Nova Scotia Power 6-K Management’s Responsibility for Financial Reporting

Exhibit 99.1

NOVA SCOTIA POWER INC.

Financial Statements

December 31, 2010 and 2009

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 9, 2011

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

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INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Nova Scotia Power Inc.

We have audited the accompanying financial statements of Nova Scotia Power Inc., which comprise the balance sheets as at December 31, 2010 and 2009, the statements of earnings, changes in shareholders’ equity and cash flows for the years then ended, and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements present fairly, in all material respects, the financial position of Nova Scotia Power Inc. as at December 31, 2010 and 2009, and its results of operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

Halifax, Canada

February 9, 2011

“Grant Thornton LLP”

Chartered Accountants

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Nova Scotia Power Inc.

Statements of Earnings

Year Ended December 31

millions of dollars	2010			2009
Revenue
Electric	$	1,167.3		$	1,188.1
Other		15.4			14.0
		1,182.7			1,202.1
Cost of operations
Fuel for generation and purchased power (note 22)		586.7			500.7
Fuel adjustment (note 4)		(99.0	)		8.5
Operating, maintenance and general (note 22)		237.5			215.1
Provincial grants and taxes		40.1			40.5
Depreciation and amortization		150.8			143.9
Regulatory amortization		36.9			27.2
		953.0			935.9
Earnings before financing charges and income taxes		229.7			266.2
Financing charges (note 6)		125.8			114.7
Earnings before income taxes		103.9			151.5
Income taxes (note 7)		(17.4	)		42.2
Net earnings applicable to common shares	$	121.3		$	109.3

See accompanying notes to the financial statements.

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Nova Scotia Power Inc.

Balance Sheets

As at December 31

millions of dollars	2010		2009
Assets
Current assets
Cash	$	0.3	$	0.3
Accounts receivable (note 8)		192.5		271.8
Income tax receivable		40.6		—
Inventory (note 9)		154.2		165.6
Prepaid expenses		6.1		5.7
Future income tax assets (note 7)		4.1		34.4
Derivatives in a valid hedging relationship		24.7		19.4
Held-for-trading derivatives		6.3		8.9
		428.8		506.1
Derivatives in a valid hedging relationship		20.8		29.8
Held-for-trading derivatives		8.2		6.2
Other assets (note 10)		512.8		339.1
Intangibles (note 11)		72.5		65.7
Property, plant and equipment (note 12)		2,669.0		2,365.6
Construction work in progress		279.2		152.8
		2,948.2		2,518.4
	$	3,991.3	$	3,465.3
Liabilities and Shareholders’ Equity
Current liabilities
Current portion of long-term debt (note 16)	$	0.1	$	100.7
Short-term debt (note 15)		48.3		198.2
Accounts payable and accrued charges		221.3		213.9
Due to associated companies (note 22)		5.1		0.7
Income tax payable		—		1.2
Dividends payable		1.7		1.7
Derivatives in a valid hedging relationship		2.2		53.0
Held-for-trading derivatives		20.8		12.2
		299.5		581.6
Derivatives in a valid hedging relationship		9.4		20.0
Held-for-trading derivatives		1.8		1.3
Future income tax liabilities (notes 4, 7)		163.1		52.0
Asset retirement obligations (note 14)		138.7		101.5
Other liabilities (note 10)		98.6		91.5
Long-term debt (note 16)		1,933.7		1,397.0
Preferred shares (note 17)		135.0		135.0
Shareholders’ equity
Common shares (note 18)		984.7		934.7
Accumulated other comprehensive income (loss)		10.8		(44.0	)
Retained earnings		216.0		194.7
		1,211.5		1,085.4
	$	3,991.3	$	3,465.3

Change in accounting estimate (note 2), Contingencies (note 23), Commitments (notes 5, 21 and 24), Guarantees (note 25)

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	2010			2009
Operating activities
Net earnings applicable to common shares	$	121.3		$	109.3
Non-cash items:
Depreciation and amortization		150.8			143.9
Amortization of other assets		14.8			14.8
Regulatory amortization		36.9			27.2
Allowance for funds used during construction		(17.1	)		(7.8	)
Interest (recovery) expense on deferral of FAM		(3.8	)		1.4
Future income taxes (note 7)		29.7			(3.4	)
Post-retirement benefits		(14.0	)		(17.3	)
Fuel adjustment (note 4)		(99.0	)		8.5
Changes in fair value of derivative instruments		15.5			(8.3	)
Other non-cash operating items		1.5			0.5
Other cash operating items		0.2			(6.1	)
		236.8			262.7
Change in non-cash operating working capital (note 19)		63.4			12.5
Net cash provided by operating activities		300.2			275.2
Investing activities
Property, plant and equipment		(517.7	)		(253.6	)
Intangibles		(10.0	)		(10.1	)
Retirement spending net of salvage		(5.6	)		(4.9	)
Net cash used in investing activities		(533.3	)		(268.6	)
Financing activities
Retirements of long-term debt		(100.0	)		(125.0	)
Issuance of long-term debt		300.0			250.0
Increase in short-term debt		90.4			123.8
Issuance of common shares		50.0			—
Redemption of preferred shares		—			(125.0	)
Dividends on common shares		(100.0	)		(126.0	)
Other financing activities		(7.3	)		(4.1	)
Net cash provided by (used in) financing activities		233.1			(6.3	)
Increase in cash		—			0.3
Cash, beginning of year		0.3			—
Cash, end of year	$	0.3		$	0.3
Supplemental disclosure of cash paid (recovered):
Interest	$	115.5		$	96.4
Income and capital taxes	$	(4.4	)	$	37.3

See accompanying notes to the financial statements.

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Nova Scotia Power Inc.

Statements of Changes in Shareholders’ Equity

For the year ended December 31, 2010 millions of dollars	Common Shares		Accumulated  Other Comprehensive Income (Loss) (“AOCI”)			Retained Earnings			Total  AOCI and Retained Earnings
Balance, December 31, 2009	$	934.7	$	(44.0	)	$	194.7		$	150.7
Comprehensive income:
Net earnings applicable to common shares		—		—			121.3			121.3
Net gain on derivatives in a valid hedging relationship		—		9.4			—			9.4
Reclassification of hedging losses included in income		—		62.9			—			62.9
Reclassification of hedging gains included in inventory		—		(17.5	)		—			(17.5	)
Total comprehensive income		—		54.8			121.3			176.1
Issuance of common shares (note 18)		50.0		—			—			—
Dividends declared on common shares		—		—			(100.0	)		(100.0	)
Balance, December 31, 2010	$	984.7	$	10.8		$	216.0		$	226.8
For the year ended December 31, 2009 millions of dollars	Common Shares		AOCI			Retained Earnings			Total  AOCI and Retained Earnings
Balance, December 31, 2008	$	930.6	$	(0.6	)	$	211.4		$	210.8
Comprehensive income:
Net earnings applicable to common shares		—		—			109.3			109.3
Net loss 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 18)		4.1		—			—			—
Dividends declared on common shares		—		—			(126.0	)		(126.0	)
Balance, December 31, 2009	$	934.7	$	(44.0	)	$	194.7		$	150.7

See accompanying notes to the financial statements.

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Nova Scotia Power Inc.

Notes to the Financial Statements

December 31, 2010 and 2009

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nova Scotia Power Inc., created through the privatization in 1992 of the crown corporation Nova Scotia Power Corporation, is a fully-integrated regulated electric utility and the primary electricity supplier in Nova Scotia. NSPI is a public utility as defined under the Public Utilities Act of Nova Scotia (“Act”) and is subject to regulation under the Act by the Utility and Review Board (“UARB”). The Act gives the UARB authority over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are subject to UARB approval. NSPI is not subject to an annual rate review process, but rather participates in hearings from time to time at NSPI’s or the UARB’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 a reasonable return to investors. NSPI’s regulated return on equity (“ROE”) range for 2010 was 9.1% to 9.6% (with 9.35% used to set rates) on an allowed common equity component up to 40% of NSPI’s total regulated 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 has set, as a condition, that NSPI will maintain its average actual regulated annual common equity at a level no higher than 40% beginning in 2010 and until the next general rate case.

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 include: measurement of property plant and equipment depreciation rates (note 1e), intangible assets amortization rates (note 1f), post-employment benefits (note 3), income taxes (note 7), accounts receivable (note 8), regulatory assets and liabilities (note 10), asset retirement obligations (note 14), financial instruments (note 21) and contingencies (note 23). Actual results may differ from these estimates.

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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.

• 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”, “Construction work in progress” and “Intangibles” 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. In absence of rate-regulated accounting, net earnings for 2010 would have been $7.8 million lower (2009 – $3.8 million).

d. Regulatory Amortization

Accounting for the impact of rate regulation:

In December 2010, the UARB granted NSPI approval to defer certain tax benefits related to renewable energy projects arising in 2010 through an increase in regulatory amortization. The UARB will convene a proceeding in 2011 to discuss how this deferral will be applied. In the absence of UARB approval, 2010 earnings would have been $14.5 million higher.

NSPI has a regulatory asset related to pre-2003 income taxes that have been paid, but not yet recovered from customers. This circumstance arose when NSPI claimed capital cost allowance (“CCA”) deductions in its income tax returns that were ultimately disallowed by a decision of the Supreme Court of Canada. NSPI applied to the regulator to include recovery of these costs in customer rates. The UARB approved recovery of this regulatory asset over eight years, commencing April 1, 2007.

In January 2010, NSPI reached an agreement with stakeholders on its calculation of regulated ROE. The agreement includes a provision which provides the Company with flexibility in its amortization of the pre-2003 income taxes to accelerate additional amortization amounts in current periods and subsequently reduce amounts in future periods. In the absence of UARB approved recovery, the liability would have been expensed when incurred. More details are provided in note 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.

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The UARB agreed to allow NSPI to defer demand side management program expenses for the period January 1, 2008 until December 31, 2009. The UARB approved recovery of this regulatory asset over six years commencing January 1, 2009.

The UARB agreed to allow NSPI to defer vegetation management spending of $2.0 million in 2008 to be recovered in rates in a future period. The period of recovery of this asset will be determined during the next general rate case.

In the absence of UARB approved deferrals for taxes, demand side management and vegetation management expenses would have been expensed as incurred. More details are provided in note 10.

e. Property, Plant and Equipment

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

Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each category. The service lives of regulated assets are determined based on formal depreciation studies, which require UARB approval.

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

Accounting for the impact of rate regulation:

During 2003, following completion of a depreciation study and a negotiated agreement with stakeholders, NSPI’s regulator approved new depreciation rates which were to be phased in over four years beginning in 2004. In the decision on NSPI’s 2005 rate application, the UARB delayed the phase-in of year-two rates for one year. In the decision on NSPI’s 2006 rate application, the UARB approved restarting of the phase-in including year-two in 2006 rates. In its February 2007 decision, the UARB postponed the scheduled year-three phase-in of increased depreciation rates until the next rate application. In its November 2008 decision, the UARB approved the year-three phase-in effective January 1, 2009.

Absent consideration of growth in plant-in-service, the phase-in of new depreciation rates will increase depreciation expense by a cumulative increase of $20 million over the phase-in period. In the absence of UARB approval of depreciation rates, NSPI would be required to set rates based on management’s best estimates of useful lives. The average rates for the major categories of plant-in-service are summarized as follows:

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

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

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operations. Gains and losses will be charged to results of operation in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment would be charged to net earnings as incurred.

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 as discussed in property, plant and equipment in note 1(e). The estimated weighted average service life for the Company’s intangible assets is 57 years (2009 – 63 years).

When indicators of impairment exist, the Company determines whether the net carrying amount of the intangible assets is recoverable from future undiscounted cash flows. Factors which could indicate impairment exists include significant changes in regulation, a change in the Company’s strategy or underperformance relative to projected future operating results.

Accounting for the impact of rate regulation:

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

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

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, management 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.

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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 from the statements of earnings and AOCI to a regulatory asset or liability where the future income taxes are expected to be included in future rates. 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.

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

Adjustments to the accrued benefit obligation arising from plan amendments are amortized on a straight-line basis over the expected years of future service to the full eligibility date for active employees.

For any given year, when the net actuarial gain (loss), less the actuarial gain (loss) not yet included in the market-related value of plan assets, exceeds 10% of the greater of the accrued benefit obligation and the market-related value of the plan assets, an amount equal to the excess divided by the average remaining service period (“ARSP”) is amortized on a straight-line basis. For NSPI, the ARSP of the active employees is 9 years as at December 31, 2010 and 2009.

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, 2010 or 2009.

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.

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

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

Loans and receivables include cash and cash equivalents and accounts receivable and are measured at amortized cost using the effective interest method. Gains and losses are included in earnings and recorded in “Operating, maintenance and general expenses”.

Other financial liabilities, which include accounts payable and accrued charges, preferred shares, short-term debt and long-term debt, are recognized at amortized cost. Preferred share dividends paid are recognized using the effective interest method. Interest expense and debt financing expenses related to the Company’s long-term debt and short-term debt are recognized using the effective interest method.

Derivatives in valid hedging relationships are categorized as cash flow hedges and fair value hedges. The Company uses cash flow hedges to manage changes in commodity prices, foreign exchange rates, and interest rates. The Company uses fair value hedges to hedge the fair value of commodity positions.

The Company uses various financial instruments to hedge its exposure to foreign exchange, interest rate, and commodity price risks. In addition, the Company has contracts for the physical purchase and sale of natural gas, and physical and financial contracts that are held-for-trading. Collectively, these contracts are referred to as derivatives.

The Company recognizes the fair value of all its hedges on its balance sheet.

Hedging relationships that meet stringent documentation requirements, and can be proven to be effective both at the inception and over the term of the relationship qualify for hedge accounting. Specifically, in a cash flow hedge, the effective portion of the change in the fair value of hedging derivatives is recorded in AOCI and reclassified to earnings, inventory or construction work in progress in the same period the related hedged item is realized. Any ineffective portion of the change in fair value of hedging derivatives is recognized in net earnings in the reporting period.

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

Where documentation and effectiveness requirements are not met, the change in fair value of the derivative is recognized in earnings in the reporting period.

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If a cash flow hedge is terminated, the effective portion of the change in fair value of the hedging derivative up until the date of termination remains in AOCI and is recognized in earnings, inventory or construction work in progress in the same period the related hedged risk is realized. The change in fair value of the derivative, if retained, would then be recognized in earnings from the termination date onward.

Amounts received or paid related to derivatives used to hedge foreign exchange and commodity price risks on fuel purchases are recognized in “Fuel for generation and purchased power” or “Inventory”. Amounts received or paid related to derivatives used to hedge foreign exchange on capital purchases are recognized in “Construction work in progress”. Amounts received or paid related to derivatives used to hedge interest rate risks are recognized over the term of the hedged item in “Financing charges”. 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 HFT derivatives and derivatives in valid hedging relationships are reflected in “Operating activities” and “Investing activities” on the statement of cash flows.

Accounting for the impact of rate regulation:

In accordance with Handbook Standard 3865 Hedges, NSPI determined that it cannot meet the probability requirement of the standard for its derivatives in place to hedge natural gas and heavy fuel oil for its Tufts Cove generating station (“TUC”). This is due to the generating station’s ability to fuel switch and NSPI’s economic dispatch based on the cost of these two fuels. The UARB has allowed NSPI to apply hedge accounting to these derivatives as long as the other requirements of the Handbook are met. In 2009, the UARB approved an amendment to NSPI’s accounting practice to include all TUC derivatives which are no longer required. Absent UARB approval, NSPI would be required to recognize the changes in fair value of these derivatives in net earnings of the period.

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

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.

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 ESTIMATE

In 2010, the Company revised its estimate of the expected benefit from accelerated tax deductions. The impact for the three months and twelve months ended December 31, 2010 was to reduce income tax expense by approximately $8.0 million and $14.0 million respectively. In accordance with rate-regulated accounting, the future income tax implications of this change in estimate have been deferred to a

14

regulatory asset in “Other assets”. This change in accounting estimate has been accounted for on a prospective basis.

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, 2010.

Valuation date for defined-benefit plans

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

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

Total cash amount

Total cash amount for 2010, made up of contributions to its funded defined-benefit pension plans, contributions to its defined-contribution pension plan, employer paid premiums for its post-retirement health care plan, and amounts paid directly to retirees and beneficiaries in other plans, was $40.2 million (2009 – $32.1 million).

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Accrued pension and non-pension benefit asset (liability)

		2010						2009
millions of dollars		Defined benefit pension plans			Non-pension benefits plan			Defined benefit pension plans			Non-pension benefits plans
Assumptions (weighted average)
Accrued benefit obligation – December 31:
Discount rate			5.50%			5.50%			6.50%			6.50%
Rate of compensation increase			3% to 5.5%			3% to 5.5%			3% to 5.5%			3% to 5.5%
Health care trend	– initial (next year)		—			4.00%			—			5.00%
	– ultimate		—			4.00%			—			4.00%
	– year ultimate reached		—			2011			—			2011
Benefit cost for year ending December 31:
Discount rate			6.50%			6.50%			7.50%			7.50%
Expected long-term return on plan assets			7.25%			—			7.25%			—
Rate of compensation increase			3% to 5.5%			3% to 5.5%			3% to 5.5%			3% to 5.5%
Health care trend	– initial (current year)		—			5.00%			—			6.00%
	– ultimate		—			4.00%			—			4.00%
	– year ultimate reached		—			2011			—			2011
Accrued benefit obligations
Balance, January 1		$	785.2		$	36.3		$	667.2		$	36.1
Employer current service cost			9.0			1.4			6.5			1.3
Employee contributions			5.5			—			5.2			—
Interest cost			50.0			2.3			49.0			2.6
Past service adjustment			(1.0	)		—			—			—
Actuarial losses			122.3			4.1			95.4			0.4
Benefits paid			(39.5	)		(4.3	)		(38.1	)		(4.1	)
Balance, December 31			931.5			39.8			785.2			36.3
Fair value of plan assets
Balance, January 1			592.1			—			508.8			—
Employer contributions			34.6		$	4.3			26.9			4.1
Employee contributions			5.5			—			5.2			—
Actual return on plan assets			55.7			—			89.3			—
Benefits paid			(39.5	)		(4.3	)		(38.1	)		(4.1	)
Balance, December 31			648.4			—			592.1			—
Reconciliation of financial status to accrued benefit asset, December 31
Fair value of plan assets			648.4			—			592.1			—
Accrued benefit obligations			931.5			39.8			785.2			36.3
Plan deficit			(283.1	)		(39.8	)		(193.1	)		(36.3	)
Unamortized past service (gains) costs			(0.3	)		1.4			(0.4	)		1.6
Unamortized actuarial losses (gains)			363.5			2.1			257.0			(2.2	)
Unamortized transitional obligation			(0.9	)		4.5			0.1			6.7
Accrued benefit asset (liability)		$	79.2		$	(31.8	)	$	63.6		$	(30.2	)

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

	2010						2009
millions of dollars	Defined benefit pension plans			Non-pension benefits  plan			Defined benefit pension plans			Non-pension benefits  plans
Accrued benefit asset	$	110.7			—		$	94.2			—
Accrued benefit liability		(31.5	)	$	(31.8	)		(30.6	)	$	(30.2	)
Net accrued benefit asset (liability)	$	79.2		$	(31.8	)	$	63.6		$	(30.2	)

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

As at December 31, 2010, the pension funds do not hold any material investments in Emera Inc. or Nova Scotia Power Inc. securities.

Plans with accrued benefit obligations in excess of assets

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

Benefits cost components millions of dollars	2010						2009
Defined benefit plan	Defined benefit pension  plans			Non-pension benefits  plan			Defined benefit pension  plans			Non-pension benefits  plan
Costs arising from events during the year:
Current service costs	$	9.0		$	1.4		$	6.5		$	1.3
Interest on accrued benefits		50.0			2.3			49.0			2.6
Less: actual return on plan assets		(55.7	)		—			(89.3	)		—
Actuarial losses on accrued benefit obligation		122.3			4.1			95.4			0.4
Past service gain		(1.0	)		—			—			—
Future benefit costs before adjustments		124.6			7.8			61.6			4.3
Adjustments to recognize long-term nature of costs:
Difference between expected return on assets and actual return		6.2			—			40.8			—
Amortization of transitional obligation		—			2.2			—			2.2
Difference between amortization of actuarial gains and actual actuarial gains on accrued benefit obligations		(112.8	)		(4.3	)		(94.8	)		(0.7	)
Difference between amortization of past service costs and past service costs for the year		1.0			0.2			—			0.2
Total cost recognized	$	19.0		$	5.9		$	7.6		$	6.0
Defined contribution plan
Employer cost	$	1.3			—		$	1.0			—

The expected return on plan assets is determined based on the market-related value of plan assets of $684.6 million at January 1, 2010 (2009 – $670.5 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 2010:

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

4. FUEL ADJUSTMENT

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

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

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

The Company has recognized a future income tax expense related to the fuel adjustment based on NSPI’s applicable statutory income tax rate. The FAM regulatory asset or liability includes amounts recognized as a fuel adjustment and associated interest included in “Financing charges”. As at December 31, 2010, NSPI’s FAM regulatory asset was $92.9 million (2009 – liability of $9.9 million), and future income tax liability related to the FAM was $29.2 million (2009 – asset of $3.4 million).

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

5. OPERATING LEASES

The Company has entered into operating lease agreements for office space and rail cars, which expire in 2011 and 2015. Future minimum annual lease payments under the leases are as follows:

millions of dollars
2011	$	1.8
2012		0.3
2013		0.3
2014		0.3
2015		0.3
	$	3.0

For the year ended December 31, 2010, the Company recognized $9.6 million (2009 – $9.5 million) of operating leases for office space and telecommunications services in “Operating, maintenance and general expense”.

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6. FINANCING CHARGES

Financing charges consists of the following:

millions of dollars	2010			2009
Interest – long-term debt	$	109.0		$	98.2
– short-term debt		1.6			1.0
Preferred share dividends (note 17)		7.9			9.5
Amortization of defeasance cost (note 10)		12.1			12.1
Amortization of debt financing costs		1.8			1.8
Allowance for funds used during construction		(17.1	)		(7.8	)
Interest (recovery) expense on deferral of FAM		(3.8	)		1.4
Foreign exchange losses (gains) recovered through the FAM		9.3			(3.0	)
Banking fees and other		5.0			1.5
	$	125.8		$	114.7

7. INCOME TAXES

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

millions of dollars	2010					2009
Earnings before income taxes	$	103.9				$	151.5
Income taxes, at statutory rates		35.3		34.0%			53.0		35.0%
Future income taxes on regulated earnings deferred to regulatory assets (note 10)		(53.4	)	(51.4	)		(22.9	)	(15.1	)
Non-deductible preferred share dividends		2.7		2.6			3.3		2.2
Non-deductible regulatory amortization (note 10)		11.8		11.4			9.3		6.1
Change in estimate of prior year expected benefit of tax deductions		(4.7	)	(4.5	)		—		—
Recovery of prior year income taxes		(4.4	)	(4.2	)		—		—
Difference in tax rate for future income taxes not deferred to regulatory assets		(1.9	)	(1.8	)		0.1		0.1
Other		(2.8	)	(2.8	)		(0.6	)	(0.4	)
		(17.4	)	(16.7)%			42.2		27.9%
Income taxes – current		(47.1	)				45.6
Income taxes – future	$	29.7				$	(3.4	)

The future income tax assets and liabilities comprise the following:

	Current portion					Long-term portion
millions of dollars	2010			2009		2010			2009
Future income tax assets:
Inventory	$	2.5		$	2.3		—			—
Share-based compensation		2.4			2.5		—			—
Derivatives		(0.9	)		25.3		—			—
Tax loss carry forwards		—			4.1		—			—
Other		0.1			0.2		—			—
	$	4.1		$	34.4		—			—
Future income tax liabilities:
Property, plant and equipment		—			—	$	176.8		$	82.2
Derivatives		—			—		4.0			3.2
Asset retirement obligations		—			—		(62.4	)		(45.2	)
Deferral of FAM							29.2			(3.4	)
Pension		—			—		21.3			14.9
Defeasance costs		—			—		19.2			20.0
Intangibles		—			—		(23.6	)		(23.2	)
Other		—			—		(1.4	)		3.5
		—			—	$	163.1		$	52.0

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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.

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 $60.1 million lower in 2010 (2009 – $18.9 million).

8. ACCOUNTS RECEIVABLE

At December 31, 2010, the Company had unbilled revenue included in accounts receivable in the amount of $84.1 million (2009 – $85.4 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 had a natural gas purchase agreement, which settled in November 2010, which included a price adjustment clause covering three years of natural gas purchases. The clause stated NSPI would pay for all gas purchases at the agreed contract price, but would be entitled to a price rebate on a portion of the volumes, settled in November 2007 and November 2010. At December 31, 2009, the receivable was $82.1 million.

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	2010			2009			2010			2009
Inventory, beginning of period	$	139.3		$	101.6		$	26.3		$	25.2
Purchases		327.5			355.4			43.2			37.1
Write-down of inventory to net realizable value		—			—			(0.9	)		(0.7	)
Inventories expensed		(340.9	)		(317.7	)		(21.8	)		(21.1	)
Inventories capitalized		—			—			(24.6	)		(21.4	)
Other		—			—			6.1			7.2
Inventory, end of period	$	125.9		$	139.3		$	28.3		$	26.3

The Company has not pledged inventory as security for liabilities.

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10. OTHER ASSETS AND LIABILITIES

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

millions of dollars	2010		2009
Other assets:
Regulatory assets:
Future income tax regulatory asset	$	136.9	$	25.2
Unamortized defeasance costs		94.6		106.7
Deferral of FAM		92.9		—
Pre-2003 income tax and related interest		56.9		75.2
Deferral of income and capital taxes not included in Q1 2005 rates		10.0		11.9
Deferral of demand side management		7.5		9.7
Deferral of vegetation management		2.0		2.0
Deferral of Tufts Cove derivatives		1.3		9.6
Held-for-trading natural gas contracts		—		3.9
		402.1		244.2
Non-regulatory assets:
Accrued pension asset (note 3)		110.7		94.2
Other		—		0.7
		110.7		94.9
	$	512.8	$	339.1
	2010		2009
Other liabilities:
Regulatory liabilities:
2010 renewable tax benefits deferral	$	14.5		—
Held-for-trading natural gas contracts		12.3	$	4.7
Deferral of Tufts Cove derivatives		2.0		10.4
Deferral of FAM		—		9.9
		28.8		25.0
Non-regulatory liabilities:
Accrued pension and non-pension benefit liability (note 3)		63.3		60.8
Unearned revenue		1.1		1.7
Other		5.4		4.0
		69.8		66.5
	$	98.6	$	91.5

Regulatory assets consist of:

Future Income Tax Regulatory Asset

In accordance with the Company’s rate-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 2010 net earnings would be $60.1 million lower (2009 –  $18.9 million).

Unamortized Defeasance Costs

Upon privatization in 1992, NSPI became responsible for managing a portfolio of defeasance securities held in trust, which as at December 31, 2010 and 2009 totaled $1.0 billion. The excess of the cost of defeasance investments over the face value of the related debt is deferred on the balance sheet and amortized over the life of the defeased debt as permitted by the UARB. In the absence of UARB approval, the losses would have been expensed as incurred and net earnings would be $12.1 million higher in 2010 and 2009.

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Deferral of 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, 2010 would be $80.4 million ($56.3 million after-tax) lower (2009 – $9.9 million or $6.5 million after-tax higher).

Pre-2003 Income Tax and Related Interest

NSPI has a regulatory asset related to pre-2003 income taxes that have been paid, but not yet recovered from customers. This circumstance arose when NSPI claimed capital cost allowance 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, to allow flexibility relating to future customer rate requirements, NSPI recorded an additional discretionary $4.8 million of regulatory amortization expense for the year ended December 31, 2010 (December 31, 2009 – $10.0 million). In the absence of UARB approved recovery, the liability would have been expensed when incurred, therefore net earnings would be $18.3 million higher in 2010 (2009 – $24.6 million).

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.

Deferral of Income and Capital Taxes Not Included in Q1 2005 Rates

The UARB agreed to allow NSPI to defer taxes not reflected in rates for the period January 1, 2005 until April 1, 2005, the date when new rates became effective. In 2005, NSPI deferred $16.7 million consisting of $4.5 million of provincial and federal grants and $12.2 million in income taxes reflecting increases in these taxes since rates were last set in 2002. In its February 2007 decision, the UARB approved recovery of this regulatory asset over eight years, commencing April 1, 2007. In the absence of UARB approval, these taxes would not have been deferred and net earnings for 2010 would be $1.9 million higher (2009 – $1.9 million).

Deferral of Demand Side Management

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

Deferral of Vegetation Management

The UARB agreed to allow NSPI to defer up to $2.0 million of vegetation management spending in 2008 to be recovered in rates in a future period. The investment in vegetation management spending was part of a specific initiative to improve the reliability of service provided to customers. In the absence of UARB approval, these costs would have been expensed as incurred.

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

22

derivatives as long as the other requirements of the Handbook are met. This accounting policy permits NSPI to defer the fair value of hedges that are no longer required because of fuel switching.

In 2009, the UARB approved an amendment to NSPI’s accounting practice to include all Tufts Cove financial commodity hedges which are no longer required. This change in practice will impact the timing of recognition between “Fuel for generation and purchased power” and “Fuel adjustment” as a result of the FAM implemented in 2009. The change in accounting practice has been applied prospectively beginning January 1, 2009, as required by the UARB.

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

Held-for-trading Natural Gas Contracts

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

Regulatory liabilities consist of:

2010 Renewable Tax Benefits Deferral

In 2010, the UARB granted NSPI approval to defer certain tax benefits related to renewable energy projects arising in 2010. The UARB will convene a proceeding in 2011 to discuss how this deferral will be applied. Absent UARB approval these benefits would not have been deferred and net earnings would be $14.5 million higher.

Held-for-trading Natural Gas Contracts

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

Deferral of Tufts Cove Derivatives

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

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11. INTANGIBLES

Intangibles are comprised of the following:

	2010
millions of dollars	Cost		Accumulated Amortization		Net Book Value
Transmission	$	51.7	$	16.3	$	35.4
Distribution		19.7		5.4		14.3
Other		32.4		9.6		22.8
	$	103.8	$	31.3	$	72.5
	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

Amortization expense for the year ended December 31, 2010 was $4.3 million (2009 – $3.2 million).

12. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of the following:

	2010
millions of dollars	Cost		Accumulated Depreciation		Net Book Value
Generation
Thermal	$	1,965.1	$	827.5	$	1,137.6
Gas Turbines		33.0		24.8		8.2
Combustion Turbines		83.5		17.6		65.9
Hydroelectric		424.4		148.4		276.0
Wind Turbines		219.7		2.5		217.2
Transmission		598.6		312.5		286.1
Distribution		1,178.7		649.2		529.5
General plant including capital lease		318.8		170.3		148.5
	$	4,821.8	$	2,152.8	$	2,669.0
	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 including capital lease		312.0		157.3		154.7
	$	4,436.1	$	2,070.5	$	2,365.6

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13. INTEREST IN JOINTLY CONTROLLED PROJECT

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

NSPI has provided a guarantee for the indebtedness of RESL in connection with the project. The guarantee is up to a maximum of $23.5 million. NSPI holds a security interest in the assets of RESL, including the project assets.

Beginning August 2010, following the commencement of service, NSPI has recorded its share of the net operating revenues of the project. As at December 31, 2010, $25.4 million was included in “Property, plant and equipment” for NSPI’s portion of the Point Tupper wind energy project. NSPI’s share of the cash flows and the net earnings was immaterial for the year.

14. ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations (“ARO”) are recognized when incurred and represent the fair value, using the Company’s credit-adjusted risk-free rate, of the Company’s estimated future cash flows necessary to discharge legal obligations related to reclamation of land at the Company’s thermal, hydro and combustion turbine sites, 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, governmental regulatory requirements and the costs of activities such as demolition, restoration and remedial work based on present-day methods and technologies. Actual results may differ from these estimates.

The change in ARO is due to the following:

millions of dollars	2010			2009
Balance, beginning of year	$	101.5		$	87.6
Accretion included in depreciation expense		3.5			3.3
Accretion deferred to regulatory asset		2.1			1.5
Liabilities settled		(1.2	)		(1.2	)
Additions		32.8			10.3
Balance, end of year	$	138.7		$	101.5

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

Asset	Credit-adjusted risk-free rate			Estimated undiscounted future obligation (millions of dollars)		Expected settlement date
Thermal		5.30	%	$	258.9		10 – 29 years
Hydro		5.27	%		101.4		21 – 51 years
Wind		5.21	%		45.5		13 – 20 years
Combustion turbines		5.25	%		12.9		1 – 14 years
Transmission & distribution		5.74	%		21.6		1 – 15 years
				$	440.3

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

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

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Accounting for the impact of rate regulation:

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

15. SHORT-TERM DEBT

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

millions of dollars	2010
Advances against the operating line of credit, which when drawn upon, bears interest at the prime rate plus 0.50%; the prime rate on December 31, 2010 was 3.00%.	$	1.6
Short-term discount notes bearing interest at prevailing market rates, which on December 31, 2010, averaged 1.07%.		46.7
	$	48.3
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 bearing interest at prevailing market rates, which on December 31, 2009, averaged 0.35%.		193.3
	$	198.2

This short-term debt is unsecured.

16. LONG-TERM DEBT

Long-term debt includes the issuances detailed below. Medium-term notes and debentures are issued under trust indentures at fixed interest rates, and are unsecured unless noted below. Also included are certain 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	2010		2009		Years of Maturity		2010			2009
Medium-term notes (1)		6.56		6.60		2011 – 2097	$	1,610.0		$	1,410.0
Debentures		9.75		9.75		2019		95.0			95.0
Short-term discount notes (2)		1.07		—		3 year renewal		241.7			—
Capital lease obligations		6.30		3.89		Various		0.1			3.7
								1,946.8			1,508.7
Amount due within one year								(0.1	)		(100.7	)
Unamortized debt financing costs								(13.0	)		(11.0	)
							$	1,933.7		$	1,397.0

(1) 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.

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

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

millions of dollars
Year of Maturity	Debt
Three year renewable	$	241.7
2011		0.1
2012		—
2013		300.0
2014		—
2015		70.0
Greater than 5 years		1,335.0
	$	1,946.8

17. 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, 2008		10.4		$	260.0
Redemption of Series C First Preferred Shares		(5.0	)		(125.0	)
December 31, 2009		5.4			135.0
December 31, 2010		5.4		$	135.0

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

Series D First Preferred Shares:

Each Series D First Preferred Share is entitled to a $1.475 per share per annum fixed cumulative preferential dividend, as and when declared by the Board of Directors, accruing from the date of issue and payable quarterly on the fifteenth day of January, April, July and October of each year.

On and after October 15, 2015, Series D First Preferred Shares are redeemable by NSPI, in whole at any time or in part from time to time at $25 per share plus accrued and unpaid dividends. NSPI also has the option, commencing October 15, 2015, to exchange the Series D First Preferred Shares into Emera Inc. common shares determined by dividing $25 by the greater of $2 and the market price of the Emera Inc. common shares.

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

Series C First Preferred Shares:

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

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18. COMMON SHARES

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

Issued and outstanding:	Millions of Shares
December 31, 2008		106.8
Issued for non-cash consideration		0.4
December 31, 2009		107.2
Issued for cash consideration		5.0
December 31, 2010		112.2

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 Performance Share Unit Plan

The Company has deferred share unit (“DSU”) and performance share unit (“PSU”) (formerly restricted share unit) plans.

Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns, or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan.

Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the provision that for participants who are subject to executive share ownership guidelines, a minimum of 50% of the value of their actual annual incentive award (25% in the first year of the program) will be payable in DSUs until the applicable guidelines are met.

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

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PSUs are granted annually for three-year overlapping performance cycles. The 2010 PSUs were granted based on the average of Emera’s stock closing price for the fifty trading days prior to December 31 of the prior year and multiplied by a dividend ratio factor of 1.15 and a discount factor of 1.191 for share price appreciation. Dividend equivalents are awarded and are used to purchase additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance.

PSUs vest at the end of the three-year cycle and will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and will be pro-rated in the case of retirement, disability or death.

	Employee DSUs Outstanding			Employee PSUs Outstanding			Director DSUs Outstanding
December 31, 2008		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
Granted		13,777			45,560			12,165
Payout		—			(33,783	)		—
December 31, 2010		64,192			145,922			64,121

The Company is using the fair value based method to measure the compensation expense related to its share-based compensation and employee purchase plan and recognizes the expense over the vesting period on a straight-line basis. The DSU and PSU liabilities are marked-to-market at the end of each period based on the common share price at the end of the period. For the year ended December 31, 2010, $3.2 million (2009 – $2.4 million) of compensation expense related to the options granted, units issued and shares purchased by employees was recognized in “Operating, maintenance and general expense”.

19. SUPPLEMENTAL CASH FLOW INFORMATION

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

millions of dollars	2010			2009
Increase in accounts receivable	$	(0.3	)	$	(71.5	)
Decrease in contract receivable		82.1			56.4
Decrease (increase) in inventory		11.4			(38.8	)
(Increase) decrease in prepaid expenses		(0.4	)		0.5
Change in posted margin included in accounts receivable		(2.5	)		25.1
Increase in other accounts payable and accrued charges and due to associated companies		11.8			35.8
Change in heavy fuel oil hedging balance in AOCI		3.1			(4.3	)
Change in income taxes receivable/payable		(41.8	)		9.3
Change in non-cash operating working capital	$	63.4		$	12.5

20. 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	2010			2009
Shareholders’ equity, excluding AOCI	$	1,200.7		$	1,129.4
Debt		1,982.1			1,695.9
Preferred shares		135.0			135.0
Cash and cash equivalents		(0.3	)		(0.3	)
	$	3,317.5		$	2,960.0

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The Company’s objective when managing capital is to ensure sufficient liquidity exists by maintaining access to capital markets in order to allow the Company to support its capital program. The Company is in compliance with its debt covenants and targets a long-term capital structure consistent or within these parameters. The covenants are maintained by the Company through the issuance of common shares, medium-term notes, preferred shares, or other indebtedness.

NSPI is subject to regulation by the UARB with a maximum allowed common equity component effective January 1, 2010 of 40% (2009 – 45%). 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 agreements. The Company’s syndicated bank credit facility limits its debt to 65% of total capitalization. The Company is in compliance with all of its financial debt covenants.

21. 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, and coal, oil and gas options and swaps, are used to hedge cash flows. Derivative financial instruments, consisting of foreign exchange forward contracts, are also used to hedge fair values.

Derivative financial instruments involve credit and market risks. Credit risks arise from the possibility a counterparty will default on its contractual obligations and is limited to those contracts where the Company would incur a loss in replacing the instrument.

Financial instruments include the following:

	2010				2009
millions of dollars	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash	$	0.3	$	0.3	$	0.3	$	0.3
Accounts receivable		192.5		192.5		271.8		271.8
Derivatives held in a valid hedging relationship (current and long-term portion)
Cash flow hedges		45.5		45.5		41.2		41.2
Fair value hedges		—		—		8.0		8.0
Held-for-trading derivatives (current and long-term portion)		14.5		14.5		15.1		15.1
Total financial assets	$	252.8	$	252.8	$	336.4	$	336.4
Accounts payable and accrued charges	$	221.3	$	221.3	$	213.9	$	213.9
Short-term debt		48.3		48.3		198.2		198.2
Derivatives held in a valid hedging relationship (current and long-term portion)
Cash flow hedges		11.6		11.6		73.0		73.0
Held-for-trading derivatives (current and long-term portion)		22.6		22.6		13.5		13.5
Long-term debt (including current portion)		1,933.8		2,280.5		1,497.7		1,712.8
Preferred shares		135.0		152.3		135.0		151.2
Total financial liabilities	$	2,372.6	$	2,736.6	$	2,131.3	$	2,362.6

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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, 2010 was as follows:

	Level 1		Level 2		Level 3		Total
(millions of dollars)
Financial assets:
Cash	$	0.3		—		—	$	0.3
Derivatives in a valid hedging relationship (current and long-term portion)
Cash flow hedges		41.2	$	4.3		—		45.5
Held-for-trading derivatives (current and long-term portion)		—		1.9	$	12.6		14.5
Total financial assets	$	41.5	$	6.2	$	12.6	$	60.3
Financial liabilities:
Derivatives in a valid hedging relationship (current and long-term portion)
Cash flow hedges	$	1.0	$	10.6		—	$	11.6
Held-for-trading derivatives (current and long-term portion)		—		1.3	$	21.3		22.6
Total financial liabilities	$	1.0	$	11.9	$	21.3	$	34.2

Changes in the fair value of financial assets classified as Level 3 in fair value hierarchy of $86.1 million during the year ended December 31, 2010, were as follows:

millions of dollars	Accounts Receivable			Derivatives in a valid hedging relationship – Cash flow hedge			Held-for-trading derivatives			Total
Balance at January 1, 2010	$	82.1		$	1.5		$	15.1		$	98.7
Total loss realized and unrealized
Included in earnings		(5.8	)		—			—			(5.8	)
Purchases, issuances, settlements		(76.3	)		(1.5	)		(0.7	)		(78.5	)
Transfer to Level 2		—			—			(1.9	)		(1.9	)
Transfer to Held-for-trading		—			—			0.1			0.1
Balance at December 31, 2010		—			—		$	12.6		$	12.6

Changes in the fair value of financial liabilities classified as Level 3 in fair value hierarchy of $11.4 million during the year ended December 31, 2010, were as follows:

millions of dollars	Derivatives in a  valid hedging relationship – Cash flow hedges			Held-for-trading derivatives			Total
Balance at January 1, 2010	$	(2.1	)	$	(7.8	)	$	(9.9	)
Total (loss) gain realized and unrealized
Included in earnings		(0.8	)		(1.3	)		(2.1	)
Included in AOCI		11.3			—			11.3
Purchases, issuances, settlements		(28.3	)		6.5			(21.8	)
Transfer to Level 2		—			1.3			1.3
Transfer to Held-for-trading		19.9			(20.0	)		(0.1	)
Balance at December 31, 2010		—		$	(21.3	)	$	(21.3	)

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ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE AND ACCRUED CHARGES

The carrying value of accounts receivable, accounts payable and accrued charges is a reasonable approximation of fair value. Losses included in earnings and recorded in “Operating, maintenance and general expenses” are $3.7 million (2009 – $4.5 million).

The allowance for doubtful accounts was $4.0 million as at January 1, 2010 (2009 – $2.8 million) and $2.5 million as at December 31, 2010 (2009 – $4.0 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 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	2010			2009
Fuel and purchased power increase	$	(64.7	)	$	(38.4	)
Financing charges decrease		1.8			6.9
Total losses	$	(62.9	)	$	(31.5	)

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

millions of dollars	2010			2009
Fuel and purchased power increase	$	(0.8	)	$	(12.8	)
Financing charges increase		(0.1	)		—
Total losses	$	(0.9	)	$	(12.8	)

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

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

The Company expects to reclassify $1.7 million of gains currently included in AOCI to net earnings over the next 12 months related to hedged items realized in net earnings.

Interest Rates

The Company may use various financial instruments to hedge against interest rate risk. Additionally, the Company uses diversification as a risk management strategy. The Company 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 so as to mitigate concentration risk.

The Company may enter into interest rate hedging contracts to limit exposure to fluctuations in floating and fixed interest rates on its short-term and long-term debt.

The Company has no interest rate hedging contracts outstanding as at December 31, 2010.

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Commodity Prices

A substantial amount of NSPI’s fuel supply comes from international suppliers and is subject to commodity price risk. As part of its fuel management strategy, NSPI manages exposure to commodity price risk utilizing financial instruments providing fixed or maximum prices.

The Company enters into natural gas swap contracts to limit exposure to fluctuations in natural gas prices. As at December 31, 2010, the Company had hedged approximately 87% of all natural gas purchases and sales associated with its forecasted natural gas burn and resale for 2011, and 35% for 2012.

The Company enters into oil swap contracts to limit exposure to fluctuations in world prices of heavy fuel oil. For 2011 and 2012, NSPI currently does not have heavy fuel oil hedging requirements.

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

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 $225.5 million are in place at a weighted average rate of $0.99 representing over 70% of 2011 anticipated USD requirements. Forward contracts to buy USD $443.0 million in 2012 through 2015 at a weighted average rate of $1.03 were outstanding at December 31, 2010 to manage exposure of 31% of anticipated USD requirements in these years. As at December 31, 2010, there were no fuel-related foreign exchange swaps outstanding.

NSPI may use foreign exchange forward contracts to hedge the currency risk for capital projects and receivables denominated in foreign currencies. Forward contracts to buy €1.8 million are in place at a weighted average rate of 1.56 (versus CAD) for capital projects in 2011.

HELD-FOR-TRADING DERIVATIVES

Derivatives included in held-for-trading assets and liabilities are required to be included in this classification in accordance with CGAAP. The Company has not designated any financial instruments to be included in the held-for-trading category.

The fair value of derivatives is estimated by obtaining prevailing market rates from investment dealers.

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

millions of dollars	2010			2009
Fuel and purchased power (increase) decrease	$	(1.3	)	$	13.0
Total (losses) gains	$	(1.3	)	$	13.0

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.

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Derivatives not in valid hedging relationships

On December 31, 2010, 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.

As at December 31, 2010, the Company determined that market risk exposure associated with its financial instruments would affect the Company’s financial results as follows:

millions of dollars	Net earnings increase (decrease)			AOCI increase (decrease)
$1 per one million British Thermal Unit increase in the price of natural gas *	$	(0.1	)		—
$5 per barrel increase in the price of heavy fuel oil		—			—
$15 per metric tonne increase in the price of coal		—		$	29.8
$0.01 decrease in the strength of the Canadian relative to the US dollar		—			7.1
100 basis point increase in the central bank interest rates		(0.1	)		—

* Fuel costs are recoverable through the FAM, thus natural gas price changes would not materially impact net earnings.

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.

Credit risk

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit assessments are conducted on all new customers and deposits are requested on any high risk accounts. The Company also maintains provisions for potential credit losses, which are assessed on a regular basis. With respect to customers other than electric customers, counterparty creditworthiness is assessed through reports of credit rating agencies or other available financial information.

As at December 31, 2010, the maximum exposure the Company has to credit risk is $252.5 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, 2010, was $12.4 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.

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As at December 31, 2010, the Company had $29.6 million (2009 – $30.8 million) in financial assets considered to be past due, which have been outstanding for an average of 70 days. The fair value of these financial assets was $27.3 million (2009 – $27.0 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, 2010 was as follows:

	millions of dollars		% of total exposure
Accounts receivable
Residential	$	96.3		38	%
Commercial		48.6		19	%
Industrial		32.3		13	%
Other		15.3		6	%
		192.5		76	%
Derivatives(in a valid hedging relationship and held-for-trading; current and long-term portions)
Credit rating of A- or above		47.5		19	%
Credit rating of BBB- to BBB+		9.1		4	%
Not rated		3.4		1	%
		60.0		24	%
	$	252.5		100	%

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:

	3 year renewable (1)		2011		2012		2013		2014		> 2014		Total
Accounts payable and accrued charges		—	$	221.3		—		—		—		—	$	221.3
Short-term debt		—		48.3		—		—		—		—		48.3
Long-term debt	$	241.7		0.1		—	$	300.0		—	$	1,405.0		1,946.8
Preferred shares		—		—		—		—		—		135.0		135.0
Derivatives held in a valid hedging relationship		—		2.2		—		6.2	$	1.8		1.4		11.6
Held-for-trading derivatives		—		20.8	$	1.8		—		—		—		22.6
Total financial liabilities	$	241.7	$	292.7	$	1.8	$	306.2	$	1.8	$	1,541.4	$	2,385.6

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

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

millions of dollars	Available		Used		Unused
Bank operating and commercial paper	$	600.0	$	289.0	$	311.0

22. RELATED PARTY TRANSACTIONS

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

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

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

millions of dollars
Affiliate	Purpose of Transaction	2010			2009
Emera Energy Services	Net (purchases) sales of gas and electricity	$	(6.7	)	$	25.0
Other	Other services provided		7.4			6.9
Other	Various services purchased		48.3			15.7

In the ordinary course of business, the Company purchased natural gas transportation capacity totaling $18.0 million (2009 – $18.2 million) during the year ended December 31, 2010, from the Maritimes & Northeast Pipeline, an investment under significant influence of Emera Inc. The amount is recognized in “Fuel for generation and purchased power” and is measured at the exchange amount. As at December 31, 2010, the amount payable to the related party was $1.0 million (2009 – $1.5 million), and is under normal interest and credit terms.

On May 28, 2010, NSPI purchased $30.1 million in wind generation assets under development related to the Digby Wind Project from a subsidiary of Emera. This transaction was measured at the carrying amount of the assets transferred. At December 31, 2010, there was no amount due.

During the year ended December 31, 2010, the Company issued a total of 5.0 million (2009 – 0.4 million) common shares to Emera Inc. and an affiliate under common control for total consideration of $50.0 million (2009 – $4.1 million).

23. 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.

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24. COMMITMENTS

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

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

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

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

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

• 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 2011 and $4 million per year from 2012 to 2014.

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

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

25. GUARANTEES

NSPI had the following guarantees at December 31, 2010:

• The Company has letters of credit issued totaling $20.7 million that extend to 2011 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 guarantee for the indebtedness of a third party, up to a maximum of $23.5 million, related to future purchased power. NSPI holds a security interest in the assets of the third party.

26. COMPARATIVE INFORMATION

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

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OPERATING STATISTICS (Unaudited)

FIVE-YEAR SUMMARY

Year Ended December 31	2010		2009		2008		2007		2006
Electric energy sales (GWh)
Residential		4,147.2		4,227.7		4,178.8		4,144.6		3,926.9
Commercial		3,088.5		3,107.3		3,114.6		3,160.5		3,023.0
Industrial		3,907.7		3,642.4		4,144.6		4,191.4		2,874.4
Other		311.7		328.1		334.2		365.9		681.2
Total electric energy sales		11,455.1		11,305.5		11,772.2		11,862.4		10,505.5
Sources of energy (GWh)
Thermal – coal		7,838.7		8,177.3		9,008.9		9,561.4		9,128.1
– oil		36.1		306.9		339.6		515.3		431.4
– natural gas		2,275.0		1,611.5		1,257.9		1,057.1		390.3
Hydro		991.5		1,063.4		1,065.3		908.8		995.7
Wind		25.3		1.8		2.4		2.4		2.4
Purchases		997.1		930.7		888.6		653.9		404.6
Total generation and purchases		12,163.7		12,091.6		12,562.7		12,698.9		11,352.5
Losses and internal use		708.6		786.1		790.5		836.5		847.0
Total electric energy sold		11,455.1		11,305.5		11,772.2		11,862.4		10,505.5
Electric customers
Residential		442,824		439,338		435,847		431,697		427,734
Commercial		34,864		34,678		34,509		34,266		34,047
Industrial		2,485		2,499		2,496		2,503		2,487
Other		9,256		9,153		9,062		9,572		9,376
Total electric customers		489,429		485,668		481,914		478,038		473,644
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		76		1		1		1		1
Independent power producers		186		137		85		85		79
		2,554		2,430		2,378		2,378		2,372
Total number of employees		1,900		1,865		1,791		1,740		1,698
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)		29,000		27,000		26,000		25,000		25,000

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FIVE YEAR SUMMARY (Unaudited)

Year Ended December 31 (millions of dollars)	2010			2009			2008			2007			2006
Statements of Earnings Information
Revenue	$	1,182.7		$	1,202.1		$	1,126.6		$	1,113.7		$	977.5
Cost of operations
Fuel for generation and purchased power		586.7			500.7			471.4			433.7			292.8
Fuel adjustment		(99.0	)		8.5			—			—			—
Operating, maintenance and general		237.5			215.1			203.7			206.0			202.5
Provincial grants and taxes		40.1			40.5			41.2			40.4			40.3
Depreciation and amortization		150.8			143.9			133.6			131.1			127.8
Regulatory amortization		36.9			27.2			17.7			17.2			8.6
		953.0			935.9			867.6			828.4			672.0
		229.7			266.2			259.0			285.3			305.5
Financing charges		125.8			114.7			106.8			123.0			130.6
Other income		—			—			—			—			(8.9	)
		103.9			151.5			152.2			162.3			183.8
Income taxes		(17.4	)		42.2			46.6			62.1			79.5
Net earnings applicable to common shares		121.3			109.3			105.6			100.2			104.3
Common dividends		100.0			126.0			75.0			193.0			50.0
Earnings retained for use in Company	$	21.3		$	(16.7	)	$	30.6		$	(92.8	)	$	54.3
Cost of fuel for generation – coal	$	327.0		$	293.9		$	282.1		$	276.0		$	266.2
– oil		12.2			5.4			17.7			49.7			34.2
– natural gas		169.3			138.5			92.5			52.0			(41.6	)
Purchased power		78.2			62.9			79.1			56.0			34.0
Total cost of fuel for generation and purchased power	$	586.7		$	500.7		$	471.4		$	433.7		$	292.8
Balance Sheets Information
Current assets	$	428.8		$	506.1		$	477.3		$	361.7		$	288.7
Long-term receivable		—			—			56.4			7.7			—
Derivatives in a valid hedging relationship		20.8			29.8			115.5			10.4			—
Held-for-trading derivatives		8.2			6.2			54.0			47.6			—
Other assets*		512.8			339.1			353.7			358.8			371.8
Intangibles		72.5			65.7			58.7			58.8			58.6
Property, plant and equipment and construction work in progress		2,948.2			2,518.4			2,375.1			2,337.5			2,342.4
Total assets	$	3,991.3		$	3,465.3		$	3,490.7		$	3,182.5		$	3,061.5
Current liabilities	$	299.5			581.6		$	586.7		$	356.5		$	205.0
Derivatives in a valid hedging relationship		9.4			20.0			51.3			33.1			—
Held-for-trading derivatives		1.8			1.3			11.7			1.2			—
Future income tax liabilities		163.1			52.0			—			—			—
Asset retirement obligations		138.7			101.5			87.6			83.5			77.7
Other liabilities*		98.6			91.5			180.3			167.6			5.8
Long-term debt		1,933.7			1,397.0			1,296.7			1,314.3			1,405.5
Preferred shares		135.0			135.0			135.0			260.0			260.0
Common shares		984.7			934.7			930.6			830.6			830.6
Accumulated other comprehensive income (loss)		10.8			(44.0	)		(0.6	)		(48.4	)		—
Retained earnings		216.0			194.7			211.4			184.1			276.9
Total equity and liabilities	$	3,991.3		$	3,465.3		$	3,490.7		$	3,182.5		$	3,061.5
Statements of Cash Flow Information
Cash provided by operating activities	$	300.2		$	275.2		$	174.3		$	306.4		$	283.6
Cash used in investing activities	$	(533.3	)	$	(268.6	)	$	(163.4	)	$	(124.4	)	$	(101.8	)
Cash provided by (used in) financing activities	$	233.1		$	(6.3	)	$	(12.8	)	$	(188.3	)	$	(177.1	)

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

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