Oct. 30, 2009 (Canada NewsWire Group) --
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
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(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
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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
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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
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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
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(unaudited, GWh) Three months ended
Sept 30, June 30,
Electricity generation 2009 2009
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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
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596 541
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Alberta contracted plants 1,638 1,623
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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
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EPCOR Power L.P. plants(2) 1,228 1,030
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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.
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(unaudited) Three months ended
Sept 30, June 30,
Generation plant availability(1) 2009 2009
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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%
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95% 94%
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Alberta contracted plants
Genesee 1 100% 99%
Genesee 2 95% 99%
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97% 99%
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Ontario and British Columbia contracted plants
Kingsbridge 1 and Port Albert 99% 100%
Miller Creek 88% 97%
Brown Lake 97% 97%
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94% 98%
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EPCOR Power L.P. plants(3) 93% 90%
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Average(3) 95% 93%
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(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:
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Payments Due by Period
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(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
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Total $ 289 $ 942 $ 742 $ 396 $3,661 $6,030
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(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:
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(unaudited, $ millions) Sept 30, 2009
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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 -
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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.
