Capital Power reports third quarter results

EDMONTON, Oct. 30 /CNW/ - Capital Power Corporation (Capital Power, or the Company) (TSX:CPX) released today its financial results for the third quarter of 2009. Net income for the third quarter 2009 was $14 million or $0.64 per share.

"Despite weak summer power prices in Alberta, our third quarter financial performance was in-line with our expectations," said Brian Vaasjo, President and Chief Executive Officer of Capital Power. "We continued to see good performance from our power plants with strong average generation plant availability of 95 per cent in the third quarter. At the Clover Bar Energy Centre, we commenced operations on a new 100-megawatt natural gas turbine in Unit 2. Based on the experience gained from the installation of Unit 2, we now expect to see Unit 3 come on-line in the first quarter of 2010, which is approximately six months ahead of schedule as well as being approximately $5 million lower than earlier estimates. Once completed, the Clover Bar facility will have a gross generation output of 243 megawatts."

"Our construction project at Keephills 3, jointly owned with TransAlta, continues to experience cost pressures which has resulted in an increase of approximately six per cent to our previous $1.8 billion total project costs estimate to $1.9 billion," continued Vaasjo. "The project schedule has also been delayed a few months with commercial operations now targeted for the second quarter 2011."

"We continue to take a leadership role in carbon capture and storage (CCS) technology through our partnership with TransAlta and Alstom Canada to develop one of the world's largest CCS projects (Project Pioneer) at the Keephills 3 plant that was announced earlier this month," stated Vaasjo. "The expected $780 million funding from the Province of Alberta and Government of Canada will help Project Pioneer work towards its goal of capturing one million tones of greenhouse gas emissions annually. In addition to Project Pioneer, we are committed to completing the front end engineering and design work on the Integrated Gasification Combined Cycle (IGCC) project at our Genesee facility. However, we do not intend to develop an IGCC facility at this time primarily because the technology is not economical in today's power price environment."

    
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    Operational and Financial Highlights(1)               Three months ended
     (unaudited)                                              Sept. 30, 2009
    -------------------------------------------------------------------------
    (millions of dollars except per share
     and operational amounts)
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    Electricity generation (GWh)                                       3,534
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    Generation plant availability (%)                                    95%
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    Revenues                                                            $525
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    Gross margin(2)                                                     $218
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    Operating margin(2)                                                 $169
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    Net income                                                           $14
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    Earnings per share                                                 $0.64
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    Dividends declared per share                                      $0.315
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    Funds from operations(2)                                             $93
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    Capital expenditures                                                $108
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    (1) The operational and financial highlights in this press release are
        derived from and should be read in conjunction with Management's
        Discussion and Analysis and the Interim Consolidated Financial
        Statements for the third quarter, 2009.
    (2) Gross margin, Operating margin and Funds from operations are non-GAAP
        financial measures and do not have standardized meanings under GAAP,
        and therefore, may not be comparable to similar measures used by
        other enterprises. Reconciliations to these non-GAAP financial
        measures to net income in the case of gross margin and operating
        margin, and cash provided by operating activities in the case of
        funds from operations are included at the end of this press release.

    Analyst Conference Call and Webcast
    -----------------------------------
    

Capital Power will be hosting a conference call and live webcast with analysts on November 2, 2009 at 11:00 am (ET) to discuss the third quarter results. The conference call dial-in numbers are: (416) 340-8061 or (866) 223-7781 (toll free). Interested parties may access the webcast on the Company's website at www.capitalpower.com. An archive of the webcast will be available on the website.

A replay of the conference call will be available following the call at: (416) 695-5800 or (800) 408-3053 (toll free) and entering pass code 2164117. The replay will be available until 11:59 p.m. (ET) on November 9, 2009.

    
    About Capital Power
    -------------------
    

Capital Power is a growth-oriented North American independent power producer, building on more than a century of innovation and reliable performance. The Company's vision is to be recognized as one of North America's most respected, reliable and competitive power generators. Headquartered in Edmonton, Alberta, Capital Power has interests in 31 facilities in Canada and the U.S. totaling approximately 3,400 megawatts of generation capacity. Capital Power and its subsidiaries develop, acquire and optimize power generation from a wide range of energy sources.

    
    Forward-Looking Statements
    --------------------------
    

This news release contains forward-looking statements, including "forward-looking statements" within the meaning of applicable Canadian and United States securities laws, as it relates to anticipated financial performance, events and strategies. Such forward-looking statements include, without limitation, (i) the expected timing of commercial operation and project costs of Keephills 3 and Clover Bar Energy Centre Unit 3; and (ii) expected funding from the Province of Alberta and Government of Canada on Project Pioneer. Where statements by Capital Power express or imply an expectation or belief as to future events or results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, forward-looking statements are subject to risks, uncertainties and other factors, which could cause actual results to differ materially from future results expressed, projected or implied by such forward-looking statements. Capital Power expressly disclaims any obligation to release publicly revisions to any forward looking statement to reflect events or circumstances after the date of this news release, or to reflect the occurrence of unanticipated events, except as may be required under applicable securities laws.

    
    Non-GAAP Financial Measures
    ---------------------------
    

The Company uses (i) gross margin, (ii) operating margin, and (iii) funds from operations as financial performance measures. These terms are not defined financial measures according to Canadian GAAP and do not have standardized meanings prescribed by GAAP, and therefore may not be comparable to similar measures used by other enterprises.

Gross margin and operating margin

Capital Power uses gross margin and operating margin to measure the operating performance of plants and groups of plants from period to period. A reconciliation of gross margin and operating margin to net income is as follows:

    
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    (unaudited, $ millions)                               Three months ended
                                                              Sept. 30, 2009
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    Revenues                                                             525
      Energy purchases and fuel                                          307
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    Gross margin                                                         218
      Operations, maintenance, and direct administration                  49
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    Operating margin                                                     169
      Deduct (add):
      Indirect administration                                             27
      Depreciation, amortization and asset retirement accretion           44
      Foreign exchange losses                                              3
      Net financing expenses                                              17
      Income taxes (reduction)                                            (2)
      Non-controlling interests                                           66
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    Net income                                                            14
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    Funds from operations and funds from operations excluding non-controlling
    interests in EPCOR Power L.P.
    

Capital Power uses funds from operations to measure the Company's ability to generate funds from current operations. Changes in working capital are primarily made up of intercompany payables and receivables between the Company and EPCOR and are not representative of how working capital is managed by the Company in this period of transition. Therefore, the Company uses funds from operations as its primary operating cash flow measure. The Company measures its interest in cash flows by excluding the non-controlling interest in EPCOR Power L.P.'s cash flows. A reconciliation of (i) funds from operations and (ii) funds from operations excluding non-controlling interests in EPCOR Power L.P., to cash provided by operating activities is as follows:

    
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    (unaudited, $ millions)                               Three months ended
                                                              Sept. 30, 2009
    -------------------------------------------------------------------------
    Funds from operations excluding non-controlling
     interests in EPCOR Power L.P.                                       $70
      Funds from operations due to non-controlling
       interests in EPCOR Power L.P.                                      23
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    Funds from operations                                                 93
      Change in non-cash operating working capital                       (40)
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    Cash provided by operating activities                                $53
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    CAPITAL POWER CORPORATION
    Interim Report
    September 30, 2009
    -------------------------------------------------------------------------
    

Management's Discussion and Analysis

This management's discussion and analysis (MD&A), dated October 30, 2009, should be read in conjunction with the unaudited interim consolidated financial statements of Capital Power Corporation and its subsidiaries for the three months ended September 30, 2009 and for the period from May 1, 2009, the date of incorporation, to September 30, 2009, the Supplemented PREP Prospectus (the Prospectus) of Capital Power Corporation dated June 25, 2009 for its initial public offering, the Company's Business Acquisition Report (BAR) dated September 16, 2009 and the cautionary statement regarding forward-looking information on page 36. In this MD&A, any reference to the Company or Capital Power, except where otherwise noted or the context otherwise indicates, means Capital Power Corporation, together with its subsidiaries. Financial information in this MD&A is based on the unaudited interim consolidated financial statements, which are prepared in accordance with Canadian generally accepted accounting principles (GAAP), and is presented in Canadian dollars unless otherwise specified. In accordance with its terms of reference, the Audit Committee of the Company's Board of Directors reviews the contents of the MD&A and recommends its approval by the Board of Directors. The Board of Directors has approved this MD&A.

Capital Power was incorporated on May 1, 2009 under the Canada Business Corporations Act as 7166575 Canada Inc. and changed its name to Capital Power Corporation pursuant to articles of amendment dated May 6, 2009. The Company became a reporting issuer under Canadian securities regulation on June 26, 2009. On July 9, 2009, the Company completed its initial public offering (IPO) and acquisition of power generation assets and operations (the Reorganization) from EPCOR Utilities Inc. (EPCOR), as described under Significant Events. The Company's outstanding share capital on September 30, 2009 consisted of 21.75 million common shares, 56.625 million special voting shares and one special limited voting share.

The Company commenced operations in July 2009 and its first fiscal year will end on December 31, 2009. Accordingly, the Company's financial statements for the interim period ended September 30, 2009 do not include prior year comparative information. In this MD&A, the Company's financial results for the three months ended September 30, 2009 are explained by comparisons with the results for the three months ended June 30, 2009 as reported in the unaudited pro forma consolidated financial information presented in Appendix B of the BAR dated September 16, 2009. The pro forma financial statements as at and for the three months ended June 30, 2009 are based on the unaudited interim combined and consolidated financial statements of EPCOR Power Group, being substantially all of the assets of the power generation business of EPCOR conducted by certain subsidiaries and interests of EPCOR, and reflect the effects of the completion of the IPO, the Reorganization and the use of the IPO proceeds as if the IPO and Reorganization were completed on January 1, 2008 for the pro forma consolidated income statement and on June 30, 2009 for the pro forma balance sheet.

Overview

The Company is among Canada's largest independent power generation companies (as measured by revenue, total assets and capacity), and owns or operates approximately 3,400 megawatts (MW) of power generating capacity in North America. The Company's facilities consist of 31 power plants with geographic, fuel source and counterparty diversification. Many of these facilities were built and commissioned by EPCOR over the last decade, providing the Company with development and construction experience and capability. The Company is constructing 595 MW of additional generation capacity at two locations, and has other projects in various stages of development which represent approximately 1,000 MW of future capacity.

The Company's performance in the third quarter of 2009 was in line with management's expectations. Plant availability averaged 95% in the third quarter compared with 93% in the previous quarter and plant output was also higher in the third quarter. The second unit at Clover Bar Energy Centre commenced operations in September and construction continued on the Company's major construction projects including Keephills 3, EPCOR Power L.P.'s North Carolina plants and the third unit at the Clover Bar Energy Centre. The separation of Capital Power's business operations from EPCOR and subsequent transition activities also went according to plan. Net income for the third quarter was $14 million which was $3 million higher than the net income in the second quarter as disclosed in the pro forma financial information.

Corporate Strategy

Capital Power's corporate strategy seeks to balance a strong financial position with targeted growth. The Company is committed to maintaining a stable dividend, an investment-grade credit rating supported by contracted cash flows, and a prudent expansion strategy.

The key components of Capital Power's corporate strategy are as follows:

Financial discipline

Capital Power is committed to a policy of financial discipline founded upon operational success, long-term contracting and targeted growth while maintaining an investment-grade credit rating. Capital Power believes that by maintaining a strong financial position with an appropriate dividend yield on its common shares, it will remain well positioned to access the capital markets to finance acquisitions or strategic development opportunities. To help achieve these objectives, Capital Power expects to continue to sell forward a significant portion of its generation output and capacity under long-term contracts.

Strong and sustainable growth

Capital Power has a pipeline of projects under construction or development. Building on the success of Genesee 3, the Company is expanding Clover Bar Energy Centre and building the Keephills 3 facility, representing 595 MW of new generation capacity, of which Capital Power has a 348 MW ownership interest. Clover Bar Energy Centre and Keephills 3 are expected to be fully operational in 2010 and 2011, respectively. The Company also has a number of other projects in various stages of development and it continues to evaluate acquisition prospects, primarily in the U.S., to strengthen its regional footprint and existing portfolio. As market conditions create new opportunities, the Company will capitalize on its experience to seek to acquire high quality assets.

Technology preference

In its selection of future power generation technologies Capital Power plans to capture economies of scale, accommodate emerging market supply and demand trends and further develop distinctive competencies. The Company expects to focus primarily on larger-scale, fossil fuel-fired technologies, supplemented by renewable facilities that are economically attractive and supportive of the Company's long-term contracting position. Fossil fuel-fired facilities will remain a core component of the Company's portfolio and Capital Power remains committed to being a leader in the development of technologies that establish or maintain economic or environmental advantages over other power generators.

Regional footprint

Capital Power intends to confine its regional footprint to Canada and the U.S. and seeks to enhance its regional diversification by focusing on a select group of target markets across Canada and the U.S. Capital Power uses a disciplined approach to selecting target regions with a preference for markets with favourable reserve margins and spark spreads, regulatory frameworks conducive to competitive power generation, sufficient scale to support the establishment of a Networked Hub of power facilities and liquid trading markets. Reserve margin means the difference between power demand during peak usage periods and the total supply of power available to meet this demand for a particular power market and is generally expressed as a percentage that is calculated as total supply less the peak demand divided by total supply. Spark spread means the theoretical difference between the price of electricity as the output and its energy cost of production.

Based on these criteria for selecting target region markets, Capital Power intends to maintain its existing strong position in Alberta and initially focus on developing additional hubs in the following three regions: Mid-Atlantic U.S., including the PJM (Pennsylvania, New Jersey and Maryland) Interconnection and the Virginia-Carolinas; the Northeast U.S., including the New York Independent System Operator and the New England Power Pool; and the Southwest U.S., including the California Independent System Operator and Desert Southwest (Arizona and Nevada). In addition, other markets will be considered on a case-by-case basis if opportunities arise for the development of contracted renewable facilities or for the replication of Capital Power's supercritical coal plant hubs with an attractive counterparty in a supportive regulatory environment. For example, Capital Power expects that long-term contracts from renewable projects will be achievable in both the Ontario and British Columbia markets.

    
    Continued focus on operational excellence, environmental and safety
    leadership
    

Capital Power's operational strategy is to safely manage, operate and maintain its power generation facilities in a manner that maximizes efficiency, productivity and reliability, and minimizes costs while reducing environmental impact. Capital Power is committed to maintaining its facilities' record of strong operational performance by continuing to plan and monitor the maintenance requirements of assets in order to ensure high levels of fleet availability. In addition, Capital Power is working with federal and provincial governments to develop technologies that will enhance the feasibility of near-zero emission coal-fired power generation. The Company also remains committed to a culture of zero injury and occupational illness.

Networked Hub strategy

The Company's Networked Hub strategy is to manage power generation assets at the hub level rather than at the individual facility level in order to be a cost-effective provider of electricity in the Company's markets. The foundation of this strategy is to establish generation hubs by acquiring larger-scale, fossil-fuel based power plants in the Company's markets. In order to reduce purchasing, warehousing, inventory and other costs, the Company seeks to standardize these plant types by fuel type and technology. The Company then seeks to enter into non-unit-specific contracts to provide it with flexibility in deploying its generation assets. The availability of physical generation from multiple sources in a market area provides the Company with the flexibility to better meet customer requirements and optimize its portfolio of assets in the Networked Hub in response to factors such as heat rate and commodity prices. Heat rate is the amount of combustible fuel (e.g. natural gas or coal) required to produce a unit of electricity. The Company believes that its approach of managing assets at the hub level improves efficiency and reduces risk through portfolio diversification.

Significant Events

Capital Power IPO closing

On July 9, 2009, Capital Power issued 21,750,000 common shares at $23.00 per share pursuant to the IPO. The proceeds from the IPO net of issue costs were approximately $475 million, of which approximately $468 million was used to purchase an approximate 27.8% equity interest in Capital Power L.P. (CPLP). CPLP purchased substantially all of the power generation assets of EPCOR in early July 2009 through the following series of transactions (the Reorganization):

    
    -   Formation of CPLP: Capital Power Corporation and Capital Power
        Holdings Inc., a wholly-owned subsidiary of Capital Power, formed
        CPLP. Capital Power Corporation acquired one general partner unit (GP
        Unit) and is the initial general partner of CPLP. Capital Power
        Holdings Inc. acquired one common limited partnership unit and as a
        result, became the initial limited partner in CPLP.

    -   Sale of EMCC Limited to Capital Power Corporation: EPCOR transferred
        all of the outstanding common shares of EMCC Limited to Capital Power
        Corporation in return for payment of approximately $468 million in
        cash.

    -   Contribution of Assets by EMCC Limited to CPLP: EMCC Limited
        contributed substantially all of its assets (consisting primarily of
        certain securities of subsidiary entities, its class B shares in the
        capital of EPLP Investments Inc. and a promissory note of EPLP
        Investments Inc.) to CPLP in return for 21.75 million GP Units.
        Capital Power Corporation transferred its GP Units in CPLP to EMCC
        Limited and as a result EMCC Limited became the general partner of
        CPLP.

    -   Sale of Assets by EPCOR Power Development Corporation (EPDC) to CPLP:
        EPDC transferred substantially all of its assets (consisting
        primarily of assets related to Genesee Units 1 and 2, the Genesee
        Coal Mine joint venture and certain interests in partnerships) to
        CPLP in return for 56.625 million exchangeable limited partnership
        units of CPLP and approximately $896 million in cash. CPLP financed
        the cash payment with the proceeds from a long-term debt obligation
        to EPCOR.

        Concurrently, EPDC subscribed for 56.625 million special voting
        shares of Capital Power for a nominal amount.
    

Immediately following completion of the Reorganization, Capital Power held approximately 27.8% of CPLP while EPCOR held 56.625 million exchangeable limited partnership units of CPLP (exchangeable for common shares of Capital Power on a one-for-one basis) representing approximately 72.2% of CPLP. Each exchangeable limited partnership unit is accompanied by a special voting share in the capital of Capital Power which entitles the holder to a vote at Capital Power shareholder meetings, subject to the restriction that such special voting shares must at all times represent not more than 49% of the votes attached to all Capital Power common shares and special voting shares, taken together. Capital Power and EPCOR have agreed that for so long as EPCOR holds not less than a 20% interest in the common shares of Capital Power, the number of directors will be not less than nine. The special voting shares also entitle EPCOR, voting separately as a class, to nominate and elect a maximum of four directors of Capital Power. There are currently twelve directors on Capital Power's board of directors. The general partner of CPLP is wholly-owned by Capital Power. Accordingly, Capital Power controls CPLP and therefore the operations of CPLP have been consolidated for financial statement purposes effective in July 2009.

Immediately following completion of the Reorganization, CPLP held 49% and EPCOR held 51% of the voting rights in EPLP Investments Inc. EPLP Investments Inc. owns the approximate 30.6% interest in EPCOR Power L.P. previously owned by EPCOR. However, CPLP is entitled to all of the economic interest in EPLP Investments Inc. Accordingly, effective in July 2009 Capital Power has consolidated the financial results of EPCOR Power L.P.

In July 2009, Capital Power entered into various agreements with EPCOR to provide for certain aspects of the separation of the business of Capital Power from EPCOR, to provide for the continuity of operations and services and to govern the ongoing relationships between the two entities and their subsidiaries.

Second new turbine at Clover Bar Energy Centre

On September 1, 2009, a new 100-megawatt (MW) natural gas-fired turbine commenced operations at our Clover Bar Energy Centre. The unit is the second of three new turbines being installed at the site and the net capacity upon completion of all three units will be 243 MW. The first unit, has a net capacity of 43 MW and commenced operation in the first quarter of 2008.

Subsequent Events

EPCOR Power Equity Ltd. $100 million preferred share issue

On October 13, 2009, EPCOR Power Equity Ltd. (EPEL), a subsidiary of EPCOR Power L.P., entered into a bought deal for the issuance of 4 million 7.0% cumulative rate reset preferred shares, Series 2 (the Series 2 Shares) at a price of $25.00 per share, for aggregate gross proceeds of $100 million (the Offering). The Series 2 Shares will pay fixed cumulative dividends of $1.75 per share per annum, as and when declared, for the initial five-year period ending December 31, 2014. The dividend rate will be reset on December 31, 2014 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield and 4.18%. The Series 2 Shares are redeemable at $25.00 per share by the Corporation on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of the Series 2 Shares will have the right to convert their shares into Cumulative Floating Rate Preferred Shares, Series 3 (Series 3 Shares) of the Corporation, subject to certain conditions, on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 3 Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the board of directors of the Corporation, at a rate equal to the sum of the then 90-day Government of Canada treasury-bill rate and 4.18%. The offering is expected to close on or about November 2, 2009, subject to certain conditions. The net proceeds will be used to repay outstanding bank indebtedness.

Changes to EPCOR Power L.P. distributions

On October 13, 2009, EPCOR Power L.P. announced a change in the frequency of its distributions to monthly from quarterly. Cash distributions of EPCOR Power L.P. for periods commencing after September 30, 2009 will be made in respect of each calendar month instead of the quarters ending March, June, September and December of each year.

EPCOR Power L.P. also announced the launch of a Premium Distribution(TM) and Distribution Reinvestment Plan (the Plan) that provides eligible unitholders with two alternatives to receiving the monthly cash distributions, including the option to accumulate additional units in EPCOR Power L.P. by reinvesting cash distributions in additional units at a 5% discount to the average market price of such units (as defined in the Plan) on the applicable distribution payment date. Under the Premium Distribution(TM) component of the Plan, eligible unitholders may elect to exchange these additional units for a cash payment equal to 102% of the regular cash distribution on the applicable distribution payment date.

Keephills 3 receives funding for carbon capture and storage

Keephills 3 is a joint development and equal ownership project of Capital Power and TransAlta Corporation (TransAlta) for the construction of a 495-MW supercritical coal-fired generation plant at TransAlta's Keephills site. As part of Keephills 3, Capital Power is partnering with TransAlta and Alstom Canada (Alstom) to develop one of the world's largest carbon capture and storage (CCS) projects, Project Pioneer (Pioneer). In October, 2009, a letter of intent was signed with the Province of Alberta under which Pioneer will be eligible to receive funding from the province's $2 billion CCS fund. The Government of Canada is also contributing toward the project through its Clean Energy Fund.

Using Alstom's chilled ammonia process, Pioneer will be designed to capture one million tonnes of greenhouse gas emissions annually. Keephills 3 was designed to reduce greenhouse gas emissions 18% compared with vintage facilities and Pioneer will deliver a further 31% reduction in Keephills 3's carbon dioxide (CO(2)) emissions. The second phase of front end engineering and design (FEED) for Pioneer is scheduled to be completed by June 2010 and will include detailed engineering and procurement planning. The development of Pioneer will not affect the construction schedule for Keephills 3.

Update on construction projects

As of October 30, 2009, the Board of Directors of CPC and TransAlta had approved additional funding and a revised schedule for the Keephills 3 project. The total project cost was revised from approximately $1.8 billion to approximately $1.9 billion and Capital Power's share was correspondingly revised from approximately $903 million to approximately $955 million. The increase primarily relates to additional labour required for the construction of the power island which is the portion of the plant that includes the turbine, boiler, air quality control system, water-treatment plant and control room. Commencement of the plant's commercial operations has been rescheduled from the first quarter of 2011 to the second quarter of 2011.

Construction of the final 100-MW unit at Clover Bar Energy Centre is ahead of schedule and the unit is now expected to commence operations in the first quarter of 2010 rather than the third quarter of 2010 as previously scheduled. The Company was able to capitalize on lessons learned during the construction of Unit 2 and the expected cost of all three units has been revised to approximately $278 million from approximately $284 million. The project will contribute to meeting the expected demand for additional peaking generation in Alberta and should add to the Company's cash flow once complete. In addition, these new high-efficiency units are designed to use 85% less water and produce 70% less nitrogen oxides (NOx) than the four turbines in the old Clover Bar plant which was decommissioned in 2007.

In addition to the Pioneer project, Capital Power is committed to completing the FEED work on its pre-combustion CCS project (the Genesee Integrated Gasification Combined Cycle (IGCC) power plant). The FEED project is being conducted in conjunction with the Canadian Clean Power Coalition, in partnership with the Alberta Energy Research Institute and Natural Resources Canada. However, Capital Power does not intend to develop an IGCC facility at this time, primarily because the technology is not economical in today's power price environment. Although, the IGCC project is no longer being considered for funding from the Province of Alberta's CCS fund, the FEED study results will provide a basis for potential future development of a gasification and CCS plant.

Summary of Financial and Other Information

The Company reports results of operations in the following categories: (i) Alberta commercial plants and portfolio optimization, (ii) Alberta contracted plants, (iii) Ontario and British Columbia contracted plants, (iv) EPCOR Power L.P. plants, and (v) other portfolio activities.

Alberta commercial plants and portfolio optimization

Alberta commercial plants and portfolio optimization consist of generation facilities for which the Company has not contracted substantially all of their power and capacity to third parties. This category includes the Company's directly-owned facilities located in Alberta consisting of Genesee 3, Joffre, Clover Bar Energy Centre, Taylor Coulee Chute, Clover Bar Landfill Gas Plant and Weather Dancer, and the Company's interests in the Battle River and Sundance Power Purchase Arrangements (acquired PPAs). The output of the plants, with the exception of Joffre, is sold by the Company into the open Alberta power market. Portfolio optimization includes (i) trading activities in the Alberta market undertaken primarily to manage the Company's exposure to electricity price movements, (ii) selling power contracts to competitive wholesale commercial and industrial customers, and (iii) managing the supply for rate-regulated tariff (RRT) customers of regulated retailers.

The Company seeks to maximize earnings from Alberta commercial plants and portfolio optimization by achieving high production from the facilities when it is economic to do so. It also actively manages the commodity price risk of its portfolio of assets and contracts by trading in a variety of financial and non-financial derivative instruments in the Alberta market with power generators, large energy-consuming entities and other trading counterparties. Credit limits are established and monitored for these counterparties.

Alberta contracted plants

Alberta contracted plants are comprised of the Genesee 1 and 2 generation facilities whose capacity and output are sold under a long-term Power Purchase Arrangement (PPA) with the Alberta Balancing Pool which expires in 2020. Under the PPA, the Alberta Balancing Pool has the right to dispatch the output from the generation facilities and it pays capacity payments, consisting of fixed operating and maintenance charges, and incentive/penalty payments based on targeted availability. The Company seeks to maximize earnings for contracted plants by achieving high availability of the plants and managing costs within the PPA terms.

Ontario and British Columbia contracted plants

Ontario and British Columbia contracted plants include the Kingsbridge and Port Albert wind farms in Ontario and the Brown Lake and Miller Creek hydro facilities in British Columbia. Revenues from these plants are earned under contracts with the Ontario Power Authority and BC Hydro and consist of sales of committed amounts of energy (firm energy sales) and sales of energy generated in excess of the firm commitment amount (excess energy sales).

EPCOR Power L.P. plants

EPCOR Power L.P. plants consist of a fleet of 20 facilities located in Canada and the U.S. with PPAs and fuel supply contracts that provide stable cash flows. The Company owns 30.6% of the limited partnership units of EPCOR Power L.P. and consolidates EPCOR Power L.P. in its financial statements. In this MD&A the EPCOR Power L.P. facilities are discussed on a combined basis rather than individually unless otherwise stated. EPCOR Power L.P.'s plants are all contracted.

Other portfolio facilities

Other portfolio activities include natural gas trading in Alberta and electricity trading in eastern Canada, the U.S. Northeast and the U.S. Pacific Northwest markets. The Company also holds retail and commercial natural gas customer contracts in Alberta but the Company is seeking opportunities to exit these natural gas contracts or allow them to expire as it no longer participates in the competitive natural gas retail market.

Unrealized changes in fair value of derivative instruments

The Company's financial results for the Alberta commercial plants and EPCOR Power L.P. plants include unrealized changes in the fair value of derivative instruments and natural gas inventory held for trading. The Company believes that these unrealized fair value changes are not representative of the instruments' or inventory's underlying economic value without considering them in conjunction with the economically hedged items to which they relate, such as natural gas required for future plant operations, future power sales, and future cash flows denominated in foreign currencies. While the changes in the fair value of the derivatives used to hedge the exposures are recognized in net income in each reporting period, the changes in the fair value of the associated economically hedged exposures are not. Accordingly, derivative instruments that are recorded at fair value for accounting purposes can produce volatility in net income as a result of changes in forward commodity prices, foreign exchange rates and interest rates which does not necessarily represent the underlying economics of the hedging transactions.

While the Company's net income can vary significantly from period to period due to fair value changes that the Company believes are not necessarily representative of the underlying economic performance of the business, the Company's cash flows are relatively stable. Accordingly, management views funds from operations as a key performance indicator since it highlights the key sources of cash generation and liquidity of the Company.

    
    Generation volume information

    -------------------------------------------------------------------------
    (unaudited, GWh)                                      Three months ended
                                                          Sept 30,   June 30,
    Electricity generation                                   2009       2009
    -------------------------------------------------------------------------
    Alberta commercial plants
     Genesee 3                                                470        464
     Joffre                                                    89         57
     Clover Bar Energy Centre 1 and 2(1)                       16          4
     Taylor Coulee Chute                                       12          7
     Clover Bar Landfill Gas                                    9          8
     Weather Dancer                                             -          1
    -------------------------------------------------------------------------
                                                              596        541
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    Alberta contracted plants                               1,638      1,623
    -------------------------------------------------------------------------
    Ontario and British Columbia contracted plants
      Kingsbridge 1 and Port Albert                            14         25
      Miller Creek                                             47         29
      Brown Lake                                               11         13
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                                                               72         67
    -------------------------------------------------------------------------
    EPCOR Power L.P. plants(2)                              1,228      1,030
    -------------------------------------------------------------------------
    Total                                                   3,534      3,261
    -------------------------------------------------------------------------
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    (1) Clover Bar Energy Centre includes Unit 2 as of its commercial
        operation date, September 1, 2009.
    (2) EPCOR Power L.P. plants exclude Castleton which was sold on May 26,
        2009.


    -------------------------------------------------------------------------
    (unaudited)                                           Three months ended
                                                          Sept 30,   June 30,
    Generation plant availability(1)                         2009       2009
    -------------------------------------------------------------------------
    Alberta commercial plants
      Genesee 3                                               97%        98%
      Joffre                                                  96%        82%
      Clover Bar Energy Centre 1 and 2(2)                     75%       100%
      Taylor Coulee Chute                                    100%       100%
      Clover Bar Landfill Gas                                 90%        83%
      Weather Dancer                                          55%        82%
    -------------------------------------------------------------------------
                                                              95%        94%
    -------------------------------------------------------------------------
    Alberta contracted plants
      Genesee 1                                              100%        99%
      Genesee 2                                               95%        99%
    -------------------------------------------------------------------------
                                                              97%        99%
    -------------------------------------------------------------------------
    Ontario and British Columbia contracted plants
      Kingsbridge 1 and Port Albert                           99%       100%
      Miller Creek                                            88%        97%
      Brown Lake                                              97%        97%
    -------------------------------------------------------------------------
                                                              94%        98%
    -------------------------------------------------------------------------
    EPCOR Power L.P. plants(3)                                93%        90%
    -------------------------------------------------------------------------
    Average(3)                                                95%        93%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Plant availability represents the percentage of time in the period
        that the plant was available to generate power, regardless of whether
        it was running, and therefore is reduced by planned and unplanned
        outages.
    (2) Clover Bar Energy Centre includes Unit 2 as of its commercial
        operation date, September 1, 2009.
    (3) Average generation plant availability is an average of individual
        plant availability weighted by owned or operated capacity.
    

The increase in electricity generation in the third quarter of 2009 over the previous quarter primarily relates to the Joffre plant and the northwestern U.S. plants owned by EPCOR Power L.P. The increase for Joffre was due to two planned outages in the second quarter compared with no planned outages in the third quarter. The increase for the northwestern U.S. plants primarily relates to the Frederickson plant which is subject to a tolling arrangement with three Washington Sate public utility districts (PUDs) whereby plant dispatch is determined by the PUDs. Availability at Clover Bar Energy Centre in the third quarter includes Unit 2 as of the date of commercial operation. The unit was declared unavailable when an operator was not on site which was during the off-peak hours when it was not economical to run. Its availability will increase once the unit can be operated remotely.

    
    Financial highlights

    -------------------------------------------------------------------------
    (unaudited, $ millions, except                        Three months ended
     earnings per share)                                  Sept 30,   June 30,
                                                             2009     2009(2)
    -------------------------------------------------------------------------
    Revenues                                                  525        537
    Gross margin(1)                                           218        250
    Operating margin(1)                                       169        176
    Net income                                                 14         11
    Earnings per share                                     $ 0.64
    Fully diluted earnings per share(3)                    $ 0.59
    Cash provided by operating activities(4)                    -
    Capital expenditures                                      108        125
    Long-term debt including current portion                1,771      1,762
    Total assets                                            4,918      4,853
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The consolidated financial information, except for gross margin and
        operating margin, has been prepared in accordance with Canadian GAAP.
        See Non-GAAP Financial Measures.
    (2) Financial highlights for the three months ended June 30, 2009 are as
        reported in the pro forma consolidated financial information included
        in the BAR.
    (3) Fully diluted earnings per share is calculated after giving effect to
        the exchanged limited partnership units of CPLP (exchangeable for
        common shares of Capital Power on a one-for-one basis) held by EPCOR.
    (4) The pro forma financial information does not include a statement of
        cash flows or earnings per share.


    Consolidated Net Income


    -------------------------------------------------------------------------
    (unaudited, $ millions)
    Net income for the three months ended June 30, 2009(1)              $ 11
    -------------------------------------------------------------------------
    Higher Alberta contracted plants operating margin           7
    Higher unrealized changes in the fair value of
     CPLP's derivative instruments and natural gas
     trading inventory held for trading                         5
    Lower unrealized changes in the fair value of EPCOR
     Power L.P.'s derivative instruments                      (21)
    Higher net financing expenses                              (9)
    Other                                                       3
    Lower income taxes                                         13
    --------------------------------------------------------------
                                                               (2)
    Lower (higher) non-controlling interests:
      - CPLP                                                   (4)
      - EPCOR Power L.P.                                       10
      - Preferred share dividends paid by subsidiary
         company                                               (1)
    -------------------------------------------------------------------------
    Increase in net income                                      3          3
    -------------------------------------------------------------------------
    Net income for the three months ended September 30, 2009            $ 14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net income for the three months ended June 30, 2009 is the pro forma
        consolidated net income as reported in the pro forma consolidated
        financial information included in the BAR.

    Net income increased $3 million for the quarter ended September 30, 2009
compared with the previous quarter due to the net impact of the following:

    -   The operating margin for the Alberta contracted plants was higher
        primarily due to transition costs incurred in the second quarter for
        the Reorganization.

    -   The unrealized changes in the fair value of CPLP's derivative
        instruments and natural gas inventory held for trading that were not
        designated as hedges for accounting purposes were higher primarily
        due to the impact of decreases in Alberta forward power prices on a
        net short position for these derivatives in the third quarter of
        2009.

    -   The unrealized changes in the fair value of EPCOR Power L.P.'s
        derivative contracts that were not designated as hedges for
        accounting purposes were lower primarily due to the impact of
        decreases in forward natural gas prices on the fair value of natural
        gas supply contracts.

    -   Financing expenses for the third quarter were in accordance with
        expectations. The $9 million variance from the pro forma financial
        information for the second quarter primarily relates to the
        allocation of the pro forma interest expense adjustment between the
        first and second quarters of 2009.

    -   Income taxes were lower primarily due to an out-of-period adjustment
        of $10 million recorded in the third quarter of 2009 to recognize net
        future income tax assets associated with EPCOR Power L.P.'s interest
        in Primary Energy Recycling Holdings LLC (PERH), an indirect
        subsidiary of EPCOR Power L.P. PERH is treated as a partnership for
        U.S. tax purposes and the adjustments are attributable to the
        allocation of tax deductions between EPCOR Power L.P. and PERH's
        other partner, Primary Energy Recycling Corporation (PERC), that were
        incorrectly calculated by PERH's external tax advisors for the
        relevant periods. Of the $10 million, $3 million is attributable to
        2007, $6 million is attributable to 2008 and $1 million is
        attributable to the six months ended June 30, 2009.

    -   Non-controlling interests reflect higher income from CPLP and lower
        income from EPCOR Power L.P. in the third quarter of 2009 compared
        with the second quarter of 2009.


    Results by Plant Category


    -------------------------------------------------------------------------
    (unaudited, $ millions)                               Three months ended
                                                          Sept 30,   June 30,
                                                             2009       2009
    -------------------------------------------------------------------------
    Revenues(2)
    Alberta commercial plants and portfolio optimization    $ 228      $ 233
    Alberta contracted plants                                  70         68
    Ontario and British Columbia contracted plants              4          4
    EPCOR Power L.P. plants                                   123        134
    Other portfolio activities                                 13         61
    Inter-plant category eliminations                         (10)         -
    -------------------------------------------------------------------------
                                                              428        500

    Unrealized fair value changes in derivative instruments
      - CPLP                                                   64          3
      - EPCOR Power L.P.                                       33         34
    -------------------------------------------------------------------------
                                                               97         37
    -------------------------------------------------------------------------
                                                            $ 525      $ 537
    -------------------------------------------------------------------------
    Gross margin(1)(2)
    Alberta commercial plants and portfolio optimization    $  50      $  55
    Alberta contracted plants                                  58         57
    Ontario and British Columbia contracted plants              4          4
    EPCOR Power L.P. plants                                    77         83
    Other portfolio activities                                  8          8
    Inter-plant category eliminations                          (8)        (2)
    -------------------------------------------------------------------------
                                                              189        205

    Unrealized fair value changes in derivative instruments
      - CPLP                                                   16         12
      - EPCOR Power L.P.                                       13         33
    -------------------------------------------------------------------------
                                                               29         45
    -------------------------------------------------------------------------
                                                            $ 218      $ 250
    -------------------------------------------------------------------------
    Operating margin(1)(3)
    Alberta commercial plants and portfolio optimization    $  41      $  39
    Alberta contracted plants                                  47         40
    Ontario and British Columbia contracted plants              3          3
    EPCOR Power L.P. plants                                    48         47
    Other portfolio activities                                  2          2
    Inter-plant category eliminations                          (1)         -
    -------------------------------------------------------------------------
                                                              140        131

    Unrealized fair value changes in derivative instruments
      - CPLP                                                   16         12
      - EPCOR Power L.P.                                       13         33
    -------------------------------------------------------------------------
                                                               29          5
    -------------------------------------------------------------------------
                                                            $ 169      $ 176
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The results by plant category, except for gross margin and operating
        margin, have been prepared in accordance with Canadian GAAP. See
        Non-GAAP Financial Measures.
    (2) Revenues and gross margin for the quarter ended June 30, 2009 are as
        reported in the pro forma consolidated financial information included
        in the BAR.
    (3) The Company commenced using operating margin as a measure of plant
        performance on July 1, 2009. Accordingly, the pro forma consolidated
        financial information for the three months ended June 30, 2009 has
        been restated to conform to the presentation adopted in the third
        quarter of 2009. See Non-GAAP Financial Measures.


    -------------------------------------------------------------------------
                                                          Three months ended
                                                          Sept 30,   June 30,
                                                             2009       2009
    -------------------------------------------------------------------------
    Spot Prices
    Alberta power ($/MWh)(1)                                49.49      32.30
    Eastern region power ($/MWh)(1)                         21.94      23.00
    Western region power (Mid-C) ($/MWh)(1)                 35.67      26.72
    Alberta natural gas (AECO) ($/Gj)(2)                     2.81       3.38
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Capital Power's Alberta portfolio captured power
     price ($/MWh)(1)(3)                                    53.85      57.60
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Megawatt hours (MWh)
    (2) Gigajoule (Gj). AECO means a historical virtual trading hub, located
        in Alberta, which is now known as the Nova Inventory Transfer System
        operated by TransCanada Pipelines Limited.
    (3) Captured power price represents the price realized on the Company's
        commercial contracted sales and portfolio hedging activities.
    

Alberta commercial plants and portfolio optimization

Alberta power prices averaged $49/MWh in the third quarter of 2009 compared with $32/MWh in the second quarter. The increase in the Alberta spot price was primarily due to planned outages in the province including Sundance 5 which is one of Capital Power's acquired PPAs. The Company's average realized price for commercial contracted sales and portfolio hedging activities was $54/MWh for the third quarter and $58/MWh in the second quarter. The captured power price decreased despite higher spot prices in the third quarter primarily because more of the volume in the second quarter was sold forward with lower exposure to spot prices.

Revenues and operating margin from the Alberta commercial plants and portfolio optimization decreased $5 million primarily due to the lower captured power price in the third quarter of 2009 compared with the previous quarter. Operating margin from Alberta commercial plants and portfolio optimization increased by $2 million primarily due to transition costs for the Reorganization and business development costs incurred in the second quarter.

Alberta contracted plants

Genesee 1 and 2 operated according to expectations in the third quarter of 2009 with financial results consistent with their results for the second quarter. There was a short unplanned outage at Genesee 2 in September due to a tube leak which had a small unfavourable impact on operating income. Revenues increased primarily due to a higher recovery from the Alberta Balancing Pool for greenhouse gas emission charges paid to the Alberta Electric System Operator. Operating expenses decreased primarily due to transition costs incurred in the second quarter for the Reorganization, partly offset by increased greenhouse gas emission charges.

Ontario and British Columbia contracted plants

The Ontario and British Columbia plants performed as expected in the third quarter of 2009.

EPCOR Power L.P. plants

Generation from the EPCOR Power L.P. plants increased in the third quarter of 2009 over the previous quarter primarily due to the Frederickson plant. The increase in generation had minimal impact on revenues because revenues for the Frederickson plant primarily consist of fixed capacity payments which are not dependent on the amount of generation. Revenues for the EPCOR Power L.P. plants decreased $10 million due to normal seasonal variances including lower water volumes at the hydro facilities and lower contractual prices for the power produced by the Ontario plants, partly offset by higher capacity payments under the Naval contracts and summer performance bonuses earned by all the California plants.

Fuel costs for the EPCOR Power L.P. plants decreased $5 million primarily due to lower natural gas prices. Operations and maintenance costs decreased $5 million primarily due to an annual maintenance outage at Williams Lake and repairs completed at the North Carolina plants in the second quarter.

Other portfolio activities

The 2009 third quarter financial results for other portfolio activities were in accordance with expectations and were consistent with the previous quarter. The $48 million decrease in revenues reflects a difference in accounting for the recognition of speculative physical natural gas trading. Capital Power records the gross margin earned on the settlement of these trades on a net basis in revenues whereas the unaudited pro forma consolidated financial information for the quarter ended June 30, 2009 reflects the gross amounts of revenue and cost of natural gas associated with these trades on the respective income statement lines.

    
    Unrealized changes in fair value of derivative instruments and natural
    gas inventory held for trading
    

Revenues and expenses for unrealized changes in the fair value of derivative instruments and natural gas inventory held for trading increased $60 million and $76 million, respectively in the quarter ended September 30, 2009 compared with the quarter ended June 30, 2009. The increases were primarily due to decreases in the forward electricity and natural gas prices relative to the prices of derivative energy sales and purchase contracts that were not designated as hedges for accounting purposes.

The gross margin for changes in the fair value of derivative instruments and natural gas inventory decreased $16 million in the quarter ended September 30, 2009 compared with the quarter ended June 30, 2009, primarily due to a decrease in the fair value of EPCOR Power L.P. natural gas supply contracts in the third quarter resulting from a decrease in forward natural gas prices. This was partly offset by a higher increase in the third quarter in the fair value of derivative electricity contracts that were not designated as hedges for accounting purposes resulting from a net short position for these contracts combined with decreases in forward Alberta power prices. On July 31, 2009, EPCOR Power L.P. designated certain of its natural gas supply contracts as hedges for accounting purposes. The fair value of these contracts increased $4 million in the period from August 1, 2009 to September 30, 2009 and this gain was recorded in other comprehensive income.

Consolidated Other Expenses

    
    -------------------------------------------------------------------------
    (unaudited, $ millions)                               Three months ended
                                                          Sept 30,   June 30,
                                                             2009       2009
    -------------------------------------------------------------------------
    Indirect administration(2)                                 27         29
    Depreciation, amortization and asset retirement
     accretion(1)                                              44         44
    Foreign exchange losses(1)                                  3          2
    Net financing(1)                                           17          8
    Income taxes (reductions)(1)                               (2)        11
    Non-controlling interests(1)
      - CPLP                                                   44         40
      - EPCOR Power L.P.                                       20         30
      - Preferred share dividends paid by EPEL(3)               2          1
    -------------------------------------------------------------------------
    (1) For the three months ended June 30, 2009, consolidated other
        expenses, except for indirect administration, are as reported in the
        pro forma consolidated financial information included in the BAR.
    (2) The pro forma consolidated financial information for the three months
        ended June 30, 2009 has been restated to conform to the presentation
        adopted in the third quarter where indirect administration is
        separated from plant results. See Non-GAAP Financial Measures.
    (3) EPEL is a subsidiary of EPCOR Power L.P. See Subsequent Events.
    

Indirect administration

Indirect administration expenses include the cost of support departments and services such as treasury, finance, internal audit, legal, human resources, corporate risk management and health and safety, as well as business development expenses including CCS and IGCC projects. In the third quarter of 2009, indirect administration expenses were slightly lower than the previous quarter primarily due to lower business development expenses.

Foreign exchange losses

Foreign exchange loss recorded during the quarter ended September 30, 2009 reflects the strengthening Canadian dollar relative to the U.S. dollar resulting in losses on the translation of U.S. monetary assets and liabilities of certain U.S. subsidiaries of the Company.

Net financing

Financing expenses for the third quarter of 2009 were in accordance with expectations. The $9 million variance from the pro forma financial information for the second quarter primarily relates to the allocation of the pro forma interest expense adjustment between the first and second quarters of 2009.

Income taxes

Income taxes for the third quarter of 2009 were lower than for the second quarter primarily due to a future income tax recovery recognized in the third quarter relating to adjustments in taxable income calculations for prior years for EPCOR Power L.P.

Non-controlling interests

The non-controlling interests in EPCOR Power L.P. reflect approximately 69.4% of the income from EPCOR Power L.P. which was lower in the third quarter of 2009 than the previous quarter. The non-controlling interests in CPLP reflect approximately 72.2% of the income from CPLP which was higher in the third quarter than the previous quarter.

Income from CPLP includes approximately 30.6% of the income from EPCOR Power L.P. Therefore the non-controlling interests in CPLP include 22.1% (72.2% of 30.6%) of the income from EPCOR Power L.P.

Non-GAAP Financial Measures

The Company uses (i) gross margin, (ii) operating margin, (iii) funds from operations, and (iv) funds from operations excluding non-controlling interests in EPCOR Power L.P. as financial performance measures. These terms are not defined financial measures according to Canadian GAAP and do not have standardized meanings prescribed by GAAP, and therefore may not be comparable to similar measures used by other enterprises. These measures should not be considered alternatives to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with Canadian GAAP. Rather, these measures are provided to complement Canadian GAAP measures in the analysis of the Company's results of operations from management's perspective.

Gross margin and operating margin

Capital Power uses gross margin and operating margin to measure the operating performance of plants and groups of plants from period to period. A reconciliation of gross margin and operating margin to net income is as follows:

    
    -------------------------------------------------------------------------
    (unaudited, $ millions)                               Three months ended
                                                          Sept 30,   June 30,
                                                             2009       2009
    -------------------------------------------------------------------------
    Revenues                                                  525        537
      Energy purchases and fuel                               307        287
    -------------------------------------------------------------------------
    Gross margin                                              218        250
      Operations, maintenance, and direct administration       49         74
    -------------------------------------------------------------------------
    Operating margin                                          169        176
      Deduct (add):
      Indirect administration                                  27         29
      Depreciation, amortization and asset retirement
       accretion                                               44         44
      Foreign exchange losses                                   3          2
      Net financing expenses                                   17          8
      Income taxes (reduction)                                 (2)        11
      Non-controlling interests                                66         71
    -------------------------------------------------------------------------
      Net income                                               14         11
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

In the Prospectus and BAR, the Company used adjusted earnings before foreign exchange, interest, income tax, depreciation and amortization and impairments (adjusted EBITDA) to measure plant operating performance. Commencing with the third quarter of 2009, the Company adopted operating margin rather than adjusted EBITDA to measure plant performance. Operating margin is more representative of plant performance as it excludes corporate administration and business development expenses (indirect administration).

    
    Funds from operations and funds from operations excluding non-controlling
    interests in EPCOR Power L.P.
    

Capital Power uses funds from operations to measure the Company's ability to generate funds from current operations. Changes in working capital are primarily made up of intercompany payables and receivables between the Company and EPCOR and are not representative of how working capital is managed by the Company in this period of transition. Therefore, the Company uses funds from operations as its primary operating cash flow measure. The Company measures its interest in cash flows by excluding the non-controlling interest in EPCOR Power L.P.'s cash flows. A reconciliation of (i) funds from operations and (ii) funds from operations excluding non-controlling interests in EPCOR Power L.P., to cash provided by operating activities is as follows:

    
    -------------------------------------------------------------------------
    (unaudited, $ millions)                               Three months ended
                                                              Sept. 30, 2009
    -------------------------------------------------------------------------
    Funds from operations excluding non-controlling
     interests in EPCOR Power L.P.                                     $  70
      Funds from operations due to non-controlling
       interests in EPCOR Power L.P.                                      23
    -------------------------------------------------------------------------
    Funds from operations                                                 93
      Change in non-cash operating working capital                       (40)
    -------------------------------------------------------------------------
    Cash provided by operating activities                              $  53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Balance Sheet


    -------------------------------------------------------------------------
    Changes in consolidated assets:
    June 30, 2009 and September 30, 2009
    -------------------------------------------------------------------------
                                                            Explanation of
    (unaudited,    June 30,     Acqui-   Increase  Sept 30,     increase
     $ millions)      2009      sition  (decrease)    2009     (decrease)
    -------------------------------------------------------------------------
    Cash and cash   $    -      $   71         (7)      64  Refer to cash
     equivalents                                            flows summary
                                                            below.
    -------------------------------------------------------------------------
    Accounts             -         233         35      268  Receivables from
     receivable                                             EPCOR for
     (including                                             operations during
     income taxes                                           transition and
     recoverable)                                           higher
                                                            receivables for
                                                            wholesale and RRT
                                                            sales and for
                                                            generation sales
                                                            to the Alberta
                                                            Balancing Pool
                                                            due to higher
                                                            power pool prices
                                                            in September
                                                            compared with
                                                            June.
    -------------------------------------------------------------------------
    Derivative           -         140          8      148  Increase in fair
     instruments                                            value of
     assets                                                 derivative
     (current)                                              instrument power,
                                                            natural gas and
                                                            forward foreign
                                                            exchange
                                                            contracts.
    -------------------------------------------------------------------------
    Other current        -          64          8       72  Increase in small
     assets                                                 parts,
                                                            consumables and
                                                            wood waste
                                                            inventories and
                                                            prepaid expenses.
    -------------------------------------------------------------------------
    Property, plant      -       3,163         36    3,199  Capital
     and equipment                                          expenditures
                                                            partly offset by
                                                            depreciation and
                                                            amortization
                                                            expense and the
                                                            impact of the
                                                            strengthening
                                                            Canadian dollar
                                                            on the
                                                            translation of
                                                            property, plant
                                                            and equipment
                                                            of U.S.
                                                            subsidiaries.
    -------------------------------------------------------------------------
    Power purchase       -         572        (36)     536  Amortization and
     arrangements                                           the impact of the
                                                            strengthening
                                                            Canadian dollar
                                                            on the
                                                            translation of
                                                            PPAs of U.S.
                                                            subsidiaries.
    -------------------------------------------------------------------------
    Contract             -         179          2      181
     and customer
     rights and
     other
     intangible
     assets
    -------------------------------------------------------------------------
    Derivative           -          74         64      138  Increase in the
     instruments                                            fair value of
     assets                                                 derivative power
     (non-current)                                          sales and forward
                                                            foreign exchange
                                                            contracts.
    -------------------------------------------------------------------------
    Future income        -          57        (17)      40  The net change in
     tax assets                                             future income tax
     (non-current)                                          assets and
                                                            liabilities was
                                                            primarily due to
                                                            the tax impact
                                                            of the
                                                            out-of-period
                                                            adjustment
                                                            relating to EPCOR
                                                            Power L.P.'s
                                                            investment in
                                                            PERH.
    -------------------------------------------------------------------------
    Goodwill             -         123         (4)     119
    -------------------------------------------------------------------------
    Other assets         -         122         (5)     117
    -------------------------------------------------------------------------
    Assets held
     for sale            -          36          -       36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Changes in consolidated liabilities and shareholders' equity:
    June 30, 2009 and September 30, 2009
    -------------------------------------------------------------------------
                                                            Explanation of
    (unaudited,    June 30,     Acqui-   Increase  Sept 30,    increase
     $ millions)      2009      sition  (decrease)    2009    (decrease)
    -------------------------------------------------------------------------
    Accounts        $    -      $  261     $   14   $  275  Accrued interest
     payable and                                            on long-term
     accrued                                                debt.
     liabilities
    -------------------------------------------------------------------------
    Derivative           -         143        (19)     124  Increase in the
     instruments                                            fair value of
     liabilities                                            natural gas
     (current)                                              supply contracts
                                                            and forward
                                                            foreign exchange
                                                            contracts.
    -------------------------------------------------------------------------
    Other current        -          10         16       26  The net change in
     liabilities                                            future income tax
                                                            assets and
                                                            liabilities was
                                                            primarily due to
                                                            the tax impact of
                                                            the out-of-period
                                                            adjustment
                                                            relating
                                                            to EPCOR Power
                                                            L.P.'s investment
                                                            in PERH.
    -------------------------------------------------------------------------
    Long-term debt       -       1,761         10    1,771  Draws on credit
     (including                                             facilities,
     current                                                partly offset by
     portion)                                               the impact of
                                                            foreign currency
                                                            translation on
                                                            EPCOR Power
                                                            L.P.'s U.S.
                                                            dollar debt and
                                                            scheduled
                                                            repayments of
                                                            long-term debt
                                                            payable to EPCOR.
    -------------------------------------------------------------------------
    Derivative           -          64         31       95  Decrease in the
     instruments                                            fair value of
     liabilities                                            natural gas
     (non-current)                                          supply and
                                                            derivative power
                                                            contracts, partly
                                                            offset by an
                                                            increase in the
                                                            fair value of
                                                            forward foreign
                                                            exchange
                                                            contracts.
    -------------------------------------------------------------------------
    Other
     non-current
     liabilities         -          99          -       99
    -------------------------------------------------------------------------
    Future income        -          93        (34)      59  The net change in
     tax                                                    future income tax
     liabilities                                            assets and
     (non-current)                                          liabilities was
                                                            primarily due to
                                                            the tax impact of
                                                            the out-of-period
                                                            adjustment
                                                            relating to EPCOR
                                                            Power L.P.'s
                                                            investment in
                                                            PERH.
    -------------------------------------------------------------------------
    Non-controlling       -      1,935         40    1,975  Non-controlling
     interests                                              interests' share
                                                            of CPLP and EPCOR
                                                            Power L.P. net
                                                            income and other
                                                            comprehensive
                                                            income, partly
                                                            offset by
                                                            non-controlling
                                                            interests' share
                                                            in EPCOR Power
                                                            L.P.
                                                            distributions.
    -------------------------------------------------------------------------
    Shareholders'        -         477         17      494  Net income and
     equity                                                 other
                                                            comprehensive
                                                            income.
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Liquidity and Capital Resources


    -------------------------------------------------------------------------
    Cash inflows (outflows)
    -------------------------------------------------------------------------
                         Three months ended
                            Sept 30, 2009
                  -------------------------------
                   Acquisition
    (unaudited,        and
     $ millions)  reorganization  Other    Total
    -------------------------------------------------------------------------
    Funds from
     Operations(1)    $    -     $   93   $   93

    Investing         (1,293)      (108)  (1,401)  Capital expenditures,
                                                   primarily for property
                                                   plant and equipment.

    Financing          1,456        (41)   1,415   Acquisition and
                                                   reorganization - issue of
                                                   long-term debt and common
                                                   shares, net of issue
                                                   costs.

                                                   Other - scheduled
                                                   repayments of long-term
                                                   debt.
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Cash inflows and outflows, except funds from operations, have been
        prepared in accordance with Canadian GAAP. See Non-GAAP Financial
        Measures.
    

Upon closing of the IPO, CPLP had credit facilities of approximately $1,220 million, of which $500 million may be utilized for issuing letters of credit. On September 30, 2009, $1,052 million remained available under these facilities. Also on September 30, 2009, EPCOR Power L.P. had revolving credit facilities of approximately $366 million, of which $224 million remained available and Capital Power had an undrawn bank line of credit of $5 million.

Upon closing of the IPO, CPLP had obligations to pay $943 million pursuant to long-term debt agreements and on June 30, 2009 EPCOR Power L.P. had obligations to pay $811 million pursuant to long-term debt agreements. In September, CPLP made a $39 million repayment on the long-term debt owing to EPCOR. Long-term debt outstanding at September 30, 2009 consisted of the following:

    
    -------------------------------------------------------------------------
                              Carrying
                                amount                      Nominal interest
    (unaudited)            ($ millions)   Maturity date                 rate
    -------------------------------------------------------------------------
    Long-term debt payable      $  876     Ranging from         Ranging from
     to EPCOR                              2009 to 2018       5.80% to 9.00%


    Joffre Cogeneration             48    2020 and 2016      Fixed 8.59% and
     and Brown Lake project                                        8.70% and
     non-recourse financing                                       floating(1)

    CPLP revolving
     extendible credit
     facilities                     77             2011                0.40%

    EPCOR Power L.P.               786     Ranging from   Fixed ranging from
     long-term debt                        2009 to 2036      5.87% to 11.25%
                                                              and floating(1)
    -------------------------------------------------------------------------
                                $1,787
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Floating interest rates are a function of the prevailing bankers'
        acceptance rates
    

CPLP will be required to make principal repayments of $247 million in 2010 under terms of its long-term debt agreements. The long-term debt payable to EPCOR was issued in connection with the Reorganization pursuant to a credit agreement entered into by CPLP and EPCOR on July 9, 2009. Some of the indebtedness of CPLP to EPCOR mirrors certain debt obligations of EPCOR to the public and has repayment and interest rate terms that correspond with EPCOR's mirrored debt. The remainder of the indebtedness of CPLP to EPCOR includes an amount sufficient to meet certain debt obligations of EPCOR to The City of Edmonton, and will be repaid in accordance with an amortization schedule. On or after December 2, 2012, if EPCOR no longer owns, directly or indirectly, at least 20% of the outstanding limited partnership units of CPLP, then EPCOR may, by written notice to CPLP, require repayment of all or any portion of the outstanding principal amount under the credit agreement and accrued interest thereon, within 180 to 365 days depending on the amount outstanding. The long-term debt payable to EPCOR requires CPLP to meet certain financial covenants under the credit agreement.

CPLP's credit facilities include an extendible revolving syndicated bank credit facility (Syndicated Facility) of up to $700 million with an initial term of three years and an extendible revolving club credit facility (Club Facility) of up to $500 million with an initial 364 day period following which any drawn portion of the facility will convert into a non-revolving facility for a one year term-out period. Borrowings and repayments under the Club Facility will be made by CPLP with each lender on an individual lender basis up to that lender's commitment, and not on a pro-rata basis. The terms of these credit facilities include financial covenants and provisions for default and change of control, as more fully described in the Prospectus. Capital Power also has revolving demand credit facilities totaling $25 million.

At September 30, 2009, EPCOR Power L.P.'s credit facilities included two revolving facilities of $100 million each with terms expiring in September 2010 and October 2011, and a revolving facility of $125 million expiring in June 2011. In October, the facility expiring in 2010 was extended by one year to September 2011. The two $100 million facilities were also amended in October 2009 to add a U.S. co-borrower to facilitate funding of capital expenditures at the partnership's U.S. plants. EPCOR Power L.P. also has two demand facilities, one for $20 million and the other for US$20 million.

The committed bank credit facilities are expected to be used primarily for the purposes of providing funds for capital expenditures, letters of credit and general corporate purposes. Letters of credit are issued to meet conditions of certain debt and service agreements, to meet the credit requirements of energy market participants and to satisfy legislated reclamation requirements. On September 30, 2009, EPCOR Power L.P. had $142 million of long-term debt borrowings and less than $1 million of letters of credit outstanding under its credit facilities. At September 30, 2009, CPLP had $77 million of debt and $90 million of letters of credit outstanding under its credit facilities.

CPLP's corporate credit rating provided by S&P and DBRS is BBB. The BBB debt rating is S&P's and DBRS' 4th highest rating out of ten rating categories. According to the S&P rating system, debt rated BBB exhibits adequate protection parameters. According to the DBRS rating system, an obligation rated BBB is of an adequate credit quality with the protection of interest and principal considered to be acceptable.

Further information respecting the credit ratings assigned by these agencies is included in the Prospectus. Having an investment grade credit rating impacts CPLP's ability to re-finance existing debt as it matures and to access cost competitive capital for future growth.

    
    -------------------------------------------------------------------------
    (unaudited, $ millions)                               Three months ended
                                                              Sept. 30, 2009
    -------------------------------------------------------------------------
    Capital expenditures
    Keephills 3                                                       $   60
    EPCOR Power L.P.'s North Carolina plants enhancement
     project                                                              24
    Clover Bar Energy Centre                                               8
    EPCOR Power L.P.'s Oxnard plant turbine replacement                    4
    Other                                                                 12
    -------------------------------------------------------------------------
    Total capital expenditures                                        $  108
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

Capital spending in the third quarter of 2009 included expenditures for the Keephills 3 and Clover Bar Energy Centre projects which are described under Subsequent Events. EPCOR Power L.P.'s enhancement project for its Southport and Roxboro plants in North Carolina is nearing completion of the installation phase and the project is expected to be in service by the end of 2009. The enhancements will reduce the plants' environment emission levels and improve their economic performance. EPCOR Power L.P. is also pursuing a project for the repowering of the natural gas turbine at the Oxnard plant which is scheduled to be completed in 2010. The Company's other capital expenditures for the third quarter of 2009 included plant maintenance capital expenditures.

Future cash requirements - excluding EPCOR Power L.P.

Capital Power's estimated cash requirements for the fourth quarter of 2009, excluding EPCOR Power L.P.'s cash requirements, are expected to include approximately $84 million for capital expenditures, approximately $18 million for CPLP distributions to EPCOR, and approximately $7 million for Capital Power's quarterly dividend payable on October 30, 2009. The dividend of $0.315 per share was declared by the Board of Directors on July 17, 2009. The major project expenditures in 2009 are expected to be for the Keephills 3 and Clover Bar Energy Centre construction projects. If total cash requirements for the fourth quarter of 2009 remain as planned, the sources of capital will be cash on hand, cash provided by operating activities, distributions from EPCOR Power L.P. and the use of existing credit facilities. For the longer term, the Company expects to use the same sources of capital as well as new public debt or equity offerings if required. If future distributions from EPCOR Power L.P. decline, it could negatively impact the Company's cash flow.

Future cash requirements - EPCOR Power L.P.

EPCOR Power L.P.'s estimated cash requirements for the fourth quarter of 2009 are expected to include approximately $33 million for capital expenditures on the Roxboro and Southport projects and approximately $40 million for distributions. If its total cash requirements for the fourth quarter of 2009 remain as planned, the sources of capital will be cash on hand, cash provided by operating activities, the net proceeds of the preferred share offering of EPEL, which is discussed under Subsequent Events, and the use of existing credit facilities. If required, other sources of capital for 2009 or subsequent years could include additional public or private debt borrowings or additional public equity market offerings.

Although liquidity in the financial markets has improved in recent months, financial market stability remains an issue. If the instability in the Canadian and U.S. financial markets continues, it may adversely affect Capital Power's ability to raise new capital, to meet its financial requirements and to refinance indebtedness under existing credit facilities and debt agreements at their maturity dates. In addition, Capital Power has credit exposure with a number of counterparties to various agreements, most notably its PPA, trading and supplier counterparties. While the Company continues to monitor its exposure to its significant counterparties, there can be no assurance, particularly in light of the current economy, that all counterparties will be able to meet their commitments.

Contractual Obligations

Capital Power's contractual obligations at September 30, 2009 were as follows:

    
    -------------------------------------------------------------------------
                                     Payments Due by Period
    -------------------------------------------------------------------------
    (unaudited,          Fourth                            2013 and
     $ millions)        quarter                              there-
                           2009     2010     2011     2012    after    Total

    Acquired PPA
     obligations(1)      $   31   $   90   $   89   $  101   $1,249   $1,560

    Capital projects(2)     120      290       20        -        -      430

    Energy purchase and
     transportation
     contracts(3)(4)         56      113       93       78      269      609

    Operating and
     maintenance
     contracts(5)             7       28       28       28      155      246

    Operating leases          -        2        1        4       74       81

    Forward foreign
      exchange contracts
      and commodity
      contracts-for-
      differences            38       69       42        5        3      157

    Long-term debt            1      247      376      104    1,051    1,779

    Interest on
     long-term debt(6)       28       95       84       67      511      785

    Asset retirement
     obligations(7)           2        8        9        9      349      377

    Loan commitments          6        -        -        -        -        6
    -------------------------------------------------------------------------
    Total                $  289   $  942   $  742   $  396   $3,661   $6,030
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Capital Power's obligation to make payments on a monthly basis for
        fixed and variable costs under the terms of its acquired PPAs will
        vary depending on generation volume and scheduled plant outages.
    (2) Capital Power's obligations for capital projects including Keephills
        3 and Clover Bar Energy Centre construction and EPCOR Power L.P.'s
        Roxboro, Southport, North Island and Oxnard facility enhancements.
        The obligations for Keephills 3 and Clover Bar Energy Centre include
        the revisions approved in October 2009 as discussed under Subsequent
        Events.
    (3) The natural gas purchase contracts have fixed and variable
        components. The variable components are based on estimates subject to
        variability in plant production. These contracts have expiry terms
        ranging from 2010 to 2016 with built-in escalators in the contracts'
        terms for pricing.
    (4) The natural gas transportation contracts are based on estimates
        subject to changes in regulated rates for transportation and have
        expiry terms ranging from 2011 to 2017.
    (5) Operating and maintenance contracts are based on fixed fees subject
        to annual escalators and have expiry terms ranging from 2017 to 2018.
    (6) Repayments of bankers' acceptances outstanding under CPLP's and EPCOR
        Power L.P.'s extendible credit facilities at September 30, 2009, are
        reflected in the year of the maturity of the respective credit
        facility.
    (7) Capital Power's asset retirement obligations reflect the undiscounted
        cash flow required to settle obligations for the retirement of its
        generation plants and Genesee coal mine.
    

Off-balance Sheet Arrangements

As at September 30, 2009, the Company had no off-balance sheet arrangements which were required to be disclosed in accordance with applicable securities regulations.

Related Party Transactions

EPCOR, including its subsidiaries is the only related party with which the Company had material transactions in the third quarter of 2009. The Company's acquisition of power generation assets from EPCOR in July 2009 was recorded at cost for the non-controlling interests' approximate 72.2% share of the transaction and at fair value for Capital Power's approximate 27.8% interest in the transaction. The acquisition is described under Significant Events. As part of the Reorganization, the Company issued 56.625 million special voting shares and one special limited voting share to EPCOR for $57 million. In the second quarter, the Company issued one special limited voting share to EPCOR for one dollar. The special limited voting share entitles EPCOR to the right to vote as a class on any matter that would: (i) change the location of Capital Power's head office to a place other than The City of Edmonton in the Province of Alberta; (ii) amend the articles of Capital Power to, or result in a transaction that would, in each case, impact the location of the head office or its meaning as defined in Capital Power's articles; or (iii) amend the rights attaching to the special limited voting share. Also, as part of the Reorganization, the Company borrowed $918 million of long-term debt, including $22 million of fair value increments, of which $39 million was repaid in the third quarter of 2009 as discussed under Liquidity and Capital Resources, and $3 million of the fair value increment was amortized. The terms and interest rates of this debt mirror the debt payable by EPCOR or provide for sufficient payments to EPCOR to allow it to meet its debt obligations to The City of Edmonton. The interest incurred on the Company's long-term debt payable to EPCOR was $15 million for the third quarter of 2009, of which $9 million was capitalized as property, plant and equipment for construction work in progress and the remainder was included in net financing expense.

The Company entered into various agreements with EPCOR to provide for certain aspects of the separation of the business of Capital Power from EPCOR, to provide for the continuity of operations and services and to govern the ongoing relationships between the two entities and their subsidiaries. These transactions are in the normal course of operations and are recorded at the exchange values which are based on normal commercial rates.

The Company's revenues for power sold to EPCOR for resale to its customers were $99 million in the third quarter of 2009. The Company's purchases of distribution and transmission services from EPCOR were $6 million. The Company also contributed $7 million to EPCOR for the construction of aerial and underground transmission lines.

At September 30, 2009, the balances resulting from transactions with EPCOR were as follows:

    
    -------------------------------------------------------------------------
    (unaudited, $ millions)                                    Sept 30, 2009
    -------------------------------------------------------------------------
    Balance sheet
    Accounts receivable                                               $   60
    Other assets                                                           7
    Property, plant and equipment                                          9
    Accounts payable - accrued interest on debt                           12
    Long-term debt (including current portion)                           876
    Share capital                                                          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

Outlook

As discussed in the management's discussion and analysis of financial condition and results of operations included in the Prospectus, commencing in 2006, management's strategy has been to sell its Battle River PPA and a portion of its interest in the Sundance PPA and replace this power output with power produced from its own new physical facilities. Interests in the PPAs were sold over the period from 2006 to 2009 with the remaining 15% interest in the Battle River PPA expected to be sold in January 2010. These disposals precede the addition of the new facilities as Clover Bar Unit 1 commenced operations in 2008, followed by Unit 2 in the third quarter of 2009. Clover Bar Unit 3 is expected to be commissioned in 2010 followed by Keephills 3 in 2011. Accordingly, the Company's operating margin and cash flow from operations are expected to be negatively impacted by the Company's reduced interests in PPAs in 2009 and 2010 and are expected to increase as the new facilities come on line in 2010 and 2011.

Alberta forward power prices are expected to remain low in the fourth quarter of 2009 mainly due to low natural gas prices. Consistent with the third quarter results, lower power prices are expected to reduce operating margin (excluding unrealized fair value adjustments), and cash flow from operations for the fourth quarter of 2009 as approximately half of the Company's Alberta commercial portfolio is exposed to the spot market. The remainder has been sold forward at an average price in the low-$60/MWh range. The Alberta commercial plants represent approximately 40% to 50% of operating margin excluding unrealized fair value changes and the non-controlling interest in EPCOR Power L.P.

For 2010, a significant portion of the Alberta commercial portfolio position has been sold forward at an average price in the mid-$60/MWh range which should reduce the exposure to changes in power prices. For 2011, the Alberta commercial portfolio's open position is expected to increase to approximately 60% of the total portfolio which could introduce more variability in operating margin, excluding unrealized fair value adjustments, and cash flow depending on changes in power prices. The average contracted price is in the low-$70/MWh range for the generation sold forward in 2011. The Company will continue to monitor commodity price forecast movements and undertake transactions to optimize the portfolio and limit exposure to price movements.

The sensitivity to an increase/decrease of $1/MWh in the Alberta power price, assuming all other factors are held constant, is estimated to be an operating margin (excluding unrealized fair value adjustments) increase/decrease of $0.5 million for each of the remainder of 2009 and all of 2010. In 2011, the sensitivity of operating margin (excluding unrealized fair value adjustments) to a $1/MWh increase/decrease in the Alberta power price, is expected to increase to approximately $4 million due to the open position on the Keephills 3 facility and the expiration of certain Alberta wholesale and commercial and industrial customer contracts. The Alberta power price sensitivity provides a range of outcomes assuming all other factors are held constant and current risk management strategies, including hedges, are in place. Under normal circumstances, such other factors will not be held constant. In addition, the sensitivity is presented at September 30, 2009 and the degree of sensitivity will change as the Company's mix of assets and operations subject to this factor changes or the degree of commodity hedge coverage changes.

As discussed under Subsequent Events, the Company's share of the total construction cost of the Keephills 3 facility is expected be approximately $955 and commercial operation of the plant is anticipated to commence in the second quarter of 2011. Construction of the third unit of the Clover Bar Energy Centre is expected to continue in the fourth quarter and once complete, the total cost of all three units is expected to be approximately $278 million. The third unit is expected to commence operation in the first quarter of 2010. Progress on the Quality Wind project, in British Columbia, including environmental assessment work, has been delayed as BC Hydro has not yet made its selection of projects under its 2008 Clean Power Call. In 2008, the power generation business of EPCOR submitted a bid in response to the 2008 Clean Power Call proposing a 142 MW wind farm located near Tumbler Ridge, British Columbia. An announcement of BC Hydro's selection was expected at the end of the second quarter but is now not expected until the end of 2009.

For the remainder of 2009, the committed capital expenditures, primarily for Keephills 3 and the Clover Bar Energy Centre and excluding EPCOR Power L.P.'s capital expenditures, are approximately $84 million, and approximately $273 million is committed for 2010. In addition to capital project costs, maintenance capital spending for any given year, excluding EPCOR Power L.P., is expected to be in the range of $30 million to $40 million with an additional $10 million to $20 million in other capital expenditures.

The major items that are expected to reduce operating margin (excluding unrealized fair value adjustments), and cash flow from operations for 2010 compared with 2009 are:

    
    -   the impact of the Company's reduced interest in the Battle River PPA
        after the sale of the remaining portion in January 2010;

    -   maintenance outages scheduled in 2010 at the Genesee site for Units 2
        and 3 compared with only one scheduled outage in 2009. In general,
        major maintenance expenses for the Genesee maintenance programs can
        vary significantly depending on the frequency of scheduled
        turnarounds. The total operating expenses for the two outages in 2010
        for both units is expected to be between $18 million and $22 million.
    

These decreases are expected to be partly offset by higher operating margin (excluding fair value adjustments) from a full year of operation of the second unit of Clover Bar Energy Centre which was commissioned in 2009, and from Unit 3 after commissioning in early 2010.

Business Risks

Our approach to risk management is to identify, monitor and manage the key controllable risks facing the Company and consider appropriate actions to respond to uncontrollable risks. Risk management includes the controls and procedures for reducing controllable risks to acceptable levels and the identification of the appropriate actions in cases of events occurring outside of management's control. Acceptable levels of risk for the Company are established by the Board of Directors and govern the Company's decisions and policies associated with risk.

Risk management is carried out at three levels. Firstly, general oversight, policy review and recommendation, and reviews of risk compliance are provided by the executive team including the Senior Vice President, Strategy and Risk. Secondly, the Director, Risk Management is responsible for monitoring compliance with risk management policies. His responsibilities include oversight of the enterprise risk management program and leadership of our commodity risk management (or middle office) function. Thirdly, the operations and shared service departments are responsible for carrying out the risk management and mitigation activities associated with the risks in their respective operations. The Company management views risk management as an ongoing process and continually looks for ways to enhance the Company's risk management processes.

We maintain a Compliance and Ethics Policy which includes an Accounting and Auditing Complaint Procedures Policy to provide for confidential disclosure of any wrong-doing relating to accounting, reporting and auditing matters. The policy prohibits any retaliation against a person making a complaint.

Environmental Regulatory Risk

Many of the Company's operations are subject to extensive environmental laws, regulations and guidelines relating to the generation and transmission of electricity, pollution and protection of the environment, health and safety, greenhouse gases (GHG) and other air emissions, water usage, wastewater discharges, hazardous material handling, storage, treatment and disposal of waste and other materials and remediation of sites and land-use responsibility. These regulations can impose liability for costs to investigate and remediate contamination without regard to fault and under certain circumstances, liability may be joint and several resulting in one contributing party being held responsible for the entire obligation.

On April 29, 2009, the Canadian Environment Minister announced in a media interview that the Canadian Federal Government is planning new climate change regulations aimed at coal-fired power in Canada's electricity sector. The regulations would purportedly require all newly constructed coal generation plants to use technology to capture GHG and inject it underground for permanent storage. Compliance with this and other known and unknown environmental regulations may require material capital and operating expenditures and failure to comply with such regulations could result in fines, penalties or the forced curtailment of operations.

Further, there can be no assurances that compliance with and/or changes to environmental regulations will not materially adversely impact the Company's business, prospects, financial conditions, operations or cash flow.

The Company's business is a significant emitter of nitrogen oxide (NOx), sulphur dioxide (SO(2)) and mercury and is required to comply with all licenses and permits and existing and emerging federal, provincial and state requirements, including programs to reduce or offset GHG emissions.

EPCOR Power L.P.'s wood waste plants may also be subject to SO(2) and mercury reduction requirements within the next five to seven years. There are a number of uncertainties associated with the estimated cost of compliance with these existing and emerging requirements. Compliance with new regulatory requirements may require EPCOR Power L.P. to incur significant capital expenditures and/or additional operating expenses.

Electricity Price and Volume Risk

The Company's revenues are tied, directly and indirectly, to the market price for electricity in the jurisdictions in which the Company operates. The Company buys and sells some of its electricity in the wholesale markets of Alberta, Ontario, and the U.S. Such transactions are settled at the spot market prices of the respective markets. Market electricity prices are dependent upon a number of factors, including: the projected supply and demand of electricity; the price of raw materials that are used to generate sources of electricity; the cost of complying with applicable regulatory requirements, including environmental; the structure of the particular market; and weather conditions. It is not possible to predict future electricity prices with complete certainty, and electricity price volatility could therefore have a material adverse effect on the Company.

In order to manage its exposure to spot price variability within specified risk limits, the Company enters into purchase and sale arrangements, including contracts-for-differences (CfD) and firm price physical contracts, for varying periods of duration. A contract-for-differences is an arrangement whereby a payment is made by one party to the contract to the other, based on the difference between a reference price and the price of an underlying commodity such as electricity or natural gas. However, due to limited market liquidity and the variance in electricity consumption between peak usage hours and off-peak usage hours, it is not possible to hedge all positions every hour. The Company operates under specific policy limits, such as total exposure and stop-loss limits, and generally trades in electricity to reduce the Company's exposure to changes in electricity prices or to match physical and financial obligations.

When aggregate customer electricity consumption (load shape) changes unexpectedly, the Company is exposed to price risk. Load shape refers to the different pattern of consumption between peak hours and off-peak hours. Consumption is higher during peak hours when people and organizations are most active; conversely, consumption is lower during off-peak hours. The Company purchases blocks of electricity in advance of consumption so as to minimize exposure to extreme price fluctuations, especially during higher priced peak hour periods. In order to do this, the Company relies on historical aggregate consumption data (load shape) provided by load settlement agents and local distribution companies to anticipate what aggregate customer consumption will be during peak hours. When consumption varies from historical consumption patterns and from the volume of electricity purchased for any given peak hour period, the Company is exposed to prevailing market prices because it must either buy the electricity if it is short or sell the electricity if it is long. Such exposures can be exacerbated by other events such as unexpected generation plant outages and unusual weather patterns.

Fuel Cost, Supply and Transportation

The Company requires fuel supplies, such as natural gas, coal, wood waste, waste heat, water and wind, to generate electricity. A disruption in the supply of, or a significant increase in the price of, any fuel supplies required by the Company could have a material adverse impact on the Company's business, financial condition and results of operation. The price of fuel supplies is dependent upon a number of factors, including: the projected supply and demand for such fuel supplies; the quality of the fuel (particularly in regards to wood waste); and the cost of transporting such fuel supplies to the Company's facilities. Changes in any of these factors could increase the Company's cost of generating electricity or decrease the Company's revenues due to production cutbacks, either of which could have a material adverse effect on the Company's business, financial condition and results of operation.

The Company's fuel expense for the Genesee plants is predominantly comprised of coal supply. Coal is supplied under long-term agreements with the Genesee Coal Mine joint venture, of which the Company holds a 50% interest. The price is based on a cost-of-service model with annual updates for inflation, interest rate and capital budget parameters and is therefore not subject to coal market price volatility. To the extent that coal mine operations or equipment suffers significant disruption, existing coal stock-pile inventories representing an approximate 6 months supply would be exhausted prior to, the generation of electricity from the Genesee generation units and the associated revenues being negatively impacted.

The Roxboro and Southport facilities purchase coal and coal-based fuel from local suppliers in the Southeast U.S. The coal and coal-based fuel is transported to the power plants by rail service. Any disruption in rail service due to unforeseen circumstances could impair the operations of these coal-fired power plants if alternative transportation cannot be arranged in a timely manner. Existing coal supply contracts will meet the 2009 requirements and approximately half of the 2010 requirements for Roxboro and Southport. There can be no assurance of if, when or upon what terms, including pricing, the existing supply agreements will be renewed or replaced.

Some of the Company's natural gas-fired plant operations are susceptible to the risks associated with the volatility of natural gas prices beyond any fixed price term. Natural gas purchases for the Naval Station, Naval Training Centre, North Island, Oxnard and Kenilworth power plants are made under variable price structures with fuel cost flow-through provisions that partially mitigate risks relating to natural gas price changes. However, each of these power plants has PPAs extending for terms in excess of existing contractual supply arrangements. The Company is exposed to commodity price risk on its natural gas purchases for EPCOR Power L.P.'s Tunis Plant beginning in 2010 when its natural gas supply agreements end prior to expiry of the OEFC PPA in 2014. In addition, EPCOR Power L.P.'s Greeley facility is exposed to fuel price risk when existing natural gas contracts expire in 2011, prior to the PPA expiry in 2013. The failure to contract for additional fuel supply for these plants at the end of existing contract terms at acceptable prices may lead to a disruption in operations and an inability to perform under their power and steam purchase agreements. The Company also maintains a quantity of natural gas in storage for trading and management of natural gas needs. At September 30, 2009, the estimated fair value of the inventory was $6 million. The inventory is subject to resale in current or forward markets and realized or unrealized gains or losses on such natural gas are subject to the volatility of the market price for natural gas.

Wood waste is required to fuel EPCOR Power L.P.'s two Canadian biomass wood waste plants, Williams Lake and Calstock. In addition, the enhancements that are in process at the North Carolina plants will increase the level of wood waste consumption at those plants. At Williams Lake, the cost of delivered wood waste for the firm energy component (approximately 80% of fuel supply cost) is flowed through to BC Hydro, while EPCOR Power L.P. is at risk for the wood waste price escalation for the remaining 20% of the fuel supply. At Calstock, the PPA price does not permit EPCOR Power L.P. to directly flow through the fuel supply cost to the OEFC, and EPCOR Power L.P. is at risk for wood waste price escalation. Market forces, including levels of activity in the regional forestry sector, competition from other users of wood waste and limits to the distance over which wood waste can economically be transported, expose EPCOR Power L.P. to price and supply risk for wood waste.

EPCOR Power L.P.'s five Ontario plants (namely, Nipigon, Kapuskasing, North Bay, Calstock and Tunis) also generate electricity in part from the use of waste heat gases of adjoining natural gas compressor stations. Supply of the waste heat gases is secured under long-term contracts; however the availability of the waste heat gases varies depending on the output of the compressor stations along the TransCanada pipeline system, and the host's altering those operations under the terms of a Waste Heat Optimization Agreement. In addition, the availability of waste heat gases is also dependent on the compressor stations remaining in use and their ability to supply the waste heat gases. Declining waste heat availability that began in 2007 continued into 2008 and 2009 due to lower throughput on the TransCanada pipeline system. The Company expects there will be a potential for recovery of volumes beginning in 2012.

Performance of hydroelectric facilities is dependent upon the availability of water. Variances in water flows, which may be caused by shifts in weather or climate patterns, the timing and rate of melting and other uncontrollable weather-related factors affecting precipitation, could result in volatility of hydroelectric plant revenues. In addition, the hydroelectric facilities are exposed to potential dam failure, which could affect water flows and have a material adverse impact on revenues from the associated plants. There is an increasing level of regulation respecting the use, treatment and discharge of water, and respecting the licensing of water rights, in Alberta. A continued tightening of such regulations could have a material adverse effect on the Company's business, financial condition and results of operation.

The Company's wind power facilities, like those of the Kingsbridge I project, have no fuel costs but are dependent on the availability and constancy of sufficient wind resources to meet generation capacity. Wind resources can vary due to abnormal weather conditions, and decreases in wind speed or duration can negatively impact the performance of the wind turbines and, in turn, could potentially have a material negative impact on related revenues.

Operational Risk

The operation of power plants involves many risks, including: (i) the breakdown or failure of, and the necessity to repair, upgrade or replace, power and steam generation equipment, transmission lines, pipelines or other equipment, structures or processes; (ii) the inability to secure critical or back-up parts for generator equipment on a timely basis; (iii) fire, explosion or other property damage; (iv) an inability to obtain adequate fuel supplies, site control, and operation and maintenance and other site services for at least the term of any PPA; (v) performance of generation equipment below expected levels, including those pertaining to efficiency and availability; (vi) fluctuating costs, including fuel costs; (vii) compliance with all operating permits and licences (including environmental permits and emissions restrictions) under applicable laws and regulations; and (viii) an inability to retain, at all times, adequate skilled personnel, the occurrence of any of which could have a material adverse effect on the Company, including a shut-down of a power plant or reduction in its operating capacity, emissions in excess of permitted levels, or diversion of water levels below levels required by regulation.

The inability of the Company's power plants to generate the expected amount of electricity that will be sold under contract or to the applicable market would have a significant adverse impact on the revenues of the Company. If a power plant delivers less than the required quantities of electricity in a given month, or is available for production less than required under the PPAs in a given month, revenue may be insufficient to cover contractual or financial obligations.

To the extent that plant equipment requires significant capital and other operation and maintenance expenditures to maintain efficiency, requires longer-than-forecast down times for maintenance and repair, experiences outages due to equipment failure or suffers disruptions of power generation for other reasons, the Company's cost of generating electricity will be increased and/or the Company's revenues may be negatively affected. As an adopter of new technology, the Company can be exposed to design flaws or other issues, the impacts of which may not be covered by warranties or insurance. The decision regarding expenditures and maintenance would depend on, among other things, the remaining term of the PPA. The failure of the Company's facilities to operate at required capacity levels may result in the facilities having their contracted capacity reduced and, in certain cases, the Company having to make payments on account of reduced capacity to power purchasers.

Operational risks are partly mitigated by our, and the acquired PPA plant owners' operating and maintenance practices that are intended to minimize the likelihood of prolonged unplanned down time. The terms of the PPAs provide appropriate incentives to owners to keep the plants well maintained and operational as well as force majeure protection for high-impact low probability events including major equipment failures. Maintenance practices are augmented by an inventory of strategic spare parts, which can reduce down time considerably in the event of failure. Finally, the Company has secured appropriate business interruption insurance to reduce the impact of prolonged outages caused by insured events.

In the case of EPCOR Power L.P.'s Ontario plants, a combination of increasing operation and maintenance costs, fuel costs, and decreasing availability of waste heat as a fuel source, may cause EPCOR Power L.P. to restrict their operation to on-peak hours to maximize revenue under their respective PPAs.

In addition, counterparties to PPAs have remedies available to them if the Company fails to operate facilities in accordance with contract requirements, including the recovery of damages and termination of contractual arrangements.

Projects in Construction and Development

The Company participates in the design, construction and operation of new power generation facilities. Development of power generation facilities is subject to substantial risks and can be adversely affected by changes in engineering and design requirements, non-performance or errors by third-party contractors, construction performance falling below expected levels, changes in government policy and regulation, environmental concerns, increases in capital costs, increases in interest rates, competition in the industry and other matters beyond the direct control of the Company. Any one of these factors could cause actual results to vary significantly and the Company may not be able to recover its investment, materially and adversely affecting the Company's financial position, operating results and business.

The Company attempts to mitigate these risks by performing detailed project analysis and due diligence prior to and during construction or acquisition, and by entering into favourable long-term contracts for output and services to be provided where and when available.

Credit Risk

Credit risk is the possible financial loss associated with the potential inability of counterparties to satisfy their contractual obligations to the Company, including payment and performance. In the event of default by a purchasing counterparty, existing PPAs and steam purchase agreements may not be replaceable on similar terms, particularly those agreements that have favourable pricing for the Company relative to their current markets. The Company is also dependant upon counterparties with respect to its cogeneration hosts and suppliers of fuel to its plants. Failure of any such counterparties could impact the operations of some of the Company's plants and could adversely impact the Company's financial results. In the wholesale electricity market, should a counterparty default, the Company may not be able to effectively replace such counterparty in order to manage short or long electricity positions, resulting in reduced revenues or increased power costs. Furthermore, a prolonged deterioration in economic conditions, such as the recent economic recession, could increase the foregoing risks and could have a material adverse affect on the Company.

Financial Liquidity Risk

The Company's future development, enhancement opportunities, acquisition plans or other cash requirements, may require additional financing from time to time. The ability of the Company to arrange such financing in the future will depend in part upon prevailing market conditions as well as the business performance of the Company. Current global financial conditions and recent market events have been characterized by increased volatility and the resulting tightening of the credit and capital markets has reduced the amount of available liquidity and overall economic activity. There can be no assurance that debt or equity financing, the ability to borrow funds or cash generated by operations will be available or sufficient to replace financing as it matures or becomes due, or to meet or satisfy the Company's initiatives, objectives or requirements or, if financing is available to the Company, that it will be on terms acceptable to the Company. See Liquidity and Capital Resources. The inability of the Company to access sufficient amounts of capital on terms acceptable to the Company for its operations could have a material adverse effect on the Company's business, prospects and financial condition.

Supply Risk of Alberta PPAs

The Company holds interests in PPAs in Alberta which entitle the Company to its proportionate interest in the electricity produced from certain generating units up to their committed capacity. In most cases where plant capability falls below committed capacity, the Company is entitled to receive availability payments from the plant owner based on 30-day rolling average power pool prices and target availability. The occurrence of an event which disrupts the ability of the power plants to produce or sell power or thermal energy for an extended period under such PPAs, including events which preclude the subsequent purchasers of the rights and obligations under the acquired PPAs from fulfilling their obligations under such PPAs, could have a material negative impact on the ability of the Company to generate revenue. In such circumstances, the Company may be required to replace the electricity that was not delivered to it at market rates prevailing at that time, although it would be relieved of the obligation to pay the unit capacity fee. Depending on market liquidity, these market prices could be significantly higher than the prices inherent in the PPA, thus increasing the cost of energy purchases to the Company.

PPA Contract Risk

Many of the Company's generation plants operate under PPAs. Such contracts contain performance benchmarks that must be achieved and other obligations that must be complied with by the Company. The Company may incur charges in the event of unplanned outages or variations from the contract performance benchmarks. In addition, there is no assurance that counterparties to PPAs will perform their obligations or make required payments to the Company or EPCOR Power L.P., as applicable.

Electricity sales associated with the Company's Genesee 1 and 2 facilities are governed by the terms of a PPA. These sales are accounted for as long-term fixed margin contracts, which limit the impact of swings in wholesale spot electricity prices, unless plant availability drops significantly below the PPA target availability for an extended period. Most of the Company's other plants, including Brown Lake, Miller Creek, and Kingsbridge I, operate under long-term commercial contracts with counterparties. Electricity sales or steam sales associated with Joffre are subject to market price variability as there are provisions in the NOVA contract that require the facility to run to provide steam to the host facility, irrespective of market prices.

In order to stabilize future cash flows, EPCOR Power L.P. seeks to re-contract existing generation plants under new or extended contracts and acquire new plants that meet its investment criteria. However, there is no guarantee that existing PPAs will be extended or renewed on more favourable terms. Electricity prices under the PPAs for the Naval Facilities and Oxnard are based on the purchasing utilities' SRAC. The SRAC formula is determined by the California Public Utility Commission and is subject to adjustment. In the future, the California Public Utility Commission may make adjustments to the SRAC formula to change the basis on which future electricity prices will be determined for these facilities. Such adjustments may adversely affect the value of the affected PPAs to the Company.

Reliance on Transmission Systems

The Company depends on transmission facilities owned and operated by third parties to deliver the wholesale power it sells from its power generation plants to its customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, the Company's ability to sell and deliver wholesale power may be adversely impacted. If a region's power transmission infrastructure is inadequate, the Company's recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The Company also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. The Company's ability to develop new projects is also impacted by the availability of various transmission and distribution systems.

Foreign Exchange Risk

Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar affect the Company's capital and operating costs, revenues and cash flows and could have an adverse impact on the Company's financial performance and condition. The U.S. plant operations of EPCOR Power L.P. and the foreign-sourced equipment required for capital projects such as Keephills 3 and Clover Bar are transacted in U.S. dollars. In addition, certain of EPCOR Power L.P.'s indebtedness is denominated in U.S. dollars.

The foreign exchange risk of anticipated U.S. dollar denominated cash flows, net of debt service obligations, is managed through the use of forward foreign exchange contracts for periods of up to seven years. In addition, large value equipment purchase prices are generally fixed in Canadian dollars by contracting in Canadian dollars or using forward foreign exchange contracts.

PPA Contract Expiration Risks

Power generated from the Company's facilities is, in many cases, sold under PPAs that expire at various times. When a PPA expires, there can be no assurance that a subsequent PPA will be available or, if available, that any such subsequent PPA will be on terms, or at prices, acceptable to the Company. Failure by the Company to enter into a subsequent PPA on terms and at prices that permit the operation of a facility on a profitable basis could have a material adverse effect on the Company's operations and financial condition, and may even require the Company to temporarily or permanently cease operations at the affected facility.

Derivatives Risk

The Company uses derivative instruments, including futures, forwards, options and swaps, to manage its commodity and financial market risks inherent in its electricity generation operations. These activities, although intended to mitigate price volatility, expose the Company to other risks. When the Company sells power forward, it gives up the opportunity to sell power at higher prices in the future, which not only may result in lost opportunity costs but also may require the Company to post significant amounts of cash collateral or other credit support to its counterparties. In addition, the Company purchases and sells commodity-based contracts in the natural gas and electricity markets for trading purposes. In the future, the Company could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. See Financial Instrurments - Risk Management and Hedge Accounting for more information about the Company's use of derivative instruments.

Weather Risks

Weather can have a significant impact on the Company's operations. Temperature levels, seasonality and precipitation, both within the Company's markets and adjacent geographies, can affect the level of demand for electricity and natural gas, thus resulting in electricity and natural gas price volatility. In addition, the performance of the hydroelectric facilities is partly dependent upon the availability of water and variances in water flows are caused by non-controllable weather-related factors affecting precipitation and could result in volatility of hydroelectric plant revenues. Although the Company's wind power facilities have no fuel costs, they rely on the availability and constancy of wind resources, which could vary due to abnormal weather conditions.

Financial exposures associated with extreme weather are partially mitigated through our insurance programs.

Litigation Update

On June 11, 2009, William Pidruchney filed a Statement of Claim against The City of Edmonton, the Mayor and Councillors of The City of Edmonton, EPCOR, EPCOR Power L.P.'s General Partner, EPCOR Power L.P. and Capital Power (the Co-defendants). Mr. Pidruchney alleged, among other things, that The City of Edmonton acted beyond its power and contrary to the Municipal Government Act (Alberta) and did not observe an appropriate public process in connection with the initial public offering involving Capital Power. Based on its review of the available information, Capital Power believes that the claim is without merit and intends to vigorously defend itself. On June 26, 2009, Capital Power filed a Statement of Defence denying all of the allegations contained in the Statement of Claim. On July 3, 2009, the Alberta Court of Queen's Bench denied an application by William Pidruchney for an interim injunction to delay the closing of the Capital Power initial public offering and its acquisition of EPCOR's power generation business. The court was not satisfied that there was any real merit to Mr. Pidruchney's application. The Co-defendants have now applied to the Alberta Court of Queen's Bench for summary dismissal of Mr. Pidruchney's action against them.

On June 30, 2009, an Originating Notice was filed in the Court of the Queen's Bench of Alberta, Judicial District of Edmonton, by the Alberta Federation of Labour, the Canadian Union of Public Employees, Local 30, and the Civic Service Union 52. The Notice named The City of Edmonton, EPCOR Utilities Inc. and Capital Power Corporation as Respondents and requested that the transaction pursuant to which the power generation assets previously owned by EPCOR were transferred to Capital Power be overturned on the basis that certain purported actions taken by The City of Edmonton in connection with the initial public offering were allegedly outside the jurisdiction of the municipality under the Municipal Government Act. On September 25, 2009, the Alberta Court of Queen's Bench denied the application.

Future Accounting Changes

International Financial Reporting Standards

In February 2008, the CICA confirmed that Canadian reporting issuers will be required to report under International Financial Reporting Standards (IFRS) effective January 1, 2011, including comparative figures for the prior year.

In January 2008, EPCOR established a core team to develop a plan which would result in the first interim report for 2011 being in compliance with IFRS. In July 2009, Capital Power organized its own IFRS team which is working in conjunction with the EPCOR core team to carry on with the progress made to date and implement IFRS in Capital Power in time to meet the 2011 reporting requirements. The terms of the services to be provided by EPCOR to Capital Power for IFRS support are outlined in the Services Agreement by and between Capital Power and EPCOR Utilities Inc.

The diagnostic phase of the project was completed in April 2008. For each international standard, EPCOR identified the primary differences from Canadian GAAP and made an initial assessment of the impact of the required changes for the purpose of prioritizing and assigning resources. The assessments were reviewed from a Capital Power perspective. The following standards are likely to have a significant impact on Capital Power.

    
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    International Financial Reporting Standard
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    IFRS 7, IAS 32, IAS 39 Financial Instruments
    IAS 23 Borrowing Costs
    IAS 18 Revenue
    IAS 16 Property, Plant and Equipment
    IAS 31 Interests in Joint Ventures
    IAS 21 The Effects of Changes in Foreign Exchange Rates
    IFRS 3 Business Combinations
    IAS 12 Income Taxes
    IAS 17 Leases
    IAS 37 Provisions, Contingent Liabilities and Contingent Assets
    IAS 36 Impairment of Assets
    -------------------------------------------------------------------------
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The information obtained from the diagnostic phase was used to develop a detailed plan for convergence and implementation. The convergence and implementation work has the following five key sections.

Financial Statement Adjustments

For each international standard, the Company will determine the quantitative impacts to the financial statements, system requirements, accounting policy decisions, and changes to internal controls and business policies. The initial accounting policy decisions will be brought forward to the Audit Committee for their information as each standard is addressed. However, final accounting policy decisions for all standards in effect at the end of 2009 will be made in the fourth quarter of 2009 and brought forward to the Audit Committee in the first quarter of 2010, as they should not be determined in isolation of other policy decisions. Policy decisions for any new standards or standards that are amended in 2010 will be made in conjunction with our analysis of those standards in 2010.

As the project progresses, the timing of completion of certain items may change as changes to standards and other external factors such as discussions with certain stakeholders may result in a change in priorities. However, the Company believes the project has sufficient resources to meet the overall project timeline.

Financial Statements

There are also a number of international standards which relate to financial statement presentation. Draft financial statements highlighting the disclosure and presentation requirements were prepared for EPCOR before the Reorganization and will be used as a foundation for preparing draft financial statements in accordance with IFRS for Capital Power. Draft financial statements will be brought forward to the Audit Committee by then end of the first quarter of 2010. The development of the financial statement presentation will evolve throughout the project as impacts of implementing the various standards are quantified.

Systems Updates

The diagnostic phase of the project identified two key accounting system requirements. The system must be able to capture 2010 financial information under both the prevailing Canadian GAAP and IFRS to allow comparative reporting in 2011, the first year of reporting under IFRS. It must also be able to accommodate possible changes to foreign currency translation methods, depending on how certain foreign entities are classified under IFRS. EPCOR developed a systems strategy in 2008 and implementation of a parallel fixed asset subledger and general ledger was completed in the third quarter of 2009.

Policies and Internal Controls

In the determination of the financial statement adjustments, requirements for changes to Company policies and internal controls will be identified and documented. As there may be factors other than IFRS impacting policies and internal controls, the formal documentation and approval of revised policies and internal controls will not occur until the third quarter of 2010.

The impact of IFRS on certain agreements, such as debt, shareholder and compensation agreements, has also been included in the plan. Assessments of these agreements will be performed in the fourth quarter of 2009 and the first quarter of 2010 as most of these agreements were revised as a result of the Reorganization.

Training

The Company recognizes that training at all levels is essential to a successful conversion and integration. Accounting staff have attended two training sessions with more planned to occur throughout the conversion process. The Audit Committee will receive regular updates on the conversion project and training for the Board of Directors and Audit Committee will occur throughout the project.

Disclosures about financial instruments

In June 2009, the CICA amended Handbook Section 3862 Financial Instruments - Disclosures, to adopt the amendments recently made by the International Accounting Standards Board to IFRS 7 Financial Instruments: Disclosures. The amendments require enhanced disclosures about fair value measurements, including the relative reliability of the inputs used in those measurements, and about the liquidity risk of financial instruments. The Company will assess the impacts of these amendments on its financial statements and implement the necessary additional disclosures commencing with the annual financial statements for 2009.

Consolidated financial statements and non-controlling interests

In January 2009, the CICA issued Handbook Section 1601 - Consolidated Financial Statements and Section 1602 - Non-controlling Interests, which replace Section 1600 - Consolidated Financial Statements. Section 1601 establishes the standards for the preparation of consolidated financial statements while Section 1602 establishes the standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. Section 1602 is equivalent to the corresponding provisions of International Accounting Standard 27 - Consolidated and Separate Financial Statements.

Sections 1601 and 1602 will apply to Capital Power's interim and annual consolidated financial statements relating to periods commencing on or after January 1, 2011. Earlier adoption is permitted as of the beginning of a fiscal year provided Section 1582 - Business Combinations is also adopted at the same time. The impact of the new standards and the option to adopt them early will be assessed as part of the Company's IFRS project.

Business combinations

In January 2009, the CICA issued Handbook Section 1582 - Business Combinations, which replaces Section 1581 - Business Combinations and provides the Canadian equivalent to IFRS 3 - Business Combinations. The section will apply on a prospective basis to a business combination by Capital Power for which the acquisition date is on or after January 1, 2011. Earlier adoption is permitted as of the beginning of a fiscal year provided Sections 1601 - Consolidated Financial Statements and 1602 - Non-controlling Interests are also adopted at the same time. The impact of the new standard and the option to adopt it early will be assessed as part of the Company's IFRS project.

Significant Accounting Policies

Revenue recognition under PPAs

The Company's Genesee power generation units 1 and 2 operate under a PPA. Under the terms of the PPA, the target levels of generation availability set out in the PPA recognize that the generation units will experience planned and forced outages over the terms of the PPA. The Company records the electricity revenue from the generation units under PPAs at the price embedded in the PPAs, including expected incentives and penalties for operating above or below specified availability targets set out in the PPA. Under this approach, incentives for the period may be deferred and included in non-current liabilities on the balance sheet if they are not expected to be sustained over the full term of the PPA. As penalties are incurred, any balance of deferred incentive is drawn down. If cumulative penalties exceed cumulative incentives, the excess is charged to income and no deferred charge is created.

The degree to which incentives are recognized or deferred changes from period to period due to revisions to the long-term outlook of plant performance, which is based on historical performance, planned maintenance, reliability and generation availability, and due to revisions in the estimated long-term price embedded in the PPA.

Revenues from the Company's power generation plants located outside of Alberta are recognized upon delivery of output or upon availability for delivery as prescribed by contractual arrangements. These contractual arrangements are also commonly referred to as PPAs. Revenues under the Curtis Palmer and Morris PPAs are recognized at the lower of (1) the MWhs made available during the period multiplied by the billable contract price per MWh and (2) an amount determined by the MWhs made available during the period multiplied by the average price per MWh over the term of the contract. Any excess of the contract price for the period over the average price is recorded as deferred revenue.

Leases or arrangements containing a lease

Leases or other arrangements entered into for use of property, plant and equipment are classified as either capital or operating leases. Leases or other arrangements that transfer substantially all of the benefits and risks of ownership of property to the Company are classified as capital leases. Equipment acquired under capital leases is depreciated over the term of the lease. Rental payments under operating leases are expensed as incurred.

Certain power generation plants operate under PPAs that convey the rights to use the related property, plant and equipment to the holder of the agreements. Consequently, these power generation plants are accounted for as assets under operating leases.

Foreign currency translation

EPCOR Power L.P. has operations in the U.S. with a functional currency of U.S. dollars. Accordingly, these operations are translated using the current rate method whereby assets and liabilities are translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Revenues and expenses are translated at rates in effect at the time of the transactions. The resulting foreign exchange gains and losses are accumulated as a component of accumulated other comprehensive income.

Consolidation of EPCOR Power L.P. and CPLP

While the Company owns only 30.6% of the outstanding units of EPCOR Power L.P. and an approximate 27.8% interest in CPLP, it controls both partnerships under GAAP. Accordingly, EPCOR Power L.P. and CPLP are consolidated in the financial statements of the Company.

Critical accounting estimates

In preparing the consolidated financial statements, management necessarily made estimates in determining transaction amounts and financial statement balances. The following are the items for which significant estimates were made in the financial statements.

Fair values

The Company is required to estimate the fair value of certain assets and obligations for determining the valuation of certain financial instruments, asset impairments, asset retirement obligations and purchase price allocations for business combinations, and for determining certain disclosures.

Fair values of financial instruments are based on quoted market prices when these instruments are traded in active markets. In illiquid or inactive markets, the Company uses appropriate price modeling to estimate fair value. For determining purchase price allocations for business combinations, the Company is required to estimate the fair value of acquired assets and obligations. Goodwill arising on business combinations is tested for impairment annually or more frequently if events and circumstances indicate that a possible impairment may exist. To test for impairment, the fair value of the reporting unit to which the goodwill relates is compared with the carrying value, including goodwill, of the reporting unit. If the carrying value of the reporting unit exceeds its fair value, the fair value of the reporting unit's goodwill is compared with its carrying amount to measure the impairment loss, if any.

The Company reviews the valuation of long-lived assets subject to amortization when events or changes in circumstances may indicate or cause a long-lived asset's carrying amount to exceed the total undiscounted future cash flows expected from the asset's use and eventual disposition. An impairment loss, if any, would be recorded as the excess of the carrying amount of the asset over its fair value, measured by either market value, if available, or estimated by calculating the present value of expected future cash flows related to the asset. Fair values and useful lives are used in determining potential impairments for each long-lived asset, which will vary with each asset and market conditions at the particular time.

Estimates of fair value for purchase price allocations, and goodwill and other asset impairments as described above, are primarily based on depreciable replacement cost or discounted cash flow techniques employing estimated future cash flows based on a number of assumptions and using an appropriate discount rate. The cash flow estimates will vary with the circumstances of the particular assets or reporting unit and will be based on, among other things, the lives of the assets, contract prices, estimated future prices, revenues and expenses, including inflation, and required capital expenditures.

The fair values of asset retirement obligations are estimated using the total undiscounted amount of the estimated future cash flows required to settle the obligations and applying the appropriate credit-adjusted risk-free discount rate. In this process assumptions are made regarding the useful lives of the assets and the legal restoration obligations. The range for the estimates of fair value for the purposes of determining an asset retirement obligation varies by asset.

Useful lives of assets

Depreciation and amortization allocate the cost of assets over their estimated useful lives on a systematic and rational basis. Depreciation and amortization also include amounts for future decommissioning costs and asset retirement obligation accretion expenses. Estimating the appropriate useful lives of assets requires significant judgement and is generally based on estimates of the life characteristics of common assets.

Income taxes

The Company follows the asset and liability method of accounting for income taxes. Current income taxes are recognized for the estimated income taxes payable or recoverable for the period. Estimates of future income taxes resulting from temporary differences between the carrying values of assets and liabilities in the financial statements and their tax values are recognized as future income tax assets and liabilities. Future income tax assets are assessed to determine the likelihood that they will be recovered from future taxable income. To the extent recovery is not considered likely, a valuation allowance is recorded and charged against income in the period that the allowance is created or revised. Estimates of the provision for current income taxes, future income tax assets and liabilities and any related valuation allowance might vary from actual amounts incurred. Income taxes will vary with taxable income and, under certain conditions, with fair values of assets and liabilities.

PPA availability incentives

Electricity revenue from the Genesee 1 and 2 units includes an estimate of availability incentives as described above under Significant Accounting Policies. Availability incentive payments received are deferred in non-current liabilities and recognized in energy sales when they are expected to be sustained over the full term of the PPA. Accordingly the amount deferred can vary from no amount to the full amount of availability incentive payments received.

Financial Instruments

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

The Company classifies its cash, cash equivalents and current and non-current derivative instruments assets and liabilities as held for trading, and measures them at fair value. Accounts receivable and long-term loans are classified as loans and receivables and accounts payable and accrued liabilities are classified as other liabilities. Accounts receivable and accounts payable and accrued liabilities are measured at amortized cost and their fair values are not materially different from their carrying values due to their short-term nature.

The classification, carrying amounts and fair values of other financial instruments held at September 30, 2009 are as follows:

    
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                                                                        Fair
                                                Carrying amount        value
                                             --------------------------------
                                                            Other
                                             Loans and  financial
    (unaudited, $ millions)                receivables liabilities
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    Other assets                                $   77     $    -     $   72
    Long-term debt (including current
     portion)                                   $    -     $1,771     $1,745
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Risk management and hedging activities

The Company is exposed to changes in energy commodity prices, foreign currency exchange rates and interest rates. The Company uses various risk management techniques, including derivative instruments such as forward contracts, fixed-for-floating swaps, and option contracts, to reduce this exposure. These derivative instruments are recorded at fair value on the balance sheet unless the Company elects the fair value exemption for non-financial derivatives that are entered into and continue to be held for the purpose of receipt or delivery of a non-financial item in accordance with the Company's expected purchase, sale or usage requirements. The derivative instruments assets and liabilities used for risk management purposes are measured at fair value and consist of the following:

    
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                                                  Energy   Foreign
                                   Energy cash      non-  exchange
    (unaudited, $ millions)        flow hedges    hedges non-hedges    Total
    -------------------------------------------------------------------------
    Total derivative instruments
     net assets (liabilities) as
     at September 30, 2009              $  (19)   $   69    $   17    $   67
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Energy derivatives designated as accounting hedges

At September 30, 2009, the net fair value of energy derivative instruments designated and qualifying for hedge accounting was a net liability of $19 million and is included in derivative instruments assets and derivative instruments liabilities on the consolidated balance sheet. The net derivative liability is primarily due to a decrease in the forward Alberta natural gas prices relative to the derivative contract prices. Unrealized gains and losses for fair value changes on derivatives that qualify for hedge accounting are recorded in other comprehensive income and reclassified to net income as energy revenues, energy purchases, or fuel as appropriate when realized.

On July 31, 2009, EPCOR Power L.P. applied hedge accounting to certain of its natural gas purchase contracts. An unrealized gain of $4 million for the increase in the fair value of these contracts for the period from the inception of the hedge to September 30, 2009 was recognized in other comprehensive income. Prior to the application of the hedge, the unrealized changes in the fair value of these contracts were recognized in net income.

Energy derivatives not designated as accounting hedges

At September 30, 2009, the net fair value of energy derivative instruments not designated as hedges for accounting was a net asset of $69 million and is included in derivative instruments assets and derivative instruments liabilities on the consolidated balance sheet. This net derivative asset was primarily due to unrealized gains arising from a net short position for the portfolio combined with lower forward Alberta electricity prices, relative to the derivative contract prices.

At September 30, 2009, the fair value of the Company's forward foreign currency contracts was a net derivative instrument asset of $17 million. The net asset was due to the impact of a strengthening Canadian dollar relative to the U.S. dollar on forward foreign exchange sales contracts used to hedge U.S. dollar denominated revenues. The weighted average fixed exchange rate for contracts outstanding at September, 2009 was $1.12 for every U.S. dollar. Unrealized and realized gains and losses on foreign exchange derivatives that are not designated as hedges for accounting purposes are recorded in energy revenues or foreign exchange gains and losses.

All non-financial derivative instruments are measured at fair value unless they are designated as contracts used for the purpose of receipt or delivery of a non-financial item in accordance with the Company's expected purchase, sale or usage requirements as defined by accounting standards, or are designated and qualify for hedge accounting. Some of the Company's physical power and natural gas purchase and sales contracts that are used to meet power generation and retail customer requirements were not designated as contracts used in accordance with the Company's expected purchase requirements and therefore are recorded at fair value in the balance sheet.

Risk management and hedge accounting

The Company uses various financial and non-financial derivatives primarily for risk management purposes. Unrealized changes in the fair value of financial and non-financial derivatives that either do not qualify for hedge accounting or the Company elects not to apply hedge accounting, and non-financial derivatives that do not qualify for the expected purchase, sale or usage requirements of the contract, are recorded in energy revenues, energy purchases or cost of fuel, as appropriate. The corresponding unrealized changes in the fair value of the associated economically hedged exposures are not recognized in income. Accordingly, derivative instruments that are recorded at fair value can produce volatility in net income as a result of fluctuating forward commodity prices, exchange rates and interest rates which are not offset by the unrealized fair value changes of the exposure being hedged on an economic basis. As a result, accounting gains or losses relating to changes in fair values of derivative instruments do not necessarily represent the underlying economics of the hedging transaction.

For example, the Company has more physical supply of power in Alberta from its generating stations and power purchased under PPAs than the Company has contracted to physically sell. The Company utilizes financial sales contracts to reduce its exposure to changes in the price of power in Alberta. Economically, the Company benefits from higher Alberta power prices due to the net long position held since the Company's expected physical supply is in excess of the Company's physical and financial sales contracts. However, financial sales contracts that are not hedged for accounting purposes are recorded at fair value at each balance sheet date and the offsetting anticipated future physical supply or economically hedged item is not. Accordingly, an increase in forward Alberta power prices can result in fair value losses for accounting purposes whereas on an economic basis, these losses are offset by unrecognized gains on the physical supply. The economic gains will be recognized in later periods when the power is produced and sold. The opposite is true for forward price decreases in Alberta power.

Other comprehensive income

Changes in the fair value of the effective hedge portion of the financial derivative contracts used to manage the energy portfolio and designated as accounting hedges, are recorded in other comprehensive income. The ineffective portion of the contracts is recorded in net income.

For the period ended September 30, 2009, an unrealized gain, net of income taxes, of $8 million was recorded in other comprehensive income for the effective portion of cash flow hedges, and a realized loss, net of income taxes, of $21 million was reclassified to energy purchases and revenues as appropriate. There was no ineffective portion of cash flow hedges for which unrealized gains or losses were required to be recognized in income. Of the $29 million in net fair value gains related to derivative instruments designated as cash flow hedges included in accumulated other comprehensive income at September 30, 2009, net losses of $14 million, net of taxes of $1 million are expected to settle and be reclassified to net income over the next twelve months.

Internal Control Over Financial Reporting

As part of the Reorganization and acquisition of the power generation assets and operations from EPCOR in July 2009, the Company assumed the underlying processes and internal controls. The agreements between the Company and EPCOR for transitional and ongoing services between the two entities and their subsidiaries also provide for continuity of internal controls after the Reorganization and acquisition. There was no change in the Company's internal control over financial reporting during the period beginning July 1, 2009 and ended on September 30, 2009 that has materially affected, or is reasonably likely to materially affect the Company's internal control over financial reporting.

Forward-looking Information

Certain information in this MD&A is forward-looking within the meaning of Canadian securities laws as it relates to anticipated financial performance, events or strategies. When used in this context, words such as will, anticipate, believe, plan, intend, target, and expect or similar words suggest future outcomes.

Forward-looking information in this MD&A includes, among other things, information relating to: (i) expected timing of commercial operation and project cost of Keephills 3 and Clover Bar Energy Centre Unit 3; (ii) future financings by EPCOR Power Equity Ltd; (iii) expectations for the use of the Company's committed bank credit facilities; (iv) Capital Power's and EPCOR Power L.P.'s cash requirements for the fourth quarter of 2009 and related financing; (v) expectations regarding future financial strength and access to and terms of future financings; (vi) the expected impact of the further reduction in the Company's interest in the Battle River PPA and of Keephills 3 coming on line, on cash flow from operations and operating margin; (vii) expectations for Alberta spot power prices in the fourth quarter of 2009 and their impact on operating margin and cash flow from operations; (viii) expectation that the Alberta commercial portfolio position in 2010 will reduce the exposure to changes in power prices; (ix) expectation that the Alberta commercial portfolio's open position will increase to approximately 60% of the total portfolio in 2011; ( x) the Company's estimated sensitivity to Alberta power prices; (xi) the expected annual spending for maintenance capital and other capital for the Company excluding EPCOR Power L.P.; (xii) expectation that the two maintenance outages scheduled in 2010 at the Genesee site will reduce operating margin (excluding unrealized fair value adjustments) and cash flow from operations, and the expected amount of operating expense for the two outages; and (xiii) expectation that the operating margin in 2010 will benefit from a full year of operation of the second unit of Clover Bar Energy Centre and from Unit 3 after its commissioning.

These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments and other factors it believes are appropriate. The material factors and assumptions used to develop these forward-looking statements include, but are not limited to: (i) the operation of the Company's facilities; (ii) power plant availability, including those subject to acquired PPAs (iii) the Company's financial position and credit facilities (iv) the Company's assessment of commodity and power markets; (v) the Company's assessment of the markets and regulatory environments in which it operates; (vi) weather; (vii) availability and cost of labour and management resources; (viii) performance of contractors and suppliers; (ix) availability and cost of financing; ( x) foreign exchange rates; (xi) management's analysis of applicable tax legislation; (xii) the currently applicable and proposed tax laws will not change and will be implemented; (xiii) currently applicable and proposed environmental regulations will be implemented; (xiv) counterparties will perform their obligations; (xv) renewal and terms of PPAs; (xvi) ability to successfully integrate and realize benefits of its acquisitions; (xvii) ability to implement strategic initiatives which will yield the expected benefits; and (xviii) the Company's assessment of capital markets and ability to complete future share offerings.

Whether actual results, performance or achievements will conform to the Company's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results and experience to differ materially from the Company's expectations. Such risks and uncertainties include, but are not limited to risks relating to: (i) operation of the Company's facilities; (ii) power plant availability and performance; (iii) unanticipated maintenance and other expenditures; (iv) availability and price of energy commodities; (v) electricity load settlement; (vi) regulatory and government decisions including changes to environmental, financial reporting and tax legislation; (vii) weather and economic conditions; (viii) competitive pressures; (ix) construction; ( x) availability and cost of financing; (xi) foreign exchange; (xii) availability and cost of labour, equipment and management resources; (xiii) performance of counterparties, partners, contractors and suppliers in fulfilling their obligations to the Company; (xiv) developments in the North American capital markets; (xv) compliance with financial covenants; (xvi) ability to successfully realize the benefits of acquisitions and investments; (xvii) the tax attributes of and implications of any acquisitions; and (xviii) other factors and assumptions discussed in the section entitled Risk Factors in the Prospectus and in other documents filed with provincial securities commissions in Canada. If any such risks actually occur, they could materially adversely affect the Company's business, financial condition or results of operations. In that case the trading price of the Company's common shares could decline, perhaps materially.

This MD&A includes the following updates to previously disclosed forward-looking statements: (i) the estimated date for Clover Bar Energy Centre Unit 3 to enter commercial operation was revised from the third quarter of 2010 to the first quarter of 2010; (ii) the estimated total cost for all three units at Clover Bar Energy Centre was revised from $284 million to $278 million; (iii) the estimated total project cost for Keephills 3 was revised from $1.8 billion to $1.9 billion and Capital Power's share was revised from $903 million to $955 million; (iv) the estimated commercial operation date for Keephills 3 was revised from the first quarter of 2011 to the second quarter of 2011; and (v) the expected timing of BC Hydro's selection of projects under its 2008 Clean Power Call was revised from the second quarter of 2009 to the end of 2009 and the completion of the environmental assessment work for the Quality Wind project, which was previously expected in the third quarter of 2009, has been delayed.

Readers are cautioned not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Forward-looking statements are provided for the purpose of providing information about management's current expectations, and plans relating to the future. Readers are cautioned that such information may not be appropriate for other purposes. The Company does not undertake or accept any obligation or undertaking to release publicly any updates or revisions to any forward-looking statements to reflect any change in the Company's expectations or any change in events, conditions or circumstances on which any such statement is based, except as required by law.

Quarterly Common Share Trading Information

The Company's common shares trade on the Toronto Stock Exchange under the symbol CPX and began trading on June 26, 2009.

    
    -------------------------------------------------------------------------
    Three months ended                                     Sept 30,  June 30,
    (unaudited)                                              2009      2009
    -------------------------------------------------------------------------
    Share price
      High                                                  $22.39    $23.00
      Low                                                   $19.50    $22.00
      Close                                                 $19.75    $22.35
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Volume traded (millions)                                  12.1       5.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

On October 30, 2009, the Company had 21.75 million common shares outstanding which were publicly held and represented approximately 27.8% of CPLP. On October 30, 2009, EPCOR held 56.625 million exchangeable limited partnership units of CPLP (exchangeable for common shares of Capital Power on a one-for-one basis), representing approximately 72.2% of CPLP. The weighted average number of shares outstanding for the three months ended September 30, 2009 was 78.375 million. On October 30, 2009, the Company had 56.625 million special voting shares outstanding and one special limited voting share outstanding, which were held by EPCOR.

Additional Information

Additional information relating to Capital Power Corporation, including continuous disclosure documents, is available on SEDAR at www.sedar.com.

    
    CAPITAL POWER CORPORATION
    Consolidated Statement of Income
    (Unaudited, in millions of dollars)

    -------------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
    -------------------------------------------------------------------------

    Revenues                                                         $   525
    Energy purchases and fuel                                            307
    -------------------------------------------------------------------------
                                                                         218

    Operations, maintenance and direct administration                     49
    Indirect administration                                               27
    Depreciation, amortization and asset retirement accretion
     (note 5)                                                             44
    Foreign exchange losses                                                3
    Net financing expenses (note 17)                                      17
    -------------------------------------------------------------------------
                                                                         140

    -------------------------------------------------------------------------
    Income before income tax reductions and non-controlling
     interests                                                            78

    Income tax reductions (note 18)                                       (2)

    -------------------------------------------------------------------------
    Income before non-controlling interests                               80

    Non-controlling interests (note 13)                                   66
    -------------------------------------------------------------------------
    Net income                                                        $   14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Earnings per share (note 14)
    Basic                                                             $ 0.64
    Diluted                                                             0.59
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Weighted average number of common shares outstanding
    Basic                                                         21,750,000
    Diluted                                                       78,375,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to consolidated financial statements.



    CAPITAL POWER CORPORATION
    Consolidated Balance Sheet
    (Unaudited, in millions of dollars)

    September 30, 2009

    -------------------------------------------------------------------------
                                                                        2009
    -------------------------------------------------------------------------

    Assets
    Current assets:
      Cash and cash equivalents (note 24)                             $   64
      Accounts receivable                                                248
      Income taxes recoverable                                            20
      Inventories (note 4)                                                57
      Prepaid expenses                                                    13
      Derivative instruments assets (note 20)                            148
      Future income tax assets (note 18)                                   2
    -------------------------------------------------------------------------
                                                                         552

    Property, plant and equipment (note 5)                             3,199

    Power purchase arrangements (note 6)                                 536

    Contract and customer rights and other intangible assets
     (note 7)                                                            181

    Derivative instruments assets (note 20)                              138

    Future income tax assets (note 18)                                    40

    Goodwill (note 8)                                                    119

    Other assets (note 9)                                                117

    Assets held for sale (note 30)                                        36

    -------------------------------------------------------------------------
                                                                      $4,918
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Liabilities and Shareholders' Equity
    Current liabilities:
      Accounts payable and accrued liabilities                        $  275
      Derivative instruments liabilities (note 20)                       124
      Other current liabilities                                            9
      Future income tax liabilities (note 18)                             17
      Current portion of long-term debt (note 10)                        247
    -------------------------------------------------------------------------
                                                                         672

    Long-term debt (note 10)                                           1,524

    Derivative instruments liabilities (note 20)                          95

    Other non-current liabilities (note 11)                               99

    Future income tax liabilities (note 18)                               59
    -------------------------------------------------------------------------
                                                                       2,449

    Non-controlling interests (note 13)                                1,975

    Shareholders' equity:
      Share capital (note 14)                                            477
      Retained earnings                                                   14
      Accumulated other comprehensive income (note 15)                     3
    -------------------------------------------------------------------------
                                                                         494
    Contingencies and commitments (note 27)
    Subsequent events (note 31)

    -------------------------------------------------------------------------
                                                                      $4,918
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to consolidated financial statements.



    CAPITAL POWER CORPORATION
    Consolidated Statement of Changes in Shareholders' Equity
    (Unaudited, in millions of dollars)

    -------------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
    -------------------------------------------------------------------------

    Share capital:
      Common shares issued (notes 3 and 14)                           $  477

    -------------------------------------------------------------------------
      Balance, end of period (note 14)                                   477
    -------------------------------------------------------------------------

    Retained earnings:
      Net income                                                          14

    -------------------------------------------------------------------------
    Balance, end of period                                                14
    -------------------------------------------------------------------------

    Accumulated other comprehensive income:
      Other comprehensive income                                           3

    -------------------------------------------------------------------------
    Balance, end of period (note 15)                                       3
    -------------------------------------------------------------------------

    Total shareholders' equity, end of period                         $  494
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to consolidated financial statements.



    CAPITAL POWER CORPORATION
    Consolidated Statement of Comprehensive Income
    (Unaudited, in millions of dollars)

    -------------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
    -------------------------------------------------------------------------

    Net income                                                        $   14

    Other comprehensive income (loss), net of income taxes:
      Unrealized gains on derivative instruments designated
       as cash flow hedges(1)                                              8
      Reclassification of losses on derivative instruments
       designated as cash flow hedges to net income(2)                    21
      Unrealized loss in self-sustaining foreign operations(3)           (33)
      Non-controlling interests(3) (note 13)                               7
    -------------------------------------------------------------------------
                                                                           3
    -------------------------------------------------------------------------

    Comprehensive income                                              $   17
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) For the three months ended September 30, 2009, net of income tax
        expense of $1.
    (2) For the three months ended September 30, 2009, net of
        re-classification of income tax recovery of $2.
    (3) For the three months ended September 30, 2009, net of income tax
        expense of nil.

    See accompanying notes to consolidated financial statements.



    CAPITAL POWER CORPORATION
    Consolidated Statement of Cash Flows
    (Unaudited, in millions of dollars)

    -------------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
    -------------------------------------------------------------------------
    Operating activities:
      Net income                                                      $   14
      Adjustments to reconcile net income to cash flows
       from operating activities:
        Depreciation, amortization and asset retirement
         accretion (note 5)                                               44
        Non-controlling interests in EPLP and CPLP (note 13)              64
        Fair value changes on derivative instruments                     (28)
        Unrealized foreign exchange losses                                 3
        Future income taxes                                               (3)
        Other                                                             (1)
    -------------------------------------------------------------------------
                                                                          93
    Change in non-cash operating working capital (note 16)               (40)
    -------------------------------------------------------------------------
                                                                          53
    Investing activities:
      Property, plant and equipment and other assets                    (108)
      Business acquisition, net of acquired cash (note 3)             (1,293)
    -------------------------------------------------------------------------
                                                                      (1,401)
    Financing activities:
      Proceeds from issue of long-term debt                            1,001
      Repayment of long-term debt                                        (41)
      Issue of common shares (notes 3 and 14)                            500
      Share issue costs (notes 3 and 14)                                 (32)
      Debt issue costs                                                   (13)
    -------------------------------------------------------------------------
                                                                       1,415
    -------------------------------------------------------------------------

    Foreign exchange losses on cash held in a foreign currency            (3)

    -------------------------------------------------------------------------
    Increase in cash and cash equivalents                                 64
    Cash and cash equivalents, beginning of period                         -
    -------------------------------------------------------------------------
    Cash and cash equivalents, end of period                          $   64
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Supplementary cash flow information:
      Interest paid net of interest received                          $   18
      Income taxes recovered net of income taxes paid                     (1)

    See accompanying notes to consolidated financial statements.



    CAPITAL POWER CORPORATION
    Notes to Interim Consolidated Financial Statements
    September 30, 2009
    (Unaudited, tabular amounts in millions of dollars)

    1.  Description of business:

        Capital Power Corporation (the Company or Capital Power) builds, owns
        and operates power plants and manages its related electricity and
        natural gas portfolios by undertaking trading and marketing
        activities. The Company operates in one reportable business segment
        within the geographic areas of Canada and the United States (U.S.),
        with its head office located in Edmonton, Alberta.

        The common shares of the Company are traded on the Toronto Stock
        Exchange under the symbol "CPX".

    2.  Summary of significant accounting policies:

        (a) Basis of presentation:

            These unaudited interim consolidated financial statements have
            been prepared by management in accordance with Canadian generally
            accepted accounting principles (GAAP). In the opinion of
            management, these consolidated financial statements have been
            properly prepared within reasonable limits of materiality and
            within the framework of the significant accounting policies
            summarized below.

            These unaudited interim consolidated financial statements include
            the accounts of Capital Power, its subsidiaries, and its
            proportionate share of assets, liabilities, revenues and expenses
            of joint ventures. They also include the accounts of the
            Company's approximate 30.6% interest in EPCOR Power L.P. (EPLP)
            and the Company's approximate 27.8% interest in Capital Power LP
            (CPLP). Under GAAP, Capital Power controls EPLP and CPLP which
            therefore are subsidiaries of Capital Power.

            All significant intercompany balances and transactions have been
            eliminated on consolidation.

            The Company has determined that December 31 will be its fiscal
            year-end. As the Company was incorporated on May 1, 2009, there
            is no comparative balance sheet as at December 31, 2008 or
            comparative statement of income, statement of changes in
            shareholders' equity, statement of comprehensive income and
            statement of cash flows for the period ended September 30, 2008.

            Although the Company was incorporated on May 1, 2009 the Company
            did not have any results from operations or significant cash
            flows in the period from May 1 to June 30, 2009. Accordingly, the
            company's statements of income, comprehensive income and cash
            flows reflect only information for the three months ended
            September 30, 2009.

        (b) Changes in significant accounting policies:

            Future accounting changes

            The CICA has announced that Canadian reporting issuers will need
            to begin reporting under International Financial Reporting
            Standards (IFRS), including comparative figures, by the first
            quarter of 2011. The Company is currently working on its IFRS
            conversion project which includes assessing the impact of the
            differences in accounting standards on the Company's future
            financial reporting requirements.

            In June 2009, the CICA amended Handbook Section 3862 Financial
            Instruments - Disclosures, to adopt the amendments recently made
            by the International Accounting Standards Board to IFRS 7
            Financial Instruments: Disclosures. The amendments require
            enhanced disclosures about fair value measurements, including the
            relative reliability of the inputs used in those measurements,
            and about the liquidity risk of financial instruments. Although
            the amendments apply to financial statements relating to fiscal
            years ending after September 30, 2009, comparative information is
            not required in the first year of application. We are assessing
            the impacts of these amendments on our financial statements and
            will implement the necessary additional disclosures commencing
            with the annual financial statements for 2009.

            In January 2009, the CICA issued Handbook Section 1601 -
            Consolidated Financial Statements and Section 1602 - Non-
            controlling Interests, which replace Section 1600 - Consolidated
            Financial Statements. Section 1601 establishes the standards for
            the preparation of consolidated financial statements while
            Section 1602 establishes the standards for accounting for a non-
            controlling interest in a subsidiary in consolidated financial
            statements subsequent to a business combination. Section 1602 is
            equivalent to the corresponding provisions of IFRS IAS 27 -
            Consolidated and Separate Financial Statements.

            Sections 1601 and 1602 will apply to interim and annual
            consolidated financial statements relating to periods commencing
            on or after January 1, 2011. Earlier adoption is permitted as of
            the beginning of a fiscal year, provided Section 1582 - Business
            Combinations is also adopted at the same time. The impact of the
            new standards and the option to adopt them early is being
            assessed as part of the Company's IFRS conversion project.

            In January 2009, the CICA issued Handbook Section 1582 - Business
            Combinations, which replaces Section 1581 - Business Combinations
            and provides the Canadian equivalent to IFRS 3 - Business
            Combinations. The section will apply, on a prospective basis, to
            future business combinations for which the acquisition date is on
            or after January 1, 2011. Earlier adoption is permitted as of the
            beginning of a fiscal year provided Sections 1601 - Consolidated
            Financial Statements and 1602 - Non-controlling Interests are
            also adopted at the same time. The impact of the new standard and
            the option to adopt it early is being assessed as part of the
            Company's IFRS conversion project.

        (c) Measurement uncertainty:

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

            The degree to which revenues are recognized or deferred under the
            Power Purchase Arrangements (PPAs) described in note 2(k) depends
            upon long-term outlooks of generation unit performance. Such
            outlooks of performance are estimated based on the generation
            units' historical performance, planned maintenance, reliability
            and generation availability, and revisions in the estimated long-
            term price embedded in the PPA.

            For certain accounting measures such as determining asset
            impairments, purchase price allocations for business
            combinations, recording financial assets and liabilities,
            recording certain non-financial derivatives and for certain
            disclosures, the Company is required to estimate the fair value
            of certain assets or obligations. Estimates of fair value may be
            based on readily determinable market values or on depreciable
            replacement cost or discounted cash flow techniques employing
            estimated future cash flows based on a number of assumptions and
            using an appropriate discount rate.

            Measurement of the Company's asset retirement obligations and the
            related accretion expense requires the use of estimates with
            respect to the amount and timing of asset retirements, the extent
            of site remediation required and related future cash flows.

            Measurement of certain of the Company's pension costs and plan
            assets and obligations requires the use of estimates with respect
            to expected plan investment performance, salary escalation,
            retirement ages of employees, timing of related future cash flows
            and appropriate discount rates for use in discounted cash flow
            and actuarial techniques.

            Depreciation and amortization is an estimate to allocate the cost
            of an asset over its estimated useful life on a systematic and
            rational basis. Estimating the appropriate useful lives of assets
            requires significant judgment and is generally based on estimates
            of common life characteristics of common assets.

            Income taxes are determined based on estimates of the Company's
            current income taxes and estimates of future income taxes
            resulting from temporary tax differences. Future income tax
            assets are assessed to determine the likelihood that they will be
            realized from future taxable income. To the extent that
            realization is not considered likely, a valuation allowance is
            recorded and charged against income in the period that the
            allowance is created or revised.

            Estimates of the value of electricity and natural gas consumed by
            customers but not billed until subsequent to year-end are based
            on volume data provided by the parties responsible for delivering
            the commodity and contracted prices.

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

        (d) Revenue recognition:

            Revenues from the sales of electricity and natural gas are
            recognized on delivery or availability for delivery under take-
            or-pay contracts. These revenues include an estimate of the value
            of electricity and natural gas consumed by customers, but billed
            subsequent to period-end.

            The Company recognizes revenue from its Alberta generation units
            operating under PPAs as described in note 2(k). PPAs are a form
            of long-term sales arrangements between the owner of a generation
            unit and the buyer of the PPA.

            Revenues from the Company's power generation plants located
            outside of Alberta are recognized on delivery of output or on
            availability for delivery as prescribed by contractual
            arrangements. These contractual arrangements are also commonly
            referred to as PPAs. Revenue from certain long-term contracts
            with fixed payments is recognized at the lower of (1) the
            megawatt hours (MWhs) made available during the period multiplied
            by the billable contract price per MWh and (2) an amount
            determined by the MWhs made available during the period,
            multiplied by the average price per MWh over the term of the
            contract from the date of acquisition. Any excess of the contract
            price over the average price is recorded as deferred revenue.

        (e) Financial instruments:

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

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

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

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

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

        (f) Derivative instruments and hedging activities:

            To reduce its exposure to movements in energy commodity prices,
            interest rate changes, and foreign currency exchange rates, the
            Company uses various risk management techniques including the use
            of derivative instruments. Derivative instruments may include
            forward contracts, fixed-for-floating swaps, and option
            contracts. Such instruments may be used to establish a fixed
            price for an energy commodity, an interest-bearing obligation or
            an obligation denominated in a foreign currency. All derivative
            instruments, including embedded derivatives, are recorded at fair
            value on the balance sheet as derivative instruments assets or
            derivative instruments liabilities except for embedded
            derivatives instruments that are clearly and closely linked to
            their host contract and the combined instrument is not measured
            at fair value. Any contract to buy or sell a non-financial item
            is not treated as a non-financial derivative if that contract was
            entered into and continues to be held for the purpose of the
            receipt or delivery of a non-financial item in accordance with
            the Company's expected purchase, sale or usage requirements. All
            changes in the fair value of derivatives are recorded in net
            income unless cash flow hedge accounting is used, in which case
            changes in fair value of the effective portion of the derivatives
            are recorded in other comprehensive income. The Company accounts
            separately for any embedded derivatives in any hybrid instruments
            issued or acquired. The Company does not account for foreign
            currency derivatives embedded in non-financial instrument host
            contracts when the currency that is commonly used in contracts to
            purchase or sell non-financial items in the economic environment
            is that currency in which the transaction takes place.

            The Company uses financial contracts-for-differences (or fixed-
            for-floating swaps) to hedge the Company's exposure to
            fluctuations in electricity prices. Under these instruments, the
            Company agrees to exchange, with creditworthy or adequately
            secured counterparties, the difference between the variable or
            indexed price and the fixed price on a notional quantity of the
            underlying commodity for a specified timeframe.

            The Company uses non-financial forward delivery derivatives to
            manage the Company's exposure to fluctuations in natural gas
            prices related to its natural gas customer contracts and
            obligations arising from its natural gas fired generation
            facilities. Under these instruments, the Company agrees to sell
            or purchase natural gas at a fixed price for delivery of a pre-
            determined quantity under a specified timeframe.

            Foreign exchange forward contracts are used by the Company to
            manage foreign exchange exposures, consisting mainly of U.S
            dollar exposures, resulting from anticipated transactions
            denominated in foreign currencies. For transactions involving the
            development or acquisition of property, plant and equipment, when
            the real or anticipated transaction subsequently results in the
            recognition of a financial asset, the associated gains or losses
            on hedging derivatives recognized in other comprehensive income
            are included in the initial carrying amount of the asset acquired
            in the same period or periods during which the asset acquired
            affects net income.

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

            The Company may use physical or financial commodity derivative
            trades which are transacted with the intent of benefiting from
            short-term actual or expected differences between their buying
            and selling prices or to lock in arbitrage opportunities. Such
            trades are recognized on a net basis in the Company's revenues.

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

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

            If a cash flow hedging relationship is discontinued or ceases to
            be effective, any cumulative gains or losses arising prior to
            such time are deferred in accumulated other comprehensive income
            and recognized in net income in the same period as the hedged
            item, and subsequent changes in the fair value of the derivative
            instrument are reflected in net income. If the hedged or hedging
            item matures, expires, or is sold, extinguished or terminated and
            the hedging item is not replaced, any gains or losses associated
            with the hedging item that were previously recognized in other
            comprehensive income are recognized in net income in the same
            period as the corresponding gains or losses on the hedged item.
            When it is no longer probable that an anticipated transaction
            will occur within the originally determined period and the
            associated cash flow hedge has been discontinued, any gains or
            losses associated with the hedging item that were previously
            recognized in other comprehensive income are recognized in net
            income in the period.

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

        (g) Income taxes:

            The Company's Canadian subsidiaries are subject to income taxes
            pursuant to the Income Tax Act (Canada) (ITA) and provincial
            income tax acts. The Company's U.S. subsidiaries are subject to
            income tax pursuant to U.S. federal and state tax laws.

            The Company follows the asset and liability method of accounting
            for income taxes. Under this method, current income taxes are
            recognized for the estimated income taxes payable or recoverable
            for the current year. Future income tax assets and liabilities
            are recognized for the future tax consequences attributable to
            differences between the financial statement carrying amounts of
            existing assets and liabilities and their respective tax bases.
            Future income tax assets and liabilities are measured using
            enacted or substantively enacted rates of tax expected to apply
            to taxable income in the years in which those temporary
            differences are expected to be recovered or settled. The effect
            of a change in tax rates on future tax assets and liabilities is
            recognized in income in the period that includes the date of
            enactment or substantive enactment.

        (h) Cash and cash equivalents:

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

        (i) Inventories:

            Small parts and other consumables and coal, the majority of which
            are consumed by the Company in the provision of its goods and
            services, are valued at the lower of cost and net realizable
            value. Cost includes the purchase price, transportation costs and
            other costs to bring the inventories to their present location
            and condition. The cost of any assembled inventory includes
            direct labour, materials and attributable overhead. The costs of
            inventory items that are interchangeable are determined on an
            average cost basis. For inventory items that are not
            interchangeable, cost is assigned using specific identification
            of their individual costs. Natural gas inventory held in storage
            for trading purposes is recorded at fair value less costs to
            sell, as measured by the one-month forward price of natural gas.
            Previous write-downs of inventories from cost to net realizable
            value can be fully or partially reversed if supported by economic
            circumstances.

        (j) Property, plant and equipment:

            Property, plant and equipment are recorded at cost and include
            contracted services, materials, interest, direct and indirect
            labour, directly attributable overhead costs, asset retirement
            costs, development costs associated with specific property, plant
            and equipment, and net revenues during the pre-operating period.
            Contributions received for financing the costs of assets are
            recorded as a reduction of the related asset cost.

            Depreciation on property, plant and equipment is provided on the
            straight-line basis over their estimated useful lives. No
            depreciation is provided on construction work in progress.

            The Company capitalizes interest during construction to provide
            for the costs of borrowing on construction activities. Interest
            is applied during construction using the weighted average cost of
            debt incurred on the Company's external borrowings used to
            finance qualifying assets.

        (k) Power purchase arrangements:

            Acquired PPAs are reflected on the consolidated balance sheet as
            power purchase arrangements and are recorded at cost and are
            amortized over their terms on a straight-line basis.

            Under the terms of the Alberta PPAs, the Company is obligated to
            make fixed and variable payments to the owners of the underlying
            generation units over their respective terms. Such amounts are
            recorded as operating expenses as incurred. At September 30,
            2009, the remaining term of the 20-year Sundance PPA is
            approximately 11 years. The Company is also obligated to make
            fixed and variable payments to the buyer of the Battle River PPA,
            in proportion to its effective ownership interest, until the sale
            of the Company's remaining interest in the Battle River Power
            Syndicate Agreement (Battle River PSA) is completed in 2010 as
            described in note 30.

            The Company's Alberta PPAs are owned under equity syndication
            agreements with an equity syndicate. Under the terms of the
            agreements, the syndicate members receive their proportionate
            share of the committed generating capacity in exchange for their
            proportionate share of the price paid for the Alberta PPAs and
            all payments to the generation unit owners.

            The Company's investment in the Alberta PPAs and its related
            revenues and expenses are recorded on a proportionate basis,
            after deducting the equity syndicate's share.

            The EPLP PPAs reflect the cost to acquire long-term sales
            contracts under which revenue is earned by EPLP's generation
            units. The EPLP PPAs are amortized over their remaining terms,
            which range from one to 18 years.

        (l) Contract and customer rights and other intangible assets:

            Contract rights include acquired management and operations
            agreements and water rights. Costs assigned to contract rights
            related to management and operations agreements are amortized on
            a straight-line basis, from the dates of acquisition, over the
            remaining contract terms which range from 5 to 57 years. Water
            rights associated with acquired hydroelectric power generation
            plants are recorded at cost and are amortized over the remaining
            useful lives of the associated property, plant and equipment.

            Other rights include the cost of land lease agreements for use in
            wind power projects in Ontario and coal supply access rights
            relating to the Keephills 3 Project (note 27(b)). The lease
            rights are amortized on a straight-line basis over the estimated
            useful lives of the related wind power assets, commencing when
            those assets are constructed and commissioned for service. The
            access rights will be amortized over the life of the coal supply
            agreement and amortization will commence when the Keephills 3
            plant is commissioned for service.

            Other intangible assets, which include the costs of acquired
            software, are amortized over the estimated useful lives of the
            assets which range from 1 to 10 years.

            Customer rights represent the costs to acquire the rights to a
            long-term sales contract for the output of the Brown Lake plant.
            The costs are amortized on a straight-line basis over the 30-year
            term of the contract.

        (m) Goodwill:

            Goodwill is the cost of an acquisition less the fair value of the
            net assets of an acquired business. Goodwill is tested for
            impairment by comparing the fair value of each reporting unit to
            which the goodwill relates to the carrying amount, including
            goodwill, of each reporting unit. If the carrying amount of the
            reporting unit exceeds its fair value, indicating an impairment,
            a second test is performed to measure the amount of the
            impairment. In the second test, the fair value of the reporting
            unit's goodwill is compared with its carrying amount to measure
            the impairment loss, if any.

        (n) Other assets:

            Loans and other long-term receivables are comprised of promissory
            notes receivable and amounts due from customers more than one
            year from the balance sheet date and will be repaid between 2009
            and 2025.

            Investments in which the Company exercises significant influence
            are accounted for using the equity method. Other investments are
            classified as available for sale and are recorded at fair value
            unless the investments do not have a quoted market price in an
            active market in which case the investments are recorded at cost.
            Investments recorded at cost for which there is a decline in fair
            value below cost that is other than temporary are written down
            and the loss is recognized in net income.

        (o) Impairment of long-lived assets:

            The Company reviews the valuation of long-lived assets subject to
            depreciation and amortization when events or changes in
            circumstances may indicate or cause a long-lived asset's carrying
            amount to exceed the total undiscounted future cash flows
            expected from its use and eventual disposition. An impairment
            loss, if any, would be recorded as the excess of the carrying
            amount of the asset over its fair value, measured by either
            market value, if available, or estimated by calculating the
            present value of expected future cash flows related to the asset.

        (p) Deferred availability incentives:

            Under the terms of the Genesee PPA, the target levels of
            generation availability set out in the PPA recognize that the
            respective generation units will experience planned and forced
            outages over the term of the PPA. The Company records the
            electricity revenue from these generation units at the price
            embedded in the PPA, including expected incentives and penalties
            for operating above or below specified availability targets set
            out in the PPA. Under this approach, incentives for the current
            period are deferred since they are not expected to be sustained
            over the full term of the PPA. As penalties are incurred, any
            balance of deferred incentive will be drawn down. If cumulative
            penalties exceed cumulative incentives, the excess will be
            charged to income and no deferred charge will be created.
            Deferred incentive amounts are included in other non-current
            liabilities on the balance sheet.

            The degree to which incentives are recognized or deferred will
            change due to revisions to the long-term outlook of plant
            performance, which is based on historical performance, planned
            maintenance, reliability and generation availability, and due to
            revisions in the estimated long-term price embedded in the PPA.

        (q) Asset retirement obligations:

            The Company recognizes asset retirement obligations in the period
            in which they are incurred, unless the fair value cannot be
            reasonably determined. A corresponding asset retirement cost is
            added to the carrying amount of the associated long-lived asset,
            and is depreciated over the estimated useful life of the asset.
            Accretion of the liability due to the passage of time is an
            operating expense, and is recorded over the estimated time period
            until settlement of the obligation.

            The Company has recorded asset retirement obligations for its
            power generation plants and Genesee coal mine as it is legally
            required to remove the facilities at the end of their useful
            lives and restore the plant and mine sites to their original
            condition. Asset retirement obligations for the coal mine are
            incurred over time as new areas are mined, and a portion of the
            liability is settled over time as areas are reclaimed prior to
            final pit reclamation.

        (r) Leases or arrangements containing a lease:

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

        (s) Contract liabilities:

            The Company's contract liabilities, primarily related to acquired
            EPLP PPAs, are being amortized over the terms of the contracts
            which range from three to eight years.

        (t) Foreign currency translation:

            The Company's self-sustaining foreign operations are translated
            to Canadian dollars using the current rate method. Assets and
            liabilities are translated at the exchange rate in effect at the
            balance sheet date. Revenues and expenses are translated at
            average exchange rates prevailing during the period. The
            resulting translation gains and losses are deferred and included
            in accumulated other comprehensive income until there is a
            reduction in the Company's net investment in the foreign
            operations.

            Foreign currency transactions and financial statements of
            integrated foreign operations are translated to Canadian dollars
            using the temporal method. Transactions denominated in foreign
            currencies are translated at exchange rates in effect at the
            transaction date. Monetary assets and liabilities denominated in
            foreign currencies are translated at the exchange rate in effect
            on the balance sheet date. The resulting foreign exchange gains
            and losses are included in the consolidated statements of income.

        (u) Employee future benefits:

            The employees of the Company are either members of the Local
            Authorities Pension Plan (LAPP) or other defined contribution or
            benefit plans.

            The LAPP is a multiemployer defined benefit pension plan. The
            Trustee of the plan is the Treasurer of Alberta and the plan is
            administered by a Board of Trustees. The Company and its
            employees make contributions to the plan at rates prescribed by
            the Board of Trustees to cover costs under the plan. Since the
            plan is a multiemployer plan, it is accounted for as a defined
            contribution plan. Accordingly, the Company does not recognize
            its share of any plan surplus or deficit.

            The Company maintains additional defined contribution and defined
            benefit pension plans to provide pension benefits to those
            employees (comprising less than 30% of total employees of Capital
            Power) who are not otherwise served by LAPP.

            The Company accrues its obligations for its defined benefit
            pension plans net of plan assets in the employee future benefits
            liabilities included in other non-current liabilities. The cost
            of pension benefits earned by employees is actuarially determined
            using the projected benefit method pro-rated on services and
            management's best estimate of expected plan investment
            performance, salary escalation and retirement ages of employees.
            For the purpose of calculating the expected return on plan
            assets, those assets are valued at quoted market value. The
            discount rate used to calculate the interest cost on the accrued
            benefit obligation is determined by reference to market interest
            rates at the balance sheet date on high-quality debt instruments
            with cash flows that match the timing and amount of expected
            benefit payments. Past service costs from plan amendments are
            amortized on a straight-line basis over the estimated average
            remaining service of employees active at the date of amendment.
            The excess of the net cumulative unamortized actuarial gain or
            loss over 10% of the greater of the accrued benefit obligation
            and the market value of plan assets is amortized over the
            estimated average remaining service period of the active
            employees.

            The Company has an unfunded long-term disability benefit plan
            which provides provincial health care premiums, health and dental
            benefits, and required pension contributions for current disabled
            employees. The plan is a defined benefit plan and the obligation
            related to long-term disability benefits is actuarially
            determined using the projected benefit method pro-rated on
            services and management's best estimate of future health care
            costs, salary escalation for estimating future benefit
            contributions, recovery and termination experience, and inflation
            rates. The Company's accrual for the long-term disability benefit
            plan is reflected in the employee future benefits liabilities
            included in other non-current liabilities. The discount rate used
            to calculate the interest cost on the accrued benefit obligation
            is determined by reference to market interest rates at the
            balance sheet date on high-quality debt instruments with cash
            flows that match the timing and amount of expected benefit
            payments. Actuarial gains or losses on the accrued benefit
            obligation arise from differences between actual and expected
            experience and from changes in the actuarial assumptions used to
            determine the accrued benefit obligation. Actuarial gains and
            losses are recognized in income immediately.

        (v) Stock-based compensation

            The Company determines the fair value of stock options using a
            binomial option pricing model at the date of grant. The fair
            value of the granted options is recognized over the vesting
            period as a compensation expense and contributed surplus.
            Contributed surplus is reduced as the options are exercised and
            the amount initially recorded in contributed surplus is credited
            to share capital. The Company has not incorporated an estimated
            forfeiture rate for stock options that will not vest, as the
            Company accounts for actual forfeitures as they occur.

        (w) Earnings per share

            Basic earnings per share is calculated by dividing income
            available to common shareholders by the weighted average number
            of common shares outstanding during the period.

            Diluted earnings per share is calculated on the treasury stock
            method, by dividing income available to common shareholders,
            adjusted for the effects of dilutive securities, by the weighted
            average number of common shares outstanding during the period
            and all additional common shares that would have been outstanding
            had all potential dilutive common shares been issued. This method
            computes the number of additional shares by assuming all
            outstanding options, for which the average market price of the
            common shares for the period exceeds the exercise price, are
            exercised. The total number of shares is then reduced by the
            number of common shares assumed to be repurchased from the total
            issuance proceeds, using the average market price of the
            Company's common shares for the period. The average market price
            of the Company's common shares for the period ended September 30,
            2009 was below the exercise price of all granted options and as a
            result none of the share purchase options described in note 14
            have a dilutive effect on earnings per share. Exchangeable common
            limited partnership units of CPLP, as described in note 3, are
            exchangeable for common shares of the Company and have a dilutive
            effect on earnings per share as described in note 14.

       ( x) Offsetting of financial assets and financial liabilities:

            Financial assets and financial liabilities are presented on a net
            basis when the Company has a legally enforceable right to set-off
            the recognized amounts and intends to settle on a net basis or to
            realize the asset and settle the liability simultaneously.

        (y) Long-term debt discounts, premiums and issue expenses:

            Debenture discounts, premiums and issue expenses with respect to
            long-term debt are amortized over the term of the related debt
            using the effective interest rate method.

    3.  Acquisition of assets and initial public offering:

        Pursuant to its initial public offering on July 9, 2009, the Company
        issued 21,750,000 common shares at a price of $23.00 per share for
        net proceeds of $468 million after deducting underwriting commissions
        of $25 million and offering expenses of $7 million. The net proceeds
        of the offering were used to purchase a 27.8% equity interest in
        CPLP. CPLP purchased substantially all of the power generation assets
        from EPCOR Utilities Inc. (EPCOR), effective July 1, 2009 through the
        following series of transactions (the Reorganization):

           -  Formation of CPLP: Capital Power and a wholly-owned subsidiary
              of Capital Power (Capital Power LP Holdings Inc.) formed CPLP.
              Capital Power acquired one general partner unit (GP Unit) and
              became the initial general partner of CPLP. Capital Power LP
              Holdings Inc. acquired one common limited partnership unit and
              as a result, became the initial limited partner in CPLP.

           -  Sale of EMCC Limited to Capital Power: EPCOR transferred all of
              the outstanding common shares of EMCC Limited to Capital Power
              in return for payment of approximately $468 million in cash.

           -  Contribution of Assets by EMCC Limited to CPLP: EMCC Limited
              contributed substantially all of its assets (consisting
              primarily of certain securities of subsidiary entities, its
              class B shares in the capital of EPLP Investments Inc. and
              promissory note of EPLP Investments Inc.) to CPLP in return for
              GP Units. Capital Power transferred its GP Unit in CPLP to EMCC
              Limited and as a result EMCC Limited became the general partner
              of CPLP.

           -  Sale of Assets by EPCOR Power Development Corporation (EPDC) to
              CPLP: EPDC transferred substantially all of its assets
              (consisting primarily of assets related to Genesee Units 1 and
              2, the Genesee Coal Mine joint venture and certain interests in
              partnerships) to CPLP in return for 56.625 million exchangeable
              limited partnership units of CPLP and approximately $896
              million in cash. CPLP financed the cash payment with the
              proceeds from a long-term debt obligation to EPCOR.

              Concurrently, EPDC subscribed for 56.625 million special voting
              shares of Capital Power for a nominal amount.

        Immediately following completion of the Reorganization, Capital Power
        held approximately 27.8% of CPLP while EPCOR held 56.625 million
        exchangeable limited partnership units of CPLP (exchangeable for
        common shares of Capital Power on a one-for-one basis) representing
        approximately 72.2% of CPLP. Each exchangeable limited partnership
        unit is accompanied by a special voting share in the capital of
        Capital Power which entitles the holder to a vote at Capital Power
        shareholder meetings, subject to the restriction that such special
        voting shares must at all times represent not more than 49% of the
        votes attached to all Capital Power common shares and special voting
        shares, taken together. Capital Power and EPCOR have agreed that for
        so long as EPCOR holds not less than a 20% interest in the common
        shares of Capital Power, the number of directors will not be less
        than nine. The special voting shares also entitle EPCOR, voting
        separately as a class, to nominate and elect a maximum of four
        directors of Capital Power. There are currently twelve directors on
        Capital Power's board of directors. Accordingly, Capital Power will
        have control over CPLP and, on that basis, the operations of CPLP
        will be consolidated by Capital Power for financial statement
        purposes.

        Immediately following completion of the Reorganization, CPLP held 49%
        and EPCOR held 51% of the voting rights in EPLP Investments Inc. EPLP
        Investments Inc. owns the approximate 30.6% interest in EPLP
        previously owned by EPCOR. However, CPLP is entitled to all of the
        economic interest in EPLP Investments Inc. Accordingly, effective
        July 1, 2009 Capital Power will consolidate the financial results of
        EPLP.

        The $468 million purchase price was allocated to the assets acquired
        and liabilities assumed based on estimated fair values as follows:

        ---------------------------------------------------------------------
        Cash and cash equivalents                                     $   71
        Other current assets                                             437
        Property, plant and equipment                                  3,163
        Power purchase arrangements                                      572
        Contract and customer rights and other intangible assets         179
        Derivative instruments assets - non-current                       74
        Future income tax assets - non-current                            57
        Acquired goodwill                                                123
        Other non-current assets                                         122
        Assets held for sale                                              36
        Current liabilities                                             (414)
        Long-term debt (including current portion)                    (1,761)
        Derivative instruments liabilities - non-current                 (64)
        Future income tax liabilities - non-current                      (93)
        Other non-current liabilities                                    (99)
        ---------------------------------------------------------------------
                                                                       2,403
        Non-controlling interests in net assets (note 13)             (1,935)
        ---------------------------------------------------------------------
        Fair value of net assets acquired                             $  468
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The values of the assets and liabilities above reflect management's
        best estimates as of the release date of these financial statements.
        The values of certain assets and liabilities are preliminary, and are
        subject to refinement as additional information is obtained. As of
        the issue date of these financial statements, the Company is
        performing additional analysis on its income tax balances recognized
        on acquisition and upon finalization, material adjustments may
        result.

        The $179 million of contract and customer rights and other
        intangibles includes $115 million of contract rights, $43 million of
        coal supply access rights and $21 million of other rights which
        include customer rights, lease rights, software intangibles and
        emission credits. Substantially all of the acquired contract and
        customer rights and other intangible assets are subject to
        amortization as described in note 2(l).

        The amount allocated to acquired goodwill is not deductible for
        income tax purposes.

        Non-controlling interests in net assets acquired include preferred
        share and other non-controlling interests in EPLP at the acquisition
        date of $122 million and $370 million respectively, as well as
        limited partnership units of CPLP issued to non-controlling interests
        as a part of the Reorganization of $1,302 million. The remaining non-
        controlling interests of $141 million relate to the non-controlling
        interest in net assets acquired.

        The results of operations of the subsidiaries and assets acquired
        from EPCOR are included in the Company's consolidated statements of
        income and retained earnings from July 1, 2009, the effective date of
        the acquisition.

        Capital Power has entered into various agreements with EPCOR to
        provide for certain aspects of the separation of the business of
        Capital Power from EPCOR, to provide for the continuity of operations
        and services and to govern the ongoing relationships between the two
        groups of entities.

    4.  Inventories:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Small parts and other consumables                             $   41
        Coal                                                              10
        Natural gas held in storage for trading purposes                   6
        ---------------------------------------------------------------------
                                                                      $   57
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Inventories expensed upon usage during the three months ended
        September 30, 2009 of $4 million were charged to energy purchases and
        fuel, and operations, maintenance and administration. No write-downs
        of inventories or reversals of previous write-downs were recognized
        in the three months ended September 30, 2009. At September 30, 2009,
        no inventories were pledged as security for liabilities.

    5.  Property, plant and equipment:

        ---------------------------------------------------------------------
                                            September 30, 2009
        ---------------------------------------------------------------------

                                  Composite
                               Depreciation             Accumulated Net Book
                                       Rate       Cost Depreciation    Value
        ---------------------------------------------------------------------
        Land                           None     $   66     $    -     $   66
        Plant and equipment            5.4%      2,323         27      2,296
        Contributions                 12.0%        (27)        (1)       (26)
        Construction work in
         progress                      None        863          -        863
        ---------------------------------------------------------------------
                                                $3,225     $   26     $3,199
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Depreciation, amortization and asset retirement accretion expense is
        comprised of:

        ---------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Depreciation on assets in service                             $   33
        Amortization of PPAs                                              12
        Gain on settlement of asset retirement obligations
         (note 12)                                                        (2)
        Accretion on asset retirement obligations (note 12)                1
        Amortization of contributions                                     (1)
        Amortization of contract and customer rights and other
         intangible assets                                                 1
        ---------------------------------------------------------------------
                                                                      $   44
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Interest capitalized to property, plant and equipment for the three
        months ended September 30, 2009 is $9 million.

        ---------------------------------------------------------------------

    6.  Power purchase arrangements:

        ---------------------------------------------------------------------
                                            September 30, 2009
        ---------------------------------------------------------------------
                                                        Accumulated Net book
                                                  Cost amortization    value
        ---------------------------------------------------------------------
        Alberta PPAs                            $  149     $    3     $  146
        EPLP PPAs                                  399          9        390
        ---------------------------------------------------------------------
                                                $  548     $   12     $  536
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    7.  Contract and customer rights and other intangible assets:

        ---------------------------------------------------------------------
                                            September 30, 2009
        ---------------------------------------------------------------------
                                                        Accumulated Net book
                                                  Cost amortization    value
        ---------------------------------------------------------------------
        Contract rights                         $  114      $    1   $   113
        Other rights                                50           -        50
        Software intangibles                         7           -         7
        Emission credits                             7           -         7
        Customer rights                              4           -         4
        ---------------------------------------------------------------------
                                                $  182      $    1   $   181
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    8.  Goodwill:

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

        ---------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Acquired goodwill (note 3)                                    $  123
        Foreign exchange translation adjustment                           (4)
        ---------------------------------------------------------------------
        Balance, end of period                                        $  119
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    9.  Other assets:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Carrying amount
          Loans and other long-term receivables                       $   49
          Net investment in lease                                         28
          Investment in PERH                                              13
          Portfolio investments                                            7
          Other                                                           20
        ---------------------------------------------------------------------
                                                                      $  117
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Net investment in lease

        The PPA under which the Company's power generation facility located
        in Oxnard, California operates is considered to be a direct financing
        lease for accounting. The PPA expires in 2020. The current portion of
        the net investment in lease of $2 million is included in accounts
        receivable. Financing income for the three months ended September 30,
        2009 of $1 million is included in revenues.

        Investment in PERH

        Through the acquisition described in note 3, the Company, as part of
        its EPLP subsidiary, acquired 17.0% of the common share interests and
        14.2% of the preferred interests in Primary Energy Recycling Holdings
        LLC (PERH). Effective August 24, 2009, PERH converted its outstanding
        preferred interests into common shares. As a result of the
        conversion, the Company now holds 14.3% of the outstanding common
        shares of PERH. Until the conversion date, the Company's common share
        interest in PERH was accounted for using the equity method and the
        preferred interest was recorded on the cost basis. Subsequent to the
        conversion of the preferred interests into common shares, the Company
        commenced recording its entire 14.3% common share interest on the
        cost basis. For the period from July 1 to August 24, 2009, equity
        losses of $1 million, included in operations, maintenance and
        administration expense, have been recorded against the common share
        investment in PERH.

        The Company, through its EPLP subsidiary, monitors its investment in
        PERH for impairment by considering current economic factors and
        records an impairment charge when it believes the investment has
        experienced a decline that is other than temporary. The Company
        estimates the fair value of its investment in PERH by considering
        factors such as the quoted market price of the securities issued by
        PERC, which owns the remaining interests in PERH not held by EPLP.
        During the three months ended September 30, 2009 the Company has not
        recognized an impairment on this investment.

    10. Long-term debt:

        ---------------------------------------------------------------------
                                                        Effective
                                                         Interest  September
                                                             Rate   30, 2009
        ---------------------------------------------------------------------
        Unsecured senior debt payable to EPCOR
          Due in 2010 at 6.95%                              4.90%     $  203
          Due in 2011 at 6.60%                              5.53%        204
          Due in 2016 at 6.75%                              6.16%        134
          Due in 2018 at 5.80%                              5.63%        165
          Due in 2018 at 9.00%                              7.41%        170
        ---------------------------------------------------------------------
                                                                         876
        EPLP unsecured senior notes (US$190), at 5.90%,
         due in 2014                                        6.23%        203
        EPLP unsecured senior medium-term notes, at 5.95%,
         due in 2036                                        7.11%        203
        EPLP unsecured senior medium-term notes (US$150),
         at 5.87%, due in 2017                              6.13%        159
        EPLP unsecured senior medium-term notes (US$75),
         at 5.97%, due in 2019                              6.26%         78
        EPLP secured term loan, at 11.25%, due in 2010     10.69%          1
        Non-recourse financing:
          Brown Lake Project, at 8.7%, due in 2016          7.13%          6
          Joffre Cogeneration Project, at fixed and
           floating rates, due in 2020                      8.35%         42
        CPLP revolving extendible credit facilities, at
         floating rates, due in 2009                        3.15%         77
        EPLP revolving extendible credit facilities, at
         floating rates, due in 2009                        1.16%        142
        ---------------------------------------------------------------------
                                                                       1,787

        Less: Current portion                                            247
              Deferred debt issue costs                                   16
        ---------------------------------------------------------------------
                                                                      $1,524
        ---------------------------------------------------------------------


        Unsecured senior debt payable to EPCOR

        The unsecured senior debt payable to EPCOR matures between 2010 and
        2018. On or after December 2, 2012, if EPCOR no longer owns, directly
        or indirectly, at least 20% of the outstanding limited partnership
        units of CPLP, a subsidiary of Capital Power, then EPCOR may, by
        written notice, require repayment of all or any portion of the
        outstanding principal amount of this debt and accrued interest
        thereon.

        EPLP unsecured senior notes

        The unsecured senior notes of $203 million mature in 2014 and are
        fully and unconditionally guaranteed by EPLP as to payment of
        principal, premium, if any, and interest on a senior unsecured basis.
        Interest is payable semi-annually.

        The unsecured senior medium-term notes of $203 million are due in
        2036 with interest payable semi-annually.

        The unsecured senior medium-term notes aggregating to $237 million
        (US$225 million) were issued in two tranches. The $159 million
        (US $150 million) and $78 million (US$75 million) are due in 2017 and
        2019 respectively with interest payable semi-annually.

        EPLP secured term loan

        The term loan matures in 2010 and is secured by a first fixed and
        specific mortgage over the Queen Charlotte plant which has a carrying
        amount of $14 million.

        Non-recourse financing

        Joffre Cogeneration Project financing represents the Company's share
        of syndicated loans for the project. A $40 million portion of the
        debt bears a fixed interest rate of 8.59% payable quarterly until
        2020. The remaining debt bears interest at the prevailing bankers'
        acceptance rate plus a spread of 1.5% which escalates to 1.875% over
        the term of the loan. The debt is secured by a charge against project
        assets which have a carrying amount of $100 million. Brown Lake
        Project financing is secured by a charge against project assets which
        have a carrying amount of $10 million.

        EPLP and CPLP revolving extendible credit facilities

        Unsecured three-year credit facilities of $100 million, $100 million
        and $125 million, for a total of $325 million, committed to 2011, and
        uncommitted amounts of $20 million, are available to the Company's
        subsidiary, EPLP. At September 30, 2009, the Company had $66 million
        in bankers' acceptances and $76 million (US$71 million) in U.S. LIBOR
        loans outstanding under this facility. Unsecured three-year credit
        facilities of $700 million, committed to 2012 and uncommitted amounts
        of $20 million, are available to the Company's subsidiary, CPLP. At
        September 30, 2009, the Company had $77 million in bankers'
        acceptances outstanding under this facility.

        The Company also has unsecured credit facilities of $500 million
        available through its CPLP subsidiary. These facilities have a
        maturity date of July 8, 2011 with an option to extend for an
        additional 364 day period. As at September 30, 2009, no amounts have
        been drawn on this facility, but letters of credit of $90 million
        have been issued as described in note 28.

        Under the terms of the extendible facilities, the Company may obtain
        advances by way of prime loans, U.S. base rate loans, U.S LIBOR loans
        and bankers' acceptances. Depending on the facility, amounts drawn by
        way of prime loans bear interest at the prevailing Canadian prime
        rate or the average one-month bankers' acceptance rate plus a spread
        ranging from 0.75% to 1.00%. Amounts drawn by way of U.S. base rate
        loans bear interest at a bank determined variable commercial lending
        rate or the prevailing Federal Funds Rate as published by the U.S.
        Federal Reserve Board plus a spread ranging from 0.75% to 1.00%.
        Amounts drawn by way of U.S. LIBOR loans bear interest at the
        prevailing LIBOR rate plus a spread based on the Company's credit
        rating. Amounts drawn by way of bankers' acceptances bear interest at
        the prevailing bankers' acceptance rate plus a spread based on the
        Company's credit rating.

    11. Other non-current liabilities:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Asset retirement obligations (note 12)                        $   81
        Employee future benefit liabilities                               11
        Other                                                              7
        ---------------------------------------------------------------------
                                                                      $   99
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    12. Asset retirement obligations:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Liabilities assumed on acquisition of assets (note 3)         $   88
        Liabilities incurred                                               2
        Liabilities settled                                               (2)
        Asset retirement accretion expense                                 1
        ---------------------------------------------------------------------
                                                                          89
        Less: current portion in accounts payable and accrued
         liabilities                                                       8
        ---------------------------------------------------------------------
                                                                      $   81
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Company estimates the undiscounted amount of cash flow required
        to settle its asset retirement obligations is approximately $383
        million, calculated using inflation rates ranging from 2% to 3%. The
        expected timing for settlement of the obligations is between 2009 and
        2090. The majority of the payments to settle the obligations are
        expected to occur between 2023 and 2064 for the power generation
        plants, and between 2009 and 2013 for sections of the Genesee coal
        mine. Discount rates ranging from 4.1% to 8.7% were used to calculate
        the carrying amount of the asset retirement obligations. No assets
        have been legally restricted for settlement of these liabilities.

    13. Non-controlling interests:

        Results of operations which relate to non-controlling interests are
        as follows:

        ---------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Non-controlling interests in EPLP                             $   20
        Non-controlling interests in CPLP                                 44
        Preferred share dividends paid by subsidiary company               2
        ---------------------------------------------------------------------
                                                                      $   66
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Non-controlling interests reflected on the consolidated balance sheet
        are comprised of:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Non-controlling interests in EPLP in net assets
         acquired (note 3)                                            $  370
        Net income attributable to non-controlling interests              20
        Other comprehensive loss attributable to non-controlling
         interests                                                       (20)
        Distributions to non-controlling interests                       (17)
        ---------------------------------------------------------------------
        Non-controlling interests in EPLP, end of period                 353
        ---------------------------------------------------------------------

        Non-controlling interests in CPLP in net assets
         acquired (note 3)                                               141
        Partnership units issued to non-controlling interests
         (note 3)                                                      1,302
        Net income attributable to non-controlling interests              44
        Other comprehensive income attributable to non-controlling
         interests                                                        13
        ---------------------------------------------------------------------
        Non-controlling interests in CPLP, end of period               1,500
        ---------------------------------------------------------------------

        Preferred shares outstanding in acquired subsidiaries
         (note 3)                                                        122
        ---------------------------------------------------------------------
        Preferred shares issued by subsidiary companies, end of
         period                                                          122
        ---------------------------------------------------------------------

                                                                      $1,975
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The non-controlling interests in EPLP represent the approximately
        69.4% interest in EPLP not owned by CPLP. The non-controlling
        interests in CPLP represents the approximately 72.2% interest in CPLP
        not owned by the Company which includes approximately 72.2% of CPLP's
        approximate 30.6% interest in EPLP.

    14. Share capital:

        ---------------------------------------------------------------------
                                                            Number of shares
        Authorized                                                authorized
        ---------------------------------------------------------------------
        Common shares                                              unlimited
        Preference shares, issuable in series                      unlimited
        Special voting shares                                      unlimited
        Special limited voting share                                     one
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        ---------------------------------------------------------------------
                                                                September 30,
        Issued and outstanding                                          2009
        ---------------------------------------------------------------------
        21,750,000 common shares                                      $  477
        56,625,000 special voting shares                                   -
        1 special limited voting share                                     -
        ---------------------------------------------------------------------
                                                                      $  477
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The $500 million of common shares issued to the public are recorded
        net of share issue costs of $32 million as described in note 3.
        Future income taxes of $9 million related to the share issue costs
        have been recorded as an increase to common shares.

        The special voting shares and special limited voting shares were
        issued to a related party, EPCOR (including subsidiaries of EPCOR).
        The special limited voting share entitles holders the right to vote
        as a class on any matter that would: (i) change the location of
        Capital Power's head office to a place other than The City of
        Edmonton in the Province of Alberta; (ii) amend the articles of
        Capital Power to, or result in a transaction that would, in each
        case, impact the location of the head office or its meaning as
        defined in Capital Power's articles; or (iii) amend the rights
        attaching to the special limited voting share.

        Share Purchase Options

        Under the Company's long term incentive plan, the Company provides
        stock options to certain employees to purchase common shares,
        provided that the number of shares reserved for issuance will not
        exceed 10% of the common shares to be outstanding at closing and that
        the aggregate number of shares issued by the Corporation under this
        Plan will not exceed 5,000,000 common shares.

        During the three months ended September 30, 2009 the Company granted
        993,400 stock options with one third vesting on January 1 of each of
        2010, 2011, and 2012. Fair value of these options at grant date was
        $2.57 per option resulting in total compensation expense recognized
        of $1 million in operations, maintenance and administration for the
        three months ended September 30, 2009. Granted options may be
        exercised within 7 years of the grant date at a price of $23.00 per
        share.

        At September 30, 2009, none of the Company's outstanding stock
        options were vested.

        The following assumptions were used in estimating the fair value of
        the granted stock options:

        ---------------------------------------------------------------------
        Variable                                   Value

        ---------------------------------------------------------------------
        Expected life              Seven-year term
        Risk free interest rate    Based on Government of Canada treasury
                                    bills and bonds at December 31, 2008
        Volatility                 20% (estimated based on similar publicly-
                                    traded companies)
        Dividend yield             4.75% to 5.5%
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Earnings per share

        The 56.625 million exchangeable limited partnership units issued to
        EPCOR as described in note 3 may be exchanged for common shares of
        Capital Power on a one-for-one basis. For purposes of the diluted
        earnings per share calculation, the exchange of such units for common
        shares of the Company would remove the non-controlling interest in
        net income related to CPLP of $44 million. Additionally, the income
        tax provision of the Company would need to be adjusted to reflect the
        non-controlling interest's share of CPLP income taxes of
        approximately $12 million.

    15. Accumulated other comprehensive income:

        The components of accumulated other comprehensive income, at
        September 30, 2009, are as follows:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Unrealized gains on derivative instruments
         designated as cash flow hedges(1)                           $    29
        Unrealized loss in self-sustaining foreign operations(2)         (33)
        Non-controlling interests(2)                                       7
        ---------------------------------------------------------------------
                                                                     $     3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Net of income tax expense of $3 million.
        (2) Net of income tax expense of nil.


    16. Change in non-cash working capital:

        ---------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Accounts receivable                                           $  (39)
        Income taxes recoverable                                           3
        Inventories                                                       (4)
        Prepaid expenses                                                  (3)
        Accounts payable and accrued liabilities                          (3)
        Other current liabilities                                          6
        ---------------------------------------------------------------------
                                                                      $  (40)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    17. Net financing expenses:

        ---------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Interest on long-term debt                                    $   26
        Capitalized interest                                              (9)
        ---------------------------------------------------------------------
                                                                      $   17
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    18. Income taxes:

        ---------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Current income taxes                                          $    -
        Future income taxes                                               (2)
        ---------------------------------------------------------------------
                                                                      $   (2)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Income taxes differ from the amounts that would be computed by
        applying the federal and provincial income tax rates as follows:

        ---------------------------------------------------------------------
                                                          Three months ended
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Income before income taxes and non-controlling
         interests                                                    $   78
        Statutory income tax rates                                     29.0%
        ---------------------------------------------------------------------
        Income taxes at statutory rate                                    23
        Increase (decrease) resulting from:
          Income not subject to income taxes at statutory
           rates                                                         (12)
          Change in income tax related to out-of-period
           adjustment                                                    (10)
          Unrecognized future income tax assets                           (4)
          Non-taxable amounts                                              2
          Adjustment for enacted changes in income tax laws and
           rates and other tax rate differences                           (1)

        ---------------------------------------------------------------------
                                                                      $   (2)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The tax effects of temporary differences that give rise to
        significant components of the future income tax assets and future
        income tax liabilities are presented below:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Property, plant and equipment - differences in net
         book value and tax bases                                     $ (114)
        Losses carried forward                                            74
        Cumulative eligible capital                                       21
        Deferred income from partnerships                                (19)
        Asset retirement obligations                                      15
        Power purchase arrangements                                      (11)
        Derivative Instruments                                             5
        Other                                                             (5)

        ---------------------------------------------------------------------
        Net future income tax liabilities                             $  (34)
        ---------------------------------------------------------------------

        Presented on the balance sheet as follows:
        Current assets                                                $    2
        Non-current assets                                                40
        Current liabilities                                              (17)
        Non-current liabilities                                          (59)

        ---------------------------------------------------------------------
                                                                      $  (34)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        At September 30, 2009, the Company has non-capital losses carried
        forward of approximately $239 million, of which $152 million relate
        to certain U.S. subsidiaries. These losses expire between 2010 and
        2029. The Company also has capital losses for income tax purposes of
        approximately $12 million which carry forward indefinitely. There are
        non-capital losses available to be carried forward of $22 million,
        and capital losses available to be carried forward of $3 million for
        which no tax benefit has been recognized.

        Reorganization

        As a result of the Reorganization (as described in note 3), Capital
        Power holds an economic interest in CPLP of 27.8%. Accordingly, the
        Company records current and future income tax provisions related to
        its economic interest in CPLP's taxable income. The Company also
        records future income tax provisions related to CPLP's temporary
        differences, and related to temporary differences of partnerships of
        which CPLP is a partner, to the extent of the Company's economic
        interest in CPLP.

        Out-of-period adjustment

        During the quarter ended September 30, 2009, EPLP, a subsidiary of
        the Company, recorded an out-of-period adjustment of $10 million
        relating to 2007, 2008 and 2009 to recognize net future income tax
        assets associated with EPLP's interest in a long-term investment. The
        long-term investment is treated as a partnership for U.S. tax
        purposes and the adjustments are attributable to allocation of tax
        deductions between the partners that were incorrectly calculated by
        the long-term investment's external tax advisors for the relevant
        periods. Of the $10 million, $3 million is attributable to 2007,
        $6 million is attributable to 2008 and $1 million is attributable to
        2009. The Company's management determined that the impact of the
        adjustment, after considering non-controlling interests, was not
        material to the expected results for the year ending December 31,
        2009. As such, the adjustment was recorded during the quarter ended
        September 30, 2009.

    19. Fair value and classification of non-derivative financial assets and
        liabilities:

        The Company classifies its cash and cash equivalents as held for
        trading and measures them at fair value. Accounts receivable are
        classified as loans and receivables; accounts payable and accrued
        liabilities are classified as other financial liabilities; all of
        which are measured at amortized cost and their fair values are not
        materially different from their carrying amounts due to their short-
        term nature.

        The classification, carrying amount and fair value of the Company's
        other financial instruments at September 30, 2009 are summarized as
        follows:

        ---------------------------------------------------------------------
                                                          September 30, 2009
                                                         --------------------
                                                         Carrying       Fair
        Financial asset or liability    Classification     amount      value
        ---------------------------------------------------------------------
        Other assets
         Loans and other long-term      Loans and
          receivables                   receivables        $   49     $   44
         Net investment in lease        Loans and
                                        receivables            28         28
        Long-term debt (including       Other financial
         current portion)               liabilities         1,771      1,745
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Net investment in lease

        The fair value of the Company's net investment in lease is based on
        the estimated interest rates implicit in comparable lease
        arrangements or loans plus an estimated credit spread based on the
        counterparty risk as at September 30, 2009.

        Long-term debt

        The fair value of the Company's long-term debt is based on
        determining a current yield for the Company's debt as at September
        30, 2009. This yield is based on an estimated credit spread for the
        Company over the yields of long-term Government of Canada and U.S.
        Government bonds that have similar maturities to the Company's debt.
        The estimated credit spread is based on the Company's indicative
        spread as published by independent financial institutions.

        Other financial instruments

        Fair values on the remaining financial instruments are determined by
        reference to quoted bid or ask prices, as appropriate, in active
        markets at period-end dates.

        The fair value of certain capital venture investments cannot be
        measured reliably as the shares are not quoted in an active market.
        Investments in common shares held at their carrying amount have not
        been offered for sale and in the event the Company elected to dispose
        of the shares, they would most likely be sold in a private
        transaction.

    20. Derivative instruments and hedge accounting:

        Derivative financial and non-financial instruments are held for the
        purpose of energy purchases, merchant trading or financial risk
        management.

        The derivative instruments assets and liabilities used for risk
        management purposes as described in note 21 consist of the following:

        ---------------------------------------------------------------------
                                            September 30, 2009
                              -----------------------------------------------
                                                          Foreign
                                          Energy         exchange
                              ------------------------- ----------
                                  Cash flow       Non-       Non-
                                     hedges     hedges     hedges      Total
        ---------------------------------------------------------------------
        Derivative instruments
         assets:
          Current                    $   17     $  128     $    3     $  148
          Non-current                    25         93         20        138

        Derivative instruments
         liabilities:
          Current                       (32)       (91)        (1)      (124)
          Non-current                   (29)       (61)        (5)       (95)
        ---------------------------------------------------------------------
        Net fair value               $  (19)    $   69     $   17     $   67
        ---------------------------------------------------------------------

        Net notional buys (sells):
          Megawatt hours of
           electricity (millions)        (2)        (3)
          Gigajoules of natural gas
           (millions)                    47         11
          Foreign currency
           (U.S. dollars)                                  $ (431)

        Range of contract               0.1        0.1        0.1
         terms in years              to 7.3     to 5.0     to 6.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Fair values of derivative instruments are determined, when possible,
        using exchange or over-the-counter price quotations by reference to
        quoted bid, ask or closing market prices as appropriate, in active
        markets. When there are limited observable prices due to illiquid or
        inactive markets, the Company uses appropriate valuation and price
        modeling techniques commonly used by market participants to estimate
        fair value. The Company may also rely on price forecasts prepared by
        third party market experts to estimate fair value when there are
        limited observable prices available. Fair values determined using
        valuation models require the use of assumptions concerning the
        amounts and timing of future cash flows. Fair value amounts reflect
        management's best estimates using external readily observable market
        data such as future prices, interest rate yield curves, foreign
        exchange rates, quoted Canadian dollar swap rate as the discount rate
        for time value, and volatility when available. It is possible that
        the assumptions used in establishing fair value amounts will differ
        from future outcomes and the impact of such variations could be
        material.

        The extent to which fair values of derivative instruments are based
        on observable market data is determined by the extent to which the
        market for the underlying commodity is judged to be active. With
        respect to natural gas, the Company has determined the market is
        active to the end of the contract terms. The fair value of the
        natural gas supply contracts is determined by reference to published
        price quotations.

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

        ---------------------------------------------------------------------
                                                         Three months ended
                                                         September 30, 2009
                                                      -----------------------

                                                       Unrealized   Realized
                                                            gains      gains
                                                          (losses)   (losses)
        ---------------------------------------------------------------------
        Energy cash flow hedges                            $   31     $  (22)
        Energy non-hedges                                      (4)         -
        Foreign exchange non-hedges                            32          -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Realized gains and losses relate only to financial derivative
        instruments. Gains and losses on non-financial derivative instruments
        settlements are recorded in energy revenues or energy purchases and
        fuel, as appropriate.

        If hedge accounting requirements are not met, unrealized and realized
        gains and losses on financial energy derivatives are recorded in
        energy revenues or energy purchases and fuel, as appropriate. If
        hedge accounting requirements are met, realized gains and losses on
        financial energy derivatives are recorded in energy revenues or
        energy purchases and fuel, as appropriate, while unrealized gains and
        losses are recorded in other comprehensive income. Unrealized and
        realized gains and losses on financial foreign exchange derivatives
        are recorded in energy revenues or foreign exchange gains and losses
        while such gains and losses on financial interest rate derivatives
        are recorded in net financing expenses.

        The Company has elected to apply hedge accounting on certain
        derivatives it uses to manage commodity price risk relating to
        electricity and natural gas prices. For the three months ended
        September 30, 2009, the change in the fair value of the ineffective
        portion of hedging derivatives required to be recognized in the
        income statement was nil. Net losses of $14 million, net of income
        taxes of $1 million, related to derivative instruments designated as
        cash-flow hedges, are expected to settle and be reclassified to net
        income over the next twelve months. The Company's cash flow hedges
        extend up to 2016.

    21. Risk management:

        Risk management overview

        The Company is exposed to a number of different financial risks,
        arising from business activities and its use of financial
        instruments, including market risk, credit risk, and liquidity risk.
        The Company's overall risk management process is designed to
        identify, manage and mitigate business risk which includes, among
        other risks, financial risk. Risk management is overseen by the
        Company's executive team according to objectives, targets, and
        policies approved by the Capital Power Board of Directors. The
        executive team is comprised of a senior management group including
        the Senior Vice President, Strategy and Risk.

        Capital Power's Senior Vice President, Strategy and Risk reports
        regularly to the Board of Directors on risk management activities of
        the executive team. Risk management strategies, policies, and limits
        are designed to help ensure the risk exposures are managed within the
        Company's business objectives and risk tolerance. The Company's
        financial risk management objective is to protect and minimize
        volatility in earnings and cash flow.

        Commodity price risk management and the associated credit risk
        management are carried out in accordance with financial risk
        management policies, as approved by the executive team and the Board
        of Directors. Financial risk management including foreign exchange
        risk, interest rate risk, liquidity risk, and the associated credit
        risk management, is carried out by a centralized Treasury function.
        Capital Power's Audit Committee of the Board of Directors, in its
        oversight role, monitors the assessment of risk management controls
        and procedures to ensure compliance with applicable policies.

        Market risk

        Market risk is the risk of loss that results from changes in market
        factors such as commodity prices, foreign currency exchange rates,
        interest rates, and equity prices. The level of market risk to which
        the Company is exposed at any point in time varies depending on
        market conditions, expectations of future price or market rate
        movements and the composition of the Company's financial assets and
        liabilities held, non-trading physical asset and contract portfolios,
        and trading portfolios.

        To manage the exposure related to changes in market risk, the Company
        uses various risk management techniques including derivative
        instruments. Derivative instruments may include forward contracts,
        fixed-for-floating swaps (or contracts-for-differences), and option
        contracts. Such derivative instruments may be used to establish a
        fixed price for an energy commodity, an interest-bearing obligation
        or an obligation denominated in a foreign currency. Commodity market
        risk exposures are monitored daily against approved risk limits, and
        control processes are in place to monitor that only authorized
        activities are undertaken.

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

        Commodity price risk

        The Company is exposed to commodity price risk as part of its normal
        business operations, including energy procurement activities in
        Alberta, Ontario, and the U.S. The Company's energy procurement
        activities consist of power generation, non-market traded and market
        traded electricity and natural gas purchase and sales contracts, and
        derivative contracts. The Company is primarily exposed to changes in
        the prices of electricity, and to a lesser extent is exposed to
        changes in the prices of natural gas and coal. The Company actively
        manages commodity price risk by optimizing its asset and contract
        portfolios utilizing the following methods variously:

        -  The Company reduces its exposure to the volatility of commodity
           prices related to electricity sales by entering into offsetting
           contracts such as contracts-for-differences and firm price
           physical contracts for periods of varying duration.

        -  The Company enters into fixed-price energy sales contracts and
           power purchase arrangements which limit the exposure to
           electricity prices. The Company has entered into long-term tolling
           arrangements whereby variable changes linked to the price of
           natural gas and coal are assumed by the counterparty.

        -  When it is economically feasible, the Company purchases natural
           gas under long-term fixed-price supply contracts to reduce the
           exposure to fluctuating natural gas prices on its natural gas-
           fired generation plants and physical obligations arising from
           retail customers.

        -  The Company enters into back-to-back electricity and natural gas
           physical and financial contracts in order to lock in a margin.

        The Company also engages in taking market risk positions within
        authorized limits approved by Capital Power's executive team and
        Board of Directors. The trading portfolio consists of electricity and
        natural gas physical and financial derivative contracts which are
        transacted with the intent of benefiting from short-term actual or
        expected differences between their buying and selling prices or to
        lock in arbitrage opportunities.

        The fair value of the Company's energy related derivatives at
        September 30, 2009 that are required to be measured at fair value
        with the respective changes in fair value recognized in net income
        are disclosed in note 20.

        The Company employs specific volumetric limits and a Value-at-Risk
        (VaR) methodology to manage risk exposures to commodity prices on a
        consolidated basis. VaR measures the estimated potential loss in a
        portfolio of positions associated with the movement of a commodity
        price for a specified time or holding period and a given confidence
        level. Capital Power's VaR uses a statistical confidence interval of
        95% over a twenty business day holding period. This measure reflects
        a 5% probability that, over the twenty day period commencing with the
        point in time that the VaR is measured, the fair value of the overall
        commodity portfolio could decrease by an amount in excess of the VaR
        amount. The VaR methodology is a statistically-defined, probability-
        based approach that takes into consideration market volatilities and
        risk diversification by recognizing offsetting positions and
        correlations between products and markets. This technique makes use
        of historical data and makes an assessment of the market risk arising
        from possible future changes in commodity prices over the holding
        period.

        VaR should be interpreted in light of the limitations of the
        methodologies used. These limitations include the following:

        -  VaR calculated based on a holding period may not fully capture the
           market risk of positions that cannot be liquidated or hedged
           within the holding period.

        -  The Company computes VaR of the portfolios at the close of
           business and positions may change substantially during the course
           of the day.

        -  VaR, at a 95% confidence level, does not reflect the extent of
           potential losses beyond that percentile. Losses on the other 5% of
           occasions could be substantially greater than the estimated VaR.

        These limitations and the nature of the VaR measurements mean that
        the Company can neither guarantee that losses will not exceed the VaR
        amounts or that losses in excess of the VaR amounts will not occur
        more frequently than 5% of the time. As VaR is not a perfect measure
        of risk, the Company applies a safety factor to the calculated VaR
        amount to estimate total exposure (TE) which attempts to capture
        unaccounted for exposures due to the assumptions and limitations
        inherent in the calculation of VaR and to improve the confidence
        level beyond 95%.

        The estimation of TE takes into account positions from all wholly-
        owned subsidiaries and subsidiaries in which the Company has
        controlling interest, and reflects the Company's aggregate commodity
        positions from its trading and asset portfolios. Capital Power's
        Board of Directors has established an aggregate TE limit, under their
        risk management policy, which is monitored and reported to the
        executive team on a daily basis. The portfolios are stress tested
        regularly to observe the effects of plausible scenarios taking into
        account historical maximum volatilities and maximum observed price
        movements.

        Foreign exchange risk

        The Company is exposed to foreign exchange risk on foreign currency
        denominated forecasted transactions, firm commitments, and monetary
        assets and liabilities denominated in a foreign currency and on its
        net investments in foreign operations. The Company's operations
        expose it to foreign exchange risk arising from transactions
        denominated in foreign currencies. The Company's foreign exchange
        risk arises primarily with respect to the U.S. dollar but it is
        potentially exposed to changes in other currencies if and when it
        transacts in other currencies. The risk is that the functional
        currency value of cash flows will vary as a result of the movements
        in exchange rates.

        The Company's foreign exchange management policy is to attempt to
        minimize economic and material transactional exposures arising from
        movements in the Canadian dollar relative to the U.S. dollar or other
        foreign currencies. The Company's exposure to foreign exchange risk
        arises from future anticipated cash flows from its U.S. operations,
        debt service obligations on U.S. dollar borrowings, and from certain
        capital expenditure commitments denominated in U.S. dollars or other
        foreign currencies. The Company co-ordinates and manages foreign
        exchange risk centrally, by identifying opportunities for naturally-
        occurring opposite movements and then dealing with any material
        residual foreign exchange risks; these are hereinafter referred to as
        being economically hedged.

        The Company primarily uses foreign currency forward contracts to fix
        the functional currency of its non-functional currency cash flows
        thereby reducing its anticipated U.S. dollar denominated
        transactional exposure. The Company looks to limit foreign currency
        exposures as a percentage of estimated future cash flows. The
        percentage amount to be fixed will generally be higher, the shorter
        the period into the future that the cash flows relate to. At
        September 30, 2009, US$453 million or approximately 94% of expected
        future net cash flows from EPLP's U.S. plants had been economically
        hedged for 2009 to 2015 at a weighted average exchange rate of $1.12
        per U.S. dollar. At September 30, 2009, the Company has transactional
        exposure for US$22 million or approximately 91% of expected future
        net cash flows for capital expenditure commitments, which have been
        economically hedged for 2009 to 2011 at a weighted average exchange
        rate of $1.09 per U.S. dollar.

        As at September 30, 2009, holding all other variables constant, a
        $0.10 strengthening or weakening of the Canadian dollar against the
        U.S. dollar would increase or decrease net income by approximately $1
        million after tax. There would be no impact to other comprehensive
        income.

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

        Interest rate risk

        The Company is exposed to changes in interest rates on its cash and
        cash equivalents, and floating rate short-term and long-term loans
        and obligations. The Company is exposed to interest rate risk from
        the possibility that changes in the interest rates will affect future
        cash flows or the fair values of its financial instruments. In some
        circumstances, floating rate funding may be used for short-term
        borrowings and other liquidity requirements. At September 30, 2009,
        the proportion of fixed rate debt was approximately 88% of total
        long-term debt outstanding. The Company may also use derivative
        instruments to manage interest rate risk. At September 30, 2009, the
        Company did not hold any interest rate derivative instruments.

        Assuming that the amount and mix of fixed and floating rate loans and
        net debt remains unchanged from that held at September 30, 2009, a
        100 basis point change to interest rates would decrease or increase
        full year net income by $1 million and would have no direct impact on
        other comprehensive income.

        The effect on net income does not consider the effect of an overall
        change in economic activity that would accompany such an increase or
        decrease in interest rates. There would be no impact on net income
        for debt and long-term loan arrangements issued and held by the
        Company at fixed interest rates.

        Credit risk

        Credit risk is the possible financial loss associated with the
        inability of counterparties to satisfy their contractual obligations
        to the Company. The Company's counterparty credit risk management
        policy is established by the executive team and approved by the Board
        of Directors and the associated procedures and practices are designed
        to manage the credit risks associated with the various business
        activities throughout the Company. Credit and counterparty risk
        management procedures and practices generally include assessment of
        individual counterparty creditworthiness and establishment of
        exposure limits prior to entering into a transaction with the
        counterparty. Exposures and concentrations are subsequently monitored
        and are regularly reported to the executive team. Creditworthiness
        continues to be evaluated after transactions have been initiated, at
        minimum, on an annual basis. To manage and mitigate credit risk, the
        Company employs various credit mitigation practices such as master
        netting agreements, margining to reduce energy trading risks, credit
        derivatives and other forms of credit enhancements including cash
        deposits, parent company guarantees, and bank letters of credit.

        Maximum credit risk exposure

        The Company's maximum credit exposure was represented by the carrying
        amount of the following financial assets:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Cash and cash equivalents                                       $ 64
        Accounts receivable(1)                                           248
        Derivative instruments assets(1)                                 286
        Loans and other long-term receivables                             49
        Net investments in leases                                         28
        Loan commitments to third parties                                  6
        ---------------------------------------------------------------------
                                                                       $ 681
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) The Company's maximum exposures related to accounts receivable
            and derivative instruments assets by major credit concentration
            are comprised of maximum exposures of $170 million for generation
            and $364 million for wholesale.

        This table does not take into account collateral held. At September
        30, 2009, the Company held cash deposits of $2 million as security
        for certain counterparty accounts receivable and derivative
        contracts. The Company is not permitted to sell or re-pledge this
        collateral in the absence of default of the counterparties providing
        the collateral. At September 30, 2009, the Company also held other
        forms of credit enhancement in the form of letters of credit of $25
        million and parental guarantees of $723 million.

        Credit quality and concentrations

        The Company is exposed to credit risk on outstanding accounts
        receivable associated with its generation and energy sales activities
        including power purchase arrangements and agreements with independent
        system operators, power and steam sales contracts and on energy
        supply agreements with government sponsored entities and wholesale
        customers. The Company is also exposed to credit risk from its cash
        and cash equivalents (including short-term investments), financial
        and non-financial derivative instruments, and long-term financing
        arrangements.

        The credit quality of the Company's accounts receivable, by major
        credit concentrations, and other financial assets are the following:

        ---------------------------------------------------------------------
                                                         September 30, 2009
                                                      -----------------------
                                                       Investment       Non-
                                                      grade(1) or investment
                                                        secured(3)   grade(1)
        ---------------------------------------------------------------------
        Accounts receivable and financial derivative
         instruments
          Generation                                         100%          -
          Wholesale(2)                                        90%        10%
        Cash and cash equivalents                            100%          -
        Loans and other long-term receivables                100%          -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Credit ratings are based on the Company's internal criteria and
            analyses which take into account, among other factors, the
            investment grade ratings of external credit rating agencies when
            available.

        (2) Includes industrial end-use customers, trading and position
            management counterparties.

        (3) Certain accounts receivable and other financial assets are
            considered to have low credit risk as they are either secured by
            the underlying assets, secured by other forms of credit
            enhancements, or the counterparties are local or provincial
            governments.

        Generation credit risk

        Credit risk exposure from power purchase arrangements, agreements
        with independent system operators, power and steam sales contracts,
        and certain energy supply agreements is predominantly restricted to
        accounts receivables and contract default. In certain cases, the
        Company relies on a single or small number of customers to purchase
        all or a significant portion of a facility's output. The failure of
        any one of these counterparties to fulfill its contractual
        obligations could negatively impact the Company's financial results.
        Financial loss resulting from events of default by counterparties in
        certain power purchase arrangements and steam purchase agreements may
        not be recovered since the contracts may not be replaceable on
        similar terms under current market conditions. Consequently, the
        Company's financial performance depends on the continued performance
        by customers and suppliers of their obligations under these long-term
        agreements. Credit risk exposure is mitigated by dealing with
        creditworthy counterparties, netting amounts by legally enforceable
        set-off rights, and, when appropriate, taking back security from the
        counterparty. Credit risk with government-owned or sponsored entities
        and regulated public utility distributors is generally considered
        low.

        Wholesale and merchant credit risk

        Credit risk exposure for wholesale and merchant trading
        counterparties is measured by calculating the costs (or proceeds) of
        replacing the commodity position (physical and derivative contracts),
        adjusting for settlement amounts due to or due from the counterparty
        and, if permitted, netting amounts by legally enforceable set-off
        rights. Financial loss on wholesale contracts could include, but is
        not limited to, the cost of replacing the obligation, amounts owing
        from the counterparty or any loss incurred on liability settlements.
        Credit risk exposure is mitigated by dealing with creditworthy
        counterparties, monitoring credit exposure limits, margining to
        reduce energy trading risks, parent company guarantees, and when
        appropriate taking back security from the counterparty.

        Accounts receivable and allowance for doubtful accounts

        Accounts receivable consist primarily of amounts due from customers
        including industrial and commercial customers, independent system
        operators from various regions, government-owned or sponsored
        entities, and other counterparties. Larger commercial and industrial
        customer contracts and contracts-for-differences provide for
        performance assurances including letters of credit. The Company also
        has credit exposures to large suppliers of electricity and natural
        gas. The Company mitigates these exposures by dealing with
        creditworthy counterparties and, when appropriate, taking back
        appropriate security from the supplier.

        The aging of accounts receivable was:

        ---------------------------------------------------------------------
                                                  September 30, 2009
                                         ------------------------------------
                                                        Allowance
                                                 Gross        for        Net
                                              accounts   doubtful   accounts
                                            receivable   accounts receivable
        ---------------------------------------------------------------------
        Current(1)                              $  249     $    1     $  248
        Outstanding 30 to 60 days                    1          1          -
        ---------------------------------------------------------------------
        Total                                   $  250     $    2     $  248
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Current amounts represent accounts receivable outstanding zero to
            30 days. Amounts outstanding more than 30 days are considered
            past due.

        In conjunction with the acquisition of assets described in note 3,
        the Company has assumed allowances for doubtful accounts of $2
        million, which is the balance included in accounts receivable as at
        September 30, 2009. The Company has also assumed allowances for
        doubtful accounts of $2 million relating to long-term receivables
        which are recorded against the long-term receivable balance in other
        assets at September 30, 2009.

        At September 30, 2009, the Company held $2 million of customer
        deposits for the purpose of mitigating the credit risk associated
        with accounts receivable from customers.

        At September 30, 2009, there was no provision for credit losses
        associated with accounts receivable from treasury, trading and energy
        procurement counterparties as all balances are considered to be fully
        collectable.

        Liquidity risk

        Liquidity risk is the risk that the Company will not be able to meet
        its financial obligations as they become due. The Company's liquidity
        is managed centrally by the Treasury function. The Company manages
        liquidity risk through regular monitoring of cash and currency
        requirements by preparing short-term and long-term cash flow
        forecasts and also by matching the maturity profiles of financial
        assets and liabilities to identify financing requirements. The
        financing requirements are addressed through a combination of
        committed and demand revolving credit facilities, financings in
        public capital debt markets and equity offerings by the Company or
        its CPLP or EPLP subsidiaries.

        CPLP has a long-term debt rating of BBB, assigned by both Standard
        and Poor's (S&P) and DBRS Limited (DBRS). EPLP has a long-term debt
        rating of BBB+ and BBB(high), assigned by S&P and DBRS respectively.

        As at September 30, 2009, the Company had undrawn and committed bank
        credit facilities, including operating lines of credit, of $1,282
        million, of which $723 million is committed for at least two years.
        In addition, EPLP has a Canadian shelf prospectus under which it may
        raise up to $1 billion in partnership units or debt securities, of
        which a maximum of $600 million can be medium-term notes. The
        Canadian shelf prospectus expires August 2010. As at September 30,
        2009, EPLP has not drawn on the shelf prospectus.

        The following are the undiscounted cash flow requirements and
        contractual maturities of the Company's financial liabilities,
        including interest payments, as at September 30, 2009:

    -------------------------------------------------------------------------
                                                                       Total
                                           Due in             Due in  contr-
                               ------------------------------   2014  actual
                      Due in                                     and    cash
                        2009    2010    2011    2012    2013  beyond   flows
    -------------------------------------------------------------------------
    Non-derivative
     financial
     liabilities:
    Long-term debt    $    1  $  247  $  376  $  104  $  313  $  738  $1,779
    Interest payments
     on long-term debt    28      95      84      67      65     446     785
    Accounts payable
     and accrued
     liabilities(1)      267       -       -       -       -       -     267
    Other current
     liabilities           9       -       -       -       -       -       9
    Loan commitments       6       -       -       -       -       -       6
    Derivative financial
     liabilities:
    Net forward foreign
     exchange contracts    -       2       1       1       1       2       7
    Net commodity
     contracts-for-
     differences          38      67      41       4       -       -     150
    -------------------------------------------------------------------------
    Total             $  349  $  411  $  502  $  176  $  379  $1,186  $3,003
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Excluding accrued interest on long-term debt of $8 million.


    22. Capital management:

        The Company's primary objectives when managing capital are to
        safeguard the Company's ability to continue as a going concern, pay
        dividends to its shareholders in accordance with the Company's
        dividend policy, maintain a suitable credit rating, and to facilitate
        the acquisition or development of projects in Canada and the U.S.
        consistent with the growth strategy of the Company. The Company
        manages its capital structure in a manner consistent with the risk
        characteristics of the underlying assets.

        The Company manages capital through regular monitoring of cash and
        currency requirements by preparing short-term and long-term cash flow
        forecasts and reviewing monthly financial results. The Company
        matches the maturity profiles of financial assets and liabilities to
        identify financing requirements to help ensure an adequate amount of
        liquidity.

        The Company considers its capital structure to consist of short-term
        debt and long-term debt net of cash and cash equivalents, non-
        controlling interests (including preferred shares issued by
        subsidiary companies) and shareholder's equity. The following table
        represents the total capital of the Company:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Long-term debt (including current portion) (note 10)          $1,771
        Cash and cash equivalents                                        (64)
        ---------------------------------------------------------------------
        Net debt                                                       1,707
        ---------------------------------------------------------------------

        Non-controlling interests (note 13)                            1,975
        Shareholders' equity                                             494
        ---------------------------------------------------------------------
        Total equity                                                   2,469
        ---------------------------------------------------------------------

        Total capital                                                 $4,176
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Company has no externally imposed requirements on its capital
        except as disclosed below.

        CPLP has the following externally imposed requirements on its capital
        as a result of its credit facilities and certain debt covenants:

        -  Maintenance of modified consolidated net tangible assets to
           consolidated net tangible assets ratio, as defined in the debt
           agreements, of not less than 0.90 to 1.0;

        -  Maintenance of senior debt to consolidated capitalization ratio,
           as defined in the debt agreements, of not more than 0.65 to 1.0;

        -  Limitation on debt issued by subsidiaries; and

        -  In the event that CPLP is assigned a rating of less than BBB- by
           S&P and BBB(Low) by DBRS, CPLP would also be required to maintain
           a ratio of earnings before interest, income taxes, depreciation
           and amortization to interest expense, as defined in the debt
           agreements, of not less than 2.5 to 1.0.

        EPLP has the following externally imposed requirements on its
        capital:

        -  Maintenance of debt to total capitalization ratio, as defined in
           the debt agreements, of not more than 65%; and

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

        These capital restrictions are defined in accordance with the
        respective agreements.

        For the period ended September 30, 2009, CPLP and EPLP complied with
        all externally imposed capital restrictions.

        To manage or adjust its capital structure, the Company can issue new
        debt, issue common or preferred shares, redeem preferred shares,
        issue new CPLP or EPLP units, repay existing debt or adjust dividends
        paid to its shareholders.

    23. Related party balances and transactions:

        The following summarizes the Company's related party balances and
        transactions with EPCOR and its subsidiaries. All transactions are in
        the normal course of operations, and are recorded at the exchange
        amount, which is the consideration established and agreed to by the
        parties.

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Balance sheet:
          Accounts receivable                        (a)              $   60
          Other assets                               (b)                   7
          Property, plant and equipment              (c)                   9
          Accounts payable - accrued interest
           on debt                                                        12
          Long-term debt (including current
           portion) (note 10)                                            876
          Share capital (note 14)                                          -

        Income statement:
          Revenues - energy sales                                        103
          Energy purchases and fuel                  (d)                   6
          Net financing expenses                     (e)                   6

        ---------------------------------------------------------------------

        (a) Accounts receivable includes $30 million relating to energy
            sales to subsidiaries of EPCOR and $30 million of amounts owed
            from EPCOR relating to operational cash transactions during the
            acquisition changeover period.
        (b) Contributions made to subsidiaries of EPCOR for the construction
            of aerial and underground transmission lines.
        (c) Interest on long-term debt to EPCOR capitalized to property,
            plant and equipment.
        (d) Includes energy distribution and transmission charges from
            subsidiaries of EPCOR.
        (e) Net financing expenses on long-term debt to EPCOR.

    24. Joint ventures:

        The Company and the coal mine operator at the Genesee plant site each
        have a 50% interest in the Genesee Coal Mine Joint Venture. The joint
        venture partner operates the coal mine. Under agreements governing
        this joint venture, all coal mined is to be supplied to the Company's
        Genesee generation plant.

        The Company holds 50% interests in the Genesee 3 Project, the
        Keephills 3 Project and the Taylor's Coulee Chute Hydro Project, and
        holds a 40% interest in the Joffre Cogeneration Project. The Company,
        through its EPLP subsidiary, also holds a 50.15% interest in the
        Frederickson power plant.

        A financial summary of the Company's investments in joint ventures is
        as follows:

        ---------------------------------------------------------------------
                                                                September 30,
                                                                        2009
        ---------------------------------------------------------------------
        Current assets                                                $   43
        Long-term assets                                               1,061
        Current liabilities                                               56
        Long-term liabilities                                             41
        Revenues(1)                                                       16
        Expenses(2)                                                       19
        Net loss                                                          (3)
        Cash flows from operating activities                              (1)
        Cash flows used in investing activities                          (79)
        Cash flows from financing activities                              66
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Excludes all revenues from Genesee 3, which are recorded as
            revenues by the Company but are not subject to the terms of the
            joint venture agreement.
        (2) Excludes all costs of operating the Genesee Coal Mine Joint
            Venture which are recorded as fuel expenses by the Company.

        Included in the Company's cash and cash equivalents at September 30,
        2009 is its proportionate share of cash and cash equivalents which is
        restricted to use within joint ventures of $26 million.

        Under the terms of the Company's interests in the Frederickson power
        plant, the Genesee 3 Project and the Keephills 3 Project, the Company
        and its respective partners have guaranteed financial and performance
        obligations under the joint venture agreements limited to $40
        million, $50 million and $50 million respectively.

    25. Employee future benefits:

        Multiemployer defined benefit pension plan and defined contribution
        pension plan

        Over 85% of the Company's employees are either members of the Local
        Authority Pension Plan or the Company's registered defined
        contribution plans. Accordingly, the majority of the Company's
        pension costs and obligations are accounted for as defined
        contribution plans.

        Defined benefit plans

        Prior to the transfer of employees resulting from the acquisition
        described in note 3, the effective date for the latest actuarial
        valuations of both the Company's registered and supplemental pension
        plans was December 31, 2007. The effective date of the next valuation
        for funding purposes is no later than December 31, 2010 for both
        plans. The plan assets and the accrued benefit obligation have been
        estimated as at September 30, 2009. The supplemental pension plan is
        a non-contributory plan that is unfunded at September 30, 2009.

        As part of the Company's acquisition of its interest in EPLP from
        EPCOR, employees who transferred to Capital Power on July 1, 2009
        became members of the Company's registered pension plan. The plan
        provides pension benefits based on an employee's years of service and
        their highest earnings over three consecutive years of employment.
        Retirement pensions will be increased annually by a portion of the
        increase in the Consumer Price Index. Prior to the Company's
        acquisition of its interest in EPLP, EPCOR had previously acquired
        the interest in EPLP from a third party. Under the terms of EPCOR's
        previous purchase and sale agreement, the previous plan sponsor
        transferred the pension liabilities for the Canadian employees and
        associated assets based on an actuarial valuation. At September 30,
        2009, the actual transfer of assets has not yet occurred as
        regulatory approval required for transfer of the assets and
        obligations is still outstanding.

        Plan benefit costs, assets and obligations

        The accrued benefit liability and other employee future benefit
        liabilities, totalling $11 million and assumed as part of the
        acquisition described in note 3 are included in other non-current
        liabilities. Other employee future benefit liabilities consist mainly
        of obligations for benefits provided to employees on long-term
        disability leaves.

        The market value of the defined benefit plan assets at September 30,
        2009 was approximately $10 million.

        Total cash payments for pension benefits in the three months ended
        September 30, 2009, consisting of cash contributed by the Company to
        the LAPP, other defined contribution and benefit plans and cash
        payments directly to beneficiaries for its unfunded pension plan,
        were $2 million.

    26. Plants under operating leases:

        Certain power generation plants operate under PPAs that convey the
        right to the holder of the agreement to use the related property,
        plant and equipment. Consequently, these power generation plants,
        comprised of ManChief, Mamquam, Queen Charlotte, Southport, Roxboro,
        Kenilworth, Greeley, Williams Lake, Genesee units 1 and 2, Miller
        Creek and Brown Lake are accounted for as assets under operating
        leases. As at September 30, 2009, the carrying amount of such
        property, plant and equipment was $1,314 million, less accumulated
        depreciation of $12 million. The Company's revenue pursuant to the
        arrangements for the three months ended September 30, 2009 was
        $106 million.

    27. Contingencies and commitments:

        (a) The Company has committed to purchase new high efficiency gas-
            fired electric generating units for its Clover Bar Energy Centre.
            As at September 30, 2009, the estimated remaining total cost to
            be incurred is $30 million.

        (b) The Company and TransAlta Corporation (TransAlta) are in the
            process of building Keephills 3, a 495 megawatt (MW)
            supercritical coal-fired generation plant at TransAlta's
            Keephills site. The construction is expected to be completed in
            2011. As at September 30, 2009, the Company's 50% committed share
            of the estimated total remaining capital cost to be incurred is
            $287 million. As of October 30, 2009, the Board of Directors of
            CPC and TransAlta had approved additional funding and a revised
            schedule for the Keephills 3 project. The total project cost was
            revised from $1.8 billion to $1.9 billion and Capital Power's
            share was correspondingly revised from $903 million to $955
            million resulting in an additional $52 million of costs expected
            to be incurred by the Company. As part of contractual
            arrangements, the Company and TransAlta have indemnified each
            other for up to $115 million during construction in the event
            that either party makes payments to the turbine supplier on
            behalf of the other party.

        (c) EPLP has committed to the enhancement of the Southport and
            Roxboro facilities through 2009. As at September 30, 2009, the
            Company expects an additional $33 million (US$31 million) to be
            spent on the enhancement work. EPLP has committed to the upgrade
            of the gas turbine at the Oxnard facility, to be spent over the
            remaining months of 2009 and 2010. As at September 30, 2009, the
            Company expects an additional $17 million (US$16 million) to be
            spent on the upgrade of the Oxnard turbine.

        (d) Under the terms of the acquired Alberta PPAs, the Company is
            obligated to make monthly payments for fixed and variable costs.
            The estimated annual total of these payments for the remainder of
            2009 is $31 million. The actual amounts for the remainder of 2009
            and future years may vary from estimates depending on generation
            volume and scheduled outages. It is expected that the annual
            payments over the remaining terms of the Alberta PPAs, as
            described in note 2(k), will range from $89 million to $182
            million, adjusted for inflation, other than in the event of a
            forced outage.

        (e) The Company has entered into a number of long-term energy
            purchase and transportation contracts and operating and
            maintenance contracts in the normal course of operations. Some of
            these energy purchase and transportation contracts are measured
            at their fair value and recorded on the consolidated balance
            sheet as derivative instruments assets and liabilities as
            appropriate. The energy purchase and transportation contract
            amounts disclosed below are based on gross settlement amounts.
            Approximate future payments under these contracts and under
            operating leases for premises are as follows:

            -----------------------------------------------------------------
                                                Energy  Operating
                                          purchase and  and main-
                                        transportation    tenance  Operating
                                             contracts  contracts     leases
            -----------------------------------------------------------------
            Fourth quarter of 2009              $   56     $    7     $    -
            2010                                   113         28          2
            2011                                    93         28          1
            2012                                    78         28          4
            2013                                    64         29          4
            Thereafter                             205        126         70
            -----------------------------------------------------------------
            Total                               $  609     $  246     $   81
            -----------------------------------------------------------------
            -----------------------------------------------------------------

        (f) The Company has committed to issue non-interest bearing notes
            receivable to the non-Capital Power syndicate members involved in
            the Sundance Swap transaction entered into by Capital Power
            subsidiaries prior to the acquisition of subsidiaries and assets
            from EPCOR as disclosed in note 3. The commitment relates to
            funding potential income tax liabilities incurred by the non-
            Capital Power syndicate members in relation to the transaction.
            The total estimated loan commitment is $19 million, with annual
            payments of principal commencing from the date the commitment is
            called by the non-Capital Power syndicate members through to
            December 2012. At September 30, 2009, the Company has $13 million
            extended under such notes and their carrying amount of $8
            million, after fair value adjustments, is included in other
            assets.

        (g) On June 11, 2009, a Statement of Claim was filed against The City
            of Edmonton, the Mayor and Councilors of The City of Edmonton,
            EPCOR, EPCOR Power L.P.'s General Partner, EPCOR Power L.P. and
            Capital Power (the Co-defendants). The claim alleged, among other
            things, that The City of Edmonton acted beyond its power and
            contrary to the Municipal Government Act (Alberta) and did not
            observe an appropriate public process in connection with the
            initial public offering involving Capital Power. Based on its
            review of the available information, Capital Power believes that
            the claim is without merit and intends to vigorously defend
            itself. On June 26, 2009, Capital Power filed a Statement of
            Defence denying all of the allegations contained in the Statement
            of Claim. On July 3, 2009, the Alberta Court of Queen's Bench
            denied an application for an interim injunction to delay the
            closing of the Capital Power initial public offering and its
            acquisition of EPCOR's power generation business. The court was
            not satisfied that there was any real merit to the application.
            The Co-defendants have now applied to the Alberta Court of
            Queen's Bench for summary dismissal of this action against them.

            On June 30, 2009, an Originating Notice was filed in the Court of
            the Queen's Bench of Alberta, Judicial District of Edmonton, by
            the Alberta Federation of Labour, the Canadian Union of Public
            Employees, Local 30, and the Civic Service Union 52. The Notice
            named The City of Edmonton, EPCOR Utilities Inc. and Capital
            Power Corporation as Respondents and requested that the
            transaction pursuant to which the power generation assets
            previously owned by EPCOR were transferred to Capital Power be
            overturned on the basis that certain purported actions taken by
            The City of Edmonton in connection with the initial public
            offering were allegedly outside the jurisdiction of the
            municipality under the Municipal Government Act. On September 25,
            2009, the Alberta Court of Queen's Bench denied the application.

        (h) The Company and its subsidiaries are subject to various other
            legal claims that arise in the normal course of business.
            Management believes that the aggregate contingent liability of
            the Company arising from these claims is immaterial and therefore
            no provision has been made.

    28. Guarantees:

        The Company has issued letters of credit for $90 million to meet the
        credit requirements of energy market participants, to meet conditions
        of certain service agreements, and to satisfy legislated reclamation
        requirements.

        Prior to the acquisition of subsidiaries and assets from EPCOR
        disclosed in note 3, EPCOR issued parental guarantees on behalf of
        former EPCOR subsidiaries to meet the credit requirements of energy
        market participants, to meet conditions of certain service
        agreements, and to satisfy legislated reclamation requirements. At
        September 30, 2009, EPCOR continues to have outstanding parental
        guarantees on behalf of Capital Power totaling $1,315 million related
        to subsidiaries of Capital Power. In addition to this amount, EPCOR
        also has outstanding parental guarantees which do not have a defined
        limit, but which provide full support on any outstanding positions
        related to power purchase arrangements of Capital Power. The Company
        is working on transferring these parental guarantees over from EPCOR.

    29. Geographic information:

        ---------------------------------------------------------------------
                                     Three months ended September 30, 2009
                                  -------------------------------------------
                                                       Inter-area
                                                           elimi-
                                    Canada        U.S.    nations      Total
        ---------------------------------------------------------------------
        Revenues - external         $  433      $   92     $    -     $  525
        Inter-area revenues              5           1         (6)         -

        ---------------------------------------------------------------------
        Total revenues              $  438      $   93     $   (6)    $  525
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Property, plant and
         equipment                  $2,719      $  480     $    -     $3,199
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Goodwill                    $   95      $   24     $    -     $  119
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Inter-area transactions occur in the normal course of operations and
        are recorded at the exchange amount which is the consideration
        established and agreed to by the parties.

    30. Assets held for sale:

        The Company's interest in the Battle River PSA will be disposed of on
        January 15, 2010. Since the final disposal will occur within one year
        of the balance sheet date, the remaining Battle River PSA assets on
        the consolidated balance sheet have been reclassified from power
        purchase arrangements to assets held for sale.

    31. Subsequent events:

        (a) On October 14, 2009, the Company announced it will be partnering
            with two third parties to develop what will be one of the world's
            largest Carbon Capture and Storage (CCS) projects, Project
            Pioneer (Pioneer). A letter of intent has been signed with the
            Province of Alberta, under which Pioneer will be eligible to
            receive funding from the province's $2 billion CCS fund. The
            Government of Canada is also contributing toward the project
            through its Clean Energy Fund. Pioneer entails the development of
            a CCS facility at the Keephills 3 power plant, currently under
            construction west of Edmonton. Pioneer will be designed to
            capture one million tonnes of greenhouse gas emissions annually.
            The development of Pioneer will not affect the construction
            schedule for Keephills 3, which is expected to enter commercial
            operation in early 2011.

        (b) On October 13, 2009, a subsidiary of the Company, EPLP, announced
            a change in the frequency of its distributions to monthly from
            quarterly. Cash distributions of EPLP for periods commencing
            after September 30, 2009 will be made in respect of each calendar
            month instead of the quarters ending March, June, September and
            December of each year. EPLP also announced the launch of a
            Premium Distribution(TM) and Distribution Reinvestment Plan (the
            "Plan") that provides eligible unitholders with two alternatives
            to receiving the monthly cash distributions, including the option
            to accumulate additional units in EPLP by reinvesting cash
            distributions in additional units issued at a 5% discount to the
            Average Market Price of such units (as defined in the Plan) on
            the applicable distribution payment date. Under the Premium
            Distribution(TM) component of the Plan, eligible unitholders may
            elect to exchange these additional units for a cash payment equal
            to 102% of the regular cash distribution on the applicable
            distribution payment date.

        (c) On October 13, 2009, a subsidiary of the Company entered into a
            bought deal for the issuance of 4,000,000 7.0% Cumulative Rate
            Reset Preferred Shares, Series 2 (the "Series 2 Shares") at a
            price of $25.00 per share, for aggregate gross proceeds of $100
            million (the "Offering"). The Series 2 Shares will pay fixed
            cumulative dividends of $1.75 per share per annum, as and when
            declared, for the initial five-year period ending December 14,
            2014. The dividend rate will reset on December 31, 2014 and every
            five years thereafter at a rate equal to the sum of the then
            five-year Government of Canada bond yield and 4.18%. The Series 2
            Shares are redeemable at $25.00 per share by the Corporation on
            December 31, 2014 and on December 31 every five years thereafter.
            The holders of the Series 2 Shares will have the right to convert
            their shares into Cumulative Floating Rate Preferred Shares,
            Series 3 (the "Series 3 Shares") of the Corporation, subject to
            certain conditions, on December 31, 2014 and on December 31 of
            every fifth year thereafter. The holders of Series 3 Shares will
            be entitled to receive quarterly floating rate cumulative
            dividends, as and when declared by the board of directors of the
            Corporation, at a rate equal to the sum of the then 90-day
            Government of Canada treasury bill rate and 4.18%. The offering
            is expected to close on or about November 2, 2009, subject to
            certain conditions. The net proceeds will be used to repay
            outstanding bank indebtedness.
    

SOURCE Capital Power Corporation

For further information: For further information: Media Relations: Mike Long, (780) 392-5207, mlong@capitalpower.com; Investor Relations: Randy Mah, (780) 392-5305 or (866) 896-4636 (toll-free), investor@capitalpower.com

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Capital Power Corporation

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