CPN Calpine Corp.

Calpine Corporation (NYSE:CPN) today reported Adjusted EBITDA of $1,374 million for the nine months ended September 30, 2009, which matched the results reported for the same period of 2008 despite generally weaker market conditions. Commodity Margin for the first nine months of 2009 was $1,947 million, down slightly from $1,988 million in the prior year period. Meanwhile, the company also reported strong 2009 nine-month Adjusted Free Cash Flow of $520 million. Net income1 during the nine months ended September 30, 2009, was $192 million, or $0.39 per diluted share, compared to net income of $119 million, or $0.25 per diluted share, in 2008.

“Our performance this quarter demonstrates our strong and continuing commitment to operating excellence, a hedging strategy that mitigates market price risk in a difficult economic environment, a customer-focused approach to our business, the opportunistic restacking of our debt, and our organic growth strategy,” said Jack Fusco, Calpine’s President and Chief Executive Officer. “This combination of achievements, in addition to our solid year over year financial performance, shows that the building blocks of a strong foundation are in place and we are well-positioned for the future.”

“Operationally, we improved availability across the fleet, and our capacity factor was up significantly during the quarter, while our adjusted EBITDA and other results show that our hedging program worked well,” said Fusco. “On the business development front, we announced today significant new and restructured contracts with key customers and previously announced the successful commissioning of Otay Mesa, both of which speak to our commitment to delivering clean, reliable energy to the markets we serve. Financially, we demonstrated progress and an ability to access capital markets on favorable terms with a unique and successful exchange of $1.2 billion of term loans for bonds, which pushed out our maturities and improved our covenant terms to provide future flexibility. Finally, in addition to implementing our turbine blades upgrade program, we also have announced the upgrade of Los Esteros that will add 120 MW and improve the operating efficiency of the plant.”

SUMMARY OF FINANCIAL PERFORMANCE

Third Quarter Results

Adjusted EBITDA for the third quarter of 2009 was $586 million, down modestly from $594 million in the prior year period. The year-over-year decline was primarily due to a $32 million decrease in Commodity Margin from $800 million in 2008 to $768 million in 2009, offset by cost reduction efforts that are further described below. Though Commodity Margin in our West region improved by $21 million in the third quarter of 2009 compared to 2008, primarily due to higher hedge prices and higher market heat rates, this performance was offset by a decline of $46 million in our Texas segment that was largely driven by weaker spark spreads and reduced steam sales.

Adjusted EBITDA was favorably impacted by controllable expenses2 as a component of plant operating expense, which declined by $19 million in the 2009 period, after excluding $15 million in reimbursements for insurance claims from prior periods that reduced expenses in the 2008 period, and by controllable expenses2 as a component of sales, general and administrative expense, which declined by $14 million. These savings reflect the results of the efficiency initiatives that management has instituted over the past year.

Net income1 increased to $238 million in the third quarter of 2009 from $136 million in the third quarter of 2008. As detailed in Table 1 below, net income, excluding reorganization items, one-time items and unrealized mark-to-market gains or losses, declined from $279 million in the third quarter of 2008 to $196 million in the third quarter of 2009. This decline was primarily associated with the $32 million year-over-year decrease in Commodity Margin, as previously noted, as well as a $73 million increase in income tax expense during the 2009 period due to non-cash intraperiod tax allocations that reduced significantly from 2008 to 2009. These factors were partially offset by a $33 million aggregate decrease in controllable expenses2 as a component of plant operating expense and sales, general and administrative expense, after adjusting for insurance reimbursements, as previously discussed.

Year-to-Date Results

Unchanged from the prior year period, Adjusted EBITDA for the nine months ended September 30, 2009, was $1,374 million. Adjusted EBITDA remained stable despite a $41 million decrease in Commodity Margin. Increased Commodity Margin in our West and Southeast regions, which improved by $29 million and $25 million, respectively, in the 2009 period, was offset by a decline of $82 million in our Texas region. The West segment benefited in 2009 from higher hedge levels, higher average hedge prices and the sale of surplus emission allowances, while the Southeast benefited from higher hedge levels, higher average hedge prices and higher market heat rates related to our open positions. The decline in Texas was due in large part to weaker natural gas prices and weaker market heat rates.

In the 2009 period, we reduced controllable expenses2 as a component of plant operating expense by $27 million, after excluding $30 million in reimbursements for insurance claims from prior periods that reduced expenses in the 2008 period. We further reduced controllable expenses2 as a component of sales, general and administrative expense by $23 million in the same period. Adjusted EBITDA from unconsolidated investments increased by $19 million year-to-date in 2009 compared to the corresponding 2008 period, primarily as a result of the Greenfield Energy Centre achieving commercial operations in the fourth quarter of 2008. Royalty expenses also decreased by $10 million year-over-year as a result of lower average power prices at The Geysers during the 2009 period.

Net income1 increased to $192 million in the nine months ended September 30, 2009, from $119 million in the prior year period. As detailed in Table 1 below, net income, excluding reorganization items, one-time items and unrealized mark-to-market gains or losses, decreased from $239 million in the first nine months of 2008 to $153 million in 2009. The decline is primarily attributable to the $41 million decrease in Commodity Margin as well as a $77 million increase in income tax expense associated with the non-cash intraperiod tax allocations previously mentioned. Meanwhile, aggregate controllable expenses2 as a component of plant operating expense and sales, general and administrative expense decreased by $50 million, after adjusting for $30 million in insurance reimbursements, as previously discussed. In addition, income from unconsolidated investments in power plants increased by $37 million (excluding an impairment loss of $179 million in 2008).

Cash flows provided by operating activities for the nine months ended September 30, 2009, improved to $537 million compared to $355 million for the nine months ended September 30, 2008. Cash paid for interest decreased by $310 million, to $563 million for the nine months ended September 30, 2009, as compared to $873 million for the same period in 2008, primarily due to the repayment of the Second Priority Debt, the one time payments of post-petition interest of $135 million related to pre-emergence debt and $27 million in post-petition interest paid by our Canadian subsidiaries as a result of our emergence from Chapter 11 on January 31, 2008, and, to a lesser extent, lower interest rates for the comparable period in 2009. In addition, cash payments for reorganization items decreased by $119 million. Meanwhile, working capital employed increased by approximately $202 million for the 2009 period compared to the 2008 period, after adjusting for debt-related balances and derivative activities, which did not impact cash provided by operating activities. The increase was primarily due to a reduction in assets held for sale for the nine months ended September 30, 2008. Finally, cash payments for debt extinguishment costs in the 2009 period were $40 million related to the CCFC Refinancing, compared to cash payments of $6 million related to the refinancing of Blue Spruce and Metcalf for the comparable period in 2008.

1 Reported as net income attributable to Calpine on our Consolidated Condensed Statements of Operations.

2 Controllable expenses include variable and fixed expenses, but exclude major maintenance expense, stock compensation expense, non-cash gains/losses on dispositions of assets, and depreciation and amortization.

Table 1: Summarized Consolidated Condensed Statements of Operations

    (Unaudited) Three Months Ended September 30, Nine Months Ended September 30, 2009 2008 2009 2008 (in millions) Operating revenues $ 1,847 $ 3,190 $ 4,995 $ 7,969 Cost of revenue   1,354   2,656   4,014   6,988 Gross profit 493 534 981 981

SG&A, (income) loss from unconsolidated investments in

power plants and other operating expense

  56   262   118   358 Income from operations 437 272 863 623 Net interest expense, debt extinguishment costs and other (income) expense   215   219   659   828 Income (loss) before reorganization items and income taxes 222 53 204 (205 ) Reorganization items (8 ) (2 ) (2 ) (263 ) Income tax expense (benefit)   (7 )   (80 )   17   (60 ) Net income $ 237 $ 135 $ 189 $ 118   Net loss attributable to the noncontrolling interest   1   1   3   1 Net income attributable to Calpine $ 238 $ 136 $ 192 $ 119   Reorganization items(1) (8 ) (2 ) (2 ) (263 ) Other one-time items(1)(2)   10   192   30   367 Net income (loss), net of reorganization items and other one-time items 240 326 220 223 Unrealized MtM (gains) losses on derivatives(1)(3)   (44 )   (47 )   (67 )   16 Net income, net of reorganization items other one-time items and unrealized MtM impacts $ 196 $ 279 $ 153 $ 239  

(1) Shown net of tax, assuming a 0% effective tax rate for these items (other than those referenced in note 2 below).

(2) One-time items in the three and nine months ended September 30, 2009, include $16 million and $49 million, respectively, in debt extinguishment costs, shown net of tax assuming a 38.4% effective tax rate. One-time items in both the three and nine months ended September 30, 2008, include an impairment loss of $179 million associated with our Auburndale plant and $13 million in settlement costs. One-time items in the nine months ended September 30, 2008, also include $13 million in debt extinguishment costs, as well as $135 million in post-petition interest expense and $27 million in settlement obligations related to the Canadian debtors and other deconsolidated foreign entities recorded prior to their reconsolidation in February 2008, both of which were associated with our emergence from bankruptcy.

(3) Represents unrealized mark-to-market (MtM) (gains) losses on contracts that did not qualify as hedges under the hedge accounting guidelines or qualified under the hedge accounting guidelines and the hedge accounting designation had not been elected.

REGIONAL SEGMENT REVIEW OF RESULTS

   

 

Table 2: Commodity Margin by Segment (in millions)

  Three Months Ended September 30, Nine Months Ended September 30, 2009   2008(1) 2009   2008(1)   West $ 393 $ 372 $ 994 $ 965 Texas 187 233 505 587 Southeast 92 95 233 208 North   96   100   215   228 Total $ 768 $ 800 $ 1,947 $ 1,988  

(1) 2008 Commodity Margin as previously reported has been recast to conform to our current year presentation.

West: Despite on-peak spark spreads in California settling substantially lower for the three months ended September 30, 2009, compared to the same period in 2008, Commodity Margin in our West region increased in the third quarter of 2009 primarily as a result of higher hedge prices and, although spark spreads were lower overall, the higher market heat rate component of spark spread where we had hedged the corresponding open natural gas position. The higher market heat rates were primarily in the Pacific Northwest region, which experienced high market generation outages and warmer weather. In addition, the current period benefited from the non-recurrence in 2009 of an unfavorable natural gas storage inventory pricing adjustment in September 2008.

For the nine month period, Commodity Margin in the West improved by $29 million in 2009. Although spark spreads for the nine month period settled substantially lower in 2009 than in 2008, primarily as a result of lower natural gas prices combined with weak power demand and conservative ISO operations during the launch of MRTU in 2009, Commodity Margin in the West improved primarily as a result of higher hedge levels, higher average hedge prices, sales of surplus emission allowances in the first quarter of 2009 and the non-recurrence in 2009 of an unfavorable natural gas storage inventory price adjustment in September 2008.

Texas: During the third quarter of 2009, Commodity Margin for the Texas region declined from $233 million in the prior year period to $187 million in 2009. This $46 million decrease primarily resulted from weaker spark spreads, caused by lower natural gas prices, which declined 64% in the third quarter of 2009 compared to 2008. The decrease in Commodity Margin was also attributable to reduced steam sales and a relative period on period decline in the optimization margin that benefited us during Hurricane Ike in September 2008 when it was more advantageous to buy as opposed to generate power to cover our hedges given the extremely low power prices. The adverse impact of the lower spark spreads in 2009 was partially offset by an increase in market heat rates and higher average fleet availability.

Commodity Margin in our Texas region declined from $587 million for the nine months ended September 30, 2008, to $505 million for the 2009 period. This decrease is primarily attributable to weaker natural gas prices, a decline in market heat rates and lower steam sales resulting from weaker industrial demand.

Southeast: Commodity Margin in our Southeast segment decreased by $3 million during the third quarter of 2009, driven by lower on-peak spark spreads related to open positions in the third quarter of 2009 compared to the same period in 2008, which was largely offset by the positive impact of higher hedge volumes and hedge prices, as well as a new tolling contract, for the three months ended September 30, 2009, compared to 2008. Generated volumes increased 60% for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to significantly higher off-peak dispatch in response to higher off-peak spark spreads; however, the extra generation in the third quarter of 2009 provided relatively less incremental Commodity Margin than in prior quarters due to the lower off-peak margin and the fact that many of our power plants in the Southeast have tolling contracts. The strength in off-peak spark spreads was attributed to higher natural gas generation displacement of coal generation in certain sub-markets in our Southeast segment, as well as the favorable impact of an off-take agreement at one of our power plants.

For the nine month period, Commodity Margin in the Southeast improved by $25 million in 2009 compared to 2008. The nine month results were largely impacted by the same factors that drove performance for the third quarter. In addition, the prior year period results include a gain of $21 million related to the temporary assignment of a transmission capacity contract in the second quarter of 2008, which did not recur in the 2009 period.

North: In the North region, Commodity Margin declined from $100 million in the third quarter of 2008 to $96 million in the current year period. The decline in Commodity Margin is primarily due to lower average hedge prices during the three months ended September 30, 2009, compared to the same period of 2008.

Commodity Margin in the North region decreased by $13 million in the first nine months of 2009 compared to the prior year period, primarily driven by the same factors that influenced performance for the third quarter.

LIQUIDITY AND CAPITAL RESOURCES

     

Table 3: Corporate Liquidity

  September 30, December 31, 2009 2008 (in millions) Cash and cash equivalents, corporate(1) $ 681 $ 1,361 Cash and cash equivalents, non-corporate   232   296 Total cash and cash equivalents 913 1,657 Restricted cash 505 503 Letter of credit availability(2) 2 2 Revolver availability   789   16 Total current liquidity(3) $ 2,209 $ 2,178  

(1) Includes $1 million and $169 million of margin deposits held by us posted by our counterparties as of September 30, 2009, and December 31, 2008, respectively.

(2) Includes available balances for Calpine Development Holdings, Inc.

(3) Excludes contingent amounts of $150 million under the Knock-in Facility and $200 million under the Commodity Collateral Revolver as of December 31, 2008.

Liquidity remained strong during the third quarter of 2009 at over $2.2 billion. For the first nine months of 2009, we generated $520 million of Adjusted Free Cash Flow, which nearly meets our previous full year guidance for 2009 largely due to changes in working capital. As previously discussed, operating activities resulted in net cash proceeds of $537 million during the first nine months of 2009, compared to $355 million in the prior year period. In addition, cash flows used in investing activities resulted in a net outflow of $164 million, driven largely by $140 million in capital expenditures, which were primarily related to maintenance expenditures across the fleet.

Continuing our efforts toward efficient balance sheet management, earlier this month we completed an offering of approximately $1.2 billion in Senior Secured Notes due 2017, which were exchanged for an equal amount of term loans under our First Lien Credit Facility that were due in 2014. “Our team worked hard to come up with this somewhat unique bond-for-loan approach to restacking our debt, and we are very pleased with the results,” said Zamir Rauf, Calpine’s Chief Financial Officer. “We extended the maturity of the debt by three and a half years, secured a very attractive rate and obtained an investment grade covenant package giving us greater flexibility. We will continue to be creative and opportunistic about addressing our future debt maturities.”

We were able to complete this transaction as a result of the amendment to our First Lien Credit Facility that we obtained during the third quarter. In addition to providing us the ability to exchange or retire term loans with bonds, the amendment also gives us the option to buy back debt at a discount using cash on hand via an auction process, the option to issue bonds under the accordion provision of our First Lien Credit Facility, and the option to extend all or a portion of our revolver and term loan maturities on revised terms subject to acceptance by applicable lenders.

PLANT DEVELOPMENT

Otay Mesa Energy Center: Otay Mesa, Calpine’s wholly owned 608 MW natural gas-fired power plant in southern San Diego County, California, began commercial operations on October 3, 2009, under a 10-year tolling agreement with SDG&E. “We are excited to begin the operating phase of this project,” said Thad Hill, Calpine’s Chief Commercial Officer. “We look forward to extending our track record of providing affordable, reliable and clean energy in California at Otay Mesa and continuing our relationship with SDG&E.”

Los Esteros Critical Energy Center: As we announced today, we have entered into an agreement with PG&E to upgrade our Los Esteros power plant from a 180 MW simple-cycle peaking plant to a 300 MW combined-cycle generation plant. In addition to the increase in capacity, the upgrade will increase the efficiency and environmental performance of the power plant by lowering the heat rate. While the plant upgrade is under construction, we will provide capacity from our Gilroy Cogeneration power plant. Upon completion of the upgrade, PG&E will purchase all of the capacity from our Los Esteros power plant for a term of 10 years.

OPERATIONS UPDATE

Power Operations Achievements: During the third quarter of 2009, we demonstrated our continued focus on operating excellence by:

• Safety Performance: Maintained top-quartile safety performance with year-to-date lost-time incident rate of 0.19
• Availability Performance:
  • Provided 99% or higher availability on nearly 60% of our capacity during the third quarter
  • Achieved fleet-wide forced outage factor of only 2.19%
  • Delivered natural gas fleet starting reliability of 98.1%
• Geothermal Generation: Provided 1.5 million MWh of renewable baseload generation with 93% capacity factor and 0.21% forced outage factor
• Sustainable Cost Reductions: Reduced controllable expenses2 as a component of plant operating expense by $19 million in the third quarter of 2009 compared to the third quarter of 2008, after accounting for $15 million of prior period insurance proceeds that benefited the 2008 period

Commercial Operations Achievements: We continued to benefit from the efforts of our commercial operations team during the third quarter of 2009, including:

• Customer-led growth: Worked with key customers toward significant new and amended long-term contracts covering approximately 2,800 MW of capacity in California
  • Extended term and increased volume of existing contracts with PG&E at The Geysers geothermal plants
  • Entered into replacement contract with PG&E for our California peaking plants
  • Signed new agreement with PG&E for our Los Esteros plant, under which we will upgrade the existing plant
  • Entered into a new tolling agreement with PG&E for all the capacity at our Delta plant
  • Executed a resource adequacy agreement for all of the capacity from our Pastoria power plant with Southern California Edison
• Effective hedging: Maintained stable year-over-year Adjusted EBITDA, despite declining commodity prices

2 Controllable expenses include variable and fixed expenses, but exclude major maintenance expense, stock compensation expense, non-cash gains/losses on dispositions of assets, and depreciation and amortization.

FINANCIAL OUTLOOK

     

Table 4: Adjusted EBITDA and Adjusted Free Cash Flow Guidance

  Full Year 2009 Full Year 2010 (in millions) Adjusted EBITDA $ 1,710 – 1,735 $ 1,500 – 1,600 Less: Operating lease payments 50 50 Major maintenance expense and capital expenditures(1) 350 290 Cash interest, net 775 750 Cash taxes 5 10 Working capital and other adjustments(2)   — - (25)     Adjusted Free Cash Flow $ 530 - 580 $ 400 - 500  

(1) Includes projected Major Maintenance Expense of $200 million and $180 million in 2009 and 2010, respectively, and maintenance Capital Expenditures of $150 million and $110 million in 2009 and 2010, respectively. Capital expenditures exclude major construction and development projects.

(2) Excludes changes in cash collateral for commodity procurement and risk management activities.

We are tightening and raising our full year guidance for 2009. We are now projecting Adjusted EBITDA of $1.710 billion to $1.735 billion, and Adjusted Free Cash Flow of $530 million to $580 million.

Today, we are also providing our 2010 guidance for the first time, a full four months earlier than we initially provided our guidance for the current year. For 2010, we project Adjusted EBITDA of $1.5 billion to $1.6 billion, and Adjusted Free Cash Flow of $400 million to $500 million.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the third quarter 2009, on Friday, October 30, 2009, at 10:00 a.m. ET / 9:00 a.m. CT. A listen-only webcast of the call may be accessed through our web site at www.calpine.com, or by dialing 888-510-1768 (or 719-785-1748 for international listeners) at least 10 minutes prior to the beginning of the call. An archived recording of the call will be made available for a limited time on the web site. The recording also can be accessed by dialing 888-203-1112 or 719-457-0820 (International) and providing Confirmation Code 1657864. Presentation materials to accompany the conference call will be made available on our web site on October 30, 2009.

ABOUT CALPINE

Calpine Corporation is helping meet the needs of an economy that demands more and cleaner sources of electricity. Founded in 1984, Calpine is a major U.S. power company, currently capable of delivering nearly 25,000 megawatts of clean, cost-effective, reliable and fuel-efficient power to customers and communities in 16 states in the United States and Canada. Calpine owns, leases, and operates low-carbon, natural gas-fired, and renewable geothermal power plants. Using advanced technologies, Calpine generates power in a reliable and environmentally responsible manner for the customers and communities it serves. Please visit www.calpine.com for more information.

Calpine’s Quarterly Report on Form 10-Q for the period ended September 30, 2009, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC’s web site at www.sec.gov.

FORWARD-LOOKING INFORMATION

In addition to historical information, this Report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:

• The uncertain length and severity of the current general financial and economic downturn and its impacts on our business including demand for our power and steam products, the ability of customers, suppliers, service providers and other contractual counterparties to perform under their contracts with us and the cost and availability of capital and credit;
• Fluctuations in prices for commodities such as natural gas and power including the effects of fluctuations in liquidity and volatility in the energy commodities markets including our ability to hedge risks;
• Our ability to manage our significant liquidity needs and to comply with covenants under our First Lien Credit Facility, our First Lien Notes and other existing financing obligations;
• Financial results that may be volatile and may not reflect historical trends due to, among other things, general economic and market conditions outside of our control;
• Our ability to attract and retain customers and counterparties, including suppliers and service providers, and to manage our customer and counterparty exposure and credit risk, including our commodity positions;
• Competition, including risks associated with marketing and selling power in the evolving energy markets;
• Regulation in the markets in which we participate and our ability to effectively respond to changes in laws and regulations or the interpretation thereof including changing market rules and evolving federal, state and regional laws and regulations including those related to greenhouse gas emissions;
• Natural disasters such as hurricanes, earthquakes and floods that may impact our power plants or the markets our power plants serve;
• Seasonal fluctuations of our results and exposure to variations in weather patterns;
• Disruptions in or limitations on the transportation of natural gas and transmission of power;
• Our ability to attract, retain and motivate key employees;
• Our ability to implement our new business plan and strategy;
• Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of waste water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
• Present and possible future claims, litigation and enforcement actions, including our ability to complete the implementation of our Plan of Reorganization;
• The expiration or termination of our power purchase agreements and the related results on revenues;
• Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies; and
• Other risks identified in this release or in our reports and registration statements filed with the Securities and Exchange Commission (SEC), including, without limitation, the risk factors identified in our Quarterly Reports on Form 10-Q for the quarters ended March 31, June 30 and September 30, 2009 and in our Annual Report on Form 10-K for the year ended December 31, 2008.

Actual results or developments may differ materially from the expectations expressed or implied in the forward-looking statements, and we undertake no obligation to update any forward-looking statements, whether as a result of new information, future developments or otherwise. Unless specified otherwise, all information set forth in this release is as of today’s date, and we undertake no duty to update this information. For additional information about our general business operations, please refer to our Annual Report on Form 10-K for the year ended December 31, 2008, and any other recent report we have filed with the SEC. These filings are available by visiting the SEC’s web site at www.sec.gov or our web site at www.calpine.com.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

  Three Months Ended September 30,

Nine Months Ended September 30,

2009 2008 2009 2008 (in millions, except share and per share amounts) Operating revenues $ 1,847 $ 3,190 $ 4,995 $ 7,969   Cost of revenue: Fuel and purchased energy expense 1,030 2,322 2,967 5,935 Plant operating expense 196 198 654 636 Depreciation and amortization expense 108 110 330 329 Other cost of revenue   20   26   63   88 Total cost of revenue   1,354   2,656   4,014   6,988 Gross profit 493 534 981 981 Sales, general and other administrative expense 38 58 131 154 (Income) loss from unconsolidated investments in power plants 13 202 (27 ) 189 Other operating expense   5   2   14   15 Income from operations 437 272 863 623 Interest expense 198 212 615 837 Interest (income) (3 ) (11 ) (13 ) (38 ) Debt extinguishment costs 16 — 49 13 Other (income) expense, net   4   18   8   16 Income (loss) before reorganization items and income taxes 222 53 204 (205 ) Reorganization items   (8 )   (2 )   (2 )   (263 ) Income before income taxes 230 55 206 58 Income tax expense (benefit)   (7 )   (80 )   17   (60 ) Net income $ 237 $ 135 $ 189 $ 118 Net loss attributable to the noncontrolling interest   1   1   3   1 Net income attributable to Calpine $ 238 $ 136 $ 192 $ 119   Basic earnings per common share: Weighted average shares of common stock outstanding (in thousands)   485,736   485,076   485,619   485,027 Net income per common share attributable to Calpine – basic $ 0.49 $ 0.28 $ 0.40 $ 0.25   Diluted earnings per common share: Weighted average shares of common stock outstanding (in thousands)   486,585   485,744   486,171   485,588 Net income per common share attributable to Calpine – diluted $ 0.49 $ 0.28 $ 0.39 $ 0.25    

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

  September 30, December 31, 2009 2008

(in millions, except share and per share amounts)

ASSETS Current assets: Cash and cash equivalents $ 913 $ 1,657 Accounts receivable, net of allowance of $19 and $42 880 850 Inventory 164 163 Margin deposits and other prepaid expense 418 776 Restricted cash, current 461 337 Current derivative assets 2,032 3,653 Other current assets   37   64 Total current assets 4,905 7,500   Property, plant and equipment, net 11,683 11,908 Restricted cash, net of current portion 44 166 Investments 210 144 Long-term derivative assets 288 404 Other assets   571   616 Total assets $ 17,701 $ 20,738 LIABILITIES & STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable $ 605 $ 574 Accrued interest payable 71 85 Debt, current portion 421 716 Current derivative liabilities 2,097 3,799 Income taxes payable 7 5 Other current liabilities   245   437 Total current liabilities 3,446 5,616   Debt, net of current portion 9,064 9,756 Deferred income taxes, net of current portion 64 93 Long-term derivative liabilities 421 698 Other long-term liabilities   207   203 Total liabilities 13,202 16,366   Stockholders’ equity: Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding at September 30, 2009 and December 31, 2008 — — Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 442,699,628 shares issued and 442,372,296 shares outstanding at September 30, 2009; 429,025,057 shares issued and 428,960,025 shares outstanding at December 31, 2008 1 1 Treasury stock, at cost; 327,332 shares at September 30, 2009 and 65,032 shares at December 31, 2008 (3 ) (1 ) Additional paid-in capital 12,249 12,217 Accumulated deficit (7,497 ) (7,689 ) Accumulated other comprehensive loss   (250 )   (158 ) Total Calpine stockholders’ equity 4,500 4,370 Noncontrolling interest   (1 )   2 Total stockholders’ equity   4,499   4,372 Total liabilities and stockholders’ equity $ 17,701 $ 20,738    

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

  Nine Months Ended September 30, 2009 2008 (in millions) Cash flows from operating activities: Net income $ 189 $ 118 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization expense(1) 399 411 (Income) loss from unconsolidated investments in power plants (27 ) 189 Debt extinguishment costs 9 7 Deferred income taxes 15 (60 ) Loss on disposal of assets, excluding reorganization items 29 6 Mark-to-market activity, net (67 ) 15 Stock-based compensation expense 30 36 Reorganization items (7 ) (331 ) Other 6 21 Change in operating assets and liabilities: Accounts receivable (23 ) 126 Derivative instruments (239 ) (45 ) Other assets 387 96 Accounts payable, LSTC and accrued expenses 13 (76 ) Other liabilities   (177 )   (158 ) Net cash provided by operating activities   537   355 Cash flows from investing activities: Purchases of property, plant and equipment (140 ) (108 ) Disposals of property, plant and equipment — 16 Proceeds from sale of power plants, turbines and investments — 398 Cash acquired due to reconsolidation of the Canadian Debtors and other deconsolidated foreign entities — 64 Contributions to unconsolidated investments (19 ) (14 )

Return of investment from unconsolidated investments

— 26 (Increase) decrease in restricted cash (2 ) 145 Other   (3 )   7 Net cash provided by (used in) investing activities   (164 )   534 Cash flows from financing activities: Repayments of notes payable

 

(106 )

 

(98 ) Repayments of project financing (889 ) (274 ) Borrowings from project financing 1,028 356 Repayments of DIP Facility — (98 ) Borrowings under First Lien Facilities — 3,523 Repayments on First Lien Facilities (770 ) (1,460 ) Borrowings under Commodity Collateral Revolver — 100 Repayments on Second Priority Debt — (3,672 ) Repayments on capital leases (34 ) (29 ) Redemptions of preferred interests (310 ) (166 ) Financing costs (34 ) (207 ) Derivative contracts classified as financing activities — 70 Other   2   2 Net cash used in financing activities   (1,117 )   (1,953 ) Net decrease in cash and cash equivalents (744 ) (1,064 ) Cash and cash equivalents, beginning of period   1,657   1,915 Cash and cash equivalents, end of period $ 913 $ 851   Cash paid (received) during the period for: Interest, net of amounts capitalized $ 563 $ 873 Income taxes $ 6 $ 16 Reorganization items included in operating activities, net $ 5 $ 124 Reorganization items included in investing activities, net $ — $ (414 )   Supplemental disclosure of non-cash investing and financing activities: Settlement of commodity contract with project financing $ 79 $ — Change in capital expenditures included in accounts payable $ 3 $ 13 Settlement of LSTC through issuance of reorganized Calpine Corporation common stock $ — $ 5,200 DIP Facility borrowings converted into exit financing under First Lien Facilities $ — $ 3,872 Settlement of Convertible Senior Notes and Unsecured Senior Notes with reorganized Calpine Corporation common stock $ — $ 3,703  

(1)  Includes depreciation and amortization that is also recorded in sales, general and other administrative expense and interest expense on our Consolidated Condensed Statements of Operations.

REGULATION G RECONCILIATIONS

Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These measures should not be viewed as alternatives to GAAP measures of performance.

Commodity Margin includes our power and steam revenues, capacity revenue, revenue from renewable energy credits, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, RGGI compliance costs and cash settlements from our marketing, hedging and optimization activities that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other revenue. Commodity Margin is presented because we believe it is a useful tool for assessing the performance of our core operations, and it is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent gross profit (loss), the most comparable GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other companies.

Adjusted EBITDA represents net income (loss) before interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. Adjusted EBITDA is presented because our management uses Adjusted EBITDA (i) as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends; (ii) as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations; and (iii) in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. We believe Adjusted EBITDA is also used by and is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. Adjusted EBITDA is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies.

Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes, working capital and other adjustments. Adjusted Free Cash Flow is presented because our management uses this measure, among others, to make decisions about capital allocation. Adjusted Free Cash Flow is not intended to represent cash flows from operations as defined by GAAP as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other companies.

Commodity Margin Reconciliation

 

The following table reconciles our Commodity Margin to its GAAP results for the three months ended September 30, 2009 and 2008:

  Three Months Ended September 30, 2009

(in millions)

  Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 393 $ 187 $ 92 $ 96 $ — $768 Add: Mark-to-market commodity activity, net and other revenue(1) 41 2 (4 ) 21 (12 ) 48 Less: Plant operating expense 99 35 27 18 17 196 Depreciation and amortization expense 49 27 17 16 (1 ) 108 Other cost of revenue(2)   18   6   3   10   (18 ) 19 Gross profit $ 268 $ 121 $ 41 $ 73 $ (10 ) $493   Three Months Ended September 30, 2008

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 372 $ 233 $ 95 $ 100 $ — $800 Add: Mark-to-market commodity activity, net and other revenue(1) (45 ) 188 3 (69 ) (9 ) 68 Less: Plant operating expense 96 56 31 23 (8 ) 198 Depreciation and amortization expense 48 31 16 15 — 110 Other cost of revenue(2)   19   3   5   8   (9 ) 26 Gross profit (loss) $ 164 $ 331 $ 46 $ (15 ) $ 8 $534  

(1) Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, as well as a non-cash gain from amortization of prepaid power sales agreements included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.

(2) Excludes $1 million and nil of RGGI compliance costs for the three months ended September 30, 2009 and 2008, respectively, which were included as a component of Commodity Margin.

 

 

The following table reconciles our Commodity Margin to its GAAP results for the nine months ended September 30, 2009 and 2008:

  Nine Months Ended September 30, 2009

(in millions)

  Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 994 $ 505 $ 233 $ 215 $ — $ 1,947 Add: Mark-to-market commodity activity, net and other revenue(1) 120 (48 ) 2 37 (35 ) 76 Less: Plant operating expense 326 163 94 61 10 654 Depreciation and amortization expense 150 88 50 47 (5 ) 330 Other cost of revenue(2)   45   11   7   23   (28 )   58 Gross profit $ 593 $ 195 $ 84 $ 121 $ (12 ) $ 981   Nine Months Ended September 30, 2008

(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 965 $ 587 $ 208 $ 228 $ — $ 1,988 Add: Mark-to-market commodity activity, net and other revenue(1) (30 ) 114 6 (24 ) (20 ) 46 Less: Plant operating expense 309 178 84 73 (8 ) 636 Depreciation and amortization expense 143 94 54 40 (2 ) 329 Other cost of revenue(2)   54   9   23   21   (19 )   88 Gross profit $ 429 $ 420 $ 53 $ 70 $ 9 $ 981  

(1)  Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, as well as a non-cash gain from amortization of prepaid power sales agreements included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.

(2)  Excludes $5 million and nil of RGGI compliance costs for the nine months ended September 30, 2009 and 2008, respectively, which were included as a component of Commodity Margin.

Consolidated Adjusted EBITDA Reconciliation

 

In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our Income from operations for the three and nine months ended September 30, 2009 and 2008, as reported under GAAP.

  Three Months Ended September 30, Nine Months Ended September 30, 2009 2008(1) 2009 2008(1) (in millions) Net income attributable to Calpine $ 238 $ 136 $ 192 $ 119 Net loss attributable to noncontrolling interest (1 ) (1 ) (3 ) (1 ) Income tax expense (benefit) (7 ) (80 ) 17 (60 ) Reorganization items (8 ) (2 ) (2 ) (263 ) Other (income) expense and debt extinguishment costs, net 20 18 57 29 Interest expense, net   195   201   602   799 Income from operations $ 437 $ 272 $ 863 $ 623 Add: Adjustments to reconcile income from operations to Adjusted EBITDA: Depreciation and amortization expense, excluding deferred financing costs(2) 110 117 339 357 Impairment loss(3) — 179 — 185 Major maintenance expense 22 22 124 118 Operating lease expense 12 12 35 35 Non-cash realized gains on derivatives — (13 ) — (33 ) Unrealized (gains) losses on commodity derivative mark-to-market activity (43 ) (43 ) (60 ) 22 Adjustments to reflect Adjusted EBITDA from unconsolidated investments(3),(4) 28 34 11 29 Stock-based compensation expense 8 17 30 36 Non-cash loss on dispositions of assets 12 1 29 9 Other(6)   —   (4 )   3   (7 ) Adjusted EBITDA $ 586 $ 594 $ 1,374 $ 1,374 Less: Lease payments 12 35 Major maintenance expense and capital expenditures(5) 67 264 Cash interest(6) 176 563 Cash taxes 4 6 Working capital and other adjustments   (36 )   (14 ) Adjusted Free Cash Flow $ 363 $ 520  

(1) Adjusted EBITDA for the three and nine months ended September 30, 2008, has been recast to conform to our current period definition.

(2) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets and amounts classified as sales, general and other administrative expenses.

(3) Included in our Consolidated Condensed Statements of Operations in (income) loss from unconsolidated investments in power plants.

(4) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include $14 million and $12 million in unrealized (gains) losses on mark-to-market activity for the three months ended September 30, 2009 and 2008, respectively, and $(14) million and $4 million for the nine months ended September 30, 2009 and 2008, respectively.

(5) Includes $22 million and $124 million in major maintenance expense for the three and nine months ended September 30, 2009, respectively, and $45 million and $140 million in capital expenditures for the three and nine months ended September 30, 2009, respectively.

(6) Includes fees for letters of credit, net of interest income.

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance

  Full Year 2009 Range: Low High

(in millions)

GAAP Net Income $ 80 $ 105 Plus: Interest expense, net of interest income 795 795 Depreciation and amortization expense 455 455 Major maintenance expense 200 200 Operating lease expense 50 50 Other(1)   130   130 Adjusted EBITDA $ 1,710 $ 1,735 Less: Operating lease payments 50 50 Major maintenance expense and maintenance capital expenditures(2) 350 350 Cash interest, net(3) 775 775 Cash taxes 5 5 Working capital and other adjustments   —   (25 ) Adjusted Free Cash Flow $ 530 $ 580   Full Year 2010 Range: Low High

(in millions)

GAAP Net Income $ (30 ) $ 70 Plus: Interest expense, net of interest income 750 750 Depreciation and amortization expense 465 465 Major maintenance expense 180 180 Operating lease expense 50 50 Other(1)   85   85 Adjusted EBITDA $ 1,500 $ 1,600 Less: Operating lease payments 50 50 Major maintenance expense and maintenance capital expenditures(2) 290 290 Cash interest, net(3) 750 750 Cash taxes   10   10 Adjusted Free Cash Flow $ 400 $ 500  

(1) Other includes stock-based compensation expense and other adjustments.

(2) Includes projected Major Maintenance Expense of $200 million and $180 million in 2009 and 2010, respectively and maintenance Capital Expenditures of $150 million and $110 million in 2009 and 2010, respectively. Capital expenditures exclude major construction and development projects.

(3) Includes fees for letters of credit, net of interest income.

CASH FLOW ACTIVITIES

   

The following table summarizes our cash flow activities for the nine months ended September 30, 2009 and 2008:

  (Unaudited) Nine Months Ended September 30, 2009 2008 (in millions) Beginning cash and cash equivalents $ 1,657 $ 1,915 Net cash provided by (used in): Operating activities 537 355 Investing activities (164 ) 534 Financing activities   (1,117 )   (1,953 ) Net decrease in cash and cash equivalents   (744 )   (1,064 ) Ending cash and cash equivalents $ 913 $ 851

OPERATING PERFORMANCE METRICS

 

The table below shows the operating performance metrics for continuing operations:

  Three Months Ended September 30, Nine Months Ended September 30, 2009 2008 2009 2008 Total MWh generated(1) (in thousands)   28,051   25,773   66,717   67,890 West 10,447 10,563 26,108 27,702 Texas 10,246 9,830 23,058 27,048 Southeast 6,006 3,753 13,842 9,058 North 1,352 1,627 3,709 4,082   Average availability 97.1 % 96.6 % 92.9 % 90.8 % West 95.2 % 95.8 % 92.3 % 89.6 % Texas 97.5 % 96.9 % 92.1 % 90.1 % Southeast 98.2 % 97.4 % 93.3 % 92.6 % North 98.5 % 96.7 % 95.5 % 92.0 %   Average capacity factor, excluding peakers 60.7 % 55.2 % 49.0 % 49.0 % West 73.0 % 73.9 % 62.3 % 65.9 % Texas 64.0 % 61.4 % 48.5 % 56.7 % Southeast 51.0 % 29.8 % 40.0 % 24.5 % North 31.5 % 39.1 % 30.1 % 33.8 %   Steam adjusted Heat Rate 7,268 7,274 7,246 7,237 West 7,302 7,314 7,299 7,287 Texas 7,227 7,147 7,149 7,090 Southeast 7,187 7,335 7,214 7,409 North 7,758 7,722 7,693 7,596  

(1) MWh generated is shown here as our net operating interest. Excludes generation at RockGen from January 1 to September 30, 2008, as the plant was deconsolidated during this period.