Edgar Filing: ATLANTIC POWER CORP

Date: May 11, 2011

Atlantic Power Corporation

/s/ PATRICK J. WELCH

Patrick J. Welch

Chief Financial Officer (Duly Authorized
Officer and Principal Financial Officer)

Use these links to rapidly review the document
TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q


ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2011
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

COMMISSION FILE NUMBER 001-34691

ATLANTIC POWER CORPORATION
(Exact name of registrant as specified in its charter)


British Columbia, Canada (State or other jurisdiction of incorporation or organization)		55-0886410 (I.R.S. Employer Identification No.)
200 Clarendon Street, Floor 25 Boston, MA (Address of principal executive offices)		02116 (Zip code)

(617) 977-2400
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

The number of shares outstanding of the registrant's Common Stock as of May 10, 2011 was 68,531,901.

Table of Contents

ATLANTIC POWER CORPORATION

FORM 10-Q

THREE MONTHS ENDED MARCH 31, 2011

Index


	General
	PART I—FINANCIAL INFORMATION	3
ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	3
	Consolidated Balance Sheets as of March 31, 2011 (unaudited) and December 31, 2010	3
	Consolidated Statements of Operations for the three month periods ended March 31, 2011 and March 31, 2010 (unaudited)	4
	Consolidated Statements of Cash Flows for the three month periods ended March 31, 2011 and March 31, 2010 (unaudited)	5
	Notes to Consolidated Financial Statements (unaudited)	6
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	23
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	39
ITEM 4.	CONTROLS AND PROCEDURES	42
	PART II—OTHER INFORMATION	43
ITEM 1.	LEGAL PROCEEDINGS	43
ITEM 1A.	RISK FACTORS	43
ITEM 6.	EXHIBITS	43

Table of Contents

GENERAL

In this Quarterly Report on Form 10-Q, references to "Cdn$" and "Canadian dollars" are to the lawful currency of Canada and references to "$" and "US$" and "U.S. dollars" are to the lawful currency of the United States. All dollar amounts herein are in U.S. dollars, unless otherwise indicated.

Unless otherwise stated, or the context otherwise requires, references in this Quarterly Report on Form 10-Q to "we," "us," "our" and "Atlantic Power" refer to Atlantic Power Corporation, those entities owned or controlled by Atlantic Power Corporation and predecessors of Atlantic Power Corporation.

Table of Contents

PART I—FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

ATLANTIC POWER CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands of U.S. dollars)

		March 31, 2011			December 31, 2010

		(unaudited)
Assets
Current assets:
	Cash and cash equivalents	$	28,258		$	45,497
	Restricted cash		23,268			15,744
	Accounts receivable		19,781			19,362
	Note receivable—related party (Note 14)		17,671			22,781
	Current portion of derivative instruments asset (Notes 8 and 9)		9,340			8,865
	Prepayments, supplies, and other		8,583			8,480
	Refundable income taxes		2,079			1,593

	Total current assets		108,980			122,322
Property, plant, and equipment, net			284,018			271,830
Transmission system rights			186,171			188,134
Equity investments in unconsolidated affiliates (Note 4)			294,231			294,805
Other intangible assets, net			82,933			88,462
Goodwill			12,453			12,453
Derivative instruments asset (Notes 8 and 9)			22,461			17,884
Other assets			16,554			17,122

	Total assets	$	1,007,801		$	1,013,012

Liabilities
Current Liabilities:
	Accounts payable and accrued liabilities	$	22,857		$	20,530
	Current portion of long-term debt (Note 6)		24,394			21,587
	Current portion of derivative instruments liability (Notes 8 and 9)		8,940			10,009
	Interest payable on convertible debentures (Note 7)		3,759			3,078
	Dividends payable		6,430			6,154
	Other current liabilities		124			5

	Total current liabilities		66,504			61,363
Long-term debt (Note 6)			240,692			244,299
Convertible debentures (Note 7)			210,005			220,616
Derivative instruments liability (Notes 8 and 9)			20,214			21,543
Deferred income taxes			31,632			29,439
Other non-current liabilities			1,949			2,376
Commitments and contingencies (Note 15)			—			—

Equity
Common shares, no par value, unlimited authorized shares; 68,530,369 and 67,118,154 issued and outstanding at March 31, 2011 and December 31, 2010, respectively			642,453			626,108
	Accumulated other comprehensive loss (Note 9)		527			255
	Retained deficit		(209,528	)		(196,494	)

	Total Atlantic Power Corporation shareholders' equity		433,452			429,869

Noncontrolling interest			3,353			3,507

Total equity			436,805			433,376

Total liabilities and equity		$	1,007,801		$	1,013,012

See accompanying notes to consolidated financial statements.

Table of Contents

ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands of U.S. dollars, except per share amounts)

(Unaudited)

		Three months ended March 31,

		2011			2010
Project revenue:
	Energy sales	$	18,502		$	15,913
	Energy capacity revenue		27,138			23,194
	Transmission services		7,644			7,644
	Other		381			470

			53,665			47,221
Project expenses:
	Fuel		17,068			16,157
	Operations and maintenance		8,833			5,041
	Project operator fees and expenses		2,239			919
	Depreciation and amortization		10,879			10,071

			39,019			32,188
Project other income (expense):
	Change in fair value of derivative instruments (Notes 8 and 9)		3,561			(12,194	)
	Equity in earnings of unconsolidated affiliates (Note 4)		1,311			5,436
	Interest expense, net		(4,647	)		(4,411	)
	Other expense, net		(2	)		—

			223			(11,169	)

Project income			14,869			3,864
Administrative and other expenses (income):
	Administration		4,054			4,100
	Interest expense, net		3,968			2,794
	Foreign exchange gain (Note 9)		(658	)		(1,792	)

			7,364			5,102

Income (loss) from operations before income taxes			7,505			(1,238	)
Income tax expense			1,523			4,873

Net income (loss)			5,982			(6,111	)
Net loss attributable to noncontrolling interest			(154	)		(48	)

Net income (loss) attributable to Atlantic Power Corporation		$	6,136		$	(6,063	)

Net income (loss) per share attributable to Atlantic Power Corporation shareholders: (Note 12)
	Basic	$	0.09		$	(0.10	)
	Diluted	$	0.09		$	(0.10	)

See accompanying notes to consolidated financial statements.

Table of Contents

ATLANTIC POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands of U.S. dollars)

(Unaudited)

		Three months ended March 31,

		2011			2010
Cash flows from operating activities:
Net income (loss)		$	5,982		$	(6,111	)
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation and amortization		10,879			10,071
	Long-term incentive plan expense		825			1,420
	Equity in earnings from unconsolidated affiliates		(1,311	)		(5,436	)
	Distributions from unconsolidated affiliates		1,450			1,334
	Unrealized foreign exchange loss (gain)		1,878			(623	)
	Change in fair value of derivative instruments		(3,561	)		12,194
	Change in deferred income taxes		2,011			4,829
Change in other operating balances
	Accounts receivable		(419	)		350
	Prepayments, refundable income taxes and other assets		176			(372	)
	Accounts payable and accrued liabilities		1,937			1,276
	Other liabilities		500			1,907

Net cash provided by operating activities			20,347			20,839
Cash flows (used in) provided by investing activities:
	Acquisitions and investments, net of cash acquired		—			324
	Change in restricted cash		(7,524	)		(7,526	)
	Proceeds from related party loan repayment		5,110			—
	Biomass development costs		(308	)		(317	)
	Purchase of property, plant and equipment		(15,393	)		(319	)

Net cash used in investing activities			(18,115	)		(7,838	)
Cash flows (used in) provided by financing activities:
	Repayment of project-level debt		(3,400	)		(2,700	)
	Proceeds from project-level borrowings		2,781			—
	Dividends paid		(18,852	)		(15,795	)

Net cash used in financing activities			(19,471	)		(18,495	)

Net decrease in cash and cash equivalents			(17,239	)		(5,494	)
Cash and cash equivalents at beginning of period			45,497			49,850

Cash and cash equivalents at end of period		$	28,258		$	44,356

Supplemental cash flow information
	Interest paid	$	4,659		$	1,450
	Income taxes paid (refunded), net	$	14		$	(26	)

See accompanying notes to consolidated financial statements.

Table of Contents

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of presentation and summary of significant accounting policies

Overview

Atlantic Power Corporation owns and operates a diverse fleet of power generation and infrastructure assets in the United States. Our power generation projects sell electricity to utilities and other large commercial customers under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 megawatts (or "MW") in which our ownership interest is approximately 871 MW. Our current portfolio consists of interests in 12 operational power generation projects across nine states, one biomass project under construction in Georgia, and a 500 kilovolt 84-mile electric transmission line located in California. Atlantic Power also owns a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development. Six of our projects are wholly-owned subsidiaries: Lake Cogen, Ltd., Pasco Cogen, Ltd., Auburndale Power Partners, L.P., Cadillac Renewable Energy, LLC, Piedmont Green Power, LLC and Atlantic Path 15, LLC.

The interim consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission ("SEC") regulations for interim financial information and with the instructions to Form 10-Q. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to our financial statements in our Annual Report on Form 10-K for the year ended December 31, 2010. Interim results are not necessarily indicative of results for the full year.

In our opinion, the accompanying unaudited interim consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly our consolidated financial position as of March 31, 2011, the results of operations for the three month periods ended March 31, 2011 and 2010, and our cash flows for the three month periods ended March 31, 2011 and 2010.

Use of estimates:

The preparation of financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results could differ from those estimates. During the periods presented, we have made a number of estimates and assumptions, including the fair values of acquired assets, the useful lives and recoverability of property, plant and equipment and power purchase agreements ("PPAs"), the recoverability of equity investments, the recoverability of deferred tax assets, tax provisions, the valuation of shares associated with our long-term incentive plan and the fair value of financial instruments and derivatives. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets if indications of impairment exist during the period. These estimates and assumptions are based on present conditions and our planned course of action, as well as assumptions about future business and economic conditions. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Should the underlying assumptions and estimates change, the recorded amounts could change by a material amount.

Table of Contents

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. Basis of presentation and summary of significant accounting policies (Continued)

Reclassifications:

Certain prior year amounts have been reclassified to conform to the current year presentation.

Recently issued accounting standards:

Adopted

In December 2010, the FASB issued changes to the disclosure of pro forma information for business combinations. These changes clarify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Also, the existing supplemental pro forma disclosures were expanded to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. We adopted these changes beginning January 1, 2011. Upon adoption, we determined these changes did not impact the consolidated financial statements.

In December 2010, the FASB issued changes to the testing of goodwill for impairment. These changes require an entity to perform all steps in the test for a reporting unit whose carrying value is zero or negative if it is more likely than not (more than 50%) that a goodwill impairment exists based on qualitative factors, resulting in the elimination of an entity's ability to assert that such a reporting unit's goodwill is not impaired and additional testing is not necessary despite the existence of qualitative factors that indicate otherwise. We adopted these changes beginning January 1, 2011. Based on the most recent impairment review of our goodwill (2010 fourth quarter), we determined these changes did not impact the consolidated financial statements.

In October 2009, the FASB issued changes to revenue recognition for multiple-deliverable arrangements. These changes require separation of consideration received in such arrangements by establishing a selling price hierarchy (not the same as fair value) for determining the selling price of a deliverable, which will be based on available information in the following order: vendor-specific objective evidence, third-party evidence, or estimated selling price; eliminate the residual method of allocation and require that the consideration be allocated at the inception of the arrangement to all deliverables using the relative selling price method, which allocates any discount in the arrangement to each deliverable on the basis of each deliverable's selling price; require that a vendor determine its best estimate of selling price in a manner that is consistent with that used to determine the price to sell the deliverable on a standalone basis; and expand the disclosures related to multiple-deliverable revenue arrangements. We adopted these changes beginning January 1, 2011. We determined that the adoption of these changes did not impact the consolidated financial statements, as our projects do not currently have any such arrangements with their customers.

In January 2010, the FASB issued changes to disclosure requirements for fair value measurements. Specifically, the changes require a reporting entity to disclose, in the reconciliation of fair value measurements using significant unobservable inputs (Level 3), separate information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than as one net number) of these Level 3 financial instruments. We adopted these changes beginning January 1, 2011. We determined that these changes did not have an impact on the consolidated financial statements.

Table of Contents

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1. Basis of presentation and summary of significant accounting policies (Continued)

In April 2010, the FASB issued changes to the classification of certain employee share-based payment awards. These changes clarify that there is not an indication of a condition that is other than market, performance, or service if an employee share-based payment award's exercise price is denominated in the currency of a market in which a substantial portion of the entity's equity securities trade and differs from the functional currency of the employer entity or payroll currency of the employee. An employee share-based payment award is required to be classified as a liability if the award does not contain a market, performance, or service condition. These changes were adopted beginning on January 1, 2011. We determined that these changes did not have an impact on the consolidated financial statements.

2. Comprehensive income (loss)

The following table summarizes the components of comprehensive income (loss), net of tax of $480 and ($11), respectively, for the three months ended March 31, 2011 and 2010:

	Three months ended March 31,

	2011		2010
Net income (loss)	$	5,982	$	(6,111	)
Unrealized gain (loss) on hedging activity		721		(16	)

Comprehensive income (loss)	$	6,703	$	(6,127	)

3. Acquisitions and divestitures

(a) Topsham

On February 28, 2011, we entered into a purchase and sale agreement with an affiliate of ArcLight Capital Partners, LLC ("ArcLight") for the purchase of our lessor interest in the project. The transaction closed on May 6, 2011 and we received proceeds of $8.5 million, resulting in no gain or loss on the sale.

Table of Contents

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Equity method investments

The following summarizes the operating results for the three months ended March 31, 2011 and 2010, respectively, for our equity earnings interest in our equity method investments:

		Three-months ended March 31,

		2011			2010
Revenue
	Chambers		13,269			15,416
	Badger Creek		3,316			3,886
	Gregory		7,181			8,866
	Orlando		9,926			10,439
	Selkirk		10,902			13,479
	Other		1,821			664

			46,415			52,750
Project expenses
	Chambers		9,380			10,266
	Badger Creek		2,983			3,470
	Gregory		6,630			8,224
	Orlando		9,463			10,047
	Selkirk		12,659			12,828
	Other		1,428			590

			42,543			45,425
Project other income (expense)
	Chambers		(427	)		(907	)
	Badger Creek		—			6
	Gregory		(38	)		207
	Orlando		(30	)		(33	)
	Selkirk		(1,636	)		(1,098	)
	Other		(430	)		(64	)

			(2,561	)		(1,889	)
Project income (loss)
	Chambers		3,462			4,243
	Badger Creek		333			422
	Gregory		513			849
	Orlando		433			359
	Selkirk		(3,393	)		(447	)
	Other		(37	)		10

			1,311			5,436

Table of Contents

ATLANTIC POWER CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents accumulated depreciation of property, plant and equipment and the accumulated amortization of transmission system rights and other intangible assets as of March 31, 2011 and December 31, 2010:

Long-term debt represents project-level long-term debt of our consolidated subsidiaries and the unamortized balance of purchase accounting adjustments that were recorded in connection with the Path 15 acquisition in order to adjust the debt to its fair value on the acquisition date. Project-level debt is non-recourse to Atlantic Power and generally amortizes during the term of the respective revenue generating contracts of the projects.

Project-level debt is secured by the respective project and its contracts with no other recourse to us. The loans have certain financial covenants that must be met. At March 31, 2011, all of our projects were in compliance with the covenants contained in project-level debt. However, the holding company for our investment in the Chambers project, Epsilon Power Partners, as well as the Selkirk and Delta-Person projects had not achieved the levels of debt service coverage ratios required by the project-level debt arrangements as a condition to make distributions and were therefore restricted from making distributions to us.

As of March 31, 2011 the inception to date balance on the Piedmont construction debt funded by the bridge loan was $2.8 million.

The following table contains details related to outstanding convertible debentures during the three month period ended March 31, 2011:

Aggregate interest expense related to the convertible debentures was $3.4 million and $2.3 million for the three-month periods ended March 31, 2011 and 2010, respectively.

The following represents our financial assets and liabilities that were recognized at fair value as of March 31, 2011 and December 31, 2010. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

The fair value of our derivative instruments are based on price quotes from brokers in active markets who regularly facilitate those transactions and we believe such price quotes are executable. We adjust the fair value of financial assets and liabilities to reflect credit risk, which is calculated based on our credit rating or the credit rating of our counterparties. As of March 31, 2011, the credit reserve resulted in a $0.1 million net increase in fair value, which is comprised of a $0.3 million pre-tax gain in other comprehensive income offset by a $0.1 million loss in change in fair value of derivative instruments and a $0.1 million loss in foreign exchange. As of December 31, 2010, the credit reserve resulted in a $0.6 million net increase in fair value, which is comprised of a $0.2 million pre-tax gain in other comprehensive income and a $0.5 million gain in change in fair value of derivative instruments offset by a $0.1 million loss in foreign exchange.

We have elected to disclose derivative instrument assets and liabilities on a trade-by-trade basis and do not offset amounts at the counterparty master agreement level. The following table summarizes the fair value of our derivative assets and liabilities:

The Lake project's operating margin is exposed to changes in natural gas spot market prices through the expiration of its PPA on July 31, 2013. The Auburndale project purchases natural gas under a fuel supply agreement which provides approximately 80% of the project's fuel requirements at fixed prices through June 30, 2012. The remaining 20% is purchased at spot market prices and therefore the project is exposed to changes in natural gas prices for that portion of its gas requirements through the termination of the fuel supply agreement and 100% of its natural gas requirements from the expiration of the fuel supply agreement in mid-2012 until the termination of its PPA at the end of 2013.

In October 2010, we entered into natural gas swaps that are effective in 2014 and 2015. The natural gas swaps are related to our 50% share of expected fuel purchases at our Orlando project as its operating margin is exposed to changes in natural gas prices following the expiration of its fuel contract at the end of 2013. These financial swaps effectively fix the price of 1.2 million Mmbtu of natural gas at the Orlando project at a weighted average price of $5.76/Mmbtu and represent approximately 25% of our share of the expected natural gas purchases at the project during 2014 and 2015. These swap agreements were entered into by Atlantic Power Corporation and not at the project level. Orlando is accounted for under the equity method of accounting.

Our strategy to mitigate the future exposure to changes in natural gas prices at Lake, Auburndale and Orlando consists of periodically entering into financial swaps that effectively fix the price of natural gas expected to be purchased at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheet at fair value.

We have executed an interest rate swap at our consolidated Auburndale project to economically fix a portion of its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Auburndale debt agreement. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 3.12%. The notional amount of the swap matches the outstanding principal balance over the remaining life of Auburndale's debt. The interest rate swap was executed in November 2009 and expires on November 30, 2013.

The Cadillac project has an interest rate swap agreement that effectively fixes the interest rate at 5.90% from February 20, 2008 to February 15, 2011, 6.02% from February 16, 2011 to February 15, 2015, 6.14% from February 16, 2015 to February 15, 2019, 6.26% from February 16, 2019 to February 15, 2023, and 6.38% thereafter. The notional amount of the interest rate swap agreement matches the outstanding principal balance over the remaining life of Cadillac's debt. This swap agreement, which qualifies and is designated as a cash flow hedge, is effective through June 2025.

We executed two interest rate swaps at our consolidated Piedmont project to economically fix its exposure to changes in interest rates related to its variable-rate debt. The interest rate swap agreements are not designated as hedges and changes in their fair market value are recorded in the consolidated statements of operations. The interest rate swap agreement effectively converted the floating rate debt to a fixed interest rate of 1.7% plus an applicable margin ranging from 3.5% to 3.75% from March 31, 2011 to February 29, 2016. From February 2016 until the maturity of the debt in November 2017, the fixed rate of the swap is 4.47% and the applicable margin is 4.0%, resulting in an all-in rate of 8.47%. The swap continues at the fixed rate of 4.47% from the maturity of the debt in November 2017 until November 2030. The notional amounts of the interest rate swap agreements match the estimated outstanding principal balance of Piedmont's cash grant bridge loan and the construction loan facility which will convert to a term loan. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively.

Unrealized gains (losses) on interest rate swaps designated as cash flow hedges have been recorded in shareholders' equity as a gain in other comprehensive income of $1.2 million and $0.2 million for the three-month periods ended March 31, 2011 and 2010, respectively. Realized losses on these interest rate swaps of $0.6 million and $0.2 million were recorded in interest expense, net for the three-month periods ended March 31, 2011 and 2010, respectively.

Unrealized gains and losses on natural gas swaps previously designated as cash flow hedges are recorded in other comprehensive income. In the period in which the unrealized gains and losses are settled, the cash settlement payments are recorded as fuel expense. Other comprehensive loss recorded for natural gas swap contracts accounted for as cash flow hedges totaled $5.1 million, prior to July 1, 2009 when hedge accounting for these natural gas swaps was discontinued prospectively. Amortization of the gain (loss) of $0.1 million and $(0.4) million, was recorded in change in fair value of derivative instruments for the three-month periods ended March 31, 2011 and 2010, respectively.

Unrealized gains and losses on derivative instruments not designated as cash flow hedges are recorded in change in fair value of derivative instruments in the consolidated statements of operations.

The following table summarizes realized gains and losses for derivative instruments not designated as cash flow hedges:

Unrealized gains and losses associated with changes in the fair value of derivative instruments not designated as cash flow hedges and ineffectiveness of derivatives designated as cash flow hedges are reflected in current period earnings. The following table summarizes the pre-tax gains and (losses) resulting from changes in the fair value of derivative financial instruments that are not designated as cash flow hedges:

We entered into derivative instruments in order to economically hedge the following notional volumes of forecasted transactions as summarized below, by type, excluding those derivatives that qualified for the normal purchases and normal sales exception as of March 31, 2011:

We use foreign currency forward contracts to manage our exposure to changes in foreign exchange rates, as we generate cash flow in U.S. dollars but pay dividends to shareholders and interest on convertible debentures predominantly in Canadian dollars. We have a hedging strategy for the purpose of mitigating the currency risk impact on the long-term sustainability of dividends to shareholders. We have executed this strategy by entering into forward contracts to purchase Canadian dollars at a fixed rate to hedge approximately 86% of our expected dividend and convertible debenture interest payments through 2013. Changes in the fair value of the forward contracts partially offset foreign exchange gain or losses on the U.S. dollar equivalent of our Canadian dollar obligations. The forward contracts consist of (1) monthly purchases through the end of 2013 of Cdn$6.0 million at an exchange rate of

Cdn$1.134 per U.S. dollar and (2) purchases in both April and October 2011 of Cdn$1.9 million at an exchange rate of Cdn$1.1075 per U.S. dollar.

It is our intention to periodically consider extending the length of these forward contracts. In addition, we will consider executing additional foreign currency forward contracts to hedge expected additional dividend and interest payments associated with the common shares and convertible debentures issued in our October 2010 public offering.

The foreign exchange forward contracts are recorded at estimated fair value based on quoted market prices and our estimation of the counterparty's credit risk. The fair value of our forward foreign currency contracts is $26.9 million and $23.4 million at March 31, 2011 and December 31, 2010, respectively. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain) loss in the consolidated statements of operations.

The following table contains the components of recorded foreign exchange (gain) loss for the three-month periods ended March 31, 2011 and 2010:

The following table illustrates the impact on our financial instruments of a 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar as of March 31, 2011:

The following table summarizes the changes in the accumulated other comprehensive income (loss) ("OCI") balance attributable to derivative financial instruments designated as a hedge, net of tax rate:

The difference between the actual tax expense of $1.5 million for the three months ended March 31, 2011 and the expected income tax expense, based on a the Canadian enacted statutory rate of 26.5%, of $2.0 million is primarily due to an increase in the valuation allowance and various other permanent differences.

As of March 31, 2011, we have recorded a valuation allowance of $79.1 million. This amount is comprised primarily of provisions against available Canadian and U.S net operating loss carryforwards. In assessing the recoverability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon projected future taxable income in the United States and in Canada and available tax planning strategies.

The following table summarizes the changes in outstanding LTIP notional units during the three months ended March 31, 2011:

Certain awards have a market condition based on our total shareholder return during the performance period compared to a group of peer companies. See further details as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010.

The calculation of simulated total shareholder return under the Monte Carlo model for the remaining time in the performance period for awards with market conditions included the following assumptions:

Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average common shares outstanding during their respective period. Diluted earnings (loss) per share is computed including dilutive potential shares as if they were outstanding shares during the year. Dilutive potential shares include shares that would be issued if all of the convertible debentures were converted into shares at January 1, 2011. Dilutive potential shares also include the weighted average number of shares, as of the date such notional units were granted, that would be issued if the unvested notional units outstanding under the LTIP were vested and redeemed for shares under the terms of the LTIP.

Because we reported a loss for the three months ended March 31, 2010, diluted earnings per share are equal to basic earnings per share as the inclusion of potentially dilutive shares in the computation is anti-dilutive.

The following table sets forth the diluted net income (loss) and potentially dilutive shares utilized in the per share calculation for the three-month periods ended March 31, 2011 and 2010:

Potentially dilutive shares from convertible debentures have been excluded from fully diluted shares in the three-month period ended March 31, 2011 because its impact would be anti-dilutive.

Potentially dilutive shares from convertible debentures and potentially dilutive shares from LTIP notional units have been excluded from fully diluted shares in the three-month period ended March 31, 2010 because its impact would be anti-dilutive.

We have six reportable segments: Path 15, Auburndale, Lake, Pasco, Chambers and Other Project Assets.

We analyze the performance of our operating segments based on Project Adjusted EBITDA which is defined as project income less interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are

required to be recorded at fair value. A reconciliation of project income to Project Adjusted EBITDA is included in the table below.

Progress Energy Florida and the California Independent System Operator ("CAISO") provide for 71.7% and 14.2%, respectively, of total consolidated revenues for the three months ended March 31, 2011 and 77.0% and 16.2% for the three months ended March 31, 2010. Progress Energy Florida purchases electricity from Auburndale and Lake, and the CAISO makes payments to Path 15.

During 2010, we made a short-term $22.8 million loan to Idaho Wind to provide temporary funding for construction of the project until a portion of the project-level construction financing is completed. Member loans will be paid down with a combination of excess proceeds from the federal stimulus grant after repaying the cash grant facility, funds from a third closing for additional debt and project cash flow. The federal stimulus grant is expected in June of 2011 and a third closing is expected by the end of the year. The outstanding loans bear interest at a prime rate plus 10% (13.25% as December 31, 2010). During the three-months ended March 31, 2011, we received $0.5 million in interest payments related to the member loans. As of May 10, 2011, $5.1 million of the loan has been repaid.

Prior to December 31, 2009, Atlantic Power was managed by Atlantic Power Management, LLC (the "Manager"), which was owned by two private equity funds managed by ArcLight. On December 31, 2009, we terminated our management agreements with the Manager and have agreed to pay the ArcLight funds an aggregate of $15 million, to be satisfied by a payment of $6 million that was made at the termination date, and additional payments of $5 million, $3 million and $1 million on the respective first, second and third anniversaries of the termination date. The remaining liability associated with the termination fee is recorded at its estimated fair value of $3.7 million at March 31, 2011. The contract termination liability is being accreted to the final amounts due over the term of these payments.

Our Lake project is currently involved in a dispute with Progress Energy Florida over off-peak energy sales in 2010. All amounts billed for off-peak energy during 2010 by the Lake project have been paid in full by Progress. The Lake project has filed a claim against Progress in which we seek to confirm our contractual right to sell off-peak energy at the contractual price for such sales. Progress filed a counter-claim against the Lake project, seeking, among other things, the return of amounts paid for off-peak power sales during 2010 and a declaratory order clarifying Lake's rights and obligations under the PPA. The Lake project has stopped dispatching during off-peak periods pending the outcome of the dispute. However, we strongly believe that the court will confirm our contractual right to sell off-peak power using the contractual price that was used during 2010 and that we will be able to continue such off-peak power sales for the remainder of the term of the PPA. We have not recorded any reserves related to this dispute and expect that the outcome will not have a material adverse effect on our financial position or results of operations.

From time to time, Atlantic Power, its subsidiaries and the projects are parties to disputes and litigation that arise in the normal course of business. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. There are no matters pending as of March 31, 2011 which are expected to have a material adverse impact on our financial position or results of operations.

On May 6, 2011 we closed on the sale of our 50.0% lessor interest in the Topsham project for $8.5 million, resulting in no gain or loss on the sale.

Certain statements in this Quarterly Report on Form 10-Q constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements generally can be identified by the use of forward-looking terminology such as "outlook," "objective," "may," "will," "expect," "intend," "estimate," "anticipate," "believe," "should," "plans," "continue," or similar expressions suggesting future outcomes or events. Examples of such statements in this Quarterly Report on Form 10-Q include, but are not limited to, statements with respect to the following:

Such forward-looking statements reflect our current expectations regarding future events and operating performance and speak only as of the date of this Quarterly Report on Form 10-Q. Such forward-looking statements are based on a number of assumptions which may prove to be incorrect, including, but not limited to the assumption that the projects will operate and perform in accordance with our expectations. Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not or the times at or by which such performance or results will be achieved. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements, including, but not limited to, the factors discussed under "Risk Factors" included in the filings we make from time to time with the SEC. Our business is both competitive and subject to various risks.

Other factors, such as general economic conditions, including exchange rate fluctuations, also may have an effect on the results of our operations. Many of these risks and uncertainties can affect our actual results and could cause our actual results to differ materially from those expressed or implied in any forward-looking statement made by us or on our behalf.

Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward-looking information include third party projections of regional fuel and electric

capacity and energy prices or cash flows that are based on assumptions about future economic conditions and courses of action. Although the forward-looking statements contained in this Quarterly Report on Form 10-Q are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking statements, and the differences may be material. Certain statements included in this Quarterly Report on Form 10-Q may be considered "financial outlook" for the purposes of applicable securities laws, and such financial outlook may not be appropriate for purposes other than this Quarterly Report on Form 10-Q.

These forward-looking statements are made as of the date of this Form 10-Q, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and results of operations of Atlantic Power Corporation should be read in conjunction with the interim consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q.

Atlantic Power Corporation owns and operates a diverse fleet of power generation and infrastructure assets in the United States. Our power generation projects sell electricity to utilities and other large commercial customers under long-term power purchase agreements, which seek to minimize exposure to changes in commodity prices. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,948 MW in which our ownership interest is approximately 871 MW. Our current portfolio consists of interests in 12 operational power generation projects across nine states, one biomass project under construction in Georgia, and a 500 kilovolt 84-mile electric transmission line located in California. Atlantic Power also owns a majority interest in Rollcast Energy, a biomass power plant developer with several projects under development.We sell the capacity and energy from our power generation projects under power purchase agreements (or "PPAs") with a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from 2011 to 2037, we receive payments for electric energy sold to our customers (known as energy payments), in addition to payments for electric generation capacity (known as capacity payments). We also sell steam from a number of our projects under steam sales agreements to industrial purchasers. The transmission system rights (or "TSRs") we own in our power transmission project entitle us to payments indirectly from the utilities that make use of the transmission line.

Our power generation projects generally operate pursuant to long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales agreements provide for the indexing or pass-through of fuel costs to our customers. In cases where there is not a pass-through of fuel costs, we use a financial hedging strategy designed to mitigate the market price risk of fuel purchases.

We partner with recognized leaders in the independent power industry to operate and maintain our projects, including Caithness Energy, LLC, Power Plant Management Services, Delta Power Services and the Western Area Power Administration. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

We completed our initial public offering on the Toronto Stock Exchange (TSX: ATP) in November 2004. Our shares began trading on the NYSE under the symbol "AT" on July 23, 2010.

As of May 10, 2011, we had 68,531,901 common shares, Cdn$48.1 million ($50.4 million) principal amount of 6.50% convertible secured debentures due October 31, 2014 (the "2006 Debentures"), Cdn$75.0 million ($78.6 million) principal amount of 6.25% convertible debentures due March 15, 2017 (the "2009 Debentures"), and Cdn$80.5 million ($84.4 million) principal amount of 5.60% convertible debentures due June 30, 2017 (the "2010 Debentures" and together with the 2006 and 2009 Debentures, the "Debentures") outstanding. The 2006 Debentures, 2009 Debentures and 2010 Debentures are convertible at any time, at the option of the holder, into 80.645, 76.923 and 55.249, respectively, common shares per Cdn$1,000 principal amount of Debentures, representing a conversion price of Cdn$12.40, Cdn$13.00 and Cdn$18.10, respectively, per common share. Holders of common shares currently receive a monthly dividend at a current annual rate of Cdn$1.094 per common share.

The following table outlines our portfolio of power generating and transmission assets in operation and under construction as of May 10, 2011, including our interest in each facility. Management believes the portfolio is well diversified in terms of electricity and steam buyers, fuel type, regulatory jurisdictions and regional power pools, thereby partially mitigating exposure to market, regulatory or environmental conditions specific to any single region.

On May 6, 2011 we closed on the sale of our 50.0% lessor interest in the Topsham project for $8.5 million, resulting in no gain or loss on the sale.

The following table and discussion is a summary of our consolidated results of operations for the three month periods ended March 31, 2011 and 2010. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

We have six reportable segments: Auburndale, Chambers, Lake, Pasco, Path 15 and Other Project Assets. The results of operations are discussed below by reportable segment.

Project income is the primary GAAP measure of our operating results and is discussed in "Project Operations Performance" below. In addition, an analysis of non-project expenses impacting our results is set out in "Administrative and Other Expenses (Income)" below.

Significant non-cash items, which are subject to potentially significant fluctuations, include: (1) the change in fair value of certain derivative financial instruments that are required by GAAP to be revalued at each balance sheet date (see "Quantitative and Qualitative Disclosures About Market Risk" for additional information); (2) the non-cash impact of foreign exchange fluctuations from period to period on the U.S. dollar equivalent of our Canadian dollar-denominated obligations and; (3) the related deferred income tax expense (benefit) associated with these non-cash items.

Cash available for distribution was $16.6 million and $17.8 million for the three months ended March 31, 2011 and 2010, respectively. See "Cash Available for Distribution" in this Form 10-Q for additional information.

Income (loss) from operations before income taxes for the three months ended March 31, 2011 and 2010, was $7.5 million and $(1.2) million, respectively. See "Project Income" below for additional information.

Three months ended March 31, 2011 compared with three months ended March 31, 2010

The increase in project income for our Auburndale segment of $6.3 million to $6.0 million in the three-month period ended March 31, 2011 from a loss of $(0.3) million in the comparable 2010 period is primarily attributable to the $5.2 million change in the benefit associated with the non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments. Project revenue at Auburndale increased by $1.3 million in the three-month period ended March 31, 2011 due to favorable energy pricing compared to 2010, as well as the annual contractual escalation of capacity payments.

Project income for our Lake segment increased $10.7 million to $7.8 million in the three-month period ended March 31, 2011, from a loss of $(2.9) million in the comparable 2010 period. The increase is primarily attributable to the $9.5 million change in the benefit associated with the non-cash change in fair value of derivative instruments associated with its natural gas swaps. These swaps were executed to financially hedge the project's exposure to changes in the market prices of natural gas. See Item 3, "Quantitative and Qualitative Disclosures About Market Risk", for additional details about our derivative instruments and other financial instruments. Project revenue at Lake increased by $0.9 million in the three-month period ended March 31, 2011 due to the annual contractual escalation of capacity payments and increased energy sales, compared to 2010. In addition, fuel costs were lower due to the lower price on natural gas swaps.

Project income for our Pasco segment decreased $2.5 million to a project loss of $(1.8) million in the three-month period ended March 31, 2011, from project income of $0.7 million in the comparable 2010 period. The decrease is due to higher operations and maintenance expenses attributable to the unplanned replacement of gas turbine blades.

Project income for our Path 15 segment decreased $0.2 million to $1.6 million in the three-month period ended March 31, 2011 from $1.8 million in the comparable 2010 period due to higher operation and maintenance costs associated with an erosion control initiative.

Project income for our Chambers segment, which is recorded under the equity method of accounting, decreased $0.3 million to $3.1 million in the three-month period ended March 31, 2011 from $3.4 million in the comparable 2010 period. The decrease in project income at Chambers is primarily attributable to higher maintenance costs associated with a planned outage in April 2011 and lower dispatch compared to 2010, partially offset by a $0.6 million benefit in the non-cash change in fair value of derivative instruments associated with its interest rate swaps.

Project income for our Other Project Assets segment decreased $(2.8) million to a project loss of $(1.7) million for the three-period ended March 31, 2011 compared to project income of $1.1 million in 2010. The decrease was primarily a result of a $(2.9) million decrease in project income from our Selkirk project. This was due to a planned outage lasting longer than expected, resulting in a delay in the receipt of capacity payments until the second quarter. Project income was also reduced slightly due to the sale of the Topsham project which is no longer generating income, offset by project income generated from Cadillac and Idaho Wind.

Administration includes the costs of operating as a public company. Administration was consistent at $4.1 million for both the three-month periods ended March 31, 2011 and 2010.

Interest expense at the corporate level primarily relates to our convertible debentures. Interest expense, net increased $1.2 million to $4.0 million in the three-month period ended March 31, 2011 from $2.8 million in the comparable 2010 period. This increase is primarily due to the issuance of Cdn$80.5 million of convertible debentures in October of 2010.

Foreign exchange loss (gain) primarily reflects the unrealized impact of changes in foreign exchange rates on the U.S. dollar equivalent of our Canadian dollar-denominated obligations to holders of the convertible debentures. In addition, unrealized and realized gains and losses on our forward contracts for the purchase of Canadian dollars to satisfy these obligations and our dividends to shareholders are included in foreign exchange loss (gain). Unrealized gains and losses on our forward contracts are reclassified to realized gains and losses upon cash settlement of the contracts. Foreign exchange gain decreased $1.1 million to a $0.7 million gain in the three-month period ended 2011 compared to a $1.8 million gain in the comparable 2010 period. The U.S. dollar to Canadian dollar exchange rate increased by 2.6% during the three-month period ended March 31, 2011, compared to an increase of 3.5% in the comparable period in 2010. See Item 3 "Quantitative and Qualitative Disclosures About Market Risk" for additional details about our management of foreign currency risk

and the components of the foreign exchange gain recognized during the three-month period ended March 31, 2011 compared to the foreign exchange gain in the comparable 2010 period.

The key measure we use to evaluate the results of our projects is Cash Available for Distribution. Cash Available for Distribution is not a measure recognized under GAAP, does not have a standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. We believe Cash Available for Distribution is a relevant supplemental measure of our ability to pay dividends to our shareholders. A reconciliation of net cash provided by operating activities to Cash Available for Distribution is set out below under "Cash Available for Distribution." Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

The primary factor influencing Cash Available for Distribution is cash distributions received from the projects. These distributions received are generally funded from Project Adjusted EBITDA generated by the projects, reduced by project-level debt service and capital expenditures, and adjusted for changes in project-level working capital and cash reserves. Project Adjusted EBITDA is defined as project income less interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use unaudited Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. A reconciliation of project income to Project Adjusted EBITDA is set out below under "Project Adjusted EBITDA." Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

Because Project Adjusted EBITDA and project distributions are key drivers of both the performance of our projects and Cash Available for Distribution, please see the following supplementary unaudited non-GAAP information that summarizes Project Adjusted EBITDA by project and a reconciliation of Project Adjusted EBITDA by project to project distributions actually received by us.

Reconciliation of Project Distributions (in thousands of U.S. dollars)
For the three months ended March 31, 2011

Reconciliation of Project Distributions (in thousands of U.S. dollars)
For the three months ended March 31, 2010

Project Operations Performance—Three months ended March 31, 2011 compared with three months ended March 31, 2010

Aggregate Project Adjusted EBITDA decreased $2.8 million to $36.0 million in the three-month period ended March 31, 2011 from $38.8 million in the comparable 2010 period and included the following factors:

Aggregate power generation for projects in operation at March 31, 2011 was 0.4% greater than the three-month period ended March 31, 2010. Generation during the three-month period ended March 31, 2011 compared to the comparable 2010 period was favorably impacted primarily by additional generation associated with the acquisition of Cadillac in the fourth quarter of 2010 and with Idaho Wind achieving commercial operation in the first quarter of 2011, as well as increased dispatch at Selkirk. The favorable variance was offset largely by lower generation at Chambers and Pasco due to reduced dispatch and by a planned major maintenance outage at Orlando in 2011.

The project portfolio achieved a weighted average availability of 93.8% for the three-month period ended March 31, 2011 compared to 98.2% in the 2010 period. The decrease in portfolio availability for the three-month period ended March 31, 2011 versus the prior period was primarily due to planned outages at Chambers and Selkirk and a forced outage at Delta-Person in the first quarter of 2011. Each of the projects with reduced availability was nevertheless able to achieve substantially all of their respective capacity payments as a result of contract terms that provide for certain levels of planned and unplanned outages.

Our cash flow from the projects may vary from year to year based on, among other things, changes in prices under the PPAs, fuel supply and transportation agreements, steam sales agreements and other project contracts, changes in regulated transmission rates, compliance with the terms of non-recourse project-level financing including debt repayment schedules, the transition to market or recontracted pricing following the expiration of PPAs, fuel supply and transportation contracts, working capital requirements and the operating performance of the projects. Project cash flows may have some seasonality and the pattern and frequency of distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have a material impact on our business.

Cash flow from operating activities decreased by $0.5 million for the three-month period ended March 31, 2011 over the comparable period in 2010. The changes from the prior period are consistent with and partially attributable to the changes in Project Adjusted EBITDA described above, as well as changes in working capital at both consolidated and unconsolidated affiliates.

Cash flow from investing activities includes restricted cash. Restricted cash fluctuates from period to period in part because non-recourse project-level financing arrangements typically require all operating cash flow from the project to be deposited in restricted accounts and then released at the time that principal payments are made and project-level debt service coverage ratios are met. As a result, the timing of principal payments on project-level debt causes significant fluctuations in restricted cash balances, which typically benefits investing cash flow in the second and fourth quarters of the year and decreases investing cash flow in the first and third quarters of the year.

Cash flows used in investing activities for the three-month period ended March 31, 2011 were $18.1 million compared to cash flows used in investing activities of $7.8 million for the comparable 2010 period. We invested $15.1 million for the construction-in-progress for our Piedmont biomass project offset by the repayment of $5.1 million from our related-party loan to Idaho Wind.

Cash used in financing activities for the three-month period ended March 31, 2011 resulted in a net outflow of $19.5 million compared to a net outflow of $18.5 million for the same period in 2010. The change from the comparable period is primarily attributable to a $3.1 million increase in dividends paid due to a higher number of common shares outstanding compared to the first quarter 2010. Since the third quarter of 2010, Cdn$23.1 million of convertible debentures have converted to common stock.

In addition, we issued common shares in a public offering in October 2010. The increase in dividends is partially offset by proceeds of $2.8 million of project-level debt related to our Piedmont biomass project.

Holders of our common shares receive monthly cash distributions of Cdn$1.094 per year in the form of a dividend. The payout ratio for the three-month periods ended March 31, 2011 and 2010 was 114% and 89%, respectively.

The table below presents our calculation of cash available for distribution for the three-month periods ended March 31, 2011 and 2010:

Based on our actual performance to date and projections for the remainder of the year, we expect to receive distributions from our projects in the range of $80 million to $90 million for the full year 2011. We expect overall levels of operating cash flows in 2011 to be improved over actual 2010 levels. Higher distributions from existing projects, initial distributions from our recent investment in Idaho Wind and Cadillac, and a slightly lower payment under the management termination agreement are expected to be partially offset by the non-recurrence of $8.0 million of cash tax refunds in 2010. In 2012, additional increases in distributions from projects are expected to further increase operating cash flow compared to 2011. The most significant factor in the expected higher operating cash flow in 2012 is increased distributions from Selkirk following the final payment of its non-recourse project-level debt in 2012.

The following items comprise the most significant increases in projected 2011 project distributions compared to 2010:

In 2010, the following five projects comprised approximately 90% of project distributions received: Auburndale, Lake, Orlando, Path 15 and Pasco. For 2011, we expect these same five projects to contribute approximately 85% of total project distributions.

In addition to the items above, the following is a summary of other projections for project distributions in 2011 and beyond:

The Lake project is exposed to changes in natural gas prices from the expiration of its natural gas supply contract on June 30, 2009 through to the expiration of its PPA in July 2013 that are not passed through in its PPAs. We have executed a hedging strategy to mitigate this exposure by periodically entering into financial swaps that effectively fix the forward price of natural gas expected to be purchased at the project. These hedges are summarized in Item 3, "Quantitative and Qualitative Disclosures About Market Risk", in this Form 10-Q. We intend to continue, when appropriate, to evaluate opportunities to further mitigate natural gas price exposure at Lake in 2013, but do not intend to execute additional hedges at Lake for 2011 and 2012 because our natural gas exposure for those years is already substantially hedged.

The variable energy revenues in the Lake project's PPA are indexed, in part, to the price of coal consumed by a specific utility plant in Florida, the Crystal River facility. The components of this coal price are proprietary to the utility, but we believe that the utility purchases coal for that plant under a combination of short to medium term contracts and spot market transactions.

Coal prices used in the energy revenue component of the projected distributions from the Lake project incorporate a forecast of the applicable Crystal River facility coal cost provided by the utility based on their internal projections. The projected annual cash distributions change by approximately $1.0 million for every $0.25/Mmbtu change in the projected price of coal.

We expect to receive distributions from the Lake project of approximately $30 million to $34 million in both 2011 and 2012. The increases in 2011 and 2012 over the $28.8 million of distributions in 2010 are primarily due to higher contractual capacity payments and lower hedged natural gas prices than in 2010.

Based on the current forecast, we expect distributions from Auburndale of $25 million to $27 million per year from 2011 through 2013, when the project's current PPA expires. Distributions received from Auburndale in the 2011 through 2013 period will be impacted by projected coal and gas prices in the forecast period.

The projected revenue from the Auburndale PPA contains a component related to the costs of coal consumed at the utility off-taker's Crystal River facility as described above for the Lake project. Because that mechanism does not pass through changes in the project's fuel costs, Auburndale's operating margin is exposed to changes in natural gas prices for approximately 20% of its natural gas requirements through the expiration of the project's gas supply contract. The remaining 80% of the project's fuel requirements are supplied under an agreement with fixed prices through its expiration in

mid-2012. We have been executing a strategy to mitigate the future exposure to changes in natural gas prices at Auburndale by periodically entering into financial swaps that effectively fix the forward price of natural gas required at the project. These hedges are summarized in Item 3, "Quantitative and Qualitative Disclosures About Market Risk", in this Form 10-Q. The 2011 natural gas price exposure at Auburndale has been substantially hedged. We intend to continue, when appropriate, to evaluate opportunities to further mitigate natural gas price exposure at Auburndale in 2012 and 2013.

The PPA at the Orlando project extends through 2023. However, the project's natural gas supply agreement expires in 2013. Current market prices for natural gas following the expiration of the current supply agreement are lower than the price of natural gas currently being purchased under the project's gas contract. As a result, we expect a significant increase in cash distributions from the Orlando project beginning in 2014. We have been executing a hedging strategy to reduce the market price risk associated with expected natural gas requirements at Orlando in 2014 and beyond. See "Item 3. Quantitative and Qualitative Disclosures About Market Risks" in this Form 10-Q for further details.

Our primary source of liquidity is distributions from our projects and availability under our revolving credit facility. A significant portion of the cash received from project distributions is used to pay dividends to our shareholders and interest on our outstanding convertible debentures. We may fund future acquisitions with a combination of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately-placed bank or institutional non-recourse operating level debt.

We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due.

We do not expect any additional material or unusual requirements for cash outflows for 2011 for capital expenditures or other required investments. We have contributed approximately $75.0 million to fund the equity portion of the construction costs for Piedmont. Approximately $59.0 million of this amount was contributed in the fourth quarter of 2010 and the remaining balance was paid in the quarter ending March 31, 2011. In addition, there are no debt instruments with significant maturities or refinancing requirements in 2011. See "Outlook" above for information about changes in expected distributions from our projects in 2011 and beyond.

We maintain a credit facility with a capacity of $100 million, $50 million of which may be utilized for letters of credit. The credit facility matures in August 2012.

The credit facility bears interest at the London Interbank Offered Rate ("LIBOR") plus an applicable margin between 1.5% and 3.25% that varies based on the credit statistics of one of our subsidiaries. As of March 31, 2011, the applicable margin was 1.5%. As of March 31, 2011, $48.6 million was allocated, but not drawn, to support letters of credit for contractual credit support at eight of our projects.

We must meet certain financial covenants under the terms of the credit facility, which are generally based on the cash flow coverage ratios and also require us to report indebtedness ratios to our lenders. The facility is secured by pledges of assets and interests in certain subsidiaries. We expect to remain in compliance with the covenants of the credit facility for at least the next 12 months.

In October 2006, we issued, in a public offering, Cdn$60 million aggregate principal amount of 6.25% convertible secured debentures, which we refer to as the 2006 Debentures. In 2009 the holders agreed to change the rate to 6.50% and extend the maturity date to 2014. The 2006 Debentures pay interest semi-annually on April 30 and October 31 of each year. The Debentures have a maturity date of October 31, 2014 and are convertible into approximately 80.6452 common shares per Cdn$1,000 principal amount of 2006 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$12.40 per common share. The 2006 Debentures are secured by a subordinated pledge of our interest in certain subsidiaries and contain certain restrictive covenants. Through May 10, 2011, a cumulative Cdn$11.9 million of the 2006 Debentures have been converted to 0.96 million common shares. As of May 10, 2011 the 2006 Debentures balance is Cdn$48.1 million ($50.4 million).

In December 2009, we issued, in a public offering, Cdn$86.25 million aggregate principal amount of 6.25% convertible unsecured subordinated debentures, which we refer to as the 2009 Debentures. The 2009 Debentures pay interest semi-annually on March 15 and September 15 of each year beginning September 15, 2010. The 2009 Debentures mature on March 15, 2017 and are convertible into approximately 76.9231 common shares per Cdn$1,000 principal amount of 2009 Debentures, at any time, at the option of the holder, representing a conversion price of Cdn$13.00 per common share. Through May 10, 2011, a cumulative Cdn$11.2 million of the 2009 Debentures have been converted to 0.86 million common shares. As of May 10, 2011 the 2009 Debentures balance is Cdn$75.0 million ($78.6 million).

In October 2010, we issued, in a public offering, Cdn$80.5 million aggregate principal amount of 5.60% convertible unsecured subordinated debentures, which we refer to as the 2010 Debentures. The 2010 Debentures pay interest semi-annually on June 30 and December 30 of each year beginning June 30, 2011. The 2010 Debentures mature on June 30, 2017, unless earlier redeemed. The debentures are convertible into our common shares at an initial conversion rate of 55.2486 common shares per Cdn$1,000 principal amount of debentures, representing an initial conversion price of approximately Cdn$18.10 per common share. As of May10, 2011 the 2010 debentures balance is Cdn$80.5 million ($84.4 million).

The following table summarizes the maturities of project-level debt. The amounts represent our share of the non-recourse project-level debt balances at March 31, 2011 and exclude any purchase accounting adjustments recorded to adjust the debt to its fair value at the time the project was acquired. Certain of the projects have more than one tranche of debt outstanding with different maturities, different interest rates and/or debt containing variable interest rates. Project-level debt agreements contain covenants that restrict the amount of cash distributed by the project if certain debt service coverage ratios are not attained. As of March 31, 2011, the covenants at the Selkirk and Delta-Person projects and at Epsilon Power Partners are temporarily preventing those projects from making cash distributions to us. We expect to resume receiving distributions from Epsilon Power Partners in 2011 and Selkirk and Delta-Person in 2012. All project-level debt is non-recourse to us and substantially the entire principal is amortized over the life of the projects' PPAs. The non-recourse holding company debt relating to our investment in Chambers is held at Epsilon Power Partners, our wholly-owned subsidiary. For the three-month period ended March 31, 2011, we have contributed approximately $0.48 million to Epsilon Power Partners for debt service payments on the holding company debt but do not anticipate any additional required contributions to Epsilon.

The range of interest rates presented represents the rates in effect at March 31, 2011. The amounts listed below are in thousands of U.S. dollars, except as otherwise stated.

The projects generally have reserve requirements to support payments for major maintenance costs and project-level debt service. For projects that are consolidated, our share of these amounts is reflected as restricted cash on the consolidated balance sheet. At March 31, 2011, restricted cash at the consolidated projects totaled $23.3 million.

Capital expenditures for the projects are generally made at the project level using project cash flows and project reserves. Therefore, the distributions that we receive from the projects are made net of capital expenditures needed at the projects. The projects in which we have investments generally consist of large capital assets that have established commercial operations. Ongoing capital expenditures for assets of this nature are generally not significant because most major expenditures relate to planned repairs and maintenance and are expensed when incurred.

In 2011, several of the projects have planned outages to complete maintenance work. The level of maintenance and capital expenditures is slightly higher than in 2010. During the first quarter of 2011, Selkirk completed a major inspection of its steam turbine generator and a minor inspection of one of its combustion turbines, with costs and lost margin largely covered by reserves and gas resales proceeds, respectively. Also in the first quarter of 2011, Chambers completed its scheduled outage to inspect and complete customary repairs on one boiler. At Orlando, a major gas turbine overhaul and major steam turbine overhaul were commenced in March, the cost of which was largely covered under its long-term maintenance agreement with the gas turbine manufacturer. In late March, Pasco commenced its scheduled spring outage to conduct regular maintenance as well as replace some components of the

combustion turbine. A portion of the repair costs are covered under Pasco's service agreement with General Electric.

In the three-month period ended March 31, 2011, we incurred approximately $15.4 million in capital expenditures for the construction of our Piedmont biomass project. For the remainder of 2011, we expect to incur approximately $84.1 million in capital expenditures related to the Piedmont project, with total project costs through expected completion in late 2012 of approximately $207.0 million. The project is being funded with an $82.0 million construction loan which will convert to a term loan upon commercial operation, a $51.0 million bridge loan and approximately $75.0 million of equity contributed by Atlantic Power. The bridge loan will be repaid from the proceeds of a federal stimulus grant which is expected to be received two months after achieving commercial operation.

As of March 31, 2011, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of Regulation S-K.

Market risk is the risk that changes in market prices, such as foreign exchange rates, interest rates and commodity prices, will affect our cash flows or the value of our holdings of financial instruments. The objective of market risk management is to minimize the impact that market risks have on our cash flows as described in the following paragraphs.

Our market risk-sensitive instruments and positions have been determined to be "other than trading." Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in fuel commodity prices, currency exchange rates or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in fuel commodity prices, currency exchange rates or interest rates and the timing of transactions.

Our current and future cash flows are impacted by changes in electricity, natural gas and coal prices. The combination of long-term energy sales and fuel purchase agreements is generally designed to mitigate the impacts to cash flows of changes in commodity prices by generally passing through changes in fuel prices to the buyer of the energy.

The Lake project's operating margin is exposed to changes in the market price of natural gas from until the expiration of its PPA on July 31, 2013. The Auburndale project purchases natural gas under a fuel supply agreement which provides approximately 80% of the project's fuel requirements at fixed prices through June 30, 2012. The remaining 20% is purchased at market prices and therefore the project is exposed to changes in natural gas prices for that portion of its gas requirements through the termination of the fuel supply agreement and 100% of its natural gas requirements from the expiration of the fuel contract in mid-2012 until the termination of its PPA at the end of 2013.

We have executed a strategy to mitigate the future exposure to changes in natural gas prices at Lake and Auburndale by periodically entering into financial swaps that effectively fix the price of natural gas required at these projects. These natural gas swaps are derivative financial instruments and are recorded in the consolidated balance sheet at fair value. Changes in the fair value of the natural gas swaps at Lake and Auburndale, through June 30, 2009 were recorded in other comprehensive income (loss) as they were designated as a hedge of the risk associated with changes in market prices of natural gas. As of July 1, 2009, these natural gas swap hedges were de-designated and the changes in

their fair value are recorded in change in fair value of derivative instruments in the consolidated statements of operations.

In 2011, projected cash distributions at Auburndale would change by approximately $0.5 million per $1.00/Mmbtu change in the price of natural gas based on the current level of un-hedged natural gas volumes at the project. In 2011, projected cash distributions at Lake would change by approximately $0.8 million per $1.00/Mmbtu change in the price of natural gas based on the current level of un-hedged natural gas volumes at the project.

Coal prices used in the revenue component of the projected distributions from the Lake and Auburndale projects incorporate a forecast of the applicable Crystal River facility coal cost provided by the utility based on their internal projections. The projected annual cash distributions from Lake and Auburndale combined would change by approximately $2.4 million for every $0.25/Mmbtu change in the projected price of coal.

The following table summarizes the hedge position related to natural gas needed to meet PPA requirements at Lake and Auburndale as of March 31, 2011 and May 10, 2011:

We expect cash distributions from Orlando to increase significantly following the expiration of the project's gas contract at the end of 2013 because both projected natural gas prices at that time and the prices in the natural gas swaps we have executed are lower than the price of natural gas being purchased under the project's gas contract.

We use forward foreign currency contracts to manage our exposure to changes in foreign exchange rates as we earn our income in U.S. dollars but pay dividends to shareholders in Canadian dollars. Since our inception, we have had an established hedging strategy for the purpose of mitigating the currency risk impact on the long-term sustainability of our dividends to shareholders. We have executed this strategy by entering into forward contracts to purchase Canadian dollars at fixed rates of exchange to hedge approximately 86% of our expected dividend and convertible debenture interest payments through 2013. Changes in the fair value of the forward contracts partially offset foreign exchange gains

or losses on the U.S. dollar equivalent of our Canadian dollar obligations. The forward contracts consist of (1) monthly purchases through the end of 2013 of Cdn$6.0 million at an exchange rate of Cdn$1.134 per U.S. dollar and (2) purchases in both April and October 2011 of Cdn$1.9 million at an exchange rate of Cdn$1.1075 per U.S. dollar.

The foreign exchange forward contracts are recorded at estimated fair value based on quoted market prices and the estimation of the counter-party's credit risk. Changes in the fair value of the foreign currency forward contracts are recorded in foreign exchange (gain) loss in the consolidated statements of operations.

The following table contains the components of recorded foreign exchange (gain) loss for the three-month periods ended March 31, 2011 and 2010:

The following table illustrates the impact on the fair value of our financial instruments of a 10% hypothetical change in the value of the U.S. dollar compared to the Canadian dollar as of March 31, 2011:

Changes in interest rates do not have a significant impact on cash payments that are required on our debt instruments as approximately 84% of our debt, including our share of the project-level debt associated with equity investments in affiliates, either bears interest at fixed rates or is financially hedged through the use of interest rate swaps.

We have executed an interest rate swap at our consolidated Auburndale project to economically fix a portion of its exposure to changes in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Auburndale debt. The interest rate swap was executed in November 2009 and expires on November 30, 2013.

We have an interest rate swap at our consolidated Cadillac project to economically fix a portion of its exposure to changes in interest rates related to the variable-rate debt. The interest rate swap agreement was designated as a cash flow hedge of the forecasted interest payments under the project-level Cadillac debt. The interest rate swap expires on June 30, 2025.

are not designated as hedges and changes in their fair market value are recorded in the statements of operations. The interest rate swaps were executed on October 21, 2010 and November 2, 2010 and expire on February 29, 2016 and November 30, 2030, respectively.

In accounting for cash flow hedges, gains and losses on the derivative contracts are reported in other comprehensive income, but only to the extent that the gains and losses from the change in value of the derivative contracts can later offset the loss or gain from the change in value of the hedged future cash flows during the period in which the hedged cash flows affect net income. That is, for cash flow hedges, all effective components of the derivative contracts' gains and losses are recorded in other comprehensive income (loss), pending occurrence of the expected transaction. Other comprehensive income (loss) consists of those financial items that are included in "Accumulated other comprehensive loss" in our accompanying consolidated balance sheets but not included in our net income. Thus, in highly effective cash flow hedges, where there is no ineffectiveness, other comprehensive income changes by exactly as much as the derivative contracts and there is no impact on earnings until the expected transaction occurs.

After considering the impact of interest rate swaps, a hypothetical change in the average interest rate of 100 basis points would change annual interest costs, including interest at equity investments, by approximately $1.1 million.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on this evaluation, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report on Form 10-Q.

There were no changes in our internal controls over financial reporting (as such term is defined in Rules 13a-15(f) under the Exchange Act) that occurred during the period covered by this report that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles. However, internal controls over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Except to the extent additional factual information disclosed elsewhere in this Quarterly Report on Form 10-Q relates to such risk factors (including, without limitation, the matters discussed in Part I, "Item 2-Management's Discussion and Analysis of Financial Condition and Results of Operations"), there were no material changes to the risk factors disclosed in Part I, "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2010.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	March 31, 2011		December 31, 2010

Property, plant and equipment	$	95,067	$	91,851
Transmission system rights		45,498		43,535
Other intangible assets		62,730		57,000

	March 31, 2011			December 31, 2010

Project debt, interest rates ranging from 5.1% to 9.0% maturing through 2028	$	253,962		$	254,581
Purchase accounting fair value adjustments		11,124			11,305
Less: current portion of long-term debt		(24,394	)		(21,587	)

Long-term debt	$	240,692		$	244,299



Balance at December 31, 2010 (Cdn$)	55,801		83,124		80,500
Principal amount converted (Cdn$)	(7,685	)	(8,119	)	—

Balance at March 31, 2011 (Cdn$)	48,116		75,005		80,500
Balance at March 31, 2011 (US$)	49,625		77,357		83,023
Common shares issued on conversion	619,752		624,535		—

		March 31, 2011

		Derivative Assets		Derivative Liabilities
Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—	$	2,107
	Interest rate swaps long-term		—		2,041

Total derivative instruments designated as cash flow hedges			—		4,148

Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—		2,253
	Interest rate swaps long-term		4,708		1,765
	Foreign currency forward contracts current		9,340		—
	Foreign currency forward contracts long-term		17,545		—
	Natural gas swaps current		—		4,580
	Natural gas swaps long-term		208		16,408

Total derivative instruments not designated as cash flow hedges			31,801		25,006

Total derivative instruments		$	31,801	$	29,154

		December 31, 2010

		Derivative Assets		Derivative Liabilities
Derivative instruments designated as cash flow hedges:
	Interest rate swaps current	$	—	$	2,124
	Interest rate swaps long-term		—		2,626

Total derivative instruments designated as cash flow hedges			—		4,750

Derivative instruments not designated as cash flow hedges:
	Interest rate swaps current		—		1,286
	Interest rate swaps long-term		3,299		2,000
	Foreign currency forward contracts current		8,865		—
	Foreign currency forward contracts long-term		14,585		—
	Natural gas swaps current		—		6,599
	Natural gas swaps long-term		—		16,917

Total derivative instruments not designated as cash flow hedges			26,749		26,802

Total derivative instruments		$	26,749	$	31,552

		March 31, 2011

		Level 1		Level 2		Level 3		Total
Assets:
	Cash and cash equivalents	$	28,258	$	—	$	—	$	28,258
	Restricted cash		23,268		—		—		23,268
	Derivative instruments asset		—		31,801		—		31,801

	Total	$	51,526	$	31,801	$	—	$	83,327

Liabilities:
	Derivative instruments liability	$	—	$	29,154	$	—	$	29,154

	Total	$	—	$	29,154	$	—	$	29,154

		Three months ended March 31,

	Classification of (gain) loss recognized in income	Three months ended March 31,
	Classification of (gain) loss recognized in income	2011			2010
Natural gas swaps	Fuel	$	2,476		$	1,818
Foreign currency forwards	Foreign exchange gain		(2,537	)		(1,169	)
Interest rate swaps	Interest, net		976			475

	Units	March 31, 2011

Interest rate swaps	Interest (US$)	$	63,732
Currency forwards	Dollars (Cdn$)	$	201,800
Natural gas swaps	Natural Gas (Mmbtu)		14,580

		Three months ended March 31,

		2011			2010
Unrealized foreign exchange (gain) loss:
	Convertible debentures	$	5,314		$	(541	)
	Forward contracts and other		(3,436	)		(82	)

			1,878			(623	)
Realized foreign exchange gains on forward contract settlements			(2,536	)		(1,169	)

		$	(658	)	$	(1,792	)


Convertible debentures, at carrying value	$	21,001
Foreign currency forward contracts	$	(22,539	)

For the three month period ended March 31, 2011	Interest Rate Swaps			Natural Gas Swaps			Total

Accumulated OCI balance at December 31, 2010	$	(427	)	$	682		$	255
Change in fair value of cash flow hedges		721			—			721
Realized from OCI during the period		(360	)		(89	)		(449	)

Accumulated OCI balance at March 31, 2011	$	(66	)	$	593		$	527

For the three month period ended March 31, 2010	Interest Rate Swaps			Natural Gas Swaps			Total

Accumulated OCI balance at December 31, 2009	$	(538	)	$	(321	)	$	(859	)
Change in fair value of cash flow hedges		116			—			116
Realized from OCI during the period		(132	)		248			116

Accumulated OCI balance at March 31, 2010	$	(554	)	$	(73	)	$	(627	)

	Three months ended March 31,

	2011			2010
Current income tax expense (benefit)	$	(488	)	$	44
Deferred tax expense (benefit)		2,011			4,829

Total income tax expense (benefit)	$	1,523		$	4,873

			Grant Date Weighted-Average Fair Value per Unit

Outstanding at December 31, 2010	600,981		$	10.28
Granted	153,094		$	15.00
Additional shares from dividends	11,226		$	10.19
Vested	(263,523	)	$	9.40

Outstanding at March 31, 2011	501,778		$	11.97



Weighted average risk free rate of return	0.80	%
Dividend yield	7.5	%
Expected volatility—Company	25.0	%
Expected volatility—peer companies	15.0 – 85.0	%
Weighted average remaining measurement period	1.19 years



Project Name	Location (State)	Type	Total MW		Economic Interest⁽¹⁾			Net MW⁽²⁾		Electricity Purchaser	Power Contract Expiry			Customer S&P Credit Rating

Auburndale	Florida	Natural Gas		155		100.00	%		155	Progress Energy Florida		2013		BBB+

Lake	Florida	Natural Gas		121		100.00	%		121	Progress Energy Florida		2013		BBB+

Pasco	Florida	Natural Gas		121		100.00	%		121	Tampa Electric Co.		2018		BBB

Chambers	New Jersey	Coal		262		40.00	%		89	ACE⁽³⁾		2024		BBB+

									16	DuPont		2024		A

Path 15	California	Transmission		N/A		100.00	%		N/A	California Utilities via CAISO⁽⁴⁾		N/A	⁽⁵⁾	BBB+ to A⁽⁶⁾

Orlando	Florida	Natural Gas		129		50.00	%		46	Progress Energy Florida		2023		BBB+

									19	Reedy Creek Improvement District		2013	⁽⁷⁾	A1⁽⁸⁾

Selkirk	New York	Natural Gas		345		17.70	%⁽⁹⁾		15	Merchant		N/A		N/R

									49	Consolidated Edison		2014		A-

Gregory	Texas	Natural Gas		400		17.10	%		59	Fortis Energy Marketing and Trading		2013		AA

									9	Sherwin Alumina		2020		NR

Badger Creek	California	Natural Gas		46		50.00	%		23	Pacific Gas & Electric		2012	⁽¹⁰⁾	BBB+

Koma Kulshan	Washington	Hydro		13		49.80	%		6	Puget Sound Energy		2037		BBB

Delta-Person	New Mexico	Natural Gas		132		40.00	%		53	PNM		2020		BB-

Cadillac	Michigan	Biomass		40		100.00	%		40	Consumers Energy		2028		BBB-

Idaho Wind	Idaho	Wind		183		27.56	%		50	Idaho Power Co.		2030		BBB

Piedmont⁽¹¹⁾	Georgia	Biomass		54		98.00	%		53	Georgia Power		2032		A

	Range of Interest Rates	Total Remaining Principal Repayments		2011		2012		2013		2014		2015		Thereafter

Consolidated Projects:
Epsilon Power Partners	7.40%	$	36,107	$	1,125	$	1,500	$	3,000	$	5,000	$	5,750	$	19,732
Piedmont⁽¹⁾	5.20%		2,781		—		2,781		—		—		—		—
Path 15	7.9% - 9.0%		153,868		7,987		8,667		9,402		8,065		8,749		110,998
Auburndale	5.10%		19,250		7,350		7,000		4,900		—		—		—
Cadillac	6.02% - 8.0%		41,956		1,725		3,791		2,400		2,000		2,500		29,540

Total Consolidated Projects			253,962		18,187		23,739		19,702		15,065		16,999		160,270
Equity Method Projects:
Chambers	0.4% - 7.2%		72,222		8,471		12,176		10,783		5,780		5,213		29,799
Delta-Person	2.1%		10,253		862		1,212		1,300		1,394		1,495		3,990
Selkirk	9.0%		16,793		10,948		5,845		—		—		—		—
Idaho Wind	2.8% - 13.3%		83,940		41,666		1,848		1,892		2,049		2,136		34,349
Gregory	1.8% - 7.5%		13,972		1,523		2,044		2,205		2,385		2,492		3,323

Total Equity Method Projects			197,180		63,470		23,125		16,180		11,608		11,336		71,461

Total Project-Level Debt		$	451,142	$	81,657	$	46,864	$	35,882	$	26,673	$	28,335	$	231,731

	Three months ended March 31,

	2011		2010
Numerator:
Net income (loss) attributable to Atlantic Power Corporation	$	6,136	$	(6,063	)
Add: interest expense for potentially dilutive convertible debentures, net⁽¹⁾		—		—

Diluted net income (loss) attributable to Atlantic Power Corporation	$	6,136	$	(6,063	)

		Three months ended March 31,

		2011		2010
Denominator:
Basic shares outstanding			67,654		60,404
Dilutive potential shares:
	Convertible debentures		14,809		11,473
	LTIP notional units		517		394

Potentially dilutive shares			82,980		72,271

Diluted EPS		$	0.09	$	(0.10	)

	Path 15		Auburndale			Lake			Pasco			Chambers			Other Project Assets			Un-allocated Corporate			Consolidated

Three month period ended March 31, 2011:
Operating revenues	$	7,644	$	21,782		$	17,124		$	2,520		$	0		$	4,595		$	0		$	53,665
Segment assets		215,019		102,926			108,409			37,991			145,450			338,068			59,938			1,007,801
Project Adjusted EBITDA	$	6,570	$	10,313		$	8,490		$	(1,077	)	$	4,724		$	6,973		$	0		$	35,993
Change in fair value of derivative instruments		—		(961	)		(1,565	)		—			(752	)		494			—			(2,784	)
Depreciation and amortization		1,973		4,959			2,290			757			836			6,622			—			17,437
Interest, net		2,992		313			(3	)		—			1,386			1,552			—			6,240
Other project (income) expense		—		—			—			—			200			31			—			231

Project income		1,605		6,002			7,768			(1,834	)		3,054			(1,726	)		—			14,869
Interest, net		—		—			—			—			—			—			3,968			3,968
Administration		—		—			—			—			—			—			4,054			4,054
Foreign exchange gain		—		—			—			—			—			—			(658	)		(658	)
Other expense, net		—		—			—			—			—			—			—			—
Income (loss) from operations before income taxes		1,605		6,002			7,768			(1,834	)		3,054			(1,726	)		(7,364	)		7,505
Income tax expense (benefit)		—		—			—			—			—			—			1,523			1,523

Net income (loss)	$	1,605	$	6,002		$	7,768		$	(1,834	)	$	3,054		$	(1,726	)	$	(8,887	)	$	5,982

		Three months ended March 31,

(Unaudited) (in thousands of U.S. dollars, except as otherwise stated)		2011			2010
Project revenue
	Auburndale	$	21,782		$	20,467
	Lake		17,124			16,241
	Pasco		2,520			2,869
	Path 15		7,644			7,644
	Chambers		—			—
	Other Project Assets		4,595			—

			53,665			47,221
Project expenses
	Auburndale		16,428			16,044
	Lake		10,924			11,197
	Pasco		4,354			2,200
	Path 15		3,047			2,690
	Chambers		1			—
	Other Project Assets		4,265			57

			39,019			32,188
Project other income (expense)
	Auburndale		648			(4,683	)
	Lake		1,568			(7,933	)
	Pasco		—			—
	Path 15		(2,992	)		(3,146	)
	Chambers		3,055			3,449
	Other Project Assets		(2,056	)		1,144

			223			(11,169	)
Total project income
	Auburndale		6,002			(260	)
	Lake		7,768			(2,889	)
	Pasco		(1,834	)		669
	Path 15		1,605			1,808
	Chambers		3,054			3,449
	Other Project Assets		(1,726	)		1,087

			14,869			3,864
Administrative and other expenses
	Administration		4,054			4,100
	Interest, net		3,968			2,794
	Foreign exchange gain		(658	)		(1,792	)

Total administrative and other expenses			7,364			5,102

Income (loss) from operations before income taxes			7,505			(1,238	)
Income tax expense			1,523			4,873

Net (loss) income			5,982			(6,111	)
Net loss attributable to noncontrolling interest			(154	)		(48	)

Net income (loss) attributable to Atlantic Power Corporation shareholders		$	6,136		$	(6,063	)

		Project Adjusted EBITDA			Repayment of long-term debt			Interest expense, net			Capital expenditures			Change in working capital & other items			Project distributions received

Reportable Segments
	Auburndale	$	10,313		$	(2,450	)	$	(313	)	$	—		$	(750	)	$	6,800
	Chambers		4,724			(3,199	)		(1,386	)		—			(139	)		—
	Lake		8,490			—			3			(257	)		2,040			10,276
	Pasco		(1,077	)		—			—			—			1,732			655
	Path 15		6,570			—			(2,990	)		—			(3,580	)		—

Total Reportable Segments			29,020			(5,649	)		(4,686	)		(257	)		(697	)		17,731

Other Project Assets
	Cadillac		1,747			(575	)		(654	)		(62	)		744			1,200
	Piedmont		(29	)		—			—			—			29			—
	Idaho Wind		806			—			(369	)		—			105			542
	Badger Creek		760			—			—			—			65			825
	Delta Person		399			(268	)		(59	)		—			(72	)		—
	Gregory		772			(377	)		(38	)		(12	)		(345	)		—
	Koma Kulshan		60			—			—			—			165			225
	Orlando		1,891			—			1			(88	)		(1,604	)		200
	Selkirk		1,109			—			(394	)		—			(715	)		—
	Topsham		—			—			—			—			—			—
	Rollcast		(467	)		—			1			—			466			—
	Other		(75	)		—			(42	)		11			306			200

Total Other Project Assets Segment			6,973			(1,220	)		(1,554	)		(151	)		(856	)		3,192

Total all Segments		$	35,993		$	(6,869	)	$	(6,240	)	$	(408	)	$	(1,553	)	$	20,923

		Project Adjusted EBITDA			Repayment of long-term debt			Interest expense, net			Capital expenditures			Change in working capital & other items			Project distributions received

Reportable Segments
	Auburndale	$	9,371		$	(2,450	)	$	(471	)	$	—		$	(650	)	$	5,800
	Chambers		5,988			(3,013	)		(1,676	)		(34	)		(1,265	)		—
	Lake		7,313			—			2			(274	)		(1,011	)		6,030
	Pasco		1,415			—			—			(24	)		(361	)		1,030
	Path 15		7,053			—			(3,146	)		—			(3,907	)		—

Total Reportable Segments			31,140			(5,463	)		(5,291	)		(332	)		(7,194	)		12,860

Other Project Assets
	Badger Creek		736			—			6			—			92			834
	Delta Person		364			(662	)		(69	)		—			367			—
	Gregory		855			(394	)		206			—			(349	)		318
	Koma Kulshan		119			—			—			—			63			182
	Orlando		1,801			—			(33	)		(43	)		(1,725	)		—
	Rumford		(8	)		—			—			—			8			—
	Selkirk		3,530			—			(600	)		—			(2,930	)		—
	Topsham		415			—			—			—			(415	)		—
	Rollcast		—			—			—			—			—			—
	Other		(157	)		—			3			(21	)		175			—

Total Other Project Assets Segment			7,655			(1,056	)		(487	)		(64	)		(4,714	)		1,334

Total all Segments		$	38,795		$	(6,519	)	$	(5,778	)	$	(396	)	$	(11,908	)	$	14,194

As of March 31, 2011 and May 10, 2011			2011			2012			2013

Portion of gas volumes currently hedged:
	Lake:
		Contracted		—			—			—
		Financially hedged		78	%		90	%		83	%

		Total		78	%		90	%		83	%

	Auburndale:
		Contracted		80	%		40	%		0	%
		Financially hedged		13	%		32	%		79	%

		Total		93	%		72	%		79	%

Average price of financially hedged volumes (per Mmbtu)
	Lake		$	6.52		$	6.90		$	6.63
	Auburndale		$	6.68		$	6.51		$	6.92

Exhibit Number			Description

	31.1		Certification of Chief Executive Officer uprsuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
	31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
	32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002