness” activities and will ensure the achievement of critical project milestones. 

The IT Solutions Strategy was developed in Q3 and Q4 of 2009 and addressed the need for a “Transition Solution” and an “End State
Solution”. The Transition Solution supports the creation of comparative IFRS data for 2010 and the End State Solution supports post-2010 reporting under both IFRS and in accordance with regulatory requirements. The extent to which financial
statements prepared for the Company’s regulators and those prepared under IFRS will differ and cannot be determined until the outcome of the ED is known. Therefore, the Company has adopted a phased approach to the design, development, testing
and implementation of IT systems change. Phases or “releases” required to be implemented before the outcome of the ED is known will maintain the flexibility to report with or without a RRA standard. The first release of the Transition
Solution was designed in Q4 2009 and was implemented in 
  

 68 

 
January 2010. This supports the capture of transactional PP&E data throughout 2010 as required for IFRS reporting. The End State IT Solution requires upgrades and/or modifications to several
of NSPI’s financial reporting systems and software in 2010. 
 Finalization of technical papers, draft IFRS financial statements and design
activities will continue throughout 2010 until the outcome of the ED is known. 
 Phase Four: Implementation – In Progress 

Phase Four began in Q4 2009 and involves implementing changes to business and accounting processes across the organization, along with formal
documentation of all approved accounting policies and procedures in accordance with IFRS. The impact of accounting policy changes will be quantified in this phase and the opening IFRS balance sheet, as at January 1, 2010, will be prepared.

 IT solutions and system upgrades will be implemented in this phase. The first release of the Transition Solution was successfully implemented
in January 2010 and involved setting up the financial reporting system to capture PP&E data on the component basis required for IFRS. Activities to upgrade and modify IT systems started in Q4 2009 and will continue through 2010. 

In regards to January 2010 Readiness activities, the Company updated its hedge documentation prior to December 31, 2009 to ensure its existing
hedges qualified for the desired accounting treatment under IFRS. 
 Phase Four activities will continue throughout 2010 and into 2011 when the
Company goes live under IFRS. 
 Business Combinations 

In January 2009, the CICA issued Standard 1582 Business Combinations (“1582”) together with Standard 1601 Consolidated Financial Statements
(“1601”) and Standard 1602 Non-Controlling Interests (“1602”) applicable to NSPI’s 2011 fiscal year, replacing Standard 1581 Business Combinations and Standard 1600 Consolidated Financial Statements. 

Adoption of 1582 will change the measurement of non-controlling interest and goodwill for future acquisitions. Changes also include expensing
acquisition-related transaction costs rather than including the costs as part of the purchase price and the disallowing recognition of restructuring accruals by the acquirer. Standard 1582 will affect the recognition of business combinations
completed by the Company on or after January 2011. 
 Standard 1601 establishes standards for the preparation of consolidated financial
statements and Standard 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The adoption of 1601 and 1602 will result in non-controlling
interests being presented on the consolidated balance sheet as components of equity rather than as liabilities. Also, net earnings and components of other comprehensive income attributable to the owners of the parent and to the non-controlling
interests are required to be separately disclosed on the statement of earnings. The Company is currently assessing the effect of 1601 and 1602 on its financial statements but does not expect a material impact. 

 

 69 

 SUMMARY OF QUARTERLY RESULTS 

 
  

																									
	 For the quarter ended

millions of dollars
	  	 	  	 	  	 	  	 	  	 	  	 	  	 	  	 
	 	  	Q4	  	Q3	  	Q2	  	Q1	  	Q4	  	Q3	  	Q2	  	Q1
	 	  	2009	  	2009	  	2009	  	2009	  	2008	  	2008	  	2008	  	2008
	 Total revenues
	  	$	306.9	  	$	267.5	  	$	276.9	  	$	350.8	  	$	284.2	  	$	254.3	  	$	262.0	  	$	326.1
		  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 
	 Net earnings applicable to common shares
	  	 	17.4	  	 	16.6	  	 	22.8	  	 	52.5	  	 	14.4	  	 	2.3	  	 	31.0	  	 	57.9
		  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 

 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. 
  

 70Unaudited Interim Financial Statements and MD&A

 Exhibit 4.3 

Financial Statements 
 Nova Scotia
Power Inc. 
 Statements of Earnings (Unaudited) 
  

									
	 For the

millions of dollars
	  	Three months ended
March 31	 
	  	2010	 	 	2009	 
	 Revenue
	  				 			
	 Electric
	  	$	337.5	  	 	$	347.8	  
	 Other
	  	 	3.2	  	 	 	3.0	  
		  	 	 	 	 	 	 	 
		  	 	340.7	  	 	 	350.8	  
		  	 	 	 	 	 	 	 
	 Cost of operations
	  				 			
	 Fuel for generation and purchased power
	  	 	181.2	  	 	 	148.6	  
	 Fuel adjustment (note 4)
	  	 	(39.4	) 	 	 	(5.8	) 
	 Operating, maintenance and general
	  	 	53.2	  	 	 	51.2	  
	 Provincial grants and taxes
	  	 	10.0	  	 	 	10.1	  
	 Depreciation and amortization
	  	 	36.6	  	 	 	35.4	  
	 Regulatory amortization
	  	 	4.4	  	 	 	4.2	  
		  	 	 	 	 	 	 	 
		  	 	246.0	  	 	 	243.7	  
		  	 	 	 	 	 	 	 
	 Earnings before financing charges and income taxes
	  	 	94.7	  	 	 	107.1	  
	 Financing charges (note 5)
	  	 	32.3	  	 	 	35.6	  
		  	 	 	 	 	 	 	 
	 Earnings before income taxes
	  	 	62.4	  	 	 	71.5	  
	 Income taxes (note 6)
	  	 	(0.9	) 	 	 	19.0	  
		  	 	 	 	 	 	 	 
	 Net earnings applicable to common shares
	  	$	63.3	  	 	$	52.5	  
		  	 	 	 	 	 	 	 

 See accompanying notes to the unaudited financial statements. 

 

 1 

 Balance Sheets (Unaudited) 

 

									
	 As at

millions of dollars
	  	March 31
2010	 	 	December 31
2009	 
	 Assets
	  				 			
	 Current assets
	  				 			
	 Cash and cash equivalents
	  	$	0.3	  	 	$	0.3	  
	 Accounts receivable
	  	 	318.2	  	 	 	271.8	  
	 Income tax receivable
	  	 	11.4	  	 	 	—  	  
	 Inventory
	  	 	134.2	  	 	 	165.6	  
	 Prepaid expenses
	  	 	23.5	  	 	 	7.0	  
	 Future income tax assets
	  	 	14.7	  	 	 	34.4	  
	 Derivatives in a valid hedging relationship
	  	 	18.3	  	 	 	19.4	  
	 Held-for-trading derivatives
	  	 	3.3	  	 	 	8.9	  
		  	 	 	 	 	 	 	 
		  	 	523.9	  	 	 	507.4	  
		  	 	 	 	 	 	 	 
	 Derivatives in a valid hedging relationship
	  	 	18.2	  	 	 	29.8	  
	 Held-for-trading derivatives
	  	 	3.1	  	 	 	6.2	  
	 Other assets
	  	 	414.2	  	 	 	339.1	  
	 Intangibles
	  	 	67.8	  	 	 	65.7	  
	 Property, plant and equipment
	  	 	2,359.5	  	 	 	2,365.6	  
	 Construction work in progress
	  	 	174.8	  	 	 	152.8	  
		  	 	 	 	 	 	 	 
		  	 	2,534.3	  	 	 	2,518.4	  
		  	 	 	 	 	 	 	 
		  	$	3,561.5	  	 	$	3,466.6	  
		  	 	 	 	 	 	 	 
	 Liabilities and Shareholders’ Equity
	  				 			
	 Current liabilities
	  				 			
	 Current portion of long-term debt
	  	$	100.7	  	 	$	100.7	  
	 Short-term debt
	  	 	267.0	  	 	 	199.5	  
	 Accounts payable and accrued charges
	  	 	161.1	  	 	 	213.9	  
	 Due to associated companies (note 8)
	  	 	2.5	  	 	 	0.7	  
	 Income tax payable
	  	 	—  	  	 	 	1.2	  
	 Dividends payable
	  	 	1.7	  	 	 	1.7	  
	 Derivatives in a valid hedging relationship
	  	 	59.2	  	 	 	53.0	  
	 Held-for-trading derivatives
	  	 	20.0	  	 	 	12.2	  
		  	 	 	 	 	 	 	 
		  	 	612.2	  	 	 	582.9	  
		  	 	 	 	 	 	 	 
	 Derivatives in a valid hedging relationship
	  	 	23.2	  	 	 	20.0	  
	 Held-for-trading derivatives
	  	 	0.1	  	 	 	1.3	  
	 Future income tax liabilities
	  	 	86.3	  	 	 	52.0	  
	 Asset retirement obligations
	  	 	102.9	  	 	 	101.5	  
	 Other liabilities
	  	 	76.1	  	 	 	91.5	  
	 Long-term debt
	  	 	1,397.1	  	 	 	1,397.0	  
	 Preferred shares
	  	 	135.0	  	 	 	135.0	  
		  	 	 	 	 	 	 	 
	 Shareholders’ equity
	  				 			
	 Common shares
	  	 	934.7	  	 	 	934.7	  
	 Accumulated other comprehensive loss
	  	 	(64.1	) 	 	 	(44.0	) 
	 Retained earnings
	  	 	258.0	  	 	 	194.7	  
		  	 	 	 	 	 	 	 
		  	 	1,128.6	  	 	 	1,085.4	  
		  	 	 	 	 	 	 	 
		  	$	3,561.5	  	 	$	3,466.6	  
		  	 	 	 	 	 	 	 

 See accompanying notes to the unaudited financial statements. 

Approved on behalf of the Board of Directors 
  

			
	“George Caines”	 	“Robert R. Bennett”
	Chairman	 	President and Chief Executive Officer

  

 2 

 Statements of Cash Flow (Unaudited) 

 

									
	 For the

millions of dollars
	  	Three months ended
March 31	 
	  	2010	 	 	2009	 
	 Operating activities
	  				 			
	 Net earnings applicable to common shares
	  	$	63.3	  	 	$	52.5	  
	 Non-cash items:
	  				 			
	 Depreciation and amortization
	  	 	36.6	  	 	 	35.4	  
	 Amortization of other assets
	  	 	3.4	  	 	 	3.4	  
	 Regulatory amortization
	  	 	4.4	  	 	 	4.2	  
	 Allowance for funds used during construction
	  	 	(3.5	) 	 	 	(1.1	) 
	 Future income taxes
	  	 	10.4	  	 	 	1.9	  
	 Post-retirement benefits
	  	 	(1.5	) 	 	 	(1.8	) 
	 Fuel adjustment
	  	 	(39.4	) 	 	 	(5.8	) 
	 Changes in fair value of derivatives instruments
	  	 	(2.0	) 	 	 	21.2	  
	 Other non-cash operating items
	  	 	(0.1	) 	 	 	0.5	  
	 Other cash operating items
	  	 	2.2	  	 	 	(0.4	) 
		  	 	 	 	 	 	 	 
		  	 	73.8	  	 	 	110.0	  
	 Change in non-cash operating working capital (note 7)
	  	 	(91.1	) 	 	 	(91.3	) 
		  	 	 	 	 	 	 	 
	 Net cash (used in) provided by operating activities
	  	 	(17.3	) 	 	 	18.7	  
		  	 	 	 	 	 	 	 
	 Investing activities
	  				 			
	 Property, plant and equipment
	  	 	(46.0	) 	 	 	(27.2	) 
	 Intangibles
	  	 	(2.9	) 	 	 	(0.7	) 
	 Retirement spending net of salvage
	  	 	(1.1	) 	 	 	(0.6	) 
		  	 	 	 	 	 	 	 
	 Net cash used in investing activities
	  	 	(50.0	) 	 	 	(28.5	) 
		  	 	 	 	 	 	 	 
	 Financing activities
	  				 			
	 Increase (decrease) in short-term debt
	  	 	67.5	  	 	 	(40.2	) 
	 Issuance of long-term debt
	  	 	—  	  	 	 	50.0	  
	 Other financing activities
	  	 	(0.2	) 	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Net cash provided by financing activities
	  	 	67.3	  	 	 	9.8	  
		  	 	 	 	 	 	 	 
	 Change in cash and cash equivalents
	  	 	—  	  	 	 	—  	  
	 Cash and cash equivalents, beginning of period
	  	 	0.3	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Cash and cash equivalents, end of period
	  	$	0.3	  	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Supplemental disclosure of cash paid:
	  				 			
	 Interest
	  	$	27.1	  	 	$	18.2	  
	 Income and capital taxes
	  	$	0.7	  	 	$	8.1	  
		  	 	 	 	 	 	 	 

 See accompanying notes to the unaudited financial statements. 

 

 3 

 Statements of Changes in Shareholders’ Equity (Unaudited) 

 

															
	 For the three months ended March 31, 2010

millions of dollars
	  	Common
Shares	  	Accumulated Other
Comprehensive

(Loss) Income
(“AOCI”)	 	 	Retained
Earnings	  	Total
AOCI 
and
Retained
Earnings	 
	 Balance, December 31, 2009
	  	$	934.7	  	$	(44.0	) 	 	$	194.7	  	$	150.7	  
		  	 	 	  	 	 	 	 	 	 	  	 	 	 
	 Comprehensive income:
	  			  				 			  			
	 Net earnings applicable to common shares
	  	 	—  	  	 	—  	  	 	 	63.3	  	 	63.3	  
	 Net losses on derivatives in a valid hedging relationship
	  	 	—  	  	 	(37.9	) 	 	 	—  	  	 	(37.9	) 
	 Reclassification of hedging losses included in income
	  	 	—  	  	 	37.5	  	 	 	—  	  	 	37.5	  
	 Reclassification of hedging gains included in inventory
	  	 	—  	  	 	(19.7	) 	 	 	—  	  	 	(19.7	) 
		  	 	 	  	 	 	 	 	 	 	  	 	 	 
	 Total comprehensive (loss) income
	  	 	—  	  	 	(20.1	) 	 	 	63.3	  	 	43.2	  
		  	 	 	  	 	 	 	 	 	 	  	 	 	 
	 Balance, March 31, 2010
	  	$	934.7	  	$	(64.1	) 	 	$	258.0	  	$	193.9	  
		  	 	 	  	 	 	 	 	 	 	  	 	 	 

  

														
	 For the three months ended March 31, 2009

millions of dollars
	  	Common
Shares	  	AOCI	 	 	Retained
Earnings	  	Total
AOCI 
and
Retained
Earnings
	 Balance, December 31, 2008
	  	$	930.6	  	$	(0.6	) 	 	$	211.4	  	$	210.8
		  	 	 	  	 	 	 	 	 	 	  	 	 
	 Comprehensive income:
	  			  				 			  		
	 Net earnings applicable to common shares
	  	 	—  	  	 	—  	  	 	 	52.5	  	 	52.5
	 Net gain on derivatives in a valid hedging relationship
	  	 	—  	  	 	2.6	  	 	 	—  	  	 	2.6
	 Reclassification of hedging losses included in income
	  	 	—  	  	 	10.9	  	 	 	—  	  	 	10.9
	 Reclassification of hedging losses included in inventory
	  	 	—  	  	 	8.6	  	 	 	—  	  	 	8.6
		  	 	 	  	 	 	 	 	 	 	  	 	 
	 Total comprehensive income
	  	 	—  	  	 	22.1	  	 	 	52.5	  	 	74.6
		  	 	 	  	 	 	 	 	 	 	  	 	 
	 Balance, March 31, 2009
	  	$	930.6	  	$	21.5	  	 	$	263.9	  	$	285.4
		  	 	 	  	 	 	 	 	 	 	  	 	 

 See accompanying notes to the unaudited financial statements. 

  

 4 

 Notes to the Interim Unaudited Financial Statements 

March 31, 2010 
  

	1.	BASIS OF PRESENTATION 

The disclosures in these unaudited interim financial statements do not conform in all respects to the requirements of Canadian Generally
Accepted Accounting Principles for annual audited financial statements and should be read in conjunction with Nova Scotia Power Inc.’s annual financial statements as at and for the year ended December 31, 2009. 

“Company” and “NSPI” refer to Nova Scotia Power Inc. 

These financial statements follow the same accounting policies and methods of computation as Nova Scotia Power Inc.’s annual audited
financial statements as at and for the year ended December 31, 2009. 
  

	2.	SEASONAL NATURE OF OPERATIONS 

Interim results are not necessarily indicative of results for the full year due primarily to seasonal factors. Sales and related
production vary significantly over the year, with Q1 and Q4, the strongest periods, reflecting colder weather and fewer daylight hours in the winter season. 
  

	3.	EMPLOYEE FUTURE BENEFITS 

NSPI maintains contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees, and
plans that provide non-pension benefits for its retirees. The Company’s estimated total benefit cost, related to these plans, for the three months ended March 31, 2010 is $6.6 million (2009 – $3.9 million). 

 

	4.	FUEL ADJUSTMENT 

 The UARB
approved the implementation of a Fuel Adjustment Mechanism (“FAM”) in the 2009 General Rate Decision effective January 1, 2009. The FAM fuel adjustment 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”. Also included in the fuel adjustment is the rebate to customers of over recovered fuel costs from 2009. 

Details of the FAM components are summarized in the following table: 

 

									
	 	  	Three months ended	 
	 For the
	  	March 31	 
	 millions of dollars
	  	2010	 	 	2009	 
	 Under recovery of current period fuel costs
	  	$	(33.0	) 	 	$	(5.8	) 
	 Rebate of over recovered fuel costs from prior year
	  	 	(6.4	) 	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Fuel adjustment
	  	$	(39.4	) 	 	$	(5.8	) 
		  	 	 	 	 	 	 	 

 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 is recognized by NSPI as a regulatory asset as future rates will be adjusted to provide recovery from customers in the following year. As at March 31, 2010, NSPI’s FAM regulatory asset was
$29.8 million (December 31, 2009 – liability of $9.9 million), and future income tax liability was $9.6 million (December 31, 2009 – asset of $3.4 million). 

 

 5 

	5.	FINANCING CHARGES 

Financing charges consist of the following: 
  

									
	 	  	Three months ended	 
	 For the
	  	March 31	 
	 millions of dollars
	  	2010	 	 	2009	 
	 Interest – long-term debt
	  	$	25.6	  	 	$	24.2	  
	 – short-term debt
	  	 	2.5	  	 	 	0.5	  
	 Preferred share dividends
	  	 	2.0	  	 	 	3.5	  
	 Amortization of defeasance cost
	  	 	3.0	  	 	 	3.0	  
	 Amortization of debt financing costs
	  	 	0.4	  	 	 	0.5	  
	 Allowance for funds used during construction
	  	 	(3.5	) 	 	 	(1.1	) 
	 Foreign exchange losses
	  	 	2.3	  	 	 	5.0	  
		  	 	 	 	 	 	 	 
		  	$	32.3	  	 	$	35.6	  
		  	 	 	 	 	 	 	 

  

	6.	INCOME TAXES 

 Income
taxes are lower in Q1 2010 compared to Q1 2009 due to accelerated capital cost allowance tax deductions associated with investments in renewable energy projects in 2010. 

In addition, a $2.3 million future income tax recovery was recorded in Q1 2010 related to the timing of the tax deduction
of unregulated expenditures. 
  

	7.	CASH FLOW INFORMATION 

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

 

									
	 	  	Three months ended	 
	 For the
	  	March 31	 
	 millions of dollars
	  	2010	 	 	2009	 
	 Increase in accounts receivable and due from associated companies
	  	$	(24.6	) 	 	$	(30.8	) 
	 Increase in posted margin included in accounts receivable
	  	 	(19.1	) 	 	 	(11.9	) 
	 Increase in contract receivable
	  	 	(2.7	) 	 	 	(6.0	) 
	 Decrease (increase) in inventory
	  	 	31.4	  	 	 	(5.6	) 
	 Increase in prepaid expenses
	  	 	(16.5	) 	 	 	(16.5	) 
	 Decrease in accounts payable and accrued charges and due to associated companies
	  	 	(51.0	) 	 	 	(19.9	) 
	 Change in heavy fuel oil hedging balance in AOCI
	  	 	4.0	  	 	 	(11.0	) 
	 (Increase) decrease in income tax receivable
	  	 	(12.6	) 	 	 	10.4	  
		  	 	 	 	 	 	 	 
		  	$	(91.1	) 	 	$	(91.3	) 
		  	 	 	 	 	 	 	 

  

	8.	RELATED PARTY TRANSACTIONS 

The Company enters into various transactions with its affiliates in the normal course of operations. All transactions are recorded,
subject to terms in the Code of Conduct, at the exchange value, which is generally based on commercial rates or as agreed to by the parties. The Code of Conduct governs transactions between NSPI and its affiliates and is approved by the UARB.

 Due to associated companies represents the total carrying amounts of trade payables which are owed from NSPI to NSPI’s
parent company, Emera Inc., and companies wholly-owned by Emera Inc. The terms of repayment are the same as those for non-affiliate trade payables. 
  

 6 

 NSPI had sales and purchases from companies under common control of Emera Inc. as follows:

  

										
	 For the

millions of dollars
	  	 	  	Three months ended
March 
31
	 Affiliate
	  	 Purpose of transaction
	  	2010	 	 	2009
	 Sales:
	  		  				 		
	 Emera Energy Services
	  	Net (purchases) sales of gas, electricity, and swaps	  	$	(1.2	) 	 	$	17.7
	 Other
	  	Other services provided	  	 	1.9	  	 	 	1.5
				
	 Purchases:
	  	Various services purchased	  	$	4.4	  	 	$	2.6

 In the ordinary course
of business, the Company purchased natural gas transportation capacity totaling $4.4 million (2009 – $4.9 million) during the three months ended March 31, 2010 from the Maritimes & Northeast Pipeline, an investment under
significant influence of Emera Inc. The amount is recognized in “Fuel for generation and purchased power” and is measured at the exchange amount. As at March 31, 2010 and December 31, 2009, the amount payable to the related party
was $1.5 million and is under normal interest and credit terms. 
  

	9.	COMPARATIVE INFORMATION 

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

 

 7 

 Management’s Discussion & Analysis 

As at May 3, 2010 
 Management’s
Discussion and Analysis (“MD&A”) provides a review of the results of operations of Nova Scotia Power Inc. during the first quarter of 2010 relative to 2009, and its financial position at March 31, 2010 relative to
December 31, 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 Nova Scotia Power Inc. unaudited financial statements and supporting notes as at and
for the three month period ended March 31, 2010 and the Nova Scotia Power Inc. MD&A and annual audited financial statements and supporting notes as at and for the year ended December 31, 2009. Nova Scotia Power Inc. follows Canadian
Generally Accepted Accounting Principles (“CGAAP”), including the application of rate-regulated accounting. Nova Scotia Power Inc.’s accounting policies are subject to examination and approval by the Nova Scotia Utility and Review
Board (“UARB”). The rate-regulated accounting policies of Nova Scotia Power Inc. may differ from CGAAP for non-regulated companies. 

Throughout this discussion, “Nova Scotia Power”, “NSPI” and “Company” refer to Nova Scotia Power Inc. 

All amounts are in Canadian dollars (“CAD”). Additional information related to NSPI, 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 NSPI 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. Should one or more of these risks or
uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary significantly from those expected. NSPI 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. 

Structure of MD&A 
 This MD&A
begins with an introduction and strategic overview, followed by a financial review of the statements of earnings, balance sheets and cash flow highlights; then continues with a discussion on outlook, liquidity and capital resources, transactions
with related parties, financial risk and financial instruments, changes in accounting policies and summary of quarterly results. 
  

 8 

 INTRODUCTION AND STRATEGIC OVERVIEW 

NSPI, created following 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 with $3.6 billion of assets and provides electricity generation, transmission and distribution services to approximately 487,000 customers in the province. The Company is regulated by the UARB
under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers, and provides an opportunity to earn a prescribed return on equity (“ROE”). NSPI’s regulated ROE range
prescribed for 2010 is 9.1% to 9.6%, on an actual common equity component of up to 40% of average regulated capitalization. 
 Developments

 Nova Scotia Renewable Electricity Plan 

On April 23, 2010, a Renewable Electricity Plan was released by the government of Nova Scotia. This Plan does not change legislation relating to
existing renewable energy targets and reaffirms the government’s intention to have 25% of electricity generated from renewable resources by 2015. The Plan also outlines the roles of NSPI and the UARB in achieving the goals of the Plan.

 Digby Wind Project 
 On
April 16, 2010, NSPI filed with the UARB its intention to acquire the Digby Wind Project from another subsidiary of Emera. NSPI will later seek UARB approval of this project through the submission of a capital work order. On
April 23, 2010, the UARB replied it had no objections to NSPI proceeding on this basis. The project is expected to be completed by December 31, 2010 at a total cost of approximately $80 million. 

Port Hawkesbury Biomass Project 
 On
April 5, 2010, NSPI announced an agreement with NewPage Port Hawkesbury Corporation (“NewPage”) to develop a 60 megawatt (“MW”) biomass co-generating facility that is expected to supply approximately 3% of the
province’s total electricity needs. NSPI intends to invest approximately $200 million. NewPage will construct and operate the co-generation facility, and supply the fuel. The project, subject to regulatory approval from the UARB, is targeted to
be in-service, if approved, in late 2012. 
 Appointments 

On May 3, 2010, Elaine Sibson and Lee Bragg joined the NSPI Board of Directors. 

 

 9 

 Review of 2010 

NSPI Q1 Net Earnings 
  

									
	 millions of dollars
	  	Three months ended
March 
31	 
	  	2010	 	 	2009	 
	 Electric revenue
	  	$	337.5	  	 	$	347.8	  
		  	 	 	 	 	 	 	 
	 Fuel for generation and purchased power
	  	 	181.2	  	 	 	148.6	  
	 Fuel adjustment
	  	 	(39.4	) 	 	 	(5.8	) 
	 Operating, maintenance and general
	  	 	53.2	  	 	 	51.2	  
	 Provincial grants and taxes
	  	 	10.0	  	 	 	10.1	  
	 Depreciation and amortization
	  	 	36.6	  	 	 	35.4	  
	 Regulatory amortization
	  	 	4.4	  	 	 	4.2	  
	 Other revenue
	  	 	(3.2	) 	 	 	(3.0	) 
		  	 	 	 	 	 	 	 
	 Earnings before financing charges and income taxes
	  	 	94.7	  	 	 	107.1	  
	 Financing charges
	  	 	32.3	  	 	 	35.6	  
		  	 	 	 	 	 	 	 
	 Earnings before income taxes
	  	 	62.4	  	 	 	71.5	  
	 Income taxes
	  	 	(0.9	) 	 	 	19.0	  
		  	 	 	 	 	 	 	 
	 Net earnings
	  	$	63.3	  	 	$	52.5	  
		  	 	 	 	 	 	 	 

 NSPI’s net earnings increased $10.8 million to $63.3 million in Q1 2010 compared to $52.5 million in Q1 2009.
Highlights of the earnings changes are summarized in the following table: 
  

					
	 millions of dollars
	  	Three months ended
March 
31	 
	 Net earnings – 2009
	  	$	52.5	  
		  	 	 	 
	 Decreased electric margin
	  	 	(7.3	) 
	 Increased operating, maintenance and general expenses due primarily to higher pension costs
	  	 	(2.0	) 
	 Decreased net financing charges (see note below)
	  	 	1.3	  
	 Increased depreciation and amortization
	  	 	(1.2	) 
	 Decreased income taxes due to tax deductions related to renewable investments
	  	 	19.9	  
	 Other
	  	 	0.1	  
		  	 	 	 
	 Net earnings – 2010
	  	$	63.3	  
		  	 	 	 

 Net financing charges exclude foreign exchange gains and losses recovered as fuel costs through the Fuel Adjustment
Mechanism (“FAM”). 
  

 10 

 Balance Sheets Highlights 

Significant changes in the balance sheets between March 31, 2010 and December 31, 2009 include: 

 

							
	 millions of dollars
	  	Increase
(Decrease)	 	 	 Explanation

	 Assets
	  				 	
	 Accounts receivable
	  	$	46.4	  	 	Increase due to seasonal trends of business and higher posted margin to counterparties.
	 Income tax receivable
	  	 	12.6	  	 	Recovery of taxes due to tax deductions related to renewable investments.
	 Inventory
	  	 	(31.4	) 	 	Decreased solid fuel inventory levels.
	 Prepaid expenses
	  	 	16.5	  	 	Timing of provincial grants in lieu of taxes, insurance and other payments.
	 Derivatives in a valid hedging relationship (including long-term portion)
	  	 	(12.7	) 	 	Unfavourable USD price positions and new hedges. The effective portion of the change is recognized in “Accumulated other comprehensive loss”.
	 Other assets
	  	 	75.1	  	 	Recognition of the FAM regulatory asset in 2010, increased regulatory asset related to financial instruments, and an increase in the regulatory future income tax
(“FIT”) asset.
	 Future income tax assets
	  	 	(19.7	) 	 	Reclassification of FIT assets related to non-capital losses into FIT liabilities, and changes on items recognized in “Accumulated other comprehensive
loss”.
	 Construction work in progress
	  	 	22.0	  	 	Capital spending.
		  	 	 	 	 	
	 Liabilities and Shareholders’ Equity
	  				 	
	 Short-term debt
	  	 	67.5	  	 	Increased cash flow requirements.
	 Accounts payable and accrued charges
	  	 	(52.8	) 	 	Timing of payments.
	 Future income tax liabilities
	  	 	34.3	  	 	Increased FIT on items recognized in “Accumulated other comprehensive loss” and fixed asset balances, including wind projects. The portion expected to be recovered from
customers in future rates is recognized in “Other assets”.
	 Other liabilities
	  	 	(15.4	) 	 	Decreased regulatory liability related to financial instruments and decrease in the FAM liability to customers.
	 Accumulated other comprehensive loss
	  	 	(20.1	) 	 	Primarily represents effective portion of unfavorable USD hedge positions.
	 Retained earnings
	  	 	63.3	  	 	Net earnings.
		  	 	 	 	 	

 Cash Flow Highlights 

Significant changes in the cash flow statements between March 31, 2010 and 2009 include: 

 

										
	 Three months ended March 31
	 	 	 
	 millions of dollars
	  	2010	 	 	2009	 	 	 Explanation

	 Cash and cash equivalents, beginning of period
	  	$	0.3	  	 	—  	  	 	
	 (Used in) provided by:
	  				 			 	
				
	 Operating activities
	  	 	(17.3	) 	 	18.7	  	 	In 2010, non-cash working capital partially offset by cash earnings.
		  				 			 	In 2009, cash earnings partially offset by non-cash working capital.
				
	 Investing activities
	  	 	(50.0	) 	 	(28.5	) 	 	In 2010, capital spending including additions associated with multi-year projects and renewable investments.
		  				 			 	In 2009, capital spending.
				
	 Financing activities
	  	 	67.3	  	 	9.8	  	 	In 2010 and 2009, increased debt levels.
		  	 	 	 	 	 	 	 	
	 Cash and cash equivalents, end of period
	  	$	0.3	  	 	—  	  	 	
		  	 	 	 	 	 	 	 	

  

 11 

 Electric Margin 

The UARB approved the implementation of a FAM in the 2009 General Rate Decision effective January 1, 2009. The implementation of the FAM reduces
NSPI’s earnings volatility associated with fuel costs as differences in actual fuel costs and amounts recovered from customers through electricity rates are deferred to “Fuel adjustment” and recovered or returned in the subsequent
period. Foreign exchange gains and losses associated with fuel as reported in “Financing charges” are also recovered as fuel costs through the FAM and included in “Fuel adjustment”. The fuel cost element of NSPI’s electric
margin is also influenced by 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 fuel cost to a maximum of $5 million.

 The Company’s electric margin is influenced by load changes and the associated mix of sales volume with the highest revenue contribution
from residential customers. NSPI’s electric margin is summarized in the following table: 
  

									
	 Q1 Electric Margin

millions of dollars
	  	Three months ended
March 31
	 
	  	2010	 	 	2009	 
	 Electric revenue
	  	$	337.5	  	 	$	347.8	  
	 Fuel for generation and purchased power
	  	 	(181.2	) 	 	 	(148.6	) 
	 Fuel adjustment
	  	 	39.4	  	 	 	5.8	  
	 Fuel related foreign exchange losses
	  	 	(2.8	) 	 	 	(4.8	) 
		  	 	 	 	 	 	 	 
	 Electric margin
	  	$	192.9	  	 	$	200.2	  
		  	 	 	 	 	 	 	 

 NSPI’s electric margin decreased $7.3 million to $192.9 million in Q1 2010 compared to $200.2 million in Q1 2009 due to
a reduction in residential sales resulting from warmer weather and the recognition of an expense related to the FAM incentive compared with a recovery in Q1 2009. 

Electric Revenue 
  

										
	 Q1 Electric Sales Volumes

Gigawatt hours (“GWh”)
	  	2010	  	2009	  	2008
	  	  	  
	 Residential
	  	 	1,390	  	 	1,432	  	 	1,398
	 Commercial
	  	 	849	  	 	877	  	 	865
	 Industrial
	  	 	965	  	 	839	  	 	1,049
	 Other
	  	 	86	  	 	98	  	 	88
		  	 	 	  	 	 	  	 	 
	 Total
	  	 	3,290	  	 	3,246	  	 	3,400
		  	 	 	  	 	 	  	 	 
				
	 Q1 Electric Revenues

millions of dollars
	  	2010	  	2009	  	2008
	  	  	  
	 Residential
	  	$	172.3	  	$	179.2	  	$	160.8
	 Commercial
	  	 	88.4	  	 	93.1	  	 	83.8
	 Industrial
	  	 	66.2	  	 	63.9	  	 	68.1
	 Other
	  	 	10.6	  	 	11.6	  	 	10.3
		  	 	 	  	 	 	  	 	 
	 Total
	  	$	337.5	  	$	347.8	  	$	323.0
		  	 	 	  	 	 	  	 	 
				
	 Q1 Average Electric Revenue /

Megawatt hour (“MWh”)
	  	2010	  	2009	  	2008
	 Dollars per MWh
	  	$	103	  	$	107	  	$	95
		  	 	 	  	 	 	  	 	 

 The change in average electric revenue per MWh in 2010 compared to
2009 reflects the FAM rebate from over-recovered fuel costs in 2009 as well as the change in sales mix. 
  

 12 

 Electric revenue decreased $10.3 million to $337.5 million in Q1 2010 compared to $347.8 million in Q1 2009.
Highlights of the changes are summarized in the following table: 
  

					
	 millions of dollars
	  	Three months ended
March 
31	 
	 Electric revenue – 2009
	  	$	347.8	  
		  	 	 	 
	 Decreased electricity pricing effective January 1, 2010 related to the FAM rebate to customers of over-recovered 2009 fuel
costs
	  	 	(6.5	) 
	 Net change in residential and commercial sales volumes
	  	 	(7.5	) 
	 Increased industrial sales volume from several large industrial customers
	  	 	4.2	  
	 Decreased export sales
	  	 	(0.5	) 
		  	 	 	 
	 Electric revenue – 2010
	  	$	337.5	  
		  	 	 	 

 Fuel for Generation and Purchased Power 

 

							
	 Q1 Production Volumes

GWh
	  	2010	  	2009	  	2008
	  	  	  
	 Coal & petcoke
	  	2,299	  	2,377	  	2,461
	 Natural gas
	  	650	  	304	  	434
	 Oil
	  	6	  	262	  	71
	 Renewable
	  	286	  	313	  	370
	 Purchased power
	  	221	  	205	  	277
		  	 	  	 	  	 
	 Total
	  	3,462	  	3,461	  	3,613
		  	 	  	 	  	 
		
	 Purchased power includes 73 GWh of renewables in Q1 2010 (2009 – 42 GWh; 2008 – 48 GWh).
	  	

 Q1 Average Unit Fuel Costs 

 

										
	 	  	2010	  	2009	  	2008
	 Dollars per MWh
	  	$	52	  	$	43	  	$	31
		  	 	 	  	 	 	  	 	 

 Fuel for generation and purchased power increased $32.6 million to
$181.2 million in Q1 2010 compared to $148.6 million in Q1 2009. Highlights of the changes are summarized in the following table: 
  

					
	 millions of dollars
	  	Three months ended
March 
31	 
	 Fuel for generation and purchased power – 2009
	  	$	148.6	  
		  	 	 	 
	 Commodity price increases
	  	 	27.5	  
	 Solid fuel commodity mix and additives related to emission compliance
	  	 	10.6	  
	 Increased proceeds on resale of natural gas
	  	 	(1.7	) 
	 Valuation of contract receivable (See discussion below)
	  	 	(1.6	) 
	 Decreased hydro production
	  	 	1.4	  
	 Mark-to-market on natural gas hedges recognized in 2009 as they were no longer required due to decreased 2009 production volumes

	  	 	(12.7	) 
	 Changes in generation mix and plant performance
	  	 	8.5	  
	 Other
	  	 	0.6	  
		  	 	 	 
	 Fuel for generation and purchased power – 2010
	  	$	181.2	  
		  	 	 	 

 The valuation of the contract receivable from a natural gas supplier requires 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. 

Fuel Adjustment 
 The FAM fuel adjustment
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”. Also included in the fuel adjustment is the rebate to customers of over recovered fuel costs from 2009. 

 

 13 

 Details of the FAM components are summarized in the following table: 

 

									
	  	  	Three months ended
March 31	 
	 millions of dollars
	  	2010	 	 	2009	 
	 Under recovery of current period fuel costs
	  	$	(33.0	) 	 	$	(5.8	) 
	 Rebate of over recovered fuel costs from prior year
	  	 	(6.4	) 	 	 	—  	  
		  	 	 	 	 	 	 	 
	 Fuel adjustment
	  	$	(39.4	) 	 	$	(5.8	) 
		  	 	 	 	 	 	 	 

 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 is recognized by NSPI as a regulatory asset as future rates will be adjusted to provide recovery from customers in the following year. The FAM regulatory asset includes amounts recognized as a fuel adjustment and
associated interest carrying costs included in “Financing charges”. As at March 31, 2010, NSPI’s FAM regulatory asset was $29.8 million (December 31, 2009 – liability of $9.9 million), and future income tax liability was
$9.6 million (December 31, 2009 – asset of $3.4 million). 
 Income taxes 

Income taxes are lower in Q1 2010 compared to Q1 2009 due to accelerated capital cost allowance tax deductions associated with investments in renewable
energy projects in 2010. 
 OUTLOOK 

Business Environment 
 Economic
Environment 
 The global economy is recovering after a significant downturn in 2008 and 2009. The Bank of Canada is predicting growth
of over 3% in Canada in 2010 due largely to stronger construction and resource sectors. NSPI foresees investment opportunity due to the transformation of the energy industry from higher emissions to lower emissions and has embarked on a
capital plan to increase the Company’s generation from renewable sources, to improve the transmission connections within our service territory, and to expand access to natural gas as we transition to a cleaner, greener company. 

Environmental Legislation 
 In August
2009, the province of Nova Scotia enacted limits on greenhouse gas emissions. Caps have been set for years 2010 and 2020 inclusive. The Company has stabilized and reduced emissions; continues to add cleaner, greener sources of
electricity; and works with customers to manage energy usage. The Company will continue to reduce green house gas emissions and comply with these regulations.

The Canadian federal government has not formalized any greenhouse gas emission reduction regulations and has now signaled alignment with the United
States’ approach, which is tending towards cap and trade beginning in the 2012 – 2014 timeframe. The company continues to provide input to the Canadian federal government through their consultations. 

 

 14 

 Operations 

NSPI anticipates earning a regulated ROE within its allowed range in 2010. 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 in excess of $600 million in 2010. The Company expects to finance its capital expenditures with funds from operations and debt. 

LIQUIDITY AND CAPITAL RESOURCES 
 The
Company generates cash mainly through its operations involving the generation, transmission and distribution of electricity. NSPI’s customer base is 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 our markets, the loss of one or more large customers, and regulatory decisions affecting customer rates. 

In addition to internally generated funds, NSPI has access to $500 million committed syndicated revolving bank line of credit. NSPI has an active
commercial paper program for up to $400 million, of which outstanding amounts are 100% backed by the Company’s bank lines referred to above and this results in an equal amount of credit being considered drawn and unavailable. 

NSPI’s revolving bank lines have a maturity date in June 2010, which can be extended annually for an additional 364 days with the approval of the
syndicated banks. At each maturity date, NSPI has the option to convert all amounts drawn on the bank credit line to a one year non-revolving term credit. 

NSPI intends to file a $500 million debt shelf prospectus in the first half of 2010. 

NSPI has established the following available credit facilities: 
  

												
	 As at March 31, 2010

millions of dollars
	  	Maturity	  	Maximum
amount	  	Utilized	  	Undrawn and
available
	 Operating credit facility
	  	1 Year Revolver	  	$	500	  	$	281	  	$	219

 NSPI issues commercial paper, 100%
backed by the syndicated bank line of credit, to finance short-term cash requirements and had access to the commercial paper market as required throughout Q1 2010. 

NSPI has debt covenants associated with its credit facilities. These covenants are tested regularly, and the Company is in compliance with the covenant
requirements. 
 TRANSACTIONS WITH RELATED PARTIES 

The Company enters into various transactions with its affiliates in the normal course of operations. All transactions are recorded, subject to terms in
the Code of Conduct, at the exchange value, which is generally based on commercial rates or as agreed to by the parties. The Code of Conduct governs transactions between NSPI and its affiliates and is approved by the UARB. 

Due to associated companies represents the total carrying amounts of trade payables, which are owed from NSPI to NSPI’ parent company, Emera Inc.,
and companies wholly-owned by Emera Inc. The terms of repayment are the same as those for non-affiliate trade payables. 
  

 15 

 NSPI had sales and purchases from companies under common control of Emera Inc. as follows: 

 

										
	 millions of dollars
	  	 	  	Three months ended
March 
31
	 Affiliate
	  	 Purpose of transaction
	  	2010	 	 	2009
	 Sales:
	  		  				 		
	 Emera Energy Services
	  	Net (purchases) sales of gas, electricity, and swaps	  	$	(1.2	) 	 	$	17.7
	 Other
	  	Other services provided	  	 	1.9	  	 	 	1.5
	 Purchases:
	  	Various services purchased	  	$	4.4	  	 	$	2.6

 In the ordinary course of business, the
Company purchased natural gas transportation capacity totaling $4.4 million (2009 – $4.9 million) during the three months ended March 31, 2010 from the Maritimes & Northeast Pipeline, an investment under significant influence of
Emera Inc. The amount is recognized in “Fuel for generation and purchased power” and is measured at the exchange amount. As at March 31, 2010 and December 31, 2009, the amount payable to the related party is $1.5 million and is
under normal interest and credit terms. 
 FINANCIAL RISK AND FINANCIAL INSTRUMENTS 

NSPI manages its exposure to foreign exchange, interest rate, and commodity price risks in accordance with established risk management policies and
procedures. The Company uses financial instruments consisting mainly of foreign exchange forward contracts, interest rate options and swaps, 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 instrument qualify for hedge accounting. Specifically, for cash flow hedges, the effective portion of the change in the fair value of derivatives is deferred to “Other comprehensive loss” and
recognized in earnings in the same period 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. 

For fair value hedges, the change in fair value of the hedging derivative 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. 
 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. 

The Company’s HFT derivatives are recorded on the balance sheet at fair value, with changes normally recorded in net earnings of the period, unless
deferred as a result of regulatory accounting. The company has not designated any derivatives to be included in the HFT category. 
  

 16 

 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
	  	March 31
2010	 	 	December 31
2009	 
	 Inventory
	  	$	2.5	  	 	$	22.2	  
	 Derivatives in a valid hedging relationship
	  	 	(45.9	) 	 	 	(23.8	) 
	 Long-term debt
	  	 	—  	  	 	 	0.1	  
		  	 	 	 	 	 	 	 
		  	$	(43.4	) 	 	$	(1.5	) 
		  	 	 	 	 	 	 	 

 Hedging Impact Recognized in Earnings 

The Company recognized in net earnings the following gains and losses related to effective portion of hedging relationships under the following
categories: 
  

									
	 millions of dollars
	  	Three months ended
March 31	 
	  	2010	 	 	2009	 
	 Fuel and purchased power (increase) decrease
	  	$	(37.3	) 	 	$	19.8	  
	 Financing charges decrease (increase)
	  	 	1.2	  	 	 	(1.4	) 
		  	 	 	 	 	 	 	 
	 Effectiveness (losses) gains
	  	$	(36.1	) 	 	$	18.4	  
		  	 	 	 	 	 	 	 

 The effectiveness gains and losses reflected in the above table would be offset in net earnings by the change in the hedged
item realized in the period. 
 The Company recognized in net earnings the following gains and losses related to the ineffective portion of
hedging relationships under the following categories: 
  

									
	 millions of dollars
	  	Three months ended
March 31	 
	  	2010	 	 	2009	 
	 Fuel and purchased power decrease (increase)
	  	$	0.2	  	 	$	(12.5	) 
	 Financing charges increase
	  	 	(0.2	) 	 	 	(0.5	) 
		  	 	 	 	 	 	 	 
	 Ineffectiveness losses
	  	 	—  	  	 	$	(13.0	) 
		  	 	 	 	 	 	 	 

 Held-for-trading Items Recognized on the Balance Sheet 

The Company has recognized a net unrealized fair value of HFT derivatives liability of $13.7 million as at March 31, 2010 (December 31, 2009 –
asset of $1.6 million) on the balance sheet. 
 Held-for-trading Derivatives Recognized in Earnings 

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

 

							
	 millions of dollars
	  	Three months ended
March 31	 
	  	2010	  	2009	 
	 Financing charges increase
	  	—  	  	$	(0.1	) 
		  	 	  	 	 	 
	 Held-for-trading derivatives losses
	  	—  	  	$	(0.1	) 
		  	 	  	 	 	 

  

 17 

 CHANGES IN ACCOUNTING POLICIES 

Future Accounting Policy Changes 

Changeover to United States Generally Accepted Accounting Principles (“US GAAP”) 

In February 2008, the CICA announced Canadian GAAP 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 of Emera, NSPI’s parent company, began reviewing the option of adopting US GAAP instead of IFRS.
Emera’s Board of Directors approved the transition to US GAAP financial reporting standards in 2011. 
 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. The Company plans to file registration statements with the US Securities and Exchange
Commission (“SEC”) prior to releasing its Q1 2011 financial results and thereby become subject to US reporting obligations. Registration with the SEC will enhance the Company’s ability to access US capital markets in the future.

 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 Canadian GAAP, making them
easier for readers to understand. 
 The Company’s application of Canadian GAAP currently relies on US GAAP for guidance on the
application of RRA. RRA allows the economic impact of regulatory activities to be recognized. 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. Without a RRA standard, a transition to IFRS would result in the accounting write-off of the Company’s significant regulatory assets and liabilities and net earnings would be subject to volatility on an
on-going basis. 
 The Company expects to report its financial results in US GAAP commencing in 2011. US GAAP will be applied
retrospectively, with restatement of prior periods. A formal project has been established to transition to US GAAP for 2011, register securities of NSPI with the SEC prior to releasing its Q1 2011 financial results, and prepare the Company to
comply with the on-going reporting requirements of the SEC and requirements of the Sarbanes-Oxley Act. KPMG was engaged to assist in the Company’s changeover to IFRS and will continue in this advisory role through the changeover to US GAAP. The
Company is in the process of determining the impact of US GAAP on its accounting policies, financial statements, information systems, internal controls and other business activities. The impact on information systems is expected to be minimal.

 SUMMARY OF QUARTERLY RESULTS 
  

																									
	 For the quarter ended

millions of dollars
	  	Q1
2010	  	Q4
2009	  	Q3
2009	  	Q2
2009	  	Q1
2009	  	Q4
2008	  	Q3
2008	  	Q2
2008
	 Total revenues
	  	$	340.7	  	$	306.9	  	$	267.5	  	$	276.9	  	$	350.8	  	$	284.2	  	$	254.3	  	$	262.0
		  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 
	 Net earnings applicable to common shares
	  	 	63.3	  	 	17.4	  	 	16.6	  	 	22.8	  	 	52.5	  	 	14.4	  	 	2.3	  	 	31.0
		  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 

 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. 
  

 18

Source: [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00175-of-00352.parquet"}, [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00175-of-00352.parquet"}]]