Nova Scotia Power 6K Current report | SEC 9 Aug 11

Exhibit 99.2

NOVA SCOTIA POWER INC.

Unaudited Condensed

Financial Statements

June 30, 2011 and 2010

Nova Scotia Power Inc.

Statements of Income (Unaudited)


For the	Three months ended June 30						Six months ended June 30
millions of Canadian dollars	2011			2010 (as adjusted – note 15)			2011			2010 (as adjusted – note 15)
Operating revenues	$	299.0		$	273.2		$	667.8		$	616.0

Operating expenses
Fuel for generation and purchased power		125.4			119.5			294.3			299.1
Fuel for generation and purchased power – affiliates (note 14)		0.4			4.8			0.1			6.4
Fuel adjustment (note 2)		6.2			(12.6	)		0.4			(52.0	)
Operating, maintenance and general		68.9			60.0			134.4			114.9
Provincial grants and taxes		9.6			10.0			19.2			20.0
Depreciation and amortization		42.7			41.9			85.3			83.0

Total operating expenses		253.2			223.6			533.7			471.4

Income from operations		45.8			49.6			134.1			144.6
Other expenses, net (note 3)		2.3			2.3			4.5			5.9
Interest expense, net (note 4)		27.0			26.6			53.9			52.7

Income before provision for income taxes		16.5			20.7			75.7			86.0
Income tax (recovery) expense (note 5)		(2.2	)		3.2			(8.6	)		1.3

Net income of Nova Scotia Power Inc.		18.7			17.5			84.3			84.7
Preferred stock dividends		2.0			2.0			4.0			4.0

Net income attributable to common shareholders	$	16.7		$	15.5		$	80.3		$	80.7

The accompanying notes are an integral part of these condensed financial statements.

Nova Scotia Power Inc.

Balance Sheets (Unaudited)


As at millions of Canadian dollars	June 30 2011		December 31 2010 (as adjusted – note 15)
Assets
Current assets
Cash	$	0.3	$	0.3
Receivables, net (note 6)		219.4		192.5
Income taxes receivable		46.0		34.3
Inventory (note 7)		147.3		154.2
Derivative instruments (note 12)		25.8		31.0
Regulatory assets		87.8		71.8
Prepaid expenses		26.2		6.0
Other current assets		1.8		1.8

Total current assets		554.6		491.9

Property, plant and equipment,net of accumulated depreciation of $2,229.6 and $2,153.1, respectively		2,947.8		2,949.5

Other assets
Deferred income taxes		—		16.8
Derivative instruments (note 12)		22.5		28.9
Regulatory assets		243.5		232.5
Other		87.5		88.2

Total other assets		353.5		366.4

Total assets	$	3,855.9	$	3,807.8

The accompanying notes are an integral part of these condensed financial statements.

Nova Scotia Power Inc.

Balance Sheets (Unaudited) – Continued


As at millions of Canadian dollars	June 30 2011			December 31 2010 (as adjusted – note 15)
Liabilities and Equity
Current liabilities
Short-term debt	$	127.0		$	48.3
Current portion of long-term debt		0.1			0.1
Accounts payable		109.5			157.9
Due to associated companies (note 14)		0.4			6.2
Deferred income taxes		6.1			3.4
Derivative instruments (note 12)		15.3			23.0
Regulatory liabilities		47.4			52.4
Pension and post-retirement liabilities		8.2			8.2
Other current liabilities (note 8)		66.9			67.2

Total current liabilities		380.9			366.7

Long-term liabilities
Long-term debt		1,894.5			1,952.2
Deferred income taxes		43.9			—
Derivative instruments (note 12)		22.0			11.2
Regulatory liabilities		22.5			61.7
Asset retirement obligations		82.3			138.7
Pension and post-retirement liabilities		303.7			314.7
Other long-term liabilities		7.4			5.6

Total long-term liabilities		2,376.3			2,484.1

Commitments and contingencies (note 10)

Redeemable preferred stock		132.2			132.2

Equity
Common stock, no par value, unlimited authorized shares, 117.2 million and 2010 - 112.2 million shares issued and outstanding		1,034.7			984.7
Accumulated other comprehensive loss		(354.3	)		(365.7	)
Retained earnings		286.1			205.8

Total equity		966.5			824.8

Total liabilities and equity	$	3,855.9		$	3,807.8

The accompanying notes are an integral part of these condensed financial statements.

Approved on behalf of the Board of Directors


Chairman				President and Chief Executive Officer

Nova Scotia Power Inc.

Statements of Cash Flows (Unaudited)


For the	Six months ended June 30
millions of Canadian dollars	2011			2010 (as adjusted – note 15)
Operating activities
Net income of Nova Scotia Power Inc.	$	84.3		$	84.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		92.0			91.0
Allowance for equity funds used during construction		(3.8	)		(3.1	)
Deferred income taxes, net		1.7			15.0
Net change in pension and post-retirement obligations		0.4			(6.3	)
Fuel adjustment		(3.5	)		(53.1	)
Net change in fair value of derivative instruments		0.4			7.1
Other operating activities, net		2.3			0.6
Changes in non-cash working capital:
Receivables, net		(26.9	)		(18.2	)
Income taxes receivable		(11.7	)		(14.4	)
Inventory		6.9			3.2
Prepaid expenses		(20.2	)		(23.3	)
Accounts payable		(48.4	)		(33.8	)
Due to associated companies		(5.8	)		5.4
Other current liabilities		(0.6	)		(4.2	)

Net cash provided by operating activities		67.1			50.6

Investing activities
Additions to property, plant and equipment		(125.4	)		(201.8	)
Additions to intangibles		(2.6	)		(6.0	)
Allowance for borrowed funds used during construction		(4.1	)		(3.4	)
Retirement spending, net of salvage		(2.0	)		(2.8	)

Net cash used in investing activities		(134.1	)		(214.0	)

Financing activities
Change in short-term debt, net		21.1			(78.7	)
Proceeds from long-term debt		—			300.0
Retirement of long-term debt		—			(100.0	)
Issuance of common stock		50.0			50.0
Preferred stock dividends		(4.0	)		(4.0	)
Other financing activities		(0.1	)		(3.9	)

Net cash provided by financing activities		67.0			163.4

Net change in cash		—			—
Cash, beginning of period		0.3			0.3

Cash, end of period	$	0.3		$	0.3

Supplemental disclosure of cash paid:
Interest	$	58.9		$	53.9
Income and capital taxes	$	3.2		$	0.9

Nova Scotia Power Inc.

Statements of Comprehensive Income (Unaudited)


For the	Three months ended June 30				Six months ended June 30
millions of Canadian dollars	2011		2010 (as adjusted – note 15 )		2011		2010 (as adjusted – note 15 )
Net income of Nova Scotia Power Inc.	$	18.7	$	17.5	$	84.3	$	84.7
Other comprehensive income
Amortization of unrecognized pension and post-retirement benefit costs		5.7		2.4		11.4		4.8

Comprehensive income	$	24.4	$	19.9	$	95.7	$	89.5

The accompanying notes are an integral part of these condensed financial statements.

Nova Scotia Power Inc.

Statements of Changes in Equity (Unaudited)


millions of Canadian dollars	Common Stock		Accumulated Other Comprehensive Loss			Retained Earnings			Total Equity
For the six months ended June 30, 2011
Balance, December 31, 2010 (as adjusted – note 15)	$	984.7	$	(365.7	)	$	205.8		$	824.8
Net income of Nova Scotia Power Inc.		—		—			84.3			84.3
Other comprehensive income		—		11.4			—			11.4
Issuance of common stock		50.0		—			—			50.0
Cash dividends declared on preferred stock ($0.3688 per share)		—		—			(4.0	)		(4.0	)

Balance, June 30, 2011	$	1,034.7	$	(354.3	)	$	286.1		$	966.5

For the six months ended June 30, 2010 (as adjusted – note 15)
Balance, December 31, 2009	$	934.7	$	(256.1	)	$	186.5		$	865.1
Net income of Nova Scotia Power Inc.		—		—			84.7			84.7
Other comprehensive income		—		4.8			—			4.8
Issuance of common stock		50.0		—			—			50.0
Cash dividends declared on preferred stock ($0.3688 per share)		—		—			(4.0	)		(4.0	)

Balance, June 30, 2010	$	984.7	$	(251.3	)	$	267.2		$	1,000.6

The accompanying notes are an integral part of these condensed financial statements.

Nova Scotia Power Inc.

Notes to the Condensed Financial Statements (Unaudited)

As at June 30, 2011

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies of Nova Scotia Power Inc. are as follows:

A.	Nature of Operations

Nova Scotia Power Inc. (“NSPI” or the “Company”) is a fully-integrated regulated electric utility and the primary electricity supplier in Nova Scotia, Canada, providing generation, transmission and distribution services to approximately 490,000 customers. NSPI is a public utility as defined under the Public Utilities Act of Nova Scotia (the “Act”) and is subject to regulation by the Nova Scotia Utility and Review Board (“UARB”). The Company’s accounting policies are subject to examination and approval of the UARB.

B.	Basis of Presentation

Effective January 1, 2011, NSPI changed the basis of presentation of its financial statements from Canadian Generally Accepted Accounting Principles (“CGAAP”) to United States Generally Accepted Accounting Principles (“USGAAP”), including the application of rate-regulated accounting policies.

These unaudited condensed financial statements are prepared and presented in accordance with USGAAP and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for Quarterly Reports. These unaudited condensed financial statements do not contain all disclosures required by USGAAP for annual audited financial statements. Accordingly, they should be read in conjunction with Nova Scotia Power Inc.’s annual financial statements as at and for the year ended December 31, 2010, which were prepared in accordance with CGAAP; and note 15 to these condensed financial statements, detailing the CGAAP to USGAAP transition and reconciliation information.

In the opinion of management, these unaudited condensed financial statements include all adjustments that are of a recurring nature and necessary to fairly state the financial position of NSPI. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the year ending December 31, 2011.

All dollar amounts are presented in Canadian dollars.

C.	Seasonal Nature of Operations

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

D.	Use of Management Estimates

The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Management evaluates the Company’s estimates on an on-going basis based upon historical experience, current conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Significant estimates are included in unbilled revenue, allowance for doubtful accounts, inventory, valuation of derivative instruments, depreciation, amortization, regulatory assets and regulatory liabilities (including the determination of the current portion), income taxes (including deferred income taxes), pension and post-retirement benefits, asset retirement obligations (“AROs”) and contingencies. Actual results may differ significantly from these estimates.

E.	Regulatory Matters

Regulatory accounting applies where rates are established by, or subject to approval by, an independent third party regulator; are designed to recover the costs of providing the regulated products or services; and it is reasonable to assume rates are set at levels such that the costs can be charged to and collected from customers.

Regulatory assets represent incurred costs that have been deferred because it is probable that they will be recovered through future rates collected from customers. Management believes that existing regulatory assets are probable of recovery either because the Company received specific approval from the UARB, or due to regulatory precedent set for similar circumstances. If management no longer considers it probable that an asset will be recovered, the deferred costs are charged to income.

Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the deferred revenue is recognized in income.

For regulatory assets and liabilities that are amortized, the amortization is approved by the UARB.

F.	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 included in income.

G.	Revenue Recognition

Operating revenues are recognized when electricity is delivered to customers or when products are delivered and services are rendered. Revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity are recognized at rates approved by the UARB and recorded based on meter readings and estimates, which occur on a systematic basis throughout a month. At the end of each month, the electricity delivered to customers, but not billed, is estimated and the corresponding unbilled revenue is recognized. The accuracy of the unbilled revenue estimate is affected by energy demand, weather, line losses and changes in the composition of customer classes.

H.	Sales Taxes

Sales taxes are collected and remitted by the Company and accounted for on a net basis. Sales taxes are not reflected in the Statements of Income.

I.	Research and Development Costs

Research and development costs are expensed as incurred.

J.	Employee Benefits

The costs of the Company’s pension and other post-employment benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-employment plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes the unamortized gains and losses and past service costs in “Accumulated other comprehensive loss (“AOCL”)”.

K.	Receivables and Allowance for Doubtful Accounts

Customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for bi-monthly customers are 30 days and for monthly customers, payment terms are 20 days. A late payment fee of 1.5 percent may be assessed on account balances after the due date.

The Company is exposed to credit risk with respect to amounts receivable from customers. Credit risk 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.

Management estimates uncollectible accounts receivable after considering historical loss experience and the characteristics of existing accounts. Provisions for losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible.

L.	Inventory

Inventory, consisting of fuel and materials, is measured at the lower of cost or market. Cost is determined using the weighted average method. Fuel and materials are recorded to inventory when purchased and then expensed or capitalized, as appropriate, using the weighted average cost method.

M.	Property, Plant and Equipment

Property, plant and equipment are recorded at original cost, including allowance for funds used during construction (“AFUDC”), net of contributions received in aid of construction.

The cost of additions, including betterments and replacements of units of property are included in “Property, plant and equipment”. When units of regulated property are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation with no gain or loss reflected in income.

Normal maintenance projects are expensed as incurred. Planned major maintenance projects that do not increase the overall life of the related assets are expensed. When maintenance increases the life or value of the underlying asset, the cost is capitalized.

N.	Capitalization Policy

The cost of property, plant and equipment represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property, AROs and overhead directly attributable to the capital project. Overhead includes costs related to support functions, employee benefits, insurance, inventory, and fleet operating and maintenance.

O.	Allowance for Funds Used During Construction

AFUDC represents the cost of financing regulated construction projects with both borrowed and equity funds and is capitalized to the cost of property, plant and equipment in accordance with the accounting policies approved by the UARB. AFUDC is a non-cash item; cash is realized under the rate-making process over the service life of the related property, plant and equipment through future revenues resulting from a higher rate base and recovery of higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to “interest expense”, while the equity component is included as a reduction to “other expenses”. AFUDC is calculated using a weighted average cost of capital as per the method of calculation approved by the UARB. The average annual AFUDC rate for 2011 is 7.87 percent (2010 – 7.96 percent). AFUDC is compounded semi-annually.

P.	Depreciation

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 and are approved by the UARB.

The estimated useful lives, in years, for each major category of property, plant and equipment consist of the following:


Generation			20 to 131
Transmission			39 to 65
Distribution			24 to 75
General plant			7 to 40

Q.	Intangible Assets

Intangible assets consist primarily of land rights and computer software with definite lives. Intangible assets are presented in “Other” as a part of Other assets. 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 and approved by the UARB.

The estimated useful lives, in years, for intangibles with definite lives for 2011 consist of the following:


Land rights			50 to 80
Computer software			10

R.	Asset Impairment

Long-lived assets and intangibles are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. NSPI bases its evaluation of long-lived assets and intangibles on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors. If the sum of the undiscounted cash flows expected from an asset is less than the carrying value of the asset, the asset is written down to fair value.

There were no material asset impairments of these assets for the three and six months ended June 30, 2011 and 2010.

S.	Debt Financing Costs

The Company capitalizes the external costs of obtaining debt financing and includes them in “Other” as part of “Other assets” on the balance sheet. The deferred charge is amortized over the life of the related debt on an effective interest basis and included in “Interest expense, net”.

T.	Income Taxes and Investment Tax Credits

NSPI recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in the financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the balance sheet and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. NSPI recognizes the effect of income tax positions only when it is more likely than not that they will be realized. If management subsequently determines that it is likely that some or all of a deferred income tax asset will not be realized then a valuation allowance is recorded to report the balance at the amount expected to be realized.

Investment tax credits arise as a result of incurring qualifying scientific research and development expenditures and are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not.

NSPI classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively.

U.	Asset Retirement Obligation

An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel.

An ARO represents the fair value of the estimated cash flows necessary to discharge the future obligation using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. Accretion expense is included as part of “Depreciation and amortization”. Any accretion expense not yet approved by the UARB is deferred to a regulatory asset in “Property, plant and equipment” and included in the next depreciation study.

During Q2, NSPI’s estimated future cash flows with respect to AROs have been updated to reflect the results of a settlement agreement with stakeholders which was approved by the UARB, following the completion of a depreciation study. The changes resulted from a change in estimate of retirement dates and future decommissioning costs. The new accretion rates shall come into effect for use in the next General Rate Application (“GRA”) as is presently filed for 2012.

Some transmission and distribution assets may have conditional AROs, which are required to be estimated and recorded as a liability. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at fair value when an amount can be determined.

V.	Derivatives and Hedging Activities

NSPI’s risk management policies and procedures provide a framework through which management monitors various risk exposures. The risk management plan has been approved by the Board of Directors. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operations.

The Company manages its exposure to normal operating and market risks relating to commodity price, and foreign exchange risks using financial instruments consisting mainly of foreign exchange forwards and swaps, and coal, oil and gas options, forwards, and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas, and physical and financial contracts. Collectively these contracts are considered “derivatives”.

The Company recognizes the fair value of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty credit worthy. NSPI continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exception where the criteria are no longer met.

Derivatives entered into by NSPI that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the UARB. These derivatives are recorded at fair value on the balance sheet as derivative assets or liabilities. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized when the derivatives settle. Management believes that any gains or losses resulting from settlement of these derivatives will be refunded to or collected from customers in future rates.

Derivatives that do not meet any of the above criteria are designated as HFT derivatives and are recorded on the balance sheet at fair value, with changes normally recorded in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply.

NSPI classifies gains and losses on derivatives as a component of fuel for generation and purchased power expense, other expenses, inventory and property, plant and equipment, depending on the nature of the item being economically hedged. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Statements of Cash Flows.

W.	Fair Value Measurement

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (refer to notes 12 and 13). Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly arms-length transaction between market participants at the measurement date. Fair value measurements are required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information including the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. The Company uses a fair value hierarchy, based on the relative objectivity of the inputs used to measure fair value, with Level 1 representing the highest.

The three levels of the fair value hierarchy are defined as follows:

Level 1 Valuations - Where possible the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities.

Level 2 Valuations - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses.

Level 3 Valuations - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally developed inputs. The primary reasons for a Level 3 classification are as follows:

•

While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

•

The term of certain transactions extends beyond the period when quoted prices are available, and accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.

•

The valuations of certain transactions were based on internal models although quoted prices were utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

X.	Variable Interest Entities

The Company performs ongoing analysis to assess whether it holds any variable interest entities (“VIEs”). To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements, tolling contracts and jointly owned facilities.

VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the entity that most significantly impact its economic performance and the obligation to absorb losses of the entity that could potentially be significant to the entity. In circumstances where NSPI is not deemed the primary beneficiary, the VIE is not recorded in the Companys’ financial statements.

The Company holds a variable interest in Renewable Energy Services Ltd. (“RESL”), a VIE for which it was determined that NSPI was not the primary beneficiary since it does not have the controlling financial interest of RESL. The Company has provided a $23.5 million guarantee with no set term for the indebtedness of RESL under a loan agreement between RESL and a third party lender, in support of which NSPI holds a security interest in all present and future assets of RESL. The guarantee arose in conjunction with NSPI’s participation in a wind energy project at Point Tupper, Nova Scotia, which is being operated by RESL. Under a purchased power agreement, NSPI purchases, at a fixed price, 100 percent of the power generated by the project. A default by RESL, under its loan agreement, would require NSPI to make payment under the guarantee. As at June 30, 2011, RESL’s indebtedness under the loan agreement was $22.5 million (December 31, 2010 – $23.1 million), and NSPI has not recorded a liability in relation to the guarantee.

The Company has also identified certain long-term purchase power agreements that could be defined as variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.

For the three months and six months ended June 30, 2011, the Company has not identified any new VIEs.

Y.	Derivative Positions and Cash Collateral

Derivatives, as reflected on the balance sheets, are not offset by the fair value amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables, net” and obligations to return cash collateral are recognized in “Accounts payable”.

2.	FUEL ADJUSTMENT

The fuel adjustment related to the fuel adjustment mechanism (“FAM”) includes the effect of fuel costs in both the current and two preceding years, specifically, and as detailed in the table below:

•

The difference between actual fuel costs and amounts recovered from customers in the current period. This amount, net of the incentive component, is deferred to a FAM regulatory asset in “Regulatory assets” or a FAM regulatory liability in “Regulatory liabilities”.

•

The recovery from (rebate to) customers of under (over) recovered costs from prior years.

The fuel adjustment consisted of the following:


For the	Three months ended June 30						Six months ended June 30
millions of Canadian dollars	2011			2010			2011			2010
Under recovery of current year fuel costs	$	(0.2	)	$	(7.5	)	$	(14.2	)	$	(40.5	)
Recovery from (rebate to) customers from prior years		6.4			(5.1	)		14.6			(11.5	)

Fuel adjustment	$	6.2		$	(12.6	)	$	0.4		$	(52.0	)

The Company has recognized a deferred income tax expense related to the fuel adjustment based on NSPI’s enacted statutory tax rate.

The FAM regulatory asset or liability includes amounts recognized as a fuel adjustment and associated interest that is included in “Interest expense, net”. The following table shows the balance sheet classification of the various components of the FAM balances:


As at millions of Canadian dollars	June 30 2011		December 31 2010
Current FAM regulatory asset	$	44.6	$	27.2
Long-term FAM regulatory asset		51.8		65.7
Current deferred income tax liability		14.0		8.8
Long-term deferred income tax liability		16.1		20.4

3.	OTHER EXPENSES, NET

Other expenses, net consisted of the following:


For the	Three months ended June 30						Six months ended June 30
millions of Canadian dollars	2011			2010			2011			2010
Allowance for equity funds used during construction	$	(2.0	)	$	(1.5	)	$	(3.8	)	$	(3.1	)
Amortization of defeasance costs		3.1			3.1			6.1			6.1
Foreign exchange gains		—			—			(0.2	)		(0.5	)
Foreign exchange losses recovered through the FAM		1.4			0.9			2.7			3.7
Other		(0.2	)		(0.2	)		(0.3	)		(0.3	)

	$	2.3		$	2.3		$	4.5		$	5.9

4.	INTEREST EXPENSE, NET

Interest expense, net consisted of the following:


For the	Three months ended June 30						Six months ended June 30
millions of Canadian dollars	2011			2010			2011			2010
Interest on long-term debt	$	29.1		$	26.2		$	58.3		$	52.2
Interest on short-term debt		0.8			0.4			1.7			0.7
Interest revenue		(1.9	)		(0.8	)		(4.0	)		(1.2	)
Allowance for borrowed funds used during construction		(2.1	)		(1.7	)		(4.1	)		(3.4	)
Other		1.1			2.5			2.0			4.4

	$	27.0		$	26.6		$	53.9		$	52.7

Interest on long-term debt includes amortization of debt financing costs, premiums and discounts.

5.	INCOME TAXES

The Company’s effective tax rate for the three months ended June 30, 2011 and June 30, 2010 was (13.3) percent (representing a recovery of income taxes) and 15.5 percent, respectively. The Company’s effective tax rate for the six months ended June 30, 2011 and June 30, 2010 was (11.4) percent and 1.5 percent, respectively. The effective tax rates for the three and six months ended June 30, 2011 and June 30, 2010 were lower than the 2011 and 2010 statutory income tax rates of 32.5 percent and 34.0 percent, respectively, primarily due to deferred income taxes on regulated income deferred to regulatory assets and regulatory liabilities.

Income taxes for the three months ended June 30, 2011 are a recovery of $2.2 million (2010 - $3.2 million expense), and for the six months ended June 30, 2011 are a recovery of $8.6 million (2010 - $1.3 million expense). Income taxes are lower in 2011 compared to 2010 primarily due to decreased income before provision for income taxes, accelerated tax deductions for property, plant and equipment, and a lower statutory income tax rate.

6.	RECEIVABLES, NET

Receivables, net consisted of the following:


As at millions of Canadian dollars	June 30 2011			December 31 2010
Customer accounts receivable – billed	$	114.5		$	74.0
Customer accounts receivable – unbilled		94.0			107.8

Total customer accounts receivable		208.5			181.8
Allowance for doubtful accounts		(3.1	)		(2.5	)

Customer accounts receivable, net		205.4			179.3
Other		14.0			13.2

	$	219.4		$	192.5

7.	INVENTORY

Inventory consisted of the following:


As at millions of Canadian dollars	June 30 2011		December 31 2010
Fuel	$	116.4	$	125.9
Materials		30.9		28.3

	$	147.3	$	154.2

8.	OTHER CURRENT LIABILITIES

Other current liabilities consisted of the following:


As at millions of Canadian dollars	June 30 2011		December 31 2010
Accrued charges	$	26.3	$	27.5
Accrued interest on long-term debt		31.8		29.8
Sales taxes payable		5.6		7.0
Dividends payable		2.0		2.0
Other		1.2		0.9

	$	66.9	$	67.2

9.	REGULATORY MATTERS

The Company is a public utility as defined in the Act and is subject to regulation under the Act by the UARB. The Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. The Company is not subject to a general annual rate review process, but rather participates in hearings held from time to time at the Company’s or the UARB’s request.

NSPI is regulated under a cost-of-service model, with rates set to recover prudently-incurred costs of providing electricity service to customers, and provide an appropriate return to investors. NSPI’s prescribed regulated return on equity (“ROE”) range for 2011 is 9.1 percent to 9.6 percent based on an actual regulated common equity component of up to 40 percent of average regulated capitalization. NSPI has a FAM, which enables NSPI to seek recovery of fuel costs through regularly scheduled rate adjustments. Differences between actual fuel costs and amounts recovered from customers through electricity rates in a period are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in a subsequent period. The FAM has an incentive component, whereby NSPI retains or absorbs 10 percent of the over or under recovered amount to a maximum of $5 million.

On May 13, 2011, NSPI filed a GRA with the UARB requesting an average 7.3 percent rate increase across all customer classes effective January 1, 2012. As an alternative, NSPI publicly proposed a three-year plan that would hold rate increases stable from 2012 to 2014 inclusive. If discussions with customer representatives produce an agreement-in-principle for the alternative plan, NSPI will amend its May 13^th

application filing and request approval from the UARB for the alternative plan. NSPI’s last general rate hearing was settled by agreement with customer representatives on November 5, 2008 and the UARB approved an average 9.28 percent increase in customer rates effective January 1, 2009.

On May 11, 2011, the UARB approved changes to NSPI’s depreciation rates following NSPI’s completion of a depreciation study and a settlement agreement with stakeholders. The overall impact on the average depreciation rate is not material. The new depreciation rates shall come into effect for use in the next GRA as presently filed for 2012.

On December 23, 2010, the UARB granted NSPI approval to defer $14.5 million of tax benefits which arose in 2010 related to renewable energy projects. Accordingly, effective December 31, 2010, NSPI recognized a $14.5 million regulatory liability through an increase in regulatory amortization.

On December 8, 2010, as part of the FAM regulatory process, the UARB approved NSPI’s setting of the 2011 base cost of fuel and the under-recovered fuel related costs from prior years. The UARB approved the recovery of the prior year FAM balance from customers over three years effective January 1, 2011, with 50 percent to be recovered in 2011, 30 percent in 2012 and 20 percent in 2013. The decision resulted in an average rate increase of approximately 4.5 percent for customers in 2011. Pursuant to the FAM Plan of Administration, NSPI is entitled to earn a return on the balance of fuel related costs.

10.

COMMITMENTS AND CONTINGENCIES

A.	Commitments

As at June 30, 2011, commitments (excluding pension and other post-retirement benefits, long-term debt, and AROs) for each of the next five years and in aggregate thereafter consisted of the following:


millions of Canadian dollars	2011		2012		2013		2014		2015		Thereafter		Total
Purchased power (1)	$	31.6	$	76.0	$	84.6	$	84.4	$	84.4	$	1,206.6	$	1,567.6
Coal, biomass, oil and natural gas supply		106.0		198.6		130.0		65.6		21.9		613.7		1,135.8
Transportation (2)		36.3		49.2		10.7		9.7		0.4		—		106.3
Long-term service agreements (3)		2.2		4.5		4.5		4.3		4.4		0.5		20.4
Capital projects		34.7		35.5		5.7		—		—		—		75.9
Leases (4)		1.0		0.4		0.4		0.3		0.3		1.4		3.8
Other		0.6		0.5		0.2		—		—		—		1.3

Total	$	212.4	$	364.7	$	236.1	$	164.3	$	111.4	$	1,822.2	$	2,911.1

(1)	Purchased power: annual requirement to purchase 100 percent of electricity production from independent power producers over varying contract lengths up to 25 years.

(2)	Transportation: purchasing commitments for transportation of solid fuel and transportation capacity on the Maritimes & Northeast Pipeline (“M&NP”).

(3)	Long-term service agreements: outsourced management of the Company’s computer and communication infrastructure.

(4)	Leases: operating lease agreements for office space and rail cars.

B.	Legal Proceedings

A number of individuals who live in proximity to the Company’s Trenton generating station have filed a statement of claim for an unspecified amount against NSPI in respect of emissions from the operation of the plant for the period from 2001 forward. 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 Company has filed a defense to the claim. The outcome of this litigation, and therefore an estimate of any contingent loss, is 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.

C.	Environment

NSPI is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters primarily through its utility operations. In addition to imposing continuing compliance obligations, there are laws, regulations and permits authorizing the imposition of penalties for non-compliance, including fines, injunctive relief and other sanctions. The cost of complying with current and future environmental requirements is material to the Company. Failure to comply with environmental requirements or to recover environmental costs in a timely manner through rates could have a material adverse effect.

Conformance with legislative and Company requirements are verified through a comprehensive environmental audit program. There were no significant environmental or regulatory compliance issues identified during the 2011 and 2010 audits.

Climate Change and Air Emissions

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

On May 19, 2011 the Nova Scotia Government approved The Electricity Act (Amended) to facilitate the eligibility of energy from the Lower Churchill Project in Labrador as a resource for meeting Nova Scotia’s renewable electricity targets. The amendment will allow regulations to be developed requiring an increase in the percentage of renewable energy in the generation mix from the planned 25 percent in 2015, to 40 percent by 2020.

On April 11, 2011, the Nova Scotia Government announced that the cap on the annual amount of new forest biomass that can be used to generate electricity will be lowered by 30 percent to 350,000 dry tonnes per year. NSPI’s 60 megawatt (“MW”) Port Hawkesbury Biomass Project is not affected by this announcement.

In April 2007, the province of Nova Scotia enacted an Act Respecting Environmental Goals and Sustainable Prosperity. Within this act, there is an objective to reduce provincial greenhouse gas emissions to 10 percent below 1990 levels by 2020. In January 2009, the Province released its 2009 Energy Strategy and Climate Change Action Plan. These documents provide the elements of the plan to achieve this objective. In August 2009, the Province enacted regulations to cap greenhouse gas emissions from the electricity sector in Nova Scotia.

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

Greenhouse gas emissions from NSPI facilities are capped beginning in 2010 through to 2020. The 2010 to 2012 caps will be achieved by the continued success of energy efficiency and conservation programs and the addition of renewable energy to meet the provincial renewable energy standards. The regulations also include a transmission incentive compliance mechanism recognizing expenditures on transmission which facilitates additional renewable energy sources. Up to 3 percent of the annual cap can be offset in this way to 2019. Further, the 2010 to 2020 period years are combined to form multi-year compliance periods recognizing the variability in electricity supply sources and demand. It is anticipated that the 2013 through 2015 caps will be achieved by successful energy efficiency and conservation programs and adding renewable energy to meet the provincial 2013 renewable energy standards. Beyond 2014, reduced greenhouse gas emissions will be achieved through a combination of additional renewable energy, import of non-emitting energy, energy efficiency and conservation. The Canadian federal government has announced a proposed policy framework for greenhouse gas reductions from the

coal generating units within the electricity sector. The proposed framework has a performance based standard to be achieved upon a coal fired generating unit reaching its 45 year anniversary. The first year of regulation would be 2015.

Mercury

In 2008, NSPI carried out extensive testing on mercury abatement technology in its coal power plants. A capital program to add sorbent injection to each of the seven pulverized fuel coal units was completed in 2010 at a cost of $17.3 million. This was put in place to address a change in the mercury emissions limit, moving from 168 kilograms (“kg”) per year to 65 kg per year beginning in 2010. In the fall of 2010, the Nova Scotia government amended the limits to allow 110 kg in 2010, 100 kg in 2011, 100 kg in 2012, 85 kg in 2013, 65 kg annually for the period 2014 through 2019 and 35 kg in 2020. Any mercury emission above 65 kg, between 2010 and 2013, must be offset by lower emissions in the 2014 to 2020 period.

Nitrogen Oxide and Sulphur Dioxide Emissions

NSPI has completed its capital program of retrofitting low nitrogen oxide combustion firing systems on six of its seven pulverized fuel coal units in early 2009 at a cost of $23.3 million. NSPI now meets the nitrogen oxide emission cap of 21,365 tonnes per year established by the Province of Nova Scotia effective 2010. These investments, combined with the purchasing of compliance coal, allows NSPI to meet the provincial air quality regulations. Compared to historical levels, NSPI will have reduced mercury emissions by 60 percent effective 2014, nitrogen oxide by 40 percent effective 2009 and sulphur dioxide by 50 percent effective 2010.

Poly Chlorinated Bi-Phenol Transformers

In response to the Canadian Environmental Protection Act 1999, 2008 Poly Chlorinated Bi-Phenol (“PCB”) Regulations to phase out electrical equipment and liquids containing PCBs, NSPI has implemented a program to eliminate transformers and other electrical equipment on its system that do not meet the 2008 PCB Regulations Standard. NSPI is in the process of testing electrical equipment over a four year period. The project completion date had been extended to 2014.The cost of testing the electrical equipment, replacement of electrical equipment, the cost to install that electrical equipment and the cost of destroying PCB contaminated electrical equipment are capitalized. In addition, in response to the 2008 PCB Regulations Standard, there is a project to phase out the use of pole mount transformers before 2025. Currently, there is a capital program to destroy all confirmed PCB contaminated pole mount transformers taken out of service through attrition. The combined total cost of these projects is estimated to be $31.0 million and, as at June 30, 2011 approximately $5.4 million (December 31, 2010 - $5.4 million) has been spent to test, replace and remediate PCB contaminated electrical equipment and liquids in this effort to date.NSPI has recognized an ARO of $14.0 million as at June 30, 2011 (December 31, 2010 - $13.9 million) associated with the PCB phase-out program.

D.	Environmental Regulations

NSPI’s activities are subject to a broad range of federal, provincial, regional and local laws and environmental regulations, designed to protect, restore, and enhance the quality of the environment including air, water and solid waste. NSPI estimates its environmental capital expenditures, excluding AFUDC, based upon present environmental laws and regulations will be approximately $68.0 million during 2011 and $560.0 million from 2012 through 2015. Amounts that have been committed are included in “Capital projects” in the commitments included in note 10A. The estimated expenditures do not include costs related to possible changes in the environmental laws or regulations and enforcement policies may be enacted in response to issues such as climate change and other pollutant emissions.

E.	Risks and Uncertainties

In this section, NSPI describes some of the principal risks management believes could materially affect NSPI’s business, revenues, operating income, net income, net assets or liquidity or capital resources. The nature of risk is such that no list can be comprehensive, and other risks may arise or risks not currently considered material may become material in the future.

Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. NSPI has a business-wide risk management process, monitored by the Board of Directors, to ensure a consistent and coherent approach.

Principal Risks

Regulatory risk

The Company is regulated by the UARB and is subject to risk in the recovery of costs and investments in a timely manner. The Company manages this risk through ongoing stakeholder consultation and engagement on aspects such as utility operations, rate filings and capital plans.

Changes in environmental legislation

The Company is subject to regulation by federal, provincial and municipal authorities with regard to environmental matters primarily related to its utility operations. Changes to climate change and air emissions standards could adversely affect utility operations.

NSPI is committed to operating in a manner that is respectful and protective of the environment and in full compliance with legal requirements and Company policy. NSPI has implemented this policy through development and application of environmental management systems (“EMS”).

Commodity prices and foreign exchange rate fluctuations in fuel prices

Commodity price fluctuations related to the purchase of fuel for generation and foreign exchange fluctuations on foreign currency denominated purchases of fuel affect NSPI’s fuel costs. Fuel contracts may be exposed to broader global conditions which may include impacts on delivery reliability and price, despite contracted terms. The Company seeks to manage this risk through the use of financial hedging instruments and physical contracts. The adoption and implementation of the FAM, effective January 1, 2009, has further helped NSPI manage this risk.

Commercial relationships

NSPI’s largest customer contributed approximately 9.0 percent (2010 – 8.6 percent) of NSPI’s electric revenues for the three months ended June 30, 2011 and 7.7 percent (2010 – 7.6 percent) for the six months ended June 30, 2011. The five largest customers contributed approximately 16.6 percent (2010 – 15.0 percent) of NSPI’s electric revenues for the three months ended June 30, 2011 and 14.7 percent (2010 – 13.9 percent) for the six months ended June 30, 2011.

Relationships with employees

Certain NSPI employees are subject a collective labour agreement. Approximately 52 percent of NSPI’s full time employees and term employees are represented by a local union affiliated with the International Brotherhood of Electrical Workers.

Weather risk

Shifts in weather patterns affect electric sales volumes and associated revenues with increased volatility in the winter months attributed to heating loads. Extreme weather events generally result in increased operating costs associated with restoring power to customers. NSPI responds to significant weather event related outages according to its Emergency Services Restoration Plan.

F.	Guarantees and Letters of Credit

NSPI had the following guarantees and letters of credits as at June 30, 2011:

•

NSPI has provided a limited guarantee for the indebtedness of RESL. The guarantee is up to a maximum of $23.5 million. As at June 30, 2011 RESL’s indebtedness under the loan agreement was $22.5 million. NSPI holds a security interest in the assets of RESL and all future assets of the project owned by RESL. For further information see note 1X.

•

A financial institution has issued a standby letter of credit in the amount of 1.2 million EURO to support NSPI’s operations. The letter of credit has a one year term and is renewed as required. The amount committed as at June 30, 2011 was $1.5 million.

•

A financial institution has issued a standby letter of credit to secure obligations under an unfunded pension plan in NSPI. The letter of credit expires in June 2012 and is renewed annually. The amount committed as at June 30, 2011 was $22.5 million.

No liability has been recognized on the balance sheet related to any potential obligation under these guarantees and letters of credits.

11.

EMPLOYEE BENEFIT PLANS

NSPI maintains contributory defined-benefit and defined-contribution pension plans, which cover substantially all of its employees and plans providing non-pension benefits for its retirees.

Net periodic costs prior to the effects of capitalization consisted of the following:


For the	Three months ended June 30						Six months ended June 30
millions of Canadian dollars	2011			2010			2011			2010
Defined benefit pension plans
Service cost	$	3.3		$	2.3		$	6.7		$	4.5
Interest cost		12.6			12.5			25.2			25.1
Expected return on plan assets		(12.5	)		(12.4	)		(25.0	)		(24.8	)
Current year amortization of:
Actuarial losses		5.7			2.4			11.3			4.8
Past service costs		(0.1	)		—			(0.1	)		—

Total defined benefit pension plans		9.0			4.8			18.1			9.6

Non-pension benefits plan
Service cost		0.3			0.3			0.8			0.7
Interest cost		0.6			0.6			1.1			1.2
Current year amortization of:
Actuarial losses (gains)		—			—			0.1			(0.1	)
Past service costs		0.1			—			0.1			0.1

Total non-pension benefits plans		1.0			0.9			2.1			1.9

Total defined benefit plans	$	10.0		$	5.7		$	20.2		$	11.5

The Company contributions related to defined-benefit plans for the three months ended June 30, 2011 were $9.7 million (2010 – $9.9 million), and for the six months ended June 30, 2011 were $19.7 million (2010 - $17.8 million).

In addition, the Company contributions related to the defined-contribution plan for the three months ended June 30, 2011 were $0.3 million (2010 – $0.3 million), and for the six months ended June 30, 2011 were $0.7 million (2010 - $0.6 million).

12.

DERIVATIVE INSTRUMENTS

Physical contracts that meet the NPNS exception are not recognized on the balance sheet; they are recognized in income when they settle. The Company continually assesses contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exception if the criteria are no longer met.

Derivatives entered into by NSPI, that are documented as economic hedges, and for which the NPNS exception has not been taken, receive regulatory deferral as approved by the UARB. These derivatives are recorded at fair value on the balance sheet. The change in fair value of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized when the derivatives settle. Management believes that any gains or losses resulting from settlement of these derivatives will be refunded to or collected from customers in future rates.

Derivative assets and liabilities receiving regulatory deferral consisted of the following:


	Derivative Assets						Derivative Liabilities
As at millions of Canadian dollars	June 30 2011			December 31 2010			June 30 2011			December 31 2010
Current
Commodity swaps and forwards
Coal purchases	$	21.3		$	23.6		$	0.5		$	1.9
Natural gas purchases and sales		0.2			0.8			9.3			20.3
Heavy fuel oil (“HFO”) purchases		—			1.9			—			1.3
Foreign exchange forwards		0.2			2.1			5.9			1.2
Physical natural gas purchases and sales		4.6			4.3			0.1			—

Total gross current derivatives		26.3			32.7			15.8			24.7
Impact of master netting agreements with intent to settle net or simultaneously		(0.5	)		(1.7	)		(0.5	)		(1.7	)

Total current derivatives		25.8			31.0			15.3			23.0

Long-term
Commodity swaps and forwards
Coal purchases		16.3			18.5			—			—
Natural gas purchases and sales		0.3			0.1			0.6			1.8
Foreign exchange forwards		0.4			2.2			21.6			9.4
Physical natural gas purchases and sales		5.7			8.1			—			—

Total gross long-term derivatives		22.7			28.9			22.2			11.2
Impact of master netting agreements with intent to settle net or simultaneously		(0.2	)		—			(0.2	)		—

Total long-term derivatives		22.5			28.9			22.0			11.2

Total derivatives	$	48.3		$	59.9		$	37.3		$	34.2

Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying contracts.

Regulatory Deferral

As previously noted, NSPI receives approval from the UARB for regulatory deferral of gains and losses on certain derivatives documented as economic hedges that do not qualify for hedge accounting, including certain physical contracts that do not qualify for the NPNS exception. The Company has recorded the following unrealized gains (losses) with respect to derivatives receiving regulatory deferral:


	Regulatory Assets						Regulatory Liabilities
For the three months ended millions of Canadian dollars	June 30 2011			June 30 2010			June 30 2011			June 30 2010
Current
Commodity swaps and forwards
Coal purchases	$	0.2		$	(8.0	)	$	2.3		$	(1.1	)
Natural gas purchases and sales		(1.4	)		(3.4	)		1.4			(0.3	)
HFO purchases		—			(0.5	)		—			1.2
Foreign exchange forwards		1.1			(13.7	)		(0.1	)		(6.4	)
Physical natural gas purchases and sales		—			(9.3	)		0.1			(0.6	)
Long-term
Commodity swaps and forwards
Coal purchases		—			(9.8	)		5.1			(6.7	)
Natural gas purchases and sales		—			(1.3	)		0.1			—
Foreign exchange forwards		1.7			(4.7	)		(0.4	)		(20.7	)
Physical natural gas purchases and sales		—			(0.1	)		1.2			0.8


	Regulatory Assets						Regulatory Liabilities
For the six months ended millions of Canadian dollars	June 30 2011			June 30 2010			June 30 2011			June 30 2010
Current
Commodity swaps and forwards
Coal purchases	$	(0.8	)	$	(7.8	)	$	1.7		$	(0.8	)
Natural gas purchases and sales		(10.2	)		(1.9	)		(0.1	)		(0.5	)
HFO purchases		(1.3	)		(1.9	)		1.9			8.8
Foreign exchange forwards		4.3			(14.0	)		1.9			(6.7	)
Physical natural gas purchases and sales		0.1			4.6			(0.2	)		(1.4	)
Long-term
Commodity swaps and forwards
Coal purchases		—			(9.4	)		2.2			(4.4	)
Natural gas purchases and sales		(1.5	)		(0.5	)		—			(0.1	)
HFO purchases		—			(1.3	)		—			2.0
Foreign exchange forwards		12.2			(2.6	)		1.8			(11.3	)
Physical natural gas purchases and sales		—			—			2.4			1.9

Regulatory Impact Recognized in Net Income

The Company recognized in net income the following net losses related to derivatives receiving regulatory deferral:


millions of Canadian dollars	Three months ended June 30						Six months ended June 30
	2011			2010			2011			2010
Other expenses, net increase		—		$	(2.0	)		—		$	(1.0	)
Fuel for generation and purchased power increase	$	(1.3	)		(8.1	)	$	(16.9	)		(45.2	)

Total losses	$	(1.3	)	$	(10.1	)	$	(16.9	)	$	(46.2	)

Commodity Swaps and Forwards

As at June 30, 2011, the Company had the following notional volumes of outstanding commodity swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:

2011

2012

2013

2014

millions

Purchases

Coal (metric tonnes)

0.6

0.5

0.3

0.1

Natural gas (Mmbtu)

13.3

12.9

1.8

—

Foreign Exchange Swaps and Forwards

As at June 30, 2011, the Company had the following notional volumes of foreign exchange swaps and forward contracts designated for regulatory deferral that are expected to settle as outlined below:


	2011			2012			2013			2014			2015
Fuel purchases exposure (millions of Canadian dollars)	$	83.0		$	256.0		$	150.0		$	150.0		$	150.0
Weighted average rate		0.9923			0.9912			1.0505			1.0246			1.0213
% of USD requirements		41.4	%		60.4	%		35.4	%		35.4	%		35.4	%

Credit Risk

The Company is exposed to credit risk with counterparties to its derivatives. Credit risk is the potential loss resulting from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as at June 30, 2011, substantially all of the counterparties with transaction amounts outstanding in the Company’s derivatives portfolio are rated “investment grade” by the major rating agencies. The Company assesses credit risk internally for counterparties that are not rated.

The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements (“ISDA”), North American Energy Standards Board agreements (“NAESB”) and, or Edison Electric Institute Agreements. The Company believes that entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default.

The Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability.

Cash Collateral

The Company’s cash collateral positions consisted of the following:


As at millions of Canadian dollars	June 30 2011		December 31 2010
Cash collateral provided to others		—	$	2.5
Cash collateral received from others		—		—

Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivatives contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt to fall below investment grade, the counterparties to such derivatives could request ongoing full collateralization.

As at June 30, 2011, the total fair value of these derivatives, in a net liability position, is $37.3 million (December 31, 2010 – $34.2 million). If the credit ratings of the Company were reduced below investment grade the full value of the net liability position could be required to be posted as collateral for these derivatives.

13.

FAIR VALUE MEASUREMENTS

The Company is required to determine the fair value of all derivatives except those which qualify for the NPNS exception (see note 12), and uses a market approach to do so.

The three levels of the fair value hierarchy are defined as follows:

•

While valuations were based on quoted prices, significant assumptions were necessary to reflect seasonal or monthly shaping and locational basis differentials.

•

The valuations of certain transactions were based on internal models although quoted prices were utilized in the valuations.

Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

The following tables set out the classification of the methodology used by the Company to fair value its derivatives at June 30, 2011 and December 31, 2010:


As at millions of Canadian dollars	June 30, 2011
As at millions of Canadian dollars	Level 1			Level 2		Level 3		Total
Assets
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—		$	37.3		—	$	37.3
Natural gas purchases and sales	$	0.2			—		—		0.2
Foreign exchange forwards		—			0.6		—		0.6
Physical natural gas purchases and sales		—			—	$	10.2		10.2

Total assets		0.2			37.9		10.2		48.3

Liabilities
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			0.2		—		0.2
Natural gas purchases and sales		9.6			—		—		9.6
Foreign exchange forwards		—			27.5		—		27.5

Total liabilities		9.6			27.7		—		37.3

Net (liabilities) assets	$	(9.4	)	$	10.2	$	10.2	$	11.0


As at millions of Canadian dollars	December 31, 2010
As at millions of Canadian dollars	Level 1			Level 2		Level 3		Total
Assets
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—		$	41.2		—	$	41.2
Natural gas purchases and sales	$	0.1			—		—		0.1
HFO purchases		—			1.9		—		1.9
Foreign exchange forwards		—			4.3		—		4.3
Physical natural gas purchases and sales		—			—	$	12.4		12.4

Total assets		0.1			47.4		12.4		59.9

Liabilities
Regulatory deferral
Commodity swaps and forwards
Coal purchases		—			1.0		—		1.0
Natural gas purchases and sales		21.3			—		—		21.3
HFO purchases		—			1.3		—		1.3
Foreign exchange forwards		—			10.6		—		10.6

Total liabilities		21.3			12.9		—		34.2

Net (liabilities) assets	$	(21.2	)	$	34.5	$	12.4	$	25.7

The change in the fair value of the Level 3 financial assets for the three months ended June 30, 2011 was as follows:


millions of Canadian dollars	Physical Natural Gas Purchases and Sales
Balance, March 31	$	11.4
Reduction of benefit included in fuel for generation and purchased power		(1.0	)
Unrealized losses included in regulatory assets or liabilities		(0.2	)

Balance, June 30	$	10.2

The change in the fair value of the Level 3 financial liabilities for the three months ended June 30, 2011 was as follows:


millions of Canadian dollars	Physical Natural Gas Purchases and Sales
Balance, March 31	$	(0.1	)
Benefit included in fuel for generation and purchased power		0.1

Balance, June 30		—	��

The change in the fair value of the Level 3 financial assets for the six months ended June 30, 2011 was as follows:


millions of Canadian dollars	Physical Natural Gas Purchases and Sales
Balance, January 1	$	12.4
Reduction of benefit included in fuel for generation and purchased power		(2.2	)

Balance, June 30	$	10.2

The change in the fair value of the Level 3 financial liabilities for the six months ended June 30, 2011 was as follows:


millions of Canadian dollars	Physical Natural Gas Purchases and Sales
Balance, January 1		—
Benefit included in fuel for generation and purchased power	$	0.1
Unrealized losses included in regulatory assets or liabilities		(0.1	)

Balance, June 30		—

The Company recognizes transfers at the end of the reporting period.

The financial assets and liabilities included on the balance sheets that are not measured at fair value consisted of the following:

As at

millions of Canadian dollars

June 30, 2011

December 31, 2010

Carrying
Amount

Fair
Value

Carrying
Amount

Fair Value

Long-term debt (including current portion)

1,894.6

2,236.0

1,952.3

2,293.5

The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturity, without considering the effect of third party credit enhancements.

All other financial assets and liabilities such as cash, receivables, short-term debt and accounts payable are carried at cost. The carrying value approximates fair value due to the short-term nature of these financial instruments.

14.

RELATED PARTY TRANSACTIONS

The Company enters into transactions with related parties in the normal course of operations. All related party transactions with NSPI are governed by an affiliate Code of Conduct that is approved by the UARB.

NSPI, Emera Energy Services (“EES”), Bangor Hydro Electric Company (“Bangor Hydro”) and Emera Utility Services (“EUS”) are wholly owned subsidiaries of Emera Incorporated (“Emera”). Emera owns a 12.9 percent interest in M&NP.

Related party transactions are summarized in the following table:

For the

millions of Canadian dollars

Three months
ended
June 30

Six months
ended
June 30

Nature of Service

Presentation

2011

2010

2011

2010

Sales:

EUS

Steam sales

Operating revenues

—

0.2

0.1

Emera

Corporate support and other services

Operating, maintenance and general

0.6

0.8

1.4

1.6

EES

Corporate support and other services

Operating, maintenance and general

0.3

0.3

0.6

0.6

Bangor Hydro

Corporate support and other services

Operating, maintenance and general

0.3

0.3

0.5

0.5

Other

Corporate support and other services

Operating, maintenance and general

0.2

0.1

0.6

0.4

Purchases:

EES

Net purchase of electricity

Fuel for generation and purchased power – affiliates

—

4.7

—

5.7

EES

Net purchase of natural gas

Fuel for generation and purchased power – affiliates

0.4

0.1

0.1

0.7

EUS

Maintenance services

Operating, maintenance and general

0.9

0.1

5.0

0.6

EUS

Purchase of inventory

Inventory

0.1

0.4

0.4

0.7

EUS

Construction services

Property, plant and equipment

3.6

11.8

5.8

14.8

Beginning in Q2 2011, NSPI has recorded the impact of two agreements related to the purchase of power and receipt of contract revenues from Emera on a net basis on the statements of income. Under the agreements, NSPI purchased power from Emera and received contract revenues from Emera of $2.5 million (2010 – nil) for the three months ended June 30, 2011 and $4.9 million (2010 – nil) for the six months ended June 30, 2011. Prior interim periods have been reclassified to reflect this change.

In the ordinary course of business, the Company purchased $4.1 million (2010 – $4.8 million) in natural gas transportation capacity from M&NP during the three months ended June 30, 2011, and $8.3 million (2010 - $9.2 million) for the six months ended June 30, 2011. The amount is recognized in “Fuel for generation and purchased power” and is measured at the exchange amount. As at June 30, 2011, the amount payable to M&NP is $1.5 million (December 31, 2010 – $1.0 million) and is under normal interest and credit terms.

During the three months ended June 30, 2011, the Company issued nil common shares (2010 – 5.0 million) to Emera and an affiliate under common control of Emera for total consideration of nil (2010 - $50.0 million). During the six months ended June 30, 2011, the Company issued 5.0 million (2010 – 5.0 million) common shares to Emera and an affiliate under common control of Emera for total consideration of $50.0 million (2010 - $50.0 million).

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. As at June 30, 2011 and December 31, 2010, there were no amounts due.

Amounts due (to) from associated companies are summarized in the following table:


As at millions of Canadian dollars	June 30 2011			December 31 2010
Due from associated companies:
EES		—		$	0.7
Emera	$	1.6			—

		1.6			0.7

Due to associated companies:
EUS		(1.6	)		(5.5	)
EES		(0.4	)		—
Emera		—			(1.4	)

		(2.0	)		(6.9	)

Net due to associated companies	$	(0.4	)	$	(6.2	)

15.

USGAAP TRANSITION

ADOPTION OF USGAAP

In February 2008, the Canadian Institute of Chartered Accountants (“CICA”) announced that CGAAP for publically accountable enterprises, would be replaced by International Financial Reporting Standards (“IFRS”) for fiscal years beginning on or after January 1, 2011. In Q4 2009, due primarily to the continued uncertainty around the applicability of a rate-regulated accounting standard under IFRS, management of Emera, NSPI’s parent company, reviewed the option of adopting USGAAP instead of IFRS. In Q1 2010, the Company decided to transition to USGAAP as recommended by management. The adoption of USGAAP has been made on a retrospective basis with restatement of prior periods’ financial statements to reflect USGAAP requirements in effect at that time.

For annual reporting purposes, the transition date to USGAAP is January 1, 2010, which is the commencement of the 2010 comparative period to the Company’s 2011 financial statements.

As a result of NSPI’s decision to transition to USGAAP, effective January 1, 2011, there was an amendment to the Company’s regulated accounting policy for financial instruments and hedges which was approved by the UARB. The effects of this amendment were applied retrospectively, in accordance with that policy, without restatement of prior period income. The adjustments related to the amended accounting policy have been included with the adjustments as described further in this note.

Measurement, classification and disclosure differences arising out of the Company’s election to adopt USGAAP are presented below. With respect to measurement and classification differences, Section I “USGAAP differences”, presents quantitative reconciliations of balance sheets, income statements and statements of cash flows, previously presented in accordance with CGAAP, to the respective amounts and classifications under USGAAP, together with descriptions of the various significant measurement and classification differences arising from the adoption of USGAAP. Balance sheet reconciliations are presented as at January 1, 2010 and December 31, 2010, representing the commencement and ending dates of the comparative financial year to 2011. Income statement and statement of cash flow reconciliations are presented for the three, six and nine months ended March 31, 2010, June 30, 2010 and September 30, 2010, respectively, and for the year ended December 31, 2010, which are periods that will be presented as comparatives to 2011 financial reporting.

In addition, USGAAP requires certain disclosures of financial information, significant to the Company, that are in addition to the required disclosure under CGAAP. This information, which is as at December 31, 2010, is presented in Section II “Additional disclosures required under USGAAP”.

Except as otherwise disclosed in this note, the change in basis of accounting from CGAAP to USGAAP did not materially impact accounting policies or disclosures. Reference should be made to the previously filed CGAAP financial statements as at and for the year ended December 31, 2010 for additional information on CGAAP accounting policies and practices.

The following table summarizes the increases (decreases) to total assets:


As at millions of Canadian dollars	January 1 2010			December 31 2010
Total assets – CGAAP	$	3,465.3		$	3,991.3
Note A – Offsetting		(0.9	)		—
Note B – Income taxes		16.1			(128.5	)
Note E – Hedging		95.9			39.1
Note I – Pension and other post-retirement benefits		(94.3	)		(110.7	)
Note J – Issue costs		14.8			16.8
Other		—			(0.2	)

Total transition adjustments		31.6			(183.5	)

Total assets – USGAAP	$	3,496.9		$	3,807.8

The following table summarizes the increases (decreases) to total liabilities:


As at millions of Canadian dollars	January 1 2010			December 31 2010
Total liabilities – CGAAP	$	2,379.9		$	2,779.8
Note A – Offsetting		(0.9	)		—
Note B – Income taxes		17.3			(123.1	)
Note E – Hedging		51.9			49.8
Note I – Pension and other post-retirement benefits		168.6			259.5
Note J – Issue costs		15.9			17.9
Note M – Redeemable preferred stock		(134.0	)		(134.1	)
Note N – Share based compensation		0.9			1.1
Other		—			(0.1	)

Total transition adjustments		119.7			71.0

Total liabilities – USGAAP	$	2,499.6		$	2,850.8

The following table summarizes the increases (decreases) to net income:


For the millions of Canadian dollars	3 months ended March 31 2010		6 months ended June 30 2010			9 months ended September 30 2010			Year ended December 31 2010
Net income attributable to common shareholders - CGAAP	$	63.3	$	78.2		$	100.6		$	121.3
Note B – Income taxes		1.2		1.4			(3.0	)		(4.2	)
Note I – Pension and other post-retirement benefits		0.6		1.1			1.7			2.3
Note M – Redeemable preferred stock		—		0.1			0.1			0.1
Note N – Share based compensation		—		—			(0.1	)		(0.2	)
Other		0.1		(0.1	)		—			(0.1	)

Total transition adjustments		1.9		2.5			(1.3	)		(2.1	)

Net income attributable to common shareholders – USGAAP	$	65.2	$	80.7		$	99.3		$	119.2

Section I. USGAAP differences

The reconciliations of the January 1, 2010 and December 31, 2010 balance sheets from CGAAP to USGAAP are as follows:


As at January 1, 2010 millions of Canadian dollars	Notes		CGAAP		Effect of transition to USGAAP			USGAAP
Assets
Current assets
Cash			$	0.3		—		$	0.3
Receivables, net		A		271.8	$	(0.9	)		270.9
Inventory				165.6		—			165.6
Deferred income taxes		B		34.4		(22.3	)		12.1
Derivatives in a valid hedging relationship		C		19.4		(19.4	)		—
Held-for-trading derivatives		C		8.9		(8.9	)		—
Derivative instruments		C		—		28.3			28.3
Regulatory assets		D, E		—		122.7			122.7
Prepaid expenses				5.7		—			5.7
Other current assets		F		—		1.5			1.5

Total current assets				506.1		101.0			607.1

Property, plant and equipment		B, G		2,365.6		153.8			2,519.4
Construction work-in-progress		G		152.8		(152.8	)		—

				2,518.4		1.0			2,519.4

Other assets
Deferred income taxes		B		—		61.4			61.4
Derivatives in a valid hedging relationship		C		29.8		(29.8	)		—
Held-for-trading derivatives		C		6.2		(6.2	)		—
Derivative instruments		C		—		36.0			36.0
Regulatory assets		B, D, E		—		193.0			193.0
Intangibles		H		65.7		(65.7	)		—
Other		B, D, F, H, I, J		339.1		(259.1	)		80.0

Total other assets				440.8		(70.4	)		370.4

Total assets			$	3,465.3	$	31.6		$	3,496.9


As at January 1, 2010 millions of Canadian dollars	Notes		CGAAP			Effect of transition to USGAAP			USGAAP
Liabilities and Equity
Current liabilities
Short-term debt			$	198.2		$	0.1		$	198.3
Current portion of long-term debt				100.7			—			100.7
Accounts payable		A, K		—			151.7			151.7
Accounts payable and accrued charges		K		213.9			(213.9	)		—
Due to associated companies		N		0.7			0.9			1.6
Income taxes payable		B		1.2			2.1			3.3
Dividends payable		L		1.7			(1.7	)		—
Derivatives in a valid hedging relationship		C		53.0			(53.0	)		—
Held-for-trading derivatives		C		12.2			(12.2	)		—
Derivative instruments		C		—			65.2			65.2
Pension and post-retirement liabilities		I		—			8.3			8.3
Regulatory liabilities		B, D, E		—			45.6			45.6
Other current liabilities		B, F, K, L, M		—			65.9			65.9

Total current liabilities				581.6			59.0			640.6

Long-term liabilities
Long-term debt		J, M		1,397.0			16.5			1,413.5
Deferred income taxes		B		52.0			(52.0	)		—
Derivatives in a valid hedging relationship		C		20.0			(20.0	)		—
Held-for-trading derivatives		C		1.3			(1.3	)		—
Derivative instruments		C		—			21.3			21.3
Pension and post-retirement liabilities		I		—			221.2			221.2
Regulatory liabilities		B, D, E		—			87.1			87.1
Asset retirement obligations				101.5			—			101.5
Other long-term liabilities		D, F, I		91.5			(77.1	)		14.4
Preferred shares		M		135.0			(135.0	)		—

Total long-term liabilities				1,798.3			60.7			1,859.0

Redeemable preferred stock		M		—			132.2			132.2

Equity
Common stock				934.7			—			934.7
Accumulated other comprehensive loss		E, I		(44.0	)		(212.1	)		(256.1	)
Retained earnings		B, I, J, M, N		194.7			(8.2	)		186.5

Total equity				1,085.4			(220.3	)		865.1

Total liabilities and equity			$	3,465.3		$	31.6		$	3,496.9


As at December 31, 2010 millions of Canadian dollars	Notes		CGAAP		Effect of transition to USGAAP			USGAAP
Assets
Current assets
Cash			$	0.3		—		$	0.3
Receivables, net				192.5		—			192.5
Income taxes receivable		B		40.6	$	(6.3	)		34.3
Inventory				154.2		—			154.2
Deferred income taxes		B		4.1		(4.1	)		—
Derivatives in a valid hedging relationship		C		24.7		(24.7	)		—
Held-for-trading derivatives		C		6.3		(6.3	)		—
Derivative instruments		C		—		31.0			31.0
Regulatory assets		D, E		—		71.8			71.8
Prepaid expenses				6.1		(0.1	)		6.0
Other current assets		F		—		1.8			1.8

Total current assets				428.8		63.1			491.9

Property, plant and equipment		B, G		2,669.0		280.5			2,949.5
Construction work-in-progress		G		279.2		(279.2	)		—

				2,948.2		1.3			2,949.5

Other assets
Deferred income taxes		B		—		16.8			16.8
Derivatives in a valid hedging relationship		C		20.8		(20.8	)		—
Held-for-trading derivatives		C		8.2		(8.2	)		—
Derivative instruments		C		—		28.9			28.9
Regulatory assets		B, D, E		—		232.5			232.5
Intangibles		H		72.5		(72.5	)		—
Other		B, D, F, H, I, J		512.8		(424.6	)		88.2

Total other assets				614.3		(247.9	)		366.4

Total assets			$	3,991.3	$	(183.5	)	$	3,807.8


As at December 31, 2010 millions of Canadian dollars	Notes		CGAAP		Effect of transition to USGAAP			USGAAP
Liabilities and Equity
Current liabilities
Short-term debt			$	48.3		—		$	48.3
Current portion of long-term debt				0.1		—			0.1
Accounts payable		K		—	$	157.9			157.9
Accounts payable and accrued charges		K		221.3		(221.3	)		—
Due to associated companies		N		5.1		1.1			6.2
Dividends payable		L		1.7		(1.7	)		—
Deferred income taxes		B		—		3.4			3.4
Derivatives in a valid hedging relationship		C		2.2		(2.2	)		—
Held-for-trading derivatives		C		20.8		(20.8	)		—
Derivative instruments		C		—		23.0			23.0
Pension and post-retirement liabilities		I		—		8.2			8.2
Regulatory liabilities		B, D, E		—		52.4			52.4
Other current liabilities		B, F, K, L, M		—		67.2			67.2

Total current liabilities				299.5		67.2			366.7

Long-term liabilities
Long-term debt		J, M		1,933.7		18.5			1,952.2
Deferred income taxes		B		163.1		(163.1	)		—
Derivatives in a valid hedging relationship		C		9.4		(9.4	)		—
Held-for-trading derivatives		C		1.8		(1.8	)		—
Derivative instruments		C		—		11.2			11.2
Pension and post-retirement liabilities		I		—		314.7			314.7
Regulatory liabilities		B, D, E		—		61.7			61.7
Asset retirement obligations				138.7		—			138.7
Other long-term liabilities		D, F, I, K		98.6		(93.0	)		5.6
Preferred shares		M		135.0		(135.0	)		—

Total long-term liabilities				2,480.3		3.8			2,484.1

Redeemable preferred stock		M		—		132.2			132.2

Equity
Common stock				984.7		—			984.7
Accumulated other comprehensive income (loss)		E, I		10.8		(376.5	)		(365.7	)
Retained earnings		B, I, J, M, N		216.0		(10.2	)		205.8

Total equity				1,211.5		(386.7	)		824.8

Total liabilities and equity			$	3,991.3	$	(183.5	)	$	3,807.8

The adjustments to January 1, 2010 and December 31, 2010 equity are as follows:


As at January 1, 2010 millions of Canadian dollars	Common Stock		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total Equity
CGAAP	$	934.7	$	(44.0	)	$	194.7		$	1,085.4

Note B – Income taxes		—		—			(1.2	)		(1.2	)
Note E – Hedging		—		44.0			—			44.0
Note I – Pension and other post-retirement benefits		—		(256.1	)		(6.8	)		(262.9	)
Note J – Issue costs		—		—			(1.1	)		(1.1	)
Note M – Redeemable preferred stock		—		—			1.8			1.8
Note N – Share-based compensation		—		—			(0.9	)		(0.9	)

Total transition adjustments		—		(212.1	)		(8.2	)		(220.3	)

USGAAP	$	934.7	$	(256.1	)	$	186.5		$	865.1


As at December 31, 2010 millions of Canadian dollars	Common Stock		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total Equity
CGAAP	$	984.7	$	10.8		$	216.0		$	1,211.5

Note B – Income taxes		—		—			(5.4	)		(5.4	)
Note E – Hedging		—		(10.7	)		—			(10.7	)
Note I – Pension and other post-retirement benefits		—		(365.7	)		(4.5	)		(370.2	)
Note J – Issue costs		—		—			(1.1	)		(1.1	)
Note M – Redeemable preferred stock		—		—			1.9			1.9
Note N – Share-based compensation		—		—			(1.1	)		(1.1	)
Other		—		(0.1	)		—			(0.1	)

Total transition adjustments		—		(376.5	)		(10.2	)		(386.7	)

USGAAP	$	984.7	$	(365.7	)	$	205.8		$	824.8

The statements of income for the 2010 periods reconciled from CGAAP to USGAAP are as follows:


For the three months ended March 31, 2010 millions of Canadian dollars	Notes		CGAAP			Effect of transition to USGAAP			USGAAP
Operating revenues
Electric		O	$	337.5		$	(337.5	)		—
Other		O		3.2			(3.2	)		—
Operating revenues		O, P		—			342.8		$	342.8

Total operating revenues				340.7			2.1			342.8

Cost of operations
Fuel for generation and purchased power		Q		181.2			(1.6	)		179.6
Fuel for generation and purchased power – affiliates		Q		—			1.6			1.6
Fuel adjustment				(39.4	)		—			(39.4	)
Operating, maintenance and general		I, P		53.2			1.7			54.9
Provincial grants and taxes				10.0			—			10.0
Depreciation and amortization		B, R		36.6			4.5			41.1
Regulatory amortization		R		4.4			(4.4	)		—

Total operating expenses				246.0			1.8			247.8

Income from operations				94.7			0.3			95.0
Other expenses, net		O, S, T		—			3.6			3.6
Financing charges		M, S, T		32.3			(32.3	)		—
Interest expense, net		B, S, T		—			26.1			26.1

Income before provision for income taxes				62.4			2.9			65.3
Income tax recovery		B		(0.9	)		(1.0	)		(1.9	)

Net income of Nova Scotia Power Inc.				63.3			3.9			67.2
Dividends on preferred stock		M		—			2.0			2.0

Net income attributable to common shareholders			$	63.3		$	1.9		$	65.2


For the six months ended June 30, 2010 millions of Canadian dollars	Notes		CGAAP			Effect of transition to USGAAP			USGAAP
Operating revenues
Electric		O	$	604.5		$	(604.5	)		—
Other		O		6.8			(6.8	)		—
Operating revenues		O, P		—			616.0		$	616.0

Total operating revenues				611.3			4.7			616.0

Cost of operations
Fuel for generation and purchased power		Q		305.5			(6.4	)		299.1
Fuel for generation and purchased power – affiliates		Q		—			6.4			6.4
Fuel adjustment				(52.0	)		—			(52.0	)
Operating, maintenance and general		I, P		111.0			3.9			114.9
Provincial grants and taxes				20.0			—			20.0
Depreciation and amortization		B, R		74.0			9.0			83.0
Regulatory amortization		R		8.8			(8.8	)		—

Total operating expenses				467.3			4.1			471.4

Income from operations				144.0			0.6			144.6
Other expenses, net		O, S, T		—			5.9			5.9
Financing charges		M, S, T		63.2			(63.2	)		—
Interest expense, net		B, M, S, T		—			52.7			52.7

Income before provision for income taxes				80.8			5.2			86.0
Income tax expense (recovery)		B		2.6			(1.3	)		1.3

Net income of Nova Scotia Power Inc.				78.2			6.5			84.7
Dividends on preferred stock		M		—			4.0			4.0

Net income attributable to common shareholders			$	78.2		$	2.5		$	80.7


For the nine months ended September 30, 2010 millions of Canadian dollars	Notes		CGAAP			Effect of transition to USGAAP			USGAAP
Operating revenues
Electric		O	$	870.9		$	(870.9	)		—
Other		O		10.7			(10.7	)		—
Operating revenues		O, P		—			888.2		$	888.2

Total operating revenues				881.6			6.6			888.2

Cost of operations
Fuel for generation and purchased power		Q		440.5			(8.0	)		432.5
Fuel for generation and purchased power – affiliates		Q		—			8.0			8.0
Fuel adjustment				(75.0	)		—			(75.0	)
Operating, maintenance and general		I, N, P, T		172.5			5.8			178.3
Provincial grants and taxes				30.0			—			30.0
Depreciation and amortization		B, R		110.9			13.5			124.4
Regulatory amortization		R		13.2			(13.2	)		—

Total operating expenses				692.1			6.1			698.2

Income from operations				189.5			0.5			190.0
Other expenses, net		O, S, T		—			7.8			7.8
Financing charges		M, S, T		93.0			(93.0	)		—
Interest expense, net		B, M, S, T		—			77.9			77.9

Income before provision for income taxes				96.5			7.8			104.3
Income tax (recovery) expense		B		(4.1	)		3.1			(1.0	)

Net income of Nova Scotia Power Inc.				100.6			4.7			105.3
Dividends on preferred stock		M		—			6.0			6.0

Net income attributable to common shareholders			$	100.6		$	(1.3	)	$	99.3


For the year ended December 31, 2010 millions of Canadian dollars	Notes		CGAAP			Effect of transition to USGAAP			USGAAP
Operating revenues
Electric		O	$	1,167.3		$	(1,167.3	)		—
Other		O		15.4			(15.4	)		—
Operating revenues		O, P		—			1,191.4		$	1,191.4

Total operating revenues				1,182.7			8.7			1,191.4

Cost of operations
Fuel for generation and purchased power		Q		586.7			(8.1	)		578.6
Fuel for generation and purchased power – affiliates		Q		—			8.1			8.1
Fuel adjustment				(99.0	)		—			(99.0	)
Operating, maintenance and general		I, N, P, T		237.5			8.3			245.8
Provincial grants and taxes				40.1			—			40.1
Depreciation and amortization		B, R		150.8			37.3			188.1
Regulatory amortization		R		36.9			(36.9	)		—

Total operating expenses				953.0			8.7			961.7

Income from operations				229.7			—			229.7
Other expenses, net		O, S, T		—			11.3			11.3
Financing charges		M, S, T		125.8			(125.8	)		—
Interest expense, net		B, M, S, T		—			104.7			104.7

Income before provision for income taxes				103.9			9.8			113.7
Income tax (recovery) expense		B		(17.4	)		4.0			(13.4	)

Net income of Nova Scotia Power Inc.				121.3			5.8			127.1
Dividends on preferred stock		M		—			7.9			7.9

Net income attributable to common shareholders			$	121.3		$	(2.1	)	$	119.2

The statements of cash flows for the 2010 periods reconciled from CGAAP to USGAAP are as follows:


For the three months ended March 31, 2010 millions of Canadian dollars	Notes		CGAAP			Effect of transition to USGAAP			USGAAP
Net cash used in operating activities		M, S	$	(17.3	)	$	3.7		$	(13.6	)
Net cash used in investing activities		S		(50.0	)		(1.7	)		(51.7	)
Net cash provided by financing activities		M		67.3			(2.0	)		65.3

Net change in cash				—			—			—
Cash, beginning of period				0.3			—			0.3

Cash, end of period			$	0.3			—		$	0.3


For the six months ended June 30, 2010 millions of Canadian dollars	Notes		CGAAP			Effect of transition to USGAAP			USGAAP
Net cash provided by operating activities		M, S	$	43.2		$	7.4		$	50.6
Net cash used in investing activities		S		(210.6	)		(3.4	)		(214.0	)
Net cash provided by financing activities		M		167.4			(4.0	)		163.4

Net change in cash				—			—			—
Cash, beginning of period				0.3			—			0.3

Cash, end of period			$	0.3			—		$	0.3


For the nine months ended September 30, 2010 millions of Canadian dollars	Notes		CGAAP			Effect of transition to USGAAP			USGAAP
Net cash provided by operating activities		M, S	$	139.8		$	12.5		$	152.3
Net cash used in investing activities		S		(352.8	)		(6.5	)		(359.3	)
Net cash provided by financing activities		M		213.0			(6.0	)		207.0

Net change in cash				—			—			—
Cash, beginning of period				0.3			—			0.3

Cash, end of period			$	0.3			—		$	0.3


For the year ended December 31, 2010 millions of Canadian dollars	Notes		CGAAP			Effect of transition to USGAAP			USGAAP
Net cash provided by operating activities		B, M, S	$	300.2		$	17.1		$	317.3
Net cash used in investing activities		B, S		(533.3	)		(9.2	)		(542.5	)
Net cash provided by financing activities		M		233.1			(7.9	)		225.2

Net change in cash				—			—			—
Cash, beginning of period				0.3			—			0.3

Cash, end of period			$	0.3			—		$	0.3

NOTES TO THE TRANSITIONAL ADJUSTMENTS

Under USGAAP, the Company is (i) measuring certain assets, liabilities, revenues and expenses differently than it had been under CGAAP (see details on each measurement change below); and (ii) disclosing certain assets, liabilities, revenues and expenses on different lines in the financial statements than they had been under CGAAP (see details on each classification change below).

A. Offsetting (measurement difference)

Certain items on the balance sheets are being offset where a legal right of setoff exists. Differences exist between CGAAP and USGAAP in defining what balances may be offset.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Receivables, net	$	(0.9	)		—
Accounts payable		(0.9	)		—

B. Income taxes (measurement difference)

In addition to the tax effects of other transition adjustments, the following are included in the income tax adjustments.

Investment tax credits (“ITCs”)

Under CGAAP, the Company recognized ITCs as a reduction from the related expenditures where there was reasonable assurance of collection. Under USGAAP, the Company recognizes ITCs as a reduction to income tax expense in the current and future periods to the extent that realization of such benefit is more likely than not.

Tax rates

Under CGAAP, the Company measured income taxes using substantively enacted income tax rates. Under USGAAP, the Company uses enacted income tax rates. NSPI recognized an income tax liability under USGAAP for the difference between the enacted tax rates and the substantively enacted tax rates for the Part VI.1 tax deduction related to dividends on preferred stock.

Uncertain tax positions

Under CGAAP, the Company recognizes the benefit of an uncertain tax position when it is probable of being sustained.

Under USGAAP, the Company recognizes the benefit of an uncertain tax position only when it is more likely than not that such a position will be sustained by the taxing authorities based on the technical merits of the position. The current and deferred income tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Current assets
Income taxes receivable		—		$	(6.3	)
Deferred income taxes	$	(22.3	)		(4.1	)
Property, plant and equipment		1.0			1.3
Other assets
Deferred income taxes		61.4			16.8
Regulatory assets		(25.2	)		(136.9	)
Other		1.2			0.7
Current liabilities
Income taxes payable		2.1			—
Deferred income taxes		—			3.4
Regulatory liabilities		4.7			3.0
Other current liabilities		1.3			1.2
Long-term liabilities
Deferred income taxes		(52.0	)		(163.1	)
Regulatory liabilities		61.2			32.4
Equity
Retained earnings		(1.2	)		(5.4	)

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):


For the millions of Canadian dollars	3 months ended March 31 2010			6 months ended June 30 2010			9 months ended September 30 2010			Year ended December 31 2010
Depreciation and amortization	$	0.1		$	0.2		$	0.3		$	0.4
Interest expense, net		(0.3	)		(0.3	)		(0.4	)		(0.2	)
Income tax (recovery) expense		(1.0	)		(1.3	)		3.1			4.0

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:


For the millions of Canadian dollars	3 months ended March 31 2010		6 months ended June 30 2010		9 months ended September 30 2010		Year ended December 31 2010
Net cash provided by operating activities		—		—		—	$	0.3
Net cash used in investing activities		—		—		—		(0.3	)

C. Derivatives (classification change)

Under CGAAP, the Company was disclosing its derivatives in valid hedging relationships and held-for-trading derivatives as separate line items on the balance sheet. Under USGAAP, the Company has included these balances together in “Derivative instruments”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Current assets
Derivative instruments	$	28.3		$	31.0
Derivatives in a valid hedging relationship		(19.4	)		(24.7	)
Held-for-trading derivatives		(8.9	)		(6.3	)
Other assets
Derivative instruments		36.0			29.0
Derivatives in a valid hedging relationship		(29.8	)		(20.8	)
Held-for-trading derivatives		(6.2	)		(8.2	)
Current liabilities
Derivative instruments		65.2			23.0
Derivatives in a valid hedging relationship		(53.0	)		(2.2	)
Held-for-trading derivatives		(12.2	)		(20.8	)
Long-term liabilities
Derivative instruments		21.3			11.2
Derivatives in a valid hedging relationship		(20.0	)		(9.4	)
Held-for-trading derivatives		(1.3	)		(1.8	)

D. Regulatory assets and liabilities (classification change)

Under CGAAP, the Company was disclosing its regulatory assets and liabilities in other assets and liabilities respectively. Under USGAAP, the Company discloses its regulatory assets and liabilities as separate line items on the balance sheet.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Current assets
Regulatory assets	$	46.8		$	44.9
Other assets
Regulatory assets		198.2			357.2
Other		(245.0	)		(402.1	)
Current liabilities
Regulatory liabilities		18.8			20.8
Long-term liabilities
Regulatory liabilities		(3.9	)		8.1
Other long-term liabilities		(14.9	)		(28.9	)

E. Hedging (measurement change)

Effective for 2011, NSPI implemented an amended hedge accounting policy, which was approved by the UARB. The amended policy resulted from stakeholder requests to simplify the accounting for derivatives used to manage risk and to alleviate any USGAAP issues which would result in increased income volatility. The amended policy is applied retrospectively with restatement of prior periods with the exception of prior period income, and requires regulatory deferral for commodity, foreign exchange and interest derivatives documented as economic hedges and for physical contracts that do not qualify for the NPNS exception under USGAAP.

As a result of the amended accounting policy, NSPI receives regulatory deferral for any changes in fair value on derivatives documented as economic hedges.

As at January 1, 2010 and December 31, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010		December 31 2010
Current assets
Regulatory assets	$	75.9	$	26.9
Other assets
Regulatory assets		20.0		12.2
Current liabilities
Regulatory liabilities		22.1		28.6
Long-term liabilities
Regulatory liabilities		29.8		21.2
Equity
Accumulated other comprehensive income (loss)		44.0		(10.7	)

F. Current other assets and liabilities (classification change)

Under CGAAP, the Company was disclosing its other assets and liabilities on the balance sheet as long-term. Under USGAAP, the Company has included the current portion of these balances in “Other current assets” and “Other current liabilities”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Other current assets	$	1.5		$	1.8
Other, included in other assets		(1.5	)		(1.8	)
Other current liabilities		1.3			0.9
Other long-term liabilities		(1.3	)		(0.9	)

G. Construction work-in-progress (classification change)

Under CGAAP, the Company was disclosing its construction work-in-progress (“CWIP”) as a separate line item on the balance sheet. Under USGAAP, the Company has included this balance in “Property, plant and equipment” and will disclose its CWIP balance annually in the notes to the December 31 financial statements.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Property, plant and equipment	$	152.8		$	279.2
Construction work-in-progress		(152.8	)		(279.2	)

H. Intangibles (classification change)

Under CGAAP, the Company was disclosing its intangibles as a separate line item on the balance sheet. Under USGAAP, the Company has included this balance in “Other” as part of “Other assets”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Other, included in other assets	$	65.7		$	72.5
Intangibles		(65.7	)		(72.5	)

I. Pension and other post-retirement benefits (measurement change)

Under CGAAP, the Company disclosed, but did not recognize, its unamortized gains and losses, its past service costs, and its unamortized transitional obligation associated with pension and other post-retirement benefits. Under USGAAP, the Company has recognized its unfunded pension obligation as a liability; the unamortized gains and losses and past service costs are recognized in “Accumulated other comprehensive loss”; and the unamortized transitional obligation previously determined under CGAAP is recognized in “Retained earnings”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Other assets
Other	$	(94.3	)	$	(110.7	)
Current liabilities
Pension and post-retirement liabilities		8.3			8.2
Long-term liabilities
Pension and post-retirement liabilities		221.2			314.7
Other long-term liabilities		(60.9	)		(63.4	)
Equity
Accumulated other comprehensive loss		(256.1	)		(365.7	)
Retained earnings		(6.8	)		(4.5	)

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):


	3 months ended			6 months ended			9 months ended			Year ended
For the millions of Canadian dollars	March 31 2010			June 30 2010			September 30 2010			December 31 2010
Operating, maintenance and general	$	(0.6	)	$	(1.1	)	$	(1.7	)	$	(2.3	)

J. Issue costs

Classification change

Under CGAAP, debt financing costs, premiums and discounts were netted against long-term debt. Under USGAAP, debt financing costs are included in “Other” as part of “Other assets”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010		December 31 2010
Other, included in other assets	$	13.7	$	15.7
Long-term debt		13.7		15.7

Measurement Change

Under CGAAP, the straight-line method of amortizing debt financing costs, premiums and discounts was used to approximate the effective interest method. Under USGAAP, the straight-line method is not appropriate so the effective interest method has been adopted.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Other, included in other assets	$	1.1		$	1.1
Long-term debt		2.2			2.2
Retained earnings		(1.1	)		(1.1	)

K. Accounts payable (classification change)

Under CGAAP, trade and non-trade payables were recognized in accounts payable and accrued charges. Under USGAAP, trade payables are recognized in “Accounts payable” and non-trade payables are recognized in “Other current liabilities”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Accounts payable	$	152.6		$	157.9
Accounts payable and accrued charges		(213.9	)		(221.3	)
Other current liabilities		61.3			63.2
Other long-term liabilities		—			0.2

L. Dividends payable (classification change)

Under CGAAP, the Company was disclosing dividends payable as a separate line item on the balance sheet. Under USGAAP, the Company has included this balance in “Other current liabilities”.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Dividends payable	$	(1.7	)	$	(1.7	)
Other current liabilities		1.7			1.7

M. Redeemable preferred stock (measurement change)

Under CGAAP, NSPI’s redeemable preferred stock were classified as a liability; dividends on preferred stock were classified as an expense in the statement of income and were accrued monthly; and issuance costs were deferred on the balance sheet as a deferred financing charge and amortized to income over the life of the redeemable preferred stock.

Under USGAAP NSPI’s redeemable preferred stock are classified as mezzanine equity as the redeemable preferred stock do not meet the USGAAP definition of a liability; dividends on preferred stock are deducted from retained earnings and are accrued as declared; and issuance costs are netted against the redeemable preferred stock on the balance sheet and are not amortized.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Other current liabilities	$	0.3		$	0.3
Long-term debt		0.7			0.6
Preferred shares		(135.0	)		(135.0	)
Redeemable preferred stock		132.2			132.2
Retained earnings		1.8			1.9

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):


	3 months ended			6 months ended			9 months ended			Year ended
For the millions of Canadian dollars	March 31 2010			June 30 2010			September 30 2010			December 31 2010
Financing charges	$	(2.0	)	$	(4.0	)	$	(6.0	)	$	(7.9	)
Interest expense, net		—			(0.1	)		(0.1	)		(0.1	)
Dividends on preferred stock		2.0			4.0			6.0			7.9

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:


	3 months ended			6 months ended			9 months ended			Year ended
For the millions of Canadian dollars	March 31 2010			June 30 2010			September 30 2010			December 31 2010
Net cash provided by operating activities	$	2.0		$	4.0		$	6.0		$	7.9
Net cash used in financing activities		(2.0	)		(4.0	)		(6.0	)		(7.9	)

N. Share-based compensation

Employee Common Share Purchase Plan

Under USGAAP, the Company’s employee common share purchase plan is considered compensatory and the Company’s contribution to the plan should be recognized. Under CGAAP, the Company was recognizing the amount of its contribution in excess of 5 percent of the average market price of the shares.

As at January 1 and December 31, 2010, the effect on the Balance Sheets is reflected in the following increases (decreases):


As at millions of Canadian dollars	January 1 2010			December 31 2010
Due to associated companies	$	0.9		$	1.1
Retained earnings		(0.9	)		(1.1	)

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):

3 months ended

6 months ended

9 months ended

Year ended

For the

millions of Canadian dollars

March 31
2010

June 30
2010

September 30
2010

December 31
2010

Operating, maintenance and general

—

0.1

0.2

O. Revenue

Under CGAAP, revenue was recognized in electric and other revenue. Under USGAAP, electric and other revenue is recognized in “Operating revenues” and “Other expenses, net”.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):


	3 months ended			6 months ended			9 months ended			Year ended
For the millions of Canadian dollars	March 31 2010			June 30 2010			September 30 2010			December 31 2010
Electric revenue	$	(337.5	)	$	(604.5	)	$	(870.9	)	$	(1,167.3	)
Other revenue		(3.2	)		(6.8	)		(10.7	)		(15.4	)
Operating revenues		340.6			611.0			881.0			1,181.2
Other expenses, net		(0.1	)		(0.3	)		(0.6	)		(1.5	)

P. Netting of certain revenues and expenses

Under CGAAP, the Company was netting certain revenues and expenses in its statements of income. Under USGAAP, revenues are classified on a gross or net basis depending on whether the Company is acting as the principal or an agent in the transaction. The adoption of USGAAP has resulted in certain revenue transactions disclosed on a net basis under CGAAP to be presented on a gross basis under USGAAP.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):


	3 months ended		6 months ended		9 months ended		Year ended
For the millions of Canadian dollars	March 31 2010		June 30 2010		September 30 2010		December 31 2010
Operating revenues	$	2.3	$	5.0	$	7.3	$	10.2
Operating, maintenance and general		2.3		5.0		7.3		10.2

Q. Fuel for generation and purchased power

Under CGAAP, all the fuel for generation and purchased power was recognized as such. Under USGAAP, fuel for generation and purchased power purchased from or sold to affiliates is recognized in a separate line item.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):


	3 months ended			6 months ended			9 months ended			Year ended
For the millions of Canadian dollars	March 31 2010			June 30 2010			September 30 2010			December 31 2010
Fuel for generation and purchased power	$	(1.6	)	$	(6.4	)	$	(8.0	)	$	(8.1	)
Fuel for generation and purchased power – affiliates		1.6			6.4			8.0			8.1

R. Regulatory amortization

Under CGAAP, regulatory amortization was disclosed as a separate line item. Under USGAAP, regulatory amortization is included in “Depreciation and amortization”.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):


	3 months ended			6 months ended			9 months ended			Year ended
For the millions of Canadian dollars	March 31 2010			June 30 2010			September 30 2010			December 31 2010
Depreciation and amortization	$	4.4		$	8.8		$	13.2		$	36.9
Regulatory amortization		(4.4	)		(8.8	)		(13.2	)		(36.9	)

S. Allowance for funds used during construction

Under CGAAP, AFUDC was included in financing charges. Under USGAAP, allowance for equity funds used during construction is included in “Other expenses, net” and allowance for borrowed funds used during construction is netted against “Interest expense, net”.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):


	3 months ended			6 months ended			9 months ended			Year ended
For the millions of Canadian dollars	March 31 2010			June 30 2010			September 30 2010			December 31 2010
Other expenses, net	$	(1.8	)	$	(4.1	)	$	(8.1	)	$	(12.0	)
Financing charges expenses		3.5			7.5			14.6			20.9
Interest expense, net		(1.7	)		(3.4	)		(6.5	)		(8.9	)

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the effect on the Statements of Cash Flows is as follows:


	3 months ended			6 months ended			9 months ended			Year ended
For the millions of Canadian dollars	March 31 2010			June 30 2010			September 30 2010			December 31 2010
Net cash provided by operating activities	$	1.7		$	3.4		$	6.5		$	8.9
Net cash used in investing activities		(1.7	)		(3.4	)		(6.5	)		(8.9	)

T. Interest expense

Under CGAAP, interest expense, amortization of defeasance costs, and foreign exchange gains and losses were included in financing charges. Under USGAAP, interest expense is disclosed in a separate line item and amortization of defeasance costs and foreign exchange gains and losses are included in “Other expenses, net”.

For the quarters ended March 31, June 30, September 30 and year ended December 31, 2010, the pre-tax effect on the Statements of Income is reflected in the following increases (decreases):


	3 months ended			6 months ended			9 months ended			Year ended
For the millions of Canadian dollars	March 31 2010			June 30 2010			September 30 2010			December 31 2010
Operating, maintenance and general		—			—		$	0.1		$	0.2
Other expenses, net	$	5.6		$	10.3			16.5			24.8
Financing charges		(33.8	)		(66.7	)		(101.5	)		(138.9	)
Interest expense, net		28.2			56.4			84.9			113.9

Section II. Additional disclosures required under USGAAP

The following represents select disclosures required for annual financial statements prepared in accordance with USGAAP that are not otherwise found in these interim financial statements or in the December 31, 2010 financial statements of the Company prepared in accordance with CGAAP.

Pension and other post-retirement benefits

The change in benefit obligation, assets, and funded status for all plans for the year ended December 31, 2010 was as follows:


millions of Canadian dollars	Defined benefit pension plans			Non-pension benefits plans
Reconciliation of projected benefit obligation
Balance, January 1, 2010	$	785.2		$	36.3
Service cost		9.0			1.4
Plan participant contributions		5.5			—
Interest cost		50.0			2.3
Plan amendments		(1.0	)		—
Benefits paid		(39.5	)		(4.3	)
Actuarial losses		122.3			4.1

Balance, December 31, 2010		931.5			39.8

Reconciliation of plan assets
Balance, January 1, 2010		592.1			—
Employer contributions		34.6			4.3
Plan participant contributions		5.5			—
Benefits paid		(39.5	)		(4.3	)
Actual return on assets, net of expenses		55.7			—

Balance, December 31, 2010		648.4			—

Funded status, December 31, 2010	$	(283.1	)	$	(39.8	)

Amounts reflected in the above table that have not yet been recognized in NSPI’s net periodic benefit cost, and are included in “Accumulated other comprehensive loss”, as of December 31, 2010 were as follows:


millions of Canadian dollars	Defined benefit pension plans			Non-pension benefits plans
Actuarial losses	$	363.5		$	2.1
Past service (gains) costs		(1.3	)		1.4

Amount in AOCL	$	362.2		$	3.5

Amounts from the above tables recognized in the Balance Sheets as at December 31, 2010 were as follows:


millions of Canadian dollars	Defined benefit pension plans			Non-pension benefits plans
Current liability	$	(3.7	)	$	(4.5	)
Long-term liability		(279.4	)		(35.3	)
AOCL		362.2			3.5

Net asset (liability) recognized	$	79.1		$	(36.3	)

The Accumulated Benefit Obligation (“ABO”) for the defined benefit pension plans was $882.2 million as at December 31, 2010. The aggregate financial position for all plans with an ABO in excess of plan assets as of December 31, 2010 is as follows:


millions of Canadian dollars	Defined benefit pension plans
Accumulated benefit obligation	$	882.2
Fair value of plan assets		648.4

Funded status	$	(233.8	)

Income taxes

The deferred income tax assets and liabilities as at December 31, 2010 consisted of the following:


millions of Canadian dollars	Current			Long-term
Deferred income tax assets:
Property, plant and equipment		—		$	(178.1	)
Regulatory assets (deferral of FAM)		—			(20.4	)
Regulatory assets (unamortized defeasance costs)		—			(17.8	)
Intangibles		—			23.6
Asset retirement obligations		—			62.4
Pension and other post-retirement liabilities		—			143.0
Derivative instruments		—			(8.0	)
Tax loss carry forwards		—			17.0
Other		—			7.8

Total deferred income tax assets before valuation allowance		—			29.5
Valuation allowance		—			(12.7	)

Total deferred income tax assets after valuation allowance		—		$	16.8


millions of Canadian dollars	Current			Long-term
Deferred income tax liabilities:
Regulatory assets (deferral of FAM)	$	8.9			—
Regulatory assets (unamortized defeasance costs)		1.4			—
Derivative instruments		3.9			—
Pension and other post-retirement liabilities		(3.7	)		—
Other		(7.7	)		—

Total deferred income tax liabilities before valuation allowance		2.8			—
Valuation allowance		0.6			—

Total deferred income tax liabilities after valuation allowance	$	3.4			—

The offset to substantially all of the deferred income tax assets and liabilities noted above have been recognized as a regulatory asset or regulatory liability. These amounts include a gross up to reflect the income tax associated with future revenues required to fund deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets.

The total amount of unrecognized tax benefits as of December 31, 2010 was $10.8 million which would favorably affect the effective tax rate, if recognized. Interest of $1.3 million has been accrued related to unrecognized tax benefits as of December 31, 2010. No penalties have been accrued. During the next twelve months, it is reasonable that $3.2 million of unrecognized tax benefits may be recognized due to statute expirations or settlement agreements with taxing authorities.

As at December 31, 2010, the Company’s tax years still open to examination by taxing authorities include 2006 and subsequent years. With few exceptions, the Company is no longer subject to examination for years prior to 2006.

16.

SUBSEQUENT EVENT

On July 21, 2011, the UARB approved an agreement NSPI reached with stakeholders to apply the deferral of certain tax benefits related to renewable energy projects of $14.5 million from 2010 against the FAM regulatory asset effective January 1, 2011. The application of the deferral will reduce the FAM balance outstanding with the reduction applied to the amount that would otherwise be recovered from customers in 2012. The impact on earnings will be to reduce interest revenue on the FAM and reverse a deferred income tax liability that resulted from originally recording the FAM asset.

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