ATLANTIC POWER CORP - FORM 8-K/A - EX-99.1

ATLANTIC POWER CORP - FORM 8-K/A - EX-99.1 - December 20, 2011

Attached files

Attached files

ATLANTIC POWER CORP Reports

file	filename
8-K/A - 8-K/A - ATLANTIC POWER CORP	a11-31318_18ka.htm
EX-23.1 - EX-23.1 - ATLANTIC POWER CORP	a11-31318_1ex23d1.htm
EX-99.3 - EX-99.3 - ATLANTIC POWER CORP	a11-31318_1ex99d3.htm
EX-99.2 - EX-99.2 - ATLANTIC POWER CORP	a11-31318_1ex99d2.htm

Exhibit 99.1

KPMG LLP
Chartered Accountants
10125 - 102 Street
Edmonton AB T5J 3V8
Canada

Telephone
Fax
Internet

(780) 429-7300
(780) 429-7379
www.kpmg.ca

INDEPENDENT AUDITORS’ REPORT

To the Partners of Capital Power Income L.P.

We have audited the accompanying consolidated balance sheets of Capital Power Income L.P. and subsidiaries (“the Partnership”) as of December 31, 2010, 2009, and 2008 and the related consolidated statements of income and loss, partners’ equity, comprehensive loss and cash flows for each year in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2010, 2009, and 2008 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010 in conformity with Canadian generally accepted accounting principles.

Accounting principles generally accepted in Canada vary in certain significant respects from U.S. generally accepted accounting principles. Information relating to the nature and effect of such differences is presented in note 27 to the consolidated financial statements.

“signed KPMG”

KPMG LLP

Edmonton, Canada

March 2, 2011, except as to notes 27 and 28, which are as of July 25, 2011

CAPITAL POWER INCOME L.P.

CONSOLIDATED STATEMENTS OF INCOME AND LOSS

	Years ended December 31
	2010		2009			2008
	(In millions of dollars except units and per unit amounts)
Revenues	$	532.4	$	586.5		$	499.3
Cost of fuel	230.7		271.4			288.8
Operating and maintenance expense	114.2		103.4			99.1
	187.5		211.7			111.4
Other costs
Depreciation, amortization and accretion (Note 5)	98.3		93.3			88.3
Financial charges and other, net (Note 9)	40.1		46.4			70.7
Management and administration	13.9		15.2			20.2
Asset impairment charge (Note 8)	—		—			24.1
	152.3		154.9			203.3
Net income (loss) from continuing operations before income tax and preferred share dividends	35.2		56.8			(91.9		)
Income tax recovery (Note 14)	9.4		8.9			31.4
Net income (loss) from continuing operations before preferred share dividends	44.6		65.7			(60.5		)
Preferred share dividends of a subsidiary company (Note 11)	14.1		7.9			6.6
Net income (loss) from continuing operations	30.5		57.8			(67.1		)
Loss from discontinued operations (Note 25)	—		(0.2		)	(0.7		)
Net income (loss)	$	30.5	$	57.6		$	(67.8	)
Net income (loss) per unit from continuing operations	$	0.55	$	1.07		$	(1.24	)
Net loss per unit from discontinued operations	—		—			(0.01		)
Net income (loss) per unit	$	0.55	$	1.07		$	(1.26	)
Weighted average units outstanding (millions)	55.0		53.9			53.9

See accompanying notes to the consolidated financial statements.

CAPITAL POWER INCOME L.P.

CONSOLIDATED STATEMENTS OF CASH FLOW

	Years ended December 31
	2010			2009			2008
	(In millions of dollars)
Operating activities
Net income (loss) from continuing operations	$	30.5		$	57.8		$	(67.1	)
Items not affecting cash:
Depreciation, amortization and accretion	98.3			93.3			88.3
Asset impairment charge	—			—			24.1
Future income tax recovery	(13.9		)	(12.4		)	(34.4		)
Fair value changes on derivative instruments	3.6			(6.2		)	98.4
Unrealized foreign exchange losses	—			0.3			26.2
Other	6.6			10.0			8.7
	125.1			142.8			144.2
Change in non-cash working capital (Note 16)	(7.3		)	(8.3		)	13.3
Cash provided by operating activities of continuing operations	117.8			134.5			157.5
Cash (used in) provided by operating activities of discontinued operations	—			(2.8		)	2.7
Cash provided by operating activities	117.8			131.7			160.2
Investing activities
Additions to property, plant and equipment and other assets	(28.3		)	(100.7		)	(40.0		)
Change in non-cash working capital	(7.2		)	4.2			2.7
Dividends from equity investment	—			1.3			3.2
Acquisition of Morris Cogeneration LLC (Note 24)	—			—			(90.7		)
Acquisition of equity investment	—			(8.8		)	—
Cash used in investing activities of continuing operations	(35.5		)	(104.0		)	(124.8		)
Cash provided by (used in) investing activities of discontinued operations	—			11.6			(3.5		)
Cash used in investing activities	(35.5		)	(92.4		)	(128.3		)
Financing activities
Distributions paid	(69.5		)	(127.7		)	(135.8		)
Net borrowings under credit facilities	8.1			1.8			85.7
Proceeds from preferred share offering (Note 11)	—			100.0			—
Long-term debt repaid	(1.4		)	(1.3		)	(1.1		)
Issue costs	(0.5		)	(4.1		)	—
Cash used in financing activities	(63.3		)	(31.3		)	(51.2		)
Foreign exchange gains (losses) on cash held in a foreign currency	(1.0		)	(1.5		)	2.2
Increase (decrease) in cash and cash equivalents	18.0			6.5			(17.1		)
Cash and cash equivalents, beginning of year	9.5			3.0			20.1
Cash and cash equivalents, end of year	$	27.5		$	9.5		$	3.0
Supplementary cash flow information
Income taxes paid	$	5.6		$	2.4		$	6.7
Interest paid	$	38.0		$	43.6		$	37.1

See accompanying notes to the consolidated financial statements.

CAPITAL POWER INCOME L.P.

CONSOLIDATED BALANCE SHEETS

	As at December 31
	2010		2009		2008
	(In millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	27.5	$	9.5	$	3.0
Accounts receivable	52.5		51.8		60.6
Inventories (Note 4)	19.5		24.6		23.2
Prepaids and other	4.0		4.5		5.0
Derivative assets (Note 15)	10.4		7.8		22.8
Future income taxes (Note 14)	7.1		1.9		2.3
Current assets of discontinued operations	—		—		2.3
	121.0		100.1		119.2
Property, plant and equipment (Note 5)	994.1		1,064.7		1,106.0
Power purchase arrangements (Note 6)	290.0		330.4		408.6
Goodwill (Note 7)	45.0		47.6		55.1
Derivative assets (Note 15)	29.7		31.8		27.1
Future income taxes (Note 14)	41.2		35.0		16.8
Other assets (Note 8)	62.8		58.5		64.4
Long-term assets of discontinued operations (Note 25)	—		—		12.0
	$	1,583.8	$	1,668.1	$	1,809.2
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable	$	52.9	$	59.6	$	70.3
Distributions payable	8.2		7.9		33.9
Long-term debt due within one year (Note 9)	—		1.4		1.3
Derivative liabilities (Note 15)	21.1		2.9		13.0
Current liabilities of discontinued operations	—		—		1.2
Future income taxes (Note 14)	—		3.8		—
	82.2		75.6		119.7
Long-term debt (Note 9)	704.5		719.4		798.5
Derivative liabilities (Note 15)	81.9		36.4		38.5
Other liabilities (Note 10)	37.1		34.8		33.3
Long-term liabilities of discontinued operations (Note 25)	—		—		4.2
Future income taxes (Note 14)	50.7		62.7		60.7
Preferred shares issued by a subsidiary company (Note 11)	219.7		219.7		122.0
Partners’ equity	407.7		519.5		632.3
Commitments (Note 23)
Subsequent event (Note 28)
	$	1,583.8	$	1,668.1	$	1,809.2

Approved by CPI Income Services Ltd., as General Partner of Capital Power Income L.P.

“signed Brian Vaasjo”		“signed Brian Felesky”
Brian T. Vaasjo		Brian A. Felesky
Director and Chairman of the Board		Director and Chairman of the Audit Committee

See accompanying notes to the consolidated financial statements.

CAPITAL POWER INCOME L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

	Years ended December 31
	2010			2009			2008
	(In millions of dollars)
Partnership capital (Note 12)
Balance, beginning of year	$	1,200.6		$	1,197.1		$	1,197.1
Partnership units issued pursuant to distribution reinvestment plan	27.0			3.5			—
Balance, end of year	$	1,227.6		$	1,200.6		$	1,197.1
Deficit
Balance, beginning of year:	(543.7		)	(496.1		)	(296.5		)
Net income (loss)	30.5			57.6			(67.8		)
Distributions	(96.9		)	(105.2		)	(135.8		)
Balance, end of year	$	(610.1	)	$	(543.7	)	$	(500.1	)
Accumulated other comprehensive loss (Note 13)
Balance, beginning of year	$	(137.4	)	$	(64.7	)	$	5.1
Other comprehensive loss	(72.4		)	(72.7		)	(69.8		)
Balance, end of year	$	(209.8	)	$	(137.4	)	$	(64.7	)
Total of deficit and accumulated other comprehensive loss	$	(819.9	)	$	(681.1	)	$	(564.8	)
Partners’ equity	$	407.7		$	519.5		$	632.3

See accompanying notes to the consolidated financial statements.

CAPITAL POWER INCOME L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

	Years ended December 31
	2010			2009			2008
	(In millions of dollars)
Net income (loss)	$	30.5		$	57.6		$	(67.8	)
Other comprehensive income (loss), net of income taxes
Losses on translating net assets of self-sustaining foreign operations(1)	(27.4		)	(65.9		)	(66.0		)
Amortization of deferred gains on derivative instruments de-designated as cash flow hedges to income(2)	(0.5		)	(0.4		)	(3.8		)
Unrealized losses on derivative instruments designated as cash flow hedges(3)	(46.7		)	(6.7		)	—
Ineffective portion of cash flow hedges reclassified to net income(2)	2.2			0.3			—
	(72.4		)	(72.7		)	(69.8		)
Comprehensive loss	$	(41.9	)	$	(15.1	)	$	(137.6	)

(1) Includes income tax expense of $0.6 million (2009 and 2008—$nil).

(2) Net of income tax of $nil.

(3) Net of income tax of $14.6 million (2009—$2.5 million; 2008—$nil).

See accompanying notes to the consolidated financial statements.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Description of the Partnership

Capital Power Income L.P. (the Partnership) is a limited partnership created under the laws of the Province of Ontario pursuant to a Partnership Agreement dated March 27, 1997, as amended and restated November 4, 2009. The Partnership commenced operations on June 18, 1997 and currently has independent power generating facilities in British Columbia, Ontario, California, Colorado, Illinois, New Jersey, New York, North Carolina and Washington State.

CPI Income Services Ltd., the general partner of the Partnership (the General Partner), has the responsibility for overseeing the management of the Partnership and distributions to unitholders. The General Partner is a wholly owned subsidiary of CPI Investments Inc. (Investments). Capital Power Corporation (collectively with its subsidiaries, CPC, unless otherwise indicated) indirectly owns all of the 49 voting, participating shares of Investments and EPCOR Utilities Inc. (EPCOR) indirectly owns all of the 51 voting, non-participating shares of Investments. The General Partner has engaged certain other subsidiaries of CPC (collectively herein, the Manager) to perform management and administrative services on behalf of the Partnership and to operate and maintain the power plants pursuant to management and operations agreements.

Note 2. Significant Accounting Policies

Basis of Presentation

The consolidated financial statements of the Partnership have been prepared by the management of the General Partner in accordance with Canadian generally accepted accounting principles (GAAP) and include the accounts of the Partnership and of its subsidiaries. All significant intercompany transactions and balances have been eliminated.

Measurement Uncertainty

The preparation of the Partnership’s financial statements in accordance with GAAP requires management to make estimates that affect the reported amounts of revenues, expenses, assets and liabilities as well as the disclosure of contingent assets and liabilities at the financial statement date. The Partnership uses the most current information available and exercises careful judgment in making these estimates and assumptions.

For determining asset impairments, recording financial assets and liabilities and for certain disclosures, the Partnership is required to estimate the fair value of certain assets or obligations. Estimates of fair value may be based on readily determinable market values, depreciated replacement cost or discounted cash flow techniques employing estimated future cash flows based on a number of assumptions and using an appropriate discount rate.

Adjustments to previous estimates, which may be material, will be recorded in the period they become known.

Revenue Recognition

Power purchase arrangements, steam purchase arrangements and energy services agreements (collectively referred to as power purchase arrangements or PPAs) are long-term contracts to sell power and steam from the Partnership on a predetermined basis. As explained in “Power purchase arrangements containing a lease,” PPAs may be classified as a lease (either operating or capital) and the income is recognized in revenue according to lease revenue recognition standards. For those PPAs that are not considered to contain a lease, income earned on the PPA is recognized in revenue as follows: Revenue

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 2. Significant Accounting Policies (Continued)

from the sales of electricity, steam and natural gas are recognized on delivery or availability for delivery under take or pay contracts. Revenue from certain long-term contracts with fixed payments is recognized at the lower of (1) the megawatt hours (MWhs) made available during the period multiplied by the billable contract price per MWh and (2) an amount determined by the MWhs made available during the period multiplied by the average price per MWh over the term of the contract from the date of acquisition. Any excess of the current period contract price over the average price is recorded as deferred revenue.

Gains and losses on non-financial derivative instruments settlements are recorded in revenues or cost of fuel, as appropriate.

Financial Instruments

Financial assets are identified and classified as either available for sale, held for trading, held to maturity or loans and receivables. Financial liabilities are classified as either held for trading or other liabilities. Initially, all financial assets and financial liabilities are recorded on the balance sheet at fair value with subsequent measurement determined by the classification of each financial asset and liability.

Financial assets and financial liabilities held for trading are measured at fair value with the changes in fair value reported in net income. Financial assets held to maturity, loans and receivables and financial liabilities other than those held for trading are measured at amortized cost. Available for sale financial assets are measured at fair value with changes in fair value reported in other comprehensive income until the financial asset is disposed of or becomes impaired. Investments in equity instruments classified as available for sale that do not have quoted market prices in an active market are measured at cost.

Upon initial recognition, the Partnership may designate financial instruments as held for trading when such financial instruments have a reliably determinable fair value and where doing so eliminates or significantly reduces a measurement or recognition inconsistency that would otherwise arise from measuring assets and liabilities or recognising gains and losses on them on a different basis. The Partnership has designated its cash and cash equivalents as held for trading. All other non-derivative financial assets not meeting the Partnership’s criteria for designation as held for trading are classified as available for sale, loans and receivables or held to maturity.

Financial assets purchased or sold, where the contract requires the asset to be delivered within an established timeframe, are recognized on a settlement date basis.

Transaction costs on financial assets and liabilities classified as other than held for trading are capitalized and amortized over the expected life of the instrument, based on contractual cash flows, using the effective interest method (EIM). The EIM calculates the amortized cost of a financial asset or liability and allocates the interest income or expense over the term of the financial asset or liability using an effective interest rate.

Derivative Instruments and Hedging Activities

To reduce its exposure to movements in energy commodity prices, interest rate changes and foreign currency exchange rates, the Partnership uses various risk management techniques including the use of derivative instruments. Derivative instruments may include forward contracts, fixed-for-floating swaps and option contracts. Such instruments are used to establish a fixed price for an energy commodity, a cash flow denominated in a foreign currency or an interest-bearing obligation. All derivative instruments, including embedded derivatives, are recorded at fair value on the balance sheet as derivative instruments assets or derivative instruments liabilities except for embedded derivatives instruments that are clearly and closely

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 2. Significant Accounting Policies (Continued)

linked to their host contract and the combined instrument is not measured at fair value. Any contract to buy or sell a commodity that was entered into and continues to be held for the purpose of the receipt or delivery of that commodity in accordance with the Partnership’s expected purchase, sale or usage requirements is not treated as a derivative. All changes in the fair value of derivatives are recorded in net income unless cash flow hedge accounting is used, in which case changes in fair value of the effective portion of the derivatives are recorded in other comprehensive income.

The Partnership uses non-financial forward delivery contracts and financial contracts-for-differences to manage the Partnership’s exposure to fluctuations in natural gas prices related to obligations arising from its natural gas fired generation facilities. Under the non-financial forward delivery contracts, the Partnership agrees to purchase natural gas at a fixed price for delivery of a pre-determined quantity under a specified timeframe. Under the financial contracts-for-differences derivatives, the Partnership agrees to exchange, with creditworthy or adequately secured counterparties, the difference between the variable or indexed price and the fixed price on a notional quantity of the underlying commodity for a specified timeframe.

Foreign exchange forward contracts are used by the Partnership to manage foreign exchange exposures, consisting mainly of U.S. dollar exposures, resulting from anticipated transactions denominated in foreign currencies.

The Partnership may use forward interest rate or swap agreements and option agreements to manage the impact of fluctuating interest rates on existing debt.

The Partnership may use hedge accounting when there is a high degree of correlation between the risk in the item designated as being hedged (the hedged item) and the derivative instrument designated as a hedge (the hedging instrument). The Partnership documents all relationships between hedging instruments and hedged items at the hedge’s inception, including its risk management objectives and its assessment of the effectiveness of the hedging relationship on a retrospective and prospective basis. The Partnership uses cash flow hedges for certain of its anticipated transactions to reduce exposure to fluctuations in changes in natural gas prices. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in other comprehensive income, while the ineffective portion is recognized in net income. The amounts recognized in accumulated other comprehensive income are reclassified into net income in the same period or periods in which the hedged item occurs and is recorded in net income or when the hedged item becomes probable of not occurring. The hedging relationship for the natural gas contracts, which are derivative instruments, was established after the inception of the contracts. The fair value of these contracts at the date of hedge designation is recognized in net income as the natural gas is delivered under the contracts based on the anticipated fair value of the deliveries at the inception of the hedging relationship.

A hedging relationship is discontinued if the hedging relationship ceases to be effective, if the hedged item is an anticipated transaction and it is probable that the transaction will not occur by the end of the originally specified time period, if the Partnership terminates its designation of the hedging relationship or if either the hedged or hedging instrument ceases to exist as a result of its maturity, expiry, sale, termination or cancellation and is not replaced as part of the Partnership’s hedging strategy.

If a cash flow hedging relationship is discontinued or ceases to be effective, any cumulative gains or losses arising prior to such time are deferred in accumulated other comprehensive income and recognized in net income in the same period as the hedged item, and subsequent changes in the fair value of the derivative instrument are reflected in net income. If the hedged or hedging item matures, expires, or is

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 2. Significant Accounting Policies (Continued)

sold, extinguished or terminated and the hedging item is not replaced, any gains or losses associated with the hedging item that were previously recognized in other comprehensive income are recognized in net income in the same period as the corresponding gains or losses on the hedged item. When it is no longer probable that an anticipated transaction will occur within the originally determined period and the associated cash flow hedge has been discontinued, any gains or losses associated with the hedging item that were previously recognized in other comprehensive income are recognized in net income in the period.

When the conditions for hedge accounting cannot be applied, the changes in fair value of the derivative instruments are recognized as described above. The fair value of derivative financial instruments reflects changes in the commodity market prices and foreign exchange rates. Fair value is determined based on exchange or over-the-counter price quotations by reference to bid or asking price as appropriate, in active markets. In illiquid or inactive markets, the Partnership uses appropriate valuation and price modeling techniques commonly used by market participants to estimate fair value. Fair values determined using valuation models require the use of assumptions concerning the amounts and timing of future cash flows. Fair value amounts reflect management’s best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates, discount rates for time value and volatility where available. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.

Income Taxes

Future income tax assets and liabilities are determined based on temporary differences between the tax basis of assets and liabilities and their carrying amounts for accounting purposes. Future income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse.

The Partnership was not subject to Canadian income taxes and accordingly those taxes which are the responsibility of individual partners have not been reflected in these consolidated financial statements. Certain subsidiaries are taxable and applicable income, withholding and other taxes have been reflected in these consolidated financial statements. However, the Partnership is subject to Canadian income taxes after 2010. As a result, the Partnership recognized future income taxes based on the estimated net taxable timing differences which are expected to reverse after 2010.

Cash and Cash Equivalents

Cash and cash equivalents include cash or highly liquid, investment-grade, short-term investments and are recorded at fair value.

Inventories

Inventories represent small parts and other consumables and fuel, the majority of which is consumed by the Partnership in provision of its goods and services, and are valued at the lower of cost and net realizable value. Cost includes the purchase price, transportation costs and other costs to bring the inventories to their present location and condition. The cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not interchangeable, cost is assigned using specific identification of their individual costs. Previous write downs of inventories from cost to net realizable value can be fully or partially reversed if supported by economic circumstances.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 2. Significant Accounting Policies (Continued)

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. Power generation plant and equipment, less estimated residual value, is depreciated on a straight-line basis over estimated service lives of one to fifty years. Other equipment, which includes the costs of office furniture, tools and vehicles, is capitalized and depreciated over estimated service lives of three to fifteen years.

Property, plant and equipment, including asset retirement costs, is periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to the asset’s fair value is recognized during the period, with a charge to income.

Power Purchase Arrangements

On acquisition of power plants with existing PPAs in place, the acquired PPAs are capitalized as an intangible asset and included within the balance sheet as PPAs. The Partnership records acquired PPAs at their fair value and amortizes them over the remaining terms of the contracts.

Power Purchase Arrangements Containing a Lease

The Partnership has entered into PPAs to sell power at predetermined rates. PPAs are assessed as to whether they contain leases which convey to the counterparty the right to the use of the Partnership’s property, plant and equipment in return for future payments. Such arrangements are classified as either capital or operating leases. PPAs that transfer substantially all of the benefits and risks of ownership of property to the PPA counterparty are classified as direct financing leases.

Finance income related to leases or arrangements accounted for as direct financing leases is recognized in a manner that produces a constant rate of return on the net investment in the lease. The net investment is comprised of net minimum lease payments and unearned finance income. Unearned finance income is the difference between the total minimum lease payments and the carrying value of the leased property. Unearned finance income is deferred and recognized in net income over the lease term.

Payments received under PPAs classified as direct financing leases are segmented into those for the lease and those for other elements on the basis of their relative fair value.

Long-term Investments

Investments that are not controlled by the Partnership, but over which it has significant influence are accounted for using the equity method and recorded at original cost and adjusted periodically to recognize the Partnership’s proportionate share of the investee’s net income or losses after the date of investment, additional contributions made and dividends received. Other investments are stated at cost. When there has been a decline in value that is other than temporary, the carrying amount of an investment is reduced to its fair value.

Investment in Joint Venture

The investment in a joint venture is accounted for using the proportionate consolidation method. Under this method, the Partnership records its proportionate share of assets, liabilities, revenue and expenses of the joint venture.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 2. Significant Accounting Policies (Continued)

Goodwill

Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the net assets acquired based on their fair values. Goodwill is not amortized, but rather is tested for impairment at least annually or more frequently if events and circumstances indicate that a possible impairment may exist. To test for impairment, the fair value of the reporting unit to which the goodwill relates is compared to the carrying amount, including goodwill, of the reporting unit. If the carrying amount of the reporting unit exceeds its fair value, the fair value of the reporting unit’s goodwill is compared with its carrying amount to measure the impairment loss, if any. The Partnership determines the fair value of a reporting unit using discounted cash flow techniques and estimated future cash flows.

Other Intangible Assets

Other intangible assets consist primarily of emissions allowances and are amortized over their remaining lives.

Asset Retirement Obligations

The Partnership recognizes asset retirement obligations for its power plants. The fair value of the liability is added to the carrying amount of the associated plant asset and depreciated accordingly. The liability is accreted at the end of each period through charges to depreciation, amortization and accretion. The Partnership has recorded these asset retirement obligations, as it is legally required to remove the facilities at the end of their useful lives and restore the plant sites to their original condition.

Foreign Currency Translation

The Partnership’s functional and presentation currency is the Canadian dollar. The Partnership indirectly owns U.S. subsidiaries which are self-sustaining foreign operations translated to Canadian dollars using the current rate method. Assets and liabilities are translated at the exchange rate in effect at the balance sheet date. Revenues and expenses are translated at average exchange rates prevailing during the period. The resulting translation gains and losses are deferred and included in accumulated other comprehensive income until there is a reduction in the Partnership’s net investment in the foreign operations. Prior to October 1, 2008, the U.S. subsidiaries were considered integrated foreign operations.

Net Income Per Unit

Net income per unit is calculated by dividing net income by the weighted average number of units outstanding, including those held by CPC.

Note 3. Changes in Accounting Policies

Future Accounting Changes

International financial reporting standards

The CICA has announced that Canadian reporting issuers will need to begin reporting under IFRS, including comparative figures, by the first quarter of 2011. In the fourth quarter of 2010, the Audit Committee reviewed accounting policy decisions for all standards that were in effect at the end of the year ended December 31, 2010.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 4. Inventories

	2010		2009		2008
Parts and other consumables	$	9.0	$	14.2	$	7.7
Fuel	10.5		10.4		15.5
	$	19.5	$	24.6	$	23.2

Inventories expensed in cost of fuel and other plant operating expenses were $47.1 million for the year ended December 31, 2010 (December 31, 2009—$21.2 million; December 31, 2008—$40.5 million).

No write-down of inventory or reversal of a previous write-down was recognized in the years ended December 31, 2010, 2009 or 2008. As at December 31, 2010, 2009 and 2008, no inventories were pledged as security for liabilities.

Note 5. Property, Plant and Equipment

	2010						2009
	Cost		Accumulated Depreciation		Net Book Value		Cost		Accumulated Depreciation		Net Book Value
Land	$	4.9	$	—	$	4.9	$	5.0	$	—	$	5.0
Plant and equipment	1,439.2		455.3		983.9		1,421.6		399.0		1,022.6
Other equipment	10.1		9.3		0.8		11.0		8.7		2.3
Construction in progress	4.5		—		4.5		34.8		—		34.8
	$	1,458.7	$	464.6	$	994.1	$	1,472.4	$	407.7	$	1,064.7

	2008
	Cost		Accumulated Depreciation		Net Book Value
Land	$	3.3	$	—	$	3.3
Plant and equipment	1,423.9		346.3		1,077.6
Other equipment	8.7		7.7		1.0
Construction in progress	24.1		—		24.1
	$	1,460.0	$	354.0	$	1,106.0

Depreciation, amortization and accretion expense consists of:

	2010		2009			2008
Depreciation of property, plant and equipment	$	69.6	$	65.0		$	55.9
Accretion of asset retirement obligations	2.9		1.9			1.6
Amortization of PPAs	25.4		27.8			31.4
Other amortization	0.4		(1.4		)	(0.6		)
	$	98.3	$	93.3		$	88.3

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 6. Power Purchase Arrangements

	2010						2009						2008
	Cost		Accumulated Amortization		Net Book Value		Cost		Accumulated Amortization		Net Book Value		Cost		Accumulated Amortization		Net Book Value
PPAs	$	440.9	$	150.9	$	290.0	$	462.8	$	132.4	$	330.4	$	530.0	$	121.4	$	408.6

The PPAs are being amortized over the remaining terms of the contracts, which range from four months to seventeen years.

Note 7. Goodwill

The changes in the carrying value of goodwill are as follows:

	2010			2009			2008
Goodwill, beginning of year	$	47.6		$	55.1		$	50.9
Foreign currency translation adjustment	(2.6		)	(7.5		)	4.2
Goodwill, end of year	$	45.0		$	47.6		$	55.1

Note 8. Other Assets

	2010			2009			2008
Net investment in lease	$	23.7		$	26.9		$	33.2
Other long-term receivable	17.6			—			—
Long-term investments	20.3			21.4			19.2
Receivable from Equistar	—			9.1			9.6
Other intangible assets:
Cost	1.4			1.2			2.5
Accumulated amortization	(0.2		)	(0.1		)	(0.1		)
	$	62.8		$	58.5		$	64.4

Net Investment in Lease

The PPA under which the power generation facility located in Oxnard, California operates is considered to be a direct financing lease for accounting. The PPA expires in 2020. The current portion of the net investment in lease of $1.5 million is included in accounts receivable (2009—$1.6 million; 2008—$1.8 million). Financing income for the year ended December 31, 2010 of $2.5 million is included in revenues (2009—$2.9 million; 2008—$2.8 million).

Other Long-term Receivable

Other long-term receivable relates to amounts recoverable over the remaining term of the Oxnard PPA for unbilled services.

Long-term Investment and Asset Impairment Charge

The Partnership’s common ownership interest in Primary Energy Recycling Holdings LLC (PERH) was accounted for on the equity basis up to August 24, 2009 and on a cost basis thereafter as a result of a recapitalization of PERH and changes to the management agreement between the Partnership, PERH, Primary Energy Recycling Corporation (PERC) and Primary Energy Operations LLC. The Partnership has

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 8. Other Assets (Continued)

converted all of its common and preferred interests in PERH to a 14.3% common equity interest in PERH in connection with a recapitalization of PERH pursuant to which all previously outstanding common and preferred interests in PERH, including those held by the Partnership and PERC, were converted to new common equity interests. No gain or loss was recorded on the conversion.

In November 2009, the Partnership exercised its pre-emptive right to maintain its pro-rata interest (14.3%) in PERH whereby the Partnership subscribed for new common equity interests at an aggregate subscription price of $8.8 million (US$8.3 million).

The Partnership recorded a pre-tax impairment charge of $24.1 million during the year ended December 21, 2008 to write down the investment based on its fair value.

Note 9. Long-term Debt

	Effective interest rate		2010		2009		2008
Senior unsecured notes, due June 2036 at 5.95%	6.12	%	210.0		$	210.0	$	210.0
Senior unsecured notes (US$190.0 million), due July 2014 at 5.90%	6.16	%	189.0		199.7		231.4
Senior unsecured notes (US$150.0 million), due August 2017 at 5.87%	6.01	%	149.2		157.6		182.7
Senior unsecured notes (US$75.0 million), due August 2019 at 5.97%	6.11	%	74.6		78.8		91.4
Secured term loan at 11.25%	11.57	%	—		1.4		2.6
Revolving credit facilities at floating rates	2.85	%	86.1		78.3		86.7
			708.9		725.8		804.8
Less: Current portion of long-term debt			—		1.4		1.3
Deferred debt issue costs			4.4		5.0		5.0
			$	704.5	$	719.4	$	798.5

Senior Unsecured Notes

The notes are unsecured obligations of the Partnership and, subject to statutory preferred exemptions, rank equally with all other unsecured and unsubordinated indebtedness of the Partnership. Interest on the senior unsecured notes is payable semi-annually.

Revolving Credit Facilities

The Partnership has available to it unsecured two-year credit facilities of $100.0 million, $100.0 million and $125.0 million, for a total of $325.0 million, committed to 2012 and uncommitted amounts of $20.0 million and $20.0 million (US$20.0 million). At December 31, 2010, $86.1 million was drawn against these facilities (December 31, 2009—$78.3 million; December 31, 2008—$86.7 million).

Under the terms of the extendible facilities, the Partnership may obtain advances by way of prime loans, US base rate loans, US LIBOR loans and bankers’ acceptances. Depending on the facility, amounts drawn by way of prime loans bear interest at the prevailing Canadian prime rate or the average one-month bankers’ acceptance rate plus a spread based on the Partnership’s credit rating. Amounts drawn by way of US LIBOR loans bear interest at the prevailing LIBOR rate plus a spread based on the Partnership’s credit rating. Amounts drawn by way of bankers’ acceptances bear interest at the prevailing bankers’

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 9. Long-term Debt (Continued)

acceptance rate plus a spread based on the Partnership’s credit rating. The Partnership’s revolving credit facilities may be used for general partnership purposes including working capital support.

Deferred Debt Issue Costs

At December 31, 2010 deferred debt issue costs were $7.3 million, net of accumulated amortization of $2.9 million (December 31, 2009—deferred debt issue costs were $6.8 million, net of accumulated amortization of $1.8 million; December 31, 2008—deferred debt issue costs were $6.4 million, net of accumulated amortization of $1.4 million).

Financial Charges and Other, Net

	2010			2009			2008
Interest on long-term debt	$	39.0		$	42.6		$	40.3
Foreign exchange losses	0.3			1.0			26.2
Interest on Equistar receivable	(1.8		)	—			—
Losses from equity investment	—			3.1			6.3
Dividend income	—			(1.1		)	(1.9		)
Other	2.6			0.8			(0.2		)
	$	40.1		$	46.4		$	70.7

Note 10. Other Liabilities

	2010		2009		2008
Asset retirement obligations	$	29.3	$	28.8	$	28.6
Deferred revenue	6.5		4.5		—
Other long-term liabilities	1.3		1.5		4.7
	$	37.1	$	34.8	$	33.3

Asset Retirement Obligations

	2010			2009			2008
Asset retirement obligations, beginning of year	$	28.8		$	28.6		$	21.1
Adjustment to asset retirement obligations	(1.5		)	—			—
Assumption of Morris asset retirement obligations	—			—			5.9
Accretion of asset retirement obligations	2.9			1.9			1.6
Foreign currency translation adjustment	(0.9		)	(1.7		)	—
Asset retirement obligations, end of year	$	29.3		$	28.8		$	28.6

At December 31, 2010, the estimated cost to settle the Partnership’s asset retirement obligations was $129.4 million (2009—$146.0 million; 2008—$156.9 million) calculated using inflation rates ranging from 2.0% to 3.0% per annum (2009—2.1% to 3.0%; 2008—3.0%). The estimated cash flows were discounted at rates ranging from 6.4% to 7.5% (2009—6.4% to 7.5%; 2008—6.4%—7.5%). At December 31, 2010, the expected timing of payment for settlement of the obligations ranges from 9 to 80 years.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 11. Preferred Shares Issued by a Subsidiary Company

In November 2009, a subsidiary of the Partnership issued 4 million 7.0% Cumulative Rate Reset Preferred Shares, Series 2 (the Series 2 Shares) priced at $25.00 per share. The Series 2 Shares pay fixed cumulative dividends of $1.75 per share per annum, as and when declared, for the initial five-year period ending December 31, 2014. The dividend rate will reset on December 31, 2014 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.18%. The Series 2 Shares are redeemable at $25.00 per share by the Partnership on December 31, 2014 and on December 31 every five years thereafter. The holders of the Series 2 Shares will have the right to convert their shares into Cumulative Floating Rate Preferred Shares, Series 3 (the Series 3 Shares) of the Partnership, subject to certain conditions, on December 31, 2014 and every five years thereafter. The holders of Series 3 Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the board of directors of the Partnership, at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate and 4.18%.

A subsidiary of the Partnership has issued 5 million 4.85% Cumulative Redeemable Preferred Shares, Series 1 priced at $25.00 per share with dividends payable on a quarterly basis at the annual rate of $1.2125 per share. On or after June 30, 2012, the shares are redeemable by the subsidiary company at $26.00 per share, declining by $0.25 each year to $25.00 per share after June 30, 2016. The shares are not retractable by the holders. Under the terms of the preferred share issue, the Partnership will not make any distributions on partnership units if the declaration or payment of dividends on the preferred shares is in arrears.

Dividends will not be paid on the preferred shares if the senior unsecured notes of the Partnership are in default.

The Partnership paid dividends of $13.1 million in 2010 (2009—$7.2 million; 2008—$6.1 million) and incurred associated net current and future income taxes of $1.0 million (2009—$0.7 million; 2008—$0.5 million) for an after-tax preferred share dividend of $14.1 million (2009—$7.9 million; 2008—$6.6 million).

Note 12. Partners’ Capital

	2010			2009
	Number of Units	Millions of Dollars		Number of Units	Millions of Dollars
Partnership capital, beginning of year	54,153,871	$	1,200.6	53,897,279	$	1,197.1
Partnership units issued pursuant to distribution reinvestment plan	1,670,657	27.0		256,592	3.5
Partnership capital, end of year	55,824,528	$	1,227.6	54,153,871	$	1,200.6

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 12. Partners’ Capital (Continued)

The Partnership is authorized to issue an unlimited number of limited partnership units. Each unit represents an equal, undivided limited partnership interest in the Partnership and entitles the holder to participate equally in distributable cash and net income. Units are not subject to future calls or assessments and entitle the holder to limited liability. Each unit is transferable, subject to the requirements referred to in the Partnership Agreement.

In October 2009, the Partnership implemented a Premium Distribution (Premium Distribution is a trademark of Canaccord Capital Corporation) and Distribution Reinvestment Plan (the Plan) that provides eligible unitholders with two alternatives to receiving the monthly cash distributions, including the option to accumulate additional units in the Partnership by reinvesting cash distributions in additional units issued at a 5% discount to the Average Market Price of such units (as defined in the Plan) on the applicable distribution payment date. Alternatively, under the Premium Distribution&!bSUP!;TM&!eSUP!; component of the Plan, eligible unitholders may elect to exchange these additional units for a cash payment equal to 102% of the regular cash distribution on the applicable distribution payment date.

In 2010, the weighted average number of units outstanding was 54,968,742 (2009—53,914,046; 2008—53,897,279).

Note 13. Accumulated Other Comprehensive Income

The components of accumulated other comprehensive income are as follows:

	2010			2009			2008
Cumulative unrealized losses on translating net assets of self-sustaining foreign operations	$	(159.3	)	$	(131.9	)	$	(66.0	)
Deferred gains on derivatives de-designated as cash flow hedges	0.4			0.9			1.3
Unrealized losses on derivative instruments designated as cash flow hedges	(50.9		)	(6.4		)	—
Total accumulated other comprehensive income	$	(209.8	)	$	(137.4	)	$	(64.7	)

Note 14. Income Taxes

Components of income tax recovery	2010			2009			2008
Current income taxes	$	0.4		$	1.3		$	1.7
Future income taxes	(9.8		)	(10.2		)	(33.1		)
	$	(9.4	)	$	(8.9	)	$	(31.4	)

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 14. Income Taxes (Continued)

Reconciliation of Income Tax Recovery

	2010			2009			2008
Net income (loss) from continuing operations before income taxes and preferred share dividends	$	35.2		$	56.8		$	(91.9	)
Combined federal and provincial tax rate	29.0		%	31.0		%	31.5		%
Expected income tax expense (recovery)	10.2			17.6			(28.9		)
Amounts related to (non-taxable) non-deductible foreign exchange and other permanent differences	(9.9		)	(6.7		)	2.7
Changes in valuation allowance	(0.1		)	(4.5		)	12.7
Change due to enactment of rate changes	0.5			0.7			—
Income allocated to Partnership unitholders	(7.5		)	0.1			(15.8		)
Taxes related to prior periods	1.3			(9.9		)	—
Statutory and other rate differences	1.4			(9.6		)	6.4
Other	(5.3		)	3.4			(8.5		)
Actual income tax recovery	$	(9.4	)	$	(8.9	)	$	(31.4	)

Future Income Tax Assets and Liabilities

	2010			2009			2008
Loss carryforwards	$	87.1		$	75.4		$	53.9
Difference in accounting and tax basis of intangible assets	2.7			4.5			6.7
Asset retirement obligations	5.7			4.1			3.9
Deferred financing charges	3.5			2.4			1.8
Non-deductible accrued amounts	1.7			1.8			2.1
Unrealized losses on derivative instruments	16.0			0.8			5.1
Deferred revenue	2.9			1.7			—
Long-term receivable	—			0.8			1.0
Other	—			—			0.9
Future income tax assets	$	119.6		$	91.5		$	75.4
Difference in accounting and tax basis of plant, equipment and PPAs	$	(109.2	)	$	(114.5	)	$	(115.4	)
Unrealized foreign exchange gains	(4.9		)	(4.3		)	(1.6		)
Long-term receivable	(7.0		)	—			—
Other	(0.9		)	(2.3		)	—
Future income tax liabilities	$	(122.0	)	$	(121.1	)	$	(117.0	)
Net future income tax liabilities	$	(2.4	)	$	(29.6	)	$	(41.6	)

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 14. Income Taxes (Continued)

Presented on the Balance Sheet as Follows:

	2010			2009			2008
Current assets	$	7.1		$	1.9		$	2.3
Non-current assets	41.2			35.0			16.8
Current liabilities	—			(3.8		)	—
Non-current liabilities	(50.7		)	(62.7		)	(60.7		)
	$	(2.4	)	$	(29.6	)	$	(41.6	)

Income Taxes

The Partnership follows the liability method of accounting for income taxes, whereby income taxes are recognized on differences between the financial statement carrying values and the respective income tax basis of assets and liabilities. Future income tax assets and liabilities are measured using the substantively enacted tax rates and laws that will be effect when the temporary differences are expected to be recovered or settled. To the extent that the realization of a future tax asset is not considered ‘more likely than not,’ a valuation allowance is provided.

Taxation of Flow-through Entities

Pursuant to the Income Tax Act (Canada), beginning on January 1, 2011, the Partnership will be subject to a specified investment flow-through (SIFT) distribution tax of 16.5% (15% beginning in 2012) along with a provincial tax component of 10%. The tax rates are equivalent to the substantially enacted corporate income tax rates, but apply to distributions of certain types of income. As the partnership generates cash flows from both Canada and the United States, only the cash flows generated in Canada would be subject to the SIFT tax. Cash flows generated in the United States are exempt from the SIFT tax as they are subject to United States taxation. The Partnership expects that its distributions will be treated as eligible dividends starting on January 1, 2011.

The net future income tax liability relating to the SIFT legislation decreased $17.0 million to $45.7 million in 2010 (2009—$62.7 million; 2008—$60.7 million) due a reduction in the net taxable temporary differences which are expected to reverse subsequent to 2010. This estimate of the net future tax liability is based on the current best estimate of the accounting and tax values that exist on December 31, 2010. The Partnership and its Canadian subsidiary limited partnerships have net taxable temporary differences of $185.8 million (2009—$245.7 million, 2008—$309.1 million) of which the tax effects of $184.0 million (2009—$250.5 million, 2008—$230.5 million) are reflected in these consolidated financial statements due to the enactment of the SIFT legislation in 2007.

Taxation of Corporate Subsidiaries

Current and future taxes have been reflected in respect of taxable income and temporary differences relating to the corporate subsidiaries of the Partnership. The Canadian corporate subsidiaries of the Partnership are subject to tax on their taxable income at a rate of approximately 29% (2009—31.0%; 2008—31.5%) whereas the U.S. corporate subsidiaries are subject to tax on their taxable income at rates varying from 34% to 41% (2009—34.0% to 41.0%; 2008—34.0%—41.0%). Future income taxes relating to the corporate subsidiaries have been reflected in these consolidated financial statements except in respect

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 14. Income Taxes (Continued)

of deductible temporary differences of $4.4 million (2009—$4.4 million; 2008—$54.9 million) for which no tax benefit has been recognized.

Income Tax Loss Carry Forwards

As at December 31, 2010, the Partnership has income tax loss carry forwards of approximately US $151.4 million (2009—US$128.9 million, 2008—US$84.8 million) in the US, which may be used to reduce future US taxable income. Of these losses, US$22.3 million (2009—US$22.3 million; 2008 US$22.3 million) expire between 2022 and 2025 with the remainder expiring thereafter and $18.1 million (2009—US$18.1 million; 2008—US$22.3 million) of the losses are restricted under Section 382 of the Internal Revenue Code. Under Section 382 of the Internal Revenue Code of 1986, as amended, the utilization of the restricted losses is limited to an annual amount of US$4.7 million.

As at December 31, 2010, the Partnership has both non-capital losses and capital losses that are available for carry forward in Canada. For Canadian income tax purposes, there are non-capital loss carry forwards of approximately $120.7 million (2009—$96.7 million; 2008—$56.3 million), which may be used to reduce future income taxes otherwise payable and which expire in the years 2011 to 2030. There are also capital loss carry forwards of $3.5 million (2009—$3.5 million; 2008—$14.9 million) which can be carried forward indefinitely. The tax benefit on $0.3 million (2009—$0.2 million; 2008—$0.1 million) of the non-capital losses carry forwards and on $3.5 million (2009—$3.5 million; 2008—$14.9 million) of the capital loss carry forwards have been fully offset by the recognition of a valuation allowance.

Out of Period Adjustment

During the year ended December 31, 2009, the Partnership recorded an out-of-period adjustment of $9.7 million relating to 2007 and 2008 in order to recognize net future income tax assets associated with the Partnership’s interest in PERH. Management determined that the impact of the adjustment was not material, either individually or in aggregate, to any of the prior periods’ financial statements and accordingly, that a restatement of previously issued financial statements was not necessary.

Note 15. Financial Instruments

Fair Values and Classification of Financial Assets and Liabilities

The Partnership classifies its cash and cash equivalents and current and non-current derivative instruments assets and liabilities as held for trading and measures them at fair value. Accounts receivable are classified as loans and receivables and accounts payable and distributions payable are classified as other financial liabilities and are measured at amortized cost. The fair values of accounts receivable, accounts payable and distributions payable are not materially different from their carrying amounts due to their short-term nature. The investment in PERH is classified as available for sale and the net investment in lease is classified as loans and receivables. The net investment in lease and other long-term receivable relates to the Oxnard PPA, which is considered a direct financing lease for accounting purposes.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 15. Financial Instruments (Continued)

The classification, carrying amounts and fair values of the Partnership’s other financial instruments are summarized as follows:

2010

Carrying amount

Loans and
receivables

Other
financial
liabilities

Total

Total fair
value

Other assets—net investment in lease and other long-term receivable

41.3

—

41.3

42.4

Long-term debt (including current portion)

—

(704.5

)

(704.5

)

(697.7

)

	2009
	Carrying amount
	Loans and receivables		Other financial liabilities			Total			Total fair value
Other assets—net investment in lease and other long-term receivable	$	26.9	$	—		$	26.9		$	27.1
Other assets—receivable from Equistar	9.1		—			9.1			$	9.1
Long-term debt (including current portion)	—		(720.8		)	(720.8		)	(667.7		)

	2008
	Carrying amount
	Loans and receivables		Other financial liabilities			Total			Total fair value
Other assets—net investment in lease and other long-term receivable	$	33.2	$	—		$	33.2		$	33.1
Other assets—receivable from Equistar	9.6		—			9.6			$	9.6
Long-term debt (including current portion)	—		(799.8		)	(799.8		)	(685.9		)

The fair value of the Partnership’s long-term debt is based on determining an appropriate yield for the Partnership’s debt as at December 31, 2010, 2009 and 2008. This yield is based on an estimated credit spread for the Partnership over the yields of long-term Government of Canada and U.S. Government bonds that have similar maturities to the Partnership’s debt. The estimated credit spread is based on the Partnership’s indicative spread as published by independent financial institutions.

The Partnership has used the carrying amount of its investment in PERH as its fair value as the shares are not quoted in an active market and their fair value therefore cannot be measured reliably.

The fair value of the Partnership’s net investment in the financing lease and related long-term receivables is based on the estimated interest rate implicit in a comparable lease arrangement as at December 31, 2010, 2009 and 2008.

Derivative Instruments

Derivative instruments are held to manage financial risk related to energy procurement and treasury management. All derivative instruments, including embedded derivatives, are classified as held for trading

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 15. Financial Instruments (Continued)

and are recorded at fair value on the balance sheet unless exempted from derivative treatment as a normal purchase, sale or usage. All changes in their fair value are recorded in net income.

The derivative instruments assets and liabilities used for risk management purposes consist of the following:

December 31, 2010

Natural gas

Foreign exchange

Hedges

Non-hedges

Total

Derivative instruments assets:

Current

—

10.4

Non-current

—

29.7

Derivative instruments liabilities:

Current

(16.2

)

(3.0

)

(1.9

)

(21.1

)

Non-current

(76.9

)

—

(5.0

)

(81.9

)

(93.1

)

(3.0

)

33.2

(62.9

)

Net notional amounts:

Gigajoules (GJs) (millions)

37.8

6.5

U.S. foreign exchange (U.S. dollars in millions)

309

Contract terms (years)

6.0

0.8 to 2.0

0.2 to 5.5

	December 31, 2009
	Natural gas					Foreign exchange
	Hedges			Non-hedges		Non-hedges			Total
Derivative instruments assets:
Current	$	1.0		$	2.5	$	4.3		$	7.8
Non-current	—			6.0		25.8			31.8
Derivative instruments liabilities:
Current	(2.1		)	—		(0.8		)	(2.9		)
Non-current	(32.8		)	—		(3.6		)	(36.4		)
	$	(33.9	)	$	8.5	$	25.7		$	0.3
Net notional amounts:
Gigajoules (GJs) (millions)	45.0			11.0
U.S. foreign exchange (U.S. dollars in millions)						395
Contract terms (years)	1.0 to 7.0			0.0 to 3.0		0.2 to 6.0

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 15. Financial Instruments (Continued)

	December 31, 2008
	Natural gas					Foreign exchange
	Hedges		Non-hedges			Non-hedges			Total
Derivative instruments assets:
Current	$	—	$	15.5		$	7.3		$	22.8
Non-current	—		23.5			3.6			27.1
Derivative instruments liabilities:
Current	—		(1.5		)	(11.5		)	(13.0		)
Non-current	—		(0.6		)	(37.9		)	(38.5		)
	$	—	$	36.9		$	(38.5	)	$	(1.6	)
Net notional amounts:
Gigajoules (GJs) (millions)	—		69.0
U.S. foreign exchange (U.S. dollars in millions)						456.9
Contract terms (years)	—		0.1 to 8.0			0.2 to 6.0

The fair value of derivative instruments are determined, where possible, using exchange or over-the-counter price quotations by reference to quoted bid, ask, or closing market prices, as appropriate in active markets. Where there are limited observable prices due to illiquid or inactive markets, the Partnership uses appropriate valuation and price modeling commonly used by market participants to estimate fair value. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. In general, fair value amounts reflect management’s best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates, discount rates for time value, and volatility for all of the Partnership’s financial instruments. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material.

Unrealized and realized pre-tax gains and (losses) on derivative instruments recognized in net income and other comprehensive income were:

	Income statement category	2010			2009			2008
Foreign exchange non-hedges	Revenue	$	12.4		$	59.8		$	(57.6	)
Natural gas non-hedges	Cost of fuel	(9.3		)	(52.1		)	(30.4		)
Natural gas hedges—ineffective portion	Cost of fuel	(2.2		)	(0.3		)	—
Natural gas hedges—effective portion	Other comprehensive loss	(59.1		)	(8.9		)	—

If hedge accounting requirements are not met, unrealized and realized gains and losses on natural gas derivatives are recorded in cost of fuel. If hedge accounting requirements are met, realized gains and losses on natural gas derivatives are recorded in cost of fuel while unrealized gains and losses are recorded in other comprehensive income.

The Partnership has elected to apply hedge accounting effective July 31, 2009, on certain derivative instruments it uses to manage commodity price risk relating to natural gas prices. For the year ended December 31, 2010, the change in the fair value of the ineffective portion of hedging derivatives required to be recognized in the income statement was $2.2 million. Of the $50.9 million of after tax losses related to derivative instruments designated as cash-flow hedges included in accumulated other comprehensive income at December 31, 2010, losses of $8.8 million, net of income taxes of $3.2 million are expected to

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 15. Financial Instruments (Continued)

settle and be reclassified to net income during the year ended December 31, 2011. The Partnership’s cash flow hedges extend up to 2016.

Fair Value Hierarchy

Fair value represents the Partnership’s estimate of the price at which a financial instrument could be exchanged between knowledgeable and willing parties in an orderly arm’s length transaction under no compulsion to act. Fair value measurements recognized in the consolidated balance sheets are categorized into levels within a fair value hierarchy based on the nature of the valuation inputs, and precedence is given to those fair value measurements calculated using observable inputs over those using unobservable inputs. The determination of fair value requires judgment and is based on market information where available and appropriate. The following levels were established for each input:

Level 1: Fair value is based on quoted prices (unadjusted) in active markets for identical instruments. Financial instruments classified in Level 1 include cash and cash equivalents, including highly liquid short term investments.

Level 2: Fair value is based on other than unadjusted quoted prices included in Level 1, which are either directly or indirectly observable at the reporting date. Level 2 includes those financial instruments that are valued using commonly used valuation techniques, such as the discounted cash flow model or black-scholes option pricing models. Valuation models use inputs such as quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active but observable, and other observable inputs that are principally derived from or corroborated by observable market data for substantially the full term of the instrument. Financial instruments classified in Level 2 includes commodity, foreign exchange, and interest rate derivatives whose values are determined based on broker quotes, observable trading activity for similar, but not identical instruments, and prices published on information platforms and exchanges.

Level 3: Fair value is based unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the instrument. Level 3 includes financial instruments that are also valued using commonly used valuation techniques described in Level 2, however some inputs used in the models may not be based on observable market data and therefore based on the Partnership’s best estimate from the perspective of a market participant. There are no financial instruments classified in Level 3 at the reporting date.

The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based upon the lowest level input that is significant to the derivation of the fair value. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment thereby affecting the placement within the fair value hierarchy levels. The following

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 15. Financial Instruments (Continued)

table presents the Partnership’s financial instruments measured at fair value on a recurring basis in the consolidated balance sheets, classified using the fair value hierarchy described above:

Level 1

Level 2

Level 3

Total

Financial assets:

Cash

27.5

—

27.5

Derivative instrument assets:

Foreign exchange non-hedges

—

40.1

—

40.1

Derivative instrument liabilities:

Natural gas hedges

—

(93.1

)

—

(93.1

)

Natural gas non-hedges

—

(3.0

)

—

(3.0

)

Foreign exchange non-hedges

—

(6.9

)

—

(6.9

)

There were no significant transfers between Level 1 and 2 for the period ended December 31, 2010.

Note 16. Changes in Non-cash Working Capital

	2010			2009			2008
Accounts receivable	$	8.4		$	8.5		$	10.5
Inventories	(14.7		)	(1.2		)	(4.7		)
Accounts payable	(1.1		)	(16.7		)	8.9
Other	0.1			1.1			(1.4		)
	$	(7.3	)	$	(8.3	)	$	13.3

Note 17. Risk Management

Risk Management Overview

The Partnership is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments which include market, interest, credit and liquidity risks. The Partnership’s overall risk management process is designed to identify, manage and mitigate business risk which includes financial risk, among others. Financial risk is managed according to objectives, targets and policies set forth by the Board of Directors. Risk management strategies, policies and limits are designed to ensure the risk exposures are managed within the Partnership’s business objectives and risk tolerance. The Partnership’s risk management objective is to protect and minimize volatility in cash provided by operating activities and distributions therefrom.

Market Risk

Market risk is the risk of loss that results from changes in market factors such as commodity prices, foreign currency exchange rates, interest rates and equity prices. The level of market risk to which the Partnership is exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of the Partnership’s financial assets and liabilities held, non-trading physical assets and contract portfolios. Commodity price risk management and the associated credit risk management are carried out in accordance with Partnership’s financial risk management policies, as approved by the Board of Directors.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 17. Risk Management (Continued)

To manage the exposure related to changes in market risk, the Partnership uses various risk management techniques including the use of derivative instruments. Derivative instruments may include financial and physical forward contracts. Such instruments may be used to establish a fixed price for an energy commodity, an interest-bearing obligation or an obligation denominated in a foreign currency. Market risk exposures are monitored regularly against approved risk limits and control processes are in place to monitor that only authorized activities are undertaken.

The sensitivities provided in each of the following risk discussions disclose the effect of reasonably possible changes in relevant prices and rates on net income at the reporting date. The sensitivities are hypothetical and should not be considered to be predictive of future performance or indicative of earnings on these contracts. The Partnership’s actual exposure to market risks is constantly changing as the Partnership’s portfolio of debt, foreign currency and commodity contracts change. Changes in fair value based on market variable fluctuations cannot be extrapolated as the relationship between the change in the market variable and the change in fair value may not be linear. In addition, the effect of a change in a particular market variable on fair values or cash flows is calculated without considering interrelationships between the various market rates or mitigating actions that would be taken by the Partnership.

Commodity price risk

The Partnership is exposed to commodity price risk as part of its normal business operations, particularly in relation to the prices of electricity, natural gas and coal. The Partnership actively manages commodity price risk by optimizing its asset and contract portfolios in the following manner:

· The Partnership commits substantially all of its power supply to long-term fixed price PPAs which limits the exposure to electricity prices;

· The Partnership purchases natural gas under long-term fixed price supply contracts to reduce the exposure to natural gas prices on certain of its natural gas fired generation plants; and

· The Partnership has entered into certain PPAs whereby the counterparty bears the variable costs linked to the price of natural gas or coal.

The following represents the sensitivity of net income to derivative instruments that are accounted for on a fair value basis. As at December 31, 2010, with all other variables unchanged, a $1.00/GJ increase (decrease) of the natural gas price is estimated to increase (decrease) net income by approximately $4 million after tax and other comprehensive income by approximately $24 million after tax. This assumption is based on the volumes or position held at December 31, 2010.

Foreign exchange risk

The Partnership is exposed to foreign exchange risk on its net investment in self-sustaining foreign operations. The risk is that the Canadian dollar value of the U.S. dollar net investment in self-sustaining foreign operations will vary as a result of the movements in exchange rates.

The Partnership’s foreign exchange management policy is to manage economic and material transactional exposures arising from movements in the Canadian dollar against the U.S. dollar. The Partnership’s foreign currency exposure arises from anticipated U.S. dollar denominated cash flows from its U.S. operations and from debt service obligations on U.S. dollar borrowings. The Partnership coordinates and manages foreign currency risk through the General Partner’s central Treasury function.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 17. Risk Management (Continued)

Foreign exchange risk is managed by considering naturally occurring opposite movements wherever possible and then managing any material residual foreign currency exchange risks according to the policies approved by the Board of Directors.

The Partnership primarily uses foreign currency forward contracts to fix the Canadian currency equivalent of its U.S. currency expected cash flows thereby reducing its anticipated U.S. denominated transactional exposure. The Partnership’s foreign currency risk management practice is to ensure a majority of the net currency exposure on anticipated transactions within 7 years are economically hedged. At December 31, 2010, US$308.9 million of future anticipated net cash flows from its U.S. plants were economically hedged for 2011 to 2016 at a weighted average rate of $1.13 per US $1.00.

At December 31, 2010, holding all other variables constant, a $0.10 strengthening (weakening) of the Canadian dollar against the U.S. dollar would increase (decrease) net income by approximately $19 million after tax as a result of changes in the fair value of foreign exchange contracts.

This sensitivity analysis excludes translation risk associated with the application of the current rate and temporal translation methods, financial instruments that are non-monetary items, and financial instruments denominated in the functional currency in which they are transacted and measured.

Interest rate risk

The Partnership is exposed to changes in interest rates on its cash and cash equivalents and floating rate short-term and long-term obligations. The Partnership is exposed to interest rate risk from the possibility that changes in the interest rates will affect future cash flows or the fair values of its financial instruments. In some circumstances, floating rate funding may be used for short-term borrowings and other liquidity requirements. At December 31, 2010 the Partnership held $86.1 million in floating rate debt (December 31, 2009—$78.3 million; December 31, 2008 $86.7 million). The Partnership may also use derivative instruments to manage interest rate risk. At December 31, 2010, 2009 and 2008 the Partnership did not hold any interest rate derivative instruments.

Holding all other variables constant and assuming that the amount and mix of floating rate debt remains unchanged from that held at December 31, 2010, a 100 basis point change to interest rates would have a $0.9 million impact on net income and would have no impact on other comprehensive income.

Credit Risk

The electricity and steam generated at the Partnership’s facilities are sold under long-term contracts to 23 customers. Customers accounting for 10% or more of the Partnership’s revenue in 2010 were as follows:

	2010		2009		2008
Ontario Electricity Financial Corporation	26	%	23	%	26	%
San Diego Gas & Electric Company	11	%	10	%	18	%
British Columbia Hydro and Power Authority	11	%	10	%	11	%

The Partnership has exposure to credit risk associated with counterparty default under the Partnership’s PPAs, fuel supply agreements and foreign currency hedges. In the event of a default by a counterparty, existing PPAs may not be replaceable on similar terms as pricing in many of these

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 17. Risk Management (Continued)

agreements is favourable relative to their current markets. Credit risk is associated with the ability of counterparties to satisfy their contractual obligations to the Partnership, including payment and performance. Credit risk is managed by making appropriate credit assessments of counterparties on an ongoing basis, dealing primarily with creditworthy counterparties, diversifying the risk by using several counterparties and where appropriate and contractually allowed, requiring the counterparty to provide appropriate security.

Maximum credit risk exposure

The Partnership has the following financial assets that are exposed to credit risk:

	2010
	Canada		U.S.		Total
Trade receivables	$	21.1	$	31.4	$	52.5
Other assets—net investment in lease and other long-term receivable	—		41.3		41.3
Derivative instruments—current assets	10.4		—		10.4
Derivative instruments—non-current assets	29.7		—		29.7
	$	61.2	$	72.7	$	133.9

The maximum credit exposure of these assets is their carrying amount. No amounts were held as collateral at December 31, 2010.

Accounts receivable

Accounts receivable consist primarily of amounts due from customers including industrial and commercial customers, government-owned or sponsored entities, regulated public utility distributors and other counterparties. The Partnership historically has not experienced credit losses and accordingly has not provided for an allowance for doubtful accounts. The Partnership evaluates the need for an allowance for potential credit losses by reviewing any overdue accounts and monitoring changes in the credit profiles of counterparties. The Partnership manages its credit risk exposures by dealing with creditworthy counterparties and, where appropriate and contractually allowed, taking back appropriate security from the counterparty. The Partnership determines the creditworthiness of counterparties using its own assessments and credit ratings by Standard and Poor’s (S&P) and DBRS Limited (DBRS) if available.

No material accounts receivable were past due and there was no provision for credit losses associated with these receivables and financial derivative instruments as all balances are considered to be fully recoverable. Accounts receivable are mostly from counterparties with an investment grade rating assigned by S&P.

Liquidity Risk

Liquidity risk is the risk that the Partnership will not be able to meet its financial obligations as they come due. The Partnership’s liquidity is managed centrally through the General Partner’s Treasury function. The Partnership manages liquidity through regular monitoring of cash and currency requirements by preparing short-term and long-term cash flow forecasts and matching the maturity profiles of financial

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 17. Risk Management (Continued)

assets and liabilities to identify financing requirements. The financing requirements are addressed through a combination of committed and demand revolving credit facilities and access to capital markets.

As at December 31, 2010, the Partnership had available bank credit facilities of $238.8 million committed to 2012 as discussed in Note 11—Long-term debt. In addition, the Partnership has a Canadian shelf prospectus under which it may raise up to $600.0 million in partnership units or debt securities. The Canadian shelf prospectus expires in August 2012.

The Partnership has a long-term debt rating of BBB/stable and BBB(high)/under review (negative), assigned by S&P and DBRS respectively.

The following are the undiscounted cash flow requirements and contractual maturities of the Partnership’s financial liabilities, including interest payments as at December 31, 2010:

	Within 1 year		Between 1 & 2 years		Between 2 & 3 years		Between 3 & 4 years		Between 4 & 5 years		Beyond 5 years		Total
Non-derivative financial liabilities:
Long-term debt(1)	$	—	$	86.1	$	—	$	189.0	$	—	$	433.8	$	708.9
Interest payments on long-term debt	39.5		39.1		36.9		32.2		25.7		291.5		464.9
Accounts payable and accrued liabilities(2)	36.5		—		—		—		—		—		36.5
Distributions payable	8.2		—		—		—		—		—		8.2
Derivative financial liabilities:
Net forward exchange contracts	$	1.9	$	2.2	$	1.4	$	0.9	$	0.9	$	—	$	7.3
Total	$	86.1	$	127.4	$	38.3	$	222.1	$	26.6	$	725.3	$	1,225.8

(1) Excluding deferred debt issue costs of $4.4 million.

(2) Excluding interest on long-term debt of $10.5 million and non-cash accruals of $5.9 million.

Note 18. Capital Management

The Partnership’s primary objectives when managing capital are to safeguard the Partnership’s ability to continue as a going concern, provide stable distributions to unitholders, to maintain an investment grade credit rating and to facilitate the acquisition or development of power projects in Canada and the U.S. consistent with the growth strategy of the Partnership. The Partnership’s objective of maintaining an investment grade credit rating is subject to change in order to manage the Partnership’s growth strategy with changing economic circumstances. The Partnership manages its capital structure in a manner consistent with the risk characteristics of the underlying assets. This overall objective and policy for managing capital remained unchanged in 2010 from the prior comparative period.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 18. Capital Management (Continued)

The Partnership considers its capital structure to consist of long-term debt, preferred shares and partners’ equity. The following table represents the total capital of the Partnership:

	2010		2009		2008
Long-term debt (including current portion)	$	704.5	$	720.8	$	799.8
Preferred shares	219.7		219.7		122.0
Partners’ equity	407.7		519.5		632.3
Total capital	$	1,331.9	$	1,460.0	$	1,554.1

The Partnership’s credit and stability ratings are presented in the following table:

	2010	2009	2008
Credit rating
S&P	BBB (stable)	BBB+/negative outlook	BBB+
DBRS	BBB(high)/under review (negative)	BBB(high)/negative trend	BBB(high)
Stability rating
S&P	Not Rated	SR-2	SR-2
DBRS	STA-2 (low)	STA-2	STA-2

The Partnership has the following externally imposed requirements on its capital:

· The Partnership must maintain a debt to total capitalization ratio, as defined in the debt agreements, of not more than 65%; and

· In the event the Partnership is assigned both a rating of less than BBB+ by S&P and a rating of less than BBB(high) by DBRS, the Partnership also would be required to maintain a ratio of earnings before interest, income taxes, depreciation and amortization to interest expense of not less than 2.5 to 1.

At December 31, 2010, the Partnership’s debt to capitalization ratio was 53% (December 31, 2009—49%; December 31, 2008—51%) and ratings of BBB/stable and BBB(high)/under review (negative) were assigned by S&P and DBRS respectively (December 31, 2009—BBB+/negative outlook and BBB(high)/negative trend; December 31, 2008—BBB+ and BBB(high)).

In order to manage its capital structure, the Partnership may adjust the amount of distributions paid to unitholders, issue or redeem preferred shares, issue or repay debt or issue or buy back partnership units.

Note 19. Related Party Transactions

In operating the Partnership’s 20 power plants, the Partnership and CPC (and prior to July 1, 2009, EPCOR) engage in a number of related party transactions which are in the normal course of business. These transactions are based on contracts and many of the fees are escalated by inflation. The table below

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 19. Related Party Transactions (Continued)

summarizes the amounts included in the calculation of net income for the years ended December 31, 2010, 2009 & 2008.

	2010		2009		2008
Transactions with CPC(1)
Revenue—Frederickson duct firing capacity fees	$	0.1	$	0.1	$	0.1
Cost of fuel—Greeley natural gas swap contract	1.5		2.6		0.3
Operating and maintenance expense	47.5		50.5		45.1
Management and administration
Base fee	0.9		1.1		1.4
Incentive fee	—		—		2.3
Enhancement fee	0.1		0.2		2.4
General and administrative costs	8.4		8.0		5.9
	9.4		9.3		12.0
Transactions of discontinued operations
Cost of fuel—gas demand charge	—		1.1		2.2
Operating and maintenance expense	—		1.4		2.9
Acquisition and divestiture fees	—		0.2		1.9
Distributions	29.1		32.2		41.6

(1) Prior to July 1, 2009, EPCOR.

Greeley Natural Gas Swap Contract

The Partnership has entered into a three year natural gas swap contract with CPC to cover most of the anticipated natural gas supply for Greeley.

Operating and Maintenance

CPC is entitled to receive a fee for services related to the operation and maintenance of the power plants under the Management and Operations Agreements. The annual fees are payable on an equal monthly basis. The annual fees for the Canadian plants and two U.S. plants are annually adjusted for inflation. The annual fees for the other U.S. plants are determined using a cost recovery basis.

Base and Incentive Fee

CPC is entitled to a base fee and an incentive fee under the Management and Operations Agreements in each fiscal year of the Partnership. The base fee is equal to 1% of the Partnership’s annual cash distributions. The incentive fee is equal to 10% of annual distributable cash flow greater than $2.40 per unit. Annual distributable cash flow is defined as cash flow from operating activities before changes in non-cash operating working capital plus dividends from PERH less scheduled debt repayments and maintenance capital.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 19. Related Party Transactions (Continued)

Enhancement Fee

CPC can curtail operations of the Ontario power plants and re-sell contracted natural gas at market prices, rather than produce off-peak power at lower rates. CPC is entitled to receive an enhancement fee equivalent to 35% of the incremental profit.

General and Administrative Costs

CPC is entitled to a fee related to the salaries and wages for management and administration employees for the U.S. plants. The fee is payable monthly on a cost recovery basis. CPC is also entitled to receive a fee for Canadian support staff costs for public entity services required per the Management and Operations Agreements. The annual fee is payable on an equal monthly basis and is adjusted annually for changes in salary costs.

Acquisition and Divestiture Fees

CPC is entitled to acquisition and divestiture fees under the Transaction Fees and Costs Agreements. The fee is based on the transaction value of the acquisition or disposition.

Distributions

During the year ended December 31, 2010, the Partnership made cash distributions to CPC in the amount proportionate to its ownership interest. At December 31, 2010, CPC owned 29.6% of the Partnership’s units (30.5% at December 31, 2009; at December 31, 2008 EPCOR owned 30.6% of the Partnership’s units).

Note 20. Joint Venture

A financial summary of the Partnership’s investments in the Frederickson joint venture is as follows:

	2010			2009			2008
Current assets	$	1.8		$	4.9		$	2.3
Long-term assets	109.5			120.3			145.3
Current liabilities	0.7			0.4			1.0
Long term liabilities	0.5			0.5			0.5
Revenues	21.3			23.3			23.0
Expenses	12.9			15.5			21.9
Net income	8.4			7.8			1.1
Cash provided by operating activities	13.2			13.3			8.1
Cash used in investing activities	—			—			—
Cash used in financing activities	(16.4		)	(10.2		)	(8.4		)

Note 21. Operating Leases

From the point of view of a lessor, the terms of the Manchief, Mamquam, Moresby Lake, Greeley and Kenilworth PPAs (2009 and 2008—Manchief, Mamquam, Moresby Lake, Greeley, Kenilworth, Southport and Roxboro PPAs) are operating leases. At December 31, 2010, the carrying amounts of the property, plant and equipment of these facilities was $247.7 million less accumulated depreciation of $46.7 million

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 21. Operating Leases (Continued)

(2009—$359.7 million and $47.6 million respectively; 2008—$317.6 million and $39.6 million respectively). The Partnership’s revenues for the year ended December 31, 2010 include $74.9 million with respect to the PPAs for these plants (2009—$116.2 million; 2008—$141.8 million).

Note 22. Segment Disclosures

The Partnership operates in one reportable business segment involved in the operation of independent power generation plants within British Columbia, Ontario and in the U.S. in California, Colorado, Illinois, New Jersey, New York, North Carolina and Washington State.

Geographic Information

	2010						2009						2008
	Canada		U.S.		Total		Canada		U.S.		Total		Canada		U.S.		Total
Revenue	$	217.6	$	314.8	$	532.4	$	263.8	$	322.7	$	586.5	$	159.2	$	340.1	$	499.3

	As at December 31, 2010						As at December 31, 2009						As at December 31, 2008
	Canada		U.S.		Total		Canada		U.S.		Total		Canada		U.S.		Total
Assets
PP&E	$	502.2	$	491.9	$	994.1	$	534.5	$	530.2	$	1,064.7	$	559.3	$	546.7	$	1,106.0
PPAs	33.6		256.4		290.0		36.6		293.8		330.4		39.7		368.9		408.6
Goodwill	—		45.0		45.0		—		47.6		47.6		—		55.1		55.1
Other assets	—		62.8		62.8		—		58.5		58.5		—		64.4		64.4
	$	535.8	$	856.1	$	1,391.9	$	571.1	$	930.1	$	1,501.2	$	599.0	$	1,035.1	$	1,634.1

Note 23. Commitments

As of December 31, 2010 the Partnership’s future purchase obligations were estimated as follows, based on existing contract terms and estimated inflation.

	2011		2012		2013		2014		2015		Later years		Total payments
Natural gas purchase contracts	$	51.9	$	53.7	$	43.9	$	47.2	$	50.7	$	53.6	$	301.0
Natural gas transportation contracts	12.9		10.4		10.6		10.2		7.6		15.6		67.3
Operating and maintenance contracts	27.5		28.1		28.6		29.2		29.8		46.0		189.2

The North Bay, Kapuskasing and Nipigon plants operate under fixed long-term natural gas supply contracts and natural gas transportation contracts with built-in annual escalators. Expiry dates for the contracts vary with an average remaining contract life of six years as at December 31, 2010. The remaining fuel requirements, which account for approximately 2% of the power plants’ fuel costs, are purchased at current market prices. Morris operates under a long-term natural gas transportation contract expiring in 2013.

The operating and maintenance contracts with the Manager are based on fixed fees escalated annually by inflation and have expiry terms of June 30, 2017.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 24. Morris Acquisition

On October 31, 2008, the Partnership acquired 100% of the equity interest in Morris Cogeneration LLC (Morris), a combined heat and power facility in Illinois. The total purchase price was $90.7 million including $88.4 million (US$73.4 million) in cash plus acquisition costs of approximately $2.3 million.

The financial results of Morris are included in the Partnership’s consolidated statements of income and loss from the date of acquisition. The purchase price for the acquisition of Morris was allocated to the assets acquired and liabilities assumed based on their estimated fair values as follows:

Current assets excluding cash and derivative instruments assets	$	9.9
Derivative instruments assets—current	0.7
Derivative instruments assets—long term	2.9
Property, plant and equipment	87.2
Power purchase arrangements	2.1
Other assets	1.5
Current liabilities	(6.6		)
Asset retirement obligations	(5.9		)
Contract liabilities	(1.1		)
Fair value of net assets acquired	$	90.7
Consideration
Cash	$	88.4
Acquisition costs	2.3
	$	90.7

Note 25. Discontinued Operations

The Partnership completed the sale of its Castleton facility (Castleton) on May 26, 2009. The disposition of Castleton resulted in proceeds of $11.9 million (US$10.7 million) less transaction costs of

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 25. Discontinued Operations (Continued)

$0.2 million (US$0.2 million) and a pre-tax accounting gain of $2.4 million. Revenues and expenses of Castleton were as follows:

	2009			2008
	(millions of dollars)
Revenues	$	2.1		$	12.9
Expenses
Cost of fuel	2.1			6.5
Operating and maintenance expense	2.1			4.4
Depreciation and amortization	—			3.7
Foreign exchange gains	—			(0.2		)
Loss from operations	(2.1		)	(1.5		)
Gain on sale of Castleton	2.4			—
Income (loss) before income tax	0.3			(1.5		)
Income tax expense (recovery)	0.5			(0.8		)
Loss from discontinued operations	$	(0.2	)	$	(0.7	)

The carrying amounts of the assets and liabilities of the discontinued operations at December 31, 2009 and December 31, 2008 were as follows:

	2009		2008
Assets of the discontinued operations
Accounts receivable	$	—	$	0.7
Inventories	—		1.0
Prepaids and other	—		0.6
Current assets of the discontinued operations	—		2.3
Property, plant and equipment	—		11.2
Future income taxes	—		0.8
Long-term assets of the discontinued operations	—		12.0
Total assets of the discontinued operations	$	—	$	14.3
Liabilities of the discontinued operations
Accounts payable	$	—	$	1.2
Asset retirement obligations	—		2.1
Future income taxes	—		2.1
Long-term liabilities of the discontinued operations	—		4.2
Total liabilities of the discontinued operations	$	—	$	5.4

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 26. Comparative Figures

Certain comparative figures have been reclassified to conform to the current year’s presentation. The Partnership made an immaterial adjustment to the 2009 financial statements to reflect the reclassification of $5.2 million of costs from property, plant and equipment to inventory and to correspondingly decrease cash flow from operating activities and decrease cash flow used in investing activities. There was no impact to net earnings resulting from this adjustment.

Note 27. Canadian and U.S. Accounting Policy Differences

The consolidated financial statements of the Partnership have been prepared in accordance with Canadian GAAP which differs in some respects from U.S. GAAP. Differences in accounting principles as they pertain to the consolidated financial statements are immaterial except as described below.

The application of U.S. GAAP would have the following effect on income and comprehensive loss as reported for the years ended December 31, 2010 and 2009:

	2010			2009
Net income in accordance with Canadian GAAP	$	30.5		$	57.6
Preferred share dividends	14.1			7.9
Change in effective portion of hedging derivatives(a)	3.9			(2.1		)
Net income in accordance with U.S. GAAP	48.5			63.4
Attributable to:
Equity holders of the Partnership	34.4			55.5
Preferred share dividends of a subsidiary company	14.1			7.9
	$	48.5		$	63.4
Other comprehensive loss in accordance with Canadian GAAP	$	(72.4	)	$	(72.7	)
Change in effective portion of hedging derivatives(a)	(3.9		)	2.1
Other comprehensive loss in accordance with U.S. GAAP	$	(76.3	)	$	(70.6	)
Attributable to:
Equity holders of the Partnership	(90.4		)	(78.5		)
Preferred share dividends of a subsidiary company	14.1			7.9
	$	(76.3	)	$	(70.6	)
Net income per unit in accordance with U.S. GAAP—basic and diluted	$	0.63		$	1.03

(a) Accounting standards under U.S. GAAP requires the measurement of hedge effectiveness incorporate the credit risk of the Partnership or its counterparty. Canadian GAAP does not have a similar requirement which results in changes in the effective portion of the hedging derivatives.

CAPITAL POWER INCOME L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Note 27. Canadian and U.S. Accounting Policy Differences (Continued)

The application of U.S. GAAP would have the following effect on the consolidated balance sheets as reported at December 31, 2010 and 2009:

	2010				2009
	Canadian GAAP		U.S. GAAP		Canadian GAAP		U.S. GAAP
Current assets	$	121.0	$	121.0	$	100.1	$	100.1
Long-term assets(b)	1,462.8		1,467.2		1,568.0		1,573.0
Current liabilities	82.2		82.2		75.6		75.6
Long term liabilities(b)	874.2		878.6		853.3		858.3
Partners’ equity and preferred shares(c)	627.4		627.4		739.2		739.2

(b) Under Canadian GAAP, deferred financing fees are presented in the consolidated balance sheet as a reduction of the debt balance, while under U.S. GAAP, deferred financing fees are presented as other assets.

(c) Under Canadian GAAP, the preferred shares issued by a subsidiary company are classified between liabilities and equity, while under U.S. GAAP, they are classified in equity attributed to non-controlling interests.

U.S. GAAP requires the Partnership’s investment in a joint venture to be accounted for using the equity method. However, under an accommodation of the Securities and Exchange Commission, accounting for joint ventures needs not be reconciled from Canadian to U.S. GAAP. The different accounting treatment affects only display and classification and not earnings or partners’ equity.

Under U.S. GAAP, no sub-total would be provided in the operating section of the consolidated statement of cash flows. As well, under U.S. GAAP, reconciliation in the consolidated statement of cash flows would commence with net income instead of income of continuing operation. However, there are no differences in the total operating, investing and financing cash flows.

Note 28. Subsequent Event

On June 20, 2011, the Partnership and Atlantic Power Corporation (Atlantic Power) jointly announced that they have entered into an arrangement agreement to which Atlantic Power would acquire, directly and indirectly, all of the outstanding limited partnership units of the Partnership for $19.40 per limited partnership unit, payable in cash or shares of Atlantic Power (the “Transaction”). The Transaction is expected to be completed in the fourth quarter of 2011, subject to customary approvals including unitholder and shareholder approvals

In connection with Atlantic Power’s acquisition of the Partnership, the Partnership will sell Roxboro and Southport to an affiliate of CPC. The Transaction values the Southport and Roxboro at approximately $121 million. This Transaction will have the effect of reducing the number of Partnership units outstanding by approximately 6.2 million units.

Additionally, in connection with the Transaction, the management agreement between CPC and the Partnership will be terminated (or assigned to Atlantic Power). Atlantic Power will assume the management of the Partnership.

Number of
Units

Millions of
Dollars

Partnership capital, beginning and end of year