CPN Calpine Corp.

Calpine Corporation (NYSE:CPN) today reported a year-over-year increase in Adjusted EBITDA and Commodity Margin for the first quarter of 2009, despite a decline in revenues. Adjusted EBITDA increased to $331 million for the three months ended March 31, 2009, compared to $301 million in the same period of last year. Commodity Margin for the first quarter 2009 was $529 million, slightly above Commodity Margin of $513 million for the first quarter of 2008. Meanwhile, operating revenues were $1.7 billion for the first quarter of 2009, compared to $2.0 billion in the prior year period. Net income1 was $32 million, or $0.07 per diluted share, in the first quarter of 2009, an improvement of $246 million, or $0.51 per share, over the first quarter of 2008.

�I am pleased with our first quarter results, particularly when viewed against the backdrop of a very difficult economic climate,� said Jack Fusco, Calpine�s president and chief executive officer. �Our ability to deliver improvement in profitability in this environment demonstrates that we are reaping the benefits of the cost management and hedging programs initiated over the last six months. We believe that our financial discipline, near-term risk aversion and flexible, geographically diverse fleet will not only serve our shareholders well during this downturn, but leave us well-positioned to benefit from an economic recovery as we continue to help generate a sustainable future for America.�

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

SUMMARY OF FINANCIAL PERFORMANCE

Compared to the first quarter 2008, Adjusted EBITDA improved $30 million to $331 million in the first quarter 2009. Largely driving the improvement in Adjusted EBITDA was an increase in Commodity Margin, which rose to $529 million in the first quarter of 2009 from $513 million in the prior year period. Improved Commodity Margin in our West region was primarily associated with benefits from hedging as well as from the sale of surplus emission allowances, while our Southeast region increased its Commodity Margin primarily as a result of higher hedge prices and higher market heat rates. These improvements were partially offset by decreases in Commodity Margin in our Texas region, where weaker demand and spark spreads resulted in a 33% reduction in generation year-over-year.

The improvement in first quarter 2009 Adjusted EBITDA was further due to higher Adjusted EBITDA from our unconsolidated investments in power plants, which increased by $11 million year-over-year, primarily as a result of the Greenfield Energy Centre, which achieved its first full quarter of operations in the 2009 period. Lastly, sales, general and other administrative expense (excluding depreciation and amortization and non-cash stock-based compensation) decreased by $7 million year-over-year, largely as a result of lower personnel costs.

Cash flows provided by operating activities were $80 million in the first quarter 2009 compared to an outflow of $340 million in the prior year period. The improvement was due in large part to a year-over-year decrease of $244 million in cash paid for interest, primarily as a result of the repayment of the Second Priority Debt in 2008. In addition, working capital employed decreased by $91 million, after adjusting for debt-related balances and assets held for sale, which did not impact cash provided by operating activities. The adjusted working capital decrease was primarily due to reductions in margin deposits, partially offset by current derivative activity. Further contributing to the improvement in cash flows provided by operating activities was a $64 million decline in cash payments for reorganization items, as well as a $7 million improvement in gross profit (excluding unrealized mark-to-market activity and depreciation and amortization expense).

We believe that a comparison of net income (loss) as reported, from the first quarter 2009 to the first quarter 2008 is not meaningful, as the 2008 results include significant impacts associated with restructuring and our emergence from bankruptcy during that quarter. As detailed in Table 1 below, net loss, excluding reorganization items, other one-time items and unrealized mark-to-market gains or losses, improved by $37 million year-over-year. This improvement was driven by gains from our unconsolidated investments in power plants (as noted above), as well as by a decline in interest expense (net of one-time items) due to lower average debt balances and lower average interest rates in the first quarter of 2009.

Table 1: Summarized Consolidated Statements of Operations

� � (Unaudited) Three Months Ended March 31, 2009 � 2008 (in millions) Operating revenues $ 1,677 $ 1,951 Cost of revenue � 1,395 � � 1,980 � Gross profit (loss) 282 (29 ) SG&A, income (loss) from unconsolidated investments in power plants and other operating expense � 31 � � 53 � Income (loss) from operations 251 (82 ) Net interest expense and other (income) expense � 208 � � 416 � Income (loss) before reorganization items and income taxes 43 (498 ) Reorganization items 3 (279 ) Income tax expense (benefit) � 9 � � (5 ) Net income (loss) $ 31 $ (214 ) Add: Net loss attributable to the noncontrolling interest � 1 � � � � Net income (loss) attributable to Calpine $ 32 � $ (214 ) � Reorganization items(1) 3 (279 ) Other one-time items(1)(2) � � � � 162 � Net income (loss), net of reorganization items and other one-time items 35 (331 ) Unrealized MtM (gains) losses on derivatives (1)(3) � (126 ) � 203 � Net loss, net of reorganization items, other one-time items and unrealized MtM impacts $ (91 ) $ (128 ) � (1) Shown net of tax, assuming a 0% effective tax rate for these items. (2) One-time items in the first quarter of 2008 include $135 million in post-petition interest expense and $27 million in settlement obligations related to our Canadian debtors and other foreign entities recorded prior to their reconsolidation in February 2008, both of which were associated with our emergence from bankruptcy. (3) Represents unrealized mark-to-market (MtM) (gains) losses on contracts that do not qualify for hedge accounting treatment.

REGIONAL SEGMENT REVIEW OF RESULTS

� � Table 2: Commodity Margin by Segment

�

Three Months Ended March 31, 2009 �

2008(1)

(in millions) West $ 297 $ 278 Texas 122 139 Southeast 61 35 North � 49 � 61 Total $ 529 $ 513 � (1) 2008 Commodity Margin as previously reported has been recast to confirm to our current year presentation.

West: Commodity Margin in our West segment increased by $19 million, or 7%, for the three months ended March 31, 2009, compared to the three months ended March 31, 2008. Although market spark spreads for the first quarter of 2009 settled substantially lower than the three months ended March 31, 2008, the West segment financial performance improved in the first quarter of 2009 primarily as a result of higher hedge levels and higher average hedge prices as compared to the same period for 2008, as well as from the sale of surplus emission allowances.

Texas: Commodity Margin in our Texas segment decreased by $17 million, or 12%, for the three months ended March 31, 2009, compared to the three months ended March 31, 2008. The positive impact of our hedging activities largely mitigated a weakening market environment, due to soft demand and much weaker spark spreads, resulting in a 33% reduction in generation for the three months ended March 31, 2009. On-peak, market spark spreads were 55% lower in the Houston zone in the first quarter of 2009 compared to the first quarter of 2008, largely driven by reduced ERCOT demand and significantly lower natural gas prices.

Southeast: Commodity Margin in our Southeast segment increased by $26 million, or 74%, driven primarily by both higher average hedge prices and higher market heat rates in the first quarter of 2009 compared to 2008. The increase in market heat rates as well as the 45% increase in generation for the three months ended March 31, 2009, compared to 2008 were attributable in part to gas generation displacement of coal generation in certain markets and, to a lesser extent, a 3% increase in average availability. Additionally, some of our plants benefited from the impact of advantageous transmission, customer and transportation agreements in the first quarter of 2009.

North: Commodity Margin in our North segment decreased by $12 million, or 20%, primarily due to lower average hedge prices during the three months ended March 31, 2009, compared to 2008.

LIQUIDITY AND CAPITAL RESOURCES

� � � Table 3: Corporate Liquidity � March 31, December 31, 2009 2008 (in millions) Cash and cash equivalents, corporate(1) $ 1,424 $ 1,361 Cash and cash equivalents, non-corporate � 202 � 296 Total cash and cash equivalents 1,626 1,657 Restricted cash 476 503 Letter of credit availability(2) 22 2 Revolver availability � 45 � 16 Total current liquidity(3) $ 2,169 $ 2,178 � (1) Includes $18 million and $169 million of margin deposits held from counterparties as of March 31, 2009, and December 31, 2008, respectively. (2) Includes available balances for Calpine Development Holdings, Inc. in both periods shown and $20 million of available capacity under our Knock-in Facility as of March 31, 2009. (3) Excludes contingent amounts of $150 million under the Knock-in Facility and $200 million under the Commodity Collateral Revolver in both periods shown.

Liquidity remained strong during the first quarter of 2009 at $2.2 billion. As discussed above, operating activities resulted in cash inflows of $80 million during the quarter. These inflows were offset by, among other items, $51 million in maintenance capital expenditures and $54 million in net repayments of debt at both the corporate and project levels.

As part of our continued liquidity management efforts, we have further increased the amount of hedges performed under our first lien (or �right-way-risk�) program, which allows us to utilize our corporate debt facility to satisfy collateral obligations rather than posting cash. Under this program, we have increased our use of right-way-risk hedges approximately 350% since September 2008.

PLANT DEVELOPMENT

Russell City Energy Center: The 600 MW combined-cycle, natural gas-fired Russell City plant is a joint development project to be located in Hayward, California. We hold a 65% interest in the project, and an affiliate of General Electric Capital Corporation holds a 35% interest. In April 2009, the California Public Utilities Commission (CPUC) approved the amended power purchase agreement between Pacific Gas & Electric Company (PG&E) and Russell City Energy Company, LLC, under which PG&E will take 100% of the plant�s generation for 10 years. All permits for the projects have been issued and approved with the exception of a certain air permit pending before the local air quality board. Completion of the Russell City development project is dependent upon obtaining the necessary permits, construction contracts and construction funding under project financing facilities.

OPERATIONS UPDATE

Power Operations Achievements: During the first quarter 2009, our plants continued to demonstrate operational excellence on several fronts:

• Safety: Delivered top-quartile safety performance, achieving a fleet-wide lost time incident rate of 0.19.
• Availability: Improved fleet-wide availability to 91% during the first quarter 2009, compared to 86% in the first quarter 2008.
• Geothermal Generation: Provided over 1.5 million MWh of renewable baseload generation with a forced outage factor of 0.25%.
• Natural Gas Generation: Improved gas fleet forced outage factor by 63% compared to the first quarter of 2008.

Commercial Operations Achievements: Our commercial operations group continued to add value to our business during the first quarter of 2009, as demonstrated by:

• Effective Hedging: Achieved attractive hedged spark spreads for the quarter during difficult market conditions, providing near-term stability to Adjusted EBITDA and allowing us to outperform the prior year period despite lower revenues and lower generation volume.
• Reduced Risk: Excellent execution by commercial operations, coupled with management�s conservative strategy, allowed us to significantly reduce covenant risk associated with forward gas price exposure during the recessionary environment.
• Disciplined Growth: Received CPUC approval for Russell City power purchase agreement. Announced turbine upgrade program, which will allow us to add incremental capacity at certain of our plants while improving efficiency.
• Liquidity Management: Increased usage of first lien program by approximately 350% since September 2008.

OUTLOOK FOR 2009

� � � Table 4: Adjusted EBITDA and Adjusted Free Cash Flow Guidance for 2009 � Full Year 2009 Recurring (in millions) Adjusted EBITDA $ 1,600 � 1,700 Less: Operating lease payments 50 $ 50 Major maintenance expense and capital expenditures(1) 350 ~300 Cash interest, net 755 750 Cash taxes 5 10 Working capital and other adjustments(2) � 40 � Adjusted Free Cash Flow $ 400 � 500 � (1) Includes Major Maintenance Expense of $205 million and Capital Expenditures of $145 million in 2009. Capital expenditures exclude major construction and development projects. (2) Excludes changes in cash collateral for commodity procurement and risk management activities.

We are reaffirming our 2009 Adjusted EBITDA guidance of $1.6 to $1.7 billion and our 2009 Adjusted Free Cash Flow guidance of $400 to $500 million.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the first quarter 2009, on Friday, May 8, 2009, at 8:00 a.m. ET / 7:00 a.m. CT. A listen-only webcast of the call may be accessed through our web site at www.calpine.com, or by dialing 888-765-5547 (or 913-312-0646 for international listeners) at least 10 minutes prior to the beginning of the call. An archived recording of the call will be made available for a limited time on the web site. It also can be accessed by dialing 888-203-1112 or 719-457-0820 (International) and providing Confirmation Code 3407359. In addition, presentation materials to accompany the conference call will be made available on our web site on May 8, 2009.

ABOUT CALPINE

Calpine Corporation is helping meet the needs of an economy that demands more and cleaner sources of electricity. Founded in 1984, Calpine is a major U.S. power company, currently capable of delivering over 24,000 megawatts of clean, cost-effective, reliable and fuel-efficient power to customers and communities in 16 states in the United States and Canada. Calpine owns, leases, and operates low-carbon, natural gas-fired, and renewable geothermal power plants. Using advanced technologies, Calpine generates power in a reliable and environmentally responsible manner for the customers and communities it serves. Please visit www.calpine.com for more information.

Calpine�s Quarterly Report on Form 10-Q for the period ended March 31, 2009, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC�s web site at www.sec.gov.

FORWARD-LOOKING INFORMATION

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

• The uncertain length and severity of the current general financial and economic downturn and its impacts on our business including demand for our power and steam products, the ability of our counterparties to perform under their contracts with us and the cost and availability of capital and credit;
• Fluctuations in prices for commodities such as natural gas and power;
• The effects of fluctuations in liquidity and volatility in the energy commodities markets including our ability to hedge risks;
• The ability of our customers, suppliers, service providers and other contractual counterparties to perform under their contracts with us;
• Our ability to manage our significant liquidity needs and to comply with covenants under our Exit Credit Facility and other existing financing obligations;
• Financial results that may be volatile and may not reflect historical trends due to, among other things, general economic and market conditions outside of our control, the ability of our counterparties to perform their contracts with us and the effects of our Chapter 11 reorganization;
• Our ability to attract and retain customers and counterparties, including suppliers and service providers, and to manage our customer and counterparty exposure and credit risk, including our commodity positions;
• Competition, including risks associated with marketing and selling power in the evolving energy markets;
• Regulation in the markets in which we participate and our ability to effectively respond to changes in laws and regulations or the interpretation thereof including changing market rules and evolving federal, state and regions laws and regulations including those related to GHG emissions;
• Natural disasters such as hurricanes, earthquakes and floods that may impact our power plants or the markets our power plants serve;
• Seasonal fluctuations of our results and exposure to variations in weather patterns;
• Disruptions in or limitations on the transportation of natural gas and transmission of power;
• Our ability to attract, retain and motivate key employees;
• Our ability to implement our new business plan and strategy;
• Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements and variables associated with the injection of waste water to the steam reservoir;
• Present and possible future claims, litigation and enforcement actions, including our ability to complete the implementation of our Plan of Reorganization;
• The expiration or termination of our PPAs and the related results on revenues; and
• Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;
• 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 March 31, 2009 and in our Annual Report on Form 10-K for the year ended December 31, 2008.

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

CALPINE CORPORATION AND SUBSIDIARIES � � CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited) � March 31, December 31, 2009 2008

(in millions, exceptshare and per share amounts)

ASSETS Current assets: Cash and cash equivalents $ 1,626 $ 1,657 Accounts receivable, net of allowance of $40 and $37 656 850 Inventory 166 163 Margin deposits and other prepaid expense 474 776 Restricted cash, current 421 337 Current derivative assets 4,614 3,653 Other current assets � 65 � � 64 � Total current assets 8,022 7,500 � Property, plant and equipment, net 11,849 11,908 Restricted cash, net of current portion 55 166 Investments 163 144 Long-term derivative assets 602 404 Other assets � 598 � � 616 � Total assets $ 21,289 � $ 20,738 � LIABILITIES & STOCKHOLDERS� EQUITY Current liabilities: Accounts payable $ 442 $ 574 Accrued interest payable 48 85 Debt, current portion 740 716 Current derivative liabilities 4,436 3,799 Income taxes payable 9 5 Other current liabilities � 259 � � 437 � Total current liabilities 5,934 5,616 � Debt, net of current portion 9,735 9,756 Deferred income taxes, net of current portion 89 93 Long-term derivative liabilities 766 698 Other long-term liabilities � 206 � � 203 � Total liabilities 16,730 16,366 � Commitments and contingencies Stockholders� equity: Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding at March 31, 2009 and December 31, 2008 � � Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 429,111,851 shares issued and 428,812,216 shares outstanding at March 31, 2009; 429,025,057 shares issued and 428,960,025 shares outstanding at December 31, 2008 1 1 Treasury stock, at cost, 299,635 shares at March 31, 2009 and 65,032 shares at December 31, 2008 (3 ) (1 ) Additional paid-in capital 12,229 12,217 Accumulated deficit (7,657 ) (7,689 ) Accumulated other comprehensive loss � (12 ) � (158 ) Total Calpine stockholders� equity 4,558 4,370 Noncontrolling interest � 1 � � 2 � Total stockholders� equity � 4,559 � � 4,372 � Total liabilities and stockholders� equity $ 21,289 � $ 20,738 � � CALPINE CORPORATION AND SUBSIDIARIES � CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS (Unaudited) � Three Months Ended March 31, 2009 � 2008

(in millions, except share andper share amounts)

Operating revenues $ 1,677 $ 1,951 � Cost of revenue: Fuel and purchased energy expense 1,015 1,605 Plant operating expense 248 232 Depreciation and amortization expense 109 111 Other cost of revenue � 23 � � 32 � Total cost of revenue � 1,395 � � 1,980 � Gross profit (loss) 282 (29 ) Sales, general and other administrative expense 45 48 (Income) loss from unconsolidated investments in power plants (17 ) 3 Other operating expense � 3 � � 2 � Income (loss) from operations 251 (82 ) Interest expense 210 419 Interest (income) (6 ) (13 ) Other (income) expense, net � 4 � � 10 � Income (loss) before reorganization items and income taxes 43 (498 ) Reorganization items � 3 � � (279 ) Income (loss) before income taxes 40 (219 ) Income tax expense (benefit) � 9 � � (5 ) Net income (loss) 31 (214 ) Add: Net loss attributable to the noncontrolling interest � 1 � � � � Net income (loss) attributable to Calpine $ 32 � $ (214 ) � Basic earnings (loss) per common share: Weighted average shares of common stock outstanding (in thousands) � 485,362 � � 485,000 � Net income (loss) per common share attributable to Calpine � basic $ 0.07 � $ (0.44 ) � Diluted earnings (loss) per common share: Weighted average shares of common stock outstanding (in thousands) � 485,595 � � 485,000 � Net income (loss) per common share attributable to Calpine � diluted $ 0.07 � $ (0.44 ) �

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

� Three Months Ended March 31, 2009 � 2008 (in millions) Cash flows from operating activities: Net income (loss) $ 31 $ (214 ) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation and amortization expense(1) 132 155 Deferred income taxes 10 64 Loss on sale of assets, excluding reorganization items 10 � Mark-to-market activities, net (126 ) 203 (Income) loss from unconsolidated investments in power plants (17 ) 3 Stock-based compensation expense 13 6 Reorganization items � (325 ) Other 5 5 Change in operating assets and liabilities: Accounts receivable 194 255 Derivative instruments (114 ) (111

)

Other assets 300 (78 ) Accounts payable, LSTC and accrued expenses (200 ) (21 ) Other liabilities � (158 ) � (282 ) Net cash provided by (used in) operating activities � 80 � � (340 ) Cash flows from investing activities: Purchases of property, plant and equipment (51 ) (56 ) Disposals of property, plant and equipment � 4 Proceeds from sale of power plants, turbines and investments � 398 Cash acquired due to reconsolidation of Canadian Debtors and other foreign entities � 64 Contributions to unconsolidated investments (4 ) � Return of investment from unconsolidated investments � 24 Decrease in restricted cash 27 43 Other � 1 � � 6 � Net cash provided by (used in) investing activities � (27 ) � 483 � Cash flows from financing activities: Repayments of notes payable $ (54 ) $ (49

)

Borrowings from notes payable � 5 Repayments of project financing (50 ) (122

)

Borrowings from project financing 64 90 Repayments of DIP Facility � (98

)

Borrowings under Exit Credit Facility � 2,723 Repayments on Exit Credit Facility (15 ) (455

)

Repayments on Second Priority Debt � (3,672

)

Repayments on capital leases (22 ) (18 ) Redemptions of preferred interests (4 ) (5 ) Financing costs � (175

)

Other � (3 ) � (1 ) Net cash used in financing activities (84 ) (1,777 ) Net decrease in cash and cash equivalents (31 ) (1,634 ) Cash and cash equivalents, beginning of period � 1,657 � � 1,915 � Cash and cash equivalents, end of period $ 1,626 � $ 281 � Cash paid (received) during the period for: Interest, net of amounts capitalized $ 226 $ 470 Income taxes $ � $ 7 Reorganization items included in operating activities, net $ 3 $ 67 Reorganization items included in investing activities, net $ � $ (414 ) �

Supplemental disclosure of non-cash investing and financing activities:

Settlement of commodity contract with project financing $ 79 $ � Increase in deferred finance costs with project financing $ 7 $ � Capital expenditures in accounts payable $ 10 $ 11 Settlement of LSTC through issuance of reorganized Calpine Corporation common stock $ � $ 5,200 DIP Facility borrowings converted into exit financing under Exit Facilities $ � $ 3,872 Settlement of Convertible Senior Notes and Unsecured Senior Notes with reorganized Calpine Corporation common stock $ � $ 3,703 (1) Includes depreciation and amortization that is also recorded in sales, general and other administrative expense and interest expense on our Consolidated Condensed Statements of Operations.

REGULATION G RECONCILIATIONS

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

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

Adjusted EBITDA represents net income 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. 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 March 31, 2009 and 2008:

� Three Months Ended March 31, 2009

(in millions)

� � � � � � � Consolidation � And West Texas Southeast North Elimination Total Commodity Margin $ 297 $ 122 $ 61 $ 49 $ � $ 529

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

22 90 31 4 (14 ) 133 Less: Plant operating expense 127 78 32 20 (9 ) 248 Depreciation and amortization expense 49 30 16 16 (2 ) 109 Other cost of revenue � 15 � 3 � 3 � 8 � (6 ) � 23 Gross profit $ 128 $ 101 $ 41 $ 9 $ 3 � $ 282 � � Three Months Ended March 31, 2008

(in millions)

� � � � Consolidation � And West Texas Southeast North Elimination Total Commodity Margin $ 278 $ 139 $ 35 $ 61 $ � $ 513

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

(49 ) (125 ) (13 ) 23 (3 ) (167 ) Less: Plant operating expense 112 70 30 26 (6 ) 232 Depreciation and amortization expense 51 30 19 12 (1 ) 111 Other cost of revenue � 17 � � � � � 9 � � 6 � � � � 32 � Gross profit (loss) $ 49 � $ (86 ) $ (36 ) $ 40 $ 4 � $ (29 ) � (1) Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, as well as a non-cash gain from amortization of prepaid power sales agreements included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations. �

Consolidated Adjusted EBITDA Reconciliation

The table below provides a reconciliation of Adjusted EBITDA to our GAAP net income (loss) for the three months ended March 31, 2009 and 2008.

� (Unaudited) Three Months Ended March 31, 2009

2008(1)

(in millions) GAAP net income (loss) $ 31 $ (214 ) Add: Adjustments to reconcile GAAP net income (loss) to Adjusted EBITDA: Interest expense, net of interest income 204 406 Depreciation and amortization expense, excluding deferred financing costs(2) 113 122 Income tax expense (benefit) 9 (5 ) Reorganization items 3 (279 ) Major maintenance expense 62 54 Operating lease expense 12 12 Non-cash gains on derivatives(3) � (9 ) Unrealized (gains) losses on commodity derivative mark-to-market activity (125 ) 187 Adjustments to reflect Adjusted EBITDA from unconsolidated investments(4)(5) (2 ) 7 Stock-based compensation expense 13 6 Non-cash loss on dispositions of assets 8 6 Non-cash loss on repurchase or extinguishment of debt � 7 Other(6) � 3 � 1 � Adjusted EBITDA $ 331 $ 301 � � (1) Adjusted EBITDA for the three months ended March 31, 2008, has been recast to conform to our current year presentation. (2) Depreciation and amortization expense in the GAAP net income (loss) calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets and amounts classified as sales, general and other administrative expenses. (3) Includes realized non-cash gains on derivatives that do not qualify for hedge accounting. (4) Recorded on our Consolidated Condensed Statements of Operations in (income) loss from unconsolidated investments in power plants. (5) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include $(8) million and $1 million in unrealized (gains) losses on mark-to-market activity for the three months ended March 31, 2009 and 2008, respectively. (6) Other includes foreign currency translation gains or losses, fees associated with issuance of letters of credit and other items.

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for 2009 Guidance

� � � Full Year 2009 Range: Low High Recurring (in millions) GAAP Net Income $ 160 $ 260 Plus: Interest expense, net of interest income 765 765 Depreciation and amortization expense 475 475 Major maintenance expense 205 205 Operating lease expense 50 50 Other(1) � (55 ) � (55 ) Adjusted EBITDA $ 1,600 $ 1,700 Less: Operating lease payments 50 50 $ 50 Major maintenance expense and maintenance capital expenditures(2) 350 350 ~300 Cash interest, net 755 755 750 Cash taxes 5 5 10 Working capital and other adjustments � 40 � � 40 � � Adjusted Free Cash Flow $ 400 � $ 500 � � (1) Other includes stock-based compensation expense and other adjustments. (2) Includes major maintenance expense of $205 million and capital expenditures of $145 million. Capital expenditures exclude major construction and development projects funded with debt.

CASH FLOW ACTIVITIES

�

The following table summarizes our cash flow activities for the three months ended March 31, 2009 and 2008:

� � (Unaudited) Three Months Ended March 31, 2009 � 2008 (in millions) Beginning cash and cash equivalents $ 1,657 � $ 1,915 � Net cash provided by (used in): Operating activities 80 (340 ) Investing activities (27 ) 483 Financing activities � (84 ) � (1,777 ) Net decrease increase in cash and cash equivalents � (31 ) � (1,634 ) Ending cash and cash equivalents $ 1,626 � $ 281 �

OPERATING PERFORMANCE METRICS

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

� � Three Months Ended March 31, 2009 2008 Total MWh generated(1) (in thousands) 19,267 20,906 West 8,937 9,157 Texas 5,207 7,741 Southeast 3,879 2,670 North 1,244 1,338 � Average availability 90.9 % 85.8 % West 90.4 % 83.3 % Texas 88.3 % 82.0 % Southeast 94.0 % 91.0 % North 92.0 % 92.0 % � Average capacity factor, excluding peakers 43.2 % 46.2 % West 65.2 % 66.4 % Texas 33.2 % 48.9 % Southeast 34.4 % 22.6 % North 31.8 % 34.3 % � Steam adjusted Heat Rate 7,188 7,161 West 7,213 7,228 Texas 7,019 6,951 Southeast 7,228 7,461 North 7,634 7,419 (1) � MWh generated is shown here as our net operating interest. Excludes Auburndale Power Plant�s 186,393 MWh generation for 2008.