Nova Scotia Power F-9 Registration of securities of certain investment grade debt of preferred securities of certain Canadian issuers

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

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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.

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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 thePublic 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.

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• 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.

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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.

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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.

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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.

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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.

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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

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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	)

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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.

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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”.

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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.

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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.

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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

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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.

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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).

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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.

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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).

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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

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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

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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.

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	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.

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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

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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

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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

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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.

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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.

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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	%

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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.

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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.

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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.

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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

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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.

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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 atwww.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.

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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 thePublic 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.

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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.

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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

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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

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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.

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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			—

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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.

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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%

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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).

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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%

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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.

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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

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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.

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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.

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