CPN Calpine Corp.

Calpine Corporation (NYSE:CPN):

Recent Achievements:

• Produced 28.2 million MWh of power in the third quarter of 2010, a 5% increase from the third quarter of 2009
• Agreed to sell a 25% undivided interest in 1,038 MW Freestone Energy Center for $830/kW plus operating and energy management fees
• Successfully issued $2.0 billion of 7.5% Senior Secured Notes due 2021, terming out nearly two-thirds of our 2014 debt maturities
• Restructured Broad River and South Point leases to simplify capital structure

Third Quarter 2010 Financial Results:

• $663 million of Adjusted EBITDA, an increase of 13% over 2009
• $368 million of Adjusted Recurring Free Cash Flow, an increase of 18% over 2009
• $852 million of Commodity Margin, an increase of 15% over 2009
• $217 million of Net Income1, a decrease of 9% from 2009

September YTD 2010 Financial Results:

• $1,326 million of Adjusted EBITDA, a decrease of 3% from 2009
• $472 million of Adjusted Recurring Free Cash Flow, a decrease of 5% from 2009
• $1,815 million of Commodity Margin, a decrease of 3% from 2009
• $55 million of Net Income1, a decrease of 71% from 2009

Raising and Tightening 2010 Full Year Guidance and Updating 2011 Full Year Guidance:

  2010       2011 (in millions) Adjusted EBITDA $

1,685 -

 

1,725

$

1,700 -

 

1,800

Adjusted Recurring Free Cash Flow $

500 -

 

540

$

440 -

 

540

 

Calpine Corporation (NYSE:CPN) today reported third quarter 2010 Adjusted EBITDA of $663 million, up $77 million, or 13%, over the prior year period. The company also reported third quarter 2010 Adjusted Recurring Free Cash Flow of $368 million, compared to $311 million in the third quarter of 2009. Net income1 for the quarter was $217 million, or $0.45 per diluted share, compared to $238 million, or $0.49 per diluted share, in the 2009 period.

“Our strong third quarter performance reflects our continuing focus on operating excellence. We reliably met our customers’ needs in the peak Summer period, while generating more megawatt hours this quarter than in the same quarter last year and while maintaining safety across our fleet. It also validated our vision of creating a geographically diversified portfolio of plants concentrated in the largest competitive markets to enable us to capitalize on variations in weather patterns,” said Jack Fusco, Calpine’s President and Chief Executive Officer.

“During the third quarter and since, we have continued to execute on the initiatives we outlined to investors by successfully integrating 19 plants in the Mid-Atlantic into our fleet following the July 1 close of the Conectiv acquisition; by further reducing the overhang of bankruptcy related issues; and by opportunistically improving shareholder value through asset-related transactions,” said Fusco. “With respect to the last initiative, I am pleased to announce that we have agreed to sell a 25% undivided interest in our Freestone Energy Center at $830/kW, plus operating and energy management fees going forward. Additionally, just last week the Colorado Public Utilities Commission approved the sale of our Rocky Mountain and Blue Spruce facilities to PSCo. at $794/kW, which we expect to close in early December. With respect to the bankruptcy overhang, our recently completed $2 billion bond offering has allowed us to further pay down the first lien term loan, reducing our refinancing risk and terming out our debt maturities. We still have a ways to go but it is my objective over the course of the next year to eliminate this overhang by refinancing the remaining first lien facility, giving us greater flexibility to deliver shareholder value; by addressing the 2008 interest rate hedges associated with the first lien term loan; and by resolving the remaining claims.”

“Finally, in keeping with our pledge to provide greater transparency and on the strength of our third quarter earnings, today we are raising and tightening our 2010 full year guidance for Adjusted EBITDA and Adjusted Recurring Free Cash Flow. We are now projecting 2010 Adjusted EBITDA of $1,685 to $1,725 million and Adjusted Recurring Free Cash Flow of $500 to $540 million. In addition, we are updating our guidance for 2011, with projected Adjusted EBITDA of $1,700 to $1,800 million and Adjusted Recurring Free Cash Flow of $440 to $540 million. When viewed against the backdrop of persistently difficult market conditions, our projections for 2011 are very encouraging and speak to the continued effectiveness of our hedging strategy,” said Fusco.

SUMMARY OF FINANCIAL PERFORMANCE

Third Quarter Results

Adjusted EBITDA grew to $663 million in the third quarter of 2010 compared to $586 million in the prior year period. The year-over-year improvement was primarily due to a $109 million increase in Commodity Margin. Our North segment, where Commodity Margin increased $163 million compared to 2009, benefited from the integration of our Mid-Atlantic fleet as of July 1, 2010. This increase was offset, in part, by decreases of $30 million and $22 million in our West and Texas segments, respectively. These declines resulted from lower average hedge prices and lower realized heat rates associated with weaker market conditions in the third quarter of 2010 as compared to the same period in 2009. In addition, the West region experienced a $26 million decline in Commodity Margin as a result of the expiration of the PCF arrangement in the fourth quarter of 2009, offset by a $13 million increase related to higher renewable energy credit (REC) revenue from new contracts associated with our Geysers power plants and an increase of $16 million related to our Otay Mesa Energy Center (OMEC), which achieved commercial operation in October 2009 and was consolidated on January 1, 2010.

The overall increase in Commodity Margin was offset, in part, by a $26 million increase in normal recurring plant operating expense2 that largely resulted from the addition of our Mid-Atlantic plants during the third quarter of 2010 and of OMEC during the fourth quarter of 2009.

Net income1 remained stable at $217 million for the three months ended September 30, 2010, compared to $238 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 increased from $196 million in 2009 to $297 million in 2010. The increase was primarily attributable to the $109 million improvement in Commodity Margin previously discussed.

Year-to-Date Results

Adjusted EBITDA for the nine months ended September 30, 2010, was $1,326 million, down modestly from $1,374 million in the prior year period. The year-over-year decline in Adjusted EBITDA was primarily caused by a $56 million decrease in Commodity Margin that was driven primarily by our West and Texas segments, where Commodity Margin decreased by $109 million and $105 million, respectively. Lower average hedge margins and lower realized heat rates due to weaker market conditions impacted both regions. In addition, Commodity Margin in the West segment was negatively impacted by a $77 million decrease attributable to the expiration of the PCF arrangement at the end of 2009, offset, in part, by increases of $56 million in Commodity Margin from OMEC and $39 million related to higher REC revenue from new contracts associated with our Geysers power plants. The declines in Commodity Margin in the West and Texas regions were offset, in part, by a $175 million increase in Commodity Margin from our North region, which was primarily driven by the Mid-Atlantic plants we acquired as of the third quarter of 2010.

In addition to the decline in Commodity Margin, Adjusted EBITDA for the nine-month period was also negatively impacted by a $28 million year-over-year increase in normal recurring plant operating expense2, most of which was due to the addition of our Mid-Atlantic plants in July 2010 and the start-up of OMEC in October 2009. This increase in plant operating expense was offset by a $30 million decrease in sales, general and administrative expense3 that resulted from a contract settlement benefit in the first quarter of 2010, as well as lower personnel and consulting expenses throughout the nine-month period.

Cash flows provided by operating activities for the nine months ended September 30, 2010, improved to $783 million compared to $537 million for the same period in 2009. The change in cash flows from operating activities is primarily due to an increase in gross profit, excluding non-cash items, of $62 million in 2010 resulting primarily from the addition of our Mid-Atlantic plants and increased realized gains on financial hedges, partially offset by lower Commodity Margins in our Texas and West segments. In addition, working capital employed decreased by approximately $172 million during the period, after adjusting for debt related balances that did not impact cash provided by operating activities. The decrease was primarily due to reductions in margin deposits and certain derivative activity. Lastly, cash paid for interest decreased by $75 million for the nine months ended September 30, 2010, primarily due to the refinancing of portions of our first lien term loans, CCFC and other project financing. These decreases were partially offset by an increase in net cash paid for taxes of $26 million, primarily due to Canadian tax refunds received in the third quarter of 2009 with no similar activity in the nine months ended September 30, 2010.

Net income1 decreased to $55 million for the nine months ended September 30, 2010, from $192 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, decreased from $153 million in 2009 to $99 million in 2010. The decrease was largely driven by the $56 million decline in Commodity Margin, as well as a $21 million increase in income tax expense primarily attributable to non-cash changes in our intraperiod tax allocations, partially offset by the decrease in sales, general and administrative expense, as previously discussed.

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

2 Normal recurring plant operating expense excludes major maintenance expense, stock-based compensation expense and non-cash loss on disposition of assets. See the table titled “Consolidated Adjusted EBITDA Reconciliation” for the actual amounts of these items for the three and nine months ended September 30, 2010 and 2009.

3 Decrease in sales, general and administrative expense excludes changes in stock-based compensation, depreciation and amortization and acquisition-related costs. See the table titled "Consolidated Adjusted EBITDA Reconciliation" for the actual amounts of these items for the nine months ended September 30, 2010 and 2009.

Table 1: Summarized Consolidated Condensed Statements of Operations

  (Unaudited) Three Months Ended September 30,   Nine Months Ended September 30, 2010   2009 2010   2009 (in millions) Operating revenues $ 2,130 $ 1,822 $ 5,074 $ 4,919 Cost of revenue   1,511   1,342   4,125   3,984 Gross profit 619 480 949 935 SG&A, (income) loss from unconsolidated investments in power plants and other operating expense   65   57   137   119 Income from operations 554 423 812 816 Net interest expense, debt extinguishment costs and other (income) expense   335   212   750   646 Income before reorganization items, income taxes and discontinued operations 219 211 62 170 Reorganization items — (8 ) — (2 ) Income tax expense (benefit)   21   (7 )   38   17 Income before discontinued operations 198 226 24 155 Discontinued operations, net of tax expense   19   11   31   34 Net income 217 237 55 189 Net loss attributable to the noncontrolling interest   —   1   —   3 Net income attributable to Calpine $ 217 $ 238 $ 55 $ 192   Reorganization items(1) — (8 ) — (2 ) Other items(1)(2)   115   10   141   30 Net income, net of reorganization and other items 332 240 196 220 Unrealized MtM gains on derivatives(1)(3)   (35 )   (44 )   (97 )   (67 ) Net income, net of reorganization items, other items and unrealized MtM impacts $ 297 $ 196 $ 99 $ 153

(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 for the three and nine months ended September 30, 2010, include $70 million of interest expense associated with the reclassification of the unrealized loss on interest rate swaps that no longer qualified as cash flow hedges in the third quarter of 2010; $20 million and $27 million, respectively, in debt extinguishment costs; $19 million in impairment of development costs related to a pre-bankruptcy project; and $6 million and $25 million, respectively, in costs related to the Conectiv acquisition. Other items for 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.

(3)

Represents unrealized mark-to-market (MtM) gains 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. Includes amounts related to Blue Spruce and Rocky Mountain for the three and nine months ended September 30, 2009.

 

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

      Three Months Ended September 30, Nine Months Ended September 30, 2010   2009 2010   2009   West $ 338 $ 368 $ 809 $ 918 Texas 165 187 400 505 North 259 96 390 215 Southeast   90   92   216   233 Total $ 852 $ 743 $ 1,815 $ 1,871  

West: Commodity Margin in our West segment decreased by $30 million for the three months ended September 30, 2010, compared to the same period in 2009, primarily resulting from a decrease of $26 million related to the expiration of the PCF arrangement in the fourth quarter of 2009, lower average hedge prices for the third quarter of 2010 compared to 2009, and lower realized spark spreads on our open positions due to lower market heat rates caused by cooler weather in the third quarter of 2010, plus an overall increase in installed generation capacity in California in 2010 compared to the same period in 2009. The decrease in Commodity Margin was partially offset by an increase of $13 million related to higher REC revenue from new contracts associated with our Geysers assets and $16 million from OMEC that achieved commercial operation in October 2009 and was consolidated on January 1, 2010.

For the nine-month period, Commodity Margin in our West segment decreased by $109 million primarily resulting from a decrease of $77 million related to the expiration of the PCF arrangement in the fourth quarter of 2009, lower average hedge prices in 2010 compared to 2009, lower realized spark spreads on our open positions due to lower market heat rates caused primarily by cooler temperatures in 2010 compared to 2009 and an overall increase in installed generation capacity in California in 2010. Also contributing to the unfavorable period over period change was a decrease of $11 million for the sale of surplus emission allowances in the first quarter of 2009, which did not reoccur in the same period in 2010. The decrease in Commodity Margin was partially offset by an increase of $39 million related to higher REC revenue from new contracts associated with our Geysers assets; $56 million from OMEC, which achieved commercial operation in October 2009 and was consolidated on January 1, 2010; and a $12 million credit recognized in the second quarter of 2010 related to overcharges associated with a gas transportation contract.

Texas: Commodity Margin in our Texas segment decreased by $22 million for the three months ended September 30, 2010, compared to the same period in 2009, primarily resulting from lower average hedge prices and lower realized spark spreads on open positions due to lower market heat rates caused by an overall increase in installed generation capacity in ERCOT for the third quarter of 2010 compared to the same period in 2009.

Commodity Margin in our Texas segment decreased by $105 million for the nine months ended September 30, 2010, compared to the same period in 2009, primarily resulting from lower average hedge prices and lower realized spark spreads on open positions. The lower realized spark spreads were due to lower market heat rates, particularly with regard to June 2010, which did not benefit from the extreme heat, congestion-driven pricing and tighter reserve margins that occurred in June 2009, and an overall increase in installed generation capacity in ERCOT in 2010 compared to 2009.

North: Commodity Margin in our North segment increased by $163 million primarily due to the Mid-Atlantic fleet acquisition which closed on July 1, 2010, higher average hedge prices and higher realized spark spreads on open positions driven by much warmer weather for July and September 2010 compared to the same periods in 2009.

Commodity Margin in our North segment increased by $175 million for the nine months ended September 30, 2010, compared to the same period in 2009. The nine-month results were largely impacted by the same factors that drove performance for the third quarter, as previously discussed.

Southeast: Commodity Margin in our Southeast segment for the three months ended September 30, 2010, remains comparable to the same period in 2009. The marginal decrease resulted from higher natural gas generation displacement of coal generation in certain sub-markets in our Southeast segment in the third quarter of 2009 largely offset by higher realized spark spreads on open positions due to warmer weather for the three months ended September 30, 2010, compared to the same period in 2009.

Commodity Margin in our Southeast segment decreased by $17 million for the nine months ended September 30, 2010, compared to the same period in 2009, primarily as a result of lower average hedge prices and lower realized spark spreads for our Oneta and Pine Bluff power plants for the first half of 2010 compared to the same period in 2009. During the first six months of 2009, in contrast to the same period in 2010, these plants were advantaged by lower delivered natural gas prices relative to many of our competitors, driving higher realized spark spreads. The decrease in the Commodity Margin was partially offset by higher realized spark spreads on open positions throughout the rest of the Southeast region (excluding our Oneta and Pine Bluff power plants) caused by warmer weather in May and June 2010, as well as the non-recurring negative impact from the settlement of a disputed steam contract in the second quarter of 2009.

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Corporate Liquidity

        September 30, December 31, 2010 2009 (in millions) Cash and cash equivalents, corporate(1) $ 610 $ 725 Cash and cash equivalents, non-corporate   304   264 Total cash and cash equivalents 914 989 Restricted cash 341 562 Letter of credit availability(2) 40 34 Revolver availability   805   794 Total current liquidity $ 2,100 $ 2,379

(1)

 

Includes $62 million and $9 million of margin deposits held by us posted by our counterparties as of September 30, 2010, and December 31, 2009, respectively.

(2)

Includes availability under Calpine Development Holdings, Inc. at September 30, 2010.

 

Liquidity remained strong during the third quarter at $2.1 billion, even after accounting for the acquisition of our Mid-Atlantic fleet. As previously discussed, operating activities for the nine months ended September 30, 2010, resulted in net cash proceeds of $783 million, compared to $537 million during the 2009 period. In addition, cash flows from investing activities resulted in a net outflow of $1,585 million during the first nine months of 2010 compared to an outflow of $164 million in the 2009 period. The 2010 activity was driven largely by the previously mentioned purchase of our Mid-Atlantic fleet during the third quarter, offset in part by reduced restricted cash balances associated primarily with the maturity of our PCF project financing instrument. Cash flows from financing activities for the nine months ended September 30, 2010, resulted in a net inflow of $727 million, primarily as a result of the addition of a term loan whose proceeds were used to fund a portion of our Mid-Atlantic acquisition, offset by our repayment of the PCF financing and other payments made under project debt waterfall provisions.

During the nine months ended September 30, 2010, we generated $472 million of Adjusted Recurring Free Cash Flow, compared to $495 million in the 2009 period. The year-over-year decline was primarily the result of the $48 million decrease in Adjusted EBITDA, as previously discussed, and a $32 million increase in cash interest, net, due primarily to the addition of term loan debt used to fund our Mid-Atlantic fleet acquisition, as well as an increase in the annualized effective interest rates on our consolidated debt. These decreases were partially offset by a $62 million decrease in major maintenance expense and capital expenditures from 2009 to 2010.

Progressing toward our goals of efficiently managing our balance sheet and ensuring financial stability, we recently completed the placement of $2.0 billion in aggregate principal amount of 7.50% Senior Secured Notes due 2021, the proceeds of which were used to repay a portion of our term loan borrowings under our existing first lien facility. In addition, we have commitments to refinance our existing $1.0 billion first lien revolver. “We have now addressed approximately $5.0 billion of the original $6.3 billion in 2014 maturities under the first lien term loan,” said Zamir Rauf, Calpine’s Chief Financial Officer. “This has substantially reduced our refinancing risk and represents meaningful progress toward establishing a longer-dated and more balanced maturity profile while transitioning to a more flexible covenant package that should provide us with more options to improve shareholder value. We will continue to be opportunistic about refinancing the balance of the first lien facility.”

In addition to the bond offering, liquidity and capital flexibility have been further enhanced by the sale of a 25% undivided interest in our 1,038 MW Freestone Energy Center, which is expected to close in the fourth quarter of 2010, but no later than the first quarter of 2011. Under the terms of the sale, we will receive $215 million in immediate proceeds upon closing and will collect annual operating and energy management fees going forward.

Finally, during the third quarter, we completed a restructuring of the leases for our Broad River Energy Center and South Point Energy Center, whereby we will purchase the equity interest in the power plants for $320 million. The purchase price consists of approximately $38 million in cash and assumed incremental debt of approximately $70 million. The transaction requires FERC approval and is expected to close in the fourth quarter of 2010. In addition to providing us with more strategic and operational flexibility, this transaction simplifies our capital structure by consolidating the leases for financial reporting purposes.

PLANT DEVELOPMENT

York Energy Center: We acquired the 565 MW dual-fuel, combined-cycle power plant under construction in Peach Bottom Township, Pa., formerly referred to as the Delta Project, as part of our acquisition of our Mid-Atlantic fleet. The York Energy Center remains on budget and on schedule, with the first fire of the gas turbines now successful. All permits have been received, and commercial operations are expected to commence in June 2011. The York Energy Center will sell power under a six-year Power Purchase Agreement (PPA) with a third party.

Russell City Energy Center: Russell City Energy Center remains under advanced stages of development. The Russell City Energy Center is currently contracted to deliver its full output to Pacific Gas & Electric (PG&E) under a PPA that was executed in December 2006 and approved by the California Public Utilities Commission in January 2007. The PPA was amended in 2008 and again on April 9, 2010, to extend the expected commercial operations date to June 2013 as a result of delays in obtaining certain permits. We are in possession of all material permits. Completion of the Russell City Energy Center is dependent upon completion of certain administrative appeals processes associated with our air permit. Upon completion, this project would bring on line approximately 372 MW of net interest baseload capacity (402 MW with peaking capacity) representing our 65% share.

Los Esteros Expansion: During 2009, we and PG&E negotiated a new PPA to replace the existing California Department of Water Resources contract and facilitate the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation power 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. The PPA and related agreements with PG&E have received all of the necessary approvals and are now effective. We are amending our California Energy Commission license and emissions limits and are in the process of procuring equipment and selecting the engineering, procurement and construction contractors.

Geysers Expansion: We continue to look to expand production from our Geysers Assets. In the fourth quarter of 2009, we started drilling additional wells and have made expenditures of approximately $55 million during the first nine months of 2010 related to these expansion efforts. We have completed drilling 13 planned test wells, establishing capacity for approximately 42 MW of additional steam generation. Reservoir and economic modeling of the results obtained from the drilling is currently being performed. We expect to make a determination in the first quarter of 2011 as to whether the new wells will produce enough additional steam to warrant the construction of additional geothermal power plants at our Geysers Assets. Additionally, we are currently seeking to take advantage of certain incentives under the American Recovery and Reinvestment Act of 2009, also referred to as the Stimulus Bill. We expect that new geothermal power plant development will qualify for at least a 10% cash grant.

Turbine Upgrades: We continue to move forward with our turbine upgrade program and have entered an agreement to upgrade select GE and Siemens turbines. As of September 30, 2010, we had completed the upgrade of four Siemens turbines and have agreed to upgrade approximately 14 additional Siemens and GE turbines (and may upgrade additional turbines in the future). Our turbine upgrade program is expected to increase our generation capacity in total by approximately 245 MW. These upgrades began in the fourth quarter of 2009 and are scheduled through 2014.

OPERATIONS UPDATE

2010 Power Operations Achievements:

• Safety Performance:
  • First quartile lost-time incident rate of 0.20 year-to-date
  • No employee lost-time accidents recorded during the third quarter of 2010
• Availability Performance:
  • Achieved a strong third quarter geothermal availability factor of 99.94%
  • Maintained third quarter fleet-wide average availability factor of nearly 96%
  • Achieved fleet-wide starting reliability of 98%
• Geothermal Generation: Provided approximately 1.5 million MWh of renewable baseload generation with 94% capacity factor and 0.06% forced outage factor
• Natural Gas-fired Generation:
  • North segment increased production by nearly 3.2 million MWh
  • Broad River: 94 starts, 100% starting reliability in September
  • Hermiston: 100% availability and capacity factors in September

2010 Commercial Operations Achievements:

• Customer-oriented Growth:
  • Signed an agreement with Bonneville Power Association to provide up to 75 MW of generation flexibility from Hermiston Power Project
  • Received approval of PPA contracts totaling 1,250 MW with SDG&E and PG&E from the California Public Utilities Commission
• Portfolio Optimization:
  • Announced the sale of a 25% undivided interest in 1,038 MW Freestone Energy Center for $830/kW plus operating and energy management fees
  • Received approval from Colorado Public Utilities Commission for previously announced sale of Blue Spruce Energy Center and Rocky Mountain Energy Center to PSCo. for $739 million

FINANCIAL OUTLOOK

Table 4: Adjusted EBITDA and Adjusted Recurring Free Cash Flow Guidance

        Full Year 2010 Full Year 2011 (in millions) Adjusted EBITDA $ 1,685 – 1,725 $ 1,700 – 1,800 Less: Operating lease payments 45 30 Major maintenance expense and capital expenditures(1) 315 390 Recurring cash interest, net 810 825 Cash taxes   15   15 Adjusted Recurring Free Cash Flow $ 500 - 540 $ 440 – 540 Non-recurring interest rate swap payments(2) 25 110

(1)

 

Includes projected Major Maintenance Expense of $175 million and $235 million in 2010 and 2011, respectively, and maintenance Capital Expenditures of $140 million and $155 million in 2010 and 2011, respectively. Capital Expenditures exclude major construction and development projects.

(2)

Interest payments related to legacy LIBOR hedges associated with floating rate first lien credit facility, which has been substantially refinanced.

 

We are updating and tightening our 2010 guidance, which includes the estimated impact of the planned sale of our Colorado power plants. Including this transaction, we are projecting Adjusted EBITDA of $1,685 million to $1,725 million and Adjusted Recurring Free Cash Flow of $500 million to $540 million. Today, we are also updating our 2011 guidance. We project Adjusted EBITDA of $1,700 million to $1,800 million and Adjusted Recurring Free Cash Flow of $440 million to $540 million.

We expect to invest $35 million and $110 million in growth-related projects during 2010 and 2011, respectively, including our ongoing turbine upgrade program, our 565 MW York Energy Center, and the 120 MW upgrade of our Los Esteros plant. In addition, we expect to spend a total of $95 million between 2010 and 2011 on our proposed 619 MW Russell City Energy Center, the distribution of which between the years will depend upon the project’s draw schedule and our equity partner’s elections.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the third quarter of 2010 on Friday, October 29, 2010, at 10 a.m. ET/9 a.m. CT. A listen-only webcast of the call may be accessed through our website at www.calpine.com or by dialing 888-293-6960 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 5880624. Presentation materials to accompany the conference call will be made available on our website on October 29, 2010.

ABOUT CALPINE

Founded in 1984, Calpine Corporation is a major U.S. power company, currently capable of delivering nearly 29,000 megawatts of clean, cost-effective, reliable and fuel-efficient power from its 93 operating plants to customers and communities in 21 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 primarily 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, 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 press release contains “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the Exchange Act. 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 existing financing obligations, including our First Lien Credit Facility, First Lien Notes and New Development Holdings Project Debt;
• 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;
• Our planned sale of Blue Spruce and Rocky Mountain may not close as planned;
• Future PJM capacity revenues expected from the Conectiv Acquisition may not occur at expected levels; and
• Other risks identified in this release or in our reports and registration statements filed with the SEC, including, without limitation, the risk factors identified in our Quarterly Report on Form 10-Q for the three months ended September 30, 2010, and in our Annual Report on Form 10-K for the year ended December 31, 2009.

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of today’s date. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.

CALPINE CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

    Three Months Ended September 30, Nine Months Ended September 30, 2010   2009 2010   2009 (in millions, except share and per share amounts) Operating revenues $ 2,130 $ 1,822 $ 5,074 $ 4,919   Cost of revenue: Fuel and purchased energy expense 1,143 1,030 3,016 2,967 Plant operating expense 199 189 630 638 Depreciation and amortization expense 149 104 414 317 Other cost of revenue   20   19   65   62 Total cost of revenue   1,511   1,342   4,125   3,984 Gross profit 619 480 949 935 Sales, general and other administrative expense 44 38 122 131 (Income) loss from unconsolidated investments in power plants (1 ) 13 (14 ) (27 ) Other operating expense   22   6   29   15 Income from operations 554 423 812 816 Interest expense 314 195 722 604 Interest (income) (2 ) (3 ) (8 ) (13 ) Debt extinguishment costs 20 16 27 49 Other (income) expense, net   3   4   9   6 Income before reorganization items, income taxes and discontinued operations 219 211 62 170 Reorganization items   —   (8 )   —   (2 ) Income before income taxes and discontinued operations 219 219 62 172 Income tax expense (benefit)   21   (7 )   38   17 Income before discontinued operations 198 226 24 155 Discontinued operations, net of tax expense   19   11   31   34 Net income 217 237 55 189 Net loss attributable to the noncontrolling interest   —   1   —   3 Net income attributable to Calpine $ 217 $ 238 $ 55 $ 192   Basic earnings per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) 486,088 485,736 486,023 485,619 Income before discontinued operations attributable to Calpine $ 0.41 $ 0.47 $ 0.05 $ 0.33 Discontinued operations, net of tax expense, attributable to Calpine   0.04   0.02   0.06   0.07 Net income per common share – basic $ 0.45 $ 0.49 $ 0.11 $ 0.40   Diluted earnings per common share attributable to Calpine: Weighted average shares of common stock outstanding (in thousands) 487,443 486,585 487,199 486,171 Income before discontinued operations attributable to Calpine $ 0.41 $ 0.47 $ 0.05 $ 0.32 Discontinued operations, net of tax expense, attributable to Calpine   0.04   0.02   0.06   0.07 Net income per common share – diluted $ 0.45 $ 0.49 $ 0.11 $ 0.39  

CALPINE CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

        September 30, December 31, 2010 2009 (in millions, except share and per share amounts) ASSETS Current assets: Cash and cash equivalents $ 914 $ 989 Accounts receivable, net of allowance of $3 and $14 718 750 Margin deposits and other prepaid expense 253 490 Restricted cash, current 296 508 Derivative assets, current 1,321 1,119 Assets held for sale 545 — Inventory and other current assets   295   243 Total current assets 4,342 4,099   Property, plant and equipment, net 12,915 11,583 Restricted cash, net of current portion 45 54 Investments 69 214 Long-term derivative assets 318 127 Other assets   693   573 Total assets $ 18,382 $ 16,650 LIABILITIES & STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable $ 523 $ 578 Accrued interest payable 132 54 Debt, current portion 574 463 Derivative liabilities, current 1,247 1,360 Liabilities held for sale 11 — Other current liabilities   299   294 Total current liabilities 2,786 2,749   Debt, net of current portion 10,043 8,996 Deferred income taxes, net of current portion 159 54 Long-term derivative liabilities 499 197 Other long-term liabilities   275   208 Total liabilities 13,762 12,204   Commitments and contingencies Stockholders’ equity: Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding — — Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 444,949,620 and 443,325,827 shares issued, respectively, and 444,501,702 and 442,998,255 shares outstanding, respectively 1 1 Treasury stock, at cost, 447,918 and 327,572 shares, respectively (5 ) (3 ) Additional paid-in capital 12,275 12,256 Accumulated deficit (7,485 ) (7,540 ) Accumulated other comprehensive loss (166 ) (266 ) Total Calpine stockholders’ equity 4,620 4,448 Noncontrolling interest — (2 ) Total stockholders’ equity   4,620   4,446 Total liabilities and stockholders’ equity $ 18,382 $ 16,650  

CALPINE CORPORATION AND SUBSIDIARIES

 

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

        Nine Months Ended September 30, 2010 2009 (in millions) Cash flows from operating activities: Net income $ 55 $ 189 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization expense(1) 464 399 Debt extinguishment costs 27 9 Deferred income taxes 40 15 Impairment loss 19 — Loss on disposal of assets 11 29 Unrealized mark-to-market activity, net (97 ) (67 ) Income from unconsolidated investments in power plants (14

)

(27 ) Return on investment in unconsolidated subsidiaries 11 2 Stock-based compensation expense 18 30 Other 1

 

(3

)

Change in operating assets and liabilities: Accounts receivable 34

 

(23

)

Derivative instruments, net (42 ) (239 ) Other assets 241 387 Accounts payable and accrued expenses (1 ) 13 Other liabilities     16     (177 ) Net cash provided by operating activities     783     537   Cash flows from investing activities: Purchases of property, plant and equipment (191 ) (140 ) Purchase of Conectiv assets (1,634 ) — Cash acquired due to consolidation of Otay Mesa Energy Center 8 — Contributions to unconsolidated investments — (19 ) (Increase) decrease in restricted cash 228 (2 ) Other     4     (3 ) Net cash used in investing activities     (1,585 )   (164 ) Cash flows from financing activities: Repayments of project financing, notes payable and other $ (472 ) $ (1,339 ) Borrowings from project financing, notes payable and other 1,272 1,028 Issuance of First Lien Notes 1,491 — Repayments on First Lien Credit Facility (1,507 ) (770 ) Financing costs (67 ) (34 ) Refund of financing costs 10 — Other   —     (2 ) Net cash provided by (used in) financing activities   727     (1,117 ) Net decrease in cash and cash equivalents (75 ) (744 ) Cash and cash equivalents, beginning of period   989     1,657   Cash and cash equivalents, end of period $ 914   $ 913   Cash paid during the period for: Interest, net of amounts capitalized $ 488 $ 563 Income taxes $ 11 $ 6 Reorganization items included in operating activities, net $ — $ 5   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 $ (5 ) $ 3 Purchase of Conectiv assets included in accounts payable $ 6 $ —

(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 Recurring 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 U.S. 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, fuel transportation expense, RGGI compliance and other environmental 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 U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

Adjusted EBITDA represents earnings 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 U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly titled measures reported by other companies.

Adjusted Recurring 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 Recurring Free Cash Flow is presented because our management uses this measure, among others, to make decisions about capital allocation. Adjusted Recurring 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 tables reconcile our Commodity Margin to its GAAP results for the three months ended September 30, 2010 and 2009 (in millions):

  Three Months Ended September 30, 2010 West   Texas   North   Southeast ConsolidationAndElimination Total Commodity Margin $ 338 $ 165 $ 259 $ 90 $ — $ 852 Add: Mark-to-market commodity activity, net and other revenue(1) 42 62 18 18 (6 ) 134 Less: Plant operating expense 86 55 38 28 (8 ) 199 Depreciation and amortization expense 50 36 37 28 (2 ) 149 Other cost of revenue(2)   12   —   5   —   2   19 Gross profit $ 232 $ 136 $ 197 $ 52 $ 2 $ 619   Three Months Ended September 30, 2009 West Texas North Southeast ConsolidationAndElimination Total Commodity Margin $ 368 $ 187 $ 96 $ 92 $ — $ 743 Add: Mark-to-market commodity activity, net and other revenue(1) 41 2 21 (4 ) (12 ) 48 Less: Plant operating expense 92 35 18 27 17 189 Depreciation and amortization expense 45 27 16 17 (1 ) 104 Other cost of revenue(2)   17   6   10   3   (18 )   18 Gross profit (loss) $ 255 $ 121 $ 73 $ 41 $ (10 ) $ 480

(1)

 

Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations for the three months ended September 30, 2010 and 2009.

(2)

Excludes $1 million of RGGI compliance and other environmental costs for both the three months ended September 30, 2010 and 2009, which are included as a component of Commodity Margin.

 

The following tables reconcile our Commodity Margin to its GAAP results for the nine months ended September 30, 2010 and 2009 (in millions):

  Nine Months Ended September 30, 2010 West   Texas North   Southeast   ConsolidationAndElimination Total Commodity Margin $ 809 $ 400 $ 390 $ 216 $ — $ 1,815 Add: Mark-to-market commodity activity, net and other revenue(1) 60 148 18 31 (20) 237 Less: Plant operating expense 264 217 83 87 (21) 630 Depreciation and amortization expense 151 110 75 83 (5) 414 Other cost of revenue(2)   37   1   19   2   —   59 Gross profit $ 417 $ 220 $ 231 $ 75 $ 6 $ 949   Nine months Ended September 30, 2009 West Texas North Southeast ConsolidationAndElimination Total Commodity Margin $ 918 $ 505 $ 215 $ 233 $ — $ 1,871 Add: Mark-to-market commodity activity, net and other revenue(1) 120 (48 ) 37 2 (35 ) 76 Less: Plant operating expense 310 163 61 94 10 638 Depreciation and amortization expense 137 88 47 50 (5 ) 317 Other cost of revenue(2)   44   11   23   7   (28 )   57 Gross profit $ 547 $ 195 $ 121 $ 84 $ (12 ) $ 935

(1)

 

Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations for the nine months ended September 30, 2010 and 2009.

(2)

Excludes $6 million and $5 million of RGGI compliance and other environmental costs for the nine months ended September 30, 2010 and 2009, respectively, which are included as a component of Commodity Margin.

 

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted Recurring Free Cash Flow to our net income attributable to Calpine for the three and nine months ended September 30, 2010 and 2009, as reported under GAAP.

  Three Months Ended September 30,   Nine Months Ended September 30, 2010   2009 2010   2009 (in millions) GAAP net income attributable to Calpine $ 217 $ 238 $ 55 $ 192 Net loss attributable to noncontrolling interest — (1 ) — (3 ) Discontinued operations, net of tax expense (19 ) (11 ) (31 ) (34 ) Income tax expense (benefit) 21 (7 ) 38 17 Reorganization items — (8 ) — (2 ) Other (income) expense and debt extinguishment costs, net 23 20 36 55 Interest expense, net 312 192 714 591 Income from operations $ 554 $ 423 $ 812 $ 816 Add: Adjustments to reconcile income from operations to Adjusted EBITDA: Depreciation and amortization expense, excluding deferred financing costs(1) 151 106 424 326 Impairment loss 19 — 19 — Major maintenance expense 13 19 111 121 Operating lease expense 11 12 33 35 Unrealized gains on commodity derivative mark-to-market activity (131 ) (43 ) (212 ) (60 ) Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3) 10 28 25 11 Stock-based compensation expense 6 8 18 30 Non-cash loss on dispositions of assets 2 12 7 29 Conectiv acquisition-related costs 6 — 25 — Other(4)   2   (1 )   3   3 Adjusted EBITDA from continuing operations 643 564 1,265 1,311 Adjusted EBITDA from discontinued operations   20   22   61   63 Total adjusted EBITDA $ 663 $ 586 $ 1,326 $ 1,374 Less: Lease payments 11 12 33 35 Major maintenance expense and capital expenditures(5) 65 74 211 273

Cash interest, net(6)

217 184 601 569 Cash taxes 2 3 10 (5 ) Other   —   2   (1 )   7 Adjusted Recurring Free Cash Flow(7)(8) $ 368 $ 311 $ 472 $ 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 Condensed Statements of Operations in income from unconsolidated investments in power plants.

(3)

Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized gains (losses) on mark-to-market activity of $(1) and $(7) million for the three months ended September 30, 2010 and 2009, respectively, and $(1) and $34 million for the nine months ended September 30, 2010 and 2009, respectively.

(4)

Includes fees for letters of credit.

(5)

Includes $16 million and $120 million in major maintenance expense for the three and nine months ended September 30, 2010, respectively, and $49 million and $91 million in maintenance capital expenditures for the three and nine months ended September 30, 2010, respectively. Includes $29 million and $131 million in major maintenance expense for the three and nine months ended September 30, 2009, respectively, and $45 million and $142 million in maintenance capital expenditures for the three and nine months ended September 30, 2009, respectively.

(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 (increase) decrease in working capital of $48 million and $(32) million for the three and nine months ended September 30, 2010, and $(20) million and $(9) million for the three and nine months ended September 30, 2009.

(8)

Adjusted Recurring 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 three and nine months ended September 30, 2009, 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 nine months ended September 30, 2010 and 2009. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable GAAP measures are provided above.

  Three Months Ended September 30,   Nine Months Ended September 30, 2010   2009 2010   2009 (in millions) Commodity Margin $ 852 $ 743 $ 1,815 $ 1,871 Other revenue 2 5 24 16 Plant operating expense(1) (181 ) (155 ) (504 ) (476 ) Other cost of revenue(2) (7 ) (6 ) (23 ) (20 ) Sales, general and administrative expense(3) (31 ) (33 ) (77 ) (107 ) Adjusted EBITDA from unconsolidated investments in power plants(4) 11 14 39 38 Other operating expense (3 ) (1 ) (10 ) (12 ) Adjusted EBITDA from discontinued operations(5) 20 22 61 63 Other   —   (3 )   1   1 Adjusted EBITDA $ 663 $ 586 $ 1,326 $ 1,374

(1)

 

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

(2)

Excludes $1 million of RGGI compliance and other environmental costs for the three months ended September 30, 2010 and 2009, and $6 million and $5 million for the nine months ended September 30, 2010 and 2009, respectively, which are included as a component of Commodity Margin.

(3)

Shown net of depreciation and amortization, stock-based compensation expense and acquisition-related costs.

(4)

Amount is comprised of income from unconsolidated investments in power plants, as well as adjustments to reflect Adjusted EBITDA from unconsolidated investments.

(5)

Includes Adjusted EBITDA from Blue Spruce and Rocky Mountain.

 

Adjusted EBITDA and Adjusted Recurring Free Cash Flow Reconciliation for Guidance

Full Year 2010 Range:   Low       High (in millions) GAAP Net Income $ 0 $ 40 Plus: Interest expense, net of interest income 820 820 Depreciation and amortization expense 565 565 Major maintenance expense 170 170 Operating lease expense 45 45 Other(1)   85   85 Adjusted EBITDA $ 1,685 $ 1,725 Less: Operating lease payments 45 45 Major maintenance expense and maintenance capital expenditures(2) 315 315 Recurring cash interest, net(3) 810 810 Cash taxes   15   15 Adjusted Recurring Free Cash Flow $ 500 $ 540 Non-recurring interest rate swap payments(4) 25 25         Full Year 2011 Range: Low High (in millions) GAAP Net Income $ (115) $

(15)

Plus: Interest expense, net of interest income 910 910 Depreciation and amortization expense 560 560 Major maintenance expense 230 230 Operating lease expense 35 35 Other(1)   80   80 Adjusted EBITDA $ 1,700 $ 1,800 Less: Operating lease payments 30 30 Major maintenance expense and maintenance capital expenditures(2) 390 390 Recurring cash interest, net(3) 825 825 Cash taxes   15   15 Adjusted Recurring Free Cash Flow $ 440 $ 540 Non-recurring interest rate swap payments(4) 110 110

(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 $175 million and $235 million in 2010 and 2011, respectively, and maintenance capital expenditures of $140 million and $155 million in 2010 and 2011, respectively. Capital expenditures exclude major construction and development projects.

(3)

Includes fees for letters of credit, net of interest income.

(4)

Interest payments related to legacy LIBOR hedges associated with floating rate first lien credit facility, which has been substantially refinanced.

 

CASH FLOW ACTIVITIES

The following table summarizes our cash flow activities for the nine months ended September 30, 2010 and 2009:

  2010       2009 (in millions) Beginning cash and cash equivalents $ 989 $ 1,657 Net cash provided by (used in): Operating activities 783 537 Investing activities (1,585 ) (164 ) Financing activities   727   (1,117 ) Net decrease in cash and cash equivalents   (75 )   (744 ) Ending cash and cash equivalents $ 914 $ 913  

OPERATING PERFORMANCE METRICS

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

  Three Months Ended September 30,   Nine Months Ended September 30, 2010   2009 2010   2009 Total MWh generated (in thousands) 28,208 26,899 67,813 63,475 West 8,093 9,295 22,795 22,866 Texas 9,533 10,246 24,419 23,058 Southeast 6,065 6,006 13,712 13,842 North 4,517 1,352 6,887 3,709   Average availability 95.9 % 97.0 % 91.5 % 92.7 % West 92.9 % 94.5 % 91.5 % 91.4 % Texas 96.5 % 97.5 % 89.1 % 92.1 % Southeast 97.4 % 98.2 % 93.4 % 93.3 % North 96.8 % 98.5 % 93.1 % 95.5 %   Average capacity factor, excluding peakers 54.3 % 60.5 % 47.9 % 48.4 % West 58.7 % 72.8 % 55.7 % 60.9 % Texas 60.0 % 64.9 % 51.9 % 49.3 % Southeast 49.3 % 51.2 % 38.4 % 40.2 % North 43.7 % 30.6 % 36.8 % 29.3 %   Steam adjusted heat rate (mmbtu/kWh) 7,415 7,286 7,328 7,259 West 7,345 7,287 7,315 7,318 Texas 7,305 7,227 7,222 7,149 Southeast 7,366 7,187 7,331 7,214 North 7,865 7,758 7,773 7,693