Capital Power reports third quarter results
"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
"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
"We continue to take a leadership role in carbon capture and storage (CCS) technology through our partnership with TransAlta and Alstom
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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
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
About Capital Power
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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
Forward-Looking Statements
--------------------------
This news release contains forward-looking statements, including "forward-looking statements" within the meaning of applicable Canadian and
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
Capital Power was incorporated on
The Company commenced operations in
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
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
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
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
- 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
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
In
Second new turbine at Clover Bar Energy Centre
On
Subsequent Events
EPCOR Power Equity Ltd.
On
Changes to EPCOR Power L.P. distributions
On
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
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
Update on construction projects
As of
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
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
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
Other portfolio facilities
Other portfolio activities include natural gas trading in Alberta and electricity trading in eastern
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
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(unaudited, $ millions, except Three months ended
earnings per share) Sept 30, June 30,
2009 2009(2)
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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
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(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
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(unaudited, $ millions)
Net income for the three months ended June 30, 2009(1) $ 11
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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
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(2)
Lower (higher) non-controlling interests:
- CPLP (4)
- EPCOR Power L.P. 10
- Preferred share dividends paid by subsidiary
company (1)
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Increase in net income 3 3
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Net income for the three months ended September 30, 2009 $ 14
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(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
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(unaudited, $ millions) Three months ended
Sept 30, June 30,
2009 2009
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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) -
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428 500
Unrealized fair value changes in derivative instruments
- CPLP 64 3
- EPCOR Power L.P. 33 34
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97 37
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$ 525 $ 537
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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)
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189 205
Unrealized fair value changes in derivative instruments
- CPLP 16 12
- EPCOR Power L.P. 13 33
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29 45
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$ 218 $ 250
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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) -
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140 131
Unrealized fair value changes in derivative instruments
- CPLP 16 12
- EPCOR Power L.P. 13 33
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29 5
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$ 169 $ 176
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(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.
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Three months ended
Sept 30, June 30,
2009 2009
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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
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Capital Power's Alberta portfolio captured power
price ($/MWh)(1)(3) 53.85 57.60
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(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
Revenues and operating margin from the Alberta commercial plants and portfolio optimization decreased
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
Fuel costs for the EPCOR Power L.P. plants decreased
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
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
The gross margin for changes in the fair value of derivative instruments and natural gas inventory decreased
Consolidated Other Expenses
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(unaudited, $ millions) Three months ended
Sept 30, June 30,
2009 2009
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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
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(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
Net financing
Financing expenses for the third quarter of 2009 were in accordance with expectations. The
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
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Gross margin 218 250
Operations, maintenance, and direct administration 49 74
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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
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Net income 14 11
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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
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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.
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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
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-------------------------------------------------------------------------
-------------------------------------------------------------------------
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.
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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.
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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.
-------------------------------------------------------------------------
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(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
Upon closing of the IPO, CPLP had obligations to pay
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
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(1) Floating interest rates are a function of the prevailing bankers'
acceptance rates
CPLP will be required to make principal repayments of
CPLP's credit facilities include an extendible revolving syndicated bank credit facility (Syndicated Facility) of up to
At
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
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
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
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
-------------------------------------------------------------------------
Payments Due by Period
-------------------------------------------------------------------------
(unaudited, Fourth 2013 and
$ millions) quarter there-
2009 2010 2011 2012 after Total
Acquired PPA
obligations(1) $ 31 $ 90 $ 89 $ 101 $1,249 $1,560
Capital projects(2) 120 290 20 - - 430
Energy purchase and
transportation
contracts(3)(4) 56 113 93 78 269 609
Operating and
maintenance
contracts(5) 7 28 28 28 155 246
Operating leases - 2 1 4 74 81
Forward foreign
exchange contracts
and commodity
contracts-for-
differences 38 69 42 5 3 157
Long-term debt 1 247 376 104 1,051 1,779
Interest on
long-term debt(6) 28 95 84 67 511 785
Asset retirement
obligations(7) 2 8 9 9 349 377
Loan commitments 6 - - - - 6
-------------------------------------------------------------------------
Total $ 289 $ 942 $ 742 $ 396 $3,661 $6,030
-------------------------------------------------------------------------
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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
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
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
At
-------------------------------------------------------------------------
(unaudited, $ millions) Sept 30, 2009
-------------------------------------------------------------------------
Balance sheet
Accounts receivable $ 60
Other assets 7
Property, plant and equipment 9
Accounts payable - accrued interest on debt 12
Long-term debt (including current portion) 876
Share capital -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Outlook
As discussed in the management's discussion and analysis of financial condition and results of operations included in the Prospectus, commencing in 2006, management's strategy has been to sell its Battle River PPA and a portion of its interest in the Sundance PPA and replace this power output with power produced from its own new physical facilities. Interests in the PPAs were sold over the period from 2006 to 2009 with the remaining 15% interest in the Battle River PPA expected to be sold in
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
As discussed under Subsequent Events, the Company's share of the total construction cost of the Keephills 3 facility is expected be approximately
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
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
Further, there can be no assurances that compliance with and/or changes to environmental regulations will not materially adversely impact the Company's business, prospects, financial conditions, operations or cash flow.
The Company's business is a significant emitter of nitrogen oxide (NOx), sulphur dioxide (SO(2)) and mercury and is required to comply with all licenses and permits and existing and emerging federal, provincial and state requirements, including programs to reduce or offset GHG emissions.
EPCOR Power L.P.'s wood waste plants may also be subject to SO(2) and mercury reduction requirements within the next five to seven years. There are a number of uncertainties associated with the estimated cost of compliance with these existing and emerging requirements. Compliance with new regulatory requirements may require EPCOR Power L.P. to incur significant capital expenditures and/or additional operating expenses.
Electricity Price and Volume Risk
The Company's revenues are tied, directly and indirectly, to the market price for electricity in the jurisdictions in which the Company operates. The Company buys and sells some of its electricity in the wholesale markets of Alberta, Ontario, and the U.S. Such transactions are settled at the spot market prices of the respective markets. Market electricity prices are dependent upon a number of factors, including: the projected supply and demand of electricity; the price of raw materials that are used to generate sources of electricity; the cost of complying with applicable regulatory requirements, including environmental; the structure of the particular market; and weather conditions. It is not possible to predict future electricity prices with complete certainty, and electricity price volatility could therefore have a material adverse effect on the Company.
In order to manage its exposure to spot price variability within specified risk limits, the Company enters into purchase and sale arrangements, including contracts-for-differences (CfD) and firm price physical contracts, for varying periods of duration. A contract-for-differences is an arrangement whereby a payment is made by one party to the contract to the other, based on the difference between a reference price and the price of an underlying commodity such as electricity or natural gas. However, due to limited market liquidity and the variance in electricity consumption between peak usage hours and off-peak usage hours, it is not possible to hedge all positions every hour. The Company operates under specific policy limits, such as total exposure and stop-loss limits, and generally trades in electricity to reduce the Company's exposure to changes in electricity prices or to match physical and financial obligations.
When aggregate customer electricity consumption (load shape) changes unexpectedly, the Company is exposed to price risk. Load shape refers to the different pattern of consumption between peak hours and off-peak hours. Consumption is higher during peak hours when people and organizations are most active; conversely, consumption is lower during off-peak hours. The Company purchases blocks of electricity in advance of consumption so as to minimize exposure to extreme price fluctuations, especially during higher priced peak hour periods. In order to do this, the Company relies on historical aggregate consumption data (load shape) provided by load settlement agents and local distribution companies to anticipate what aggregate customer consumption will be during peak hours. When consumption varies from historical consumption patterns and from the volume of electricity purchased for any given peak hour period, the Company is exposed to prevailing market prices because it must either buy the electricity if it is short or sell the electricity if it is long. Such exposures can be exacerbated by other events such as unexpected generation plant outages and unusual weather patterns.
Fuel Cost, Supply and Transportation
The Company requires fuel supplies, such as natural gas, coal, wood waste, waste heat, water and wind, to generate electricity. A disruption in the supply of, or a significant increase in the price of, any fuel supplies required by the Company could have a material adverse impact on the Company's business, financial condition and results of operation. The price of fuel supplies is dependent upon a number of factors, including: the projected supply and demand for such fuel supplies; the quality of the fuel (particularly in regards to wood waste); and the cost of transporting such fuel supplies to the Company's facilities. Changes in any of these factors could increase the Company's cost of generating electricity or decrease the Company's revenues due to production cutbacks, either of which could have a material adverse effect on the Company's business, financial condition and results of operation.
The Company's fuel expense for the Genesee plants is predominantly comprised of coal supply. Coal is supplied under long-term agreements with the Genesee Coal Mine joint venture, of which the Company holds a 50% interest. The price is based on a cost-of-service model with annual updates for inflation, interest rate and capital budget parameters and is therefore not subject to coal market price volatility. To the extent that coal mine operations or equipment suffers significant disruption, existing coal stock-pile inventories representing an approximate 6 months supply would be exhausted prior to, the generation of electricity from the Genesee generation units and the associated revenues being negatively impacted.
The Roxboro and Southport facilities purchase coal and coal-based fuel from local suppliers in the Southeast U.S. The coal and coal-based fuel is transported to the power plants by rail service. Any disruption in rail service due to unforeseen circumstances could impair the operations of these coal-fired power plants if alternative transportation cannot be arranged in a timely manner. Existing coal supply contracts will meet the 2009 requirements and approximately half of the 2010 requirements for Roxboro and Southport. There can be no assurance of if, when or upon what terms, including pricing, the existing supply agreements will be renewed or replaced.
Some of the Company's natural gas-fired plant operations are susceptible to the risks associated with the volatility of natural gas prices beyond any fixed price term. Natural gas purchases for the Naval Station, Naval Training Centre, North Island, Oxnard and Kenilworth power plants are made under variable price structures with fuel cost flow-through provisions that partially mitigate risks relating to natural gas price changes. However, each of these power plants has PPAs extending for terms in excess of existing contractual supply arrangements. The Company is exposed to commodity price risk on its natural gas purchases for EPCOR Power L.P.'s
Wood waste is required to fuel EPCOR Power L.P.'s two Canadian biomass wood waste plants,
EPCOR Power L.P.'s five Ontario plants (namely, Nipigon, Kapuskasing, North Bay, Calstock and
Performance of hydroelectric facilities is dependent upon the availability of water. Variances in water flows, which may be caused by shifts in weather or climate patterns, the timing and rate of melting and other uncontrollable weather-related factors affecting precipitation, could result in volatility of hydroelectric plant revenues. In addition, the hydroelectric facilities are exposed to potential dam failure, which could affect water flows and have a material adverse impact on revenues from the associated plants. There is an increasing level of regulation respecting the use, treatment and discharge of water, and respecting the licensing of water rights, in Alberta. A continued tightening of such regulations could have a material adverse effect on the Company's business, financial condition and results of operation.
The Company's wind power facilities, like those of the Kingsbridge I project, have no fuel costs but are dependent on the availability and constancy of sufficient wind resources to meet generation capacity. Wind resources can vary due to abnormal weather conditions, and decreases in wind speed or duration can negatively impact the performance of the wind turbines and, in turn, could potentially have a material negative impact on related revenues.
Operational Risk
The operation of power plants involves many risks, including: (i) the breakdown or failure of, and the necessity to repair, upgrade or replace, power and steam generation equipment, transmission lines, pipelines or other equipment, structures or processes; (ii) the inability to secure critical or back-up parts for generator equipment on a timely basis; (iii) fire, explosion or other property damage; (iv) an inability to obtain adequate fuel supplies, site control, and operation and maintenance and other site services for at least the term of any PPA; (v) performance of generation equipment below expected levels, including those pertaining to efficiency and availability; (vi) fluctuating costs, including fuel costs; (vii) compliance with all operating permits and licences (including environmental permits and emissions restrictions) under applicable laws and regulations; and (viii) an inability to retain, at all times, adequate skilled personnel, the occurrence of any of which could have a material adverse effect on the Company, including a shut-down of a power plant or reduction in its operating capacity, emissions in excess of permitted levels, or diversion of water levels below levels required by regulation.
The inability of the Company's power plants to generate the expected amount of electricity that will be sold under contract or to the applicable market would have a significant adverse impact on the revenues of the Company. If a power plant delivers less than the required quantities of electricity in a given month, or is available for production less than required under the PPAs in a given month, revenue may be insufficient to cover contractual or financial obligations.
To the extent that plant equipment requires significant capital and other operation and maintenance expenditures to maintain efficiency, requires longer-than-forecast down times for maintenance and repair, experiences outages due to equipment failure or suffers disruptions of power generation for other reasons, the Company's cost of generating electricity will be increased and/or the Company's revenues may be negatively affected. As an adopter of new technology, the Company can be exposed to design flaws or other issues, the impacts of which may not be covered by warranties or insurance. The decision regarding expenditures and maintenance would depend on, among other things, the remaining term of the PPA. The failure of the Company's facilities to operate at required capacity levels may result in the facilities having their contracted capacity reduced and, in certain cases, the Company having to make payments on account of reduced capacity to power purchasers.
Operational risks are partly mitigated by our, and the acquired PPA plant owners' operating and maintenance practices that are intended to minimize the likelihood of prolonged unplanned down time. The terms of the PPAs provide appropriate incentives to owners to keep the plants well maintained and operational as well as force majeure protection for high-impact low probability events including major equipment failures. Maintenance practices are augmented by an inventory of strategic spare parts, which can reduce down time considerably in the event of failure. Finally, the Company has secured appropriate business interruption insurance to reduce the impact of prolonged outages caused by insured events.
In the case of EPCOR Power L.P.'s Ontario plants, a combination of increasing operation and maintenance costs, fuel costs, and decreasing availability of waste heat as a fuel source, may cause EPCOR Power L.P. to restrict their operation to on-peak hours to maximize revenue under their respective PPAs.
In addition, counterparties to PPAs have remedies available to them if the Company fails to operate facilities in accordance with contract requirements, including the recovery of damages and termination of contractual arrangements.
Projects in Construction and Development
The Company participates in the design, construction and operation of new power generation facilities. Development of power generation facilities is subject to substantial risks and can be adversely affected by changes in engineering and design requirements, non-performance or errors by third-party contractors, construction performance falling below expected levels, changes in government policy and regulation, environmental concerns, increases in capital costs, increases in interest rates, competition in the industry and other matters beyond the direct control of the Company. Any one of these factors could cause actual results to vary significantly and the Company may not be able to recover its investment, materially and adversely affecting the Company's financial position, operating results and business.
The Company attempts to mitigate these risks by performing detailed project analysis and due diligence prior to and during construction or acquisition, and by entering into favourable long-term contracts for output and services to be provided where and when available.
Credit Risk
Credit risk is the possible financial loss associated with the potential inability of counterparties to satisfy their contractual obligations to the Company, including payment and performance. In the event of default by a purchasing counterparty, existing PPAs and steam purchase agreements may not be replaceable on similar terms, particularly those agreements that have favourable pricing for the Company relative to their current markets. The Company is also dependant upon counterparties with respect to its cogeneration hosts and suppliers of fuel to its plants. Failure of any such counterparties could impact the operations of some of the Company's plants and could adversely impact the Company's financial results. In the wholesale electricity market, should a counterparty default, the Company may not be able to effectively replace such counterparty in order to manage short or long electricity positions, resulting in reduced revenues or increased power costs. Furthermore, a prolonged deterioration in economic conditions, such as the recent economic recession, could increase the foregoing risks and could have a material adverse affect on the Company.
Financial Liquidity Risk
The Company's future development, enhancement opportunities, acquisition plans or other cash requirements, may require additional financing from time to time. The ability of the Company to arrange such financing in the future will depend in part upon prevailing market conditions as well as the business performance of the Company. Current global financial conditions and recent market events have been characterized by increased volatility and the resulting tightening of the credit and capital markets has reduced the amount of available liquidity and overall economic activity. There can be no assurance that debt or equity financing, the ability to borrow funds or cash generated by operations will be available or sufficient to replace financing as it matures or becomes due, or to meet or satisfy the Company's initiatives, objectives or requirements or, if financing is available to the Company, that it will be on terms acceptable to the Company. See Liquidity and Capital Resources. The inability of the Company to access sufficient amounts of capital on terms acceptable to the Company for its operations could have a material adverse effect on the Company's business, prospects and financial condition.
Supply Risk of Alberta PPAs
The Company holds interests in PPAs in Alberta which entitle the Company to its proportionate interest in the electricity produced from certain generating units up to their committed capacity. In most cases where plant capability falls below committed capacity, the Company is entitled to receive availability payments from the plant owner based on 30-day rolling average power pool prices and target availability. The occurrence of an event which disrupts the ability of the power plants to produce or sell power or thermal energy for an extended period under such PPAs, including events which preclude the subsequent purchasers of the rights and obligations under the acquired PPAs from fulfilling their obligations under such PPAs, could have a material negative impact on the ability of the Company to generate revenue. In such circumstances, the Company may be required to replace the electricity that was not delivered to it at market rates prevailing at that time, although it would be relieved of the obligation to pay the unit capacity fee. Depending on market liquidity, these market prices could be significantly higher than the prices inherent in the PPA, thus increasing the cost of energy purchases to the Company.
PPA Contract Risk
Many of the Company's generation plants operate under PPAs. Such contracts contain performance benchmarks that must be achieved and other obligations that must be complied with by the Company. The Company may incur charges in the event of unplanned outages or variations from the contract performance benchmarks. In addition, there is no assurance that counterparties to PPAs will perform their obligations or make required payments to the Company or EPCOR Power L.P., as applicable.
Electricity sales associated with the Company's Genesee 1 and 2 facilities are governed by the terms of a PPA. These sales are accounted for as long-term fixed margin contracts, which limit the impact of swings in wholesale spot electricity prices, unless plant availability drops significantly below the PPA target availability for an extended period. Most of the Company's other plants, including Brown Lake, Miller Creek, and Kingsbridge I, operate under long-term commercial contracts with counterparties. Electricity sales or steam sales associated with Joffre are subject to market price variability as there are provisions in the NOVA contract that require the facility to run to provide steam to the host facility, irrespective of market prices.
In order to stabilize future cash flows, EPCOR Power L.P. seeks to re-contract existing generation plants under new or extended contracts and acquire new plants that meet its investment criteria. However, there is no guarantee that existing PPAs will be extended or renewed on more favourable terms. Electricity prices under the PPAs for the Naval Facilities and Oxnard are based on the purchasing utilities' SRAC. The SRAC formula is determined by the California Public Utility Commission and is subject to adjustment. In the future, the California Public Utility Commission may make adjustments to the SRAC formula to change the basis on which future electricity prices will be determined for these facilities. Such adjustments may adversely affect the value of the affected PPAs to the Company.
Reliance on Transmission Systems
The Company depends on transmission facilities owned and operated by third parties to deliver the wholesale power it sells from its power generation plants to its customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, the Company's ability to sell and deliver wholesale power may be adversely impacted. If a region's power transmission infrastructure is inadequate, the Company's recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.
The Company also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. The Company's ability to develop new projects is also impacted by the availability of various transmission and distribution systems.
Foreign Exchange Risk
Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar affect the Company's capital and operating costs, revenues and cash flows and could have an adverse impact on the Company's financial performance and condition. The U.S. plant operations of EPCOR Power L.P. and the foreign-sourced equipment required for capital projects such as Keephills 3 and Clover Bar are transacted in U.S. dollars. In addition, certain of EPCOR Power L.P.'s indebtedness is denominated in U.S. dollars.
The foreign exchange risk of anticipated U.S. dollar denominated cash flows, net of debt service obligations, is managed through the use of forward foreign exchange contracts for periods of up to seven years. In addition, large value equipment purchase prices are generally fixed in Canadian dollars by contracting in Canadian dollars or using forward foreign exchange contracts.
PPA Contract Expiration Risks
Power generated from the Company's facilities is, in many cases, sold under PPAs that expire at various times. When a PPA expires, there can be no assurance that a subsequent PPA will be available or, if available, that any such subsequent PPA will be on terms, or at prices, acceptable to the Company. Failure by the Company to enter into a subsequent PPA on terms and at prices that permit the operation of a facility on a profitable basis could have a material adverse effect on the Company's operations and financial condition, and may even require the Company to temporarily or permanently cease operations at the affected facility.
Derivatives Risk
The Company uses derivative instruments, including futures, forwards, options and swaps, to manage its commodity and financial market risks inherent in its electricity generation operations. These activities, although intended to mitigate price volatility, expose the Company to other risks. When the Company sells power forward, it gives up the opportunity to sell power at higher prices in the future, which not only may result in lost opportunity costs but also may require the Company to post significant amounts of cash collateral or other credit support to its counterparties. In addition, the Company purchases and sells commodity-based contracts in the natural gas and electricity markets for trading purposes. In the future, the Company could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. See Financial Instrurments - Risk Management and Hedge Accounting for more information about the Company's use of derivative instruments.
Weather Risks
Weather can have a significant impact on the Company's operations. Temperature levels, seasonality and precipitation, both within the Company's markets and adjacent geographies, can affect the level of demand for electricity and natural gas, thus resulting in electricity and natural gas price volatility. In addition, the performance of the hydroelectric facilities is partly dependent upon the availability of water and variances in water flows are caused by non-controllable weather-related factors affecting precipitation and could result in volatility of hydroelectric plant revenues. Although the Company's wind power facilities have no fuel costs, they rely on the availability and constancy of wind resources, which could vary due to abnormal weather conditions.
Financial exposures associated with extreme weather are partially mitigated through our insurance programs.
Litigation Update
On
On
Future Accounting Changes
International Financial Reporting Standards
In
In
The diagnostic phase of the project was completed in
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International Financial Reporting Standard
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IFRS 7, IAS 32, IAS 39 Financial Instruments
IAS 23 Borrowing Costs
IAS 18 Revenue
IAS 16 Property, Plant and Equipment
IAS 31 Interests in Joint Ventures
IAS 21 The Effects of Changes in Foreign Exchange Rates
IFRS 3 Business Combinations
IAS 12 Income Taxes
IAS 17 Leases
IAS 37 Provisions, Contingent Liabilities and Contingent Assets
IAS 36 Impairment of Assets
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The information obtained from the diagnostic phase was used to develop a detailed plan for convergence and implementation. The convergence and implementation work has the following five key sections.
Financial Statement Adjustments
For each international standard, the Company will determine the quantitative impacts to the financial statements, system requirements, accounting policy decisions, and changes to internal controls and business policies. The initial accounting policy decisions will be brought forward to the Audit Committee for their information as each standard is addressed. However, final accounting policy decisions for all standards in effect at the end of 2009 will be made in the fourth quarter of 2009 and brought forward to the Audit Committee in the first quarter of 2010, as they should not be determined in isolation of other policy decisions. Policy decisions for any new standards or standards that are amended in 2010 will be made in conjunction with our analysis of those standards in 2010.
As the project progresses, the timing of completion of certain items may change as changes to standards and other external factors such as discussions with certain stakeholders may result in a change in priorities. However, the Company believes the project has sufficient resources to meet the overall project timeline.
Financial Statements
There are also a number of international standards which relate to financial statement presentation. Draft financial statements highlighting the disclosure and presentation requirements were prepared for EPCOR before the Reorganization and will be used as a foundation for preparing draft financial statements in accordance with IFRS for Capital Power. Draft financial statements will be brought forward to the Audit Committee by then end of the first quarter of 2010. The development of the financial statement presentation will evolve throughout the project as impacts of implementing the various standards are quantified.
Systems Updates
The diagnostic phase of the project identified two key accounting system requirements. The system must be able to capture 2010 financial information under both the prevailing Canadian GAAP and IFRS to allow comparative reporting in 2011, the first year of reporting under IFRS. It must also be able to accommodate possible changes to foreign currency translation methods, depending on how certain foreign entities are classified under IFRS. EPCOR developed a systems strategy in 2008 and implementation of a parallel fixed asset subledger and general ledger was completed in the third quarter of 2009.
Policies and Internal Controls
In the determination of the financial statement adjustments, requirements for changes to Company policies and internal controls will be identified and documented. As there may be factors other than IFRS impacting policies and internal controls, the formal documentation and approval of revised policies and internal controls will not occur until the third quarter of 2010.
The impact of IFRS on certain agreements, such as debt, shareholder and compensation agreements, has also been included in the plan. Assessments of these agreements will be performed in the fourth quarter of 2009 and the first quarter of 2010 as most of these agreements were revised as a result of the Reorganization.
Training
The Company recognizes that training at all levels is essential to a successful conversion and integration. Accounting staff have attended two training sessions with more planned to occur throughout the conversion process. The Audit Committee will receive regular updates on the conversion project and training for the Board of Directors and Audit Committee will occur throughout the project.
Disclosures about financial instruments
In
Consolidated financial statements and non-controlling interests
In
Sections 1601 and 1602 will apply to Capital Power's interim and annual consolidated financial statements relating to periods commencing on or after
Business combinations
In
Significant Accounting Policies
Revenue recognition under PPAs
The Company's Genesee power generation units 1 and 2 operate under a PPA. Under the terms of the PPA, the target levels of generation availability set out in the PPA recognize that the generation units will experience planned and forced outages over the terms of the PPA. The Company records the electricity revenue from the generation units under PPAs at the price embedded in the PPAs, including expected incentives and penalties for operating above or below specified availability targets set out in the PPA. Under this approach, incentives for the period may be deferred and included in non-current liabilities on the balance sheet if they are not expected to be sustained over the full term of the PPA. As penalties are incurred, any balance of deferred incentive is drawn down. If cumulative penalties exceed cumulative incentives, the excess is charged to income and no deferred charge is created.
The degree to which incentives are recognized or deferred changes from period to period due to revisions to the long-term outlook of plant performance, which is based on historical performance, planned maintenance, reliability and generation availability, and due to revisions in the estimated long-term price embedded in the PPA.
Revenues from the Company's power generation plants located outside of Alberta are recognized upon delivery of output or upon availability for delivery as prescribed by contractual arrangements. These contractual arrangements are also commonly referred to as PPAs. Revenues under the
Leases or arrangements containing a lease
Leases or other arrangements entered into for use of property, plant and equipment are classified as either capital or operating leases. Leases or other arrangements that transfer substantially all of the benefits and risks of ownership of property to the Company are classified as capital leases. Equipment acquired under capital leases is depreciated over the term of the lease. Rental payments under operating leases are expensed as incurred.
Certain power generation plants operate under PPAs that convey the rights to use the related property, plant and equipment to the holder of the agreements. Consequently, these power generation plants are accounted for as assets under operating leases.
Foreign currency translation
EPCOR Power L.P. has operations in the U.S. with a functional currency of U.S. dollars. Accordingly, these operations are translated using the current rate method whereby assets and liabilities are translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Revenues and expenses are translated at rates in effect at the time of the transactions. The resulting foreign exchange gains and losses are accumulated as a component of accumulated other comprehensive income.
Consolidation of EPCOR Power L.P. and CPLP
While the Company owns only 30.6% of the outstanding units of EPCOR Power L.P. and an approximate 27.8% interest in CPLP, it controls both partnerships under GAAP. Accordingly, EPCOR Power L.P. and CPLP are consolidated in the financial statements of the Company.
Critical accounting estimates
In preparing the consolidated financial statements, management necessarily made estimates in determining transaction amounts and financial statement balances. The following are the items for which significant estimates were made in the financial statements.
Fair values
The Company is required to estimate the fair value of certain assets and obligations for determining the valuation of certain financial instruments, asset impairments, asset retirement obligations and purchase price allocations for business combinations, and for determining certain disclosures.
Fair values of financial instruments are based on quoted market prices when these instruments are traded in active markets. In illiquid or inactive markets, the Company uses appropriate price modeling to estimate fair value. For determining purchase price allocations for business combinations, the Company is required to estimate the fair value of acquired assets and obligations. Goodwill arising on business combinations is tested for impairment annually or more frequently if events and circumstances indicate that a possible impairment may exist. To test for impairment, the fair value of the reporting unit to which the goodwill relates is compared with the carrying value, including goodwill, of the reporting unit. If the carrying value of the reporting unit exceeds its fair value, the fair value of the reporting unit's goodwill is compared with its carrying amount to measure the impairment loss, if any.
The Company reviews the valuation of long-lived assets subject to amortization when events or changes in circumstances may indicate or cause a long-lived asset's carrying amount to exceed the total undiscounted future cash flows expected from the asset's use and eventual disposition. An impairment loss, if any, would be recorded as the excess of the carrying amount of the asset over its fair value, measured by either market value, if available, or estimated by calculating the present value of expected future cash flows related to the asset. Fair values and useful lives are used in determining potential impairments for each long-lived asset, which will vary with each asset and market conditions at the particular time.
Estimates of fair value for purchase price allocations, and goodwill and other asset impairments as described above, are primarily based on depreciable replacement cost or discounted cash flow techniques employing estimated future cash flows based on a number of assumptions and using an appropriate discount rate. The cash flow estimates will vary with the circumstances of the particular assets or reporting unit and will be based on, among other things, the lives of the assets, contract prices, estimated future prices, revenues and expenses, including inflation, and required capital expenditures.
The fair values of asset retirement obligations are estimated using the total undiscounted amount of the estimated future cash flows required to settle the obligations and applying the appropriate credit-adjusted risk-free discount rate. In this process assumptions are made regarding the useful lives of the assets and the legal restoration obligations. The range for the estimates of fair value for the purposes of determining an asset retirement obligation varies by asset.
Useful lives of assets
Depreciation and amortization allocate the cost of assets over their estimated useful lives on a systematic and rational basis. Depreciation and amortization also include amounts for future decommissioning costs and asset retirement obligation accretion expenses. Estimating the appropriate useful lives of assets requires significant judgement and is generally based on estimates of the life characteristics of common assets.
Income taxes
The Company follows the asset and liability method of accounting for income taxes. Current income taxes are recognized for the estimated income taxes payable or recoverable for the period. Estimates of future income taxes resulting from temporary differences between the carrying values of assets and liabilities in the financial statements and their tax values are recognized as future income tax assets and liabilities. Future income tax assets are assessed to determine the likelihood that they will be recovered from future taxable income. To the extent recovery is not considered likely, a valuation allowance is recorded and charged against income in the period that the allowance is created or revised. Estimates of the provision for current income taxes, future income tax assets and liabilities and any related valuation allowance might vary from actual amounts incurred. Income taxes will vary with taxable income and, under certain conditions, with fair values of assets and liabilities.
PPA availability incentives
Electricity revenue from the Genesee 1 and 2 units includes an estimate of availability incentives as described above under Significant Accounting Policies. Availability incentive payments received are deferred in non-current liabilities and recognized in energy sales when they are expected to be sustained over the full term of the PPA. Accordingly the amount deferred can vary from no amount to the full amount of availability incentive payments received.
Financial Instruments
The Company has various financial instruments that are classified for financial reporting purposes as "available for sale", "held for trading", "held to maturity", or "loans and receivables". Financial liabilities are classified as either "held for trading" or "other liabilities". Initially, all financial assets and financial liabilities are recorded on the balance sheet at fair value with subsequent measurement determined by the classification of each financial asset and liability.
The Company classifies its cash, cash equivalents and current and non-current derivative instruments assets and liabilities as held for trading, and measures them at fair value. Accounts receivable and long-term loans are classified as loans and receivables and accounts payable and accrued liabilities are classified as other liabilities. Accounts receivable and accounts payable and accrued liabilities are measured at amortized cost and their fair values are not materially different from their carrying values due to their short-term nature.
The classification, carrying amounts and fair values of other financial instruments held at
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Fair
Carrying amount value
--------------------------------
Other
Loans and financial
(unaudited, $ millions) receivables liabilities
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Other assets $ 77 $ - $ 72
Long-term debt (including current
portion) $ - $1,771 $1,745
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Risk management and hedging activities
The Company is exposed to changes in energy commodity prices, foreign currency exchange rates and interest rates. The Company uses various risk management techniques, including derivative instruments such as forward contracts, fixed-for-floating swaps, and option contracts, to reduce this exposure. These derivative instruments are recorded at fair value on the balance sheet unless the Company elects the fair value exemption for non-financial derivatives that are entered into and continue to be held for the purpose of receipt or delivery of a non-financial item in accordance with the Company's expected purchase, sale or usage requirements. The derivative instruments assets and liabilities used for risk management purposes are measured at fair value and consist of the following:
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Energy Foreign
Energy cash non- exchange
(unaudited, $ millions) flow hedges hedges non-hedges Total
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Total derivative instruments
net assets (liabilities) as
at September 30, 2009 $ (19) $ 69 $ 17 $ 67
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Energy derivatives designated as accounting hedges
At
On
Energy derivatives not designated as accounting hedges
At
At
All non-financial derivative instruments are measured at fair value unless they are designated as contracts used for the purpose of receipt or delivery of a non-financial item in accordance with the Company's expected purchase, sale or usage requirements as defined by accounting standards, or are designated and qualify for hedge accounting. Some of the Company's physical power and natural gas purchase and sales contracts that are used to meet power generation and retail customer requirements were not designated as contracts used in accordance with the Company's expected purchase requirements and therefore are recorded at fair value in the balance sheet.
Risk management and hedge accounting
The Company uses various financial and non-financial derivatives primarily for risk management purposes. Unrealized changes in the fair value of financial and non-financial derivatives that either do not qualify for hedge accounting or the Company elects not to apply hedge accounting, and non-financial derivatives that do not qualify for the expected purchase, sale or usage requirements of the contract, are recorded in energy revenues, energy purchases or cost of fuel, as appropriate. The corresponding unrealized changes in the fair value of the associated economically hedged exposures are not recognized in income. Accordingly, derivative instruments that are recorded at fair value can produce volatility in net income as a result of fluctuating forward commodity prices, exchange rates and interest rates which are not offset by the unrealized fair value changes of the exposure being hedged on an economic basis. As a result, accounting gains or losses relating to changes in fair values of derivative instruments do not necessarily represent the underlying economics of the hedging transaction.
For example, the Company has more physical supply of power in Alberta from its generating stations and power purchased under PPAs than the Company has contracted to physically sell. The Company utilizes financial sales contracts to reduce its exposure to changes in the price of power in Alberta. Economically, the Company benefits from higher Alberta power prices due to the net long position held since the Company's expected physical supply is in excess of the Company's physical and financial sales contracts. However, financial sales contracts that are not hedged for accounting purposes are recorded at fair value at each balance sheet date and the offsetting anticipated future physical supply or economically hedged item is not. Accordingly, an increase in forward Alberta power prices can result in fair value losses for accounting purposes whereas on an economic basis, these losses are offset by unrecognized gains on the physical supply. The economic gains will be recognized in later periods when the power is produced and sold. The opposite is true for forward price decreases in Alberta power.
Other comprehensive income
Changes in the fair value of the effective hedge portion of the financial derivative contracts used to manage the energy portfolio and designated as accounting hedges, are recorded in other comprehensive income. The ineffective portion of the contracts is recorded in net income.
For the period ended
Internal Control Over Financial Reporting
As part of the Reorganization and acquisition of the power generation assets and operations from EPCOR in
Forward-looking Information
Certain information in this MD&A is forward-looking within the meaning of Canadian securities laws as it relates to anticipated financial performance, events or strategies. When used in this context, words such as will, anticipate, believe, plan, intend, target, and expect or similar words suggest future outcomes.
Forward-looking information in this MD&A includes, among other things, information relating to: (i) expected timing of commercial operation and project cost of Keephills 3 and Clover Bar Energy Centre Unit 3; (ii) future financings by EPCOR Power Equity Ltd; (iii) expectations for the use of the Company's committed bank credit facilities; (iv) Capital Power's and EPCOR Power L.P.'s cash requirements for the fourth quarter of 2009 and related financing; (v) expectations regarding future financial strength and access to and terms of future financings; (vi) the expected impact of the further reduction in the Company's interest in the Battle River PPA and of Keephills 3 coming on line, on cash flow from operations and operating margin; (vii) expectations for Alberta spot power prices in the fourth quarter of 2009 and their impact on operating margin and cash flow from operations; (viii) expectation that the Alberta commercial portfolio position in 2010 will reduce the exposure to changes in power prices; (ix) expectation that the Alberta commercial portfolio's open position will increase to approximately 60% of the total portfolio in 2011; ( x) the Company's estimated sensitivity to Alberta power prices; (xi) the expected annual spending for maintenance capital and other capital for the Company excluding EPCOR Power L.P.; (xii) expectation that the two maintenance outages scheduled in 2010 at the Genesee site will reduce operating margin (excluding unrealized fair value adjustments) and cash flow from operations, and the expected amount of operating expense for the two outages; and (xiii) expectation that the operating margin in 2010 will benefit from a full year of operation of the second unit of Clover Bar Energy Centre and from Unit 3 after its commissioning.
These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments and other factors it believes are appropriate. The material factors and assumptions used to develop these forward-looking statements include, but are not limited to: (i) the operation of the Company's facilities; (ii) power plant availability, including those subject to acquired PPAs (iii) the Company's financial position and credit facilities (iv) the Company's assessment of commodity and power markets; (v) the Company's assessment of the markets and regulatory environments in which it operates; (vi) weather; (vii) availability and cost of labour and management resources; (viii) performance of contractors and suppliers; (ix) availability and cost of financing; ( x) foreign exchange rates; (xi) management's analysis of applicable tax legislation; (xii) the currently applicable and proposed tax laws will not change and will be implemented; (xiii) currently applicable and proposed environmental regulations will be implemented; (xiv) counterparties will perform their obligations; (xv) renewal and terms of PPAs; (xvi) ability to successfully integrate and realize benefits of its acquisitions; (xvii) ability to implement strategic initiatives which will yield the expected benefits; and (xviii) the Company's assessment of capital markets and ability to complete future share offerings.
Whether actual results, performance or achievements will conform to the Company's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results and experience to differ materially from the Company's expectations. Such risks and uncertainties include, but are not limited to risks relating to: (i) operation of the Company's facilities; (ii) power plant availability and performance; (iii) unanticipated maintenance and other expenditures; (iv) availability and price of energy commodities; (v) electricity load settlement; (vi) regulatory and government decisions including changes to environmental, financial reporting and tax legislation; (vii) weather and economic conditions; (viii) competitive pressures; (ix) construction; ( x) availability and cost of financing; (xi) foreign exchange; (xii) availability and cost of labour, equipment and management resources; (xiii) performance of counterparties, partners, contractors and suppliers in fulfilling their obligations to the Company; (xiv) developments in the North American capital markets; (xv) compliance with financial covenants; (xvi) ability to successfully realize the benefits of acquisitions and investments; (xvii) the tax attributes of and implications of any acquisitions; and (xviii) other factors and assumptions discussed in the section entitled Risk Factors in the Prospectus and in other documents filed with provincial securities commissions in
This MD&A includes the following updates to previously disclosed forward-looking statements: (i) the estimated date for Clover Bar Energy Centre Unit 3 to enter commercial operation was revised from the third quarter of 2010 to the first quarter of 2010; (ii) the estimated total cost for all three units at Clover Bar Energy Centre was revised from
Readers are cautioned not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Forward-looking statements are provided for the purpose of providing information about management's current expectations, and plans relating to the future. Readers are cautioned that such information may not be appropriate for other purposes. The Company does not undertake or accept any obligation or undertaking to release publicly any updates or revisions to any forward-looking statements to reflect any change in the Company's expectations or any change in events, conditions or circumstances on which any such statement is based, except as required by law.
Quarterly Common Share Trading Information
The Company's common shares trade on the
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Three months ended Sept 30, June 30,
(unaudited) 2009 2009
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Share price
High $22.39 $23.00
Low $19.50 $22.00
Close $19.75 $22.35
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Volume traded (millions) 12.1 5.8
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On
Additional Information
Additional information relating to Capital Power Corporation, including continuous disclosure documents, is available on SEDAR at www.sedar.com.
CAPITAL POWER CORPORATION
Consolidated Statement of Income
(Unaudited, in millions of dollars)
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Three months ended
September 30,
2009
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Revenues $ 525
Energy purchases and fuel 307
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218
Operations, maintenance and direct administration 49
Indirect administration 27
Depreciation, amortization and asset retirement accretion
(note 5) 44
Foreign exchange losses 3
Net financing expenses (note 17) 17
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140
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Income before income tax reductions and non-controlling
interests 78
Income tax reductions (note 18) (2)
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Income before non-controlling interests 80
Non-controlling interests (note 13) 66
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Net income $ 14
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Earnings per share (note 14)
Basic $ 0.64
Diluted 0.59
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Weighted average number of common shares outstanding
Basic 21,750,000
Diluted 78,375,000
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See accompanying notes to consolidated financial statements.
CAPITAL POWER CORPORATION
Consolidated Balance Sheet
(Unaudited, in millions of dollars)
September 30, 2009
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2009
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Assets
Current assets:
Cash and cash equivalents (note 24) $ 64
Accounts receivable 248
Income taxes recoverable 20
Inventories (note 4) 57
Prepaid expenses 13
Derivative instruments assets (note 20) 148
Future income tax assets (note 18) 2
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552
Property, plant and equipment (note 5) 3,199
Power purchase arrangements (note 6) 536
Contract and customer rights and other intangible assets
(note 7) 181
Derivative instruments assets (note 20) 138
Future income tax assets (note 18) 40
Goodwill (note 8) 119
Other assets (note 9) 117
Assets held for sale (note 30) 36
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$4,918
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Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accrued liabilities $ 275
Derivative instruments liabilities (note 20) 124
Other current liabilities 9
Future income tax liabilities (note 18) 17
Current portion of long-term debt (note 10) 247
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672
Long-term debt (note 10) 1,524
Derivative instruments liabilities (note 20) 95
Other non-current liabilities (note 11) 99
Future income tax liabilities (note 18) 59
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2,449
Non-controlling interests (note 13) 1,975
Shareholders' equity:
Share capital (note 14) 477
Retained earnings 14
Accumulated other comprehensive income (note 15) 3
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494
Contingencies and commitments (note 27)
Subsequent events (note 31)
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$4,918
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See accompanying notes to consolidated financial statements.
CAPITAL POWER CORPORATION
Consolidated Statement of Changes in Shareholders' Equity
(Unaudited, in millions of dollars)
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Three months ended
September 30,
2009
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Share capital:
Common shares issued (notes 3 and 14) $ 477
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Balance, end of period (note 14) 477
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Retained earnings:
Net income 14
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Balance, end of period 14
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Accumulated other comprehensive income:
Other comprehensive income 3
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Balance, end of period (note 15) 3
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Total shareholders' equity, end of period $ 494
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See accompanying notes to consolidated financial statements.
CAPITAL POWER CORPORATION
Consolidated Statement of Comprehensive Income
(Unaudited, in millions of dollars)
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Three months ended
September 30,
2009
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Net income $ 14
Other comprehensive income (loss), net of income taxes:
Unrealized gains on derivative instruments designated
as cash flow hedges(1) 8
Reclassification of losses on derivative instruments
designated as cash flow hedges to net income(2) 21
Unrealized loss in self-sustaining foreign operations(3) (33)
Non-controlling interests(3) (note 13) 7
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3
-------------------------------------------------------------------------
Comprehensive income $ 17
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) For the three months ended September 30, 2009, net of income tax
expense of $1.
(2) For the three months ended September 30, 2009, net of
re-classification of income tax recovery of $2.
(3) For the three months ended September 30, 2009, net of income tax
expense of nil.
See accompanying notes to consolidated financial statements.
CAPITAL POWER CORPORATION
Consolidated Statement of Cash Flows
(Unaudited, in millions of dollars)
-------------------------------------------------------------------------
Three months ended
September 30,
2009
-------------------------------------------------------------------------
Operating activities:
Net income $ 14
Adjustments to reconcile net income to cash flows
from operating activities:
Depreciation, amortization and asset retirement
accretion (note 5) 44
Non-controlling interests in EPLP and CPLP (note 13) 64
Fair value changes on derivative instruments (28)
Unrealized foreign exchange losses 3
Future income taxes (3)
Other (1)
-------------------------------------------------------------------------
93
Change in non-cash operating working capital (note 16) (40)
-------------------------------------------------------------------------
53
Investing activities:
Property, plant and equipment and other assets (108)
Business acquisition, net of acquired cash (note 3) (1,293)
-------------------------------------------------------------------------
(1,401)
Financing activities:
Proceeds from issue of long-term debt 1,001
Repayment of long-term debt (41)
Issue of common shares (notes 3 and 14) 500
Share issue costs (notes 3 and 14) (32)
Debt issue costs (13)
-------------------------------------------------------------------------
1,415
-------------------------------------------------------------------------
Foreign exchange losses on cash held in a foreign currency (3)
-------------------------------------------------------------------------
Increase in cash and cash equivalents 64
Cash and cash equivalents, beginning of period -
-------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 64
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary cash flow information:
Interest paid net of interest received $ 18
Income taxes recovered net of income taxes paid (1)
See accompanying notes to consolidated financial statements.
CAPITAL POWER CORPORATION
Notes to Interim Consolidated Financial Statements
September 30, 2009
(Unaudited, tabular amounts in millions of dollars)
1. Description of business:
Capital Power Corporation (the Company or Capital Power) builds, owns
and operates power plants and manages its related electricity and
natural gas portfolios by undertaking trading and marketing
activities. The Company operates in one reportable business segment
within the geographic areas of Canada and the United States (U.S.),
with its head office located in Edmonton, Alberta.
The common shares of the Company are traded on the Toronto Stock
Exchange under the symbol "CPX".
2. Summary of significant accounting policies:
(a) Basis of presentation:
These unaudited interim consolidated financial statements have
been prepared by management in accordance with Canadian generally
accepted accounting principles (GAAP). In the opinion of
management, these consolidated financial statements have been
properly prepared within reasonable limits of materiality and
within the framework of the significant accounting policies
summarized below.
These unaudited interim consolidated financial statements include
the accounts of Capital Power, its subsidiaries, and its
proportionate share of assets, liabilities, revenues and expenses
of joint ventures. They also include the accounts of the
Company's approximate 30.6% interest in EPCOR Power L.P. (EPLP)
and the Company's approximate 27.8% interest in Capital Power LP
(CPLP). Under GAAP, Capital Power controls EPLP and CPLP which
therefore are subsidiaries of Capital Power.
All significant intercompany balances and transactions have been
eliminated on consolidation.
The Company has determined that December 31 will be its fiscal
year-end. As the Company was incorporated on May 1, 2009, there
is no comparative balance sheet as at December 31, 2008 or
comparative statement of income, statement of changes in
shareholders' equity, statement of comprehensive income and
statement of cash flows for the period ended September 30, 2008.
Although the Company was incorporated on May 1, 2009 the Company
did not have any results from operations or significant cash
flows in the period from May 1 to June 30, 2009. Accordingly, the
company's statements of income, comprehensive income and cash
flows reflect only information for the three months ended
September 30, 2009.
(b) Changes in significant accounting policies:
Future accounting changes
The CICA has announced that Canadian reporting issuers will need
to begin reporting under International Financial Reporting
Standards (IFRS), including comparative figures, by the first
quarter of 2011. The Company is currently working on its IFRS
conversion project which includes assessing the impact of the
differences in accounting standards on the Company's future
financial reporting requirements.
In June 2009, the CICA amended Handbook Section 3862 Financial
Instruments - Disclosures, to adopt the amendments recently made
by the International Accounting Standards Board to IFRS 7
Financial Instruments: Disclosures. The amendments require
enhanced disclosures about fair value measurements, including the
relative reliability of the inputs used in those measurements,
and about the liquidity risk of financial instruments. Although
the amendments apply to financial statements relating to fiscal
years ending after September 30, 2009, comparative information is
not required in the first year of application. We are assessing
the impacts of these amendments on our financial statements and
will implement the necessary additional disclosures commencing
with the annual financial statements for 2009.
In January 2009, the CICA issued Handbook Section 1601 -
Consolidated Financial Statements and Section 1602 - Non-
controlling Interests, which replace Section 1600 - Consolidated
Financial Statements. Section 1601 establishes the standards for
the preparation of consolidated financial statements while
Section 1602 establishes the standards for accounting for a non-
controlling interest in a subsidiary in consolidated financial
statements subsequent to a business combination. Section 1602 is
equivalent to the corresponding provisions of IFRS IAS 27 -
Consolidated and Separate Financial Statements.
Sections 1601 and 1602 will apply to interim and annual
consolidated financial statements relating to periods commencing
on or after January 1, 2011. Earlier adoption is permitted as of
the beginning of a fiscal year, provided Section 1582 - Business
Combinations is also adopted at the same time. The impact of the
new standards and the option to adopt them early is being
assessed as part of the Company's IFRS conversion project.
In January 2009, the CICA issued Handbook Section 1582 - Business
Combinations, which replaces Section 1581 - Business Combinations
and provides the Canadian equivalent to IFRS 3 - Business
Combinations. The section will apply, on a prospective basis, to
future business combinations for which the acquisition date is on
or after January 1, 2011. Earlier adoption is permitted as of the
beginning of a fiscal year provided Sections 1601 - Consolidated
Financial Statements and 1602 - Non-controlling Interests are
also adopted at the same time. The impact of the new standard and
the option to adopt it early is being assessed as part of the
Company's IFRS conversion project.
(c) Measurement uncertainty:
The preparation of the Company's unaudited interim financial
statements, in accordance with Canadian GAAP, requires management
to make estimates that affect the reported amounts of revenues,
expenses, assets and liabilities as well as the disclosure of
contingent assets and liabilities at the financial statement
date. The Company uses the most current information available and
exercises careful judgment in making these estimates and
assumptions.
The degree to which revenues are recognized or deferred under the
Power Purchase Arrangements (PPAs) described in note 2(k) depends
upon long-term outlooks of generation unit performance. Such
outlooks of performance are estimated based on the generation
units' historical performance, planned maintenance, reliability
and generation availability, and revisions in the estimated long-
term price embedded in the PPA.
For certain accounting measures such as determining asset
impairments, purchase price allocations for business
combinations, recording financial assets and liabilities,
recording certain non-financial derivatives and for certain
disclosures, the Company is required to estimate the fair value
of certain assets or obligations. Estimates of fair value may be
based on readily determinable market values or on depreciable
replacement cost or discounted cash flow techniques employing
estimated future cash flows based on a number of assumptions and
using an appropriate discount rate.
Measurement of the Company's asset retirement obligations and the
related accretion expense requires the use of estimates with
respect to the amount and timing of asset retirements, the extent
of site remediation required and related future cash flows.
Measurement of certain of the Company's pension costs and plan
assets and obligations requires the use of estimates with respect
to expected plan investment performance, salary escalation,
retirement ages of employees, timing of related future cash flows
and appropriate discount rates for use in discounted cash flow
and actuarial techniques.
Depreciation and amortization is an estimate to allocate the cost
of an asset over its estimated useful life on a systematic and
rational basis. Estimating the appropriate useful lives of assets
requires significant judgment and is generally based on estimates
of common life characteristics of common assets.
Income taxes are determined based on estimates of the Company's
current income taxes and estimates of future income taxes
resulting from temporary tax differences. Future income tax
assets are assessed to determine the likelihood that they will be
realized from future taxable income. To the extent that
realization is not considered likely, a valuation allowance is
recorded and charged against income in the period that the
allowance is created or revised.
Estimates of the value of electricity and natural gas consumed by
customers but not billed until subsequent to year-end are based
on volume data provided by the parties responsible for delivering
the commodity and contracted prices.
Adjustments to previous estimates, which may be material, will be
recorded in the period they become known.
(d) Revenue recognition:
Revenues from the sales of electricity and natural gas are
recognized on delivery or availability for delivery under take-
or-pay contracts. These revenues include an estimate of the value
of electricity and natural gas consumed by customers, but billed
subsequent to period-end.
The Company recognizes revenue from its Alberta generation units
operating under PPAs as described in note 2(k). PPAs are a form
of long-term sales arrangements between the owner of a generation
unit and the buyer of the PPA.
Revenues from the Company's power generation plants located
outside of Alberta are recognized on delivery of output or on
availability for delivery as prescribed by contractual
arrangements. These contractual arrangements are also commonly
referred to as PPAs. Revenue from certain long-term contracts
with fixed payments is recognized at the lower of (1) the
megawatt hours (MWhs) made available during the period multiplied
by the billable contract price per MWh and (2) an amount
determined by the MWhs made available during the period,
multiplied by the average price per MWh over the term of the
contract from the date of acquisition. Any excess of the contract
price over the average price is recorded as deferred revenue.
(e) Financial instruments:
Financial assets are identified and classified as either
available for sale, held for trading, held to maturity, or loans
and receivables. Financial liabilities are classified as either
held for trading or other liabilities. Initially, all financial
assets and financial liabilities are recorded on the balance
sheet at fair value with subsequent measurement determined by the
classification of each financial asset and liability.
Financial assets and financial liabilities held for trading are
measured at fair value with the changes in fair value reported in
net income. Financial assets held to maturity, loans and
receivables and financial liabilities other than those held for
trading are measured at amortized cost. Available-for-sale
financial assets are measured at fair value with changes in fair
value reported in other comprehensive income until the financial
asset is disposed of, or becomes impaired. Investments in equity
instruments classified as available for sale that do not have
quoted market prices in an active market are measured at cost.
Upon initial recognition, the Company may designate financial
instruments as held for trading when such financial instruments
have a reliably determinable fair value and where doing so
eliminates or significantly reduces a measurement or recognition
inconsistency that would otherwise arise from measuring assets
and liabilities or recognizing gains and losses on them on a
different basis. The Company has designated its cash and cash
equivalents as held for trading. All other non-derivative
financial assets not meeting the Company's criteria for
designating as held for trading are classified as available for
sale, loans and receivables or held to maturity.
Financial assets purchased or sold, where the contract requires
the asset to be delivered within an established timeframe, are
recognized on a settlement date basis.
Transaction costs on financial assets and liabilities classified
as other than held for trading are capitalized and amortized over
the expected life of the instrument, based on contractual cash
flows, utilizing the effective interest method. The effective
interest method calculates the amortized cost of a financial
asset or liability and allocates the interest income or expense
over the term of the financial asset or liability using an
effective interest rate.
(f) Derivative instruments and hedging activities:
To reduce its exposure to movements in energy commodity prices,
interest rate changes, and foreign currency exchange rates, the
Company uses various risk management techniques including the use
of derivative instruments. Derivative instruments may include
forward contracts, fixed-for-floating swaps, and option
contracts. Such instruments may be used to establish a fixed
price for an energy commodity, an interest-bearing obligation or
an obligation denominated in a foreign currency. All derivative
instruments, including embedded derivatives, are recorded at fair
value on the balance sheet as derivative instruments assets or
derivative instruments liabilities except for embedded
derivatives instruments that are clearly and closely linked to
their host contract and the combined instrument is not measured
at fair value. Any contract to buy or sell a non-financial item
is not treated as a non-financial derivative if that contract was
entered into and continues to be held for the purpose of the
receipt or delivery of a non-financial item in accordance with
the Company's expected purchase, sale or usage requirements. All
changes in the fair value of derivatives are recorded in net
income unless cash flow hedge accounting is used, in which case
changes in fair value of the effective portion of the derivatives
are recorded in other comprehensive income. The Company accounts
separately for any embedded derivatives in any hybrid instruments
issued or acquired. The Company does not account for foreign
currency derivatives embedded in non-financial instrument host
contracts when the currency that is commonly used in contracts to
purchase or sell non-financial items in the economic environment
is that currency in which the transaction takes place.
The Company uses financial contracts-for-differences (or fixed-
for-floating swaps) to hedge the Company's exposure to
fluctuations in electricity prices. Under these instruments, the
Company agrees to exchange, with creditworthy or adequately
secured counterparties, the difference between the variable or
indexed price and the fixed price on a notional quantity of the
underlying commodity for a specified timeframe.
The Company uses non-financial forward delivery derivatives to
manage the Company's exposure to fluctuations in natural gas
prices related to its natural gas customer contracts and
obligations arising from its natural gas fired generation
facilities. Under these instruments, the Company agrees to sell
or purchase natural gas at a fixed price for delivery of a pre-
determined quantity under a specified timeframe.
Foreign exchange forward contracts are used by the Company to
manage foreign exchange exposures, consisting mainly of U.S
dollar exposures, resulting from anticipated transactions
denominated in foreign currencies. For transactions involving the
development or acquisition of property, plant and equipment, when
the real or anticipated transaction subsequently results in the
recognition of a financial asset, the associated gains or losses
on hedging derivatives recognized in other comprehensive income
are included in the initial carrying amount of the asset acquired
in the same period or periods during which the asset acquired
affects net income.
The Company may use forward interest rate or swap agreements and
option agreements to manage the impact of fluctuating interest
rates on existing debt.
The Company may use physical or financial commodity derivative
trades which are transacted with the intent of benefiting from
short-term actual or expected differences between their buying
and selling prices or to lock in arbitrage opportunities. Such
trades are recognized on a net basis in the Company's revenues.
The Company may use hedge accounting when there is a high degree
of correlation between the risk in the item designated as being
hedged (the hedged item) and the derivative instrument designated
as a hedge (the hedging instrument). The Company documents all
relationships between hedging instruments and hedged items at the
hedge's inception, including its risk management objectives and
its assessment of the effectiveness of the hedging relationship
on a retrospective and prospective basis. The Company uses cash
flow hedges for certain of its anticipated transactions to reduce
exposure to fluctuations in changes in commodity prices. In a
cash flow hedging relationship, the effective portion of the
change in the fair value of the hedging derivative is recognized
in other comprehensive income, while the ineffective portion is
recognized in net income. The amounts recognized in accumulated
other comprehensive income are reclassified into net income in
the same period or periods in which the hedged item occurs and is
recorded in net income or when the hedged item becomes probable
of not occurring. The Company has not designated any fair value
hedges at the balance sheet date.
A hedging relationship is discontinued if the hedge relationship
ceases to be effective, if the hedged item is an anticipated
transaction and it is probable that the transaction will not
occur by the end of the originally specified time period, if the
Company terminates its designation of the hedging relationship,
or if either the hedged or hedging instrument ceases to exist as
a result of its maturity, expiry, sale, termination or
cancellation and is not replaced as part of the Company's hedging
strategy.
If a cash flow hedging relationship is discontinued or ceases to
be effective, any cumulative gains or losses arising prior to
such time are deferred in accumulated other comprehensive income
and recognized in net income in the same period as the hedged
item, and subsequent changes in the fair value of the derivative
instrument are reflected in net income. If the hedged or hedging
item matures, expires, or is sold, extinguished or terminated and
the hedging item is not replaced, any gains or losses associated
with the hedging item that were previously recognized in other
comprehensive income are recognized in net income in the same
period as the corresponding gains or losses on the hedged item.
When it is no longer probable that an anticipated transaction
will occur within the originally determined period and the
associated cash flow hedge has been discontinued, any gains or
losses associated with the hedging item that were previously
recognized in other comprehensive income are recognized in net
income in the period.
When the conditions for hedge accounting cannot be applied, the
changes in fair value of the derivative instruments are
recognized as described above. The fair value of derivative
financial instruments reflects changes in the commodity market
prices, interest rates and foreign exchange rates. Fair value is
determined based on exchange or over-the-counter price quotations
by reference to bid or asking price as appropriate, in active
markets. In illiquid or inactive markets, the Company uses
appropriate valuation and price modeling techniques commonly used
by market participants to estimate fair value. Fair values
determined using valuation models require the use of assumptions
concerning the amounts and timing of future cash flows. Fair
value amounts reflect management's best estimates using external
readily observable market data such as future prices, interest
rate yield curves, foreign exchange rates, discount rates for
time value, and volatility where available. It is possible that
the assumptions used in establishing fair value amounts will
differ from future outcomes and the impact of such variations
could be material.
(g) Income taxes:
The Company's Canadian subsidiaries are subject to income taxes
pursuant to the Income Tax Act (Canada) (ITA) and provincial
income tax acts. The Company's U.S. subsidiaries are subject to
income tax pursuant to U.S. federal and state tax laws.
The Company follows the asset and liability method of accounting
for income taxes. Under this method, current income taxes are
recognized for the estimated income taxes payable or recoverable
for the current year. Future income tax assets and liabilities
are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Future income tax assets and liabilities are measured using
enacted or substantively enacted rates of tax expected to apply
to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect
of a change in tax rates on future tax assets and liabilities is
recognized in income in the period that includes the date of
enactment or substantive enactment.
(h) Cash and cash equivalents:
Cash and cash equivalents include cash or highly liquid,
investment-grade short-term investments and are recorded at fair
market value.
(i) Inventories:
Small parts and other consumables and coal, the majority of which
are consumed by the Company in the provision of its goods and
services, are valued at the lower of cost and net realizable
value. Cost includes the purchase price, transportation costs and
other costs to bring the inventories to their present location
and condition. The cost of any assembled inventory includes
direct labour, materials and attributable overhead. The costs of
inventory items that are interchangeable are determined on an
average cost basis. For inventory items that are not
interchangeable, cost is assigned using specific identification
of their individual costs. Natural gas inventory held in storage
for trading purposes is recorded at fair value less costs to
sell, as measured by the one-month forward price of natural gas.
Previous write-downs of inventories from cost to net realizable
value can be fully or partially reversed if supported by economic
circumstances.
(j) Property, plant and equipment:
Property, plant and equipment are recorded at cost and include
contracted services, materials, interest, direct and indirect
labour, directly attributable overhead costs, asset retirement
costs, development costs associated with specific property, plant
and equipment, and net revenues during the pre-operating period.
Contributions received for financing the costs of assets are
recorded as a reduction of the related asset cost.
Depreciation on property, plant and equipment is provided on the
straight-line basis over their estimated useful lives. No
depreciation is provided on construction work in progress.
The Company capitalizes interest during construction to provide
for the costs of borrowing on construction activities. Interest
is applied during construction using the weighted average cost of
debt incurred on the Company's external borrowings used to
finance qualifying assets.
(k) Power purchase arrangements:
Acquired PPAs are reflected on the consolidated balance sheet as
power purchase arrangements and are recorded at cost and are
amortized over their terms on a straight-line basis.
Under the terms of the Alberta PPAs, the Company is obligated to
make fixed and variable payments to the owners of the underlying
generation units over their respective terms. Such amounts are
recorded as operating expenses as incurred. At September 30,
2009, the remaining term of the 20-year Sundance PPA is
approximately 11 years. The Company is also obligated to make
fixed and variable payments to the buyer of the Battle River PPA,
in proportion to its effective ownership interest, until the sale
of the Company's remaining interest in the Battle River Power
Syndicate Agreement (Battle River PSA) is completed in 2010 as
described in note 30.
The Company's Alberta PPAs are owned under equity syndication
agreements with an equity syndicate. Under the terms of the
agreements, the syndicate members receive their proportionate
share of the committed generating capacity in exchange for their
proportionate share of the price paid for the Alberta PPAs and
all payments to the generation unit owners.
The Company's investment in the Alberta PPAs and its related
revenues and expenses are recorded on a proportionate basis,
after deducting the equity syndicate's share.
The EPLP PPAs reflect the cost to acquire long-term sales
contracts under which revenue is earned by EPLP's generation
units. The EPLP PPAs are amortized over their remaining terms,
which range from one to 18 years.
(l) Contract and customer rights and other intangible assets:
Contract rights include acquired management and operations
agreements and water rights. Costs assigned to contract rights
related to management and operations agreements are amortized on
a straight-line basis, from the dates of acquisition, over the
remaining contract terms which range from 5 to 57 years. Water
rights associated with acquired hydroelectric power generation
plants are recorded at cost and are amortized over the remaining
useful lives of the associated property, plant and equipment.
Other rights include the cost of land lease agreements for use in
wind power projects in Ontario and coal supply access rights
relating to the Keephills 3 Project (note 27(b)). The lease
rights are amortized on a straight-line basis over the estimated
useful lives of the related wind power assets, commencing when
those assets are constructed and commissioned for service. The
access rights will be amortized over the life of the coal supply
agreement and amortization will commence when the Keephills 3
plant is commissioned for service.
Other intangible assets, which include the costs of acquired
software, are amortized over the estimated useful lives of the
assets which range from 1 to 10 years.
Customer rights represent the costs to acquire the rights to a
long-term sales contract for the output of the Brown Lake plant.
The costs are amortized on a straight-line basis over the 30-year
term of the contract.
(m) Goodwill:
Goodwill is the cost of an acquisition less the fair value of the
net assets of an acquired business. Goodwill is tested for
impairment by comparing the fair value of each reporting unit to
which the goodwill relates to the carrying amount, including
goodwill, of each reporting unit. If the carrying amount of the
reporting unit exceeds its fair value, indicating an impairment,
a second test is performed to measure the amount of the
impairment. In the second test, the fair value of the reporting
unit's goodwill is compared with its carrying amount to measure
the impairment loss, if any.
(n) Other assets:
Loans and other long-term receivables are comprised of promissory
notes receivable and amounts due from customers more than one
year from the balance sheet date and will be repaid between 2009
and 2025.
Investments in which the Company exercises significant influence
are accounted for using the equity method. Other investments are
classified as available for sale and are recorded at fair value
unless the investments do not have a quoted market price in an
active market in which case the investments are recorded at cost.
Investments recorded at cost for which there is a decline in fair
value below cost that is other than temporary are written down
and the loss is recognized in net income.
(o) Impairment of long-lived assets:
The Company reviews the valuation of long-lived assets subject to
depreciation and amortization when events or changes in
circumstances may indicate or cause a long-lived asset's carrying
amount to exceed the total undiscounted future cash flows
expected from its use and eventual disposition. An impairment
loss, if any, would be recorded as the excess of the carrying
amount of the asset over its fair value, measured by either
market value, if available, or estimated by calculating the
present value of expected future cash flows related to the asset.
(p) Deferred availability incentives:
Under the terms of the Genesee PPA, the target levels of
generation availability set out in the PPA recognize that the
respective generation units will experience planned and forced
outages over the term of the PPA. The Company records the
electricity revenue from these generation units at the price
embedded in the PPA, including expected incentives and penalties
for operating above or below specified availability targets set
out in the PPA. Under this approach, incentives for the current
period are deferred since they are not expected to be sustained
over the full term of the PPA. As penalties are incurred, any
balance of deferred incentive will be drawn down. If cumulative
penalties exceed cumulative incentives, the excess will be
charged to income and no deferred charge will be created.
Deferred incentive amounts are included in other non-current
liabilities on the balance sheet.
The degree to which incentives are recognized or deferred will
change due to revisions to the long-term outlook of plant
performance, which is based on historical performance, planned
maintenance, reliability and generation availability, and due to
revisions in the estimated long-term price embedded in the PPA.
(q) Asset retirement obligations:
The Company recognizes asset retirement obligations in the period
in which they are incurred, unless the fair value cannot be
reasonably determined. A corresponding asset retirement cost is
added to the carrying amount of the associated long-lived asset,
and is depreciated over the estimated useful life of the asset.
Accretion of the liability due to the passage of time is an
operating expense, and is recorded over the estimated time period
until settlement of the obligation.
The Company has recorded asset retirement obligations for its
power generation plants and Genesee coal mine as it is legally
required to remove the facilities at the end of their useful
lives and restore the plant and mine sites to their original
condition. Asset retirement obligations for the coal mine are
incurred over time as new areas are mined, and a portion of the
liability is settled over time as areas are reclaimed prior to
final pit reclamation.
(r) Leases or arrangements containing a lease:
Finance income related to leases or arrangements accounted for as
direct financing leases are recognized in a manner that produces
a constant rate of return on the net investment in the lease. The
net investment is composed of net minimum lease payments and
unearned finance income. Unearned finance income is the
difference between the total minimum lease payments and the
carrying amount of the leased property. Unearned finance income
is deferred and recognized in net income over the lease term.
(s) Contract liabilities:
The Company's contract liabilities, primarily related to acquired
EPLP PPAs, are being amortized over the terms of the contracts
which range from three to eight years.
(t) Foreign currency translation:
The Company's self-sustaining foreign operations are translated
to Canadian dollars using the current rate method. Assets and
liabilities are translated at the exchange rate in effect at the
balance sheet date. Revenues and expenses are translated at
average exchange rates prevailing during the period. The
resulting translation gains and losses are deferred and included
in accumulated other comprehensive income until there is a
reduction in the Company's net investment in the foreign
operations.
Foreign currency transactions and financial statements of
integrated foreign operations are translated to Canadian dollars
using the temporal method. Transactions denominated in foreign
currencies are translated at exchange rates in effect at the
transaction date. Monetary assets and liabilities denominated in
foreign currencies are translated at the exchange rate in effect
on the balance sheet date. The resulting foreign exchange gains
and losses are included in the consolidated statements of income.
(u) Employee future benefits:
The employees of the Company are either members of the Local
Authorities Pension Plan (LAPP) or other defined contribution or
benefit plans.
The LAPP is a multiemployer defined benefit pension plan. The
Trustee of the plan is the Treasurer of Alberta and the plan is
administered by a Board of Trustees. The Company and its
employees make contributions to the plan at rates prescribed by
the Board of Trustees to cover costs under the plan. Since the
plan is a multiemployer plan, it is accounted for as a defined
contribution plan. Accordingly, the Company does not recognize
its share of any plan surplus or deficit.
The Company maintains additional defined contribution and defined
benefit pension plans to provide pension benefits to those
employees (comprising less than 30% of total employees of Capital
Power) who are not otherwise served by LAPP.
The Company accrues its obligations for its defined benefit
pension plans net of plan assets in the employee future benefits
liabilities included in other non-current liabilities. The cost
of pension benefits earned by employees is actuarially determined
using the projected benefit method pro-rated on services and
management's best estimate of expected plan investment
performance, salary escalation and retirement ages of employees.
For the purpose of calculating the expected return on plan
assets, those assets are valued at quoted market value. The
discount rate used to calculate the interest cost on the accrued
benefit obligation is determined by reference to market interest
rates at the balance sheet date on high-quality debt instruments
with cash flows that match the timing and amount of expected
benefit payments. Past service costs from plan amendments are
amortized on a straight-line basis over the estimated average
remaining service of employees active at the date of amendment.
The excess of the net cumulative unamortized actuarial gain or
loss over 10% of the greater of the accrued benefit obligation
and the market value of plan assets is amortized over the
estimated average remaining service period of the active
employees.
The Company has an unfunded long-term disability benefit plan
which provides provincial health care premiums, health and dental
benefits, and required pension contributions for current disabled
employees. The plan is a defined benefit plan and the obligation
related to long-term disability benefits is actuarially
determined using the projected benefit method pro-rated on
services and management's best estimate of future health care
costs, salary escalation for estimating future benefit
contributions, recovery and termination experience, and inflation
rates. The Company's accrual for the long-term disability benefit
plan is reflected in the employee future benefits liabilities
included in other non-current liabilities. The discount rate used
to calculate the interest cost on the accrued benefit obligation
is determined by reference to market interest rates at the
balance sheet date on high-quality debt instruments with cash
flows that match the timing and amount of expected benefit
payments. Actuarial gains or losses on the accrued benefit
obligation arise from differences between actual and expected
experience and from changes in the actuarial assumptions used to
determine the accrued benefit obligation. Actuarial gains and
losses are recognized in income immediately.
(v) Stock-based compensation
The Company determines the fair value of stock options using a
binomial option pricing model at the date of grant. The fair
value of the granted options is recognized over the vesting
period as a compensation expense and contributed surplus.
Contributed surplus is reduced as the options are exercised and
the amount initially recorded in contributed surplus is credited
to share capital. The Company has not incorporated an estimated
forfeiture rate for stock options that will not vest, as the
Company accounts for actual forfeitures as they occur.
(w) Earnings per share
Basic earnings per share is calculated by dividing income
available to common shareholders by the weighted average number
of common shares outstanding during the period.
Diluted earnings per share is calculated on the treasury stock
method, by dividing income available to common shareholders,
adjusted for the effects of dilutive securities, by the weighted
average number of common shares outstanding during the period
and all additional common shares that would have been outstanding
had all potential dilutive common shares been issued. This method
computes the number of additional shares by assuming all
outstanding options, for which the average market price of the
common shares for the period exceeds the exercise price, are
exercised. The total number of shares is then reduced by the
number of common shares assumed to be repurchased from the total
issuance proceeds, using the average market price of the
Company's common shares for the period. The average market price
of the Company's common shares for the period ended September 30,
2009 was below the exercise price of all granted options and as a
result none of the share purchase options described in note 14
have a dilutive effect on earnings per share. Exchangeable common
limited partnership units of CPLP, as described in note 3, are
exchangeable for common shares of the Company and have a dilutive
effect on earnings per share as described in note 14.
( x) Offsetting of financial assets and financial liabilities:
Financial assets and financial liabilities are presented on a net
basis when the Company has a legally enforceable right to set-off
the recognized amounts and intends to settle on a net basis or to
realize the asset and settle the liability simultaneously.
(y) Long-term debt discounts, premiums and issue expenses:
Debenture discounts, premiums and issue expenses with respect to
long-term debt are amortized over the term of the related debt
using the effective interest rate method.
3. Acquisition of assets and initial public offering:
Pursuant to its initial public offering on July 9, 2009, the Company
issued 21,750,000 common shares at a price of $23.00 per share for
net proceeds of $468 million after deducting underwriting commissions
of $25 million and offering expenses of $7 million. The net proceeds
of the offering were used to purchase a 27.8% equity interest in
CPLP. CPLP purchased substantially all of the power generation assets
from EPCOR Utilities Inc. (EPCOR), effective July 1, 2009 through the
following series of transactions (the Reorganization):
- Formation of CPLP: Capital Power and a wholly-owned subsidiary
of Capital Power (Capital Power LP Holdings Inc.) formed CPLP.
Capital Power acquired one general partner unit (GP Unit) and
became the initial general partner of CPLP. Capital Power LP
Holdings Inc. acquired one common limited partnership unit and
as a result, became the initial limited partner in CPLP.
- Sale of EMCC Limited to Capital Power: EPCOR transferred all of
the outstanding common shares of EMCC Limited to Capital Power
in return for payment of approximately $468 million in cash.
- Contribution of Assets by EMCC Limited to CPLP: EMCC Limited
contributed substantially all of its assets (consisting
primarily of certain securities of subsidiary entities, its
class B shares in the capital of EPLP Investments Inc. and
promissory note of EPLP Investments Inc.) to CPLP in return for
GP Units. Capital Power transferred its GP Unit in CPLP to EMCC
Limited and as a result EMCC Limited became the general partner
of CPLP.
- Sale of Assets by EPCOR Power Development Corporation (EPDC) to
CPLP: EPDC transferred substantially all of its assets
(consisting primarily of assets related to Genesee Units 1 and
2, the Genesee Coal Mine joint venture and certain interests in
partnerships) to CPLP in return for 56.625 million exchangeable
limited partnership units of CPLP and approximately $896
million in cash. CPLP financed the cash payment with the
proceeds from a long-term debt obligation to EPCOR.
Concurrently, EPDC subscribed for 56.625 million special voting
shares of Capital Power for a nominal amount.
Immediately following completion of the Reorganization, Capital Power
held approximately 27.8% of CPLP while EPCOR held 56.625 million
exchangeable limited partnership units of CPLP (exchangeable for
common shares of Capital Power on a one-for-one basis) representing
approximately 72.2% of CPLP. Each exchangeable limited partnership
unit is accompanied by a special voting share in the capital of
Capital Power which entitles the holder to a vote at Capital Power
shareholder meetings, subject to the restriction that such special
voting shares must at all times represent not more than 49% of the
votes attached to all Capital Power common shares and special voting
shares, taken together. Capital Power and EPCOR have agreed that for
so long as EPCOR holds not less than a 20% interest in the common
shares of Capital Power, the number of directors will not be less
than nine. The special voting shares also entitle EPCOR, voting
separately as a class, to nominate and elect a maximum of four
directors of Capital Power. There are currently twelve directors on
Capital Power's board of directors. Accordingly, Capital Power will
have control over CPLP and, on that basis, the operations of CPLP
will be consolidated by Capital Power for financial statement
purposes.
Immediately following completion of the Reorganization, CPLP held 49%
and EPCOR held 51% of the voting rights in EPLP Investments Inc. EPLP
Investments Inc. owns the approximate 30.6% interest in EPLP
previously owned by EPCOR. However, CPLP is entitled to all of the
economic interest in EPLP Investments Inc. Accordingly, effective
July 1, 2009 Capital Power will consolidate the financial results of
EPLP.
The $468 million purchase price was allocated to the assets acquired
and liabilities assumed based on estimated fair values as follows:
---------------------------------------------------------------------
Cash and cash equivalents $ 71
Other current assets 437
Property, plant and equipment 3,163
Power purchase arrangements 572
Contract and customer rights and other intangible assets 179
Derivative instruments assets - non-current 74
Future income tax assets - non-current 57
Acquired goodwill 123
Other non-current assets 122
Assets held for sale 36
Current liabilities (414)
Long-term debt (including current portion) (1,761)
Derivative instruments liabilities - non-current (64)
Future income tax liabilities - non-current (93)
Other non-current liabilities (99)
---------------------------------------------------------------------
2,403
Non-controlling interests in net assets (note 13) (1,935)
---------------------------------------------------------------------
Fair value of net assets acquired $ 468
---------------------------------------------------------------------
---------------------------------------------------------------------
The values of the assets and liabilities above reflect management's
best estimates as of the release date of these financial statements.
The values of certain assets and liabilities are preliminary, and are
subject to refinement as additional information is obtained. As of
the issue date of these financial statements, the Company is
performing additional analysis on its income tax balances recognized
on acquisition and upon finalization, material adjustments may
result.
The $179 million of contract and customer rights and other
intangibles includes $115 million of contract rights, $43 million of
coal supply access rights and $21 million of other rights which
include customer rights, lease rights, software intangibles and
emission credits. Substantially all of the acquired contract and
customer rights and other intangible assets are subject to
amortization as described in note 2(l).
The amount allocated to acquired goodwill is not deductible for
income tax purposes.
Non-controlling interests in net assets acquired include preferred
share and other non-controlling interests in EPLP at the acquisition
date of $122 million and $370 million respectively, as well as
limited partnership units of CPLP issued to non-controlling interests
as a part of the Reorganization of $1,302 million. The remaining non-
controlling interests of $141 million relate to the non-controlling
interest in net assets acquired.
The results of operations of the subsidiaries and assets acquired
from EPCOR are included in the Company's consolidated statements of
income and retained earnings from July 1, 2009, the effective date of
the acquisition.
Capital Power has entered into various agreements with EPCOR to
provide for certain aspects of the separation of the business of
Capital Power from EPCOR, to provide for the continuity of operations
and services and to govern the ongoing relationships between the two
groups of entities.
4. Inventories:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Small parts and other consumables $ 41
Coal 10
Natural gas held in storage for trading purposes 6
---------------------------------------------------------------------
$ 57
---------------------------------------------------------------------
---------------------------------------------------------------------
Inventories expensed upon usage during the three months ended
September 30, 2009 of $4 million were charged to energy purchases and
fuel, and operations, maintenance and administration. No write-downs
of inventories or reversals of previous write-downs were recognized
in the three months ended September 30, 2009. At September 30, 2009,
no inventories were pledged as security for liabilities.
5. Property, plant and equipment:
---------------------------------------------------------------------
September 30, 2009
---------------------------------------------------------------------
Composite
Depreciation Accumulated Net Book
Rate Cost Depreciation Value
---------------------------------------------------------------------
Land None $ 66 $ - $ 66
Plant and equipment 5.4% 2,323 27 2,296
Contributions 12.0% (27) (1) (26)
Construction work in
progress None 863 - 863
---------------------------------------------------------------------
$3,225 $ 26 $3,199
---------------------------------------------------------------------
---------------------------------------------------------------------
Depreciation, amortization and asset retirement accretion expense is
comprised of:
---------------------------------------------------------------------
Three months ended
September 30,
2009
---------------------------------------------------------------------
Depreciation on assets in service $ 33
Amortization of PPAs 12
Gain on settlement of asset retirement obligations
(note 12) (2)
Accretion on asset retirement obligations (note 12) 1
Amortization of contributions (1)
Amortization of contract and customer rights and other
intangible assets 1
---------------------------------------------------------------------
$ 44
---------------------------------------------------------------------
---------------------------------------------------------------------
Interest capitalized to property, plant and equipment for the three
months ended September 30, 2009 is $9 million.
---------------------------------------------------------------------
6. Power purchase arrangements:
---------------------------------------------------------------------
September 30, 2009
---------------------------------------------------------------------
Accumulated Net book
Cost amortization value
---------------------------------------------------------------------
Alberta PPAs $ 149 $ 3 $ 146
EPLP PPAs 399 9 390
---------------------------------------------------------------------
$ 548 $ 12 $ 536
---------------------------------------------------------------------
---------------------------------------------------------------------
7. Contract and customer rights and other intangible assets:
---------------------------------------------------------------------
September 30, 2009
---------------------------------------------------------------------
Accumulated Net book
Cost amortization value
---------------------------------------------------------------------
Contract rights $ 114 $ 1 $ 113
Other rights 50 - 50
Software intangibles 7 - 7
Emission credits 7 - 7
Customer rights 4 - 4
---------------------------------------------------------------------
$ 182 $ 1 $ 181
---------------------------------------------------------------------
---------------------------------------------------------------------
8. Goodwill:
The changes in the carrying amount of goodwill are as follows:
---------------------------------------------------------------------
Three months ended
September 30,
2009
---------------------------------------------------------------------
Acquired goodwill (note 3) $ 123
Foreign exchange translation adjustment (4)
---------------------------------------------------------------------
Balance, end of period $ 119
---------------------------------------------------------------------
---------------------------------------------------------------------
9. Other assets:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Carrying amount
Loans and other long-term receivables $ 49
Net investment in lease 28
Investment in PERH 13
Portfolio investments 7
Other 20
---------------------------------------------------------------------
$ 117
---------------------------------------------------------------------
---------------------------------------------------------------------
Net investment in lease
The PPA under which the Company's power generation facility located
in Oxnard, California operates is considered to be a direct financing
lease for accounting. The PPA expires in 2020. The current portion of
the net investment in lease of $2 million is included in accounts
receivable. Financing income for the three months ended September 30,
2009 of $1 million is included in revenues.
Investment in PERH
Through the acquisition described in note 3, the Company, as part of
its EPLP subsidiary, acquired 17.0% of the common share interests and
14.2% of the preferred interests in Primary Energy Recycling Holdings
LLC (PERH). Effective August 24, 2009, PERH converted its outstanding
preferred interests into common shares. As a result of the
conversion, the Company now holds 14.3% of the outstanding common
shares of PERH. Until the conversion date, the Company's common share
interest in PERH was accounted for using the equity method and the
preferred interest was recorded on the cost basis. Subsequent to the
conversion of the preferred interests into common shares, the Company
commenced recording its entire 14.3% common share interest on the
cost basis. For the period from July 1 to August 24, 2009, equity
losses of $1 million, included in operations, maintenance and
administration expense, have been recorded against the common share
investment in PERH.
The Company, through its EPLP subsidiary, monitors its investment in
PERH for impairment by considering current economic factors and
records an impairment charge when it believes the investment has
experienced a decline that is other than temporary. The Company
estimates the fair value of its investment in PERH by considering
factors such as the quoted market price of the securities issued by
PERC, which owns the remaining interests in PERH not held by EPLP.
During the three months ended September 30, 2009 the Company has not
recognized an impairment on this investment.
10. Long-term debt:
---------------------------------------------------------------------
Effective
Interest September
Rate 30, 2009
---------------------------------------------------------------------
Unsecured senior debt payable to EPCOR
Due in 2010 at 6.95% 4.90% $ 203
Due in 2011 at 6.60% 5.53% 204
Due in 2016 at 6.75% 6.16% 134
Due in 2018 at 5.80% 5.63% 165
Due in 2018 at 9.00% 7.41% 170
---------------------------------------------------------------------
876
EPLP unsecured senior notes (US$190), at 5.90%,
due in 2014 6.23% 203
EPLP unsecured senior medium-term notes, at 5.95%,
due in 2036 7.11% 203
EPLP unsecured senior medium-term notes (US$150),
at 5.87%, due in 2017 6.13% 159
EPLP unsecured senior medium-term notes (US$75),
at 5.97%, due in 2019 6.26% 78
EPLP secured term loan, at 11.25%, due in 2010 10.69% 1
Non-recourse financing:
Brown Lake Project, at 8.7%, due in 2016 7.13% 6
Joffre Cogeneration Project, at fixed and
floating rates, due in 2020 8.35% 42
CPLP revolving extendible credit facilities, at
floating rates, due in 2009 3.15% 77
EPLP revolving extendible credit facilities, at
floating rates, due in 2009 1.16% 142
---------------------------------------------------------------------
1,787
Less: Current portion 247
Deferred debt issue costs 16
---------------------------------------------------------------------
$1,524
---------------------------------------------------------------------
Unsecured senior debt payable to EPCOR
The unsecured senior debt payable to EPCOR matures between 2010 and
2018. On or after December 2, 2012, if EPCOR no longer owns, directly
or indirectly, at least 20% of the outstanding limited partnership
units of CPLP, a subsidiary of Capital Power, then EPCOR may, by
written notice, require repayment of all or any portion of the
outstanding principal amount of this debt and accrued interest
thereon.
EPLP unsecured senior notes
The unsecured senior notes of $203 million mature in 2014 and are
fully and unconditionally guaranteed by EPLP as to payment of
principal, premium, if any, and interest on a senior unsecured basis.
Interest is payable semi-annually.
The unsecured senior medium-term notes of $203 million are due in
2036 with interest payable semi-annually.
The unsecured senior medium-term notes aggregating to $237 million
(US$225 million) were issued in two tranches. The $159 million
(US $150 million) and $78 million (US$75 million) are due in 2017 and
2019 respectively with interest payable semi-annually.
EPLP secured term loan
The term loan matures in 2010 and is secured by a first fixed and
specific mortgage over the Queen Charlotte plant which has a carrying
amount of $14 million.
Non-recourse financing
Joffre Cogeneration Project financing represents the Company's share
of syndicated loans for the project. A $40 million portion of the
debt bears a fixed interest rate of 8.59% payable quarterly until
2020. The remaining debt bears interest at the prevailing bankers'
acceptance rate plus a spread of 1.5% which escalates to 1.875% over
the term of the loan. The debt is secured by a charge against project
assets which have a carrying amount of $100 million. Brown Lake
Project financing is secured by a charge against project assets which
have a carrying amount of $10 million.
EPLP and CPLP revolving extendible credit facilities
Unsecured three-year credit facilities of $100 million, $100 million
and $125 million, for a total of $325 million, committed to 2011, and
uncommitted amounts of $20 million, are available to the Company's
subsidiary, EPLP. At September 30, 2009, the Company had $66 million
in bankers' acceptances and $76 million (US$71 million) in U.S. LIBOR
loans outstanding under this facility. Unsecured three-year credit
facilities of $700 million, committed to 2012 and uncommitted amounts
of $20 million, are available to the Company's subsidiary, CPLP. At
September 30, 2009, the Company had $77 million in bankers'
acceptances outstanding under this facility.
The Company also has unsecured credit facilities of $500 million
available through its CPLP subsidiary. These facilities have a
maturity date of July 8, 2011 with an option to extend for an
additional 364 day period. As at September 30, 2009, no amounts have
been drawn on this facility, but letters of credit of $90 million
have been issued as described in note 28.
Under the terms of the extendible facilities, the Company may obtain
advances by way of prime loans, U.S. base rate loans, U.S LIBOR loans
and bankers' acceptances. Depending on the facility, amounts drawn by
way of prime loans bear interest at the prevailing Canadian prime
rate or the average one-month bankers' acceptance rate plus a spread
ranging from 0.75% to 1.00%. Amounts drawn by way of U.S. base rate
loans bear interest at a bank determined variable commercial lending
rate or the prevailing Federal Funds Rate as published by the U.S.
Federal Reserve Board plus a spread ranging from 0.75% to 1.00%.
Amounts drawn by way of U.S. LIBOR loans bear interest at the
prevailing LIBOR rate plus a spread based on the Company's credit
rating. Amounts drawn by way of bankers' acceptances bear interest at
the prevailing bankers' acceptance rate plus a spread based on the
Company's credit rating.
11. Other non-current liabilities:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Asset retirement obligations (note 12) $ 81
Employee future benefit liabilities 11
Other 7
---------------------------------------------------------------------
$ 99
---------------------------------------------------------------------
---------------------------------------------------------------------
12. Asset retirement obligations:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Liabilities assumed on acquisition of assets (note 3) $ 88
Liabilities incurred 2
Liabilities settled (2)
Asset retirement accretion expense 1
---------------------------------------------------------------------
89
Less: current portion in accounts payable and accrued
liabilities 8
---------------------------------------------------------------------
$ 81
---------------------------------------------------------------------
---------------------------------------------------------------------
The Company estimates the undiscounted amount of cash flow required
to settle its asset retirement obligations is approximately $383
million, calculated using inflation rates ranging from 2% to 3%. The
expected timing for settlement of the obligations is between 2009 and
2090. The majority of the payments to settle the obligations are
expected to occur between 2023 and 2064 for the power generation
plants, and between 2009 and 2013 for sections of the Genesee coal
mine. Discount rates ranging from 4.1% to 8.7% were used to calculate
the carrying amount of the asset retirement obligations. No assets
have been legally restricted for settlement of these liabilities.
13. Non-controlling interests:
Results of operations which relate to non-controlling interests are
as follows:
---------------------------------------------------------------------
Three months ended
September 30,
2009
---------------------------------------------------------------------
Non-controlling interests in EPLP $ 20
Non-controlling interests in CPLP 44
Preferred share dividends paid by subsidiary company 2
---------------------------------------------------------------------
$ 66
---------------------------------------------------------------------
---------------------------------------------------------------------
Non-controlling interests reflected on the consolidated balance sheet
are comprised of:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Non-controlling interests in EPLP in net assets
acquired (note 3) $ 370
Net income attributable to non-controlling interests 20
Other comprehensive loss attributable to non-controlling
interests (20)
Distributions to non-controlling interests (17)
---------------------------------------------------------------------
Non-controlling interests in EPLP, end of period 353
---------------------------------------------------------------------
Non-controlling interests in CPLP in net assets
acquired (note 3) 141
Partnership units issued to non-controlling interests
(note 3) 1,302
Net income attributable to non-controlling interests 44
Other comprehensive income attributable to non-controlling
interests 13
---------------------------------------------------------------------
Non-controlling interests in CPLP, end of period 1,500
---------------------------------------------------------------------
Preferred shares outstanding in acquired subsidiaries
(note 3) 122
---------------------------------------------------------------------
Preferred shares issued by subsidiary companies, end of
period 122
---------------------------------------------------------------------
$1,975
---------------------------------------------------------------------
---------------------------------------------------------------------
The non-controlling interests in EPLP represent the approximately
69.4% interest in EPLP not owned by CPLP. The non-controlling
interests in CPLP represents the approximately 72.2% interest in CPLP
not owned by the Company which includes approximately 72.2% of CPLP's
approximate 30.6% interest in EPLP.
14. Share capital:
---------------------------------------------------------------------
Number of shares
Authorized authorized
---------------------------------------------------------------------
Common shares unlimited
Preference shares, issuable in series unlimited
Special voting shares unlimited
Special limited voting share one
---------------------------------------------------------------------
---------------------------------------------------------------------
---------------------------------------------------------------------
September 30,
Issued and outstanding 2009
---------------------------------------------------------------------
21,750,000 common shares $ 477
56,625,000 special voting shares -
1 special limited voting share -
---------------------------------------------------------------------
$ 477
---------------------------------------------------------------------
---------------------------------------------------------------------
The $500 million of common shares issued to the public are recorded
net of share issue costs of $32 million as described in note 3.
Future income taxes of $9 million related to the share issue costs
have been recorded as an increase to common shares.
The special voting shares and special limited voting shares were
issued to a related party, EPCOR (including subsidiaries of EPCOR).
The special limited voting share entitles holders the right to vote
as a class on any matter that would: (i) change the location of
Capital Power's head office to a place other than The City of
Edmonton in the Province of Alberta; (ii) amend the articles of
Capital Power to, or result in a transaction that would, in each
case, impact the location of the head office or its meaning as
defined in Capital Power's articles; or (iii) amend the rights
attaching to the special limited voting share.
Share Purchase Options
Under the Company's long term incentive plan, the Company provides
stock options to certain employees to purchase common shares,
provided that the number of shares reserved for issuance will not
exceed 10% of the common shares to be outstanding at closing and that
the aggregate number of shares issued by the Corporation under this
Plan will not exceed 5,000,000 common shares.
During the three months ended September 30, 2009 the Company granted
993,400 stock options with one third vesting on January 1 of each of
2010, 2011, and 2012. Fair value of these options at grant date was
$2.57 per option resulting in total compensation expense recognized
of $1 million in operations, maintenance and administration for the
three months ended September 30, 2009. Granted options may be
exercised within 7 years of the grant date at a price of $23.00 per
share.
At September 30, 2009, none of the Company's outstanding stock
options were vested.
The following assumptions were used in estimating the fair value of
the granted stock options:
---------------------------------------------------------------------
Variable Value
---------------------------------------------------------------------
Expected life Seven-year term
Risk free interest rate Based on Government of Canada treasury
bills and bonds at December 31, 2008
Volatility 20% (estimated based on similar publicly-
traded companies)
Dividend yield 4.75% to 5.5%
---------------------------------------------------------------------
---------------------------------------------------------------------
Earnings per share
The 56.625 million exchangeable limited partnership units issued to
EPCOR as described in note 3 may be exchanged for common shares of
Capital Power on a one-for-one basis. For purposes of the diluted
earnings per share calculation, the exchange of such units for common
shares of the Company would remove the non-controlling interest in
net income related to CPLP of $44 million. Additionally, the income
tax provision of the Company would need to be adjusted to reflect the
non-controlling interest's share of CPLP income taxes of
approximately $12 million.
15. Accumulated other comprehensive income:
The components of accumulated other comprehensive income, at
September 30, 2009, are as follows:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Unrealized gains on derivative instruments
designated as cash flow hedges(1) $ 29
Unrealized loss in self-sustaining foreign operations(2) (33)
Non-controlling interests(2) 7
---------------------------------------------------------------------
$ 3
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Net of income tax expense of $3 million.
(2) Net of income tax expense of nil.
16. Change in non-cash working capital:
---------------------------------------------------------------------
Three months ended
September 30,
2009
---------------------------------------------------------------------
Accounts receivable $ (39)
Income taxes recoverable 3
Inventories (4)
Prepaid expenses (3)
Accounts payable and accrued liabilities (3)
Other current liabilities 6
---------------------------------------------------------------------
$ (40)
---------------------------------------------------------------------
---------------------------------------------------------------------
17. Net financing expenses:
---------------------------------------------------------------------
Three months ended
September 30,
2009
---------------------------------------------------------------------
Interest on long-term debt $ 26
Capitalized interest (9)
---------------------------------------------------------------------
$ 17
---------------------------------------------------------------------
---------------------------------------------------------------------
18. Income taxes:
---------------------------------------------------------------------
Three months ended
September 30,
2009
---------------------------------------------------------------------
Current income taxes $ -
Future income taxes (2)
---------------------------------------------------------------------
$ (2)
---------------------------------------------------------------------
---------------------------------------------------------------------
Income taxes differ from the amounts that would be computed by
applying the federal and provincial income tax rates as follows:
---------------------------------------------------------------------
Three months ended
September 30,
2009
---------------------------------------------------------------------
Income before income taxes and non-controlling
interests $ 78
Statutory income tax rates 29.0%
---------------------------------------------------------------------
Income taxes at statutory rate 23
Increase (decrease) resulting from:
Income not subject to income taxes at statutory
rates (12)
Change in income tax related to out-of-period
adjustment (10)
Unrecognized future income tax assets (4)
Non-taxable amounts 2
Adjustment for enacted changes in income tax laws and
rates and other tax rate differences (1)
---------------------------------------------------------------------
$ (2)
---------------------------------------------------------------------
---------------------------------------------------------------------
The tax effects of temporary differences that give rise to
significant components of the future income tax assets and future
income tax liabilities are presented below:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Property, plant and equipment - differences in net
book value and tax bases $ (114)
Losses carried forward 74
Cumulative eligible capital 21
Deferred income from partnerships (19)
Asset retirement obligations 15
Power purchase arrangements (11)
Derivative Instruments 5
Other (5)
---------------------------------------------------------------------
Net future income tax liabilities $ (34)
---------------------------------------------------------------------
Presented on the balance sheet as follows:
Current assets $ 2
Non-current assets 40
Current liabilities (17)
Non-current liabilities (59)
---------------------------------------------------------------------
$ (34)
---------------------------------------------------------------------
---------------------------------------------------------------------
At September 30, 2009, the Company has non-capital losses carried
forward of approximately $239 million, of which $152 million relate
to certain U.S. subsidiaries. These losses expire between 2010 and
2029. The Company also has capital losses for income tax purposes of
approximately $12 million which carry forward indefinitely. There are
non-capital losses available to be carried forward of $22 million,
and capital losses available to be carried forward of $3 million for
which no tax benefit has been recognized.
Reorganization
As a result of the Reorganization (as described in note 3), Capital
Power holds an economic interest in CPLP of 27.8%. Accordingly, the
Company records current and future income tax provisions related to
its economic interest in CPLP's taxable income. The Company also
records future income tax provisions related to CPLP's temporary
differences, and related to temporary differences of partnerships of
which CPLP is a partner, to the extent of the Company's economic
interest in CPLP.
Out-of-period adjustment
During the quarter ended September 30, 2009, EPLP, a subsidiary of
the Company, recorded an out-of-period adjustment of $10 million
relating to 2007, 2008 and 2009 to recognize net future income tax
assets associated with EPLP's interest in a long-term investment. The
long-term investment is treated as a partnership for U.S. tax
purposes and the adjustments are attributable to allocation of tax
deductions between the partners that were incorrectly calculated by
the long-term investment's external tax advisors for the relevant
periods. Of the $10 million, $3 million is attributable to 2007,
$6 million is attributable to 2008 and $1 million is attributable to
2009. The Company's management determined that the impact of the
adjustment, after considering non-controlling interests, was not
material to the expected results for the year ending December 31,
2009. As such, the adjustment was recorded during the quarter ended
September 30, 2009.
19. Fair value and classification of non-derivative financial assets and
liabilities:
The Company classifies its cash and cash equivalents as held for
trading and measures them at fair value. Accounts receivable are
classified as loans and receivables; accounts payable and accrued
liabilities are classified as other financial liabilities; all of
which are measured at amortized cost and their fair values are not
materially different from their carrying amounts due to their short-
term nature.
The classification, carrying amount and fair value of the Company's
other financial instruments at September 30, 2009 are summarized as
follows:
---------------------------------------------------------------------
September 30, 2009
--------------------
Carrying Fair
Financial asset or liability Classification amount value
---------------------------------------------------------------------
Other assets
Loans and other long-term Loans and
receivables receivables $ 49 $ 44
Net investment in lease Loans and
receivables 28 28
Long-term debt (including Other financial
current portion) liabilities 1,771 1,745
---------------------------------------------------------------------
---------------------------------------------------------------------
Net investment in lease
The fair value of the Company's net investment in lease is based on
the estimated interest rates implicit in comparable lease
arrangements or loans plus an estimated credit spread based on the
counterparty risk as at September 30, 2009.
Long-term debt
The fair value of the Company's long-term debt is based on
determining a current yield for the Company's debt as at September
30, 2009. This yield is based on an estimated credit spread for the
Company over the yields of long-term Government of Canada and U.S.
Government bonds that have similar maturities to the Company's debt.
The estimated credit spread is based on the Company's indicative
spread as published by independent financial institutions.
Other financial instruments
Fair values on the remaining financial instruments are determined by
reference to quoted bid or ask prices, as appropriate, in active
markets at period-end dates.
The fair value of certain capital venture investments cannot be
measured reliably as the shares are not quoted in an active market.
Investments in common shares held at their carrying amount have not
been offered for sale and in the event the Company elected to dispose
of the shares, they would most likely be sold in a private
transaction.
20. Derivative instruments and hedge accounting:
Derivative financial and non-financial instruments are held for the
purpose of energy purchases, merchant trading or financial risk
management.
The derivative instruments assets and liabilities used for risk
management purposes as described in note 21 consist of the following:
---------------------------------------------------------------------
September 30, 2009
-----------------------------------------------
Foreign
Energy exchange
------------------------- ----------
Cash flow Non- Non-
hedges hedges hedges Total
---------------------------------------------------------------------
Derivative instruments
assets:
Current $ 17 $ 128 $ 3 $ 148
Non-current 25 93 20 138
Derivative instruments
liabilities:
Current (32) (91) (1) (124)
Non-current (29) (61) (5) (95)
---------------------------------------------------------------------
Net fair value $ (19) $ 69 $ 17 $ 67
---------------------------------------------------------------------
Net notional buys (sells):
Megawatt hours of
electricity (millions) (2) (3)
Gigajoules of natural gas
(millions) 47 11
Foreign currency
(U.S. dollars) $ (431)
Range of contract 0.1 0.1 0.1
terms in years to 7.3 to 5.0 to 6.2
---------------------------------------------------------------------
---------------------------------------------------------------------
Fair values of derivative instruments are determined, when possible,
using exchange or over-the-counter price quotations by reference to
quoted bid, ask or closing market prices as appropriate, in active
markets. When there are limited observable prices due to illiquid or
inactive markets, the Company uses appropriate valuation and price
modeling techniques commonly used by market participants to estimate
fair value. The Company may also rely on price forecasts prepared by
third party market experts to estimate fair value when there are
limited observable prices available. Fair values determined using
valuation models require the use of assumptions concerning the
amounts and timing of future cash flows. Fair value amounts reflect
management's best estimates using external readily observable market
data such as future prices, interest rate yield curves, foreign
exchange rates, quoted Canadian dollar swap rate as the discount rate
for time value, and volatility when available. It is possible that
the assumptions used in establishing fair value amounts will differ
from future outcomes and the impact of such variations could be
material.
The extent to which fair values of derivative instruments are based
on observable market data is determined by the extent to which the
market for the underlying commodity is judged to be active. With
respect to natural gas, the Company has determined the market is
active to the end of the contract terms. The fair value of the
natural gas supply contracts is determined by reference to published
price quotations.
Unrealized and realized pre-tax gains and losses on derivative
instruments recognized in other comprehensive income and net income
were:
---------------------------------------------------------------------
Three months ended
September 30, 2009
-----------------------
Unrealized Realized
gains gains
(losses) (losses)
---------------------------------------------------------------------
Energy cash flow hedges $ 31 $ (22)
Energy non-hedges (4) -
Foreign exchange non-hedges 32 -
---------------------------------------------------------------------
---------------------------------------------------------------------
Realized gains and losses relate only to financial derivative
instruments. Gains and losses on non-financial derivative instruments
settlements are recorded in energy revenues or energy purchases and
fuel, as appropriate.
If hedge accounting requirements are not met, unrealized and realized
gains and losses on financial energy derivatives are recorded in
energy revenues or energy purchases and fuel, as appropriate. If
hedge accounting requirements are met, realized gains and losses on
financial energy derivatives are recorded in energy revenues or
energy purchases and fuel, as appropriate, while unrealized gains and
losses are recorded in other comprehensive income. Unrealized and
realized gains and losses on financial foreign exchange derivatives
are recorded in energy revenues or foreign exchange gains and losses
while such gains and losses on financial interest rate derivatives
are recorded in net financing expenses.
The Company has elected to apply hedge accounting on certain
derivatives it uses to manage commodity price risk relating to
electricity and natural gas prices. For the three months ended
September 30, 2009, the change in the fair value of the ineffective
portion of hedging derivatives required to be recognized in the
income statement was nil. Net losses of $14 million, net of income
taxes of $1 million, related to derivative instruments designated as
cash-flow hedges, are expected to settle and be reclassified to net
income over the next twelve months. The Company's cash flow hedges
extend up to 2016.
21. Risk management:
Risk management overview
The Company is exposed to a number of different financial risks,
arising from business activities and its use of financial
instruments, including market risk, credit risk, and liquidity risk.
The Company's overall risk management process is designed to
identify, manage and mitigate business risk which includes, among
other risks, financial risk. Risk management is overseen by the
Company's executive team according to objectives, targets, and
policies approved by the Capital Power Board of Directors. The
executive team is comprised of a senior management group including
the Senior Vice President, Strategy and Risk.
Capital Power's Senior Vice President, Strategy and Risk reports
regularly to the Board of Directors on risk management activities of
the executive team. Risk management strategies, policies, and limits
are designed to help ensure the risk exposures are managed within the
Company's business objectives and risk tolerance. The Company's
financial risk management objective is to protect and minimize
volatility in earnings and cash flow.
Commodity price risk management and the associated credit risk
management are carried out in accordance with financial risk
management policies, as approved by the executive team and the Board
of Directors. Financial risk management including foreign exchange
risk, interest rate risk, liquidity risk, and the associated credit
risk management, is carried out by a centralized Treasury function.
Capital Power's Audit Committee of the Board of Directors, in its
oversight role, monitors the assessment of risk management controls
and procedures to ensure compliance with applicable policies.
Market risk
Market risk is the risk of loss that results from changes in market
factors such as commodity prices, foreign currency exchange rates,
interest rates, and equity prices. The level of market risk to which
the Company is exposed at any point in time varies depending on
market conditions, expectations of future price or market rate
movements and the composition of the Company's financial assets and
liabilities held, non-trading physical asset and contract portfolios,
and trading portfolios.
To manage the exposure related to changes in market risk, the Company
uses various risk management techniques including derivative
instruments. Derivative instruments may include forward contracts,
fixed-for-floating swaps (or contracts-for-differences), and option
contracts. Such derivative instruments may be used to establish a
fixed price for an energy commodity, an interest-bearing obligation
or an obligation denominated in a foreign currency. Commodity market
risk exposures are monitored daily against approved risk limits, and
control processes are in place to monitor that only authorized
activities are undertaken.
The sensitivities provided in each of the following risk discussions
disclose the effect of reasonably possible changes in relevant prices
and rates on net income at the reporting date. The sensitivities are
hypothetical and should not be considered to be predictive of future
performance or indicative of earnings on these contracts. The
Company's actual exposure to market risks is constantly changing as
the Company's portfolio of debt, foreign currency and commodity
contracts changes. Changes in fair values or cash flows based on
market variable fluctuations cannot be extrapolated since the
relationship between the change in the market variable and the change
in fair value or cash flows may not be linear. In addition, the
effect of a change in a particular market variable on fair values or
cash flows is calculated without considering interrelationships
between the various market rates or mitigating actions that would be
taken by the Company.
Commodity price risk
The Company is exposed to commodity price risk as part of its normal
business operations, including energy procurement activities in
Alberta, Ontario, and the U.S. The Company's energy procurement
activities consist of power generation, non-market traded and market
traded electricity and natural gas purchase and sales contracts, and
derivative contracts. The Company is primarily exposed to changes in
the prices of electricity, and to a lesser extent is exposed to
changes in the prices of natural gas and coal. The Company actively
manages commodity price risk by optimizing its asset and contract
portfolios utilizing the following methods variously:
- The Company reduces its exposure to the volatility of commodity
prices related to electricity sales by entering into offsetting
contracts such as contracts-for-differences and firm price
physical contracts for periods of varying duration.
- The Company enters into fixed-price energy sales contracts and
power purchase arrangements which limit the exposure to
electricity prices. The Company has entered into long-term tolling
arrangements whereby variable changes linked to the price of
natural gas and coal are assumed by the counterparty.
- When it is economically feasible, the Company purchases natural
gas under long-term fixed-price supply contracts to reduce the
exposure to fluctuating natural gas prices on its natural gas-
fired generation plants and physical obligations arising from
retail customers.
- The Company enters into back-to-back electricity and natural gas
physical and financial contracts in order to lock in a margin.
The Company also engages in taking market risk positions within
authorized limits approved by Capital Power's executive team and
Board of Directors. The trading portfolio consists of electricity and
natural gas physical and financial derivative contracts which are
transacted with the intent of benefiting from short-term actual or
expected differences between their buying and selling prices or to
lock in arbitrage opportunities.
The fair value of the Company's energy related derivatives at
September 30, 2009 that are required to be measured at fair value
with the respective changes in fair value recognized in net income
are disclosed in note 20.
The Company employs specific volumetric limits and a Value-at-Risk
(VaR) methodology to manage risk exposures to commodity prices on a
consolidated basis. VaR measures the estimated potential loss in a
portfolio of positions associated with the movement of a commodity
price for a specified time or holding period and a given confidence
level. Capital Power's VaR uses a statistical confidence interval of
95% over a twenty business day holding period. This measure reflects
a 5% probability that, over the twenty day period commencing with the
point in time that the VaR is measured, the fair value of the overall
commodity portfolio could decrease by an amount in excess of the VaR
amount. The VaR methodology is a statistically-defined, probability-
based approach that takes into consideration market volatilities and
risk diversification by recognizing offsetting positions and
correlations between products and markets. This technique makes use
of historical data and makes an assessment of the market risk arising
from possible future changes in commodity prices over the holding
period.
VaR should be interpreted in light of the limitations of the
methodologies used. These limitations include the following:
- VaR calculated based on a holding period may not fully capture the
market risk of positions that cannot be liquidated or hedged
within the holding period.
- The Company computes VaR of the portfolios at the close of
business and positions may change substantially during the course
of the day.
- VaR, at a 95% confidence level, does not reflect the extent of
potential losses beyond that percentile. Losses on the other 5% of
occasions could be substantially greater than the estimated VaR.
These limitations and the nature of the VaR measurements mean that
the Company can neither guarantee that losses will not exceed the VaR
amounts or that losses in excess of the VaR amounts will not occur
more frequently than 5% of the time. As VaR is not a perfect measure
of risk, the Company applies a safety factor to the calculated VaR
amount to estimate total exposure (TE) which attempts to capture
unaccounted for exposures due to the assumptions and limitations
inherent in the calculation of VaR and to improve the confidence
level beyond 95%.
The estimation of TE takes into account positions from all wholly-
owned subsidiaries and subsidiaries in which the Company has
controlling interest, and reflects the Company's aggregate commodity
positions from its trading and asset portfolios. Capital Power's
Board of Directors has established an aggregate TE limit, under their
risk management policy, which is monitored and reported to the
executive team on a daily basis. The portfolios are stress tested
regularly to observe the effects of plausible scenarios taking into
account historical maximum volatilities and maximum observed price
movements.
Foreign exchange risk
The Company is exposed to foreign exchange risk on foreign currency
denominated forecasted transactions, firm commitments, and monetary
assets and liabilities denominated in a foreign currency and on its
net investments in foreign operations. The Company's operations
expose it to foreign exchange risk arising from transactions
denominated in foreign currencies. The Company's foreign exchange
risk arises primarily with respect to the U.S. dollar but it is
potentially exposed to changes in other currencies if and when it
transacts in other currencies. The risk is that the functional
currency value of cash flows will vary as a result of the movements
in exchange rates.
The Company's foreign exchange management policy is to attempt to
minimize economic and material transactional exposures arising from
movements in the Canadian dollar relative to the U.S. dollar or other
foreign currencies. The Company's exposure to foreign exchange risk
arises from future anticipated cash flows from its U.S. operations,
debt service obligations on U.S. dollar borrowings, and from certain
capital expenditure commitments denominated in U.S. dollars or other
foreign currencies. The Company co-ordinates and manages foreign
exchange risk centrally, by identifying opportunities for naturally-
occurring opposite movements and then dealing with any material
residual foreign exchange risks; these are hereinafter referred to as
being economically hedged.
The Company primarily uses foreign currency forward contracts to fix
the functional currency of its non-functional currency cash flows
thereby reducing its anticipated U.S. dollar denominated
transactional exposure. The Company looks to limit foreign currency
exposures as a percentage of estimated future cash flows. The
percentage amount to be fixed will generally be higher, the shorter
the period into the future that the cash flows relate to. At
September 30, 2009, US$453 million or approximately 94% of expected
future net cash flows from EPLP's U.S. plants had been economically
hedged for 2009 to 2015 at a weighted average exchange rate of $1.12
per U.S. dollar. At September 30, 2009, the Company has transactional
exposure for US$22 million or approximately 91% of expected future
net cash flows for capital expenditure commitments, which have been
economically hedged for 2009 to 2011 at a weighted average exchange
rate of $1.09 per U.S. dollar.
As at September 30, 2009, holding all other variables constant, a
$0.10 strengthening or weakening of the Canadian dollar against the
U.S. dollar would increase or decrease net income by approximately $1
million after tax. There would be no impact to other comprehensive
income.
This sensitivity analysis excludes translation risk associated with
the application of the current rate and temporal rate translation
methods, financial instruments that are non-monetary items, and
financial instruments denominated in the functional currency in which
they are transacted and measured.
Interest rate risk
The Company is exposed to changes in interest rates on its cash and
cash equivalents, and floating rate short-term and long-term loans
and obligations. The Company is exposed to interest rate risk from
the possibility that changes in the interest rates will affect future
cash flows or the fair values of its financial instruments. In some
circumstances, floating rate funding may be used for short-term
borrowings and other liquidity requirements. At September 30, 2009,
the proportion of fixed rate debt was approximately 88% of total
long-term debt outstanding. The Company may also use derivative
instruments to manage interest rate risk. At September 30, 2009, the
Company did not hold any interest rate derivative instruments.
Assuming that the amount and mix of fixed and floating rate loans and
net debt remains unchanged from that held at September 30, 2009, a
100 basis point change to interest rates would decrease or increase
full year net income by $1 million and would have no direct impact on
other comprehensive income.
The effect on net income does not consider the effect of an overall
change in economic activity that would accompany such an increase or
decrease in interest rates. There would be no impact on net income
for debt and long-term loan arrangements issued and held by the
Company at fixed interest rates.
Credit risk
Credit risk is the possible financial loss associated with the
inability of counterparties to satisfy their contractual obligations
to the Company. The Company's counterparty credit risk management
policy is established by the executive team and approved by the Board
of Directors and the associated procedures and practices are designed
to manage the credit risks associated with the various business
activities throughout the Company. Credit and counterparty risk
management procedures and practices generally include assessment of
individual counterparty creditworthiness and establishment of
exposure limits prior to entering into a transaction with the
counterparty. Exposures and concentrations are subsequently monitored
and are regularly reported to the executive team. Creditworthiness
continues to be evaluated after transactions have been initiated, at
minimum, on an annual basis. To manage and mitigate credit risk, the
Company employs various credit mitigation practices such as master
netting agreements, margining to reduce energy trading risks, credit
derivatives and other forms of credit enhancements including cash
deposits, parent company guarantees, and bank letters of credit.
Maximum credit risk exposure
The Company's maximum credit exposure was represented by the carrying
amount of the following financial assets:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Cash and cash equivalents $ 64
Accounts receivable(1) 248
Derivative instruments assets(1) 286
Loans and other long-term receivables 49
Net investments in leases 28
Loan commitments to third parties 6
---------------------------------------------------------------------
$ 681
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The Company's maximum exposures related to accounts receivable
and derivative instruments assets by major credit concentration
are comprised of maximum exposures of $170 million for generation
and $364 million for wholesale.
This table does not take into account collateral held. At September
30, 2009, the Company held cash deposits of $2 million as security
for certain counterparty accounts receivable and derivative
contracts. The Company is not permitted to sell or re-pledge this
collateral in the absence of default of the counterparties providing
the collateral. At September 30, 2009, the Company also held other
forms of credit enhancement in the form of letters of credit of $25
million and parental guarantees of $723 million.
Credit quality and concentrations
The Company is exposed to credit risk on outstanding accounts
receivable associated with its generation and energy sales activities
including power purchase arrangements and agreements with independent
system operators, power and steam sales contracts and on energy
supply agreements with government sponsored entities and wholesale
customers. The Company is also exposed to credit risk from its cash
and cash equivalents (including short-term investments), financial
and non-financial derivative instruments, and long-term financing
arrangements.
The credit quality of the Company's accounts receivable, by major
credit concentrations, and other financial assets are the following:
---------------------------------------------------------------------
September 30, 2009
-----------------------
Investment Non-
grade(1) or investment
secured(3) grade(1)
---------------------------------------------------------------------
Accounts receivable and financial derivative
instruments
Generation 100% -
Wholesale(2) 90% 10%
Cash and cash equivalents 100% -
Loans and other long-term receivables 100% -
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Credit ratings are based on the Company's internal criteria and
analyses which take into account, among other factors, the
investment grade ratings of external credit rating agencies when
available.
(2) Includes industrial end-use customers, trading and position
management counterparties.
(3) Certain accounts receivable and other financial assets are
considered to have low credit risk as they are either secured by
the underlying assets, secured by other forms of credit
enhancements, or the counterparties are local or provincial
governments.
Generation credit risk
Credit risk exposure from power purchase arrangements, agreements
with independent system operators, power and steam sales contracts,
and certain energy supply agreements is predominantly restricted to
accounts receivables and contract default. In certain cases, the
Company relies on a single or small number of customers to purchase
all or a significant portion of a facility's output. The failure of
any one of these counterparties to fulfill its contractual
obligations could negatively impact the Company's financial results.
Financial loss resulting from events of default by counterparties in
certain power purchase arrangements and steam purchase agreements may
not be recovered since the contracts may not be replaceable on
similar terms under current market conditions. Consequently, the
Company's financial performance depends on the continued performance
by customers and suppliers of their obligations under these long-term
agreements. Credit risk exposure is mitigated by dealing with
creditworthy counterparties, netting amounts by legally enforceable
set-off rights, and, when appropriate, taking back security from the
counterparty. Credit risk with government-owned or sponsored entities
and regulated public utility distributors is generally considered
low.
Wholesale and merchant credit risk
Credit risk exposure for wholesale and merchant trading
counterparties is measured by calculating the costs (or proceeds) of
replacing the commodity position (physical and derivative contracts),
adjusting for settlement amounts due to or due from the counterparty
and, if permitted, netting amounts by legally enforceable set-off
rights. Financial loss on wholesale contracts could include, but is
not limited to, the cost of replacing the obligation, amounts owing
from the counterparty or any loss incurred on liability settlements.
Credit risk exposure is mitigated by dealing with creditworthy
counterparties, monitoring credit exposure limits, margining to
reduce energy trading risks, parent company guarantees, and when
appropriate taking back security from the counterparty.
Accounts receivable and allowance for doubtful accounts
Accounts receivable consist primarily of amounts due from customers
including industrial and commercial customers, independent system
operators from various regions, government-owned or sponsored
entities, and other counterparties. Larger commercial and industrial
customer contracts and contracts-for-differences provide for
performance assurances including letters of credit. The Company also
has credit exposures to large suppliers of electricity and natural
gas. The Company mitigates these exposures by dealing with
creditworthy counterparties and, when appropriate, taking back
appropriate security from the supplier.
The aging of accounts receivable was:
---------------------------------------------------------------------
September 30, 2009
------------------------------------
Allowance
Gross for Net
accounts doubtful accounts
receivable accounts receivable
---------------------------------------------------------------------
Current(1) $ 249 $ 1 $ 248
Outstanding 30 to 60 days 1 1 -
---------------------------------------------------------------------
Total $ 250 $ 2 $ 248
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Current amounts represent accounts receivable outstanding zero to
30 days. Amounts outstanding more than 30 days are considered
past due.
In conjunction with the acquisition of assets described in note 3,
the Company has assumed allowances for doubtful accounts of $2
million, which is the balance included in accounts receivable as at
September 30, 2009. The Company has also assumed allowances for
doubtful accounts of $2 million relating to long-term receivables
which are recorded against the long-term receivable balance in other
assets at September 30, 2009.
At September 30, 2009, the Company held $2 million of customer
deposits for the purpose of mitigating the credit risk associated
with accounts receivable from customers.
At September 30, 2009, there was no provision for credit losses
associated with accounts receivable from treasury, trading and energy
procurement counterparties as all balances are considered to be fully
collectable.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet
its financial obligations as they become due. The Company's liquidity
is managed centrally by the Treasury function. The Company manages
liquidity risk through regular monitoring of cash and currency
requirements by preparing short-term and long-term cash flow
forecasts and also by matching the maturity profiles of financial
assets and liabilities to identify financing requirements. The
financing requirements are addressed through a combination of
committed and demand revolving credit facilities, financings in
public capital debt markets and equity offerings by the Company or
its CPLP or EPLP subsidiaries.
CPLP has a long-term debt rating of BBB, assigned by both Standard
and Poor's (S&P) and DBRS Limited (DBRS). EPLP has a long-term debt
rating of BBB+ and BBB(high), assigned by S&P and DBRS respectively.
As at September 30, 2009, the Company had undrawn and committed bank
credit facilities, including operating lines of credit, of $1,282
million, of which $723 million is committed for at least two years.
In addition, EPLP has a Canadian shelf prospectus under which it may
raise up to $1 billion in partnership units or debt securities, of
which a maximum of $600 million can be medium-term notes. The
Canadian shelf prospectus expires August 2010. As at September 30,
2009, EPLP has not drawn on the shelf prospectus.
The following are the undiscounted cash flow requirements and
contractual maturities of the Company's financial liabilities,
including interest payments, as at September 30, 2009:
-------------------------------------------------------------------------
Total
Due in Due in contr-
------------------------------ 2014 actual
Due in and cash
2009 2010 2011 2012 2013 beyond flows
-------------------------------------------------------------------------
Non-derivative
financial
liabilities:
Long-term debt $ 1 $ 247 $ 376 $ 104 $ 313 $ 738 $1,779
Interest payments
on long-term debt 28 95 84 67 65 446 785
Accounts payable
and accrued
liabilities(1) 267 - - - - - 267
Other current
liabilities 9 - - - - - 9
Loan commitments 6 - - - - - 6
Derivative financial
liabilities:
Net forward foreign
exchange contracts - 2 1 1 1 2 7
Net commodity
contracts-for-
differences 38 67 41 4 - - 150
-------------------------------------------------------------------------
Total $ 349 $ 411 $ 502 $ 176 $ 379 $1,186 $3,003
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excluding accrued interest on long-term debt of $8 million.
22. Capital management:
The Company's primary objectives when managing capital are to
safeguard the Company's ability to continue as a going concern, pay
dividends to its shareholders in accordance with the Company's
dividend policy, maintain a suitable credit rating, and to facilitate
the acquisition or development of projects in Canada and the U.S.
consistent with the growth strategy of the Company. The Company
manages its capital structure in a manner consistent with the risk
characteristics of the underlying assets.
The Company manages capital through regular monitoring of cash and
currency requirements by preparing short-term and long-term cash flow
forecasts and reviewing monthly financial results. The Company
matches the maturity profiles of financial assets and liabilities to
identify financing requirements to help ensure an adequate amount of
liquidity.
The Company considers its capital structure to consist of short-term
debt and long-term debt net of cash and cash equivalents, non-
controlling interests (including preferred shares issued by
subsidiary companies) and shareholder's equity. The following table
represents the total capital of the Company:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Long-term debt (including current portion) (note 10) $1,771
Cash and cash equivalents (64)
---------------------------------------------------------------------
Net debt 1,707
---------------------------------------------------------------------
Non-controlling interests (note 13) 1,975
Shareholders' equity 494
---------------------------------------------------------------------
Total equity 2,469
---------------------------------------------------------------------
Total capital $4,176
---------------------------------------------------------------------
---------------------------------------------------------------------
The Company has no externally imposed requirements on its capital
except as disclosed below.
CPLP has the following externally imposed requirements on its capital
as a result of its credit facilities and certain debt covenants:
- Maintenance of modified consolidated net tangible assets to
consolidated net tangible assets ratio, as defined in the debt
agreements, of not less than 0.90 to 1.0;
- Maintenance of senior debt to consolidated capitalization ratio,
as defined in the debt agreements, of not more than 0.65 to 1.0;
- Limitation on debt issued by subsidiaries; and
- In the event that CPLP is assigned a rating of less than BBB- by
S&P and BBB(Low) by DBRS, CPLP would also be required to maintain
a ratio of earnings before interest, income taxes, depreciation
and amortization to interest expense, as defined in the debt
agreements, of not less than 2.5 to 1.0.
EPLP has the following externally imposed requirements on its
capital:
- Maintenance of debt to total capitalization ratio, as defined in
the debt agreements, of not more than 65%; and
- In the event that EPLP is assigned a rating of less than BBB+ by
S&P and BBB(high) by DBRS, EPLP also would be required to maintain
a ratio of earnings before interest, income taxes, depreciation
and amortization to interest expense of not less than 2.5 to 1.
These capital restrictions are defined in accordance with the
respective agreements.
For the period ended September 30, 2009, CPLP and EPLP complied with
all externally imposed capital restrictions.
To manage or adjust its capital structure, the Company can issue new
debt, issue common or preferred shares, redeem preferred shares,
issue new CPLP or EPLP units, repay existing debt or adjust dividends
paid to its shareholders.
23. Related party balances and transactions:
The following summarizes the Company's related party balances and
transactions with EPCOR and its subsidiaries. All transactions are in
the normal course of operations, and are recorded at the exchange
amount, which is the consideration established and agreed to by the
parties.
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Balance sheet:
Accounts receivable (a) $ 60
Other assets (b) 7
Property, plant and equipment (c) 9
Accounts payable - accrued interest
on debt 12
Long-term debt (including current
portion) (note 10) 876
Share capital (note 14) -
Income statement:
Revenues - energy sales 103
Energy purchases and fuel (d) 6
Net financing expenses (e) 6
---------------------------------------------------------------------
(a) Accounts receivable includes $30 million relating to energy
sales to subsidiaries of EPCOR and $30 million of amounts owed
from EPCOR relating to operational cash transactions during the
acquisition changeover period.
(b) Contributions made to subsidiaries of EPCOR for the construction
of aerial and underground transmission lines.
(c) Interest on long-term debt to EPCOR capitalized to property,
plant and equipment.
(d) Includes energy distribution and transmission charges from
subsidiaries of EPCOR.
(e) Net financing expenses on long-term debt to EPCOR.
24. Joint ventures:
The Company and the coal mine operator at the Genesee plant site each
have a 50% interest in the Genesee Coal Mine Joint Venture. The joint
venture partner operates the coal mine. Under agreements governing
this joint venture, all coal mined is to be supplied to the Company's
Genesee generation plant.
The Company holds 50% interests in the Genesee 3 Project, the
Keephills 3 Project and the Taylor's Coulee Chute Hydro Project, and
holds a 40% interest in the Joffre Cogeneration Project. The Company,
through its EPLP subsidiary, also holds a 50.15% interest in the
Frederickson power plant.
A financial summary of the Company's investments in joint ventures is
as follows:
---------------------------------------------------------------------
September 30,
2009
---------------------------------------------------------------------
Current assets $ 43
Long-term assets 1,061
Current liabilities 56
Long-term liabilities 41
Revenues(1) 16
Expenses(2) 19
Net loss (3)
Cash flows from operating activities (1)
Cash flows used in investing activities (79)
Cash flows from financing activities 66
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(1) Excludes all revenues from Genesee 3, which are recorded as
revenues by the Company but are not subject to the terms of the
joint venture agreement.
(2) Excludes all costs of operating the Genesee Coal Mine Joint
Venture which are recorded as fuel expenses by the Company.
Included in the Company's cash and cash equivalents at September 30,
2009 is its proportionate share of cash and cash equivalents which is
restricted to use within joint ventures of $26 million.
Under the terms of the Company's interests in the Frederickson power
plant, the Genesee 3 Project and the Keephills 3 Project, the Company
and its respective partners have guaranteed financial and performance
obligations under the joint venture agreements limited to $40
million, $50 million and $50 million respectively.
25. Employee future benefits:
Multiemployer defined benefit pension plan and defined contribution
pension plan
Over 85% of the Company's employees are either members of the Local
Authority Pension Plan or the Company's registered defined
contribution plans. Accordingly, the majority of the Company's
pension costs and obligations are accounted for as defined
contribution plans.
Defined benefit plans
Prior to the transfer of employees resulting from the acquisition
described in note 3, the effective date for the latest actuarial
valuations of both the Company's registered and supplemental pension
plans was December 31, 2007. The effective date of the next valuation
for funding purposes is no later than December 31, 2010 for both
plans. The plan assets and the accrued benefit obligation have been
estimated as at September 30, 2009. The supplemental pension plan is
a non-contributory plan that is unfunded at September 30, 2009.
As part of the Company's acquisition of its interest in EPLP from
EPCOR, employees who transferred to Capital Power on July 1, 2009
became members of the Company's registered pension plan. The plan
provides pension benefits based on an employee's years of service and
their highest earnings over three consecutive years of employment.
Retirement pensions will be increased annually by a portion of the
increase in the Consumer Price Index. Prior to the Company's
acquisition of its interest in EPLP, EPCOR had previously acquired
the interest in EPLP from a third party. Under the terms of EPCOR's
previous purchase and sale agreement, the previous plan sponsor
transferred the pension liabilities for the Canadian employees and
associated assets based on an actuarial valuation. At September 30,
2009, the actual transfer of assets has not yet occurred as
regulatory approval required for transfer of the assets and
obligations is still outstanding.
Plan benefit costs, assets and obligations
The accrued benefit liability and other employee future benefit
liabilities, totalling $11 million and assumed as part of the
acquisition described in note 3 are included in other non-current
liabilities. Other employee future benefit liabilities consist mainly
of obligations for benefits provided to employees on long-term
disability leaves.
The market value of the defined benefit plan assets at September 30,
2009 was approximately $10 million.
Total cash payments for pension benefits in the three months ended
September 30, 2009, consisting of cash contributed by the Company to
the LAPP, other defined contribution and benefit plans and cash
payments directly to beneficiaries for its unfunded pension plan,
were $2 million.
26. Plants under operating leases:
Certain power generation plants operate under PPAs that convey the
right to the holder of the agreement to use the related property,
plant and equipment. Consequently, these power generation plants,
comprised of ManChief, Mamquam, Queen Charlotte, Southport, Roxboro,
Kenilworth, Greeley, Williams Lake, Genesee units 1 and 2, Miller
Creek and Brown Lake are accounted for as assets under operating
leases. As at September 30, 2009, the carrying amount of such
property, plant and equipment was $1,314 million, less accumulated
depreciation of $12 million. The Company's revenue pursuant to the
arrangements for the three months ended September 30, 2009 was
$106 million.
27. Contingencies and commitments:
(a) The Company has committed to purchase new high efficiency gas-
fired electric generating units for its Clover Bar Energy Centre.
As at September 30, 2009, the estimated remaining total cost to
be incurred is $30 million.
(b) The Company and TransAlta Corporation (TransAlta) are in the
process of building Keephills 3, a 495 megawatt (MW)
supercritical coal-fired generation plant at TransAlta's
Keephills site. The construction is expected to be completed in
2011. As at September 30, 2009, the Company's 50% committed share
of the estimated total remaining capital cost to be incurred is
$287 million. As of October 30, 2009, the Board of Directors of
CPC and TransAlta had approved additional funding and a revised
schedule for the Keephills 3 project. The total project cost was
revised from $1.8 billion to $1.9 billion and Capital Power's
share was correspondingly revised from $903 million to $955
million resulting in an additional $52 million of costs expected
to be incurred by the Company. As part of contractual
arrangements, the Company and TransAlta have indemnified each
other for up to $115 million during construction in the event
that either party makes payments to the turbine supplier on
behalf of the other party.
(c) EPLP has committed to the enhancement of the Southport and
Roxboro facilities through 2009. As at September 30, 2009, the
Company expects an additional $33 million (US$31 million) to be
spent on the enhancement work. EPLP has committed to the upgrade
of the gas turbine at the Oxnard facility, to be spent over the
remaining months of 2009 and 2010. As at September 30, 2009, the
Company expects an additional $17 million (US$16 million) to be
spent on the upgrade of the Oxnard turbine.
(d) Under the terms of the acquired Alberta PPAs, the Company is
obligated to make monthly payments for fixed and variable costs.
The estimated annual total of these payments for the remainder of
2009 is $31 million. The actual amounts for the remainder of 2009
and future years may vary from estimates depending on generation
volume and scheduled outages. It is expected that the annual
payments over the remaining terms of the Alberta PPAs, as
described in note 2(k), will range from $89 million to $182
million, adjusted for inflation, other than in the event of a
forced outage.
(e) The Company has entered into a number of long-term energy
purchase and transportation contracts and operating and
maintenance contracts in the normal course of operations. Some of
these energy purchase and transportation contracts are measured
at their fair value and recorded on the consolidated balance
sheet as derivative instruments assets and liabilities as
appropriate. The energy purchase and transportation contract
amounts disclosed below are based on gross settlement amounts.
Approximate future payments under these contracts and under
operating leases for premises are as follows:
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Energy Operating
purchase and and main-
transportation tenance Operating
contracts contracts leases
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Fourth quarter of 2009 $ 56 $ 7 $ -
2010 113 28 2
2011 93 28 1
2012 78 28 4
2013 64 29 4
Thereafter 205 126 70
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Total $ 609 $ 246 $ 81
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(f) The Company has committed to issue non-interest bearing notes
receivable to the non-Capital Power syndicate members involved in
the Sundance Swap transaction entered into by Capital Power
subsidiaries prior to the acquisition of subsidiaries and assets
from EPCOR as disclosed in note 3. The commitment relates to
funding potential income tax liabilities incurred by the non-
Capital Power syndicate members in relation to the transaction.
The total estimated loan commitment is $19 million, with annual
payments of principal commencing from the date the commitment is
called by the non-Capital Power syndicate members through to
December 2012. At September 30, 2009, the Company has $13 million
extended under such notes and their carrying amount of $8
million, after fair value adjustments, is included in other
assets.
(g) On June 11, 2009, a Statement of Claim was filed against The City
of Edmonton, the Mayor and Councilors of The City of Edmonton,
EPCOR, EPCOR Power L.P.'s General Partner, EPCOR Power L.P. and
Capital Power (the Co-defendants). The claim alleged, among other
things, that The City of Edmonton acted beyond its power and
contrary to the Municipal Government Act (Alberta) and did not
observe an appropriate public process in connection with the
initial public offering involving Capital Power. Based on its
review of the available information, Capital Power believes that
the claim is without merit and intends to vigorously defend
itself. On June 26, 2009, Capital Power filed a Statement of
Defence denying all of the allegations contained in the Statement
of Claim. On July 3, 2009, the Alberta Court of Queen's Bench
denied an application for an interim injunction to delay the
closing of the Capital Power initial public offering and its
acquisition of EPCOR's power generation business. The court was
not satisfied that there was any real merit to the application.
The Co-defendants have now applied to the Alberta Court of
Queen's Bench for summary dismissal of this action against them.
On June 30, 2009, an Originating Notice was filed in the Court of
the Queen's Bench of Alberta, Judicial District of Edmonton, by
the Alberta Federation of Labour, the Canadian Union of Public
Employees, Local 30, and the Civic Service Union 52. The Notice
named The City of Edmonton, EPCOR Utilities Inc. and Capital
Power Corporation as Respondents and requested that the
transaction pursuant to which the power generation assets
previously owned by EPCOR were transferred to Capital Power be
overturned on the basis that certain purported actions taken by
The City of Edmonton in connection with the initial public
offering were allegedly outside the jurisdiction of the
municipality under the Municipal Government Act. On September 25,
2009, the Alberta Court of Queen's Bench denied the application.
(h) The Company and its subsidiaries are subject to various other
legal claims that arise in the normal course of business.
Management believes that the aggregate contingent liability of
the Company arising from these claims is immaterial and therefore
no provision has been made.
28. Guarantees:
The Company has issued letters of credit for $90 million to meet the
credit requirements of energy market participants, to meet conditions
of certain service agreements, and to satisfy legislated reclamation
requirements.
Prior to the acquisition of subsidiaries and assets from EPCOR
disclosed in note 3, EPCOR issued parental guarantees on behalf of
former EPCOR subsidiaries to meet the credit requirements of energy
market participants, to meet conditions of certain service
agreements, and to satisfy legislated reclamation requirements. At
September 30, 2009, EPCOR continues to have outstanding parental
guarantees on behalf of Capital Power totaling $1,315 million related
to subsidiaries of Capital Power. In addition to this amount, EPCOR
also has outstanding parental guarantees which do not have a defined
limit, but which provide full support on any outstanding positions
related to power purchase arrangements of Capital Power. The Company
is working on transferring these parental guarantees over from EPCOR.
29. Geographic information:
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Three months ended September 30, 2009
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Inter-area
elimi-
Canada U.S. nations Total
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Revenues - external $ 433 $ 92 $ - $ 525
Inter-area revenues 5 1 (6) -
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Total revenues $ 438 $ 93 $ (6) $ 525
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Property, plant and
equipment $2,719 $ 480 $ - $3,199
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Goodwill $ 95 $ 24 $ - $ 119
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Inter-area transactions occur in the normal course of operations and
are recorded at the exchange amount which is the consideration
established and agreed to by the parties.
30. Assets held for sale:
The Company's interest in the Battle River PSA will be disposed of on
January 15, 2010. Since the final disposal will occur within one year
of the balance sheet date, the remaining Battle River PSA assets on
the consolidated balance sheet have been reclassified from power
purchase arrangements to assets held for sale.
31. Subsequent events:
(a) On October 14, 2009, the Company announced it will be partnering
with two third parties to develop what will be one of the world's
largest Carbon Capture and Storage (CCS) projects, Project
Pioneer (Pioneer). A letter of intent has been signed with the
Province of Alberta, under which Pioneer will be eligible to
receive funding from the province's $2 billion CCS fund. The
Government of Canada is also contributing toward the project
through its Clean Energy Fund. Pioneer entails the development of
a CCS facility at the Keephills 3 power plant, currently under
construction west of Edmonton. Pioneer will be designed to
capture one million tonnes of greenhouse gas emissions annually.
The development of Pioneer will not affect the construction
schedule for Keephills 3, which is expected to enter commercial
operation in early 2011.
(b) On October 13, 2009, a subsidiary of the Company, EPLP, announced
a change in the frequency of its distributions to monthly from
quarterly. Cash distributions of EPLP for periods commencing
after September 30, 2009 will be made in respect of each calendar
month instead of the quarters ending March, June, September and
December of each year. EPLP also announced the launch of a
Premium Distribution(TM) and Distribution Reinvestment Plan (the
"Plan") that provides eligible unitholders with two alternatives
to receiving the monthly cash distributions, including the option
to accumulate additional units in EPLP by reinvesting cash
distributions in additional units issued at a 5% discount to the
Average Market Price of such units (as defined in the Plan) on
the applicable distribution payment date. Under the Premium
Distribution(TM) component of the Plan, eligible unitholders may
elect to exchange these additional units for a cash payment equal
to 102% of the regular cash distribution on the applicable
distribution payment date.
(c) On October 13, 2009, a subsidiary of the Company entered into a
bought deal for the issuance of 4,000,000 7.0% Cumulative Rate
Reset Preferred Shares, Series 2 (the "Series 2 Shares") at a
price of $25.00 per share, for aggregate gross proceeds of $100
million (the "Offering"). The Series 2 Shares will pay fixed
cumulative dividends of $1.75 per share per annum, as and when
declared, for the initial five-year period ending December 14,
2014. The dividend rate will reset on December 31, 2014 and every
five years thereafter at a rate equal to the sum of the then
five-year Government of Canada bond yield and 4.18%. The Series 2
Shares are redeemable at $25.00 per share by the Corporation on
December 31, 2014 and on December 31 every five years thereafter.
The holders of the Series 2 Shares will have the right to convert
their shares into Cumulative Floating Rate Preferred Shares,
Series 3 (the "Series 3 Shares") of the Corporation, subject to
certain conditions, on December 31, 2014 and on December 31 of
every fifth year thereafter. The holders of Series 3 Shares will
be entitled to receive quarterly floating rate cumulative
dividends, as and when declared by the board of directors of the
Corporation, at a rate equal to the sum of the then 90-day
Government of Canada treasury bill rate and 4.18%. The offering
is expected to close on or about November 2, 2009, subject to
certain conditions. The net proceeds will be used to repay
outstanding bank indebtedness.
For further information: Media Relations: Mike Long, (780) 392-5207, [email protected]; Investor Relations: Randy Mah, (780) 392-5305 or (866) 896-4636 (toll-free), [email protected]
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