CPN Calpine Corp.

Calpine Corporation (NYSE: CPN) today reported 2009 Adjusted EBITDA of $1,782 million, up $83 million, or 5%, over the prior year despite recessionary influences. Although 2009 commodity prices were lower than in 2008 and annual U.S. power demand was down nearly 4% year-over-year, our Commodity Margin of $2,562 million was relatively unchanged from 2008. The company also reported strong 2009 Adjusted Free Cash Flow of $609 million, an increase of 23% over 2008 results. Additionally, corporate liquidity increased by more than $200 million in 2009 to $2,379 million. Net income1 during the year was $149 million, or $0.31 per diluted share, compared to net income of $10 million, or $0.02 per diluted share, in 2008.

“Our exceptional 2009 operating and commercial performance translated into a strong financial performance, particularly given the depressed general market and economic environment. We have made significant progress toward our goal of being ‘best in class’,” said Jack Fusco, Calpine’s President and Chief Executive Officer. “We improved on several key operating metrics, including our forced outage and availability factors, demonstrating our commitment to delivering clean, efficient and reliable energy and services to our customers. Our strong financial results reflect the effectiveness of our hedging program as well as the success of our efficiency initiatives in 2009. During the year, we also accomplished several noteworthy achievements, including the successful commissioning of our Otay Mesa Energy Center, the opportunistic refinancing of approximately $3.0 billion of debt and the origination of several important contracts with key customers throughout the country.

“Looking ahead to 2010, today we are reaffirming our Adjusted EBITDA guidance of $1.5 to $1.6 billion and our Adjusted Free Cash Flow guidance of $400 to $500 million. I am pleased that our proactive hedging efforts have substantially mitigated our exposure to natural gas price risk in 2010, allowing us to continue to focus on excellence in operations, customer-focused origination and disciplined strategic growth,” Fusco said.

“Our growth projects include our turbine upgrade program, expansion at The Geysers, and construction of the Russell City Energy Center as well as the expansion of our Los Esteros Critical Energy Facility, both located in California. These projects reaffirm Calpine’s position as a long-term leader in environmental stewardship through operation of and investment in clean technologies.”

 

SUMMARY OF FINANCIAL PERFORMANCE

Full Year Results

Adjusted EBITDA for the year ended December 31, 2009, was $1,782 million, compared to $1,699 million in the prior year period. The $83 million improvement year-over-year was primarily due to three factors. First, Commodity Margin increased by $38 million during the 2009 period. This improvement was due to higher average hedge margins in 2009 compared to 2008 and strong performance by our Southeast segment, which experienced a 35% increase in generation in 2009 largely due to higher natural gas generation displacement of coal generation in certain sub-markets of that segment, caused by lower natural gas prices resulting in higher market heat rates.

Secondly, in the 2009 period, we reduced aggregate plant operating expense2, sales, general and administrative expense2, and components of other cost of revenue by $61 million, after excluding a $29 million decrease in reimbursements for insurance claims from prior periods that reduced plant operating expense in the 2008 period and, to a much lesser extent, the 2009 period. These cost improvements were due, in large part, to efficiency efforts that we implemented over the course of 2009. Finally, Adjusted EBITDA from unconsolidated investments increased by $41 million in 2009 compared to the corresponding 2008 period, primarily as a result of Greenfield Energy Centre achieving commercial operations in the fourth quarter of 2008 and Otay Mesa Energy Center achieving commercial operations in the fourth quarter of 2009.

These increases were offset, in part by a $36 million decrease in other revenue associated with declines in revenues from operations and maintenance and construction management projects and royalty income on oil and gas producing properties.

Net income1 increased to $149 million for the year ended December 31, 2009, from $10 million in the prior year period. As detailed in Table 1, net income, excluding reorganization items, discontinued operations, other items and unrealized mark-to-market gains or losses, increased from $62 million in 2008 to $141 million in 2009. The improvement is primarily attributable to income from unconsolidated investments in power plants, which increased by $99 million, excluding an impairment loss of $180 million in 2008. In addition, the increase was due to the $38 million improvement in Commodity Margin previously noted. Offsetting these improvements, income tax expense increased by $62 million in 2009 compared to 2008, primarily due to non-cash changes in our intraperiod tax allocations.

Cash flows provided by operating activities for the twelve months ended December 31, 2009, improved to $761 million compared to $494 million for the 2008 period. Cash paid for interest decreased by $299 million in 2009, primarily due to the repayment of the Second Priority Debt, and, to a lesser extent, lower interest rates for the comparable period in 2009. In addition, cash payments for reorganization items decreased by $115 million. Meanwhile, working capital employed, after adjusting for debt-related balances and derivative activities, which did not impact cash provided by operating activities, increased by approximately $152 million for the 2009 period compared to 2008. The increase was primarily due to a reduction in assets held for sale during 2008 for which there was not a corresponding change in 2009, offset by a net reduction in working capital employed in 2009 for margins and net accounts receivable and payable. Finally, cash payments for debt extinguishment costs in 2009 were $39 million related to the CCFC Refinancing, compared to cash payments of $6 million related to the refinancing of Blue Spruce and Metcalf in 2008.

Fourth Quarter Results

Adjusted EBITDA for the fourth quarter of 2009 was $408 million, up $83 million from the prior year period. The year-over-year improvement was primarily due to a $79 million increase in Commodity Margin to $615 million in 2009 from $536 million in 2008. The Commodity Margin improvement was primarily attributable to our West region, which benefited from strong hedges, despite a weaker commodity price environment. In addition, our Southeast segment also benefited from hedge positions.

Adjusted EBITDA was also favorably impacted by a $22 million increase in Adjusted EBITDA from unconsolidated investments, primarily associated with our Otay Mesa plant, which achieved commercial operation in the fourth quarter of 2009.

These improvements were offset, in part, by a $17 million decline in other revenue from the fourth quarter of 2008 to the fourth quarter of 2009, primarily the result of lower royalty income on oil and gas producing properties.

Net loss1 decreased from $109 million in the fourth quarter of 2008 to $43 million in the fourth quarter of 2009. As detailed in Table 1, net loss, excluding reorganization items, other items and unrealized mark-to-market gains or losses, decreased from $177 million in the fourth quarter of 2008 to $12 million in the fourth quarter of 2009. This improvement was primarily associated with the $79 million year-over-year increase in Commodity Margin, as previously noted. In addition, income from unconsolidated investments in power plants increased by $62 million, excluding a $1 million impairment loss in 2008. Plant operating expense and sales, general and administrative expense, as reported, decreased by $39 million and $9 million, respectively, due, in part, to the efficiency efforts previously mentioned. These benefits were offset, in part, by the $17 million decline in other revenue noted above.

1 Reported as net income (loss) attributable to Calpine on our Consolidated Statements of Operations.

2 Plant operating expense and sales, general and administrative expense exclude, in the aggregate, decreases in major maintenance expense of $16 million, decreases in stock-based compensation expense of $12 million, decreases in non-cash loss on dispositions of assets of $2 million, and decreases in depreciation and amortization of $2 million. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items in 2008 and 2009.

Table 1: Summarized Consolidated Condensed Statements of Operations

    (Unaudited) Three Months Ended December 31, Year Ended December 31, 2009   2008 2009   2008 (in millions) Operating revenues $ 1,569 $ 1,968 $ 6,564 $ 9,937 Cost of revenue   1,335   1,791   5,349   8,779 Gross profit 234 177 1,215 1,158

SG&A, (income) loss from unconsolidated investments in power plants and other operating expense

  33   112   151   470 Income from operations 201 65 1,064 688

Net interest expense, debt extinguishment costs and other (income) expense

  246   223   905   1,051

Income (loss) before reorganization items, income taxes and discontinued operations

(45 ) (158 ) 159 (363 )

Reorganization items

  1   (39 )   (1 )   (302 )

Income (loss) before income taxes and discontinued operations

(46 ) (119 ) 160 (61 )

Income tax expense (benefit)

  (2 )   13   15   (47 )

Income (loss) before discontinued operations

(44 ) (132 ) 145 (14 )

Discontinued operations, net of tax provision of $14 in 2008

  —   23   —   23

Net income (loss)

$ (44 ) $ (109 ) $ 145 $ 9  

Net loss attributable to the noncontrolling interest

  1   —   4   1

Net income (loss) attributable to Calpine

$ (43 ) $ (109 ) $ 149 $ 10  

Reorganization items(1)

1 (39 ) (1 ) (302 ) Discontinued operations, net — (23 ) — (23 )

Other items(1)(2)

  52   34   82   401

Net income (loss), net of reorganization items, discontinued operations and other items

10 (137 ) 230 86

Unrealized MtM (gains) losses on derivatives(1)(3)

  (22 )   (40 )   (89 )   (24 )

Net income (loss), net of reorganization items,  discontinued operations, other items and unrealized MtM impacts

$ (12 ) $ (177 ) $ 141 $ 62  

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

(2) Other items in the fourth quarter of 2008 include an impairment charge of approximately $33 million related to the Auburndale peaker power plant and a $1 million impairment loss associated with our interest in the Auburndale power plant, which was sold during 2008. Other items in the full year 2008 include the $33 million impairment charge related to the Auburndale peaker power plant, a cumulative impairment loss of $180 million associated with our interest in the Auburndale power plant, $13 million in settlement costs, $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. Other items in the fourth quarter 2009 include $25 million in additional depreciation expense associated with a change in the estimated useful lives and salvage values of our power plants and related equipment and changing our Geysers Assets depreciation method, as well as $27 million in debt extinguishment costs. Other items in the full year 2009 period also include debt extinguishment costs of $49 million associated with the refinancing of CCFC, shown net of tax assuming a 38.4% effective tax rate.

(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)

                                                                                                                                Year Ended December 31, 2009     2008   West $ 1,346 $ 1,255 Texas 644 726 Southeast 304 264 North   268   279 Total $ 2,562 $ 2,524  

West: Commodity Margin in our West segment increased by $91 million for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase was primarily a result of higher hedge levels and prices, sales of surplus emission allowances in the first quarter of 2009 and higher resource adequacy and renewable energy credit revenues in 2009 compared to 2008. Market heat rates remained relatively unchanged across periods, and lower natural gas prices resulted in lower market spark spreads for the year ended December 31, 2009 compared to 2008. In addition, the current period benefited from the non-recurrence in 2009 of an unfavorable natural gas storage inventory price adjustment in September 2008.

Texas: Commodity Margin in our Texas segment decreased by $82 million for the year ended December 31, 2009 compared to 2008. This decrease is primarily attributable to weaker natural gas prices that were 56% lower in 2009 compared to 2008. Overall, market heat rates were relatively unchanged in 2009 compared to 2008; however, market heat rates were higher in the third quarter of 2009 compared to the same period in 2008 due to warmer than average weather and lower in the second quarter of 2009 compared to the same period in 2008 due to the congestion-driven pricing environment of the second quarter of 2008. Also contributing to the overall decrease in Commodity Margin was lower steam sales resulting from weaker industrial demand in 2009 compared to 2008.

Southeast: Commodity Margin in our Southeast segment increased by $40 million for the year ended December 31, 2009 compared to 2008. The increase was driven by a 35% increase in generation, which resulted from higher natural gas generation displacement of coal generation in certain sub-markets in our Southeast segment primarily caused by lower natural gas prices resulting in higher market heat rates in 2009 compared to 2008. Commodity Margin in the Southeast was also positively affected in 2009 compared to 2008, by the favorable impact of an off-take agreement at one of our power plants and incremental natural gas hedges. The benefit from these positive performance factors was partially offset by the negative impact from the settlement of a disputed steam contract, which adversely impacted operating revenues in 2009. In addition, a gain of $21 million related to the temporary assignment of a transmission capacity contract in the second quarter of 2008 led to a reduction in relative year-over-year performance.

North: Commodity Margin in our North segment decreased by $11 million for the year ended December 31, 2009 compared to 2008. Although market spark spreads were lower in 2009 compared to 2008, the impact was largely mitigated by our hedge position as well as the favorable impact of the reconsolidation of RockGen in December 2008.

 

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Corporate Liquidity

                                                                              December 31,     December 31, 2009 2008 (in millions) Cash and cash equivalents, corporate(1) $ 725 $ 1,361 Cash and cash equivalents, non-corporate   264   296 Total cash and cash equivalents 989 1,657 Restricted cash 562 503 Letter of credit availability(2) 34 2 Revolver availability(3)   794   16 Total current liquidity(4) $ 2,379 $ 2,178  

(1) Includes $9 million and $169 million of margin deposits held by us posted by our counterparties as of December 31, 2009 and 2008, respectively.

(2) Additional available balances for Calpine Development Holdings, Inc. As of December 31, 2009, we have the option to increase our availability by an additional $50 million under this letter of credit by satisfying certain conditions.

(3) We repaid $725 million previously drawn on our First Lien Credit Facility revolver on September 28, 2009.

(4) 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 improved by more than $200 million during 2009, from $2.2 billion at December 31, 2008 to $2.4 billion at December 31, 2009. Consistent with our efforts to maintain strong liquidity, during the fourth quarter of 2009, we extended the letter of credit facility at our subsidiary, Calpine Development Holdings, Inc., which was previously scheduled to mature in 2010 but will now mature in 2012.

During 2009, we generated $609 million of Adjusted Free Cash Flow, representing an improvement of $114 million over 2008 results and exceeding our guidance for the year. The year-over-year improvement in Adjusted Free Cash Flow was primarily the result of the $83 million increase in Adjusted EBITDA, as previously discussed, as well as a $48 million decrease in cash tax payments from 2008 to 2009. Operating activities resulted in net cash proceeds of $761 million during the 2009 period, compared to $494 million in 2008. In addition, cash flows used in investing activities resulted in a net outflow of $250 million in 2009, driven largely by $179 million in capital expenditures, which were primarily related to maintenance across the fleet, growth investments in our turbine upgrade program and improvements to company systems.

During the fourth quarter of 2009, we continued our efforts toward managing near-term debt maturities by amending and extending our approximately $499 million Steamboat credit facility. The credit facility, originally scheduled to mature in 2011, is now due in 2017 and was refinanced on favorable terms. Including the Steamboat refinancing in the fourth quarter, we successfully refinanced approximately $3 billion of capital during 2009. “We entered 2009 with a goal of de-risking the balance sheet by opportunistically addressing near-term maturities while maintaining a strong liquidity balance,” said Zamir Rauf, Calpine’s Chief Financial Officer. “I am pleased to report that we achieved this goal. First, we refinanced approximately $3 billion of debt at very attractive rates while simplifying the balance sheet in the process. In addition, we improved our liquidity by $200 million. I would like to commend our team for the progress made on this front, particularly considering the uncertain nature of the economy and capital markets just a year ago.”

 

PLANT DEVELOPMENT

Russell City Energy Center: On February 4, 2010, we received the Prevention of Significant Deterioration air permit, the final permit necessary, to begin construction of our Russell City Energy Center (RCEC), a proposed 600 MW, natural gas-fired power plant to be located in Hayward, California in which we own a 65% share. Under the terms of the permit, RCEC is intended to become the first power plant in the United States with a federal limit on greenhouse gas emissions, and will be designed to operate in a way that produces 25% fewer greenhouse gas emissions than the California Public Utilities Commission standard. The power plant will use 100% reclaimed water from the City of Hayward’s Water Pollution Control Facility for cooling and boiler makeup, which will prevent nearly four million gallons of wastewater per day from being discharged into the San Francisco Bay. We hope to complete financing and break ground for this new state-of-the-art power plant during 2010 with commercial operations scheduled to begin in 2013.

 

OPERATIONS UPDATE

2009 Power Operations Achievements:

• Safety Performance: Achieved seventh consecutive year of top-quartile safety performance with 2009 lost-time incident rate of 0.24
• Availability Performance:
  • Improved fleet-wide average availability factor to 92.1% in 2009, compared to 90.5% in 2008
  • Achieved fleet-wide forced outage factor of 2.03% in 2009, compared to 3.29% in 2008
  • Delivered full-year natural gas-fired fleet starting reliability of 97% in 2009
• Geothermal Generation: Provided approximately 6.0 million MWh of renewable baseload generation with 94% capacity factor and 0.26% forced outage factor
• Natural Gas-fired Generation:
  • Increased production from gas-fired plants by nearly 3.0 million MWh, or 4%, despite reduced nationwide electric consumption
  • Successfully commissioned Otay Mesa Energy Center in California
  • Six Calpine facilities recognized during fourth quarter by the Texas Commission on Environmental Quality with Bronze Level membership in the Clean Texas Program
• Sustainable Cost Reductions: Reduced plant operating expense2, sales, general and administrative expense2 and components of other cost of revenue, largely through efficiency efforts and disciplined cost controls

2009 Commercial Operations Achievements:

• Customer-oriented growth:
  • Signed or began serving term contracts covering over 5,300 MW of capacity across our portfolio, leveraging the flexible nature of our fleet to provide value for our customers
  • Developed innovative solution for Los Angeles Department of Water and Power to offer wind integration services, helping our customer meet renewables targets while providing a reliable energy product
• Effective hedging: Maintained stable year-over-year Commodity Margin, despite declining commodity prices

 

FINANCIAL OUTLOOK

Table 4: Adjusted EBITDA and Adjusted Free Cash Flow Guidance

                                                                            Full Year 2010 (in millions) Adjusted EBITDA $ 1,500 – 1,600 Less: Operating lease payments 50 Major maintenance expense and capital expenditures(1) 290 Cash interest, net 750 Cash taxes   10 Adjusted Free Cash Flow $ 400 - 500  

(1) Includes projected Major Maintenance Expense of $178 million and maintenance Capital Expenditures of $112 million. Capital expenditures exclude major construction and development projects.

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

Today we are reaffirming our 2010 guidance, which includes Adjusted EBITDA of $1.5 billion to $1.6 billion, and Adjusted Free Cash Flow of $400 million to $500 million. We are also updating estimates of our growth capital for 2010. We expect to invest $135 million in growth-related projects during the year, including our ongoing turbine upgrade program, the addition of incremental steam wells at The Geysers, and the anticipated commencement of construction on the 120 MW upgrade of our Los Esteros plant and on our proposed 600 MW Russell City Energy Center.

 

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the fourth quarter and full year 2009, on Thursday, February 25, 2010, at 9:00 a.m. ET / 8:00 a.m. CT. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing 888-695-0608 (or 719-325-2236 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 our website. The recording also can be accessed by dialing 888-203-1112 (or 719-457-0820 for international listeners) and providing Confirmation Code 1737034. Presentation materials to accompany the conference call will be made available on our website on February 25, 2010.

 

ANNUAL MEETING DATE

Calpine’s Annual Meeting of Shareholders will be held on Wednesday, May 19, 2010, at 10:00 a.m. CT in Houston, Texas, at a location to be announced.

 

ABOUT CALPINE

Founded in 1984, Calpine Corporation 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 Corporation is committed to helping meet the needs of an economy that demands more and cleaner sources of electricity. 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 our website at www.calpine.com for more information.

Calpine’s Annual Report on Form 10-K for the year ended December 31, 2009, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC’s website at www.sec.gov.

 

FORWARD-LOOKING INFORMATION

In addition to historical information, this release 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,” “should,” “estimate,” “potential,” “project” 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, the timing and strength of an economic recovery, if any, and their 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;
• Financial results that may be volatile and may not reflect historical trends due to, among other things, fluctuations in prices for commodities such as natural gas and power, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks;
• Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
• 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;
• 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 and derivative transactions;
• Natural disasters such as hurricanes, earthquakes and floods, or acts of terrorism 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 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 wastewater 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;
• Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;
• Present and possible future claims, litigation and enforcement actions;
• The expiration or termination of our power purchase agreements and the related results on revenues; 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 Annual Report on Form 10-K for the year ended December 31, 2009.

Actual results or developments may differ materially from the expectations expressed or implied in the forward-looking statement. Unless specified otherwise, all information set forth in this release is as of today’s date, and we undertake no obligation to update any forward-looking statements, whether as a result of new information, future developments or otherwise. For additional information about our general business operations, please refer to our Annual Report on Form 10-K for the year ended December 31, 2009, 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 STATEMENTS OF OPERATIONS

    (Unaudited)   Three Months Ended December 31, Year Ended December 31, 2009 2008 2009 2008 (in millions, except share and per share amounts) Operating revenues $ 1,569 $ 1,968 $ 6,564 $ 9,937   Cost of revenue: Fuel and purchased energy expense 930 1,346 3,897 7,281 Plant operating expense 243 282 897 918

Depreciation and amortization expense

137 104 467 433 Operating asset impairments 4 33 4 33

Other cost of revenue

  21   26   84   114 Total cost of revenue   1,335   1,791   5,349   8,779 Gross profit 234 177 1,215 1,158

Sales, general and other administrative expense

52 61 183 215

(Income) loss from unconsolidated investments in power plants

(23 ) 40 (50 ) 229 Other operating expense   4   11   18   26 Income from operations 201 65 1,064 688 Interest expense 214 234 829 1,071 Interest (income) (3 ) (9 ) (16 ) (47 ) Debt extinguishment costs 27 — 76 13 Other (income) expense, net   8   (2 )   16   14

Income (loss) before reorganization items, income taxes and discontinued operations

(45 ) (158 ) 159 (363 ) Reorganization items   1   (39 )   (1 )   (302 )

Income(loss) before income taxes and discontinued operations

(46 ) (119 ) 160 (61 ) Income tax expense (benefit)   (2 )   13   15   (47 )

Income (loss) before discontinued operations

(44 ) (132 ) 145 (14 )

Discontinued operations, net of tax expense of $14 in 2008

  —   23   —   23 Net income $ (44 ) $ (109 ) $ 145 $ 9 Net loss attributable to the noncontrolling interest   1   —   4   1

Net income attributable to Calpine

$ (43 ) $ (109 ) $ 149 $ 10  

Basic earnings (loss) per common share:

Weighted average shares of common stock outstanding (in thousands)

485,776 485,135 485,659 485,054

Income (loss) before discontinued operations attributable to Calpine

(0.09 ) (0.27 ) 0.31 (0.03 )

Discontinued operations, net of tax, attributable to Calpine

  —   0.05   —   0.05

Net income (loss) per common share attributable to Calpine – basic

$ (0.09 ) $ (0.22 ) $ 0.31 $ 0.02   Diluted earnings (loss) per common share:

Weighted average shares of common stock outstanding (in thousands)

485,776 485,135 486,319 485,546

Income (loss) before discontinued operations attributable to Calpine

(0.09 ) (0.27 ) 0.31 (0.03 )

Discontinued operations, net of tax, attributable to Calpine

  —   0.05   —   0.05

Net income (loss) per common share attributable to Calpine – diluted

$ (0.09 ) $ (0.22 ) $ 0.31 $ 0.02    

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2009 and 2008

    2009 2008

(in millions, exceptshare and per share amounts)

ASSETS Current assets: Cash and cash equivalents $ 989 $ 1,657 Accounts receivable, net of allowance of $14 and $42 747 846 Accounts receivable, related party 3 4 Inventory 209 163 Margin deposits and other prepaid expense 490 776 Restricted cash, current 508 337 Derivative assets, current 1,119 3,653 Other current assets   34   64 Total current assets 4,099 7,500   Property, plant and equipment, net 11,583 11,908 Restricted cash, net of current portion 54 166 Investments 214 144 Long-term derivative assets 127 404 Other assets   573   616 Total assets $ 16,650 $ 20,738 LIABILITIES & STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable $ 578 $ 574 Accrued interest payable 54 85 Debt, current portion 463 716 Derivative liabilities, current 1,360 3,799 Income taxes payable 7 5 Other current liabilities   287   437 Total current liabilities 2,749 5,616   Debt, net of current portion 8,996 9,756 Deferred income taxes, net of current portion 54 93 Long-term derivative liabilities 197 698 Other long-term liabilities   208   203 Total liabilities 12,204 16,366   Stockholders’ equity:

Preferred stock, $.001 par value per share; authorized 100,000,000 shares, none issued and outstanding at December 31, 2009 and 2008

— —

Common stock, $.001 par value per share; authorized 1,400,000,000 shares, 443,325,827 shares issued and 442,998,255 shares outstanding at December 31, 2009 and 429,025,057 shares issued and 428,960,025 shares outstanding at December 31, 2008

1 1

Treasury stock, at cost, 327,572 shares and 65,032 shares at December 31, 2009 and December 31, 2008, respectively

(3 ) (1 ) Additional paid-in capital 12,256 12,217 Accumulated deficit (7,540 ) (7,689 ) Accumulated other comprehensive loss   (266 )   (158 ) Total Calpine stockholders’ equity 4,448 4,370 Noncontrolling interest   (2 )   2 Total stockholders’ equity   4,446   4,372 Total liabilities and stockholders’ equity $ 16,650 $ 20,738    

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2009 and 2008

                                  2009 2008 (in millions) Cash flows from operating activities: Net income $ 145 $ 9

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization expense(1) 556 544

(Income) loss from unconsolidated investments in power plants

(50 ) 229 Debt extinguishment costs 37 7 Deferred income taxes 16 27 Impairment loss 4 46 Gain on sale of discontinued operations — (37 ) Loss on disposal of assets, excluding reorganization items 37 36 Unrealized mark-to-market activity, net (89 ) (24 ) Return on investment in unconsolidated subsidiaries 11 — Stock-based compensation expense 38 50 Reorganization items (6 ) (359 ) Other 6 16

Change in operating assets and liabilities, net of effects of acquisitions:

Accounts receivable 108 375 Derivative instruments (118 ) 234 Other assets 235 (101 )

Accounts payable, liabilities subject to compromise and accrued expenses

(19 ) (215 ) Other liabilities   (150 )   (343 ) Net cash provided by operating activities   761   494 Cash flows from investing activities: Purchases of property, plant and equipment (179 ) (143 ) Proceeds from sale of power plants, turbines and investments — 413 Proceeds from sale of discontinued operations — 79

Cash acquired due to reconsolidation of the Canadian Debtors and other deconsolidated foreign entities

— 64 Contributions to unconsolidated investments (19 ) (17 ) Return of investment from unconsolidated investments 9 27 (Increase) decrease in restricted cash (59 ) 78 Cash effect of deconsolidation of VIEs — (2 ) Other   (2 )   17

Net cash provided by (used in) investing activities

  (250 )   516 Cash flows from financing activities: Repayments of notes payable

 

(106 )

 

(99 ) Borrowings from CCFC New Notes 955 — Repayments of CCFC Old Notes (781 ) (4 ) Borrowings from project financing 79 357 Repayments of project financing (121 ) (275 ) Repayments of DIP Facility — (98 ) Borrowings under First Lien Facilities — 4,248 Repayments on First Lien Facilities (785 ) (1,475 ) Borrowings under Commodity Collateral Revolver — 100 Repayments of Second Priority Debt — (3,672 ) Repayments on capital leases (43 ) (42 ) Redemptions of preferred interests (310 ) (166 ) Financing costs (65 ) (207 ) Derivative contracts classified as financing activities — 64 Other   (2 )   1 Net cash used in financing activities   (1,179 )   (1,268 ) Net decrease in cash and cash equivalents (668 ) (258 ) Cash and cash equivalents, beginning of period   1,657   1,915 Cash and cash equivalents, end of period $ 989 $ 1,657   Cash paid (received) during the period for: Interest, net of amounts capitalized $ 761 $ 1,060 Income taxes $ 7 $ 74 Reorganization items included in operating activities, net $ 5 $ 120 Reorganization items included in investing activities, net $ — $ (418 )  

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 $ 6 $ 13

Issuance of First Lien Notes in exchange for First Lien Credit Facility term loans

$ 1,200 $ — Amended Steamboat project debt $ 448 $ —

Settlement of liabilities subject to compromise through issuance of reorganized Calpine Corporation common stock

$ — $ 5,200

DIP Facility borrowings converted into exit financing under our 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 recorded in sales, general and other administrative expense and interest expense on our Consolidated 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 be viewed as a supplement to and not a substitute for our GAAP measures of performance.

Commodity Margin includes our power and steam revenues, sales of purchased power and natural gas, 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 revenues. 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. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. 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 December 31, 2009 and 2008:

                           

Three Months Ended December 31, 2009(in millions)

  Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 352 $ 139 $ 71 $ 53 $ — $ 615

Add: Mark-to-market commodity activity, net and other revenue(1)

23 8 (7 ) 9 (9 ) 24 Less: Plant operating expense 111 69 40 30 (7 ) 243 Depreciation and amortization expense 55 37 29 19 (3 ) 137 Other cost of revenue(2)   17   2   3   7   (4 )   25 Gross profit (loss) $ 192 $ 39 $ (8 ) $ 6 $ 5 $ 234    

Three Months Ended December 31, 2008(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 290 $ 139 $ 56 $ 51 $ — $ 536

Add: Mark-to-market commodity activity, net and other revenue(1)

(1 ) 81 30 (16 ) (8 ) 86 Less: Plant operating expense 125 89 44 35 (11 ) 282

Depreciation and amortization expense

47 30 15 16 (4 ) 104 Other cost of revenue(2)   17   3   36   5   (2 )   59 Gross profit (loss) $ 100 $ 98 $ (9 ) $ (21 ) $ 9 $ 177  

(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 Statements of Operations.

(2) Includes operating asset impairments of $4 million and $33 million for the three months ended December 31, 2009 and 2008, respectively.

 

The following table reconciles our Commodity Margin to its GAAP results for the years ended December 31, 2009 and 2008:

                           

Year Ended December 31, 2009(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 1,346 $ 644 $ 304 $ 268 $ — $ 2,562

Add: Mark-to-market commodity activity, net and other revenue(1)

143 (40 ) (5 ) 46 (44 ) 100 Less: Plant operating expense 437 232 134 91 3 897

Depreciation and amortization expense

205 125 79 66 (8 ) 467

Other cost of revenue(2)

  62   13   10   30   (32 )   83 Gross profit $ 785 $ 234 $ 76 $ 127 $ (7 ) $ 1,215    

Year Ended December 31, 2008(in millions)

Consolidation And West Texas Southeast North Elimination Total Commodity Margin $ 1,255 $ 726 $ 264 $ 279 $ — $ 2,524

Add: Mark-to-market commodity activity, net and other revenue(1)

(31 ) 195 36 (40 ) (28 ) 132 Less: Plant operating expense 434 267 128 108 (19 ) 918 Depreciation and amortization expense 190 124 69 56 (6 ) 433 Other cost of revenue(2)   71   12   59   26   (21 )   147 Gross profit $ 529 $ 518 $ 44 $ 49 $ 18 $ 1,158  

(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 Statements of Operations for the years ended December 31, 2009 and 2008.

(2) Excludes $5 million and nil of RGGI compliance costs for the years ended December 31, 2009 and 2008, respectively, which were included as a component of Commodity Margin and includes operating asset impairments of $4 million and $33 million for the years ended December 31, 2009 and 2008, respectively.

 

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our Net Income for the three and twelve months ended December 31, 2009 and 2008, as reported under GAAP.

  Three Months Ended December 31, Year Ended December 31, 2009 2008 2009 2008 (in millions) Net income attributable to Calpine $ (43 ) $ (109 ) $ 149 $ 10

Net loss attributable to noncontrolling interest

(1 ) — (4 ) (1 ) Discontinued operations, net of tax expense — (23 ) — (23 ) Income tax expense (benefit) (2 ) 13 15 (47 ) Reorganization items 1 (39 ) (1 ) (302 )

Other (income) expense and debt extinguishment costs, net

35 (2 ) 92 27 Interest expense, net   211   225   813   1,024 Income from operations $ 201 $ 65 $ 1,064 $ 688 Add: Adjustments to reconcile income from operations to Adjusted EBITDA:

Depreciation and amortization expense, excluding deferred financing costs(1)

141 110 480 467 Impairment loss 4 41 4 226 Major maintenance expense 50 72 174 190 Operating lease expense 12 11 47 46 Non-cash realized gains on derivatives — (7 ) — (40 )

Unrealized (gains) losses on commodity derivative mark-to-market activity

(19 ) (57 ) (79 ) (35 )

Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2),(3)

6 47 17 76 Stock-based compensation expense 8 14 38 50 Non-cash loss on dispositions of assets 3 25 32 34 Other(4)   2   4   5   (3 ) Adjusted EBITDA $ 408 $ 325 $ 1,782 $ 1,699 Less: Lease payments 12 47 46

Major maintenance expense and capital expenditures(5)

77 351 321 Cash interest(6) 206 773 794 Cash taxes — (5 ) 43 Other   —   7   — Adjusted Free Cash Flow(7)(8) $ 113 $ 609 $ 495  

(1) 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.

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

(3) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include $(13) million and $61 million in unrealized (gains) losses on mark-to-market activity for the three months ended December 31, 2009 and 2008, respectively, and $(47) million and $55 million in unrealized (gains) losses on mark-to-market activity for the years ended December 31, 2009 and 2008, respectively.

(4) Includes fees for letters of credit.

(5) Includes $52 million and $183 million in major maintenance expense for the three and twelve months ended December 31, 2009, respectively, and $25 million and $168 million in maintenance capital expenditures for the three and twelve months ended December 31, 2009, respectively. Includes $191 million in major maintenance expense and $130 million in maintenance capital expenditures for the twelve months ended December 31, 2008.

(6) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income.

(7) Excludes decrease (increase) in working capital of $71 million and $70 million for the three and twelve months ended December 31, 2009 and $(44) million for the twelve months ended December 31, 2008.

(8) Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. Results for the year ended December 31, 2008 have been recast to conform to this method.

 

In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and twelve months ended December 31, 2009 and 2008. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable GAAP measures are provided above.

  Three Months Ended December 31, Year Ended December 31, 2009 2008 2009 2008 (in millions) Commodity Margin $ 615 $ 536 $ 2,562 $ 2,524 Other revenue 5 22 21 57 Plant operating expense(1) (186 ) (180 ) (675 ) (670 ) Other cost of revenue(2) (7 ) (12 ) (28 ) (46 ) Sales, general and administrative expense(3) (46 ) (49 ) (152 ) (178 ) Adjusted EBITDA from unconsolidated investments in power plants(4) 29 7 67 26 Other operating expense(5) (4 ) (3 ) (18 ) (11 ) Other   2   4   5   (3 ) Adjusted EBITDA $ 408 $ 325 $ 1,782 $ 1,699  

(1) Shown net of major maintenance expense, stock-based compensation expense, and non-cash loss on dispositions of assets.

(2) Shown net of operating lease expense and depreciation and amortization. Excludes $5 million and nil of RGGI compliance costs for the years ended December 31, 2009 and 2008, respectively, which were included as a component of Commodity Margin.

(3) Shown net of depreciation and amortization and stock-based compensation expense.

(4) Shown net of impairments in 2008. Amount is comprised of income from unconsolidated investments in power plants, as well as adjustments to reflect Adjusted EBTIDA from unconsolidated investments.

(5) Shown net of impairments in 2008.

 

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance

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, adjustments to reflect Adjusted EBITDA from unconsolidated investments, and other items.

(2) Includes projected Major Maintenance Expense of $178 million and maintenance Capital Expenditures of $112 million. 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 years ended December 31, 2009 and 2008:

                                                    Year Ended December 31, 2009   2008 (in millions) Beginning cash and cash equivalents $ 1,657 $ 1,915 Net cash provided by (used in): Operating activities

761

494 Investing activities

(250

) 516 Financing activities   (1,179 )   (1,268 ) Net decrease in cash and cash equivalents   (668 )   (258 ) Ending cash and cash equivalents $ 989 $ 1,657  

OPERATING PERFORMANCE METRICS

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

  Three Months Ended December 31, Year Ended December 31, 2009 2008 2009 2008 Total MWh generated (1) (in thousands)   21,622   19,872   88,339   87,762 West 9,925 9,435 36,033 37,137 Texas 6,629 5,360 29,687 32,408 Southeast 3,528 3,762 17,370 12,820 North 1,540 1,315 5,249 5,397   Average availability 89.9 % 89.7 % 92.1 % 90.5 % West 92.3 % 87.6 % 92.3 % 89.1 % Texas 83.9 % 84.8 % 90.0 % 88.8 % Southeast 92.9 % 96.5 % 93.2 % 93.6 % North 92.5 % 94.2 % 94.7 % 92.6 %   Average capacity factor, excluding peakers 47.5 % 43.5 % 48.7 % 47.9 % West 70.4 % 66.4 % 64.1 % 65.9 % Texas 41.9 % 34.0 % 47.4 % 51.6 % Southeast 31.0 % 32.6 % 37.9 % 26.6 % North 36.3 % 32.4 % 31.1 % 32.8 %   Steam adjusted Heat Rate (mmbtu/kWh) 7,263 7,183 7,263 7,231 West 7,318 7,208 7,304 7,267 Texas 7,118 7,040 7,142 7,082 Southeast 7,331 7,210 7,299 7,388 North 7,441 7,545 7,614 7,584  

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