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



FORM 10-K




ý

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

OR

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                           to                          

Commission file number 001-34691

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

British Columbia, Canada   55-0886410
(State of Incorporation)   (I.R.S. Employer Identification No.)

One Federal St, Floor 30
Boston, MA

 


02110
(Address of Principal Executive Offices)   (Zip Code)

(617) 977-2400
(Registrant's Telephone Number, Including Area Code)

         Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class   Name of Each Exchange on Which Registered
Common Shares, no par value per share, and
the associated Rights to Purchase Common Shares
  The New York Stock Exchange

         Securities registered pursuant to Section 12(g) of the Act: None



         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

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

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

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

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

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

         As of June 30, 2014, the aggregate market value of the voting and nonvoting common equity held by non-affiliates of the registrant was $492.6 million based upon the last reported sale price on the New York Stock Exchange. For purposes of the foregoing calculation only, all directors and executive officers of the registrant have been deemed affiliates.

         As of February 21, 2015, 121,416,459 of the registrant's Common Shares were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

         Portions of the registrant's definitive Proxy Statement for its 2015 Annual Meeting of Shareholders, to be filed not later than 120 days after the end of the registrant's fiscal year, are incorporated by reference into Items 10 through 14 of Part III of this Annual Report on Form 10-K.

   


Table of Contents


TABLE OF CONTENTS

PART I

 

 

   

ITEM 1.

 

BUSINESS

  3

ITEM 1A.

 

RISK FACTORS

  18

ITEM 1B.

 

UNRESOLVED STAFF COMMENTS

  44

ITEM 2.

 

PROPERTIES

  44

ITEM 3.

 

LEGAL PROCEEDINGS

  44

ITEM 4.

 

MINE SAFETY DISCLOSURES

  47

PART II

 

 

 
 

ITEM 5.

 

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

  48

ITEM 6.

 

SELECTED FINANCIAL DATA

  51

ITEM 7.

 

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

  52

ITEM 7A.

 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  93

ITEM 8.

 

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  97

ITEM 9.

 

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

  97

ITEM 9A.

 

CONTROLS AND PROCEDURES

  97

ITEM 9B.

 

OTHER INFORMATION

  98

PART III

 

 

 
 

ITEM 10.

 

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

  99

ITEM 11.

 

EXECUTIVE COMPENSATION

  99

ITEM 12.

 

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

  99

ITEM 13.

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

  99

ITEM 14.

 

PRINCIPAL ACCOUNTING FEES AND SERVICES

  99

PART IV

 

 

 
 

ITEM 15.

 

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

  100

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PART I

        As used herein, 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.


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

    our ability to generate sufficient cash flow to, service our debt obligations or implement our business plan, including financing internal or external growth opportunities, or to pay dividends if and when declared by our board of directors;

    the impact of recent management changes on our ability to execute our business plan;

    the outcome or impact of our business plan, including the objective of enhancing the value of our existing assets through optimization investments and commercial activities, delevering our balance sheet to improve our cost of capital and ability to compete for new investments, utilizing our core competencies to create proprietary investment opportunities, improving our cost structure and reducing overhead;

    our ability to evaluate and/or implement potential options, including asset sales or the contribution of assets to a joint venture in order to raise additional capital for growth and/or debt reduction, and the outcome or impact on our business of any such potential options;

    our ability to access liquidity for the ongoing operation of our business and the execution of our business plan or any potential options, which may involve one or more of the use of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately-placed bank or institutional non-recourse operating level debt;

    our ability to renew or enter into new power purchase agreements on favorable terms or at all after the expiration of our current agreements;

    our ability to meet the financial covenants under our Senior Secured Credit Facilities and other indebtedness;

    expectations regarding maintenance and capital expenditures; and

    the impact of legislative, regulatory, competitive and technological changes.

        Such forward-looking statements reflect our current expectations regarding future events and operating performance and speak only as of the date of this Annual Report on Form 10-K. 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. 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.

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        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. In addition, 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 included in the filings Atlantic Power makes from time to time with the SEC and the risk factors described under "Item 1A. Risk Factors" in this Annual Report on Form 10-K. Our business is both highly competitive and subject to various risks.

        These risks include, without limitation:

    our ability to service our debt obligations or implement our business plan, including financing internal or external growth opportunities or generate sufficient cash flow to pay dividends, if and when declared by our board of directors;

    the impact of recent management changes on our ability to execute our business plan;

    the outcome or impact of our business plan, and our ability to evaluate and/or implement potential options, including asset sales or the contribution of assets to a joint venture in order to raise additional capital for growth or potential debt reduction, and the outcome or impact of any such potential options;

    our ability to access liquidity for the ongoing operation of our business and the execution of our business plan or any potential options, which may involve one or more of the use of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately-placed bank or institutional non-recourse operating level debt;

    the impact of our failure to meet the fixed charge coverage ratio test in the restricted payments covenants of the indenture governing our 9.0% Notes;

    our indebtedness and financing arrangements and the terms, covenants and restrictions included in our Senior Secured Credit Facilities;

    exchange rate fluctuations;

    the impact of downgrades in our credit rating or the credit rating of our outstanding debt securities, and changes in our creditworthiness;

    unstable capital and credit markets;

    the outcome of certain shareholder class action lawsuits;

    the expiration or termination of power purchase agreements and our ability to renew or enter into new power purchase agreements on favorable terms or at all;

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

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

    the dependence of our projects on third-party suppliers;

    projects not operating according to plan;

    the effects of weather, which affects demand for electricity and fuel as well as operating conditions;

    the dependence of our wind power projects on suitable wind and associated conditions and of our hydropower projects on suitable precipitation and associated weather conditions;

    U.S., Canadian and/or global economic conditions and uncertainty;

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    risks beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of war, natural disasters or other catastrophic events;

    the adequacy of our insurance coverage;

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

    the impact of impairment of goodwill or long-lived assets;

    increased competition, including for acquisitions;

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

    transfer restrictions on our equity interests in certain projects;

    risks inherent in the use of derivative instruments;

    labor disruptions;

    the impact of hostile cyber intrusions;

    the impact of our failure to comply with the U.S. Foreign Corrupt Practices Act and/or Canadian Corruption of Foreign Public Officials Act; and

    our ability to retain, motivate and recruit executives and other key employees.

        Material factors or assumptions that were applied in drawing a conclusion or making an estimate set out in the forward-looking information include, without limitation, third-party projections of regional fuel and electric capacity and energy prices based on assumptions about future economic conditions and courses of action, the general conditions of the markets in which the Company operates, revenues, internal and external growth opportunities, the Company's ability to sell assets at favorable prices or at all and general financial market and interest rate conditions. Although the forward-looking statements contained in this Annual Report on Form 10-K are based upon what are believed to be reasonable assumptions, investors cannot be assured that actual results will be consistent with these forward-looking statements, and the differences may be material. Certain statements included in this Annual Report on Form 10-K 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 Annual Report on Form 10-K. These forward-looking statements are made as of the date of this Annual Report on Form 10-K and, except as expressly required by applicable law, we assume no obligation to update or revise them to reflect new events or circumstances.

ITEM 1.    BUSINESS

OVERVIEW

        Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to changes in commodity prices. As of December 31, 2014, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,945 megawatts ("MW") in which our aggregate ownership interest is approximately 2,024 MW. Our current portfolio consists of interests in twenty-eight operational power generation projects across eleven states in the United States and two provinces in Canada. Twenty of our projects are majority-owned subsidiaries.

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        The following charts show, based on generation capacity in MW, the diversification of our portfolio by geography, segment and fuel type:

GRAPHIC

        We sell the majority of the capacity and energy from our power generation projects under PPAs to a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from December 31, 2017 to December 31, 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 to industrial purchasers under steam sales agreements. Sales of electricity are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating.

        The majority of our natural gas, coal and biomass power generation projects have long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the term of the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales agreements provide for the indexing or pass-through of fuel costs to our customers. In cases where there is no pass-through of fuel costs, we often attempt to mitigate the market price risk of changing commodity costs through the use of hedging strategies.

        We directly operate and maintain the majority of our power generation projects. We also partner with recognized leaders in the independent power industry to operate and maintain our other projects, including Colorado Energy Management ("CEM") and Power Plant Management Services ("PPMS"). Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

HISTORY OF OUR COMPANY

        Atlantic Power Corporation is a corporation continued under the laws of British Columbia, Canada, which was incorporated in 2004. We used the proceeds from our initial public offering on the Toronto Stock Exchange ("TSX") in November 2004 to acquire a 58% interest in Atlantic Power Holdings, LLC (now Atlantic Power Holdings, Inc., which we refer to herein as "Atlantic Holdings") from two private equity funds managed by ArcLight Capital Partners, LLC ("ArcLight") and from Caithness Energy, LLC ("Caithness"). Until December 31, 2009, we were externally managed under an agreement with Atlantic Power Management, LLC, an affiliate of ArcLight, when we agreed to pay ArcLight an aggregate of $15 million to terminate its management agreement with us. In connection with the termination of the management agreement, we hired all of the then-current employees of Atlantic Power Management and entered into employment agreements with its three officers.

        At the time of our initial public offering, our publicly traded security was an Income Participating Security ("IPS"), which was comprised of one common share and a subordinated note. In November 2009, our shareholders approved a conversion from the IPS structure to a traditional common share structure in which each IPS was exchanged for one new common share and each old common share

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that did not form a part of an IPS was exchanged for approximately 0.44 of a new common share. Our common shares trade on the TSX under the symbol "ATP". On July 23, 2010, we also began trading on the New York Stock Exchange ("NYSE") under the symbol "AT".

        On November 5, 2011, we directly and indirectly acquired all of the issued and outstanding limited partnership units of Capital Power Income L.P., which was renamed Atlantic Power Limited Partnership on February 1, 2012 (the "Partnership"). The Partnership's portfolio consisted of 19 wholly-owned power generation assets located in both Canada and the United States, a 50.15% interest in a power generation asset in the state of Washington, and a 14.3% common ownership interest in Primary Energy Recycling Holdings, LLC ("PERH") which was later sold in 2012. At the acquisition date, the transaction increased the net generating capacity of our projects by 143% from 871 MW to approximately 2,116 MW.

        On December 31, 2012, we acquired Ridgeline, a wind and solar development company, which added interests in three operating wind projects totaling 150 net MW and strengthened our ability to execute development and construction stage projects.

OUR BUSINESS STRATEGY

        Our corporate strategy is to increase the value of the company through both organic growth and potential acquisitions in North America. We focus on generating stable operating margins via contracted cash flows from our existing assets. We use our depth of asset management experience to enhance the operating, contractual and financial performance of our current portfolio of projects. We also have the experience to finish development, build and/or acquire projects in the electric power industry. Our objectives include enhancing the value of existing assets, delevering our balance sheet to improve both our cost of capital and ability to compete for new investments, and providing a current return to our shareholders.

        Recently, we have been focused on initiatives aimed at, among other things, improving our financial flexibility and addressing our near-term debt maturities. Our first step towards meeting this goal was the execution of the Term Loan Facility during the first quarter of 2014 and the use of the funds therefrom to address debt maturities in 2015, 2016 and 2017 and to reduce the balance of our 2018 debt maturities. The 50% cash sweep and amortization features of the Term Loan Facility are expected to reduce leverage over time. The additional flexibility, liquidity and maturity extension associated with the Revolving Credit Facility is also a meaningful achievement with respect to these goals.

        We have also undertaken efforts to de-lever our balance sheet by buying back certain of our outstanding debt in the open market when we believe it is trading in a range that may not fully reflect its value or it is otherwise desirable to do so based on trading prices. During the fourth quarter of 2014, we announced a Normal Course Issuer Bid ("NCIB") for our convertible debentures. Under the NCIB, we entered into a pre-defined automatic securities purchase plan with our broker in order to facilitate purchases of our convertible debentures. The NCIB commenced on November 11, 2014 and will expire on November 10, 2015 or such earlier date as we complete our purchases pursuant to the NCIB. The actual amount of convertible debentures that may be purchased under the NCIB cannot exceed approximately $31 million and is further limited based on the outstanding principal of the individual outstanding tranches. As of December 31, 2014 we have repurchased and cancelled $3.1 million par value of convertible debentures with $2.4 million in cash on-hand. In January and February 2015, we also repurchased an additional $6.1 million par value of convertible debentures with $4.9 million of cash on-hand and $9.0 million of our senior unsecured notes due 2018.

        Additionally, during the third quarter of 2014, our Board of Directors, together with our management, assessed the best uses of currently anticipated Free Cash Flow in order to further meet our objectives. After taking into consideration all of these objectives, our Board of Directors

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determined to set a dividend level of Cdn$0.12 per share on an annual basis, equivalent to approximately $13 million annually. Dividends to shareholders are paid, if and when declared by, and subject to the discretion of, the Board of Directors. As we execute our business strategy, and consistent with our objectives, our Board of Directors, together with our management, will regularly evaluate what the optimal dividend policy is for the Company going forward.

        We continue to focus on executing our business plan, including the objectives of enhancing the value of our existing assets through discretionary capital investments and commercial activities, delevering our balance sheet to improve our cost of capital and ability to compete for new investments, utilizing our core competencies to create proprietary investment opportunities, improving our cost structure and reducing overhead. In addition, we continue to assess other potential options, including selected asset sales or the contribution of assets to a joint venture if the valuation of a particular asset or assets is compelling, in order to raise additional capital for growth and/or debt reduction. No guarantee can be given as to how such objectives or other potential options may evolve.

Extending PPAs following their expiration

        PPAs in our portfolio have expiration dates ranging from December 31, 2017 to December 31, 2037. We plan for PPA expirations by evaluating various options in the market. New arrangements may involve responses to utility solicitations for capacity and energy, direct negotiations with the original purchasing utility for PPA extensions, "reverse" request for proposals by the projects to likely bilateral counterparties, including traditional PPAs, tolling agreements with creditworthy energy trading firms or the use of derivatives to lock in value. 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 and in some cases, significantly. Our projects may not be able to secure a new agreement and could be exposed to selling power at spot market prices. It is possible that subsequent PPAs or the spot markets may not be available at prices that permit the operation of the project on a profitable basis. See Item 1A. "Risk Factors—Risk Related to Our Business and Our Projects—The expiration or termination of our power purchase agreements could have a material adverse impact on our business, results of operations and financial condition." We do not assume that revenues or operating margins 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.

Organic growth

        We intend to look for opportunities to enhance the operational and financial performance of our projects through:

    achievement of improved operating efficiencies, output, reliability and operation and maintenance costs through the upgrade or enhancement of existing equipment or plant configurations;

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

    to the extent we have sufficient cash flow or are able to obtain financing, the expansion or redevelopment of existing projects and the acquisition of other partners' interests in our existing portfolio.

Acquisition and investment strategy

        We believe that new electricity generation projects will continue to be required in selective markets in the United States and Canada as a result of lower projected reserve margins and the retirement of

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older generation projects due to obsolescence or environmental concerns. In addition, renewable portfolio standards in more than 31 U.S. states as well as renewables initiatives in several Canadian provinces have greatly facilitated attractive PPAs and financial returns for renewable project opportunities. To the extent we pursue acquisitions, we intend to expand our operations by making accretive acquisitions with a focus on power generation facilities in the United States and Canada. We may also work with experienced development companies to acquire additional late stage development projects and there is also a very active secondary market for the purchase and sale of existing projects.

Development and construction

        We have invested and may invest in the future in energy-related projects primarily in the electric power industry, including investments in late stage development projects or companies where the prospects for creating long-term predictable cash flows are attractive. For example, in 2012, Canadian Hills became our first wholly-owned construction project to achieve commercial operations. Canadian Hills is a 300 MW wind farm in the state of Oklahoma that was purchased as a late stage development project from Apex Wind Energy Holdings, LLC ("Apex"). Meadow Creek is a 120 MW wind project in Idaho that our Ridgeline team successfully brought to commercial operations in 2012 and Piedmont, our constructed 53 MW biomass project in Georgia, achieved commercial operations in April 2013.

OUR COMPETITIVE STRENGTHS

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

    Diversified projects.  Our power generation projects have an aggregate gross electric generation capacity of approximately 2,945 MW, and our net ownership interest in these projects is approximately 2,024 MW. These projects are diversified by fuel type, electricity and steam customers, technologies, project operators and geography. The majority are located in California, the U.S. Mid-Atlantic, New York and the provinces of Ontario and British Columbia.

    Experienced management team.  Our management team has a depth of experience in commercial power operations and maintenance, project development, asset management, mergers and acquisitions, capital raising and financial controls.

    Stability of project cash flow.  Many of our power generation projects currently in operation have been in operation for over ten years. Cash flows from each project are generally supported by PPAs with investment-grade utilities and other creditworthy counterparties. We aim to stabilize operating margins through a combination of a project's PPAs, fuel supply agreements and/or commodity hedges.

    Strong in-house operations and asset management teams.  We manage the operations of twenty-one of our power generation projects, which represent 70% of our portfolio's generating capacity. The remaining seven generation projects are operated by third-parties, which are recognized leaders in the independent power business.

ASSET MANAGEMENT

        Our asset management strategy is to optimally manage our physical assets and commercial relationships to increase shareholder value. Our preference is to own the majority of, and operate all of our businesses. We proactively seek scale opportunities and to establish best practices that result in EBITDA and cash flow growth across all of our twenty-eight operating plants. Our asset management group works to ensure that our projects receive appropriate preventative and corrective maintenance and incur capital expenditures, if justified, to provide for their safety, efficiency, availability, flexibility, longevity, and growth in EBITDA contribution. We also proactively look for opportunities to optimize

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power purchase, fuel supply, long-term service and other agreements to deliver strong and predictable financial performance. The teams at each of the businesses have extensive experience in managing, operating and maintaining the assets.

        For operations and maintenance services at the seven projects in our portfolio which we do not operate, we partner with recognized leaders in the independent power business. Examples of our third-party operators include CEM and PPMS, which are experienced, well regarded energy infrastructure management services companies. In addition, employees of Atlantic Power with significant experience managing similar assets are involved in all significant decisions with the objective of proactively identifying value-creating opportunities such as contract renewals or restructurings, asset-level refinancings, add-on acquisitions, divestitures and participation at partnership meetings and calls.

OUR ORGANIZATION AND SEGMENTS

        The following tables outline by segment our portfolio of power generating assets in operation as of February 26, 2015, including our interest in each facility. We believe our 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.

        We have four reportable segments: East, West, Wind and Un-allocated Corporate. We revised our reportable business segments in the fourth quarter of 2013 as a result of significant asset sales and in order to align with changes in management's structure, resource allocation and performance assessment in making decisions regarding our operations. Our financial results for the year ended December 31, 2012 have been presented to reflect these changes in operating segments. These changes reflect our current operating focus. The segment classified as Un-allocated Corporate includes activities that support the executive and administrative offices, capital structure and costs of being a public registrant. These costs are not allocated to the operating segments when determining segment profit or loss.

        The sections below provide descriptions of our projects as they are aligned in our segment reporting structure for financial reporting purposes.

        See Note 22 to the consolidated financial statements for information on revenue from external customers, Project Adjusted EBITDA (a non-GAAP measure), total assets by segment and revenue and total assets by geography.

East Segment

        Our East segment accounted for 55.1%, 55.0% and 62.2% of consolidated revenue in 2014, 2013 and 2012, respectively, and total net generation capacity of 787 MW at December 31, 2014. Independent Electricity System Operator ("IESO") accounted for 25.8% of total consolidated revenues and 46.8% of total revenues from the East segment for the year ended December 31, 2014.

        The table below provides the revenue and project income (loss) for the East segment. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Project Income (Loss) by Segment for additional details on our project income (loss).

        On April 12, 2013 we completed the sale of our Auburndale Power Partners, L.P. ("Auburndale"), Lake CoGen, Ltd. ("Lake") and Pasco CoGen, Ltd. ("Pasco") projects (collectively, the "Florida Projects") and have therefore excluded their revenue and project income (loss) from the table as they are recorded in income (loss) from discontinued operations in the consolidated statements of operations for the years ended December 31, 2013 and 2012. Revenue for the Florida Projects was $62.1 million and $188.0 million for the years ended December 31, 2013 and 2012, respectively. Project

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income (loss) for the Florida Projects was ($1.1) million and $31.8 million for the years ended December 31, 2013 and 2012, respectively.

 
  East Segment  
 
  Revenue
($ in millions)
  Project income (loss)
($ in millions)
 

2014

  $ 313.8   $ 21.8  

2013

    299.1     25.8  

2012

    267.5     (18.1 )

        Set forth below is a list of our East projects in operation:


 
Project
  Location
  Fuel
  Gross
MW

  Economic
Interest

  Net MW
  Primary Electric Purchasers
  Power
Contract
Expiry

  Customer
Credit
Rating
(S&P)(3)


 

Orlando(1)

  Florida   Natural Gas   129   50.00%   65   Progress Energy Florida   December 2023   BBB+

 

Piedmont

  Georgia   Biomass   53   100.00%   53   Georgia Power   December 2032   A

 

Morris

  Illinois   Natural Gas   177   100.00%   120   Merchant   N/A   NR
                   
 

                  57   Equistar Chemicals, LP   November 2023   BBB+

 

Cadillac

  Michigan   Biomass   40   100.00%   40   Consumers Energy   December 2028   BBB

 

Chambers(1)

  New Jersey   Coal   262   40.00%   89   Atlantic City Electric(2)   December 2024   BBB+
                   
 

                  16   DuPont   December 2024   A

 

Kenilworth

  New Jersey   Natural Gas   25   100.00%   25   Merck, & Co., Inc.   September 2018   AA

 

Curtis Palmer(3)

  New York   Hydro   60   100.00%   60   Niagara Mohawk Power Corperation   December 2027   A-

 

Selkirk(1)

  New York   Natural Gas   345   18.50%   64   Merchant   N/A   NR

 

Calstock

  Ontario   Biomass   35   100.00%   35   Independent Electricity System Operator   June 2020   AA-

 

Kapuskasing

  Ontario   Natural Gas   40   100.00%   40   Independent Electricity System Operator   December 2017   AA-

 

Nipigon

  Ontario   Natural Gas   40   100.00%   40   Independent Electricity System Operator   December 2022   AA-

 

North Bay

  Ontario   Natural Gas   40   100.00%   40   Independent Electricity System Operator   December 2017   AA-

 

Tunis(4)

  Ontario   Natural Gas   43   100.00%   43   Independent Electricity System Operator   November 2032   AA-

 

(1)
Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates.

(2)
The base PPA with Atlantic City Electric ("ACE") makes up the majority of the 89 net MW. For sales of energy and capacity not purchased by ACE under the base PPA and sold to the spot market, profits are shared with ACE under a separate power sales agreement.

(3)
The Curtis Palmer PPA expires at the earlier of December 2027 or the provision of 10,000 GWh of generation. From January 6, 1995 through December 31, 2014, the facility has generated 6,404 GWh under its PPA.

(4)
On January 20, 2015, we entered into an agreement with the Ontario Power Authority and its successor, the Independent Electricity System Operator ("IESO"), for the future operations of the Tunis facility. Subject to meeting certain technical modifications to the plant, gas delivery and other requirements, Tunis will operate under a 15-year agreement with the IESO commencing between November 2017 and June 2019. The new contract will require the plant to become fully dispatchable as opposed to its current baseload configuration. As such, Tunis will only provide electricity to the Ontario grid when required, thereby assisting to reduce the incidents of surplus baseload generation in the market. The new agreement provides the Tunis project with a fixed monthly payment which escalates annually according to a pre-defined formula while allowing it to earn additional energy revenues for those periods during which it is called upon to operate.

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West Segment

        Our West segment accounted for 30.8%, 32.1% and 37.0% of consolidated revenue in 2014, 2013 and 2012, respectively and total net generation capacity of 716 MW at December 31, 2014. San Diego Gas & Electric and British Columbia Hydro and Power Authority ("BC Hydro") provided for 15.1% and 9.1% of total consolidated revenues, respectively, and 49.1% and 29.5%, respectively, of total revenues from the West segment for the year ended December 31, 2014.

        The table below provides the revenue and project income for the West segment. See Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations—Project Income (Loss) by Segment for additional details on our project income (loss).

 
  West Segment  
 
  Revenue
($ in millions)
  Project (loss) income
($ in millions)
 

2014

  $ 175.2   $ (51.3 )

2013

    174.7     35.8  

2012

    159.0     5.5  

        On April 30, 2013 we completed the sale of our interest in the Path 15 Transmission Line ("Path 15") and have therefore excluded its revenue and project income from the table as they are recorded in income (loss) from discontinued operations in the consolidated statements of operations for the years ended December 31, 2013 and 2012. Revenue for Path 15 was $9.5 million and $28.7 million for the years ended December 31, 2013 and 2012, respectively. Project income for Path 15 was $2.1 million and $5.1 for the years ended December 31, 2013 and 2012, respectively.

        In March 2014 we completed the sale of our interest in the Greeley project and have therefore excluded its revenue and project income from the table as they are recorded in income (loss) from discontinued operations in the consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012. Revenue for Greeley was $0.0 million, $7.6 million and $10.6 million for the years ended December 31, 2014, 2013 and 2012, respectively. Project (loss) income for Greeley was ($0.1) million, $0.6 million and $1.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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        Set forth below is a list of our West projects in operation:


 
Project
  Location
  Fuel
  Gross
MW

  Economic
Interest

  Net
MW

  Primary Electric Purchasers
  Power
Contract
Expiry

  Customer
Credit
Rating
(S&P)(2)


 

Naval Station

  California   Natural Gas   47   100.00%   47   San Diego Gas & Electric   December 2019   A

 

Naval Training Center

  California   Natural Gas   25   100.00%   25   San Diego Gas & Electric   December 2019   A

 

North Island

  California   Natural Gas   42   100.00%   42   San Diego Gas & Electric   December 2019   A

 

Oxnard

  California   Natural Gas   49   100.00%   49   Southern California Edison   May 2020   BBB+

 

Manchief

  Colorado   Natural Gas   300   100.00%   300   Public Service Company of Colorado   October 2022   A-

 

Frederickson(1)

  Washington   Natural Gas   250   50.15%   50   Benton Co. PUD   August 2022   A+
                   
 

                  45   Grays Harbor PUD   August 2022   A
                   
 

                  30   Franklin Co. PUD   August 2022   A

 

Koma Kulshan(1)

  Washington   Hydro   13   49.80%   6   Puget Sound Energy   December 2037   BBB

 

Mamquam

  British Columbia   Hydro   50   100.00%   50   British Columbia Hydro and Power Authority   September 2027   AAA

 

Moresby Lake

  British Columbia   Hydro   6   100.00%   6   British Columbia Hydro and Power Authority   August 2022   AAA

 

Williams Lake

  British Columbia   Biomass   66   100.00%   66   British Columbia Hydro and Power Authority   March 2018   AAA

 

(1)
Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates.

Wind Segment

        Our Wind segment accounted for 13.9% and 13.0% of consolidated revenue in 2014 and 2013, respectively and total net generation capacity of 521 MW from continuing operations at December 31, 2014. Revenue from the Wind segment was immaterial for 2012. No customer from the Wind segment accounted for greater than 10% of total consolidated revenues in the year ended December 31, 2014, 2013, or 2012.

        The table below provides the revenue and project income (loss) for the Wind segment. See Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations—Project Income (Loss) by Segment for additional details on our project income (loss).

 
  Wind Segment  
 
  Revenue
($ in millions)
  Project (loss) income
($ in millions)
 

2014

  $ 79.3   $ (11.5 )

2013

    70.8     18.6  

2012

    1.9     (7.4 )

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        Set forth below is a list of our Wind projects in operation:


 
Project
  Location
  Type
  MW
  Economic
Interest

  Net MW
  Primary Electric Purchasers
  Power
Contract
Expiry

  Customer
Credit
Rating
(S&P)(5)


 

Goshen North(1)

  Idaho   Wind   125   12.50%     16   Southern California Edison   November 2030   BBB+

 

Idaho Wind(1)

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

 

Meadow Creek

  Idaho   Wind   120   100.00%     120   PacifiCorp   December 2032   A-

 

Rockland Wind Farm

  Idaho   Wind   80   50.00%     40   Idaho Power Co.   December 2036   BBB

 

Canadian Hills

  Oklahoma   Wind   300   99.0%     199   Southwestern Electric Power Company   December 2037   BBB
                     
 

                    48   Oklahoma Municipal Power Authority   December 2037   A
                     
 

                    48   Grand River Dam Authority   December 2032   A+

 

(1)
Unconsolidated entities for which the results of operations are reflected in equity earnings of unconsolidated affiliates.

POWER INDUSTRY OVERVIEW

        Historically, the North American electricity industry was characterized by vertically integrated monopolies. During the late 1980s, several jurisdictions began a process of restructuring by moving away from vertically integrated monopolies toward more competitive market models. Rapid growth in electricity demand, environmental concerns, increasing electricity rates, technological advances and other concerns prompted government policies to encourage the supply of electricity from independent power producers. More recently, the North American electricity industry has become more diversified but faces the challenges of declining reserve margins and uncertainty resulting from environmental regulations.

        According to the North American Electric Reliability Corporation's ("NERC") Long-Term Reliability Assessment, published in November 2014, summer peak demand in the ten-year period from 2015 through 2024 is projected to increase at a compound annual growth rate of approximately 1.1%, while winter peak demand is projected to increase approximately 1.0%, which are the lowest growth rates on record for both seasons. The stagnant demand growth can be attributed to the ongoing instability in projected economic indicators such as employment levels or gross domestic product in the residential, commercial, and industrial sectors. Additionally, energy efficiency and conservation programs in many areas continue to drive lower energy growth.

        Despite low projected demand growth, reserve margins are trending down. According to NERC's assessment, only 99.6 GW of Tier 1 capacity additions are projected over the next decade while 44.6 GW of retirements are projected by 2024. According to NERC, these retirements are largely driven by environmental regulations and incentives at the federal, state and provincial levels and by the impacts of declining fuel prices, particularly for natural gas.

The non-utility power generation industry

        In the independent power generation sector, electricity is generated from a number of energy sources, including natural gas, coal, water, waste products such as biomass (e.g., wood, wood waste, agricultural waste), landfill gas, geothermal, solar and wind. Our 28 power generation projects are non-utility electric generating facilities that operate in the North American electric power generation industry. The electric power industry is one of the largest industries in the United States, generating retail electricity sales of approximately $363 billion in 2012, based on information published by the Energy Information Administration in November 2013, the most recent study available. A growing portion of the power produced in the United States and Canada is generated by non-utility generators.

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According to the Energy Information Administration, independent power producers represented approximately 38% of total net generation in 2013. Independent power producers sell the electricity that they generate to electric utilities and other load-serving entities (such as municipalities and electric cooperatives) by way of bilateral contracts or open power exchanges. The electric utilities and other load-serving entities, in turn, generally sell this electricity to industrial, commercial and residential customers.

COMPETITION

        The power generation industry is characterized by intense competition, and we compete with utilities, industrial companies and other independent power producers. Supply has surpassed short-term demand plus appropriate reserve margins in numerous U.S. and Canadian markets, contributing to reduced capacity and energy prices and increasing competition among generators to obtain power sales agreements. We also compete for acquisition and joint-venture opportunities with numerous private equity, infrastructure and pension funds, Canadian and U.S. independent power firms, utility non-regulated subsidiaries and other strategic and financial players.

INDUSTRY REGULATION

Overview

        Our facilities and operations are subject to laws and regulations that govern, among other things, transactions by and with purchasers of power, including utility companies, the development and construction of generation facilities, the ownership and operations of generation facilities, access to transmission, and the geographical location, zoning, land use and operation aspects of our facilities and properties, including environmental matters.

        In the United States, the power generation and sale aspects of our projects are primarily regulated by the Federal Energy Regulation Commission ("FERC"), although most of our projects benefit from the special provisions accorded to Qualifying Facilities ("QFs") or Exempt Wholesale Generators ("EWGs").

        In Canada, electricity generation is subject primarily to provincial regulation. Our projects in British Columbia are therefore subject to different regulatory regimes from our projects in Ontario.

Regulation—generating projects

    (i)
    United States

        Eighteen of our power generating projects are QFs under the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), and FERC regulations. A QF falls into one or both of two primary classes, both of which would facilitate one of PURPA's goals to more efficiently use fossil fuels to generate electricity than typical utility plants. The first class of QFs includes energy producers that generate power using renewable energy sources such as wind, solar, geothermal, hydro, biomass or waste fuels. The second class of QFs includes cogeneration facilities, which must meet specific fossil fuel efficiency requirements by producing both electricity and steam versus electricity only.

        The generating projects with QF status and which are currently party to a PPA with a utility or have been granted authority to charge market-based rates are exempt from FERC rate-making authority. The FERC has granted seven of the projects the authority to charge market-based rates based primarily on a finding that the projects lack market power. The projects with QF status are also exempt from state regulation respecting the rates of electric utilities and the financial or organizational regulation of electric utilities. However, state regulators review the prudency of utilities entering into PPAs entered into by QFs and the siting of the generation facilities. The majority of our generation is sold by QFs under PPAs that required approval by state authorities.

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        PURPA, as initially implemented by the FERC, generally required that vertically integrated electric utilities purchase power from QFs at their avoided costs. The Energy Policy Act of 2005 (the "EP Act of 2005"), however, established new limits on PURPA's requirement that electric utilities buy electricity from QFs to certain markets that lack competitive characteristics. The projects with EWG status are also exempt from state regulation respecting the rates of electric utilities, and the projects with EWG and QF status are exempt from regulations under PUHCA.

        Notwithstanding their status as QFs and EWGs, our projects remain subject to various aspects of FERC regulation, including those relating to power marketer status and to oversight of mergers, acquisitions and investments relating to utilities under the Federal Power Act, as amended by the EP Act of 2005. All of our projects are also subject to reliability standards developed and enforced by NERC. NERC is a self-regulatory non-governmental organization which has statutory responsibility to regulate bulk power system users, generation and transmission owners and operators through the adoption and enforcement of standards for fair, ethical and efficient practices.

        Pursuant to its authority, NERC has issued, and the FERC has approved, a series of mandatory reliability standards. Users, owners and operators of the bulk power system can be penalized significantly for failing to comply with the FERC-approved reliability standards. We have designated our Manager of Operational and Regulatory Compliance to oversee compliance with liability standards and an outside law firm specializing in this area advises us on FERC and NERC compliance, including annual compliance training for relevant employees.

    (ii)
    British Columbia, Canada

        The vast majority of British Columbia's power is generated or procured by BC Hydro. BC Hydro is one of the largest electric utilities in Canada. BC Hydro is owned by the Province of British Columbia and is regulated by the British Columbia Utilities Commission (the "BCUC"), which is governed by the Utilities Commission Act (British Columbia) and is responsible for the regulation of British Columbia's public energy utilities including publicly owned and investor-owned utilities (i.e., independent power producers).

        BC Hydro is generally required to acquire all new power (beyond what it already generates from existing BC Hydro plants) from independent power producers.

        All contracts for electricity supply, including those between independent power producers and BC Hydro, must be filed with and approved by the BCUC as being "in the public interest." The BCUC may hold a hearing in this regard. Furthermore, the BCUC may impose conditions to be contained in agreements entered into by public utilities for electricity.

        The BCUC has adopted the NERC standards as being applicable to, among others, all generators of electricity in British Columbia, including independent power producers. In addition, the BCUC has adopted a number of other standards, including the Western Electricity Coordinating Council ("WECC") standards. As a practical matter, WECC typically administers standards compliance on the BCUC's behalf.

        The Clean Energy Act, which became law in British Columbia in 2010, sets out British Columbia's energy objectives. This Act states, among other things, that British Columbia aims to accelerate and expand the development of clean and renewable energy sources in British Columbia to, among other things, achieve energy self-sufficiency by 2016, promote economic development and job creation and continue to work toward the reduction of greenhouse gas emissions. This Act also explicitly states that British Columbia will encourage the use of waste heat, biogas and biomass to reduce waste. This Act is consistent with the British Columbia Government Energy Plan, introduced in 2009, which favors clean and renewable energy sources such as hydroelectric, wind and wood waste electricity generation. BC Hydro is required to meet these objectives and submit reports to the BCUC updating on its progress.

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        Other provincial regulators in British Columbia having authority over independent power producers include the British Columbia Safety Authority, the Ministry of Environment and the Integrated Land Management Bureau.

    (iii)
    Ontario, Canada

        In Ontario, the Ontario Energy Board ("OEB") is an administrative tribunal with overall responsibility for the regulation and supervision of the natural gas and electricity industries in Ontario and with the authority to grant or renew, and set the terms for, licenses with respect to electricity generation facilities, including our projects.

        No person is permitted to own or operate large or medium-scale electricity generation facilities in Ontario without a license from the OEB.

        The OEB's general functions include:

    Determination of the rates charged for regulated services in the electricity sector;

    Licensing of market participants;

    Inspections, particularly with respect to compelling production of records and information;

    Market monitoring and reporting, including on anti-competitive practice;

    Consumer advocacy; and

    Enforcement and compliance.

        The OEB has the authority effectively to modify licenses by adopting "codes" that are deemed to form part of the licenses. Furthermore, any violations of the license or other irregularities in the relationship with the OEB can result in fines. While the OEB provides reports to the Ontario Minister of Energy, it generally operates independently from the government. However, the Minister may issue policy directives (with Cabinet approval) concerning general policy and the objectives to be pursued by the OEB, and the OEB is required to implement such policy directives.

        A number of other regulators and quasi-governmental entities play a role in electricity regulation in Ontario, including the IESO, Hydro One, the Electrical Safety Authority ("ESA") and OEFC.

        The IESO is responsible for administering the wholesale electricity market and controlling Ontario's transmission grid. The IESO is a non-profit corporation whose directors are appointed by the government of Ontario. The IESO's "Market Rules" form the regulatory framework for the operation of Ontario's transmission grid and electricity market. The Market Rules require, among other things, that generators meet certain equipment and performance standards and certain system reliability obligations. The IESO may enforce the Market Rules by imposing financial penalties. The IESO may also terminate, suspend or restrict participatory rights.

        In November 2006, the IESO entered into a memorandum of understanding with NERC, in which it recognized NERC as the "electricity reliability organization" in Ontario. In addition, the IESO has also entered into a similar MOU with both the Northeast Power Coordinating Council (the "NPCC") and NERC. IESO is accountable to NERC and NPCC for compliance with NERC and NPCC reliability standards. While IESO may impose Ontario-specific reliability standards, such standards must be consistent with, and at least as stringent as, NERC's and NPCC's standards.

        As of January 1, 2015, the IESO is responsible for procuring new electricity generation. As a result, the IESO enters into electricity generation contracts with electricity generators in Ontario from time to time. Although we are not presently party to any such contracts, we may seek to enter into such contracts if and when the opportunity arises.

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        Most of the operating assets of the entity formerly known as Ontario Hydro were transferred, in or around 1998, to Hydro One, IESO and a third company called Ontario Power Generation Inc. The remaining assets and liabilities, including power contracts, were kept in OEFC. Once all of OEFC's debts (approximately $26.9 billion as of March 2012) have been retired, it will be wound up and its assets and liabilities will be transferred directly to the Government of Ontario.

        The Green Energy Act became law in Ontario in 2009 for renewable electricity generation technologies, including via a feed-in tariff program. This Act states that the Government of Ontario is, among other things, committed to fostering the growth of renewable energy projects, to removing barriers to and promoting opportunities for renewable energy projects and to promoting a green economy. From 2009 to 2013, power purchase contracts in respect of large-scale energy projects were awarded under a feed-in-tariff program. The Government of Ontario has announced that going forward, power purchase contracts for large-scale projects will be awarded through a request for qualifications (RFQ)/request for proposals (RFP) process. No such contracts have been awarded in the past 12 months.

Carbon emissions

        In the United States, during the past several years government action addressing carbon emissions has been focused on the regional and state level. Beginning in 2009, the Regional Greenhouse Gas Initiative ("RGGI") was established by certain Northeast and Mid-Atlantic states as the first cap-and-trade program in the United States for CO2 emissions. CO2 allowances are now a tradable commodity in the RGGI states. The nine states currently participating in RGGI have varied implementation plans and schedules. In February 2013, RGGI released an updated model rule that reduced the regional CO2 budget beginning in 2014, with further reductions each year from 2015 to 2020. The one RGGI state where we have project interests, New York, also provides cost mitigation for independent power projects with certain types of power contracts. California's cap-and-trade program governing greenhouse gas emissions became effective for the electricity sector on January 1, 2013. California, along with British Columbia and Ontario, is part of the Western Climate Initiative, which supports the implementation of state and provincial greenhouse gas emissions trading programs. Other states and regions in the United States have considered similar regulations, and it is possible that federal climate legislation will be established in the future.

        In 2006, the State of California passed legislation initiating two programs to control/reduce the creation of greenhouse gases. The two laws are more commonly known as AB 32 and SB 1368. Under AB 32 (the Global Warming Solutions Act), the California Air Resources Board (the "CARB") is required to adopt a greenhouse gas emissions cap on all major sources (not limited to the electric sector) to reduce state-wide emissions of greenhouse gases to 1990 levels by 2020. Under the CARB regulations that took effect on January 1, 2013, electricity generators and certain other facilities are now subject to an allowance for greenhouse gas emissions, with allowances allocated by both formulas set by the CARB and auctions.

        SB 1368 added the requirement that the California Energy Commission, in consultation with the California Public Utilities Commission (the "CPUC") and the CARB, establish greenhouse gas emission performance standards and implement regulations for PPAs for a term of five or more 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 ("MWh") associated with combined-cycle, gas turbine baseload generation, such as our North Island project.

        At the federal level, President Obama has identified climate change as a major priority. The U.S. Environmental Protection Agency (the "EPA") has taken several recent actions respecting CO2 emissions. The EPA's actions include its December 2009 finding of "endangerment" to public health

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and welfare from greenhouse gases, its issuance in September 2009 of the Final Mandatory Reporting of Greenhouse Gases Rule which required large sources, including power plants, to monitor and report greenhouse gas emissions to the EPA annually, which was required beginning in 2011, and its issuance in May 2010 of its final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which under a phased-in approach 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, in September 2013, the EPA issued a new proposed rule regulating carbon emissions from new electric generating units, and in June 2014, the EPA issued a proposed rule regulating carbon emissions from existing electric generating units, which is referred to as the Clean Power Plan. The EPA is scheduled to issue final rules governing existing, new, modified and reconstructed power plants in summer 2015, with implementation (subject to extension) beginning in summer 2016 with submission of state implementation plans.

        In Canada, British Columbia and Ontario have implemented greenhouse gas reporting regulations and are developing additional programs to address greenhouse gas emissions.

        The Government of British Columbia has enacted a number of significant pieces of climate-action legislation that frame British Columbia's approach to reducing greenhouse gas emissions with the goal of supporting the Province's participation in the emerging low-carbon economy.

        One key piece of legislation is the Greenhouse Gas Reduction Targets Act (British Columbia) ("GGRTA"), which came into force in 2008 and sets legislated targets for the reduction of greenhouse gas emissions in the Province. Using 2007 as a base year, GGRTA (along with related Ministerial Orders) requires that emissions must be reduced by a minimum of 18% by 2016, 33% by 2020 and 80% by 2050. Also required in connection with GGRTA are annual (from 2010 onward) British Columbia Greenhouse Gas Inventory Reports, Community Energy and Emissions Inventory Reports and Carbon Neutral Action Reports, all of which are designed to provide scientific, comparable and consistent reporting of greenhouse gas sources.

        Other related, key pieces of legislation include the Carbon Tax Act (British Columbia) ("CTA") and the Greenhouse Gas Reduction (Cap and Trade) Act ("GGRCTA"). CTA operates to put a price on greenhouse gas emissions, providing an incentive for sustainable choices and practices by producers of greenhouse gases. GGRCTA authorizes the imposition of hard caps on greenhouse gas emissions by providing a statutory basis for establishing a market-based cap and trade framework to reduce greenhouse gas emissions from large emitters operating in the Province. GGRCTA is currently in the process of being brought into full force. British Columbia is the first Canadian province to introduce such legislation.

        Additionally, more than half of the U.S. states and most Canadian provinces have set mandates requiring certain levels of renewable energy production and/or energy efficiency during target timeframes. This includes generation from wind, solar and biomass. In order to meet CO2 reduction goals, changes in the generation fuel mix are forecasted to include a reduction in existing coal resources, higher reliance on natural gas and renewable energy resources and an increase in demand-side resources. Investments in new or upgraded transmission lines will be required to move increasing renewable generation from more remote locations to load centers.

Regulatory and legislative tax incentives

        The U.S. regulatory environment has undergone significant changes in the last several years due to the creation of incentives for the addition of large amounts of new renewable energy generation and, in some cases, transmission. Certain U.S. and Canadian government policies support renewable power generation and other clean infrastructure technologies and enhance the economic feasibility of developing and operating energy projects in the regions in which we operate. The viability of potential future renewable energy projects is largely contingent on public policy mechanisms and favorable

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regulatory incentives, including production and investment tax credits, loan guarantees, accelerated depreciation tax benefits, state renewable portfolio standards, and regional carbon trading plans. For example, the U.S. Tax Increase Prevention Act of 2014 extended production tax credits and investment tax credits for certain projects that start construction prior to January 1, 2015 and extended bonus depreciation for projects that are placed in service prior to January 1, 2015. However, the tax credits have not been extended past these dates. The EP Act of 2005 also provides incentives for various forms of electric generation technologies. Governments from time to time may renew their policies that support renewable energy and consider actions to make the policies less conducive to the development and operation of renewable energy facilities.

EMPLOYEES

        As of February 21, 2015, we had 316 employees, 212 in the United States and 104 in Canada. Of our Canadian employees, 64 are covered by two collective bargaining agreements. During 2014, we did not experience any labor stoppages or labor disputes at any of our facilities.

AVAILABLE INFORMATION

        We make available, free of charge, on our website, www.atlanticpower.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Additionally, we make available on our website, our Canadian securities filings. The public may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. We are not a foreign private issuer, as defined in Rule 3b-4 under the Exchange Act.

        Information contained on our website or that can be accessed through our website is not incorporated into and does not constitute a part of this Annual Report on Form 10-K. We have included our website address only as an inactive textual reference and do not intend it to be an active link to our website.

ITEM 1A.    RISK FACTORS

        This section highlights specific risks that could affect our Company. You should carefully consider each of the following risks and all of the other information set forth in this Annual Report on Form 10-K. Based on the information currently known to us, we believe the following information identifies the most significant risk factors affecting our Company. However, the risks and uncertainties described below are not the only ones related to our business and are not necessarily listed in the order of their importance. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business.

        If any of the following risks and uncertainties develops into actual events or if the circumstances described in the risks and uncertainties occur or continue to occur, these events or circumstances could have a material adverse effect on our business, results of operations or financial condition. These events could also have a negative effect on the trading price of our securities.

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Risks Related to Our Structure

We may not generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities, or to pay dividends, if and when declared by our board of directors

        We continue to focus on executing our business plan, including the objectives of enhancing the value of our existing assets through discretionary capital investments and commercial activities, delevering our balance sheet to improve our cost of capital and ability to compete for new investments, utilizing our core competencies to create proprietary investment opportunities, improving our cost structure and reducing overhead. In addition, we continue to assess other potential options, including selected asset sales or the contribution of assets to a joint venture if the valuation of such assets is compelling, in order to raise additional capital for growth and/or debt reduction. However, we may not generate sufficient cash flow to service our debt obligations or implement our business plan, including financing internal or external growth opportunities, or to pay dividends, if and when declared by our board of directors.

        Our ability to make required payments under our outstanding indebtedness, including pursuant to the mandatory amortization feature of the Senior Secured Credit Facilities (as defined herein), as well as the 50% cash sweep, or to prepay or redeem any such indebtedness, will depend on our financial and operating performance, including our ability to generate cash flow from operations in the future. As a result, we may be required to refinance such indebtedness and/or obtain third-party financing in order to repay, redeem or refinance such indebtedness when it comes due. In particular, the Cdn$67.3 million aggregate principal amount of our 6.25% convertible debentures is due March 2017, the Cdn$79.7 million aggregate principal amount of our 5.60% convertible unsecured subordinated debentures is due June 2017, the $310.9 million aggregate principal amount of our 9.0% notes (the "9.0% Notes") is due November 2018, the $128.2 million aggregate principal amount of our 5.75% convertible unsecured subordinated debentures is due March 2019 and the Cdn$99.4 million aggregate principal amount of our 6.00% convertible unsecured subordinated debentures is due December 2019. There can be no assurance that our business will generate sufficient cash flow from operations or that future borrowings or refinancing opportunities will be available to us at an acceptable cost, in amounts sufficient, or at all, to enable us to service our debt obligations or to repay or redeem any such indebtedness at maturity, particularly because of our high levels of debt and the debt incurrence restrictions imposed by the various agreements governing our indebtedness. Steps taken to refinance our indebtedness or obtain other third-party financing, if any, may not be successful and may not permit us to meet our scheduled debt service obligations, which could have a material adverse effect on our liquidity and financial condition.

        In addition, a payout of a significant portion of our cash flow to service our debt, including pursuant to the mandatory amortization feature of the Senior Secured Credit Facilities, as well as the 50% cash sweep, or through any dividends, may result in us not retaining a sufficient amount of cash to finance growth and reinvestment opportunities, including through the acquisition of additional projects, to the extent any such acquisitions are otherwise available to us. As a result, we may have to forego growth and reinvestment opportunities that would otherwise be desirable, if we do not find alternative sources of financing for such opportunities or modify our dividend policy to make cash available to us. In addition, even if we are able to find alternative sources of financing for such opportunities, we may be precluded from pursuing an otherwise attractive acquisition or investment if the projected short- term cash flow from the acquisition or investment is not adequate to service the capital raised to fund such acquisition or investment. This could also limit our flexibility in planning for, or reacting to, changes in our business and industry, placing us at a competitive disadvantage compared to our competitors. We cannot provide any assurance that we will be able to identify, finance or close any transactions associated with any such growth or reinvestment opportunities on acceptable terms or timing, or at all.

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        Further, if we are unable to generate sufficient cash flow from operations, our ability to support our liquidity needs, including, but not limited to the payment of any dividends, servicing our debt obligations, including pursuant to the mandatory amortization feature of the Senior Secured Credit Facilities, as well as the 50% cash sweep, or financing internal or external growth opportunities, will depend on our ability to access the credit and capital markets, neither of which may be available to us on acceptable terms, or at all. Currently, because we no longer qualify as a "well-known seasoned issuer," which previously enabled us to, among other things, file automatically effective shelf registration statements, even if we were able to access the capital markets, any attempt to do so could be more expensive or subject to significant delays. Further, access to the credit and capital markets and the cost and availability of credit may be adversely affected by factors beyond our control, including turmoil in the financial services industry, volatility in securities trading markets and general economic conditions. We cannot provide any assurance that we will be able to access the credit or capital markets on acceptable terms or timing, or at all.

We cannot provide any assurance regarding the outcome or impact on our business of any potential options we are considering

        We are continuing to execute our business plan, including the objectives of enhancing the value of our existing assets through discretionary capital investments and commercial activities, delevering our balance sheet to improve our cost of capital and ability to compete for new investments, utilizing our core competencies to create proprietary investment opportunities, improving our cost structure and reducing overhead. In addition, we continue to assess other potential options, including selected asset sales or the contribution of assets to a joint venture if the valuation of a particular asset or assets is compelling in order to raise additional capital for growth and/or debt reduction. No assurance can be given as to how such objectives or other potential options may evolve. The process of reviewing, and potentially executing, any such potential option, may be very costly and time-consuming and may distract our management and otherwise disrupt our operations, or be unsuccessful or yield unexpected results. Some or all of such options could be limited due to transfer restrictions at certain of our projects, potentially trigger change of control provisions, or impose limitations on our ability to use our net operating losses. See "—Risks Related to Our Business and Our Projects—Our equity interests in certain projects may be subject to transfer restrictions." Furthermore, the operation of our business and the execution of our business plan or any potential options (to the extent we decide to implement any such potential options) requires liquidity, which may involve one or more of the use of cash on hand, the issuance of additional corporate debt or equity securities and the incurrence of privately-placed bank or institutional non-recourse operating level debt, although we can provide no assurances regarding the availability of such public or private financing on acceptable terms or at all.

Our recent management changes may impact our business plan

        We have recently undergone significant leadership and executive management changes, including the appointment of a new President and Chief Executive Officer and the departure of our Executive Vice President—Chief Operating Officer. These significant leadership and executive management changes will require transitions in the responsibilities of our existing management team and integration of new management into our existing management team, which could divert the attention of management and our board of directors and result in delay or disruption in the implementation of our business plan. See "—Risks Related to Our Business and Our Projects—Our success depends in part on our ability to retain, motivate and recruit executives and other key employees, and failure to do so could negatively affect us."

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Future dividends are not guaranteed

        Dividends to shareholders are paid at the discretion of our board of directors. Future dividends, if any, will depend on, among other things, the availability of cash flow for dividend payments rather than allocations of cash, the results of operations, working capital requirements, financial condition, restrictive covenants and our ability to satisfy such covenants, business opportunities, provisions of applicable law and other factors that our board of directors may deem relevant. See "—We may not generate sufficient cash flow to pay dividends, if and when declared by our board of directors, service our debt obligations or implement our business plan, including financing internal or external growth opportunities" and "—Our indebtedness and financing arrangements and any failure to comply with the covenants contained therein, could negatively impact our business and our projects and could render us unable to make dividend payments, acquisitions or investments or additional indebtedness, we would otherwise seek to do." Our board of directors may decrease the level of or entirely discontinue payment of dividends. In addition, if and for as long as we are in arrears on the declaration or payment of dividends on the 4.85% Cumulative Redeemable Preferred Shares, Series 1 (the "Series 1 Shares"), the 7.0% Cumulative Rate Reset Preferred Shares, Series 2 (the "Series 2 Shares"), or the Cumulative Floating Rate Preferred Shares, Series 3 (the "Series 3 Shares") of the Partnership, the Partnership will not be permitted to make any distributions on its limited partnership units and we will not pay any dividends on our common shares.

Our Senior Secured Credit Facilities contain certain terms, covenants and restrictions that could impact our available cash flow and restrict our ability to make dividend payments, acquisitions or investments or issue additional indebtedness

        Our Senior Secured Credit Facilities contain certain terms, covenants and restrictions, including a mandatory amortization feature and customary prepayment provisions, including, among others, using 50% of the cash flow of the Partnership and its subsidiaries that remains after the application of funds, in accordance with customary priority, to certain items, including, but not limited to, the operations and maintenance expenses of the Partnership and its subsidiaries, debt service on the Senior Secured Credit Facilities and other specified indebtedness and funding of a debt service reserve account. Such terms, covenants and restrictions may impact our available cash flow and limit our ability to retain sufficient amounts of cash to pay dividends, service our debt obligations or finance internal or external growth opportunities. Our Senior Secured Credit Facilities are a primary source of our liquidity. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources".

        The covenants under the Senior Secured Credit Facilities include a requirement that the Partnership and its subsidiaries, maintain certain leverage and interest coverage ratios (each, as defined in the credit agreement governing the Senior Secured Credit Facilities). The Senior Secured Credit Facilities also contain customary restrictions and limitations on the Partnership's and its subsidiaries' ability to (i) incur additional indebtedness, (ii) grant liens on any of their assets, (iii) change their conduct of business or enter into mergers, consolidations, reorganizations, or certain other corporate transactions, (iv) dispose of assets, (v) modify material contractual obligations, (vi) enter into affiliate transactions, (vii) incur capital expenditures, and (viii) make dividend payments or other distributions, in each case subject to customary carve-outs and exceptions and various thresholds. Any such limitations could restrict our ability to, among other things, make dividend payments, acquisitions or investments or issue additional indebtedness.

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Our indebtedness and financing arrangements, and any failure to comply with the covenants contained therein, could negatively impact our business and our projects and could render us unable to make dividend payments, acquisitions or investments or issue additional indebtedness we otherwise would seek to do

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

    our ability to maintain our dividend payments at the current level if and when declared by our board of directors;

    our ability in the future to obtain additional financing for, among other things, the repayment or redemption of indebtedness and other debt service obligations and investment in internal and external growth opportunities, including the acquisition of additional projects, to the extent any such acquisitions are otherwise available to us, or other purposes;

    our ability to refinance indebtedness on terms acceptable to us or at all;

    our ability to satisfy debt service and other obligations;

    our vulnerability to general adverse industry conditions and economic conditions, including but not limited to adverse changes in foreign exchange rates and commodity prices;

    the availability of cash flow to fund other corporate purposes and grow our business;

    our flexibility in planning for, or reacting to, changes in our business and the industry; and

    placing us at a competitive disadvantage to our competitors that are not as highly leveraged.

        As of December 31, 2014, our consolidated long-term debt represented approximately 68% of our total capitalization, comprised of debt and balance sheet equity.

        The agreements governing our indebtedness limit, but do not prohibit, the incurrence of additional indebtedness. 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, our available cash flow and results of operations could be adversely affected. Changes in interest rates do not have a significant impact on cash payments that are required on our debt instruments as approximately 77% of our debt, including our share of the project-level debt associated with equity investments in affiliates, either bears interest at fixed rates or is financially hedged through the use of interest rate swaps.

        As of December 31, 2014, we had (i) no amount outstanding and $105.7 million issued in letters of credit under our revolving credit facility, (ii) $340.6 million of outstanding convertible debentures, (iii) $319.9 million of unsecured debt, and (iv) $1.1 billion of outstanding senior secured term loan and non-recourse project-level debt.

        As previously disclosed in our Current Report on Form 8-K filed on January 30, 2014 and in our Annual Report on Form 10-K for the year ended December 31, 2013, due to the aggregate impact of the up-front costs resulting from the prepayments on certain of our indebtedness using the proceeds of Term Loan Facility, including certain make-whole payment and charges for unamortized debt discount and fee expenses (which we refer to herein as Prepayment Charges), which were reflected as interest expense in our 2014 first quarter results, we are no longer in compliance with the fixed charge coverage ratio test included in the restricted payments covenant of the indenture governing our 9.0% Notes. The fixed charge coverage ratio must be at least 1.75 to 1.00 and is measured on a rolling four quarter basis, including after giving effect to certain pro forma adjustments. As a consequence, further dividend payments, which are declared and paid at the discretion of our board of directors, in the aggregate cannot exceed the covenant's "basket" provision of the greater of $50 million and 2% of consolidated net assets (as defined in the indenture governing our 9.0% Notes) (approximately $55.8 million at

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December 31, 2014) until such time that we are in compliance with the fixed charge coverage ratio. For the year ended December 31, 2014, dividend payments to our shareholders totaled approximately $32.5 million. The Prepayment Charges would no longer be reflected in the calculation of the fixed charge coverage ratio test after the passage of four additional successive quarters following the quarter in which the Prepayment Charges are incurred (the second quarter of 2015). In addition, any similar prepayment charges incurred in connection with any further debt reduction would also be reflected in the calculation of the fixed charge coverage ratio test on a rolling four quarter basis, beginning with the quarter in which such charges are incurred, as would any associated reduction in interest expense.

        In addition, some of our projects currently have non-recourse term loans 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 our equity interests in the project. The terms of these financing arrangements generally impose many covenants and obligations on the part of the borrower. For example, some of these agreements contain requirements to maintain specified historical, and in some cases prospective debt service coverage ratios before cash may be distributed from the relevant project to us, which would adversely affect our available cash flow. We have, in the past, failed to meet the cash flow coverage ratio tests at certain of our projects, which restricted those projects from making cash distributions. Although all of our projects, with the exception of Piedmont, with non-recourse loans are currently meeting their debt service requirements, we cannot provide any assurances that our projects will generate enough future cash flow to meet any applicable ratio tests in order to be able to make distributions to us. Currently we do not expect our Piedmont project to meet its debt service coverage ratio covenants or to make distributions before 2017 at the earliest, due to continued operational issues that have resulted in higher forecasted maintenance and fuel expenses than initially expected.

        In many cases, an uncured default by any party under key 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 particular project(s) to us and may entitle the lenders to demand repayment and/or enforce their security interests, which could have a material adverse effect on our business, results of operations and financial condition. In addition, failure to comply with the terms, restrictions or obligations of any of our revolving credit facility, convertible debentures or unsecured notes, or the preferred shares of the Partnership, or any other financing arrangements, borrowings or indebtedness, or events of default thereunder, may entitle the lenders to demand repayment, accelerate related debt as well as any other debt to which a cross-default or cross-acceleration provision applies and/or enforce their security interests, which could have a material adverse effect on our business, results of operations and financial condition. In addition, if and for as long as we are in arrears on the declaration or payment of dividends on the Series 1 Shares, the Series 2 Shares or the Series 3 Shares, the Partnership will not make any distributions on its limited partnership units and we will not pay any dividends on our common shares. Additionally, if our lenders under our indebtedness demand payment, we may not, at that time, have sufficient cash and cash flows from operating activities to repay such indebtedness.

        Our failure to refinance or repay any indebtedness when due could constitute a default under such indebtedness and restrict our ability to take certain actions, including paying dividends. In addition, any covenant breach or event of default could harm our credit rating and our ability to obtain additional financing on acceptable terms or at all. The occurrence of any of these events could have a material adverse effect on our business, results of operations, financial condition and liquidity.

Exchange rate volatility may affect our available cash flow and results of operations

        Our payments to shareholders, some of our corporate-level long-term debt and convertible debenture holders are denominated in Canadian dollars. Conversely, some of our projects' revenues

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and expenses are denominated in U.S. dollars. Our 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 statements 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. Although we currently generate revenues in Canadian dollars that exceed our Canadian dollar obligations, future exchange rate volatility or changes to our Canadian dollar revenues could expose us to currency exchange rate risks, against which we do not typically hedge. 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 available cash flow and results of operations.

A downgrade in our credit rating or in the credit rating of our outstanding debt securities, or any deterioration in credit quality could negatively affect our ability to access capital and our ability to hedge, and could trigger termination rights under certain contracts

        A downgrade in our credit rating, a downgrade in the credit rating of our outstanding debt securities, or any deterioration in credit quality could adversely affect our ability to renew existing, or obtain access to new, credit facilities and could increase the cost of such facilities, restrict access to our revolving credit facility and/or trigger termination rights or enhanced disclosure requirements under certain contracts to which we are a party. Any downgrade of our corporate credit rating could also cause counterparties to require us to post letters of credit or other additional collateral, make cash prepayments, or obtain a guarantee agreement, all of which would expose us to additional costs and/or could adversely affect our ability to comply with covenants or other obligations under any of our revolving credit facility, convertible debentures or unsecured notes or any other financing arrangements, borrowings or indebtedness (or could constitute an event of default under any such financing arrangements, borrowings or indebtedness that we may be unable to cure), any of which could have a material adverse effect on our business, results of operations and financial condition.

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

        Changes to our perceived creditworthiness and ability to meet our required covenants on an on-going basis may affect the market price or value and the liquidity of our common shares.

The future issuance of additional common shares could dilute existing shareholders

        From time to time, we may decide to issue additional common shares, redeem outstanding debt for common shares, or repay outstanding principal amounts under existing debt by issuing common shares. We may also, from time to time, decide to issue common shares to meet strategic objectives or in connection with acquiring assets or pursuing broader strategic options. The issuance of additional common shares may have a dilutive effect on shareholders and may adversely impact the price of our common shares.

Volatile capital and credit markets may adversely affect our ability to raise capital on favorable terms and may adversely affect our business, results of operations, financial condition and cash flows

        Disruptions in the capital and credit markets in the United States, Canada or abroad can adversely affect our ability to access the capital markets. Our access to funds under our credit facility is dependent on the ability of the banks that are parties to the facility to meet their funding commitments. Those banks may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. Longer-term disruptions in the capital and credit markets as a result of turmoil in the financial services industry, volatility in securities trading markets and general economic conditions

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could result in an inability to support our liquidity needs, including, but not limited to, the payment of any dividends, service of our debt obligations or financing of internal or external growth opportunities. Currently, because we no longer qualify as a "well-known seasoned issuer," which previously enabled us to, among other things, file automatically effective shelf registration statements, even if we were able to access the capital markets, any attempt to do so could be more expensive or subject to significant delays. See "—We may not generate sufficient cash flow to pay dividends, if and when declared by our board of directors, service our debt obligations or implement our business plan, including financing internal or external growth opportunities."

        Our ability to arrange for financing on a recourse or non-recourse basis and the costs of such capital are dependent on numerous factors, some of which are beyond our control, including:

    general industry, economic and capital market conditions;

    the availability of bank credit;

    investor confidence;

    our financial condition, performance and prospects as well as companies in our industry or similar financial circumstances; and

    changes in tax and securities laws which are conducive to raising capital.

        Should future access to capital not be available to us, either as a result of market conditions or our financial condition, we may not be able to pay dividends, service our debt obligations or finance internal or external growth opportunities, any of which would adversely affect our business, results of operations and financial condition.

We have guaranteed the performance of some of our subsidiaries, which may result in substantial costs in the event of non-performance

        We have issued certain guarantees of the performance of some of our subsidiaries in certain situations, which obligates us to perform in the event that the subsidiaries do not perform. In the event of non-performance by the subsidiaries, we could incur substantial cost to fulfill our obligations under these guarantees. Such performance guarantees could have a material impact on our business, results of operations, financial condition and cash flows. See Notes 11 and 25 to the consolidated financial statements for information on our guarantee obligations.

We have anti-takeover protections that may discourage, delay or prevent a change in control that could benefit our shareholders.

        The BCBCA and our Articles of Continuance contain provisions that could make it more difficult for a third party to acquire us without the consent of our Board of Directors ("Board"). These provisions include:

    As a notice of meeting is required to include certain particulars in the case where a shareholder meeting is being requisitioned by shareholders, our Board must be given advance notice regarding special business that is to be brought by such requisitioning shareholders before the shareholder meeting. For special business, advance notice describing the special business to be discussed at the meeting must be provided and that notice must include any documents to be approved or ratified as an addendum or state that such document will be available for inspection at our records office or other reasonably accessible location;

    Under the BCBCA, shareholders may make proposals for matters to be considered at the annual general meeting of shareholders, provided that such shareholders represent at least 1% of the voting shares of a company or such shares have a fair market value of at least Cdn$2,000.

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      Such proposals must be sent to us in advance of any proposed meeting by delivering a timely written notice in proper form to our registered office. The notice must include information on the business the shareholder intends to bring before the meeting. These provisions could have the effect of delaying until the next shareholder meeting shareholder actions that are favored by the holders of a majority of our outstanding voting securities; and

    Casual vacancies on our Board can be approved prior to the next annual meeting of shareholders by the directors of our Board of Directors.

        If we experience a change of control, unless we elect to make a voluntary prepayment of the term loan under the Senior Secured Credit Facilities, the Partnership will be required to offer each electing lender to prepay such lender's term loans under the Senior Secured Credit Facilities at a price equal to 101% of par. Additionally, a change in control will permit holders of our convertible debentures to require that we purchase the debentures upon the conditions set forth in the respective indenture governing the debentures, which may discourage, delay or prevent a change of control or the acquisition of a substantial block of our common shares. In addition, some of our PPAs or other commercial agreements may contain change of control provisions.

        We have also adopted a shareholder rights plan that may delay or prevent a change of control or the acquisition of a substantial block of our common shares and may make any future unsolicited acquisition attempt more difficult. Under the rights plan:

    The rights will generally become exercisable if a person or group acquires 20% or more of Atlantic Power's outstanding common shares (unless such transaction is a "permitted bid" or a transaction to which the application of the shareholders rights plan has been waived pursuant to the terms of the plan) and thus becomes an "acquiring person." A "permitted bid" is an offer pursuant to which, among other things, such person or group agrees to hold the offer open to all shareholders for a period longer than the statutorily required period;

    Each right, when exercisable, will entitle the holder, other than the "acquiring person," to acquire shares of Atlantic Power's common shares at a significant discount to the then-prevailing market price; and

    As a result, the rights plan may cause substantial dilution to a person or group that becomes an "acquiring person" and may discourage or delay a merger or acquisition that shareholders may consider favorable, including transactions in which shareholders might otherwise receive a premium for their shares.

Our common shares may not continue to be qualified investments under Canadian tax laws

        There can be no assurance that our common shares 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. Canadian tax laws impose penalties for the acquisition or holding of non-qualified or ineligible investments.

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 hold promissory notes from our U.S. holding companies (the "Intercompany Notes") and are required to include, in computing our taxable income, interest on the Intercompany Notes.

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Canadian federal income tax laws and policies could be changed in a manner which adversely affects holders of our common shares

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

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

        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 two of our U.S. holding companies will claim interest deductions with respect to the Intercompany Notes in computing its income for U.S. federal income tax purposes. To the extent any interest expense under the Intercompany Notes is disallowed or is otherwise not deductible, the U.S. federal income tax liability of our U.S. holding companies will increase, which could materially affect the after-tax cash available to distribute to us.

        We received advice from our U.S. tax counsel at the time of the issuance, based on certain representations by us and our U.S. holding companies and determinations made by our independent advisors, as applicable, that the Intercompany Notes should be treated as debt for U.S. federal income tax purposes. However, it is possible that the Internal Revenue Service (the "IRS") could successfully challenge these positions and assert that any of these arrangements should be treated as equity rather than debt for U.S. federal income tax purposes or that the interest on such arrangements is otherwise not deductible. In this case, the otherwise deductible interest would be treated as non-deductible distributions and, in the case of the Intercompany Notes, may be subject to U.S. withholding tax to the extent our respective U.S. holding company had current or accumulated earnings and profits. The determination of debt or equity treatment 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 numerous factors that are intended to identify the nature of the purported creditor's interest in the borrower.

        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 expense on the Intercompany Notes 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 Intercompany Notes 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 the remainder may be subject to U.S. withholding tax to the extent our U.S. holding companies had current or accumulated earnings and profits. We have received advice from independent advisors that the interest rate on these debt instruments was and is, as applicable, commercially reasonable under the circumstances, but the advice is not binding on the IRS.

        Furthermore, our U.S. holding companies' deductions attributable to the interest expense on the Intercompany Notes may be limited by the amount by which each U.S. holding company's net interest expense (the interest paid by each U.S. holding company on all debt, including the Intercompany Notes, 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. In addition, if our U.S. holding companies do not make regular interest payments as required under these debt agreements, other limitations on the deductibility of interest under U.S. federal income tax laws

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could apply to defer and/or eliminate all or a portion of the interest deduction that our U.S. holding companies would otherwise be entitled to.

        Our U.S. holding companies have existing net operating loss carryforwards that we can utilize to offset future taxable income. Some of these loss carryforwards are subject to an annual limitation on their use. While we expect these losses will be available to us as a future benefit, in the event that they are successfully challenged by the IRS or subject to additional future limitations, including as a result of implementation of any of the potential options we are considering, our ability to realize these benefits may be limited. A reduction in our net operating losses, or additional limitations on our ability to use such losses, may result in a material increase in our future income tax liability.

Atlantic Power Preferred Equity Ltd. is subject to Canadian tax, as is Atlantic Power's income from the Partnership

        As a Canadian corporation, we are generally subject to Canadian federal, provincial and other taxes. See "Risks Related to Our Structure—We are subject to Canadian tax." We are required to include in computing our taxable income any income earned by the Partnership. In addition, Atlantic Power Preferred Equity Ltd., a subsidiary of the Partnership, is also a Canadian corporation and is generally subject to Canadian federal, provincial and other taxes. Atlantic Power Preferred Equity Ltd. is liable to pay its applicable Canadian taxes.

We are subject to significant pending civil litigation, which if decided against us, could require us to pay substantial judgments or settlements and incur expenses that could have a material adverse effect on our business, results of operations, financial condition and liquidity.

        In addition to being subject to litigation in the ordinary course of business, we are party to numerous legal proceedings, including securities class actions, from time to time. On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints related to, among other things, claims that we made materially false and misleading statements and omissions regarding the sustainability of our common share dividend that artificially inflated the price of our common shares were filed in the United States District Court for the District of Massachusetts against us and certain of our current and former executive officers. On March 19, 2013 and April 2, 2013, two notices of action relating to purported Canadian securities class action claims were also issued by alleged investors in Atlantic Power common shares, and in one of the actions, holders of Atlantic Power convertible debentures, in the Ontario Superior Court of Justice in the Province of Ontario and on April 8, 2013, a similar claim, issued by alleged investors in Atlantic Power common shares, seeking to initiate a purported class action was filed in the Superior Court of Quebec in the Province of Quebec against us and certain of our current and former executive officers. On May 2, 2013, a statement of claim relating to the April 2, 2013 notice of action was filed with the Ontario Superior Court of Justice in the Province of Ontario. The allegations of these purported class actions are essentially the same as those asserted in the United States.

        These litigations may be time consuming, expensive and distracting from the conduct of our daily business. Due to the nature of these proceedings, the lack of precise damage claims (other than in certain Canadian Actions, as defined in "Item 3. Legal Proceedings") and the type of claims we are subject to, we are unable to determine the ultimate or maximum amount of monetary liability or financial impact, if any, to us in these legal matters, which unless otherwise described in "Item 3. Legal Proceedings", seek damages from the defendants of material or indeterminate amounts. As a result, we are also unable to reasonably estimate the possible loss or range of losses, if any, arising from these litigations. Although we are unable at this time to estimate what our ultimate liability in these matters may be, it is possible that we will be required to pay substantial judgments or settlements and incur expenses that could have a material adverse effect on our business, results of operations, financial condition and liquidity. We intend to defend vigorously against these actions. For additional information with respect to these unresolved matters, see "Item 3. Legal Proceedings".

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Risks Related to Our Business and Our Projects

The expiration or termination of our power purchase agreements could have a material adverse impact on our business, results of operations and financial condition

        Power generated by our projects, in most cases, is sold under PPAs that expire at various times. Currently, our PPAs are scheduled to expire between December 31, 2017 and December 31, 2037. See Item 1. Business—Our Organization and Segments for details about our projects' PPAs and related expiration dates. In addition, these PPAs may be subject to termination prior to expiration in certain circumstances, including default by the project. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA on acceptable terms or timing, if at all, the price received by the project for power under subsequent arrangements may be reduced significantly, or there may be a delay in securing a new PPA until a significant time after the expiration of the original PPA at the project. 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 and the value of the project may be impaired such that we would be required to record an impairment loss under applicable accounting rules. See "—Impairment of goodwill or long-lived assets could have a material adverse effect on our business, results of operations and financial condition".

        The loss of significant PPAs, our inability to secure new PPAs on favorable terms or at all, or the breach by the other parties to such contracts that prevents us from fulfilling our obligations thereunder, could have a material adverse impact on our business, results of operations and financial condition.

Our projects depend on their electricity and thermal energy customers and there is no assurance that these customers will perform their obligations or make required payments

        Each of our projects relies 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. At times, we rely on a single customer or a limited number of customers to purchase all or a significant portion of a project's output. In 2014, the largest customers of our power generation projects, including projects recorded under the equity method of accounting, are IESO, San Diego Gas & Electric, and BC Hydro which purchase approximately 9.8%, 5.6% and 6.0%, respectively, of the net electric generation capacity of our projects. If a customer stops purchasing output from our power generation projects or purchases less power than anticipated, such customer may be difficult to replace, if at all. Further concentration of our customers would increase our dependence on any one customer. Our cash flows and results of operations, including the amount of cash available to make payments on our indebtedness, are highly dependent upon customers under such agreements fulfilling their contractual obligations. There is no assurance that these customers will perform their contractual obligations or make required payments.

        Further, our customers generally have investment-grade credit ratings, as measured by Standard & Poor's. Customers that have assigned ratings at the top end of the range have, in the opinion of the rating agency, the strongest capability for payment of debt or payment of claims, while customers at the bottom end of the range have the weakest capacity. Agency ratings are subject to change, and there can be no assurance that a ratings agency will continue to rate the customers, and/or maintain their current ratings. A security rating may be subject to revision or withdrawal at any time by the rating agency, and each rating should be evaluated independently of any other rating. We cannot predict the effect that a change in the ratings of the customers will have on their liquidity or their ability to pay their debts or other obligations.

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Certain of our projects are exposed to fluctuations in the price of electricity, which may have a material adverse effect on the operating margin of these projects and on our business, results of operations and financial condition

        Those of our projects operating without a PPA or with PPAs based on spot market pricing for some or all of their output 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, which may not be favorable. The open market wholesale prices for electricity are very volatile. Long and short-term power prices may fluctuate substantially due to other factors outside of our control, including:

    changes in generation capacity in the electricity markets, including the addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation facilities, expansion or retirement of existing facilities or additional transmission capacity;

    electric supply disruptions, including plant outages and transmission disruptions;

    fuel transportation capacity constraints;

    weather conditions;

    changes in the demand for power or in patterns of power usage;

    development of new fuels and new technologies for the production or storage of power;

    development of new technologies for the production of natural gas;

    availability of competitively priced renewable fuel sources;

    available supplies of natural gas, crude oil and refined products, and coal;

    interest rate and foreign exchange rate fluctuation;

    availability and price of emission credits;

    geopolitical concerns affecting global supply of oil and natural gas;

    general economic conditions which impact energy consumption in areas where we operate; and

    power market, fuel market and environmental regulation and legislation.

        The market price for electricity is affected by changes in demand for electricity. Factors such as economic slowdown, worse than expected economic conditions, milder than normal weather, the growth of energy efficiency and efforts aimed at energy conservation, among others, could reduce energy demand or significantly slow the growth in demand for electricity, thereby reducing the market price for electricity. A reduction in demand could contribute to conditions that no longer support the continued operation of certain power generation projects, which could adversely affect our results of operations through increased depreciation rates, impairment charges and accelerated future decommissioning costs, among others.

        We are also exposed to market power prices at the Selkirk, Morris and Chambers projects. 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. In addition, during periods of low spot electricity prices the utility takes less generation, which negatively affects the project's operating margin. At Morris, approximately 68% of the facility's capacity is currently not contracted. The facility can generate and sell this excess capacity into the grid at market prices. If market prices do not justify the increased generation, the project has no requirement to sell

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any excess capacity. At Selkirk, none of the capacity of the facility is contracted and is therefore sold at market prices or not sold at all if market prices do not support the profitable operation of that portion of the facility. As a result, fluctuations in the price of electricity may have a material adverse effect on the operating margins of these facilities and on our business, results of operations and financial condition.

Our projects depend on third-party suppliers under fuel supply agreements, and 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. We may not be able to renegotiate these agreements or enter into new agreements on similar terms. 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. If our suppliers are unable to perform their contractual obligations or we are unable to renegotiate our fuel supply agreements, we may seek to meet our fuel requirements by purchasing fuel at market prices, exposing us to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price. Changes in market prices for natural gas, biomass, coal and oil may result from the following:

    weather conditions;

    seasonality;

    demand for energy commodities and general economic conditions;

    additional generating capacity;

    disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;

    availability and levels of storage and inventory for fuel stocks;

    natural gas, crude oil, refined products and coal production levels;

    changes in market liquidity;

    governmental regulation and legislation; and

    our creditworthiness and liquidity, and the willingness of fuel suppliers/transporters to do business with us.

        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. The price we can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. To the extent possible, our projects attempt to match fuel cost setting mechanisms in supply agreements to energy payment formulas in the PPA and to provide for indexing or pass-through of fuel costs to customers. In cases where there is no pass-through of fuel costs, we often attempt to mitigate the market price risk of changing commodity costs through the use of hedging strategies. To the extent that costs are not matched well to PPA energy payments, pass through of fuel costs is not allowed or hedging strategies are unsuccessful, increases in fuel costs may adversely affect our results of operation. This may have a material adverse effect on our business, results of operations and financial condition. Our energy payments at our Orlando project are subject to fluctuations as the energy payments are

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comprised of a fuel component based on the cost of coal consumed at a nearby coal-fired generating station.

Our projects may not operate as planned

        The ability of our projects to meet availability requirements and generate the required amount of power to be sold to customers under the PPAs are primary determinants of the amount of cash that will be distributed from the projects to us, and that will in turn be available for any dividends paid to our shareholders, as debt service obligations, investments in internal or external growth opportunities or funding of our operations. There is a risk of equipment failure due to wear and tear, more frequent and/or larger than forecasted downtimes for equipment maintenance and repair, unexpected construction delays, latent defect, design error or operator error, or force majeure events, among other things, which could adversely affect revenues and cash flow. Additionally, older equipment, even if maintained in accordance with good practices, is subject to operational failure, including events that are beyond our control, and may require unplanned expenditures to operate efficiently. Unplanned outages of generation facilities, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues or require us to incur significant costs as a result of obtaining replacement power from third parties in the open market to satisfy our obligations.

        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 replacement transformer can be found or manufactured. To the extent that we suffer disruptions of plant availability and power generation due to transformer failures or for any other reason, there could be a material adverse effect on our business, results of operations and financial condition and the amount of available cash flow may be adversely affected.

        We provide letters of credit under our $210 million Revolving Credit Facility for contractual credit support at some of our projects. If the projects fail to perform under the related project-level agreements, the letters of credit could be drawn and we would be required to reimburse our senior lenders for the amounts drawn.

The effects of weather and climate change may adversely impact our business, results of operations and financial condition

        Our operations are affected by weather conditions, which directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues. To the extent that weather is warmer in the summer or colder in the winter than assumed, we may require greater resources to meet our contractual commitments. These conditions, which cannot be accurately predicted, may have an adverse effect on our business, results of operations and financial condition by causing us to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.

        To the extent climate change contributes to the frequency or intensity of weather related events, our operations and planning process could be impacted, which may adversely impact our business, results of operations and financial condition.

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Revenues from windpower projects are highly dependent on suitable wind and associated weather conditions and in the absence of such suitable conditions, our wind energy projects may not meet anticipated production levels, which could adversely affect our forecasted revenues

        We own interests in five windpower projects, which are subject to substantial risks. The energy and revenues generated at a wind energy project are highly dependent on climatic conditions, particularly wind conditions, which are variable and difficult to predict. Turbines will only operate within certain wind speed ranges that vary by turbine model and manufacturer, and there is no assurance that the wind resources at any given project site will fall within such specifications.

        We base our investment decisions with respect to each wind energy project on the findings of wind studies conducted on-site before acquiring or before starting construction. However, actual climatic conditions at a project site, particularly wind conditions, may not conform to the findings of these wind studies, and, therefore, our wind energy projects may not meet anticipated production levels, which could adversely affect our forecasted revenues.

Revenues from hydropower projects are highly dependent on suitable precipitation and associated weather conditions and in the absence of such suitable conditions, our hydropower projects may not meet anticipated production levels, which could adversely affect our forecasted revenues.

        We own interests in four hydropower projects, which are subject to substantial resource risks. The energy and revenues generated at a hydro energy project are highly dependent on climatic conditions, particularly precipitation patterns, which are variable and difficult to predict for any given year. We base our investment decisions with respect to each hydro energy project on the historical stream flow records for the area. However, actual climatic conditions in any given year may not meet the historical averages which would impair our ability to meet anticipated production levels, which could adversely affect our forecasted revenues.

U.S., Canadian and/or global economic conditions and uncertainty could adversely affect our business, results of operations and financial condition

        Our business may be affected by changes in U.S., Canadian and/or global economic conditions, including inflation, deflation, interest rates, availability of capital, consumer spending rates and the effects of governmental initiatives to manage economic conditions. Uncertainty about global economic conditions may cause consumers to alter behaviors that may directly or indirectly reduce energy spending, which could have a material adverse effect on demand for our product. Volatility in the financial markets and the deterioration of national and global economic conditions may have a material adverse effect on our business, results of operations and financial condition.

        Financial markets can also be, and have been in the past, affected by concerns over U.S. fiscal policy, federal deficit and related budget and tax issues. These concerns continue to raise discussions relating to the stability of the long-term sovereign credit rating of the United States. Any actions taken by the U.S. federal government regarding the federal deficit or any action taken or threatened by ratings agencies, could significantly impact the global and U.S. economies and financial markets. Any such economic downturn could have a material adverse effect on our business, results of operations and financial condition.

Risks that are beyond our control, including but not limited to geopolitical crisis, acts of terrorism or related acts of war, natural disasters or other catastrophic events could have a material adverse effect on our business, results of operations, ability to raise capital and financial condition

        Man-made events, such as acts of terror and governmental responses to acts of terror, could adversely affect general economic conditions, which could have a material impact on our business, results of operations and financial condition. Strategic targets, such as energy-related facilities, may be

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at greater risk of future terrorist activities than other domestic targets. Our projects may be targets of terrorist activities, as well as events occurring in response to or in connection with them, that could cause environmental repercussions and/or result in full or partial disruption of the ability of the projects to generate and/or transmit electricity. Any such environmental repercussions or other disruption could result in a decline in energy consumption and significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, results of operations and financial condition.

        Our projects could also be impacted by natural disasters, such as earthquakes, floods, lightning activity, hurricanes, tropical storms, winter storms, tornadoes, wind, seismic activity, more frequent and more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena. Severe weather or other natural disasters could be destructive or otherwise disrupt our operations or compromise the physical or cyber security of our facilities, which could result in increased costs and could adversely affect our ability to manage our business effectively. We maintain standard insurance against catastrophic losses, which are subject to deductibles, limits and exclusions; however, our insurance coverage may not be sufficient to cover all of our losses. Additionally, future significant weather-related events, natural disasters and other similar events that have an adverse effect on the economy could have a material adverse effect on our business, results of operations, ability to raise capital and financial condition.

Our business faces significant operating hazards, natural disaster risks and other hazards such as fire and explosions and insurance may not be sufficient to cover all losses

        Our business involves significant operating hazards related to the generation of electricity, including hazards related to acquiring, transporting and unloading fuel, operating large pieces of rotating equipment, structural collapse, machinery failure, and delivering electricity to transmission and distribution systems. In addition, we are exposed to natural disaster risks and other hazards such as fire and explosions. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, disruption of communication systems and technology, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being subject to various litigation matters, including regulatory and administrative proceedings, asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. While we believe that the projects maintain an amount of insurance coverage that is adequate and 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 or insured, 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, results of operations, financial condition and future prospects.

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

        Our business is subject to extensive Canadian and U.S. federal, state, provincial and local laws and regulations. Compliance with the requirements under these various regimes may cause us to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.

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        Generally, in the United States, our projects are subject to regulation by the FERC regarding the terms and conditions of wholesale service and rates, as well as by state regulators regarding the prudency of utilities entering into PPAs entered into by QF projects and the siting of the generation facilities. The majority of our generation is sold by QF projects under PPAs that required approval by state authorities.

        The EP Act of 2005 also limited the requirement that electric utilities buy electricity from QFs in certain markets that have certain competitive characteristics, potentially making it more difficult for our current and future projects to negotiate favorable PPAs with these utilities.

        If any project were to lose its status as a QF, it would lose its ability to make sales to utilities on favorable terms. Such project may no longer be entitled to exemption from provisions of PUHCA of 2005 or from certain provisions of the Federal Power Act and state law and regulations. Loss of QF status could also trigger defaults under covenants to maintain that status in the PPAs 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. In such event, our business, results of operations and financial condition could be negatively impacted.

        Notwithstanding their status as QFs and EWGs, our facilities remain subject to numerous FERC regulations, including those relating to power marketer status, approval of mergers, acquisitions and investments relating to utilities, and mandatory reliability rules and regulations delegated to NERC. Any violation of these rules and regulations could subject us to significant fines and penalties and negatively impact our business, results of operations and financial condition.

        The EP Act of 2005 and other federal and state programs also may provide incentives for various forms of electric generation technologies, which may subsidize our competitors. The U.S. regulatory environment has undergone significant changes in the last several years due to state and federal policies affecting wholesale competition and the creation of incentives for the addition of large amounts of new renewable energy generation and, in some cases, transmission. These changes are ongoing and we cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on our business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism as well as proposals to re-regulate the markets. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, or new law or other future regulatory developments are introduced, our business, results of operations and financial condition could be negatively impacted.

        Generally, in Canada, our projects are subject to energy regulation primarily by the relevant provincial authorities. In addition, our projects are subject to Canada's corporate, commercial and other laws of general application to businesses. 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.

        Additionally, public policy mechanisms and favorable regulatory incentives in the United States and Canada, including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, renewable portfolio standards, and carbon trading plans, impact the viability of our renewable energy projects. As a result of budgetary constraints, political factors or otherwise, governments from time to time may review their policies that support renewable energy and consider actions to make the policies less conducive to the development and operation of renewable energy facilities. In the U.S., the federal production and investment tax credits were allowed to expire at the end of 2013, and although partially extended in December 2014 to projects that are under construction

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prior to January 1, 2015, their continued availability is uncertain. Any reductions to, or the elimination of, governmental incentives that support renewable energy, or the imposition of additional taxes or other assessments on renewable energy, could result in a material adverse effect on our business, results of operations and financial condition.

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

        Risks with respect to the two Canadian provinces where we currently have projects are addressed further below.

    (i)    British Columbia

        The Government of British Columbia has a number of specific statutes and regulations that govern the generation, transmission and distribution of electricity within British Columbia. Our projects in that province are subject to these laws. These statutes can be changed by act of the provincial legislature and the regulations may be changed by the provincial cabinet. Such changes could have a material effect on our projects.

        The Clean Energy Act, which became law in British Columbia in 2010, sets out British Columbia's energy objectives, one of which is the generation of at least 94% of the electricity in British Columbia from clean or renewable resources. BC Hydro is required to submit resource plans outlining how it will meet these objectives and requires the province to be energy self-sufficient by 2016. BC Hydro is generally required to acquire all new power (beyond what it already generates from existing BC Hydro plants) from independent power producers. Two of our three British Columbia projects currently sell all of their electricity to BC Hydro, and the third project sells substantially all of its electricity to BC Hydro. Therefore, changes to BC Hydro's energy procurement policies and financial difficulties of or regulatory intervention in respect of BC Hydro and/or the province's energy objectives could impact the market for electricity generated by our British Columbia projects although BC Hydro is currently limited by regulation to undertaking efficiency improvements at its existing facilities and only undertaking development of new generation facilities/projects with BCUC approval. There is a risk that the regulatory regime could adversely affect the amount of power that BC Hydro purchases from our projects and the competitive environment or the price at which BC Hydro is willing to purchase power from our British Columbia projects

        The Utilities Commission Act governs the BCUC, which is responsible for the regulation of British Columbia's public energy utilities, which include publicly owned and investor-owned utilities (i.e., independent power producers). All contracts for electricity supply, including those between independent power producers and BC Hydro, must be filed with and approved by the BCUC as being "in the public interest." The BCUC may hold a hearing in this regard. Furthermore, the BCUC may impose conditions to be contained in agreements entered into by public utilities for electricity. Consequently, power procurement is controlled by the BCUC and, as a result, our potential contracts with BC Hydro may be subject to terms that adversely affect us.

    (ii)    Ontario

        The government of Ontario has a number of specific statutes and regulations that govern our projects in that province. The statutes can be changed by act of the provincial legislature and the regulations may be changed by the provincial cabinet. Such changes could have a material effect on our projects.

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        In Ontario, the OEB is an administrative tribunal with authority to grant or renew, and set the terms for, licenses with respect to electricity generation facilities, including our projects. No person is permitted to own or operate a large or medium-scale electricity generation facility in Ontario without a license from the OEB. While all of our Ontario projects are currently licensed, the OEB has the authority to effectively modify the licenses by adopting "codes" that are deemed to form part of the licenses. Furthermore, any violations of the license or other irregularities in the relationship with the OEB can result in fines.

        While the OEB provides reports to the Ontario Minister of Energy, it generally operates independently from the government. However, the Minister may issue policy directives (with Cabinet approval) concerning general policy and the objectives to be pursued by the OEB, and the OEB is required to implement such policy directives. Thus, the OEB's regulation of our projects is subject to potential political interference, to a degree.

        A number of other regulators and quasi-governmental entities play a role, including the IESO, Hydro One, the ESA and OEFC. All these agencies may affect our projects.

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

        Many of our operations are subject to the regulations of NERC, a self-regulatory non-governmental organization which has statutory responsibility to regulate bulk power system users and 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 federal 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 or identified through self-certification, compliance audits, spot checking, self-reporting, compliance investigations by NERC (or a regional reliability organization) and the FERC, periodic data submissions, exception reporting, and complaints. The penalty that could 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, which could have a material adverse effect on our business, results of operations and financial condition.

Our projects are subject to significant environmental and other regulations

        Our projects are subject to numerous and significant federal, state, provincial 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. Our facilities could experience incidents, malfunctions or other unplanned events that could result in spills or emissions in excess of permitted levels and result in personal injury, penalties and property damage. 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. We have implemented environmental, health and safety management programs designed to regularly improve environmental, health and safety performance, but there is no guarantee that such programs will fully and effectively eliminate the inherent risk of environmental, health and safety liabilities related to the operation of our projects.

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        Environmental laws and regulations have generally become more stringent over time, and this trend may continue. In the United States, the Clean Air Act and related regulations and programs of the Environmental Protection Agency (the "EPA") extensively regulate the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds by power plants. In July 2011, the EPA issued its final Cross-State Air Pollution Rule ("CSAPR"), which replaces its prior Clean Air Interstate Rule and requires 27 states and the District of Columbia to curb emissions of sulfur dioxide and nitrogen oxides from power plants through participation in a cap and trade system or more aggressive state-by-state emissions limits. In November 2014, the EPA issued a ministerial rule setting a schedule for implementation of the CSAPR beginning in 2015. Other more stringent EPA air emission regulations currently being implemented include the more stringent national ambient air quality standards for sulfur dioxide, issued in June 2010, and for fine particulate matter, issued in December 2012, and the new mercury and air toxics emissions standards for power plants, issued in December 2011. Meeting these new standards, when implemented, may have a material adverse impact on our business, results of operations and financial condition.

        In December 2014, the EPA issued its final regulations governing disposal of coal ash in landfills and impoundments. The final rule affirmed the historic treatment of coal ash as non-hazardous solid waste but establishes new requirements governing structural integrity, groundwater protection, operating criteria, recordkeeping and reporting, and closure for such landfills and impoundments. We are currently assessing the increased compliance obligations and associated costs to our 40% owned coal-fired facility.

        Similar increasingly stringent environmental regulations also apply to our projects in British Columbia and Ontario.

        Significant costs may be incurred 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. Some of our projects' PPAs do not allow for the pass through of emissions allowance or emission reduction capital expenditure costs. 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 and which could have a material adverse effect on our business, results of operations and financial condition.

If additional regulatory requirements are imposed on energy companies mandating limitations on greenhouse gas emissions or requiring efficiency improvements, such requirements may result in compliance costs that alone or in combination could make some of our projects uneconomical to maintain or operate

        The EPA, other regulatory agencies, environmental advocacy groups and other organizations are focusing considerable attention on greenhouse gas emissions from power generation facilities and their

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potential role in climate change. In the United States, President Obama has declared action addressing climate change to be a major priority, and the EPA has taken several recent actions for the regulation of greenhouse gas emissions. See "Item 1. Business—Industry Regulation—Carbon Emissions." We expect that additional EPA regulations, and possibly additional legislation and/or regulation by other regulatory authorities, may be issued, resulting in the imposition of additional limitations on greenhouse gas emissions or requiring efficiency improvements from fossil fuel-fired electric generating units.

        There are also potential impacts on our natural gas businesses as greenhouse gas legislation or regulations may require greenhouse gas emission reductions from the natural gas sector and could affect demand for natural gas. Additionally, greenhouse gas requirements could result in increased demand for energy conservation and renewable products, as well as increase competition surrounding such innovation. Additionally, our reputation could be damaged due to public perception surrounding greenhouse gas emissions at our power generation projects. Any such negative public perception could ultimately result in a decreased demand for electric power generation or distribution. Several regions of the United States and Canada have moved forward with greenhouse gas emission regulation.

        Concerning our projects in British Columbia, regulatory restrictions stemming from the GGRTA and the GGRCTA, and financial commitments arising in connection with the requirements under the CTA, could affect our ability to operate our projects in British Columbia and affect our profitability.

        All of our subject generating facilities have complied on a timely basis with the new EPA and Ontario greenhouse gas reporting requirements. Compliance with greenhouse gas emission reduction requirements may require increasing the energy efficiency of equipment at our natural gas projects, committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting projects and potential replacement with lower emitting projects. The cost of compliance with greenhouse gas emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon capture and storage technology, and the selected compliance alternatives. We cannot estimate the aggregate effect of such requirements on our business, results of operations, financial condition or our customers. However, such expenditures, if material, could make our generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect our business, results of operations and financial condition.

Impairment of goodwill or long-lived assets could have a material adverse effect on our results of operations and financial condition

        As of December 31, 2014, we had $197.2 million of goodwill, which represented approximately 7% of our total assets on our consolidated balance sheets. Goodwill is not amortized, but is evaluated for impairment at least annually or more frequently if an event or change in circumstance occurs that would more likely than not reduce the fair value of a reporting unit below its carrying value. We could be required to, and have in the past, evaluated the potential impairment of goodwill outside of the required annual evaluation process if we experience situations, including but not limited to, sustained declines in market capitalization, deterioration in general economic conditions or our operating or regulatory environment, increased competitive environment, an increase in fuel costs (particularly when we are unable to pass through the impact to customers), negative or declining cash flows, loss of a key contract or customer (particularly when we are unable to replace it on equally favorable terms), divestiture of a significant component of our business or adverse actions or assessments by a regulator. These types of events and the resulting analyses could result in goodwill impairment expense, which could substantially affect our results of operations for those periods. Additionally, goodwill may be

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impaired if any acquisitions we make do not perform as expected. See Note 8 to the consolidated financial statements included in this Annual Report on Form 10-K.

        Long-lived assets are initially recorded at acquisition cost and are amortized or depreciated over their estimated useful lives. Long-lived assets are evaluated for impairment only when impairment indicators are present whereas goodwill is evaluated for impairment on an annual basis or more frequently if potential impairment indicators are present. Otherwise, the recoverability assessment of long-lived assets is similar to the potential impairment evaluation of goodwill particularly as it relates to the identification of potential impairment indicators, and making estimates and assumptions to determine fair value, as described above.

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 uncontracted output. In recent years, there has been increasing competition among generators for PPAs, and this has contributed to a reduction in electricity prices in certain markets where supply has surpassed demand plus appropriate reserve margins.

        Further, changes and developments in technology, including fuel cells, microturbines, solar cells and other emerging technologies related to energy generation, distribution and consumption, may facilitate the entrance of new competitors, increase the supply of electricity, reduce the cost of methods of producing power that we do not currently use or lower the price of or demand for energy. If these technologies became cost competitive, we could face increasing competition and the value of our generating facilities could be reduced.

        In addition, we continue to confront significant competition for acquisition and investment opportunities and, to the extent that any opportunities are identified, we may be unable to effect acquisitions or investments on attractive terms, if at all. Increasing competition among participants in the power generation industry may adversely affect our performance and the performance of our projects. Further, a payout of a significant portion of our cash flow through dividends, and/or to service our debt, may result in us not retaining a sufficient amount of cash to finance acquisition or investment opportunities and make other capital and operating expenditures. See "—Risk Related to Our Structure—We may not generate sufficient cash flow to pay dividends, if and when declared by our board of directors, service our debt obligations or implement our business plan, including financing internal or external growth opportunities."

We have limited control over management decisions at certain projects

        Approximately one third of 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 CEM and PPMS) operate seven of our projects. As such, we must rely on the technical and management expertise of these third-party operators although typically we negotiate to obtain positions 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, our cash flow may be adversely affected. The approval of third-party operators also may be required for us to receive distributions of funds from projects or to transfer our interest in projects. Our inability to control fully certain projects could have an adverse effect on our business, results of operations and financial condition.

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We may face significant competition for acquisitions and may not be able to finance or otherwise pursue, execute or successfully integrate acquisitions or new business initiatives

        To the extent identification of and pursuit of acquisition opportunities forms a part of our strategy, 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 at all, or be sure that such acquisitions, if any, will be successfully integrated into our existing operations. In addition, a payout of a significant portion of our cash flow through dividends, and/or to service our debt obligations, may result in us not retaining a sufficient amount of cash to finance any acquisition or other growth opportunities, to the extent any such acquisition or other opportunities are available to us. As a result, we may have to forego such opportunities, even if they would otherwise be necessary or desirable, if we do not find alternative sources of financing for such opportunities or modify our dividend policy to make cash available to us. In addition, even if we are able to find alternative sources of financing for such opportunities, we may be precluded from pursuing an otherwise attractive acquisition or investment if the projected short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund such acquisition or investment. This could limit our flexibility in planning for, or reacting to, changes in our business and industry, placing us at a competitive disadvantage compared to our competitors.

        Although electricity demand is expected to grow, creating the need for more generation, such growth is expected to occur at a slower rate. The U.S. power industry is continuing to undergo consolidation and may present attractive acquisition opportunities but 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, investment or new business initiative 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, inadequate return on capital 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 or prior to launching an initiative or entering a market. We may not be indemnified for some or all of these liabilities in an acquisition transaction. In addition, our funding requirements associated with acquisitions, integration and implementation costs may reduce the funds available to us to make any dividend payments.

Our equity interests in certain 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 these 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. See "—Risks Related to Our Structure—We cannot provide any assurance regarding the outcome or impact on our business of any potential options we are considering."

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

        We and our projects may use derivative instruments, including futures, forwards, options and swaps, to manage commodity and financial market risks. These activities, though intended to mitigate price volatility, expose us to other risks. In the future, the project operators could recognize financial losses on these arrangements, including as a result of volatility in the market values of the underlying

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commodities, if a counterparty fails to perform under a contract or upon the failure or insolvency of a financial intermediary, exchange or clearinghouse used to enter, execute or clear the transactions. 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 the statement of operations, resulting in significant volatility in our income (loss) (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 (loss) (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 business, results of operations, financial condition 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 increases in natural gas prices, we have incurred income on these natural gas swaps. We execute these swaps only for the purpose of managing risks and not for speculative trading.

        We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do not hedge against commodity price volatility, our business, results of operations and financial condition may be improved or diminished based upon movement in commodity prices.

Certain employees are subject to collective bargaining

        A number of our plant employees, from one plant in British Columbia and four plants in Ontario are subject to collective bargaining agreements. These agreements expire periodically and we may not be able to renew them without a labor disruption or without agreeing to significant increases in labor costs. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on our business, results of operations and financial condition.

Our Pension Plan may require additional future contributions

        Certain of our employees in Canada are participants in a legacy defined benefit pension plan that we sponsor. As of December 31, 2014, our pension plan was at a surplus on a going concern basis which measures its funded status on the basis that the plan will continue to operate indefinitely. The additional amount of future contributions to our defined benefit plan will depend upon asset returns and a number of other factors and, as a result, the amounts we will be required to contribute in the future may vary. Cash contributions to the plan will reduce the cash available for our business.

Hostile cyber intrusions could severely impair our operations, lead to the disclosure of confidential information, damage our reputation and otherwise have an adverse effect on our business, results of operations and financial condition

        A cyber intrusion is considered to be any adverse event that threatens the confidentiality, integrity or availability of our information resources. More specifically, a cyber intrusion is an intentional attack or an unintentional event that can include gaining unauthorized access to systems to disrupt operations, corrupt data, steal confidential information, and impact our ability to make collections or otherwise impact our operations. We are dependent on various information technologies throughout our company and our projects to carry out multiple business activities. Further, the computer systems that run our facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S.

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and/or Canadian bulk power system or our operations could view our computer systems, software or networks as attractive targets for cyber attack. In addition, our business requires that we collect and maintain confidential employee and shareholder information, which is subject to the risk of electronic theft or loss.

        A successful cyber attack, such as unauthorized access, malicious software or other violations on the systems that control generation and transmission at our projects could severely disrupt business operations, diminish competitive advantages through reputation damages and increase operational costs. The breach of certain business systems could affect our ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. For these reasons, a significant cyber incident could materially and adversely affect our business, results of operations and financial condition.

Failure to comply with the U.S. Foreign Corrupt Practices Act and/or the Canadian Corruption of Foreign Public Officials Act could subject us to, among other things, penalties and legal expenses that could harm our reputation and have a material adverse effect on our business, results of operations and financial condition

        We are subject to anti-corruption laws and regulations including the U.S. Foreign Corrupt Practices Act ("FCPA") and the Canadian Corruption of Foreign Public Officials Act (the "CFPOA"), which generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. In addition, the FCPA imposes accounting standards and requirements on U.S. publicly traded corporations and their foreign affiliates, which are intended to prevent the diversion of corporate funds to the payment of bribes and other improper payments, and to prevent the establishment of "off books" slush funds from which improper payments can be made (similar provisions have been proposed to be added to the CFPOA). The Securities and Exchange Commission (the "SEC") has increased its enforcement of the FCPA during the past several years. In recent years, enforcement of the CFPOA in Canada has also increased and can be attributed, in part, to the establishment of the Royal Canadian Mounted Police's International Anti-Corruption Unit in 2008. Although we have implemented policies and procedures designed to ensure that we, our employees and other intermediaries comply with the FCPA and/or the CFPOA, there is no assurance that such policies or procedures will work effectively all of the time or protect us against liability under the FCPA and/or the CFPOA for actions taken by our employees and other intermediaries with respect to our business or any businesses that we may acquire. If we are not in compliance with the FCPA and/or the CFPOA, we may be subject to criminal penalties pursuant to the CFPOA and/or criminal and civil penalties and other remedial measures pursuant to the FCPA, including changes or enhancements to our procedures, policies and control, as well as potential personnel change and disciplinary actions, which could have an adverse impact on our business, results of operations and financial condition.

Our success depends in part on our ability to retain, motivate and recruit executives and other key employees, and failure to do so could negatively affect us

        Our success depends in part on our ability to retain, recruit and motivate key employees who have experience in our industry. Experienced employees in the power industry are in high demand and competition for their talents can be intense. Further, an aging work force in the power industry necessitates recruiting, retaining and developing the next generation of leadership. A failure to attract and retain executives and other key employees with specialized knowledge in power generation could have an adverse impact on our business, results of operations and financial condition because of the difficulty of promptly finding qualified replacements. See "—Risks Related to our Structure—Our recent management changes may impact our business plan."

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ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

ITEM 2.    PROPERTIES

        We have included descriptions of the locations and general character of our principal physical operating properties, including an identification of the segments that use such properties, in "Item 1. Business," which is incorporated herein by reference. A significant portion of our equity interests in the entities owning these properties is pledged as collateral under our Senior Secured Credit Facilities (as defined herein) or under non-recourse operating level debt arrangements.

        Our principal executive office is located at One Federal Street, 30th floor, Boston, Massachusetts under a lease that expires in 2023.

ITEM 3.    LEGAL PROCEEDINGS

    Shareholder class action lawsuits

        Massachusetts District Court Actions

        On March 8, 14, 15 and 25, 2013 and April 23, 2013, five purported securities fraud class action complaints were filed by alleged investors in Atlantic Power common shares in the United States District Court for the District of Massachusetts (the "District Court") against Atlantic Power and Barry E. Welch, our former President and Chief Executive Officer and a former Director of Atlantic Power, in each of the actions, and, in addition to Mr. Welch, some or all of Patrick J. Welch, our former Chief Financial Officer, Lisa Donahue, our former interim Chief Financial Officer, and Terrence Ronan, our current Chief Financial Officer, in certain of the actions (the "Proposed Individual Defendants," and together with Atlantic Power, the "Proposed Defendants") (the "U.S. Actions").

        The District Court complaints differed in terms of the identities of the Proposed Individual Defendants they named, as noted above, the named plaintiffs, and the purported class period they alleged (July 23, 2010 to March 4, 2013 in three of the District Court actions and August 8, 2012 to February 28, 2013 in the other two District Court actions), but in general each alleged, among other things, that in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, Atlantic Power and the Proposed Individual Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The District Court complaints assert claims under Section 10(b) and, against the Proposed Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended.

        The parties to each District Court action filed joint motions requesting that the District Court set a schedule in the District Court actions, including: (i) setting a deadline for the lead plaintiff to file a consolidated amended class action complaint (the "Amended Complaint"), after the appointment of lead plaintiff and counsel; (ii) setting a deadline for Proposed Defendants to answer, file a motion to dismiss or otherwise respond to the Amended Complaint (and for subsequent briefing regarding any such motion to dismiss); and (iii) confirming that the Proposed Defendants need not answer, move to dismiss or otherwise respond to any of the five District Court complaints prior to the filing of the Amended Complaint. On May 7, 2013, each of six groups of investors (the "U.S. Lead Plaintiff Applicants") filed a motion (collectively, the "U.S. Lead Plaintiff Motions") with the District Court seeking: (i) to consolidate the five U.S. Actions (the "Consolidated U.S. Action"); (ii) to be appointed lead plaintiff in the Consolidated U.S. Action; and (iii) to have its choice of lead counsel confirmed. On May 22, 2013, three of the U.S. Lead Plaintiff Applicants filed oppositions to the other U.S. Lead Plaintiff Motions, and on June 6, 2013, those three Lead Plaintiff Applicants filed replies in support of

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their respective motions. On August 19, 2013, the District Court held a status conference to address certain issues raised by the U.S. Lead Plaintiff Motions, entered an order consolidating the five U.S. Actions, and directed two of the six U.S. Lead Plaintiff Applicants to file supplemental submissions by September 9, 2013. Both of those U.S. Lead Plaintiff Applicants filed the requested supplemental submissions, and then sought leave to file additional briefing. The Court granted those requests for leave and additional submissions were filed on September 13 and September 18, 2013.

        On March 31, 2014, the Court entered an order consolidating the five individual U.S. Actions, appointing the Feldman, Shapero, Carter and Smith investor group (one of the six U.S. Lead Plaintiffs Applicants) as Lead Plaintiff and approving Lead Plaintiff's selection of counsel. The Court also granted the parties' joint motion regarding initial case scheduling and directed the parties to resubmit a proposed schedule that contains specific dates. In response to that directive, on April 7, 2014, Lead Plaintiff filed an application and proposed order, which sought an extension of the schedule contained in the joint motion. The application and proposed order requested that: (i) Lead Plaintiff be permitted to file an amended complaint on or before May 30, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before July 29, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before September 24, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff's opposition on or before November 13, 2014. Proposed Defendants did not object to the schedule proposed by Lead Plaintiff. On May 29, 2014, Lead Plaintiff filed a renewed application and proposed order, which sought another extension of the schedule, and on June 3, 2014, Lead Plaintiff and the Proposed Defendants jointly filed a stipulation and proposed order requesting the following revised schedule: (i) Lead Plaintiff be permitted to file an amended complaint on or before June 6, 2014, (ii) the Proposed Defendants be permitted to move to dismiss or otherwise respond to the amended complaint on or before August 5, 2014, (iii) Lead Plaintiff be permitted to file an opposition, if any, on or before October 6, 2014, and (iv) the Proposed Defendants be permitted to file a reply to Lead Plaintiff's opposition on or before November 20, 2014. On June 3, 2014, the Court entered an order setting this requested schedule.

        On June 6, 2014, Lead Plaintiff filed the amended complaint (the "Amended Complaint"). The Amended Complaint names as defendants Barry E. Welch and Terrence Ronan (the "Individual Defendants") and Atlantic Power (together with the Individual Defendants, the "Defendants") and alleges a class period of June 20, 2011 to March 4, 2013 (the "Class Period"). The Amended Complaint makes allegations that are substantially similar to those asserted in the five initial complaints. Specifically, the Amended Complaint alleges, among other things, that in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, Defendants made materially false and misleading statements and omissions regarding the sustainability of Atlantic Power's common share dividend, which artificially inflated the price of Atlantic Power's common shares during the class period. The Amended Complaint continues to assert claims under Section 10(b) and, against the Individual Defendants, under Section 20(a) of the Securities Exchange Act of 1934, as amended. It also asserts a claim for unjust enrichment against the Individual Defendants. In accordance with the schedule referenced above, Defendants filed their motion to dismiss the consolidated (the "Motion to Dismiss") U.S. Action on August 5, 2014.

        On September 30, 2014, citing Atlantic Power's September 16, 2014 announcement of changes to its dividend and its President and CEO transition, Lead Plaintiff filed a motion (the "Extension Motion") requesting a thirty-day extension of its October 6, 2014 deadline for filing its brief in opposition to the Motion to Dismiss, in which to determine whether to file a second amended complaint. On October 2, 2014, the Court entered an order (i) extending Lead Plaintiff's deadline to file its opposition to the Motion to Dismiss to October 10, 2014 and (ii) requiring Defendants to file their opposition to the Extension Motion by October 2, 2014. In accordance with this order, on October 2, 2014, Defendants filed their opposition to the Extension Motion. On October 10, 2014, Lead Plaintiff filed its opposition to the Motion to Dismiss (the "Opposition") and also filed a motion

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for leave to amend the Amended Complaint, attaching a proposed second amended complaint. On October 21, 2014, Lead Plaintiff and Defendants filed a joint scheduling motion requesting (i) November 7, 2014 as the deadline for Defendants to file their opposition to Lead Plaintiff's motion for leave to amend the Amended Complaint; (ii) November 24, 2014 as the deadline for Defendants to file their reply in further support of the Motion to Dismiss; and (iii) November 24, 2014 as the deadline for Lead Plaintiff to file its reply in further support of its motion for leave to amend the Amended Complaint. On October 22, 2014, the Court entered an order setting this requested schedule. Pursuant to that order, the Motion to Dismiss and Extension Motion were fully briefed on November 24, 2014. On January 22, 2015, the Court held oral argument on the Motion to Dismiss and Extension Motion.

        On January 30, 2015, Lead Plaintiff filed a motion for leave to file a supplemental submission in opposition to Defendants' motion to dismiss (the "Motion for Leave"). The Court denied the Motion for Leave in an order entered on February 5, 2015, but permitted Lead Plaintiff to submit a brief letter identifying supplemental authorities. Lead Plaintiff filed that letter on February 9, 2015, and Defendants filed a response on February 10, 2015.

        Canadian Actions

        On March 19, 2013, April 2, 2013 and May 10, 2013, three notices of action relating to Canadian securities class action claims against the Proposed Defendants were also issued by alleged investors in Atlantic Power common shares, and in one of the actions, holders of Atlantic Power convertible debentures, with the Ontario Superior Court of Justice in the Province of Ontario. On April 8, 2013, a similar claim issued by alleged investors in Atlantic Power common shares seeking to initiate a class action against the Proposed Defendants was filed with the Superior Court of Quebec in the Province of Quebec (the "Canadian Actions").

        On April 17, May 22, and June 7, 2013 statements of claim relating to the notices of action were filed with the Ontario Superior Court of Justice in the Province of Ontario.

        On August 30, 2013, the three Ontario actions were succeeded by one action with an amended claim being issued on behalf of Jacqeline Coffin and Sandra Lowry. As in the U.S. Action, this claim names the Company, Barry E. Welch and Terrence Ronan as Defendants. The Plaintiffs seek leave to commence an action for statutory misrepresentation under the Ontario Securities Act and assert common law claims for misrepresentation. The Plaintiffs' allegations focus on, among other things, claims the Defendants made materially false and misleading statements and omissions in Atlantic Power's press releases, quarterly and year-end filings and conference calls with analysts and investors, regarding the sustainability of Atlantic Power's common share dividend that artificially inflated the price of Atlantic Power's common shares. The Plaintiffs seek to certify the statutory and common law claims under the Class Proceedings Act for security holders who purchased and held securities through a proposed class period of November 5, 2012 to February 28, 2013.

        On October 4, 2013, the Plaintiffs delivered materials supporting their request for leave to commence an action for statutory misrepresentations and for certification of the statutory and common claims as class proceedings. These materials estimate the damages claimed for statutory misrepresentation at $197.4 million.

        Between June 2014 and January 2015, the Defendants and Plaintiffs exchanged responding and reply materials.

        A schedule for the Plaintiffs' leave and certification motions was set in December 2014. It provides for a hearing of the Plaintiffs' motions on May 20-21, 2015.

        The proposed class action in Quebec is stayed until March 30, 2015.

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        Pursuant to the Private Securities Litigation Reform Act of 1995, all discovery is stayed in the U.S. Actions. Plaintiffs have not yet specified an amount of alleged damages in the U.S. Actions. As noted above, the plaintiffs in the Canadian Action have estimated their alleged statutory damages at $197.4 million. Because both the U.S. and Canadian Actions are in their early stages, Atlantic Power is unable to reasonably estimate the possible loss or range of losses, if any, arising from this litigation. Atlantic Power intends to defend vigorously against each of the actions.

ITEM 4.    MINE SAFETY DISCLOSURES

        Not applicable.

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information and Holders

        Our common shares trade on the NYSE under the symbol "AT" and on the TSX under the symbol "ATP".

        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 December 31, 2014:

Period
  High (US$)   Low (US$)  

Quarter ended December 31, 2014

    2.93     1.91  

Quarter ended September 30, 2014

    4.15     3.15  

Quarter ended June 30, 2014

    4.13     2.82  

Quarter ended March 31, 2014

    3.60     2.11  

Quarter ended December 31, 2013

    5.36     3.06  

Quarter ended September 30, 2013

    4.66     3.81  

Quarter ended June 30, 2013

    5.57     3.86  

Quarter ended March 31, 2013

    13.03     4.56  

        The following table sets forth the price ranges of our common shares, as applicable, as reported by the TSX for the periods indicated:

Period
  High (Cdn$)   Low (Cdn$)  

Quarter ended December 31, 2014

    3.40     2.14  

Quarter ended September 30, 2014

    4.44     2.43  

Quarter ended June 30, 2014

    4.40     3.11  

Quarter ended March 31, 2014

    3.88     2.41  

Quarter ended December 31, 2013

    5.51     3.05  

Quarter ended September 30, 2013

    4.86     4.01  

Quarter ended June 30, 2013

    5.63     4.04  

Quarter ended March 31, 2013

    13.02     4.64  

        The number of holders of common shares was approximately 121,416,459 on February 21, 2015.

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Dividends

        Dividends declared per common share in 2014 and 2013 were as follows (Cdn$):

Month
  2014   2013  
 
  Amount
 

January

  $ 0.0333   $ 0.0958  

February

    0.0333     0.0958  

March

    0.0333     0.0333  

April

    0.0333     0.0333  

May

    0.0333     0.0333  

June

    0.0333     0.0333  

July

    0.0333     0.0333  

August

    0.0333     0.0333  

September

        0.0333  

October

        0.0333  

November

    0.0300     0.0333  

December

        0.0333  

        See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations—Factors That May Influence Our Results" for a discussion of certain non-recourse project-level debt that can restrict the ability of our projects to make cash distributions to us and Item 1A. "Risk Factors—Risk Related to Our Structure—Our indebtedness and financing arrangements, and any failure to comply with the covenants contained therein, could negatively impact our business and our projects and could render us unable to make dividend payments, cash distributions, acquisitions or investments or issue additional indebtedness we otherwise would seek to do."

Securities Authorized for Issuance under Equity Compensation Plans

        The following table provides information as of December 31, 2014 regarding our Long-Term Incentive Plan. For the description of our Long-Term Incentive Plan, see Note 16, Equity Compensation Plans to the consolidated financial statements.

 
  Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights(1)(2)
  Weighted-average
exercise price of
outstanding options,
warrants and rights
  Number of securities remaining
available for future issuance
under equity compensation plans
(excluding securities reflected
in column (a))(1)(2)
 
 
  (a)
  (b)
  (c)
 

Equity compensation plans approved by security holders

    1,157,598   $     919,887  

Equity compensation plans not approved by security holders

   
   
   
 

Total

    1,157,598   $     919,887  

(1)
Number of securities to be issued upon exercise of outstanding awards and number of securities remaining available for future issuance reflects expected redemption of award one-third in cash and two-thirds in shares of our common stock. See Item 15. "Exhibits and Financial Statements Schedule"—Note 2(r), Equity compensation plans.

(2)
The maximum aggregate number of common shares that may be issued under our Long-Term Incentive Plan upon redemption of notional shares is 3,000,000. See Item 15. "Exhibits and Financial Statements Schedule"—Note 2(r), Equity compensation plans.

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Performance Graph

        The performance graph below compares the cumulative total shareholder return on our common shares for the period December 31, 2009, through December 31, 2014, with the cumulative total return of the Standard & Poor's 500 Composite Stock Price Index, or S&P 500 and the Standard & Poor's TSX Composite or S&P/TSX. Our common shares trade on the NYSE under the symbol "AT" and the TSX under the symbol "ATP". The performance graph shown below is being furnished and compares each period assuming that an investment was made on December 31, 2009, in each of our common shares, the stocks included in the S&P 500 and the stocks included in the S&P/TSX, and that all dividends were reinvested.


Total Shareholder Return 2009 – 2014

GRAPHIC

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ITEM 6.    SELECTED FINANCIAL DATA

        The following table sets forth our selected historical consolidated financial information for each of the periods indicated. The annual historical information for each of the years in the three-year period ended December 31, 2014 has been derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

        You should read the following selected consolidated financial data along with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the accompanying notes, which describe the impact of material acquisitions and dispositions that occurred in the three-year period ended December 31, 2014.

 
  Year Ended December 31,  
(in millions of U.S. dollars, except as otherwise stated)
  2014(a)(d)   2013(a)(d)   2012(a)   2011(a)(b)   2010(a)  

Project revenue

  $ 569.2   $ 544.1   $ 429.8   $ 93.9   $ 1.1  

Project (loss) income

    (50.5 )   63.7     (31.2 )   (3.6 )   16.1  

Loss from continuing operations

    (182.1 )   (18.2 )   (116.0 )   (69.9 )   (26.7 )

(Loss) income from discontinued operations, net of tax

    (0.1 )   (5.6 )   15.7     34.3     22.9  

Net loss attributable to Atlantic Power Corporation

    (177.4 )   (33.0 )   (112.8 )   (38.4 )   (3.8 )

Basic and diluted loss per share(c)

                               

Loss per share from continuing operations attributable to Atlantic Power Corporation

  $ (1.47 ) $ (0.23 ) $ (1.10 ) $ (0.94 ) $ (0.45 )

(Loss) income from discontinued operations, net of tax                   

        (0.05 )   0.13   $ 0.44   $ 0.37  

Net loss attributable to Atlantic Power Corporation

  $ (1.47 ) $ (0.28 ) $ (0.97 ) $ (0.50 ) $ (0.08 )

Per common share dividend declared

  $ 0.27   $ 0.51   $ 1.1   $ 1.11   $ 1.06  

Total assets

  $ 2,916.6   $ 3,395.0   $ 4,002.7   $ 3,248.4   $ 1,013.0  

Total long-term liabilities

  $ 1,976.4   $ 1,909.6   $ 2,280.8   $ 1,940.2   $ 518.3  

(a)
The Florida Projects, Path 15, Greeley and Rollcast are classified as discontinued operations for the five years ended December 31, 2014. Prior periods have been reclassified to reflect the impact.

(b)
The acquisition of the Partnership was completed on November 5, 2011.

(c)
Diluted earnings (loss) per share is computed including dilutive potential shares, which include those issuable upon conversion of convertible debentures and under our long term incentive plan. Because we reported a loss during each of the five years ended December 31, 2014, the effect of including potentially dilutive shares in the calculation during those periods is anti-dilutive. Please see the notes to our historical consolidated financial statements included elsewhere in this Form 10-K for information relating to the number of shares used in calculating basic and diluted earnings (loss) per share for the periods presented.

(d)
Includes $106.6 million and $34.9 million of goodwill and long-lived asset impairment for the years end December 31, 2014 and 2013, respectively.

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ITEM 7.    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 audited consolidated financial statements included in this Annual Report on Form 10-K. All dollar amounts discussed below are in millions of 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").


(in millions of U.S. dollars, except per-share amounts)

Overview of Our Business

        Atlantic Power owns and operates a diverse fleet of power generation assets in the United States and Canada. Our power generation projects sell electricity to utilities and other large commercial customers largely under long-term power purchase agreements ("PPAs"), which seek to minimize exposure to changes in commodity prices. As of December 31, 2014, our power generation projects in operation had an aggregate gross electric generation capacity of approximately 2,945 megawatts ("MW") in which our aggregate ownership interest is approximately 2,024 MW. Our current portfolio consists of interests in twenty-eight operational power generation projects across eleven states in the United States and two provinces in Canada. Twenty of our projects are majority-owned subsidiaries.

        We sell the majority of the capacity and energy from our power generation projects under PPAs to a variety of utilities and other parties. Under the PPAs, which have expiration dates ranging from December 31, 2017 to December 31, 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 to industrial purchasers under steam sales agreements. Sales of electricity are generally higher during the summer and winter months, when temperature extremes create demand for either summer cooling or winter heating.

        The majority of our natural gas, coal and biomass power generation projects have long-term fuel supply agreements, typically accompanied by fuel transportation arrangements. In most cases, the term of the fuel supply and transportation arrangements correspond to the term of the relevant PPAs and many of the PPAs and steam sales agreements provide for the indexing or pass-through of fuel costs to our customers. In cases where there is no pass- through of fuel costs, we often attempt to mitigate the market price risk of changing commodity costs through the use of hedging strategies.

        We directly operate and maintain twenty-one of our power generation projects. We also partner with recognized leaders in the independent power industry to operate and maintain our other projects, including CEM and PPMS. Under these operation, maintenance and management agreements, the operator is typically responsible for operations, maintenance and repair services.

    Our organization

        We have four reportable segments: East, West, Wind and Un-allocated Corporate. We revised our reportable business segments in the fourth quarter of 2013 as a result of significant project asset sales and in order to align our reportable business segments with changes in management's structure, resource allocation and performance assessment in making decisions regarding our operations. Our previously reported financial results for the year ended December 31, 2012 has been presented to reflect these changes in operating segments. The segment classified as Un-allocated Corporate includes activities that support the executive and administrative offices, capital structure, costs of being a public registrant, costs to develop future projects and intercompany eliminations. These costs are not allocated to the operating segments when determining segment profit or loss. Project income (loss) is the primary GAAP measure of our operating results and is discussed below by reportable segment.

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Our strategy and execution of our business plan

        We continue to focus on executing our business plan objectives and have been focused on initiatives aimed at, among other things, improving our financial flexibility and addressing our near-term maturities.

        As announced in the third quarter of 2014, as part of our previously announced strategic review process, we concluded that a sale or merger of the Company was not in the best interests of the Company or its stakeholders. With the assistance of its external financial advisors, Goldman, Sachs & Co. and Greenhill & Co., LLC, our Board of Directors conducted a thorough review of the options available to the Company with respect to a possible sale or merger. The Board of Directors determined that the interests of the Company and its stakeholders are best served by continuing to operate as an independent company and executing our business plan. This plan includes the objectives of delevering our balance sheet to improve our cost of capital and ability to compete for new investments, enhancing the value of our existing assets through discretionary capital investments and commercial activities, utilizing our core competencies to create proprietary investment opportunities, improving our cost structure and reducing overhead. In addition, we continue to assess other potential options, including asset sales or the contribution of assets to a joint venture if the valuation of a particular asset or assets is compelling, and to raise additional capital for growth or potential debt reduction.

    Delevering our balance sheet and improving financial flexibility

        In February 2014, we executed the Term Loan Facility and used the funds therefrom to address debt maturities in 2014, 2015 and 2017 as discussed in more detail in "—Liquidity and Capital Resources". The 50% cash sweep and amortization features of the Term Loan Facility are expected to reduce leverage over time. During 2014 we paid down $58.4 million of principal through the cash sweep and amortization. With a portion of the proceeds received from the Term Loan Facility, we paid down $140.1 million aggregate principal amount of the 9.0% Notes. In January 2015, we also repurchased an additional $9.0 million of the 9.0% Notes. Also, as previously announced in the third quarter of 2014, our Board of Directors determined to set a dividend level of Cdn$0.12 per share on an annual basis, equivalent to approximately $13 million annually. Dividends to shareholders are paid, if and when declared by, and subject to the discretion of, the Board of Directors. As we execute our business strategy, and consistent with our objectives, our Board of Directors, together with our management, will regularly evaluate what the optimal dividend policy is for the Company going forward.

        On October 31, 2014, we used Cdn$44.8 million of cash on hand to repay at maturity our 6.5% Convertible Secured Debentures due October 31, 2014. Additionally, we have targeted opportunistic market purchases of our outstanding debt securities. We believe these purchases have the benefit of reducing financial risk and lowering cost of capital. During the fourth quarter of 2014, we announced a Normal Course Issuer Bid ("NCIB") for our convertible debentures. Under the NCIB, we entered into a pre-defined automatic securities purchase plan with our broker in order to facilitate purchases of our convertible debentures. The NCIB commenced on November 11, 2014 and will expire on November 10, 2015 or such earlier date as we complete our purchases pursuant to the NCIB. The actual amount of convertible debentures that may be purchased under the NCIB cannot exceed approximately $31 million and is further limited based on the outstanding principal of the individual outstanding tranches. As of December 31, 2014 we have repurchased and cancelled $3.1 million par value of convertible debentures with $2.6 million of cash on-hand. In January and February 2015, we also repurchased and cancelled an additional $6.1 million par value of convertible debentures with $4.9 million of cash on-hand.

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    Investment in our existing businesses and extension of our contracts

        We continue to make both mandatory maintenance and optimization investments in our existing fleet designed to improve longevity, safety and efficiency, boost output or reduce costs. During 2014, we invested $33.2 million in maintenance and capital expenditures, of which approximately $17.2 million was for optimization projects. We are targeting funding approximately $35.0 million of maintenance and capital expenditures during 2015, of which between $10 and $15 million will be discretionary investments aimed at improving the projects' economics.

        On January 20, 2015, we entered into an agreement with the Ontario Power Authority ("OPA") and its successor, IESO, for the future operations of the Tunis facility. Subject to meeting certain technical modifications to the plant, gas delivery and other requirements, Tunis will operate under a 15-year agreement with the IESO commencing between November 2017 and June 2019. The new contract will require the plant to become fully dispatchable as opposed to its current baseload configuration. As such, Tunis will only provide electricity to the Ontario grid when required, thereby assisting to reduce the incidents of surplus baseload generation in the market. The new agreement provides the Tunis project with a fixed monthly payment which escalates annually according to a pre-defined formula while allowing it to earn additional energy revenues for those periods during which it is called upon to operate.

    Improving our cost structure and reducing overhead

        Beginning in 2013 and throughout 2014, we took aggressive actions to reduce corporate expenses in the areas of personnel, development and administrative costs. We expect these actions to result in a savings of at least $15 million in corporate general and administrative and development expenses in 2015 as compared to amounts incurred in 2013 (our baseline year for comparison). As a result of these actions, we incurred $6.0 million of employee severance costs and $4.9 million of other non-recurring costs in 2014. In addition, we also expect to incur approximately $2.2 million of employee severance costs in the first quarter of 2015. We will continue to evaluate improvements to our cost structure.

    Management and oversight

        We concluded our search for a President and Chief Executive Officer. On January 22, 2015, our Board of Directors appointed James J. Moore, Jr., as President, Chief Executive Officer and a director of the Company, effective January 26, 2015. In connection with Mr. Moore's appointment, effective January 26, 2015, Kenneth Hartwick stepped down as Interim President and CEO. Mr. Hartwick remains a member of the Board of Directors of the Company. During the fourth quarter of 2014, the Board also appointed two new independent directors of the company: Teresa M. Ressel and Kevin T. Howell. With these additions, our Board of Directors now consists of eight members, seven of whom are independent under applicable stock exchange and SEC standards.

Other significant events during the year ended December 31, 2014

    Zachry Arbitration

        In October 2014, we settled a dispute in arbitration with Zachry, the contractor of Piedmont, related to work performed under the project's engineering, procurement and construction contract ("EPC"). The settlement reflects payment for the completion of the contract. Under the terms of the settlement, Piedmont agreed to pay Zachry $5.0 million within seven days of execution of the settlement agreement. The settlement results in a mutual release of all arbitration claims by both parties. Piedmont had accrued $8.2 million for the final retainage payment under the EPC in 2013. On November 5, 2014, Piedmont made a $5.0 million payment from restricted cash related to the settlement agreement, while the remaining $3.2 million of reversed accrual was credited to operations and maintenance expense which was originally accrued in 2013.

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    Goodwill Impairment

        During the three months ended June 30, 2014, based on the continued deficit of our market capitalization as compared to our book carrying value, we determined that it was appropriate to initiate a test of the remaining goodwill at all of our reporting units. We completed this during the third quarter of 2014 and determined that goodwill was impaired at the Kenilworth (East segment), Manchief (West Segment) and Williams Lake (West segment) reporting units. The total non-cash impairment recorded in the three and nine months ended September 30, 2014 was $91.8 million. We updated this test in the fourth quarter in connection with our annual test as of November 30, 2014 and recorded no additional impairment.

        Under our accounting policies for long-lived assets and goodwill impairment, we perform an impairment analysis at the earlier of (i) executing a new PPA (or other arrangement) and (ii) six months prior to the expiration of an existing PPA. The Tunis project's PPA expired on December 31, 2014 and accordingly, we performed a long-lived assets impairment test and a goodwill impairment test during the second quarter of 2014. Based on the results of these tests, the project recorded a $9.6 million long-lived impairment charge and a $5.2 million goodwill impairment charge in the second quarter of 2014. The $14.8 million aggregate long-lived asset and goodwill impairment was primarily due to our assessment of the forecasted cash flows from re-contracting and other strategic outcomes at Tunis. We anticipate that forecasted cash flows under Tunis' new PPA are expected to recover the remaining long-lived asset balance at the project.

    Sale of Delta-Person

        In December 2012 we and the other owners of Delta-Person, entered into a purchase and sale agreement with BHB Power, LLC and Public Service Company of New Mexico to sell the project for approximately $37.2 million including working capital adjustments. The sale of Delta-Person closed in July 2014, resulting in a gain on sale of approximately $8.6 million that was recorded as a component of equity in earnings of unconsolidated affiliates in the consolidated statement of operations. We received net cash proceeds for our ownership interest of approximately $7.2 million in the aggregate. We expect to receive an additional $1.4 million of cash proceeds held in escrow for up to twelve months after the close of the transaction. We intend to use the net proceeds from the sale for general corporate purposes.

    Expiration of Selkirk PPA

        The PPA at Selkirk (in which our economic ownership interest is 18.5%) expired as of August 31, 2014. This resulted in 100% of the project's capacity not being contracted. As of August 31, 2014, Selkirk began operating on a 100% merchant basis, with the project selling power into the spot power market to the extent spot market prices support profitable operation of the project.

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Performance highlights

 
  Year Ended December 31,  
 
  2014   2013   2012  

Project (loss) income

  $ (50.5 ) $ 63.7   $ (31.2 )

Loss from continuing operations

  $ (182.1 ) $ (18.2 ) $ (116.0 )

(Loss) income from discontinued operations

  $ (0.1 ) $ (5.6 ) $ 15.7  

Net loss attributable to Atlantic Power Corporation

  $ (177.4 ) $ (33.0 ) $ (112.8 )

Loss per share from continuing operations attributable to Atlantic Power Corporation—basic and diluted

 
$

(1.47

)

$

(0.23

)

$

(1.10

)

Earnings (loss) per share from discontinued operations—basic

        (0.05 )   0.13  

Loss per share attributable to Atlantic Power Corporation-basic and diluted

  $ (1.47 ) $ (0.28 ) $ (0.97 )

Project Adjusted EBITDA(1)

  $ 299.3   $ 268.9   $ 224.4  

Free Cash Flow(1)

  $ (55.6 ) $ 108.8   $ 131.6  

(1)
See reconciliation and definition below under Supplementary Non-GAAP Financial Information.

        Consolidated project loss was $(50.5) million for the year ended December 31, 2014, a decrease of $114.2 million from the prior year. The decrease was primarily due to $71.7 million increase in non-cash goodwill and long-lived asset impairments, a $58.2 million increase in non-cash loss on changes in the fair value of derivatives and a $21.8 million decrease in the gain in sale of equity method projects from the comparable 2013 period, partially offset by a $25.1 million increase in revenue from strong wind and waste heat generation and lower development and general and administrative expenses. Project Adjusted EBITDA, a non-GAAP measure, increased $30.4 million for the year ended December 31, 2014. This increase was driven by strong wind generation, increased waste heat at our Ontario projects and lower maintenance and administrative expenses as compared to a year ago. This was partially offset by lower dispatch at several plants due to mild summer weather. A detailed discussion of project (loss) income by segment is provided in Consolidated Overview and Results of Operations below. The discussion of Project Adjusted EBITDA by segment begins on page 71.

Factors That May Influence Our Results

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

    Financial performance of our projects

        The operating performance of our projects supports cash distributions that are made to us after all operating, maintenance, capital expenditures and debt service requirements are satisfied at the project-level. Our projects are able to generate cash flows 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:

    Power generated by our projects, in most cases, is sold under PPAs that expire at various times. Currently, our PPAs are scheduled to expire between December 31, 2017 and December 31, 2037. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA on acceptable terms or timing, if at all, or the price received by the project for power under

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      subsequent arrangements may be reduced significantly, or there may be a delay in securing a new PPA until a significant time after the expiration of the original PPA at the project. For example, the PPA at Selkirk expired in August 2014. As a result, 100% of the capacity at Selkirk is not contracted and therefore sold at market power prices. Our next PPA expirations do not occur until year end 2017 and are at our North Bay and Kapuskasing projects in Ontario. See "Risk Factors—Risks Related to Our Business and Our Projects—The expiration or termination of our power purchase agreements could have a material adverse impact on our business, results of operations and financial condition."

    While approximately 28% of our power generation revenue in 2014 was related to contractual capacity payments, commodity prices do influence our variable revenues and the 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 the utility and its customers, but some of our projects do have exposure to market power and fuel prices. See Item 1A. "Risk Factors—Risks Related to Our Business and Our Projects—Our projects depend on third-party suppliers under fuel supply agreements, and increases in fuel costs may adversely affect the profitability of the projects" and Item 7A. "Quantitative and Qualitative Disclosures About Market Risk" for additional details about our hedging arrangements.

    Our most significant exposure to market power prices exists at the Selkirk, Chambers and Morris projects. 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. With low demand for electricity the utility reduces its dispatch to minimum contracted levels during off-peak hours. At Selkirk, none of the capacity of the facility is currently 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. Additionally at Morris, approximately 68% of the facility's capacity is currently not contracted and is sold at market power prices or not sold at all if market prices do not support profitable operation of the facility. See Item 1A. "Risk Factors—Risks Related to Our Business and Our Projects—Certain of our projects are exposed to fluctuations in the price of electricity, which may have a material adverse effect on the operating margin of these projects and on our business, results of operations and financial condition."

    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. If re-contracted, the degree of the expected decline in cash flows from operations is subject to market conditions when we execute new PPAs for these projects and is difficult to estimate at this time. See Item 1A. "Risk Factors—Risks Related to Our Business and Our Projects—The expiration or termination of our power purchase agreements could have a material adverse impact on our business, results of operations and financial condition." These projects will be free of debt when their PPAs expire, which we expect to provide us with some flexibility to pursue the most economic type of contract without restrictions that might be imposed by project-level debt.

    Some of our projects have non-recourse project-level debt that can restrict the ability of the project to make cash distributions. The project-level debt agreements typically contain cash flow coverage ratio tests that restrict the project's cash distributions if project cash flows do not exceed project-level debt service requirements by a specified amount. Although all projects, with the exception of Piedmont, are currently meeting these debt service requirements, we cannot provide any assurances that these projects will generate enough future cash flow to meet any applicable ratio tests and be able to make distributions to us. See "Liquidity and Capital Resources—Project-level debt" and Item 1A. "Risk Factors—Risks Related to Our Structure—Our indebtedness and financing arrangements, and any failure to comply with the covenants

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      contained therein, could negatively impact our business and our projects and could render us unable to make dividend payments, acquisitions or investments or issue additional indebtedness we otherwise would seek to do."

    The performance of our projects is impacted by a variety of operational and other factors, including planned and unplanned outages and maintenance requirements, delays in start-up, sourcing of fuel from suppliers and wind, water and waste heat levels, among others. For example, delays in the start- up of our Piedmont project and subsequent unplanned outages have resulted in increased costs and lost revenue and have affected our results. For additional details regarding the various operational and other risks that we face, see "Risk Factors—Risks Related to Our Business and Our Projects."

    Non-cash gains and losses on derivatives instruments

        In the ordinary course of our business, we execute natural gas purchase agreements and natural gas swap contracts to manage our exposure to fluctuations in commodity prices, foreign currency forward 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 currently 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 Item 7A. "Quantitative and Qualitative Disclosures About Market Risk" 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. A portion of our convertible debentures and long-term corporate level debt are 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 statements 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.

    Impairment

        We test our long-lived assets and goodwill for impairment at least annually, or more often if deemed appropriate based on the determination of management or the occurrence of certain trigger events under our impairment policy. We recorded $106.6 million and $34.9 million of long-lived asset and goodwill impairments for the years ended December 31, 2014 and 2013, respectively.

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Consolidated Overview and Results of Operations

    2014 compared to 2013

        The following tables and discussion summarizes our consolidated results of operations and provide an analysis by reportable segment:

 
  Years Ended December 31,  
 
  2014   2013   $ change   % change  

Project revenue:

                         

Energy sales

  $ 315.9   $ 302.2   $ 13.7     5 %

Energy capacity revenue

    161.3     163.7     (2.4 )   –1 %

Other

    92.0     78.2     13.8     18 %

    569.2     544.1     25.1     5 %

Project expenses:

                         

Fuel

    210.4     194.3     16.1     8 %

Operations and maintenance

    130.2     150.8     (20.6 )   –14 %

Development

    3.7     7.2     (3.5 )   NM  

Depreciation and amortization

    162.6     166.1     (3.5 )   –2 %

    506.9     518.4     (11.5 )   –2 %

Project other income (expense):

                         

Change in fair value of derivative instruments

    (8.7 )   49.5     (58.2 )   –118 %

Equity in earnings of unconsolidated affiliates

    25.8     26.9     (1.1 )   –4 %

Gain on sale of equity investments

    8.6     30.4     (21.8 )   –72 %

Interest expense, net

    (31.9 )   (34.4 )   2.5     –7 %

Impairment

    (106.6 )   (34.9 )   (71.7 )   NM  

Other income, net

        0.5     (0.5 )   NM  

    (112.8 )   38.0     (150.8 )   NM  

Project (loss) income

    (50.5 )   63.7     (114.2 )   NM  

Administrative and other expenses (income):

   
 
   
 
   
 
   
 
 

Administration

    37.9     35.2     2.7     8 %

Interest, net

    146.7     104.1     42.6     41 %

Foreign exchange gain

    (38.3 )   (27.4 )   (10.9 )   40 %

Other income, net

    (2.8 )   (10.5 )   7.7     –73 %

    143.5     101.4     42.1     42 %

Loss from continuing operations before income taxes

    (194.0 )   (37.7 )   (156.3 )   NM  

Income tax benefit

    (11.9 )   (19.5 )   7.6     –39 %

Loss from continuing operations

    (182.1 )   (18.2 )   (163.9 )   901 %

Loss from discontinued operations, net of tax

    (0.1 )   (5.6 )   5.5     –98 %

Net loss

    (182.2 )   (23.8 )   (158.4 )   NM  

Net loss attributable to noncontrolling interests

    (16.4 )   (3.4 )   (13.0 )   NM  

Net income attributable to Preferred share dividends of a subsidiary company

    11.6     12.6     (1.0 )   –8 %

Net loss attributable to Atlantic Power Corporation

  $ (177.4 ) $ (33.0 ) $ (144.4 )   NM  

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Project Income (Loss) by Segment

 
  Year Ended December 31, 2014  
 
  East   West(2)   Wind   Un-allocated
Corporate
  Consolidated
Total
 

Project revenue:

                               

Energy sales

  $ 152.0   $ 84.9   $ 79.0   $   $ 315.9  

Energy capacity revenue

    116.0     45.3             161.3  

Other

    45.8     45.0     0.3     0.9     92.0  

    313.8     175.2     79.3     0.9     569.2  

Project expenses:

                               

Fuel

    148.0     62.3         0.1     210.4  

Operations and maintenance

    55.6     48.8     21.1     4.7     130.2  

Development

                3.7     3.7  

Depreciation and amortization

    68.3     53.3     40.3     0.7     162.6  

    271.9     164.4     61.4     9.2     506.9  

Project other income (expense):

                               

Change in fair value of derivative instruments

    8.0         (15.5 )   (1.2 )   (8.7 )

Equity in earnings of unconsolidated affiliates

    22.3     3.3     0.3     (0.1 )   25.8  

Gain on sale of equity investments          

        8.6             8.6  

Interest expense, net

    (17.7 )       (14.2 )       (31.9 )

Impairment

    (32.7 )   (74.0 )       0.1     (106.6 )

Other expense, net

                     

    (20.1 )   (62.1 )   (29.4 )   (1.2 )   (112.8 )

Project income (loss)

  $ 21.8   $ (51.3 ) $ (11.5 ) $ (9.5 ) $ (50.5 )

 

 
  Year Ended December 31, 2013  
 
  East(1)   West(2)   Wind   Un-allocated
Corporate(3)
  Consolidated
Total
 

Project revenue:

                               

Energy sales

  $ 150.1   $ 81.6   $ 70.6   $ (0.1 ) $ 302.2  

Energy capacity revenue

    118.3     45.6         (0.2 )   163.7  

Other

    30.7     47.5     0.2     (0.2 )   78.2  

    299.1     174.7     70.8     (0.5 )   544.1  

Project expenses:

                               

Fuel

    135.0     59.2         0.1     194.3  

Operations and maintenance

    63.7     55.5     20.8     10.8     150.8  

Development

                7.2     7.2  

Depreciation and amortization

    68.9     54.9     41.8     0.5     166.1  

    267.6     169.6     62.6     18.6     518.4  

Project other income (expense):

                               

Change in fair value of derivative instruments

    25.5         24.0         49.5  

Equity in earnings of unconsolidated affiliates

    21.3     4.5     1.1         26.9  

Gain on sale of equity investments          

        30.4             30.4  

Interest expense, net

    (19.6 )   (0.1 )   (14.6 )   (0.1 )   (34.4 )

Impairment

    (30.8 )   (4.1 )           (34.9 )

Other expense, net

    (2.1 )       (0.1 )   2.7     0.5  

    (5.7 )   30.7     10.4     2.6     38.0  

Project income (loss)

  $ 25.8   $ 35.8   $ 18.6   $ (16.5 ) $ 63.7  

(1)
Excludes the Florida Projects which are classified as discontinued operations.

(2)
Excludes Path 15 and Greeley which are classified as discontinued operations.

(3)
Excludes Rollcast which is designated as discontinued operations.

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    East

        Project income for 2014 decreased $4.0 million or 15.5% from 2013 primarily due to:

    increased project loss of $12.0 million at Tunis due primarily to a $14.8 million non-cash goodwill and long-lived asset impairment charge recorded during the year ended December 31, 2014;

    decreased project income of $11.9 million at Selkirk due primarily to lower energy revenue resulting from lower generation from mild weather conditions, as well as accelerated depreciation resulting from the expiration of the project's PPA in August 2014. Selkirk is operating as a 100% merchant facility subsequent to the expiration of the project's PPA;

    decreased project income of $9.2 million at Piedmont due primarily to a negative $9.7 million non-cash change in the fair value of interest rate swap agreements that are accounted for as derivatives;

    decreased project income at North Bay of $2.8 million due primarily to a negative $5.5 million non-cash change in the fair value of gas purchase agreements that are accounted for as derivatives, partially offset by increased energy revenue from higher waste heat generation than in the comparable 2013 period; and

    decreased project income of Kapuskasing of $2.5 million due primarily to a negative $5.5 million non-cash change in the fair value of gas purchase agreements that are accounted for as derivatives and $2.6 million in decreased revenues, partially offset by a $3.6 million decrease in fuel expense and a $1.3 million decrease in operations and maintenance expense.

        These decreases were partially offset by:

    increased project income of $11.4 million at Kenilworth due primarily to a $17.9 million goodwill impairment charge recorded during the year ended December 31, 2014 as compared to a $30.7 million goodwill impairment charge recorded during the comparable 2013 period;

    increased project income of $9.5 million at Orlando due primarily to a $4.9 million increase in revenue resulting from increased generation and a $5.5 million decrease in fuel costs compared to the 2013 period. Orlando operated under an above-market fuel supply agreement that expired in the fourth quarter of 2013;

    increased project income of $6.6 million at Morris due primarily to a $14.4 million increase in energy revenues. Energy payments were escalated under the terms of the project's PPA due to higher natural gas prices. This increase was offset by higher fuel expenses compared to the 2013 period;

    increased project income of $6.4 million at Nipigon due primarily to a positive $4.0 million non-cash change in the fair value of a gas purchase agreement that is accounted for as a derivative, as well as a $2.4 million decrease in maintenance expenses as compared to the 2013 period, during which the project underwent a scheduled turbine outage. Nipigon also underwent a five-week outage during the third quarter of 2014 to upgrade its steam generator. Costs related to this project are being capitalized; and

    increased project income of $4.4 million at Curtis Palmer due primarily to a $5.0 million decrease in interest expense related to the project's repayment of its senior unsecured notes with proceeds from our Senior Secured Credit Facilities.

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    West

        Project income for 2014 decreased $87.1 million from 2013 primarily due to:

    decreased project income of $52.3 million at Manchief due primarily to a $50.2 million goodwill impairment charge recorded during the year ended December 31, 2014;

    decreased project income of $32.0 million at Gregory due to the sale of the project in August 2013, which resulted in a gain on sale of approximately $31.0 million recorded during the comparable 2013 period; and

    decreased project income of $23.0 million at Williams Lake due primarily to a $23.7 million goodwill impairment charge recorded during the year ended December 31, 2014.

        These decreases were partially offset by:

    increased project income of $8.1 million at Delta-Person which was sold in July 2014, which resulted in a gain on sale of $8.6 million recorded during 2014;

    increased project income of $3.9 million at Naval Station due primarily to $2.8 million of increased revenue due primarily to higher generation and energy prices resulting from higher gas prices during the 2014 period;

    increased project income of $3.6 million at Naval Training due primarily to decreased maintenance expenses as compared to the comparable 2013 period, during which the project underwent a scheduled turbine overhaul; and

    increased project income of $3.6 million at Mamquam due primarily to decreased maintenance expenses as compared to the comparable 2013 period, during which the project underwent a scheduled turbine overhaul.

        Project income for the West segment excludes the Path 15 and Greeley projects which are accounted for as a component of discontinued operations. Project income for Path 15 was $0.0 million and $2.1 million for the years ended December 31, 2014 and 2013, respectively. The decrease in 2014 compared to 2013 is due primarily to the project being sold in April 2013. Project (loss) income for Greeley was ($0.1) million and $0.6 million for the years ended December 31, 2014 and 2013, respectively. The decrease in 2014 compared to 2013 is due primarily to the project being sold in March 2014.

    Wind

        Project income for 2014 decreased $30.1 million from 2013 primarily due to:

    decreased project income from Rockland of $15.0 million due primarily to a negative $17.0 million non-cash change in the fair value of interest rate swap agreements that are accounted for as derivatives; and

    decreased project income from Meadow Creek of $15.0 million due primarily to a negative $22.5 million non-cash change in the fair value of interest rate swap agreements that are accounted for as derivatives, partially offset by $5.5 million of increased revenue due to higher generation compared to the 2013 period.

    Un-allocated Corporate

        Total project loss decreased $7.0 million from 2013 primarily due to a $3.5 million decrease in development and administrative costs at Ridgeline, which was acquired in December 2012, as well as administrative reduction initiatives undertaken during the year ended December 31, 2014.

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    Administrative and other expenses (income)

        Administrative and other expenses (income) include the income and expenses not attributable to our projects and are allocated to the Un-allocated Corporate segment. These costs include the activities that support the executive and administrative offices, capital structure, costs of being a public registrant, costs to develop future projects, interest costs on our corporate obligations, the impact of foreign exchange fluctuations and corporate tax. Significant non-cash items that impact Administrative and other expenses (income), which are subject to potentially significant fluctuations, include 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 the related deferred income tax expense (benefit) associated with these non-cash items.

    Administration

        Administration expense increased $2.7 million or 8% from 2013 primarily due to a $3.9 million increase in labor costs primarily due to $6.0 million of employee severance expenses incurred during the third and fourth quarters of 2014 which are expected to result in lower administrative costs on a go-forward basis.

    Interest, net

        Interest expense increased $42.6 million or 41% from the comparable 2013 period primarily due to $23.3 million of make-whole premiums paid to redeem the Series A Notes and Series B Notes (each as defined herein), as well as $16.4 million of premiums paid and non-cash deferred financing costs written off for the repurchase of $140.1 million aggregate principal amount of the 9.0% Notes in the first quarter of 2014.

    Foreign exchange gain

        Foreign exchange gain increased $10.9 million or 40% from the comparable 2013 period primarily due to a $7.4 million increase in unrealized gain in the revaluation of instruments denominated in Canadian dollars and a $18.4 million decrease in unrealized loss on foreign exchange forward contracts, offset by a $14.9 million decrease in realized gains on the settlement of foreign currency forward contracts. The U.S. dollar to Canadian dollar exchange rate was 1.16 and 1.06 at December 31, 2014 and 2013, respectively, an increase of 9.4% in 2014 compared to an increase of 6.9% in 2013.

    Other income, net

        Other income, net decreased $7.7 million or 73% from the 2013 comparable period primarily due to a $2.1 million non-cash gain recorded for the sale of Greeley in 2014 as compared to a $10.3 million gain and management fee agreement termination fee in 2013 resulting from the sale of Path 15.

    Income tax benefit

        Income tax benefit for the year ended December 31, 2014 was $11.9 million. Expected income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $50.4 million. The primary items impacting the tax rate for the year ended December 31, 2014 were $40.5 million relating to a change in the valuation allowance, $33.9 million relating to goodwill impairment, and $6.6 million relating to minority interest adjustments. These items were partially offset by $20.9 million relating to operating in higher tax rate jurisdictions, $10.2 million of capital losses recognized on tax restructuring, $7.4 million relating to foreign exchange, and $4.1 million relating to return to provision adjustments.

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    2013 compared to 2012

        The following tables and discussion summarize our consolidated results of operations and provide an analysis by reportable segment:

 
  Years Ended December 31,  
 
  2013   2012   $ change   % change  

Project revenue:

                         

Energy sales

  $ 302.2   $ 214.5   $ 87.7     41 %

Energy capacity revenue

    163.7     147.2     16.5     11 %

Other

    78.2     68.1     10.1     15 %

    544.1     429.8     114.3     27 %

Project expenses:

                         

Fuel

    194.3     164.9     29.4     18 %

Operations and maintenance

    150.8     119.6     31.2     26 %

Development

    7.2         7.2     NM  

Depreciation and amortization

    166.1     116.6     49.5     42 %

    518.4     401.1     117.3     29 %

Project other income (expense):

                         

Change in fair value of derivative instruments

    49.5     (59.3 )   108.8     NM  

Equity in earnings of unconsolidated affiliates

    26.9     15.2     11.7     77 %

Gain on sale of equity investments

    30.4     0.6     29.8     NM  

Interest expense, net

    (34.4 )   (16.4 )   (18.0 )   110 %

Impairment

    (34.9 )       (34.9 )   NM  

Other income, net

    0.5         0.5     NM  

    38.0     (59.9 )   97.9     NM  

Project income (loss)

    63.7     (31.2 )   94.9     NM  

Administrative and other expenses (income):

   
 
   
 
   
 
   
 
 

Administration

    35.2     28.3     6.9     24 %

Interest, net

    104.1     89.8     14.3     16 %

Foreign exchange (gain) loss

    (27.4 )   0.5     (27.9 )   NM  

Other income, net

    (10.5 )   (5.7 )   (4.8 )   84 %

    101.4     112.9     (11.5 )   –10 %

Loss from continuing operations before income taxes

    (37.7 )   (144.1 )   106.4     –74 %

Income tax benefit

    (19.5 )   (28.1 )   8.6     –31 %

Loss from continuing operations

    (18.2 )   (116.0 )   97.8     –84 %

(Loss) income from discontinued operations, net of tax

    (5.6 )   15.7     (21.3 )   NM  

Net loss

    (23.8 )   (100.3 )   76.5     –76 %

Net loss attributable to noncontrolling interests

    (3.4 )   (0.6 )   (2.8 )   NM  

Net income attributable to Preferred share dividends of a subsidiary company

    12.6     13.1     (0.5 )   –4 %

Net loss attributable to Atlantic Power Corporation

  $ (33.0 ) $ (112.8 ) $ 79.8     –71 %

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Project Income (Loss) by Segment

 
  Year Ended December 31, 2013  
 
  East(1)   West(2)   Wind   Un-allocated
Corporate(3)
  Consolidated
Total
 

Project revenue:

                               

Energy sales

  $ 150.1   $ 81.6   $ 70.6   $ (0.1 ) $ 302.2  

Energy capacity revenue

    118.3     45.6         (0.2 )   163.7  

Other

    30.7     47.5     0.2     (0.2 )   78.2  

    299.1     174.7     70.8     (0.5 )   544.1  

Project expenses:

                               

Fuel

    135.0     59.2         0.1     194.3  

Operations and maintenance

    63.7     55.5     20.8     10.8     150.8  

Development

                7.2     7.2  

Depreciation and amortization

    68.9     54.9     41.8     0.5     166.1  

    267.6     169.6     62.6     18.6     518.4  

Project other income (expense):

                               

Change in fair value of derivative instruments

    25.5         24.0         49.5  

Equity in earnings of unconsolidated affiliates

    21.3     4.5     1.1         26.9  

Gain on sale of equity investments          

        30.4             30.4  

Interest expense, net

    (19.6 )   (0.1 )   (14.6 )   (0.1 )   (34.4 )

Impairment

    (30.8 )   (4.1 )           (34.9 )

Other (expense) income, net

    (2.1 )       (0.1 )   2.7     0.5  

    (5.7 )   30.7     10.4     2.6     38.0  

Project income (loss)

  $ 25.8   $ 35.8   $ 18.6   $ (16.5 ) $ 63.7  

 

 
  Year Ended December 31, 2012  
 
  East(1)   West(2)   Wind   Un-allocated
Corporate(3)
  Consolidated
Total
 

Project revenue:

                               

Energy sales

  $ 143.7   $ 70.8   $   $   $ 214.5  

Energy capacity revenue

    98.7     46.6     1.9         147.2  

Other

    25.1     41.6         1.4     68.1  

    267.5     159.0     1.9     1.4     429.8  

Project expenses:

                               

Fuel

    123.0     41.8     0.1         164.9  

Operations and maintenance

    52.8     53.3     1.0     12.5     119.6  

Development

                     

Depreciation and amortization

    61.6     54.9         0.1     116.6  

    237.4     150.0     1.1     12.6     401.1  

Project other income (expense):

                               

Change in fair value of derivative instruments

    (59.3 )               (59.3 )

Equity in earnings of unconsolidated affiliates

    27.5     (4.1 )   (8.2 )       15.2  

Gain on sale of equity investment          

        0.6             0.6  

Interest expense, net

    (16.4 )               (16.4 )

    (48.2 )   (3.5 )   (8.2 )       (59.9 )

Project income (loss)

  $ (18.1 ) $ 5.5   $ (7.4 ) $ (11.2 ) $ (31.2 )

(1)
Excludes the Florida Projects which are classified as discontinued operations.

(2)
Excludes Path 15 and Greeley which are classified as discontinued operations.

(3)
Excludes Rollcast which is designated as discontinued operations

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    East

        Project income for 2013 increased $43.9 million from 2012 primarily due to:

    increased project income from Kapuskasing of $37.4 million due primarily to a positive $35.8 million non-cash change in the fair value of gas purchase agreements that were accounted for as derivatives;

    increased project income from North Bay of $35.2 million due primarily to a positive $35.8 million non-cash change in the fair value of gas purchase agreements that were accounted for as derivatives;

    increased project income from Curtis Palmer of $4.0 million due primarily to increased generation resulting from higher water levels than the comparable period;

    increased project income from Calstock of $3.1 million due to increased capacity rates and generation, lower maintenance costs, and lower fuel costs than in the comparable 2012 period that had planned steam turbine maintenance; and

    increased project income from Nipigon of $2.6 million due primarily to higher availability and lower maintenance costs resulting from a planned outage in the comparable 2012 period.

        These increases were partially offset by:

    decreased project income from Kenilworth of $27.2 million due primarily to a $30.8 million non-cash goodwill impairment charge recorded in the third quarter of 2013;

    decreased project income from Chambers of $6.2 million due primarily to the collection of the DuPont partial settlement associated with the dispute of the electricity price calculation under its PPA in the second quarter of 2012; and

    decreased project income from Tunis of $5.5 million due primarily to lower generation and energy prices.

        Project income for the East segment excludes the Florida Projects as these projects were sold in April 2013, and are accounted for as a component of discontinued operations. Project loss for the Florida Projects was $1.1 million for the year ended December 31, 2013 as compared to project income of $13.6 million for the year ended December 31, 2012. The decrease is due primarily to the projects being sold in April 2013.

    West

        Project income for 2013 increased $30.3 million from 2012 primarily due to:

    increased project income from Gregory of $32.8 million primarily due to a $30.4 million gain on sale resulting from the project being sold in August 2013; and

    the sale of Badger Creek project in August in 2012 which had a $2.8 million project loss recorded in 2012.

        These increases were partially offset by:

    decreased project income of $3.7 million at Naval Station, Naval Training Center, and North Island due primarily to a $4.1 million non-cash goodwill impairment charge recorded in the third quarter of 2013; and

    decreased project income from Mamquam of $3.5 million primarily attributable to increased maintenance costs from a scheduled outage and lower revenues due to lower water levels than the comparable period.

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        Project income for the West segment excludes the Path 15 and Greeley projects which are accounted for as a component of discontinued operations. Project income for Path 15 was $2.1 million and $5.1 million for the years ended December 31, 2013 and 2012, respectively. The decrease is due primarily to the project being sold in April 2013. Project income for Greeley was $0.6 million and $1.8 million for the years ended December 31, 2013 and 2012, respectively. The decrease is due primarily to the project being sold in March 2014.

    Wind

        Project income for 2013 increased $26.0 million from 2012 primarily due to:

    increased project income from Rockland of $18.2 million attributable to the 100% consolidation of a former equity method project subsequent to an ownership change from 30% to 50% as part of the Ridgeline acquisition during the fourth quarter of 2012; and

    increased project income from Meadow Creek of $6.0 million which achieved commercial operations in December 2012. Meadow Creek was also part of the Ridgeline acquisition in December 2012. Meadow Creek's project income was primarily due to a positive $12.5 million non-cash change in the fair value of interest rate swap agreements that were accounted for as derivatives. This increase in income was offset by $8.1 million of interest expense.

    Un-allocated Corporate

        Total project loss increased $5.3 million from 2012 primarily due to $7.2 million of development expense at Ridgeline which was acquired in December 2012.

    Administrative and other expenses (income)

        Administrative and other expenses (income) include the income and expenses not attributable to our projects and are allocated to the Un-allocated Corporate segment. These costs include the activities that support the executive and administrative offices, capital structure, costs of being a public registrant, costs to develop future projects, interest costs on our corporate obligations, the impact of foreign exchange fluctuations and corporate tax. Significant non-cash items that impact Administrative and other expenses (income), which are subject to potentially significant fluctuations, include 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 the related deferred income tax expense (benefit) associated with these non-cash items.

    Administration

        Administration expense increased $6.9 million or 24% from 2012 primarily due to transactional fees during 2013 related to divestitures, the shareholder class action lawsuits and the amendment of the Prior Credit Facility in August as well as an increase in salaries and severance expenses.

    Interest, net

        Interest expense increased $14.3 million or 16% from 2012 primarily due to the issuance of the $130 million principal amount of convertible debentures in July of 2012 and issuance of the Cdn$100 million principal amount of convertible debentures in December of 2012 as well as interest related to the Prior Credit Facility.

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    Foreign exchange loss (gain)

        Foreign exchange gain increased $27.9 million primarily due to a $39.4 million increase in unrealized gain in the revaluation of instruments denominated in Canadian dollars, offset by a $4.1 million decrease in realized gains on the settlement of foreign currency forward contracts and a $7.4 million increase in unrealized loss on foreign exchange forward contracts. The U.S. dollar to Canadian dollar exchange rate was 1.0636 and 0.9949 at December 31, 2013 and 2012, respectively, an increase of 6.9% in 2013 compared to a decrease of 2.2% in 2012.

    Other income, net

        Other income, net increased $4.8 million or 84% from 2012 period primarily due to a $10.3 million gain on sale and management agreement termination fee resulting from the sale of Path 15. In 2012, we recorded a $6.0 million management agreement termination fee related to the sale of our equity interest in PERH.

    Income tax benefit

        Income tax benefit for the year ended December 31, 2013 was $19.5 million. Income tax benefit for the same period, based on the Canadian enacted statutory rate of 26%, was $9.7 million. The primary items impacting the effective tax rate relate to a benefit of $18.9 million from the 1603 Treasury Grants received in 2013, a $9.9 million benefit relating to foreign exchange differences, and $4.5 million related to production tax credits. These benefits were offset by a $12.1 million additional tax expense related to a change in the valuation allowance and an additional $13.6 million tax expense related to the goodwill impairment charge during 2013.

Project Operating Performance

        Two of the primary metrics we utilize to measure the operating performance of our projects are generation and availability. Generation measures the net output of our proportionate project ownership percentage in megawatt hours. Availability is calculated by dividing the total scheduled hours of a project less forced outage hours by the total hours in the period measured. The terms of our PPAs require our projects to maintain certain levels of availability. The majority of our projects were able to achieve substantially all of their respective capacity payments. For projects where reduced availability adversely impacted capacity payments, the impact was approximately $10.3 million for the year ended December 31, 2014. The terms of our PPAs provide for certain levels of planned and unplanned outages.

    Generation

 
  Year ended December 31,  
(in Net MWh)
  2014   2013   2012   % change
2014 vs. 2013
  % change
2013 vs. 2012
 

Segment

                               

East(1)

    3,966.2     3,889.0     3,533.4     2.0 %   10.1 %

West(2)

    2,432.8     2,455.9     2,006.9     –0.9 %   22.4 %

Wind

    1,800.3     1,749.6     221.7     2.9 %   NM  

Total

    8,199.3     8,094.5     5,762.0     1.3 %   40.5 %

(1)
Excludes the Florida Projects which are classified as discontinued operations.

(2)
Excludes (i) Delta-Person, which was sold in July 2014, (ii) Gregory, which was sold in August 2013 and (iii) Greeley, which was sold in March 2014 and is designated as discontinued operations.

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    Year ended December 31, 2014 compared with Year ended December 31, 2013

        Aggregate power generation for 2014 increased 1.3% from 2013 primarily due to:

    increased generation in the East segment due to a 123.5 net MWh increase in generation at Piedmont, which achieved commercial operations in April 2013, resulting in an additional quarter of generation in 2014, and a 45.4 MWh increase in generation at Orlando which was due to the expiration of an unfavorable natural gas contract in the comparable 2013 period, partially offset by a 151.6 net MWh decrease at Selkirk due to mild summer weather resulting in lower dispatch for the 2014 period; and

    increased generation in the Wind segment due to a 64.5 net MWh increase resulting from favorable winds at Meadow Creek.

        Generation did not change materially in our West segment for the year ended December 31, 2014.

    Year ended December 31, 2013 compared with Year ended December 31, 2012

        Aggregate power generation for 2013 increased 40.5% from 2012 primarily due to:

    increased generation in the East segment due to Piedmont, which achieved commercial operations in April 2013;

    increased generation in the West segment due to increased dispatch at Manchief and higher generation at Frederickson; and

    increased generation in the Wind segment primarily due to Canadian Hills which achieved commercial operations in December 2012 and Meadow Creek, which was acquired as part of the Ridgeline acquisition in December 2012.

    Availability

 
  Year ended December 31,  
 
  2014   2013   2012   % change
2014 vs. 2013
  % change
2013 vs. 2012
 

Segment

                               

East(1)

    93.6 %   95.6 %   96.3 %   –2.1 %   –0.7 %

West(2)

    91.7 %   91.8 %   93.1 %   –0.1 %   –1.4 %

Wind

    96.8 %   98.7 %   98.6 %   –1.9 %   0.1 %

Weighted average

    93.4 %   94.8 %   95.3 %   –1.5 %   –0.5 %

(1)
Excludes the Florida Projects which are classified as discontinued operations.

(2)
Excludes (i) Delta-Person, which was sold in July 2014, (ii) Gregory, which was sold in August 2013 and (iii) Greeley, which was sold in March 2014 and is designated as discontinued operations.

        Weighted average availability for 2014 decreased 1.5% to 93.4% from 2013 primarily due to:

    decreased availability in the East segment resulting from decreased availability at Nipigon, Chambers, and Orlando, each of which experienced planned maintenance outages in the year ended December 31, 2014; and

    decreased availability in the Wind segment due to Canadian Hills, which underwent a weather-related outage in the first quarter of 2014.

        Availability did not change materially in our West segment for the year ended December 31, 2014.

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    Year ended December 31, 2013 compared with Year ended December 31, 2012

        Weighted average availability for 2013 decreased 0.5% to 94.8% from 2012 primarily due to:

    decreased availability in the West segment resulting from decreased availability at Mamquam and Moresby Lake, which underwent scheduled maintenance during 2013; and

    decreased availability in the East segment resulting from decreased availability at Morris, which underwent scheduled maintenance during 2013.

        This decrease was partially offset by:

    increased availability in the Wind segment resulting from increased availability at Meadow Creek and Goshen, which were acquired in December 2012, as well as increased availability at Canadian Hills, which achieved commercial operations in December 2012.

        Generation and availability statistics for the East segment exclude the Florida Projects which are accounted for as a component of discontinued operations. Total generation for Auburndale was 916.5 MWh and availability was 94.8% for the year ended December 31, 2012. Total generation for Lake was 588.9 MWh and availability was 99.2% for the year ended December 31, 2012. Total generation for Pasco was 252.0 MWh and availability was 96.1% for the year ended December 31, 2012. Generation and availability statistics for the West segment exclude Greely, Delta-Person and Gregory, the totals of which are immaterial.

Supplementary Non-GAAP Financial Information

        A key measure we use to evaluate the results of our business is Free Cash Flow. Free Cash Flow 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 Free Cash Flow is a relevant supplemental measure of our ability to pay for additional debt reduction, fund internal or external growth, pay any dividends to our shareholders, or many other allocations of any available cash. A reconciliation of Free Cash Flow to cash flows from operating activities, the most directly comparable GAAP measure, is set out below under "Free Cash Flow." Free Cash Flow is comparable to Cash Available for Distribution, the non-GAAP measure we previously used to evaluate the results of our business. Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

        The primary factor influencing Free Cash Flow is cash distributions received from projects. These distributions are generally funded from Project Adjusted EBITDA generated by the projects, reduced by project-level debt service, capital expenditures, dividends paid on preferred shares of a subsidiary company, distributions to noncontrolling interests and adjusted for changes in project-level working capital and cash reserves. Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized under GAAP and does not have a standardized meaning prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We use Project Adjusted EBITDA to provide comparative information about project performance without considering how projects are capitalized or whether they contain derivative contracts that are required to be recorded at fair value. A reconciliation of Project Adjusted EBITDA to project income (loss) is provided under "Project Adjusted EBITDA" below and a reconciliation of Project Adjusted EBITDA by segment to project income (loss) by segment is provided in Note 22 to the consolidated financial statements of this Annual Report on Form 10-K. Project Adjusted EBITDA for our equity investments in unconsolidated affiliates is presented on a proportionately consolidated basis in the table below. Investors are cautioned that we may calculate this measure in a manner that is different from other companies.

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Project Adjusted EBITDA

 
  Year ended December 31,   $ change  
 
  2014   2013   2012   2014   2013  

Project Adjusted EBITDA by segment

                               

East(1)

  $ 158.5   $ 150.7   $ 145.7   $ 7.8   $ 5.0  

West(2)

    78.5     77.2     78.9     1.3     (1.7 )

Wind

    69.8     59.6     10.9     10.2     48.7  

Un-allocated Corporate(3)

    (7.5 )   (18.6 )   (11.1 )   11.1     (7.5 )

Total

    299.3     268.9     224.4     30.4     44.5  

Reconciliation to project income

   
 
   
 
   
 
   
 
   
 
 

Depreciation and amortization

    201.7     208.8     163.5     (7.1 )   45.3  

Interest expense, net

    39.5     38.5     24.0     1.0     14.5  

Change in the fair value of derivative instruments

    10.4     (50.3 )   56.6     60.7     (106.9 )

Impairment and other expense

    98.2     8.2     11.5     90.0     (3.3 )

Project (loss) income

  $ (50.5 ) $ 63.7   $ (31.2 ) $ (114.2 ) $ 94.9  

(1)
Excludes the Florida Projects which are classified as discontinued operations.

(2)
Excludes Path 15 and Greeley which are classified as discontinued operations.

(3)
Excludes Rollcast which is classified as discontinued operations.

    East

        The following table summarizes Project Adjusted EBITDA for our East segment for the periods indicated:

 
  Year ended December 31,  
 
  2014   2013   2012   % change
2014 vs. 2013
  % change
2013 vs. 2012
 

East

                               

Project Adjusted EBITDA

  $ 158.5   $ 150.7   $ 145.7     5 %   3 %

    Year ended December 31, 2014 compared with Year ended December 31, 2013

        Project Adjusted EBITDA for 2014 increased $7.8 million or 5% from 2013 primarily due to increases in Project Adjusted EBITDA of:

    $6.3 million at Morris due primarily to a $14.4 million increase in energy revenues. Energy payments were escalated under the terms of the project's PPA due to higher natural gas prices. This increase was partially offset by higher fuel expenses compared to the 2013 period;

    $6.3 million at Orlando primarily attributable to increased generation and higher energy revenues due to a change in revenue escalators in the amended off-taker contract as well as lower fuel expenses than the comparable 2013 period. Orlando operated under an above-market fuel agreement that expired in the fourth quarter of 2013;

    $4.4 million at Piedmont due primarily to $7.0 million of increased revenues offset by $3.5 million of increased fuel expense resulting from a full year of operation in 2014 as compared to the eight months in 2013 when it became commercially operational in April 2013; and

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    $2.5 million at Kapuskasing, $2.3 million at North Bay, and $2.1 million at Nipigon due to lower maintenance costs and increased energy revenue resulting from higher waste heat generation than the comparable 2013 period.

        These increases were partially offset by decreases in Project Adjusted EBITDA of:

    $10.5 million at Selkirk primarily attributable to lower energy revenue resulting from decreased generation due to lower dispatch from mild weather conditions during the 2014 period and expiration of its PPA in August 2014;

    $2.0 million at Chambers due to increased maintenance costs, partially offset by higher energy revenues resulting from increased dispatch than in the comparable 2013 period;

    $1.5 million at Kenilworth primarily attributable to lower steam revenue resulting from lower steam prices in the comparable 2013 period; and

    $1.3 million at Cadillac due to increased maintenance expenses resulting from a scheduled turbine maintenance outage in the 2014 period.

        Project Adjusted EBITDA for the East segment excludes the Florida Projects as these projects were sold in April 2013, and are accounted for as a component of discontinued operations. Project Adjusted EBITDA for the Florida Projects was $27.2 million for the year ended December 31, 2013.

    Year ended December 31, 2013 compared with Year ended December 31, 2012

        Project Adjusted EBITDA for 2013 increased $5.0 million or 3% from 2012 primarily due to increases in Project Adjusted EBITDA of:

    $4.0 million at Curtis Palmer primarily attributable to increased generation resulting from higher water levels than the comparable period and a $2.0 million favorable water reclamation tax assessment during 2013;

    $3.6 million at Kenilworth primarily attributable to increased capacity revenues under the renewal of the project's energy service agreement;

    $3.0 million at Calstock which had a steam turbine maintenance outage occur in the comparable 2012 period and contractual escalation of capacity rates in the 2013 period;

    $3.0 million at Selkirk due to energy revenues resulting from higher generation, partially offset by higher fuel costs; and

    $2.4 million at Kapuskasing primarily attributable to a steam turbine maintenance outage that occurred in the comparable 2012 period.

        These increases were partially offset by decreases in Project Adjusted EBITDA of:

    $7.2 million at Chambers primarily attributable to the collection of the DuPont partial settlement associated with the dispute of the electricity price calculation in the comparable 2012 period; and

    $4.0 million at Tunis resulting from lower generation and higher maintenance costs due to a scheduled maintenance outage.

        Project Adjusted EBITDA for the East segment excludes the Florida Projects as these projects were sold in April 2013, and are accounted for as a component of discontinued operations. Project Adjusted EBITDA for the Florida Projects was $27.2 million for the year ended December 31, 2013 as compared to $82.4 million for the year ended December 31, 2012.

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    West

        The following table summarizes Project Adjusted EBITDA for our West segment for the periods indicated:

 
  Year ended December 31,  
 
  2014   2013   2012   % change
2014 vs. 2013
  % change
2013 vs. 2012
 

West

                               

Project Adjusted EBITDA

  $ 78.5   $ 77.2   $ 78.9     2 %   –2 %

    Year ended December 31, 2014 compared with Year ended December 31, 2013

        Project Adjusted EBITDA for 2014 increased by $1.3 million or 2% from 2013 primarily due to increases in Project Adjusted EBITDA of:

    $3.8 million at Naval Training Center which underwent a scheduled turbine maintenance outage in the comparable 2013 period; and

    $3.6 million at Mamquam due to $0.9 million in higher revenues resulting from increased water flows as well as a $2.5 million decrease in maintenance expense compared to the 2013 period, during which the project underwent turbine maintenance.

        These increases were partially offset by decreases in Project Adjusted EBITDA of:

    $3.2 million at Gregory and Delta-Person, which were sold in August 2013 and July 2014, respectively;

    $2.2 million at Oxnard attributable to higher maintenance costs due to scheduled turbine maintenance than in the comparable 2013 period; and

    $2.0 million at Manchief attributable to lower dispatch than the comparable 2013 period.

        Project Adjusted EBITDA for the West segment excludes the Path 15 and Greeley projects which are accounted for as components of discontinued operations. Project Adjusted EBITDA for Path 15 was $9.0 million for the year ended December 31, 2013. Project Adjusted EBITDA for Greeley was $0.1 million and $1.5 million for the years ended December 31, 2014 and 2013, respectively. The decrease is due to the project being sold during the first quarter of 2014.

    Year ended December 31, 2013 compared with Year ended December 31, 2012

        Project Adjusted EBITDA for 2013 decreased by $1.7 million or 2% from 2012 primarily due to decreases in Project Adjusted EBITDA of:

    $3.4 million at Mamquam resulting from higher maintenance costs due to a scheduled outage and decreased revenues caused by lower water levels; and

    $2.2 million at Williams Lake due to lower energy revenues from contractual price decreases and higher maintenance costs than the comparable 2012 period.

        Project Adjusted EBITDA for the West segment excludes the Path 15 project which is accounted for as a component of discontinued operations. Project Adjusted EBITDA for Path 15 was $9.0 million and $24.5 million for the years ended December 31, 2013 and 2012, respectively. The decrease is due to the project being sold during the second quarter of 2013. Project Adjusted EBITDA for Greeley was $1.5 million and $3.2 million for the years ended December 31, 2014 and 2013, respectively. The decrease is due to the projects PPA expiring during the third quarter of 2013.

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    Wind

        The following table summarizes Project Adjusted EBITDA for our Wind segment for the periods indicated:

 
  Year ended December 31,
 
  2014   2013   2012   % change
2014 vs. 2013
  % change
2013 vs. 2012

Wind

                           

Project Adjusted EBITDA

  $ 69.8   $ 59.6   $ 10.9     17 % NM

    Year ended December 31, 2014 compared with Year ended December 31, 2013

        Project Adjusted EBITDA for 2014 increased by $10.2 million or 17% from 2013 primarily due to increases in Project Adjusted EBITDA of:

    $5.3 million at Meadow Creek, $2.0 million at Rockland, and $1.0 million at Canadian Hills primarily attributable to higher generation than in the comparable 2013 period.

    Year ended December 31, 2013 compared with Year ended December 31, 2012

        Project Adjusted EBITDA for 2013 increased by $48.7 million from 2012 primarily due to increases in Project Adjusted EBITDA of:

    $24.8 million at Canadian Hills which achieved commercial operations in December 2012;

    $14.0 million at Meadow Creek which was part of the Ridgeline acquisition and achieved commercial operations in December 2012;

    $6.8 million at Rockland attributable to the 100% consolidation of a former equity method project subsequent to an ownership change from 30% to 50% as part of the Ridgeline acquisition in December 2012; and

    $3.0 million at Goshen which was acquired as part of the Ridgeline acquisition in December 2012.

    Un-allocate Corporate

        The following table summarizes Project Adjusted EBITDA for our Un-allocated Corporate segment for the periods indicated:

 
  Year ended December 31,  
 
  2014   2013   2012   % change
2014 vs. 2013
  % change
2013 vs. 2012
 

Un-allocated Corporate

                               

Project Adjusted EBITDA

  $ (7.5 ) $ (18.6 ) $ (11.1 )   –60 %   68 %

    Year ended December 31, 2014 compared with Year ended December 31, 2013

        Project Adjusted EBITDA for 2014 increased by $11.1 million or 60% from the comparable 2013 period primarily due to decreased development costs at Ridgeline, which was acquired in December 2012, and a decrease in administrative costs related to administrative and development reduction initiatives undertaken during the year ended December 31, 2014.

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    Year ended December 31, 2013 compared with Year ended December 31, 2012

        Project Adjusted EBITDA for 2013 decreased by $7.5 million from 2012 primarily due to $7.2 million of administrative and development costs at Ridgeline which was acquired in December 2012.

    Free Cash Flow

        Free Cash Flow was ($55.6) million, $108.8 million, and $131.6 million for the years ended December 31, 2014, 2013, and 2012, respectively. Debt repayments of $58.4 million on the Partnership's term loan facility, increased project debt repayment of $10.6 million and increased purchases of property, plant and equipment of $6.9 million together with an $87.4 million reduction in cash flows from operations contributed to the decrease in Free Cash Flow. The net reduction of $87.4 million in cash flows from operations is due to interest expense related to the debt repayment and repurchase transactions in the first quarter of 2014, changes in working capital and the loss of cash flows from businesses that were divested in 2013.

        The $22.8 million decrease in Free Cash Flow for the year ended December 31, 2013 as compared to the same period in 2012 was positively impacted by the reduced cash dividends declared to shareholders as well as the inclusion of operating results from Canadian Hills and Meadow Creek, which achieved commercial operations in late December 2012. This was partially offset by lower operating cash flows as a result of the sale of the Florida Projects and Path 15 in April 2013. The decrease in cash flows from operating activities is discussed in-depth in the "Consolidated Cash Flows" section below.

        The table below presents our calculation of Free Cash Flow for the years ended December 31, 2014, 2013, and 2012, and the reconciliation to cash flows from operating activities, the most directly comparable GAAP measure:

 
  Years ended December 31,  
 
  2014   2013   2012  

Cash flows from operating activities

  $ 65.0   $ 152.4   $ 167.1  

Term loan facility repayments(1)

    (58.4 )        

Project-level debt repayments

    (26.2 )   (15.6 )   (19.6 )

Purchases of property, plant and equipment(2)

    (13.4 )   (6.5 )   (2.9 )

Distributions to noncontrolling interests(3)

    (11.0 )   (8.9 )    

Dividends on preferred shares of a subsidiary company

    (11.6 )   (12.6 )   (13.0 )

Free Cash Flow(4)

  $ (55.6 ) $ 108.8   $ 131.6  

(1)
Includes mandatory 1% annual amortization and 50% excess cash flow repayments by the Partnership under the Senior Secured Credit Facilities (as defined herein).

(2)
Excludes construction costs related to our Canadian Hills and Piedmont projects in 2014 and our Canadian Hills, Piedmont and Meadow Creek projects in 2013.

(3)
Distributions to noncontrolling interests include distributions to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland.

(4)
Free Cash Flow is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP. Therefore, this measure may not be comparable to similar measures presented by other companies. See "Supplementary Non-GAAP Financial Information" above. This table should be read together with the below table under "Consolidated Cash Flows" that sets forth Net cash provided by (used in) investing activities and Net cash (used in) provided by financing activities for the years ended December 31, 2014, 2013, and 2012.

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Consolidated Cash Flows

        The following table reflects the changes in cash flows for the periods indicated:

 
  Year ended
December 31,
   
 
 
  2014   2013   Change  

Net cash provided by operating activities

  $ 65.0   $ 152.4   $ (87.4 )

Net cash provided by investing activities

    68.7     147.1     (78.4 )

Net cash used in financing activities

    (182.4 )   (207.6 )   25.2  

Operating Activities

        Cash flow from our projects may vary from year to year based on working capital requirements and the operating performance of the projects, as well as changes in prices under PPAs, fuel supply and transportation agreements, steam sales agreements and other project contracts, and the transition to merchant or re-contracted pricing following the expiration of PPAs. Project cash flows may have some seasonality and the pattern and frequency of distributions to us from the projects during the year can also vary, although such seasonal variances do not typically have a material impact on our business.

        Cash flow from operating activities decreased $87.4 million for the year ended December 31, 2014 from the comparable period in 2013. The decrease in cash flows from operating activities is primarily due to (i) $46.8 million of interest expense related to make-whole, accrued interest and premium payments made in connection with the redemption of the Series A Notes, the Series B Notes, and the Curtis Palmer Notes (each as defined herein) and the repurchase of $140.1 million aggregate principal amount of the 9.0% Notes in the first quarter of 2014, (ii) a decrease in cash flows from operating activities from the Florida Projects and Path 15, which were sold in 2013 and (iii) a $65.7 million increase in cash outflows for working capital. The decrease in cash flows from working capital is primarily due to a $39.4 million decrease in working capital from the 2013 collection of security deposits related to our completed construction projects, such as Piedmont, Canadian Hills and Meadow Creek.

Investing Activities

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

        Cash flows provided by investing activities for the year ended December 31, 2014 were $68.7 million compared to cash flows provided by investing activities of $147.1 million for the year ended December 31, 2013. The change is due to $182.6 million in cash received for the sale of the Florida Projects, Path 15 and Gregory projects during the 2013 period, $103.2 million in treasury grant proceeds received for Meadow Creek and Piedmont in the year ended December 31, 2013, partially offset by a $166.3 million increase in the change in restricted cash primarily due to the release of the $75.0 million requirement under the prior credit facility, and a $39.3 million decrease of cash used in construction costs related to the Piedmont and Canadian Hills projects, which both completed construction and achieved commercial operations during 2013.

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Financing Activities

        Cash used in financing activities for the year ended December 31, 2014 resulted in a net outflow of $182.4 million compared to a net outflow of $207.6 million for the comparable 2013 period. The change from the prior year is due to a $79.0 million increase in net proceeds and payments on project-level and corporate debt attributable to the proceeds from the Senior Secured Credit Facilities (as defined herein) offset by repayments of the Series A Notes and Series B Notes and the Curtis Palmer Notes, and the repurchase of $140.1 million aggregate principal amount of the 9.0% Notes in the first quarter of 2014, $67.0 million decrease in payments for our revolving credit facility borrowings, offset partially by a $44.6 million decrease in equity contributions from noncontrolling interests at Canadian Hills received during the comparable 2013 period, a $36.2 million increase in deferred financing costs primarily due to the issuance of the Senior Secured Credit Facility in the first quarter of 2014, and a $20.8 million decrease in proceeds from project-level debt.

Liquidity and Capital Resources

 
  December 31,  
 
  2014   2013  

Cash and cash equivalents

  $ 109.9   $ 158.6  

Restricted cash(1)

    41.6     114.2  

Total

    151.5     272.8  

Revolving credit facility availability

    104.3     52.8  

Total liquidity

  $ 255.8   $ 325.6  

(1)
The decrease in restricted cash is primarily due to the release of the $75.0 million reserve requirement under the prior credit facility.

        Our primary source of liquidity is distributions from our projects and availability under our Revolving Credit Facility. Our liquidity depends in part on our ability to successfully enter into new PPAs at projects when PPAs expire or terminate. PPAs in our portfolio have expiration dates ranging from December 31, 2017 to December 31, 2037. When a PPA expires or is terminated, it may be difficult for us to secure a new PPA, if at all, or the price received by the project for power under subsequent arrangements may be reduced significantly. As a result, this may reduce the cash received from project distributions and the cash available for further debt reduction, identification of and investment in accretive growth opportunities (both internal and external), to the extent available, and other allocation of available cash. See "Risk Factors—Risks Related to Our Structure—We may not generate sufficient cash flow to pay dividends, if and when declared by our board of directors, service our debt obligations or implement our business plan, including financing external growth opportunities or fund our operations."

        We expect to reinvest approximately $35.0 million in our portfolio in the form of project capital expenditures and maintenance expenses in 2015. Such investments are generally paid at the project level. See "—Capital and Major Maintenance Expenditures." We do not expect any other material or unusual requirements for cash outflow in 2015 for capital expenditures or other required investments. We believe that we will be able to generate sufficient amounts of cash and cash equivalents to maintain our operations and meet obligations as they become due for at least the next 12 months.

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Corporate Debt Service Obligations

        The following table summarizes the maturities of our corporate debt at December 31, 2014:

 
  Maturity
Date
  Interest
Rates
  Remaining
Principal
Repayments
  2015   2016   2017   2018   2019   Thereafter  

Senior Secured Term Loan Facility(1)

  February 2021   4.75%-5.90%   $ 541.5   $ 5.4   $ 5.4   $ 5.4   $ 5.4   $ 5.4   $ 514.5  

Atlantic Power Corporation Notes(2)

  November 2018   9.0%     319.9                 319.9          

Atlantic Power Income LP Note

  June 2036   6.0%     181.0