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As filed with the Securities and Exchange Commission on October 7, 2010

Registration No. 333-168856

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

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AMENDMENT NO. 3
TO
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

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ATLANTIC POWER CORPORATION
(Exact Name of Registrant as Specified in Its Charter)

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200 Clarendon St., Floor 25
Boston, Massachusetts 02116
(617) 977-2400
(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant's Principal Executive Offices)

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Barry E. Welch
President and Chief Executive Officer
Atlantic Power Corporation
200 Clarendon St., Floor 25
Boston, Massachusetts 02116
(617) 977-2400
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service)

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            Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

           If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:     o

           If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o

           If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o

           If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     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 definition of "larger accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

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CALCULATION OF REGISTRATION FEE

(1)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

(2)

Represents the number of common shares, no par value, issuable upon conversion of the debentures. Pursuant to Rule 416 under the Securities Act, the common shares being registered hereby also include an indeterminate number of additional shares resulting from stock splits, dividends or similar transactions.

(3)

$3,931.48 of the registration fee was paid with the initial filing of the Registration Statement on August 13, 2010.

(4)

Pursuant to Rule 457(i) under the Securities Act, there is no additional filing fee with respect to the common shares issuable upon conversion of the debentures because no additional consideration will be received in connection with the exercise of the conversion privilege.

            The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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EXPLANATORY NOTES

        This Registration Statement contains both a United States prospectus (the "U.S. Prospectus") and a prospectus to be used in connection with offering the securities registered hereby in Canada (the "Canadian Prospectus"). The U.S. Prospectus and the Canadian Prospectus are identical in all material respects, except for the front cover page and certain other pages, and except that the Canadian Prospectus includes a "Certificate of the Company" and a "Certificate of the Underwriters." The complete U.S. Prospectus is included herein and is followed by those pages to be used solely in the Canadian Prospectus. Each of the alternate pages for the Canadian Prospectus included herein is labeled "Alternate Page for Canadian Prospectus."

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell and is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion dated October 7, 2010

Cdn$70,000,000

% Series B Convertible Unsecured Subordinated Debentures due         

          We are selling Cdn$70,000,000 aggregate principal amount of our      % Series B convertible unsecured subordinated debentures due         (the "Debentures"), at a price of Cdn$1,000 per Cdn$1,000 principal amount of Debentures. The Debentures have a maturity date of        and bear interest at an annual rate of       % payable semi-annually in arrears.

          Each Debenture will be convertible into our common shares at the option of the holder at any time prior to the close of business on the earlier of the maturity date and the business day immediately preceding the date specified by us for redemption of the Debentures at a conversion price of Cdn$      per common share, being a conversion rate of approximately         common shares per Cdn$1,000 principal amount of Debentures, subject to adjustment in accordance with the trust indenture governing the terms of the Debentures. We will not receive any proceeds from the issuance of the common shares upon conversion of the Debentures.

          The Debentures may not be redeemed by us on or before        (except in certain limited circumstances involving a change in control). After        and prior to         , we may redeem the Debentures, in whole or in part, at a redemption price equal to their principal amount plus accrued and unpaid interest, provided that the volume weighted average trading price of our common shares on the Toronto Stock Exchange (the "TSX") for the 20 consecutive trading days ending five trading days preceding the date on which notice of redemption is given is not less than 125% of the conversion price. On or after        and prior to the maturity date, we may redeem the Debentures, in whole or in part, at a price equal to their principal amount plus accrued and unpaid interest. See "Description of Debentures—Redemption and Purchase."

          The Debentures constitute a new issue of our securities for which there is currently no public market. As of October 4, 2010, we had $395.8 million of debt outstanding that ranks equal with or senior to the Debentures, and we expect to incur additional debt in the future. The amount at October 4, 2010 is comprised of $20.0 million outstanding under our revolving credit facility, $142.9 million of outstanding convertible debentures and $232.9 million of outstanding non-recourse project-level debt. Our outstanding common shares are listed on the TSX under the symbol "ATP" and on the New York Stock Exchange under the symbol "AT." The last reported sale price of our common shares on October 4, 2010 on the TSX and the New York Stock Exchange was Cdn$14.07 and $13.76 per common share, respectively. See "Exchange Rate Information" on page 30 for information regarding the exchange rate between Canadian dollars and U.S. dollars.

           Investing in the Debentures involves risks. You should read the section entitled "Risk Factors" beginning on page 11 of this prospectus for a discussion of certain risk factors you should consider before buying the Debentures.

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           Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

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          The underwriters have the option to purchase up to an additional Cdn$10,500,000 aggregate principal amount of Debentures from us at the public offering price less the underwriting discount.

          Book-entry only certificates representing the Debentures offered by this prospectus will be issued in registered form to CDS Clearing and Depository Services Inc. ("CDS") or its nominee as registered global securities and will be deposited with CDS on the date of issue of the Debentures, which is expected to occur on or about      , 2010 or such later date as we and the underwriters may agree, but in any event no later than      , 2010.

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BMO Capital Markets

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          The date of this prospectus is            , 2010.

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Prospectus

         You should rely only on information contained in this document or to which we have referred you. We have not, and our underwriters have not, authorized anyone to provide any information or to make any representations other than those contained in this prospectus or in any free writing prospectuses we have prepared or, for purchasers in Canada, the Canadian prospectus relating to this offering. If anyone provides you with different or inconsistent information, you should not rely on it. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We are not, and the underwriters are not, making an offer to sell the securities in any jurisdiction where the offer or sale is not permitted. This document may only be used where it is legal to sell these securities.

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        As used in this prospectus, the terms "Atlantic Power," the "Company," "we," "our," and "us" refer to Atlantic Power Corporation, together with those entities owned or controlled by Atlantic Power Corporation, unless the context indicates otherwise. All references to "Cdn$" and "Canadian dollars" are to the lawful currency of Canada and references to "$," "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. This prospectus includes our trademarks and other trade names identified herein. All other trademarks and trade names appearing in this prospectus are the property of their respective holders.

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PROSPECTUS SUMMARY

         The following summary may not contain all the information that may be important to you or that you should consider before deciding to purchase any Debentures and is qualified in its entirety by the more detailed information appearing elsewhere in this prospectus. You should read the entire prospectus, especially the risks set forth under the heading "Risk Factors" in this prospectus, as well as the financial and other information included herein, before making an investment decision.

Atlantic Power Corporation

        Atlantic Power Corporation is an independent power producer, with power projects located in major markets in the United States. Our current portfolio consists of interests in 12 operational power generation projects across eight states, one wind project under construction, a 500 kilovolt 84-mile electric transmission line located in California, and six development projects in five states. Our power generation projects have an aggregate gross electric generation capacity of approximately 1,823 megawatts (or "MW") in which our ownership interest is approximately 808 MW.

        The following map shows the location of our projects, including joint venture interests, across the United States:

        We sell the capacity and power 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 2010 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 and/or other forms of thermal energy from a number of our projects under energy sales agreements to industrial purchasers ("steam sales agreements"). The transmission system rights 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 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 most of the PPAs and steam sales agreements provide for the pass-through or indexing of fuel costs to our customers.

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

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        Atlantic Power Corporation is organized under the laws of the Province of British Columbia. Our registered office is located at 355 Burrard Street, Suite 1900, Vancouver, British Columbia, Canada V6C 2G8 and our headquarters are located at 200 Clarendon Street, Floor 25, Boston, Massachusetts, USA 02116. Our telephone number is (617) 977-2400. Our website address is www.atlanticpower.com. Information contained on, or otherwise accessible through, our website is not incorporated into, and does not constitute a part of, this prospectus or any other report or documents we file with or furnish to the SEC.

        We completed our initial public offering on the Toronto Stock Exchange, or the TSX, in November 2004. At the time of our initial public offering, our publicly traded security was an "income participating security," or "IPS," each of which was comprised of one common share and Cdn$5.767 principal value of 11% subordinated notes due 2016. On November 27, 2009, our shareholders approved a conversion from the IPS structure to a traditional common share structure. Each IPS has been exchanged for one new common share and each old common share that did not form a part of an IPS was exchanged for approximately 0.44 of a new common share. Our shares trade on the TSX under the symbol "ATP" and began trading on the New York Stock Exchange, or the NYSE, under the symbol "AT" on July 23, 2010.

Our Competitive Strengths

        We believe we distinguish ourselves from other independent power producers through the following competitive strengths:

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Diversified Projects.   Our power generation projects are diversified by geographic location, electricity and steam customers, and project operators. These projects are generally located in deregulated and more liquid electricity markets or regions of relatively high electricity demand growth.



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Strong Customer Base.   Our customers are generally large utilities and other parties with investment-grade credit ratings. The largest customers of our power generation projects include Progress Energy Florida, Inc., Tampa Electric Company and Atlantic City Electric.



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Leading Third-Party Managers.   Our power generation projects rely on a number of different operators for their operation, which are generally recognized leaders in the independent power business. Affiliates of Caithness, Power Plant Management Services and Babcock and Wilcox Power Generation Group, Inc. are our primary project operators.



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Stability of Project Cash Flow.   Each of our power generation projects currently in operation has been in operation for over ten years. Cash flows from each project are generally supported by energy sales contracts with investment-grade utilities and other sophisticated counterparties.

Our Objectives and Business Strategies

        Our objectives include maintaining the stability and sustainability of dividends to shareholders and to maximize the value of our company. In order to achieve these objectives, we intend to focus on enhancing the operating and financial performance of the projects and on pursuing additional acquisitions primarily in the electric power industry in the U.S. and Canada.

Organic Growth

        We intend to enhance the operation and financial performance of our projects through:

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optimization of commercial arrangements such as PPAs, fuel supply and transportation contracts, steam sales agreements, and operations and maintenance agreements;



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achievement of improved operating efficiencies;

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upgrade or enhancement of existing equipment or plant configurations; and



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expansion of existing projects.

        Successfully extending PPAs and fuel agreements may facilitate refinancings that provide capital to fund growth opportunities.

Extending PPAs Following Their Expiration

        PPAs in our portfolio have expiration dates ranging from 2010 to 2037. In each case, we plan for expirations by evaluating various options in the market for maximizing project cash flows. New arrangements may involve responses to utility solicitations for capacity and energy, direct negotiations with the original purchasing utility for PPA extensions, arrangements with creditworthy energy trading firms for tolling agreements, full service PPAs or the use of derivatives to lock in value. We do not assume that pricing under existing PPAs will necessarily be sustained after PPA expirations, since most original PPAs included capacity payments related to return of and return on original capital invested and counterparties or evolving regional electricity markets may or may not provide similar payments under new or extended PPAs.

Acquisition and Investment Strategy

        We believe that new electricity generation projects will be required in the United States and Canada over the next several years as a result of growth in electricity demand, transmission constraints and the retirement of older generation projects due to obsolescence or environmental concerns. There is also a very active secondary market for existing projects. We intend to expand our operations by making accretive acquisitions with a focus on power generation, transmission, distribution and related facilities in the United States and Canada. We may also invest in other forms of energy-related projects, utility projects and infrastructure projects, as well as additional investments in development stage projects or companies where the prospects for creating long-term predictable cash flows are attractive. Since the time of our initial public offering on the TSX in 2004, we have twice acquired the interest of another partner in one of our existing projects and will continue to look for such opportunities.

        Our senior management has significant experience in the independent power industry and we believe the experience, reputation and industry relationships of our management team will provide us with enhanced access to future acquisition opportunities.

Recent Developments

        On July 2, 2010, we acquired a 27.6% equity interest in Idaho Wind Partners 1, LLC ("Idaho Wind") for approximately $40 million. Idaho Wind recently commenced construction of a 183 MW wind power project located near Twin Falls, Idaho, which is currently scheduled to be completed in late 2010 or early 2011. Idaho Wind has 20-year fixed-price PPAs with Idaho Power Company. Our investment in Idaho Wind was funded with cash on hand and a $20 million borrowing under our senior credit facility. Upon completion of construction, we expect Idaho Wind to provide after-tax cash flows to us of $4.5 million to $5.5 million for each full year of operations. Our investment in Idaho Wind will be accounted for under the equity method of accounting. We expect Idaho Wind to shortly close a project-level financing in the amount of approximately $225 million, which will be non-recourse to Atlantic Power Corporation.

        In April 2010, our majority-owned subsidiary, Rollcast Energy, Inc., entered into a construction agreement for a 53.5 MW biomass project, known as Piedmont Green Power, to be located in Barnesville, Georgia. Pursuant to the terms of our investment in Rollcast, we have the option, but not the obligation, to invest directly in biomass power plants under development by Rollcast. We currently

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expect to invest up to $75 million in the Piedmont Green Power project, representing substantially all of the equity interests in the project. We intend to use a sole arranger to syndicate project-level debt financing for the project. Construction of the project is scheduled to commence upon the closing of construction financing early in the fourth quarter of 2010. The Piedmont Green Power project has a 20-year PPA with Georgia Power Company which includes an adjustment related to the cost of biomass fuel for the plant.

        Concurrently with this offering, we are also conducting a separate public offering of 5,100,000 common shares (plus up to an additional 765,000 common shares that we may issue and sell upon the exercise of the underwriters' option to purchase additional shares). This offering is not conditioned upon the successful completion of the concurrent offering of common shares and the concurrent offering of common shares is not conditioned upon the successful completion of this offering. See "Description of Concurrent Offering of Common Shares."

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Our Power Projects

        The following table outlines our portfolio of power generating and transmission assets in operation and under construction as of October 4, 2010, 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.

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Summary Risk Factors

        An investment in the Debentures involves material risks, including those we have highlighted below. You should consider carefully the risks described below and under "Risk Factors" before purchasing any Debentures in this offering:

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Our revenues depend on our power purchase agreements and we may be adversely affected if these agreements expire or terminate.



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We are dependent on our power generation projects and our transmission project for virtually all cash available for dividends and may be affected by the profitability of our projects.



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Each of our power generation projects depends on their customers for a substantial portion of its revenues and we may be adversely affected if these customers do not make required payments.



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Certain of our power generation projects are exposed to fluctuations in the price of electricity which affect their revenues.



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Fuel costs may affect profitability of our power generation projects.



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Our projects and operations are subject to various energy, environmental and other laws and regulations by federal and state agencies.



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We face increasing competition, which may adversely affect our performance and the performance of our projects.



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We are exposed to currency exchange rate risks because our revenues and most of our expenses are denominated in U.S. dollars and our payments to shareholders and debenture holders are denominated in Canadian dollars.



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Our projects may not operate as planned.



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Future dividends are not guaranteed.



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We have limited control over management decisions at certain projects.



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Financing arrangements could negatively impact our business.



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Conversion of Debentures into common shares could result in tax.



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There is no trading market for the Debentures.



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We may be unable to repay the Debentures.



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The Debentures may be redeemed prior to maturity.



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The rights and privileges of the Debenture holders are subordinate to our senior indebtedness.

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The Debentures

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Summary Historical Financial Information

        The following table presents summary consolidated financial information, which should be read in conjunction with our consolidated financial statements beginning on page F-1 and the related notes thereto, and "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 38. The annual historical information for each of the years in the three-year period ended December 31, 2009 has been derived from our audited consolidated financial statements included elsewhere in this prospectus. The historical information for the six-month periods ended June 30, 2009 and 2010 has been derived from our unaudited consolidated financial statements included elsewhere in this prospectus.

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RISK FACTORS

         Investing in the Debentures involves a high degree of risk. In addition to other information contained in this prospectus you should carefully consider the risks described below in evaluating our company and our business before making a decision to invest in the Debentures. These risks are not the only ones faced by us. Additional risks not presently known or that we currently deem immaterial could also materially and adversely affect our financial condition, results of operations, business and prospects. The trading price of our common shares into which the Debentures will be convertible could decline due to any of these risks, and you may lose all or part of your investment. This prospectus also contains forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including the risks faced by us described below and elsewhere in this prospectus. Please refer to the section entitled "Cautionary Statements Regarding Forward-Looking Statements" in this prospectus.

Risks Related to Our Business and Our Projects

Our revenue may be reduced upon the expiration or termination of our power purchase agreements

        Power generated by our projects, in most cases, is sold under PPAs that expire at various times. For example, PPAs at our Rumford, Badger Creek and Topsham projects expire between now and the end of 2011 and represent 52 MWs of our net generating capacity and the PPAs at our Auburndale, Lake and Gregory projects expire by the end of 2013 and represent 335 MWs of our net generating capacity. The table on page 5 contains details about all our projects' PPAs. In addition, these PPAs may be subject to termination in certain circumstances, including default by the project. When a PPA expires or is terminated, it is possible that the price received by the project for power under subsequent arrangements may be reduced significantly. It is possible that subsequent PPAs may not be available at prices that permit the operation of the project on a profitable basis. If this occurs, the affected project may temporarily or permanently cease operations.

Our projects depend on their electricity, thermal energy and transmission services customers

        Each of our projects rely on one or more PPAs, steam sales agreements or other agreements with one or more utilities or other customers for a substantial portion of its revenue. The largest customers of our power generation projects, including projects recorded under equity method of accounting, are Progress Energy Florida, Inc. ("PEF"), Tampa Electric Company ("TECO"), and Atlantic City Electric ("ACE"), which purchase approximately 40%, 15% and 11%, respectively, of the net electric generation capacity of our projects. The amount of cash available to pay dividends to shareholders is highly dependent upon customers under such agreements fulfilling their contractual obligations. There is no assurance that these customers will perform their obligations or make required payments.

Certain of our projects are exposed to fluctuations in the price of electricity

        Those of our projects with no PPA or PPAs based on spot market pricing will be exposed to fluctuations in the wholesale price of electricity. In addition, should any of the long-term PPAs expire or terminate, the relevant project will be required to either negotiate a new PPA or sell into the electricity wholesale market, in which case the prices for electricity will depend on market conditions at the time.

        Our most significant exposure to market power prices is at the Selkirk and Chambers projects. At Selkirk, approximately 23% of the capacity of the facility is not contracted and is sold at market prices or not sold at all if market prices do not support profitable operation of that portion of the facility. At Chambers, our utility customer has the right to sell a portion of the plant's output into the spot power market if it is economical to do so and the Chambers project shares in the profits from these sales.

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Our projects may not operate as planned

        The revenue generated by our power generation projects is dependent, in whole or in part, on the amount of electric energy and steam generated by them. The ability of our projects to generate the required amount of power to be sold to customers under the PPAs is a primary determinant of the amount of cash that will be distributed from the projects to us, and that will in turn be available for dividends paid to our shareholders. There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things, which could adversely affect revenues and cash flow. To the extent that our projects' equipment requires more frequent and/or longer than forecast down times for maintenance and repair, or suffers disruptions of power generation for other reasons, the amount of cash available for dividends may be adversely affected.

        In general, our power generation projects transmit electric power to the transmission grid for purchase under the PPAs through a single step up transformer. As a result, the transformer represents a single point of vulnerability and may exhibit no abnormal behavior in advance of a catastrophic failure that could cause a temporary shutdown of the facility until a spare transformer can be found or a replacement manufactured.

        If the reason for a shutdown is outside of the control of the operator, a power generation project may be able to make a force majeure claim for temporary relief of its obligations under the project contracts such as the PPA, fuel supply, steam sales agreement, a project-level debt agreement or otherwise mitigate impacts through business interruption insurance policies. If successful, such a claim may prevent a default or reduce monetary losses under such contracts. However, a force majeure claim may be challenged by the contract counterparty and, to the extent the challenge is successful, the outage may still have a materially adverse effect on the project.

Our projects depend on suppliers under fuel supply agreements and increases in fuel costs may adversely affect the profitability of the projects

        Revenues earned by our projects may be affected by the availability, or lack of availability, of a stable supply of fuel at reasonable or predictable prices. To the extent possible, the projects attempt to match fuel cost setting mechanisms in supply agreements to energy payments formulas in the PPA. To the extent that fuel costs are not matched well to PPA energy payments, increases in fuel costs may adversely affect the profitability of the projects.

        The amount of energy generated at the projects is highly dependent on suppliers under certain fuel supply agreements fulfilling their contractual obligations. The loss of significant fuel supply agreements or an inability or failure by any supplier to meet its contractual commitments may adversely affect our results.

        Upon the expiration or termination of existing fuel supply agreements, we or our project operators will have to renegotiate these agreements or may need to source fuel from other suppliers. Our project operators may not be able to renegotiate these agreements or enter into new agreements on similar terms. Furthermore, there can be no assurance as to availability of the supply or pricing of fuel under new arrangements and it can be very difficult to accurately predict the future prices of fuel. For example, a portion of the required natural gas at our Auburndale project and all of the natural gas required at our Lake project is purchased at market prices, but the projects' PPAs that expire in 2013 do not effectively pass through changes in natural gas prices. We have executed a hedging program to substantially mitigate this risk through 2013.

        The amount of energy generated at the projects is dependent upon the availability of natural gas, coal, oil or biomass. The long-term availability of such resources may not remain unchanged.

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Our projects depend on a favorable regulatory regime

        The profitability of our projects is in part dependent upon the continuation of a favorable regulatory climate with respect to the continuing operations and the future growth and development of the independent power industry. Should the regulatory regime in an applicable jurisdiction be modified in a manner which adversely affects the projects, including increases in taxes and permit fees, dividends to shareholders may be adversely affected. The failure to obtain all necessary licenses or permits, including renewals thereof or modifications thereto, may also adversely affect cash available to pay dividends.

Our operations are subject to the provisions of various energy laws and regulations

        Generally, in the United States, our projects are subject to regulation by the Federal Energy Regulatory Commission, or "FERC," regarding the terms and conditions of wholesale service and rates, as well as by state agencies regarding PPAs entered into by qualifying facility projects and the siting of the generation facilities. The majority of our generation is sold by qualifying facility projects under PPAs that required approval by state authorities.

        In August 2005, the Energy Policy Act of 2005 was enacted, which removed certain regulatory constraints on investment in utility power producers. The Energy Policy Act of 2005 also limited the requirement that electric utilities buy electricity from qualifying facilities to certain markets that lack competitive characteristics, potentially making it more difficult for our current and future projects to negotiate favorable PPAs with these utilities. Finally, the Energy Policy Act of 2005 amended and expanded the reach of the FERC's merger approval authority.

        If any project that is a qualifying facility were to lose its status as a qualifying facility, then such project may no longer be entitled to exemption from provisions of the Public Utility Holding Company Act of 2005 or from provisions of the Federal Power Act and state law and regulations. Such project may be able to obtain exempt wholesale generator status to maintain its exemption from the provisions of the Public Utility Holding Company Act of 2005, however our projects may not be able to obtain such exemptions. Loss of qualifying facility status could trigger defaults under covenants to maintain qualifying facility status in the PPAs, steam sales agreements and project-level debt agreements and if not cured within allowed cure periods, could result in termination of agreements, penalties or acceleration of indebtedness under such agreements, plus interest.

        Our projects would also have to file with the FERC for market-based rates or file for acceptance for filing of the rates set forth in the applicable PPA, and our projects' rates would then be subject to initial and potentially subsequent reviews by the FERC under the Federal Power Act, which could result in reductions to the rates.

        Our projects require licenses, permits and approvals which can be in addition to any required environmental permits. No assurance can be provided that we will be able to obtain, comply with and renew, as required, all necessary licenses, permits and approvals for these facilities. If we cannot comply with and renew as required all applicable licenses, permits and approvals, our business, results of operations and financial condition could be adversely affected.

        The Energy Policy Act of 2005 provides incentives for various forms of electric generation technologies, which may subsidize our competitors. In addition, pursuant to the Energy Policy Act of 2005, the FERC selected an electric reliability organization which imposes mandatory reliability rules and standards. Among other things, the FERC's rules implementing these provisions allow such reliability organizations to impose sanctions on generators that violate their new reliability rules.

        The introductions of new laws, or other future regulatory developments, may have a material adverse impact on our business, operations or financial condition.

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Future FERC rate determinations could negatively impact Path 15's cash flows

        The stability of Path 15's cash flows will continue to be subject to the risk of the FERC's adjusting the expected formulation of revenues upon its rate review every three years, and a rate review is set to commence in 2011. The cost-of-service methodology currently applied by the FERC is well established and transparent; however, certain inputs in the FERC's determination of rates are subject to its discretion, including in response to protests from interveners in such rate cases, which include return on equity and the recovery of certain extraordinary expenses. Unfavorable decisions on these matters could adversely affect the cash flow, financial position and results of operations of us and Path 15, and could adversely affect our cash available for dividends.

Noncompliance with federal reliability standards may subject us and our projects to penalties

        Our operations are subject to the regulations of the North American Electric Reliability Corporation ("NERC"), a self-regulatory organization that is a non-governmental entity which has statutory responsibility to regulate bulk power system users, generation and transmission owners and operators. NERC groups the users, owners, and operators of the bulk power system into 17 categories, known as functional entities—e.g., Generator Owner, Generator Operator, Purchasing-Selling Entity, etc.—according to the tasks they perform. The NERC Compliance Registry lists the entities responsible for complying with the mandatory reliability standards and the FERC, NERC, or a regional reliability organization may assess penalties against any responsible entity found to be in noncompliance. Violations may be discovered through self-certification, compliance audits, spot checking, self-reporting, compliance investigations by NERC (or a regional reliability organization) and the FERC, periodic data submittals, exception reporting, and complaints. NERC and the FERC have assigned a Violation Risk Factor of High, Medium, or Lower to each requirement of the mandatory reliability standards corresponding to the risk to the bulk power system associated with a violation of that requirement. The penalty that might be imposed for violating the requirements of the standards is a function of the Violation Risk Factor. Penalties for the most severe violations can reach as high as $1 million per violation, per day, and our projects could be exposed to these penalties if violations occur.

Our projects are subject to significant environmental and other regulations

        Our projects are subject to numerous and significant federal, state and local laws, including statutes, regulations, by-laws, guidelines, policies, directives and other requirements governing or relating to, among other things: air emissions; discharges into water; ash disposal; the storage, handling, use, transportation and distribution of dangerous goods and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the prevention, presence and remediation of hazardous materials in soil and groundwater, both on and off site; land use and zoning matters; and workers' health and safety matters. As such, the operation of our projects carries an inherent risk of environmental, health and safety liabilities (including potential civil actions, compliance or remediation orders, fines and other penalties), and may result in the projects being involved from time to time in administrative and judicial proceedings relating to such matters.

        The Clean Air Act and related regulations and programs of the Environmental Protection Agency extensively regulate the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by power plants. Environmental laws and regulations have generally become more stringent over time, and this trend may continue. In particular, the U.S. Environmental Protection Agency has promulgated regulations under the federal Clean Air Interstate Rule ("CAIR") requiring additional reductions in nitrogen oxides, or "NO _X, " and sulphur dioxide, or "SO _2, " emissions, beginning in 2009 and 2010 respectively, and has also promulgated regulations requiring reductions in mercury emissions from coal-fired electric generating units, beginning in 2010 with more substantial reductions in 2018.

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Moreover, certain of the states in which we operate have promulgated air pollution control regulations which are more stringent than existing and proposed federal regulations.

        While CAIR was set aside by a court decision in 2008, that decision allowed the CAIR requirements to remain in place pending further rulemaking by the Environmental Protection Agency. On July 6, 2010, the Environmental Protection Agency proposed to replace CAIR by requiring 31 states and the District of Columbia to curb emissions of sulfur dioxide and nitrogen oxides from power plants through more aggressive state-by-state emissions budgets for nitrogen oxides and sulfur dioxide. Compliance with the proposed rule, which would take effect in 2012, may have a material adverse impact on our business, operations or financial condition.

        The Environmental Protection Agency intends to propose new mercury emissions standards for power plants by March 2011 and to have new standards in place by November 2011. Meeting these new standards at our coal-fired facilities may have a material adverse impact on our business, operations or financial condition.

        The Resource Conservation and Recovery Act has historically exempted fossil fuel combustion wastes from hazardous waste regulation. However, in June 2010 the Environmental Protection Agency proposed two alternative sets of regulations governing coal ash. One set of proposed regulations would designate coal ash as "special waste" and bring ash impoundments at coal-fired power plants under federal regulations governing hazardous solid waste under Subtitle C of the Resource Conservation and Recovery Act. Another set of proposed regulations would regulate coal ash as a non-hazardous solid waste. If the Environmental Protection Agency determines to regulate coal ash as a hazardous waste, our coal-fired facilities may be subject to increased compliance obligations and costs that may have a material adverse impact on our business, operations or financial condition.

        Significant expenditures may be required for either capital expenditures or the purchase of allowances under any or all of these programs to keep the projects compliant with environmental laws and regulations. The projects' PPAs do not allow for the pass through of emissions allowance or emission reduction capital expenditure costs, with the exception of Pasco. If it is not economical to make those expenditures it may be necessary to retire or mothball facilities, or restrict or modify our operations to comply with more stringent standards.

        Our projects have obtained environmental permits and other approvals that are required for their operations. Compliance with applicable environmental laws, regulations, permits and approvals and material future changes to them could materially impact our businesses. Although we believe the operations of the projects are currently in material compliance with applicable environmental laws, licenses, permits and other authorizations required for the operation of the projects and although there are environmental monitoring and reporting systems in place with respect to all the projects, there is no guarantee that more stringent laws will not be imposed, that there will not be more stringent enforcement of applicable laws or that such systems may not fail, which may result in material expenditures. Failure by the projects to comply with any environmental, health or safety requirements, or increases in the cost of such compliance, including as a result of unanticipated liabilities or expenditures for investigation, assessment, remediation or prevention, could result in additional expense, capital expenditures, restrictions and delays in the projects' activities, the extent of which cannot be predicted.

Our projects are subject to regulation of CO ₂ and other greenhouse gases

        Ongoing public concerns about emissions of CO ₂ and other greenhouse gases from power plants have resulted in the enactment of, and proposals for, laws and regulations at the federal, state and regional levels, some of which do or could apply to some of our project operations. For example, the multi-state CO ₂ cap-and-trade program known as the Regional Greenhouse Gas Initiative applies to our fossil fuel facilities in the Northeast region. The Regional Greenhouse Gas Initiative program went

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into effect on January 1, 2009. CO ₂ allocations are now a tradeable commodity, currently averaging in the $2.05 to $3.20/ton range. The State of Florida has conducted stakeholder meetings as part of the process of developing greenhouse gas emissions regulations, the most recent of which was in January 2009. Discussions indicate favoring a program similar to that of the Regional Greenhouse Gas Initiative.

        California, New Mexico, Washington and other states are part of the Western Climate Initiative, which is developing a regional cap-and-trade program to reduce greenhouse gas emissions in the region to 15% below 2005 levels by 2020.

        In 2006, the State of California passed legislation initiating two programs to control/reduce the creation of greenhouse gases. The two laws, more commonly known as AB 32 and SB 1368, are currently in the regulatory rulemaking phase which will involve public comment and negotiations over specific provisions. Development towards the implementation of these programs continues.

        Under AB 32 (the California Global Warming Act of 2006) the California Air Resources Board is required to adopt a greenhouse gas emissions cap on all major sources (not limited to the electric sector). In order to do so, it must adopt regulations for the mandatory reporting and verification of greenhouse gas emissions and to reduce state-wide emissions of greenhouse gases to 1990 levels by 2020. This will most likely require that electric generating facilities reduce their emissions of greenhouse gases or pay for the right to emit by the implementation date of January 1, 2012. The program has yet to be finalized and the decision as to whether allocations will be distributed or auctioned will be determined in the rulemaking process that is currently underway. Discussion to date favors an auction-based allocation program.

        SB 1368 added the requirement that the California Energy Commission, in consultation with the California Public Utilities Commission (the "CPUC") and the California Air Resources Board establish greenhouse gas emission performance standards and implement regulations for power purchase agreements that exceed five years entered into prospectively by publicly-owned electric utilities. The legislation directs the California Energy Commission to establish the performance standard as one not exceeding the rate of greenhouse gas emitted per megawatt-hour associated with combined-cycle, gas turbine baseload generation, such as our Badger Creek project. Provisions are under consideration in the rulemaking to allow facilities that have higher CO ₂ emissions to be able to negotiate PPA's for up to a five-year period or sell power to entities not subject to SB 1368.

        In addition to the regional initiatives, legislation for the regulation of greenhouse gases has been introduced at the federal level and if passed, may eventually override the regional efforts with a national cap and trade program. Federal bills to create both a cap-and-trade allowance system and a renewable/efficiency portfolio standard have been introduced in both the house and senate. Separately, the U.S. Environmental Protection Agency has taken several recent actions to regulate greenhouse gas emissions.

        The Environmental Protection Agency's recent actions include its finding of "endangerment" to public health and welfare from greenhouse gases, its issuance in September 2009 of the Final Mandatory Reporting of Greenhouse Gases Rule which requires large sources, including power plants, to monitor and report greenhouse gas emissions to the Environmental Protection Agency annually starting in 2011, and its publication in May 2010 of its final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, to take effect in 2011, which requires large industrial facilities, including power plants, to obtain permits to emit, and to use best available control technology to curb emissions of, greenhouse gases.

        In addition, the United States is actively participating in various international initiatives to reduce greenhouse gas emissions globally that may result in further regulatory developments in the United States.

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        The implementation of existing CO ₂ and other greenhouse gas regulations, the introduction of new regulation, or other future regulatory developments may subject the Company to increased compliance obligations and costs that could have a material adverse impact on our business, operations or financial condition.

Increasing competition could adversely affect our performance and the performance of our projects

        The power generation industry is characterized by intense competition, and our projects encounter competition from utilities, industrial companies and other independent power producers, in particular with respect to un-contracted output. In recent years, there has been increasing competition among generators for power sales agreements, and this has contributed to a reduction in electricity prices in certain markets where supply has surpassed demand plus appropriate reserve margins. In addition, many states have implemented or are considering regulatory initiatives designed to increase competition in the U.S. power industry. Increasing competition among participants in the power generation industry may adversely affect our performance and the performance of our projects.

We have limited control over management decisions at certain projects

        In many cases, our projects are not wholly-owned by us or we have contracted for their operations and maintenance, and in some cases we have limited control over the operation of the projects. Although we generally prefer to acquire projects where we have control, we may make acquisitions in non-control situations to the extent that we consider it advantageous to do so and consistent with regulatory requirements and restrictions, including the Investment Company Act of 1940. Third-party operators (such as Caithness and GE) operate many of the projects. As such, we must rely on the technical and management expertise of these third-party operators, although typically we are represented on a management or operating committee if we do not own 100% of a project. To the extent that such third party operators do not fulfill their obligations to manage the operations of the projects or are not effective in doing so, the amount of cash available to pay dividends may be adversely affected.

We may face significant competition for acquisitions and may not successfully integrate acquisitions

        Our business plan includes growth through identifying suitable acquisition opportunities, pursuing such opportunities, consummating acquisitions and effectively integrating them with our business. We may be unable to identify attractive acquisition candidates in the power industry in the future, and we may not be able to make acquisitions on an accretive basis or that acquisitions will be successfully integrated into our existing operations.

        Although electricity demand is expected to grow, creating the need for more generation, and the U.S. power industry is continuing to undergo consolidation and may offer attractive acquisition opportunities, we are likely to confront significant competition for those opportunities and, to the extent that any opportunities are identified, we may be unable to effect acquisitions or investments.

        Any acquisition or investment may involve potential risks, including an increase in indebtedness, the inability to successfully integrate operations, the potential disruption of our ongoing business, the diversion of management's attention from other business concerns and the possibility that we pay more than the acquired company or interest is worth. There may also be liabilities that we fail to discover, or are unable to discover, in our due diligence prior to the consummation of an acquisition, and we may not be indemnified for some or all these liabilities. In addition, our funding requirements associated with acquisitions and integration costs may reduce the funds available to us to make dividend payments.

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Insurance may not be sufficient to cover all losses

        Our business involves significant operating hazards related to the generation of electricity. While we believe that the projects' insurance coverage addresses all material insurable risks, provides coverage that is similar to what would be maintained by a prudent owner/operator of similar facilities, and are subject to deductibles, limits and exclusions which are customary or reasonable given the cost of procuring insurance, current operating conditions and insurance market conditions, there can be no assurance that such insurance will continue to be offered on an economically feasible basis, nor that all events that could give rise to a loss or liability are insurable, nor that the amounts of insurance will at all times be sufficient to cover each and every loss or claim that may occur involving our assets or operations of our projects. Any losses in excess of those covered by insurance, which may include a significant judgment against any project or project operator, the loss of a significant permit or other approval or the imposition of a significant fine or penalty, could have a material adverse effect on our business, financial condition and future prospects and could adversely affect dividends to our shareholders.

Financing arrangements could negatively impact our business

        Our current or future borrowings could increase the level of financial risk to us and, to the extent that the interest rates are not fixed and rise, or that borrowings are refinanced at higher rates, then cash available for dividends could be adversely affected. As of October 4, 2010, we had $20.0 million outstanding under our revolving credit facility, $142.9 million of outstanding convertible debentures and $232.9 million of outstanding non-recourse project-level debt. Covenants in these borrowings may also adversely affect cash available for dividends. In addition, most of the projects currently have term loan or other financing arrangements in place with various lenders. These financing arrangements are typically secured by all of the project assets and contracts as well as the equity interests in the project operator (including those owned by us). The terms of these financing arrangements generally impose many covenants and obligations on the part of the project operator and other borrowers and guarantors. For example, some agreements contain requirements to maintain specified debt service coverage ratios before cash may be distributed from the relevant project to us. In many cases, a default by any party under other project agreements (such as a PPA or a fuel supply agreement) will also constitute a default under the project's term loan or other financing arrangement. Failure to comply with the terms of these term loans or other financing arrangements, or events of default thereunder, may prevent cash distributions by the project to us and may entitle the lenders to demand repayment and/or enforce their security interests.

        Our failure to refinance or repay any indebtedness when due could constitute a default under such indebtedness. Under such circumstances, it is expected that dividends to our shareholders would not be permitted until such indebtedness was refinanced or repaid and we may be required to sell assets or take other actions, including the initiation of bankruptcy proceedings or the commencement of an out-of-court debt restructuring.

Our equity interests in our projects may be subject to transfer restrictions

        The partnership or other agreements governing some of the projects may limit a partner's ability to sell its interest. Specifically, these agreements may prohibit any sale, pledge, transfer, assignment or other conveyance of the interest in a project without the consent of the other partners. In some cases, other partners may have rights of first offer or rights of first refusal in the event of a proposed sale or transfer of our interest. These restrictions may limit or prevent us from managing our interests in the projects in the manner we see fit, and may have an adverse effect on our ability to sell our interests in these projects at the prices we desire.

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The projects are exposed to risks inherent in the use of derivative instruments

        We and the projects may use derivative instruments, including futures, forwards, options and swaps, to manage commodity and financial market risks. In the future, the project operators could recognize financial losses on these arrangements as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. If actively quoted market prices and pricing information from external sources are not available, the valuation of these contracts would involve judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

        Most of these contracts are recorded at fair value with changes in fair value recorded currently in earnings, resulting in significant volatility in our income (as calculated in accordance with GAAP) that does not significantly affect current period cash flows or the underlying risk management purpose of the derivative instruments. As a result, we may be unable to accurately predict the impact that our risk management decisions may have on our quarterly and annual income (as calculated in accordance with GAAP).

        If the values of these financial contracts change in a manner that we do not anticipate, or if a counterparty fails to perform under a contract, it could harm our financial condition, results of operations and cash flows. We have executed natural gas swaps to reduce our risks to changes in the market price of natural gas, which is the fuel consumed at many of our projects. Due to declining natural gas prices, we have incurred losses on these natural gas swaps. We execute these swaps only for the purpose of managing risks and not for speculative trading.

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Risks Related to Our Structure

We are dependent on our projects for virtually all cash available for dividends

        We are dependent on the operations and assets of the projects through our indirect ownership of interests in the projects. The actual amount of cash available for dividends to our shareholders depends upon numerous factors, including profitability, changes in revenues, fluctuations in working capital, availability under existing credit facilities, capital expenditure levels, applicable laws, compliance with contracts and contractual restrictive covenants contained in any debt documentation.

Distribution of available cash may restrict our potential growth

        A payout of a significant portion of substantially all of our operating cash flow will make additional capital and operating expenditures dependent on increased cash flow or additional financing in the future. Lack of these funds could limit our future growth and cash flow. In addition, we may be precluded from pursuing otherwise attractive acquisitions or investments because they may not be accretive to us on a short-term basis.

Future dividends are not guaranteed

        Our board of directors may, in their discretion, amend or repeal our existing dividend policy. Future dividends, if any, will depend on, among other things, the results of operations, working capital requirements, financial condition, restrictive covenants, business opportunities, provisions of applicable law and other factors that our board of directors may deem relevant. Our board of directors may decrease the level of or entirely discontinue payment of dividends.

Exchange rate fluctuations may impact our amount of cash available for dividends

        Our payments to shareholders and convertible debenture holders are denominated in Canadian dollars. Conversely, all of our projects' revenues and expenses are denominated in U.S. dollars. As a result, we are exposed to currency exchange rate risks. Despite our hedges against this risk through 2013, any arrangements to mitigate this exchange rate risk may not be sufficient to fully protect against this risk. If hedging transactions do not fully protect against this risk, changes in the currency exchange rate between U.S. and Canadian dollars could adversely affect our cash available for distribution.

Our indebtedness could negatively impact our business and our projects

        The degree to which we are leveraged on a consolidated basis could increase and have important consequences to our shareholders, including:

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our ability in the future to obtain additional financing for working capital, capital expenditures, acquisitions or other purposes may be limited;



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we may be unable to refinance indebtedness on terms acceptable to us or at all; and



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we may be limited in our ability to react to competitive pressures.

        As of June 30, 2010, our consolidated long-term debt and our share of the debt of our unconsolidated affiliates represented approximately 55% of our total capitalization, comprised of debt and balance sheet equity.

Changes in our creditworthiness may affect the value of our common shares

        Changes to our perceived creditworthiness may affect the market price or value and the liquidity of our common shares. The interest rate we pay on our credit facility may increase if certain credit ratios deteriorate.

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Future issuances of our common shares could result in dilution

        Our articles of incorporation authorize the issuance of an unlimited number of common shares for such consideration and on such terms and conditions as are established by our board of directors without the approval of any of our shareholders. We may issue additional common shares in connection with a future financing or acquisition. The issuance of additional common shares may dilute an investor's investment in us and reduce cash available for distribution per common share.

Investment eligibility

        There can be no assurance that our common shares or Debentures will continue to be qualified investments under relevant Canadian tax laws for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans, registered education savings plans, registered disability savings plans and tax-free savings accounts.

We are subject to Canadian tax

        As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes, and dividends paid by us are generally subject to Canadian withholding tax if paid to a shareholder that is not a resident of Canada. We completed our initial public offering on the TSX in November 2004. At the time of the initial public offering, our public security was an IPS. Each IPS was comprised of one common share and Cdn$5.767 principal value of 11% subordinated notes due 2016. In the fourth quarter of 2009, we converted to a traditional common share company through a shareholder approved plan of arrangement in which each IPS was exchanged for one of our new common shares. Our new common shares were listed and posted for trading on the TSX commencing on December 2, 2009 and trade under the symbol "ATP," and the former IPSs, which traded under the symbol "ATP.UN," were delisted at that time. In connection with our conversion from an IPS structure to a traditional common share structure and the related reorganization of our organizational structure, we received a note from our primary U.S. holding company (the "Intercompany Note"). We are required to include in computing our taxable income interest on the Intercompany Note. We expect that our existing tax attributes initially will be available to offset this income inclusion such that it will not result in an immediate material increase to our liability for Canadian taxes. However, once we fully utilize our existing tax attributes (or if, for any reason, these attributes were not available to us), our Canadian tax liability would materially increase. Although we intend to explore potential opportunities in the future to preserve the tax efficiency of our structure, no assurances can be given that our Canadian tax liability will not materially increase at that time.

Withholding Tax

        Effective January 1, 2008, the Tax Act was amended to generally eliminate withholding tax on interest paid or credited to non-residents of Canada with whom the payor deals at arm's length. However, Canadian withholding tax continues to apply to payments of "participating debt interest." For purposes of the Tax Act, participating debt interest is generally interest that is paid on an obligation where all or any portion of such interest is contingent or dependent on the use of or production from property in Canada or is computed by reference to revenue, profit, cash flow, commodity price or any similar criterion.

        Under the Tax Act, when a debenture or other debt obligation issued by a person resident in Canada is assigned or otherwise transferred by a non-resident person to a person resident in Canada (which would include a conversion of the obligation or payment on maturity), the amount, if any, by which the price for which the obligation was assigned or transferred exceeds the price for which the obligation was issued is deemed to be a payment of interest on that obligation made by the person resident in Canada to the non-resident (an "excess"). The deeming rule does not apply in respect of

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certain "excluded obligations," although it is not clear whether a particular convertible debenture would qualify as an "excluded obligation." If a convertible debenture is not an "excluded obligation," issues that arise are whether any excess would be considered to exist, whether any such excess which is deemed to be interest is "participating debt interest," and if the excess is participating debt interest, whether that results in all interest on the obligation being considered to be participating debt interest.

        The Canada Revenue Agency ("CRA") has stated that no excess, and therefore no participating debt interest, generally would arise on the conversion of a "traditional convertible debenture" and therefore, there would be no withholding tax in such circumstances (provided that the payor and payee deal at arm's length for purposes of the Tax Act). The CRA has published guidance describing certain minimum terms and conditions that a debenture should generally have to be a "traditional convertible debenture" for these purposes. The Debentures generally meet the criteria set forth in CRA's published guidance; however, the Indenture also contains additional terms which are not contemplated in the CRA's published guidance. Accordingly, the application of the CRA's published guidance is uncertain and there is a risk that amounts paid or payable by the Company to a holder of Debentures on account of interest or any "excess" amount may be subject to Canadian withholding tax at 25% (subject to any reduction in accordance with the Canadian Treaty).

        The Indenture will not contain a requirement for the Company to increase the amount of interest or other payments to holders of Debentures should the Company be required to withhold amounts in respect of income or similar taxes on payments of interest or other amounts.

Other Canadian federal income tax risks

        There can be no assurance that Canadian federal income tax laws and CRA administrative policies respecting the Canadian federal income tax consequences generally applicable to us, to our subsidiaries, or to a holder of Debentures or common shares will not be changed in a manner which adversely affects holders of our Debentures or common shares.

Our prior and current structure may be subject to additional U.S. federal income tax liability

        Under our prior IPS structure, we treated the subordinated notes as debt for U.S. federal income tax purposes. Accordingly, we deducted the interest payments on the subordinated notes and reduced our net taxable income treated as "effectively connected income" for U.S. federal income tax purposes. Under our current structure, our subsidiaries that are incorporated in the United States are subject to U.S. federal income tax on their income at regular corporate rates (currently as high as 35%, plus state and local taxes), and our U.S. holding company will claim interest deductions with respect to the Intercompany Note in computing its income for U.S. federal income tax purposes. To the extent this interest expense is disallowed or is otherwise not deductible, the U.S. federal income tax liability of our U.S. holding company will increase, which could materially affect the after-tax cash available to distribute to us. While we received advice from our U.S. tax counsel, based on certain representations by us and our U.S. holding company and determinations made by our independent advisors, as applicable, that the subordinated notes and the Intercompany Note should be treated as debt for U.S. federal income tax purposes, it is possible that the Internal Revenue Service ("IRS") could successfully challenge those positions and assert that subordinated notes or the Intercompany Note should be treated as equity rather than debt for U.S. federal income tax purposes. In this case, the otherwise deductible interest on the subordinated notes or the Intercompany Note would be treated as non-deductible distributions and, in the case of the Intercompany Note, would be subject to U.S. withholding tax to the extent our U.S. holding company had current or accumulated earnings and profits. The determination of whether the subordinated notes and the U.S. holding company's indebtedness to us is debt or equity for U.S. federal income tax purposes is based on an analysis of the facts and circumstances. There is no clear statutory definition of debt for U.S. federal income tax purposes, and its characterization is governed by principles developed in case law, which analyzes

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numerous factors that are intended to identify the nature of the purported creditor's interest in the borrower. Furthermore, not all courts have applied this analysis in the same manner, and some courts have placed more emphasis on certain factors than other courts have. To the extent it were ultimately determined that our interest expenses on either the subordinated notes or the Intercompany Note were disallowed, our U.S. federal income tax liability for the applicable open tax years would materially increase, which could materially affect the after-tax cash available to us to distribute. Alternatively, the IRS could argue that the interest on the subordinated notes or the Intercompany Note exceeded or exceeds an arm's length rate, in which case only the portion of the interest expense that does not exceed an arm's length rate may be deductible and, in the case of the Intercompany Note, the remainder would be subject to U.S. withholding tax to the extent our U.S. holding company had current or accumulated earnings and profits. We have received advice from independent advisors that the interest rate on the subordinated notes and the Intercompany Note was and is, as applicable, commercially reasonable in the circumstances, but the advice is not binding on the IRS.

        Furthermore, our U.S. holding company's deductions attributable to the interest expense on the Intercompany Note may be limited by the amount by which its net interest expense (the interest paid by our U.S. holding company on all debt, including the Intercompany Note, less its interest income) exceeds 50% of its adjusted taxable income (generally, U.S. federal taxable income before net interest expense, net operating loss carryovers, depreciation and amortization). Any disallowed interest expense may currently be carried forward to future years. Moreover, proposed legislation has been introduced, though not enacted, several times in recent years that would further limit the 50% of adjusted taxable income cap described above to 25% of adjusted taxable income, although recent proposals in the Fiscal Year Budget for 2010 would only apply the revised rules to certain foreign corporations that were expatriated. Furthermore, if our U.S. holding company does not make regular interest payments as required under the Intercompany Note, other limitations on the deductibility of interest under U.S. federal income tax laws could apply to defer and/or eliminate all or a portion of the interest deduction that our U.S. holding company would otherwise be entitled to with respect to the Intercompany Note.

Conversion of the Debentures into common shares could result in tax

        Holders of the Debentures that are subject to U.S. federal income tax could potentially recognize foreign currency gain or loss upon the conversion of the Debentures into common shares.

Passive foreign investment company treatment

        We do not believe that we are a passive foreign investment company, and we do not expect to become a passive foreign investment company. However, if we were a passive foreign investment company while a taxable U.S. holder held common shares, such U.S. holder could be subject to an interest charge on any deferred taxation and the treatment of gain upon the sale of our stock as ordinary income. Additionally, if we were a passive foreign investment company while a taxable U.S. holder held Debentures, the interest charge and gain recharacterization rules described in the preceding sentence could potentially apply to such U.S. holder with respect to its Debentures, or to any common shares received upon a conversion of the Debentures.

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Risks Related to the Debentures

There is no trading market for the Debentures

        The Debentures constitute a new issue of securities of the Company for which there is currently no public market. Even if the Debentures are listed on a public securities exchange or market, the Debentures may trade at a discount from their offering price depending on prevailing interest rates, the market for similar securities, our performance and other factors. No assurance can be given as to whether an active trading market will develop or be maintained for the Debentures. To the extent that an active trading market for the Debentures does not develop, the liquidity and trading prices for the Debentures may be adversely affected.

We may be unable to repay the Debentures

        The Debentures mature on            . We may not be able to refinance the principal amount of the Debentures in order to repay the principal outstanding or may not have generated enough cash from operations to meet this obligation. There is no guarantee that we will be able to repay the outstanding principal amount upon maturity of the Debentures. The Debentures will not be guaranteed by any of our subsidiaries, and any restrictions on the distribution of cash at the project level, such as due to restrictive covenants in project-level financing agreements, could materially limit our ability to pay principal and interest on the Debentures when due.

The Indenture will not have any covenant restriction protections

        The trust indenture governing the Debentures does not restrict us or any of our subsidiaries from incurring additional indebtedness for borrowed money or otherwise from mortgaging, pledging or charging our real or personal property or properties to secure any indebtedness or other financing. The indenture does not contain any provisions specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving us or any of our subsidiaries.

We are obligated to redeem the Debentures on a change of control

        We will be required to offer to purchase all outstanding Debentures upon the occurrence of a change of control. However, it is possible that following a change of control, we will not have sufficient funds at that time to make the required purchase of outstanding Debentures or that restrictions contained in other indebtedness will restrict those purchases. See "Description of Debentures—Change of Control."

The Debentures may be redeemed prior to maturity

        The Debentures may be redeemed, at our option, subject to certain conditions, after                  and prior to their maturity date in whole or in part, at a redemption price equal to the principal amount thereof, together with any accrued and unpaid interest, as described under "Description of Debentures—Redemption and Purchase." Holders of Debentures should assume that this redemption option will be exercised if we are able to refinance at a lower interest rate or it is otherwise in our interest to redeem the Debentures.

The Debentures may become convertible into other securities, cash or property following certain transactions

        In the event of certain transactions, pursuant to the terms of the indenture, each Debenture will become convertible into securities, cash or property receivable by a holder of common shares in such transactions. This change could substantially reduce or eliminate any potential future value of the conversion privilege associated with the Debentures. For example, if we were acquired in a cash merger, each Debenture would become convertible solely into cash and would no longer be convertible

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into securities whose value would vary depending on our future prospects and other factors. See "Description of Debentures—Conversion Privilege."

There is a credit risk associated with payment of the principal and interest on the Debentures

        The likelihood that purchasers of the Debentures will receive payments owing to them under the terms of the Debentures will depend on our financial health and creditworthiness.

The rights and privileges of the Debenture holders are subordinate to our senior indebtedness

        The Debentures are our unsecured obligations and are subordinate in right of payment to all of our existing and future senior indebtedness, including our convertible debentures issued on October 11, 2006. In the event of our insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up, the assets that serve as collateral for any senior indebtedness would be made available to satisfy the obligations of the creditors of such senior indebtedness before being available to pay our obligations to Debenture holders. Accordingly, all or a substantial portion of our assets could be unavailable to satisfy the claims of the Debenture holders.

We have discretion in the use of proceeds

        Management will have discretion concerning the use of proceeds of this offering and the concurrent offering of common shares, as well as the timing of their expenditures. As a result, investors will be relying on the judgment of management as to the application of the proceeds of the offerings. Management may use the net proceeds of the U.S. and Canadian offerings in ways that an investor may not consider desirable. The results and effectiveness of the application of the proceeds are uncertain. If the proceeds are not applied effectively, our results of operations may suffer.

The amount of interest or other payments will not increase upon an increase in amounts withheld for taxes on payments of interest or other amounts

        The indenture does not contain a requirement for us to increase the amount of interest or other payments to holders of Debentures should we be required to withhold amounts in respect of income or similar taxes on payments of interest or other amounts.

Risks Related to the Common Shares

Market conditions and other factors may affect the value of the common shares issuable upon conversion of the Debentures

        The trading price of the common shares issuable upon conversion of the Debentures will depend on many factors, which may change from time to time, including:

•

conditions in the power production markets and the energy markets generally;



•

interest rates;



•

the market for similar securities;



•

government action or regulation;



•

general economic conditions or conditions in the financial markets;



•

our past and future dividend practice; and



•

our financial condition, performance, creditworthiness and prospects.

        Accordingly, the common shares that a Debenture holder receives upon conversion of the Debentures may trade at a price lower than the conversion price.

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The market price and trading volume of the common shares issuable upon conversion of the Debentures may be volatile

        The market price of the common shares issuable upon conversion of the Debentures may be volatile, particularly given the current economic environment. In addition, the trading volume in our common shares may fluctuate and cause significant price variations to occur. If the market price of our common shares declines significantly, you may be unable to resell your shares at or above the price at the time of conversion. The market price of our common shares may fluctuate or decline significantly in the future.

        Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our common shares include:

•

quarterly variations in our operating results or the quality of our assets;



•

changes in applicable regulations or government action;



•

operating results that vary from the expectations of management, securities analysts and investors;



•

changes in expectations as to our future financial performance;



•

announcements of innovations, new products, strategic developments, significant contracts, acquisitions and other material events by us or our competitors;



•

changes in financial estimates or publication of research reports and recommendations by financial analysts or actions taken by rating agencies with respect to us or other companies in our industry;



•

the operating and securities price performance of other companies that investors believe are comparable to us;



•

changes in general market conditions, such as interest or foreign exchange rates, stock or commodity valuations, or volatility; and



•

actions by our current shareholders, including sales of our common shares by existing shareholders and/or directors and executive officers.

        Stock markets in general have experienced significant volatility over the past two years, and continue to experience significant price and volume volatility. As a result, the market price of our common shares may continue to be subject to similar market fluctuations that may be unrelated to our operating performance or prospects. Increased volatility could result in a decline in the market price of our common shares.

Present and future offerings of debt or equity securities, ranking senior to our common shares, may adversely affect the market price of our common shares

        If we decide to issue debt or equity securities ranking senior to our common shares in the future it is likely that they will be governed by an indenture or other instrument containing covenants restricting our operating flexibility. Additionally, any convertible or exchangeable securities that we issue in the future may have rights, preferences and privileges more favorable than those of holders of our common shares and may result in dilution to holders of our common shares. We and, indirectly, our shareholders, will bear the cost of issuing and servicing such securities. Because our decision to issue debt or equity securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings. Thus, holders of our common shares will bear the risk of our future offerings reducing the market price of our common shares and diluting the value of their share holdings in us.

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The number of shares available for future sale could adversely affect the market price of our common shares.

        We cannot predict whether future issuances of our common shares or the availability of shares for resale in the open market will decrease the market price per common share. We may issue additional common shares, including securities that are convertible into or exchangeable for, or that represent the right to receive common shares. Sales of a substantial number of common shares in the public market or the perception that such sales might occur could materially adversely affect the market price of our common shares. Because our decision to issue securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings. Thus, our shareholders bear the risk of our future offerings reducing the market price of our common shares and diluting their share holdings in us.

        The exercise of the underwriters' option to purchase additional Debentures, the exercise of any options granted to directors, executive officers and other employees under our stock compensation plans, and other issuances of our common shares could have an adverse effect on the market price of our common shares, and the existence of options may materially adversely affect the terms upon which we may be able to obtain additional capital through the sale of equity securities. In addition, future sales of our common shares may be dilutive to existing shareholders.

The redemption of Debentures for or repayment of principal by issuing common shares may cause common shareholders dilution

        We may determine to redeem outstanding Debentures for common shares or to repay outstanding principal amounts thereunder at maturity of the Debentures by issuing additional common shares. The issuance of additional common shares may have a dilutive effect on shareholders and an adverse impact on the price of our common shares.

Provisions of our articles of continuance could discourage potential acquisition proposals and could deter or prevent a change in control.

        We are governed by the Business Corporations Act (British Columbia). Our articles of continuance contain provisions that could have the effect of delaying, deferring or discouraging another party from acquiring control of our company by means of a tender offer, a proxy contest or otherwise. These provisions may make it more difficult for other persons, without the approval of our board of directors, to make a tender offer or otherwise acquire a substantial number of our common shares or to launch other takeover attempts that a shareholder might consider to be in his or her best interest. These provisions could limit the price that some investors might be willing to pay in the future for our common shares.

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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

        Certain statements contained in this prospectus and in any related prospectus that are not historical facts may constitute forward-looking statements. Forward-looking statements involve risks and uncertainties. These statements, which are based on certain assumptions and describe our future plans, projections, strategies and expectations, can generally be identified by the use of the words "outlook," "objective," "may," "will," "should," "could," "would," "plan," "potential," "estimate," "project," "continue," "believe," "intend," "anticipate," "expect," "target" or the negatives of these words and phrases or similar expressions that are predictions of or indicate future events or trends and which do not relate solely to present or historical matters. These forward-looking statements include, but are not limited to, statements relating to:

•

our objectives, business, asset management and acquisition strategies;



•

success of acquisitions, future operations, market position and financial position;



•

expected opportunities for accretive acquisitions;



•

the amount of distributions expected to be received from the projects for the full year 2010;



•

estimated net cash tax refund in 2010;



•

our forecast of expected after-tax cash flows from Idaho Wind for each full year of operations;



•

our forecast of expected annual cash distributions from the Lake and Auburndale projects through 2012;



•

our forecast of expected closing of construction financing for our Piedmont project;



•

the expected resumption of distributions from our Chambers, Selkirk and Delta projects in 2011; and



•

the expected use of proceeds from this offering and the concurrent offering of common shares.

        Such forward-looking statements reflect our current expectations regarding future events and operating performance and speak only as of the date of this prospectus. 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" in this prospectus. Our business is both competitive and subject to various risks.

        These risks include, without limitation:

•

a reduction in revenue upon expiration or termination of power purchase agreements;



•

the dependence of our projects on their electricity, thermal energy and transmission services customers;



•

exposure of certain of our projects to fluctuations in the price of electricity or natural gas;



•

projects not operating to plan;



•

the impact of significant environmental and other regulations on our projects;



•

increased competition, including for acquisitions;



•

our limited control over the operation of certain minority-owned projects; and

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•

changes in assumptions used in making such forward-looking statements.

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 prospectus 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. Therefore, investors are urged not to place undue reliance on our forward-looking statements. Certain statements included in this prospectus 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 prospectus.

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

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EXCHANGE RATE INFORMATION

        The following table sets forth, for each period indicated, the high and low exchange rates for one U.S. dollar, expressed in Canadian dollars, the average of such exchange rates on the last day of each month during such period and the exchange rate at the end of such period, based on the noon buying rate as quoted by the Bank of Canada. On October 4, 2010, the noon buying rate was US$1.00 = Cdn$1.0234.

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USE OF PROCEEDS

        We expect to receive net proceeds from this offering of approximately Cdn$66.3 million after deducting the underwriting discounts and our estimated expenses of this offering (or approximately Cdn$76.3 million if the underwriters exercise their option to purchase additional Debentures in full). We intend to use the net proceeds from this offering and the concurrent offering of common shares as follows:

(i)

approximately $20 million to repay indebtedness incurred under our credit facility in June 2010 to partially fund our previously-announced acquisition of a 27.6% equity interest in Idaho Wind Partners 1, LLC; and



(ii)

up to $75 million to fund an investment in the Piedmont Green Power biomass project in Barnesville, Georgia for substantially all of the equity interest in the project.

        Any remaining net proceeds will be used to fund additional growth opportunities and for general corporate purposes, including a potential further acquisition that we are currently considering.

        This offering is not conditioned upon the successful completion of the concurrent offering of common shares and the concurrent offering of common shares is not conditioned upon the successful completion of this offering. We expect to receive net proceeds from the concurrent offering of common shares of approximately $65.8 million after deducting the underwriting discounts and our estimated expenses of the concurrent offering (or approximately $75.8 million if the underwriters exercise their option to purchase additional common shares in full).

        If the concurrent offering of common shares is not successfully completed, we intend to use the net proceeds from this offering to partially fund the anticipated $75 million investment in the Piedmont Green Power biomass project and borrow from our revolving credit facility to fund any deficiency.

        As of October 4, 2010, borrowings under our revolving credit facility were $20 million and were used to fund acquisitions. The revolving credit facility has a maturity date of August 12, 2012. Borrowings under the credit facility accrue interest at the London Interbank Offered Rate ("LIBOR") plus an applicable margin between 1.50% and 3.25% that varies based on the credit statistics of one of our subsidiaries. The margin is currently 1.50%.

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RATIO OF EARNINGS TO FIXED CHARGES

        The following table sets forth our ratios of earnings to fixed charges for the periods indicated calculated on the basis of the U.S. GAAP financial statements included in this prospectus. For this purpose, "earnings" consists of earnings from continuing operations and distributed income of equity investees, excluding income taxes, non-controlling interests share in earnings and fixed charges, other than capitalized interest, and "fixed charges" consists of project-level interest expense and corporate level interest expense.

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DIVIDEND POLICY

        On November 24, 2009, our shareholders approved our conversion to a common share structure. Subsequent to the conversion, we have continued to maintain our business strategy and our current distribution levels. Each IPS has been exchanged for one new common share. Our entire current monthly cash distribution of Cdn$0.0912 per common share is being paid as a dividend on the new common shares on the last business day of each month for holders of record on the last business day of the immediately preceding month. We expect to continue paying cash dividends in the future in amounts that are comparable to the distributions paid in 2009. Future dividends are paid at the discretion of our board of directors subject to our earnings and cash flow and are not guaranteed. The primary risk that impacts our ability to continue paying cash dividends at the current rate is the operating performance of our projects and their ability to distribute cash to us after satisfying project-level obligations.

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MARKET PRICE OF AND DIVIDENDS ON THE COMMON SHARES AND
RELATED SHAREHOLDER MATTERS

        The IPSs were listed and posted for trading on the TSX under the symbol ATP.UN from our initial public offering in November 2004 through November 30, 2009. Following the closing of the exchange of IPSs for common shares, our new common shares commenced trading on the TSX on December 2, 2009 under the symbol ATP. The following table sets forth the price ranges of the outstanding IPSs and common shares, as applicable, as reported by the TSX for the periods indicated.

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        The following table shows the dividends declared for the periods indicated in Canadian dollars.

        Our shares began trading on the NYSE under the symbol "AT" on July 23, 2010. The following table sets forth the price ranges of our outstanding common shares, as reported by the NYSE from the date on which our common shares were listed through October 4, 2010.

        The following table shows the dividends declared for the periods indicated in U.S. dollars.

        On October 4, 2010, the closing price for our common shares on the TSX was Cdn$14.07, and the closing price for our common shares on the NYSE was $13.76. See "Exchange Rate Information" on page 30 for information regarding the exchange rate between Canadian dollars and U.S. dollars. There were approximately 36,600 shareholders of record of our common shares as of October 4, 2010.

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CAPITALIZATION

        The following table shows our capitalization as of June 30, 2010 on a historical basis and on an as adjusted basis to give effect to:

•

the sale of Cdn$70 million of our      % Series B convertible unsecured subordinated debentures due                 , after deducting underwriting discounts and estimated transaction expenses payable by us;



•

the concurrent offering and sale of our common shares, at an assumed offering price of $13.76 per share, the last reported sale price of our common shares on the New York Stock Exchange on October 4, 2010, after deducting underwriting discounts and estimated transaction expenses payable by us; and



•

the repayment of $20 million borrowed under our revolving credit facility in June 2010 from the net proceeds of this offering.

        You should read the information set forth in the table below together with our unaudited consolidated interim financial statements and the related notes for the six months ended June 30, 2010, included elsewhere in this prospectus.

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SELECTED HISTORICAL FINANCIAL INFORMATION

        The following table presents selected consolidated financial information, which should be read in conjunction with our consolidated financial statements beginning on page F-1 and the related notes thereto, and "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 38. The annual historical information for each of the years in the three-year period ended December 31, 2009 has been derived from our audited consolidated financial statements included elsewhere in this prospectus. The historical information for the six-month periods ended June 30, 2009 and 2010 has been derived from our unaudited consolidated financial statements included elsewhere in this prospectus.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

         The following management's discussion and analysis of financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto. All dollar amounts discussed below are in U.S. dollars, unless otherwise stated. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").

         This report contains, in addition to historical information, forward-looking statements that involve risks and uncertainties. These forward-looking statements reflect our current views about future events and financial performance. Forward-looking statements are subject to a variety of factors that could cause actual results to differ materially from our expectations. Factors that could cause, or contribute to such differences include, without limitation, the factors described under "Risk Factors." In view of these uncertainties, investors are cautioned not to place undue reliance on these forward-looking statements. We assume no obligation, unless required by law, to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Overview

        Atlantic Power Corporation is an independent power producer, with power projects located in major markets in the United States. Our current portfolio consists of interests in 12 operational power generation projects across eight states, one wind project under construction in Idaho, a 500 kilovolt 84-mile electric transmission line located in California, and six development projects in five states. Our power generation projects in operation have an aggregate gross electric generation capacity of approximately 1,823 megawatts (or "MW"), in which our ownership interest is approximately 808 MW.

        We sell the capacity and power 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 2010 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 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 most of the PPAs and steam sales agreements provide for the pass-through or indexing of fuel costs to our customers.

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

Current Trends in Our Business

Recession-related impacts

        The recession caused significant decreases in both peak electricity demand and consumption that varied by region, although as always, upcoming summer peak demand will also be greatly influenced by weather. This has the effect of delaying projected increases in capacity requirements in varying degrees by region. Historically, electricity demand has made a strong recovery to pre-recession levels along with the economic recovery and the postponement of generation capacity additions are reduced to some extent as well, depending on the pace of the recovery. The reduced electricity peak demand and

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consumption during a recession tends to impact base load (plants that typically operate at all times) and peaking plants (those that only operate in periods of very high demand) more than mid-merit plants (those that operate to meet the historical pattern of demand during the "peak" portion of most days, but not at night or in other lower demand periods such as weekends). During recessionary periods, base load plants are called on for lower levels of off-peak generation and peaking plants may be called on less frequently as a function of their efficiency and the overall peak demand level. The actual financial impacts on particular plants depend on whether contractual provisions, such as minimum load levels and/or significant capacity payments, partially mitigate the impact of reduced demand. One other recession-related industry impact was an easing of commodity costs, whose previous escalation had greatly increased new plant construction costs. The incipient economic recovery has moved prices higher again for copper, steel and other inputs, with labor costs a function of regional power plant and general construction activity levels, which in some locations includes increased renewable project construction.

Increased renewable power projects

        The combination of federal stimulus provisions, state Renewable Portfolio Standards and state or regional CO ₂ /greenhouse gases reduction programs has provided powerful incentives to build new renewable power capacity. One simple impact of this trend is the offsetting reduction in new fossil-fired generation, with the following exception. Because significant renewable capacity is being built as intermittent resources (e.g., wind and solar) there will be an increased need by system operators to have more "firming resources." These are units that can be started quickly or idled at low levels in order to be available to compensate for sudden decreases in output from the solar or wind projects. These firming resources are generally natural gas-fired generators or in more limited locations, pumped storage or reservoir-based hydro resources. The second significant impact of increased renewable projects is the increased need for new transmission lines to move power from renewable resources in typically more remote locations to the more highly-populated electricity load centers. This transmission requirement will require significant capital and tends to encounter a long and risky development and siting cycle.

Increased shale gas resources

        The substantial additions of economically viable shale gas reserves and increasing production levels have put strong downward pressure on natural gas prices in both the spot and forward markets. One impact of the reduced prices is that gas-fired generators have displaced some generation from base load coal plants, particularly in the southeast U.S. Lower natural gas prices also have compressed, and in some cases turned negative, the "spark spread," which is the industry term for the profit margin between fuel and power prices. Reduced spark spreads directly impact the profitability of plants selling power into the spot market with no contract, which are referred to as merchant plants.

        The lower power prices have a stifling impact on development of new renewable projects whose owners are attempting to negotiate power purchase agreements at favorable levels to support the financing and construction of the projects. The sense of reduced future volatility of gas prices due to increased supply has reinforced a growing expectation of natural gas' role as a "bridging fuel," helping from a carbon policy perspective to bridge the desired U.S. transition to both cleaner fuels and more commercially viable carbon removal and sequestration technologies.

Credit markets

        Weak credit markets over the past two years reduced the number of lenders providing power project financing, as well as the size and length of loans resulting in higher costs for such financing. This reduces the number of new power projects that can be feasibly financed and built. Credit market conditions for project-lending have generally improved in late 2009 and in 2010, but are still much

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weaker than pre-recession levels. However, base lending rates such as LIBOR have stayed quite low by historical standards, somewhat compensating for the increased interest rate spreads demanded by project lenders. Corporate level credit markets have experienced similar adverse impacts, which have impeded the ability of development companies to obtain financing for new power projects.

Factors That May Influence Our Results

        Our primary objective is to generate consistent levels of cash flow to support dividends to our shareholders who we believe are primarily focused on income and secondarily on capital appreciation. Because we believe that our shareholders are focused on cash flow measures of our results, we provide supplementary non-GAAP information in this MD&A and discuss our results in terms of these non-GAAP measures, in addition to analysis of our results on a GAAP basis. See "Supplementary Non-GAAP Financial Information" on page 50 of this prospectus for additional details.

        The primary components of our financial results are (i) the operating performance of our projects, (ii) non-cash gains and losses associated with derivative instruments and (iii) interest expense and foreign exchange impacts on corporate-level debt. We have recorded net losses in four of the past five years, primarily as a result of non-cash losses associated with items (ii) and (iii) above, which are described in more detail in the following paragraphs.

Operating performance of our projects

        The operating performance of our projects supports cash distributions that are made to us after all operating and capital expenditures and debt service requirements are satisfied at the project-level. Our projects are able to pay distributions to us because they generally receive revenues from long-term contracts that provide relatively stable cash flows. Risks to the stability of these distributions include the following:

•

While approximately 60% of our power generation revenue in 2009 was related to contractual capacity payments, commodity prices do influence our revenues and cost of fuel. Our PPAs are generally structured to minimize our risk to fluctuations in commodity prices by passing the cost of fuel through to our utility customers, but some of our projects do have exposure to market power and fuel prices. For example, a portion of the natural gas required for our Auburndale and Lake projects is purchased at spot market prices. We have executed a hedging strategy to substantially mitigate this risk. See "Outlook" below for additional details about our hedging program at Auburndale and Lake. Our most significant exposure to market power prices exists at the Selkirk and Chambers projects. At Selkirk, approximately 23% of the capacity of the facility is not contracted and is sold at market power prices or not sold at all if market prices do not support profitable operation of that portion of the facility. At Chambers, our utility customer has the right to sell a portion of the plant's output to the spot power market if it is economical to do so, and the Chambers project shares in the profits from those sales.



•

When revenue or fuel contracts at our projects expire, we may not be able to sell power or procure fuel under new arrangements that provide the same level or stability of project cash flows. In particular, the power agreements at our Lake and Auburndale projects expire in 2013. We expect these projects to continue operating and making distributions to us after their existing power contracts expire, but with new agreements providing significantly lower levels than the distributions we are currently receiving. The level of these distributions is subject to market conditions at such time as we execute new power agreements for these projects and cannot be estimated at this time. Both of these projects will be free of debt at the time their PPAs expire in 2013, which provides us with some flexibility to pursue the most economic type of contract without restrictions that are sometimes imposed by project-level debt.

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•

Some of our projects have non-recourse project-level debt that must be serviced before any distributions can be made to us. The project-level debt agreements typically contain cash flow coverage ratio tests that can prevent distributions to us if project cash flows do not exceed project-level debt service requirements by a specified amount. We are currently not receiving distributions from the Chambers, Selkirk and Delta-Person projects because of such restrictions. We expect to resume receiving distributions from all three of these projects in 2011. See the "Project-level debt" section of "Liquidity and Capital Resources" on page 64 for additional details.

Non-cash gains and losses on derivatives instruments

        In the ordinary course of our business, we execute natural gas swap contracts to manage our exposure to fluctuations in commodity prices, forward foreign currency contracts to manage our exposure to fluctuations in foreign exchange rates and interest rate swaps to manage our exposure to changes in interest rates on variable rate project-level debt. Most of these contracts are recorded at fair value with changes in fair value recorded in earnings, resulting in significant volatility in our income that does not significantly affect current period cash flows or the underlying risk management purpose of the derivative instruments. See "Quantitative and Qualitative Disclosures About Market Risk" on page 69 for additional details about our derivative instruments.

Interest expense and other costs associated with debt

        Interest expense relates to both non-recourse project-level debt and corporate-level debt. In addition, in connection with our common share conversion transaction, we recorded $16.2 million of charges to interest expense associated with the costs of the conversion and the write-off of unamortized debt issuance costs associated with the subordinated notes that were retired. The conversion transaction resulted in Cdn$348 million of subordinated notes bearing interest at 11% being converted to equity and, as a result, we expect a significant decrease in our interest expense beginning in 2010.

        Our convertible debentures are denominated in Canadian dollars and, prior to our common share conversion transaction, the outstanding subordinated notes were also denominated in Canadian dollars. These debt instruments are revalued at each balance sheet date based on the U.S. dollar to Canadian dollar foreign exchange rate at the balance sheet date, with changes in the value of the debt recorded in the consolidated statement of operations. The U.S. dollar to Canadian dollar foreign exchange rate has been volatile in recent years, which in turn creates volatility in our results due to the revaluation of our Canadian dollar-denominated debt.

Outlook

        The discussion below expresses management's outlook and expectations with respect to the future performance of our projects and businesses. Please see "Cautionary Statements Regarding Forward-Looking Statements."

        Based on year-to-date results and our projections for the remainder of the year, we expect to receive distributions from our projects in the range of $75 million to $80 million for the full year 2010, an increase from our previous guidance of $70 million to $77 million. This amount represents a decrease of approximately $20 million to $25 million compared to distributions received from the projects in 2009. Changes in project distributions have historically been included in our long-term cash flow projections when we periodically confirm our ability to continue paying dividends to shareholders at current levels. Additional details about these changes are included below.

        At the corporate level, we expect a net cash tax refund in 2010 in the range of $7 million to $9 million, compared to insignificant net cash taxes in 2009. Included in 2010 corporate-level costs will

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be the $5 million payment under the terms of the management agreement termination, compared to a $6 million payment in 2009.

        Looking ahead to 2011, we expect overall levels of cash flow to be improved over projected 2010 levels. Higher distributions from existing projects, initial distributions from our recent investment in Idaho Wind and a slightly lower payment under the management agreement termination are expected to be partially offset by the non-recurrence of the cash tax refunds that are anticipated in 2010. In 2012, still higher 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 one-time items and contract expirations comprise the most significant of the decreases in projected 2010 project distributions compared to 2009.

•

Final insurance proceeds received in 2009 at Orlando due to the unplanned outage in early 2008.



•

Increase in debt principal payments in 2010 for Auburndale project-level debt.



•

Resolution in 2009 of the landowner litigation over right-of-way issues at Path 15, which resulted in $6 million being released from the construction reserve account.



•

Final payment related to Pasco's prior PPA that expired at end of 2008 was received in early 2009.

        In 2009, the following five projects comprised approximately 86% of project distributions received: Auburndale, Lake, Orlando, Path 15 and Pasco. For 2010, we expect these same five projects to contribute approximately 90% of total project distributions.

        In addition to the items above, the following is a summary of other projections for project distributions in 2010 and beyond:

Lake

        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 the expiration of its PPA in July 2013. 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 required at the project. We have taken advantage of the low market price of natural gas to make significant progress in our natural gas hedging strategy. These hedges are summarized below under "Quantitative and Qualitative Disclosures About Market Risk." We intend to continue, when appropriate, to evaluate opportunities to further mitigate natural gas price exposure at Lake in the 2010 to 2013 period, but do not intend to execute additional hedges at Lake for 2010 or 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 to the price of coal consumed by a specific utility plant in Florida, PEF's 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 electricity 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 $27 million to $29 million in 2010. In 2011 and 2012, distributions from Lake are expected to be $30 million to $34 million per year. The increases in 2011 and 2012 are primarily due to higher expected contractual capacity and energy revenue and lower natural gas prices than in 2010.

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Auburndale

        Based on the current forecast, we expect distributions from Auburndale of $25 million to $27 million per year from 2010 through 2013, when the project's current PPA expires. Distributions received from Auburndale in the 2010 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 coal costs 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 gas 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. See "Quantitative and Qualitative Disclosures About Market Risk" for additional details about hedge contracts executed as of August 9, 2010. The 2010 and 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 the 2012 to 2013 period.

Chambers

        As expected, we have reported a significant decrease in cash flow at the Chambers project in 2009 due to a planned major maintenance outage, changes in market power prices and expected sales volumes and the expense associated with regional carbon allowance purchases.

        As previously reported, the reduced cash flows resulted in the project not meeting cash flow coverage ratio tests in its non-recourse debt, so we received no distributions from Chambers in 2009 and do not expect to receive distributions from Chambers in 2010. Based on our current projections, we expect to resume receiving distributions from the project in 2011 based on meeting the required debt service coverage ratios.

Results of Operations

        The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2009 and the six months ended June 30, 2010 and 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

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Consolidated Overview

        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.

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        Project income is the primary GAAP measure of our operating results and is discussed in "Project Income" 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 $66.3 million, $91.0 million and $58.5 million for the years ended December 31, 2009, 2008 and 2007, respectively. Cash available for distribution was $25.3 million and $ 39.3 million for the six months ended June 30, 2010 and 2009, respectively. See "Cash Available for Distribution" on page 61 for additional information.

        Income (loss) from operations before income taxes for the years ended December 31, 2009, 2008 and 2007 was $(54.2) million, $34.5 million and $(13.5) million, respectively. Income (loss) from operations before income taxes for the six months ended June 30, 2010 and 2009 was $3.7 million and $(9.1) million, respectively. See "Project Income" below for additional information.

        Income tax benefit was $15.7 million for the year ended December 31, 2009 compared to an income tax benefit of $13.6 million for the year ended December 31, 2008 and an income tax expense of $17.1 million for the year ended December 31, 2007. Income tax expense was $8.5 million for the six months ended June 30, 2010 compared to an income tax benefit of $2.6 million for the six months ended June 30, 2009. Our 2009 effective tax rate was 29 percent compared to negative 39 percent in 2008 and negative 127 percent in 2007. Our effective tax rate for the year ended December 31, 2009 was impacted by the recognition of a future tax benefit for net operating loss carryforwards in Canada due to an anticipated increase in Canadian taxable income in future years. Our effective tax rate for the year ended December 31, 2008 resulted primarily from the decrease in valuation allowance attributable to the increase in the deferred tax liability associated with unrealized foreign exchange gains and the effect of other permanent differences. Our effective tax rate for the year ended December 31, 2007 was impacted by the increase in valuation allowance attributable to an increase in net operating loss carryforwards in Canada partially offset by branch profits taxes on current year earnings, the impact of foreign earnings subject to tax at lower rates and the effect of other permanent differences. Our effective tax rate for the six months ended June 30, 2010 was impacted by a $2.0 million increase in the valuation allowance, a $3.3 million permanent difference related to the estimated percentage ownership at Selkirk based on the priority distribution computation, $0.5 million for dividend withholding taxes and $1.2 million of various other permanent differences.

Six months ended June 30, 2010 compared with six months ended June 30, 2009

Project Income

Auburndale Segment

        Project income (loss) for our Auburndale segment decreased $3.2 million to $4.2 million in the six-month period ended June 30, 2010 from $7.4 million in the comparable 2009 period. The decrease in project income for the six months ended June 30, 2010 is primarily attributable to the $4.8 million 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 the changes in market prices of natural gas. See "Quantitative and Qualitative Disclosures About Market Risk" below for additional details about our derivative instruments and other financial instruments. In addition, operations and maintenance costs were lower at Auburndale in the 2010 period due to timing.

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Lake Segment

        Project income for our Lake segment decreased $6.1 million to $3.9 million in the six-month period ended June 30, 2010 from $10.0 million in the comparable 2009 period. The decrease is primarily attributable to 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 the changes in market prices of natural gas. See "Quantitative and Qualitative Disclosures About Market Risk" below for additional details about our derivative instruments and other financial instruments.

Pasco Segment

        Project income for our Pasco segment decreased $0.5 million to $0.9 million in the six-month period ended June 30, 2010 from $1.4 million in the comparable 2009 period. The decrease in project income at Pasco is attributable to the timing of operation and maintenance costs during the first quarter of 2009.

Path 15 Segment

        Project income for our Path 15 segment decreased $0.6 million to $3.7 million in the six-month period ended June 30, 2010 from $4.3 million in the comparable 2009 period. The decrease in project income at Path 15 is attributable to a non-recurring gain in prior year related to the settlement of disputes with landowners over right-of-way issues.

Chambers Segment

        Project income for our Chambers segment, which is recorded under the equity method of accounting, increased $4.7 million to $5.1 million in the six-month period ended June 30, 2010 from $0.4 million in the comparable 2009 period. The increase in project income at Chambers is primarily attributable to the non-recurrence of the planned major maintenance outage during the second quarter of 2009.

Other Project Assets Segment

        Project income for our Other Project Assets segment decreased $0.9 million, to $1.6 million for the six months ended June 30, 2010 compared to a $2.5 million income in the comparable 2009 period. While the overall change in project income for the segment was not significant, the largest components of the change are as follows:

•

the absence of revenue at Rumford in 2010 as the contract that provided substantially all of the project's cash flow expired in the fourth quarter 2009; and



•

combined losses in the 2009 period of $1.6 million at the Mid-Georgia and Stockton projects, which were sold in the fourth quarter of 2009.

Administrative and Other Expenses (Income)

        Management fees and administration increased $2.4 million to $7.9 million for the six months ended June 30, 2010 from $5.5 million in the comparable period in 2009. The increase is primarily attributable to higher employee share-based compensation plan expense in 2010. The expense associated with the plan varies, in part, with the market price of our common shares, which increased significantly during the first half of 2010 compared to the first half of 2009, resulting in higher expense in the 2010 period. In addition, we incurred expenses associated with our initial NYSE listing completed in July 2010 as well as in increase in business development costs during 2010.

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        Interest expense at the corporate level in 2010 primarily relates to our convertible debentures. Interest expense decreased $14.9 million to $5.3 million in 2010 from $20.2 million in 2009. This decrease is primarily due to the extinguishment of the subordinated notes that were outstanding during 2009. In November 2009 we completed our common share conversion, which resulted in the extinguishment of Cdn$348 million principal value of 11% subordinated notes due 2016 that previously formed a part of each IPS.

        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 and, through 2009, our subordinated notes. 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). Foreign exchange loss decreased $7.1 million to a $2.4 million loss in 2010 compared to a $9.5 million loss in 2009. The U.S. dollar to Canadian dollar exchange rate increased by 1.3% during the six months ended June 30, 2010. During the six months ended June 30, 2009, the rate decreased by 4.7%. See "Quantitative and Qualitative Disclosures About Market Risk" below for additional details about our management of foreign currency risk and the components of the foreign exchange loss (gain) recognized during the six months ended June 30, 2010 compared to the foreign exchange loss (gain) in the comparable period of 2009.

Year ended December 31, 2009 vs. Year Ended December 31, 2008

Project Income

Auburndale Segment

        Project income for our Auburndale segment increased $8.4 million to $10.5 million in 2009 from $2.1 million in 2008. The increase in project income for the twelve months ended December 31, 2009 was attributable to the fact that 2009 was the first full year of ownership of the project. The Auburndale project was acquired in November 2008.

Lake Segment

        Project income for our Lake segment decreased $11.5 million, or 53%, to $10.2 million in 2009 from $21.7 million in 2008. The decrease was primarily attributable to higher fuel expense at Lake due to the expiration of its natural gas supply agreement as of June 30, 2009. A new gas supply agreement at higher prices was effective for the second half of 2009. In addition, non-cash losses associated with natural gas swaps were recorded in the change in fair value of derivative instruments during 2009 of $5.1 million. These swaps were executed to financially hedge the project's exposure to the changes in market prices of natural gas. See "Quantitative and Qualitative Disclosures About Market Risk" below for additional details about our derivative instruments and other financial instruments.

Pasco Segment

        Project income for our Pasco segment decreased $6.1 million, or 95%, to $0.3 million in 2009 from $6.4 million in 2008. The decrease in project income at Pasco was attributable to lower revenues of $47.5 million from the project's new ten-year tolling agreement effective January 1, 2009, which provides for lower rates than the power purchase agreement that expired December 31, 2008, partially offset by lower fuel expense of $26.7 million, since the new agreement requires the utility to provide the natural gas needed to generate electricity at the plant. In addition, depreciation expense decreased by $8.2 million due to the full amortization of the intangible asset associated with the project's PPA that expired on December 31, 2008. The Pasco project also recorded a $3.4 million charge in change in fair value of derivative instruments in 2008 associated with natural gas swaps that terminated at the end of 2008.

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Path 15 Segment

        Project income at Path 15 for the year ended December 31, 2009 did not change significantly from 2008.

Chambers Segment

        Project income for our Chambers segment, which is recorded under the equity method of accounting, decreased $9.7 million, or 59%, to $6.6 million in 2009 from $16.3 million in 2008 as a result of $9.4 million lower gross margin due to lower electricity sales volumes and prices throughout 2009 and a $4.6 million increase in operation and maintenance costs from a planned major maintenance outage in the second quarter of 2009. In addition, non-cash gains of $2.6 million associated with interest swaps were recorded in the change in fair value of derivative instruments during 2009 compared to $4.3 million of losses in 2008.

Other Project Assets Segment

        Project income (loss) for our Other Project Assets segment increased $26.5 million to $13.3 million in 2009 compared to a $(13.2) million loss in 2008, primarily due to the following:

•

the gain on the sale of Mid-Georgia of $15.8 million in 2009;



•

an impairment charge of $18.5 million at Stockton in 2008;



•

the absence of revenue at Onondaga in 2009 as the contract that provided substantially all of the project's cash flow expired in the second quarter 2008;



•

reduced expense at Selkirk in 2009 associated with the change in fair value of derivative instruments; and



•

an impairment of our equity investment in Rumford of $5.5 million in 2009.

Administrative and Other Expenses (Income)

        Management fees and administration expenses includes the costs of operating as a public company, as well as the fees and costs associated with our management by Atlantic Power Management, LLC (the "Manager"). Effective December 31, 2009, the Manager no longer provides management and administrative services for our company. The Manager is indirectly owned by the ArcLight Funds and received compensation in the form of an annual base fee that was indexed to inflation and an incentive fee that was equal to 25% of the cash distributions to shareholders in excess of Cdn$1.00 per year per IPS. We also reimbursed the Manager for reasonable costs incurred to manage our company. Management fees and administration increased $16 million, or 160%, to $26 million in 2009 from $10.0 million in 2008. The increase is primarily attributable to a $14.1 million charge associated with the termination of the management agreements at the end of 2009. In addition, employee and director share-based compensation plan expense increased in 2009. The expense associated with these plans varies, in part, with the market price of our common shares, which increased significantly during 2009 compared to a decrease during the twelve months of 2008, resulting in higher expense in the 2009 period.

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        Interest expense primarily relates to required interest costs associated with the subordinated notes and the debentures. Interest expense increased $12.4 million, or 29%, to $55.7 million in 2009 from $43.3 million in 2008. This increase is primarily due to the write off of unamortized subordinated note deferred finance costs of $7.5 million, the write off of the unamortized subordinated note premium of $0.9 million and transaction costs of $4.7 million upon closing of our conversion to a common share structure. A charge of $3.1 million was also recorded when we redeemed the remaining subordinated notes in December 2009. This charge was comprised of a premium paid on the redemption of $1.9 million and the write-off of unamortized subordinated note deferred finance costs of $1.2 million. In addition, there were amounts outstanding on our revolving credit facility for a portion of the year ended December 31, 2009 related to the temporary financing of the acquisition of the Auburndale project in late 2008.

        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 subordinated notes and debentures. In addition, unrealized and realized gains and losses on our forward contracts for the purchase of Canadian dollars to satisfy these obligations are included in foreign exchange loss (gain). Foreign exchange loss (gain) increased $67.7 million to $20.5 million loss in 2009 compared to a $(47.2 million) gain in 2008. The U.S. dollar to Canadian dollar exchange rate decreased by 15.9% during the year ended December 31, 2009. During the year ended December 31, 2008, the rate increased by 18.6%. See "Quantitative and Qualitative Disclosures About Market Risk" below for additional details about our management of foreign currency risk and the components of the foreign exchange loss (gain) recognized during the year ended December 31, 2009 compared to the foreign exchange loss (gain) in 2008.

Year Ended December 31, 2008 vs. December 31, 2007

Project Income

Auburndale Segment

        The Auburndale project was acquired in November 2008 and had no results of operations for the year ended December 31, 2007.

Lake Segment

        Project income for our Lake segment increased $13.5 million, or 164%, to $21.7 million in 2008 from $8.2 million in 2007 primarily due to higher dispatch in 2008, a 5% increase in capacity payments under the PPA and the non-recurrence of costs associated with a planned outage for a gas turbine upgrade during the fourth quarter of 2007.

Pasco Segment

        Project income for our Pasco segment increased $0.2 million to $6.4 million in 2008 from $6.2 million in 2007 due to an increase in ownership of the project from 50% in 2007 to 100% in 2008, offset by higher fuel costs related to gas swap payments and an overhaul of the steam turbine during the fourth quarter of 2008.

Path 15 Segment

        Project income for our Path 15 segment decreased $4 million, or 34%, to $7.7 million in 2008 from $11.7 million in 2007 as a result of lower revenues associated with the 2008-2010 rate case and a provision for rate case refund.

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Chambers Segment

        Project income for our Chambers segment decreased $0.3 million, or 2%, to $16.3 million in 2008 from $16.6 million in 2007 primarily due to timing differences of coal prices between the PPA and project fuel agreement.

Other Project Assets Segment

        Project income (loss) for our Other Project Assets segment decreased $40.7 million, or 148%, to a $(13.2) million loss in 2008 compared to $27.5 million income in 2007, primarily due to the following:

•

an impairment charge at Stockton in 2008 in the amount of $18.5 million;



•

lower income at Selkirk attributable to a decrease in the fair value of its long-term gas supply agreement, which is recorded as a derivative instrument; and



•

the absence of revenue at Onondaga for the second half of 2008 as the contract that provided substantially all of the project's cash flow expired in June 2008.

Administrative and Other Expenses

        Management fees and administration increased $1.8 million, or 22%, to $10.0 million in 2008 from $8.2 million in 2007. The increase is primarily attributable to costs associated with pursuing acquisitions that were not completed in 2008, as well as personnel additions and expense recognized related to awards under our long-term incentive plan that were granted in March 2008 and March 2007.

        Interest expense decreased $1.0 million, or 2%, to $43.3 million in 2008 from $44.3 million in 2007. Interest expense primarily relates to required interest payments to holders of the subordinated notes and the debentures. In addition, there were amounts outstanding on the revolving credit facility during the first half of 2007 related to the temporary financing of the acquisition of the Path 15 project, as well as amounts outstanding as of December 31, 2008 on the revolving credit facility due to the acquisition of Auburndale.

        Foreign exchange loss (gain) increased $77.3 million to a $(47.2 million) gain in 2008 compared to a $30.1 million loss in 2007. The increase in foreign exchange loss (gain) is due primarily to an increase in the U.S. dollar to Canadian dollar exchange rate of approximately 18.6% during the year ended December 31, 2008. The rate decreased by 17% during the year ended December 31, 2007. See "Quantitative and Qualitative Disclosures About Market Risk" for additional details about our management of foreign currency risk and the components of the foreign exchange gains recognized during the year ended December 31, 2008 compared to the foreign exchange losses in the prior year periods.

Supplementary Non-GAAP Financial Information

        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

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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. 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.

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Project Adjusted EBITDA (in thousands of U.S. dollars)

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Reconciliation of Project Distributions (in thousands of U.S. dollars)
For the six months ended June 30, 2010

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