Calpine Reports Strong Second Quarter Results and Reaffirms 2014 Guidance; Updates Capital Allocation Progress, Including Announcement of York 2 Energy Center in PJM

HOUSTON--(BUSINESS WIRE)--Calpine Corporation (NYSE: CPN)

Summary of Second Quarter 2014 Financial Results (in millions, except per share amounts):

	Three Months Ended June 30,								Six Months Ended June 30,
	2014			2013			% Change		2014		2013			% Change
Operating Revenues	$	1,939		$	1,572		23.3	%	$	3,904	$	2,813		38.8	%
Commodity Margin	$	632		$	533		18.6	%	$	1,277	$	994		28.5	%
Adjusted EBITDA	$	413		$	343		20.4	%	$	859	$	629		36.6	%
Adjusted Free Cash Flow	$	99		$	38				$	229	$	(5	)
Per Share (diluted)	$	0.23		$	0.08				$	0.54	$	(0.01	)
Net Income (Loss)^1	$	139		$	(70	)			$	122	$	(195	)
Per Share (diluted)	$	0.33		$	(0.16	)			$	0.29	$	(0.43	)
Net Income (Loss), As Adjusted^2	$	(3	)	$	(33	)			$	53	$	(103	)

Reaffirming 2014 Full Year Guidance (in millions, except per share amounts):

	2013 (Actuals)	2014 (Current Guidance)	Growth Rate^3
Adjusted EBITDA	$1,830	$1,900 - 2,000	6.6%
Adjusted Free Cash Flow	$677	$785 - 885	23%
Per Share Estimate (diluted)	$1.52	$1.85 - 2.10	30%

Recent Achievements:

• Power and Commercial Operations:
  — Generated approximately 24 million MWh⁴ of electricity in second quarter of 2014
  — Achieved record-low second quarter fleetwide forced outage factor: 1.5%
  — Entered into new contracts:

• Geysers: 225 MW, ten-year PPA commencing in 2017, subject to regulatory approval
• RockGen Energy Center: Up to 235 MW, five-year PPA commencing in 2018
• Texas fleet: Approximately 80-90 MW of PPAs commencing in 2015/2016

• Portfolio Management
  — Completed construction of Deer Park and Channel Energy Center expansion projects in Texas
  — Closed in July on divestiture of non-core assets from our Southeast portfolio for net proceeds of $1.53 billion⁵

• Capital Allocation Progress: More than $1 billion committed since first quarter
  — Completed $500 million of share repurchases; $566 million authorization remaining
  — Deployed $350 million in July toward early retirement premiums and fees with the refinancing of $2.8 billion of debt, achieving approximately $60 million in annual interest savings and enhancing capital structure flexibility
  — $120 million of 2023 Senior Notes callable at a price of 103 in the fourth quarter of 2014
  — Announcing 760 MW York 2 Energy Center in PJM, contributing to approximately $100 million of additional growth investment in 2014
  — Expanded revolver capacity by $500 million in July, bringing total capacity to $1.5 billion

Calpine Corporation (NYSE: CPN) today reported second quarter 2014 Adjusted EBITDA of $413 million, compared to $343 million in the prior year period, and Adjusted Free Cash Flow of $99 million, or $0.23 per diluted share, compared to $38 million, or $0.08 per diluted share, in the prior year period. Net Income¹ for the second quarter of 2014 was $139 million, or $0.33 per diluted share, compared to a Net Loss¹ of $70 million, or $0.16 per diluted share, in the prior year period. Net Loss, As Adjusted², for the second quarter of 2014 was $3 million compared to $33 million in the prior year period. The improvements in Adjusted EBITDA, Adjusted Free Cash Flow and Net Loss, As Adjusted², were driven primarily by higher Commodity Margin resulting from portfolio changes, stronger market conditions in the West and Texas, higher contribution from hedges and higher regulatory capacity revenue.

Year-to-date 2014 Adjusted EBITDA was $859 million, compared to $629 million in the prior year period, and Adjusted Free Cash Flow was $229 million, or $0.54 per diluted share, compared to $(5) million, or $(0.01) per diluted share, in the prior year period. Net Income¹ for the first half of 2014 was $122 million, or $0.29 per diluted share, compared to a Net Loss¹ of $195 million, or $0.43 per diluted share, in the prior year period. Net Income, As Adjusted², for the first half of 2014 was $53 million compared to a Net Loss, As Adjusted², of $103 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted², compared to the prior year period were primarily due to higher commodity margin resulting from stronger market conditions, including colder than normal weather during the first quarter, our ability to capture the value of our dual-fuel capable plants in the North during extreme commodity pricing conditions, portfolio changes and higher regulatory capacity revenue.

“Our strong second quarter results reflect ongoing portfolio management, effective hedging and operational excellence,” said Thad Hill, Calpine’s President and Chief Executive Officer. “We increased generation volumes, achieved a record-low forced outage factor and maintained our focus on safety, with no lost time incidents reported this year. On the commercial front, since the first quarter, we have entered into four new contracts, most notably a ten-year PPA with Southern California Edison for 225 MW of capacity and renewable energy from our Geysers geothermal fleet beginning in 2017, subject to regulatory approval. In addition, we have advanced our growth pipeline and are today announcing plans for our York 2 Energy Center, a new 760 MW combined-cycle power plant, scheduled to achieve commercial operations in PJM in 2017. York 2 will be co-located with our existing York Energy Center, allowing us to leverage the infrastructure to build at a significant discount with attractive returns. Finally, on July 3, we closed on the previously announced Southeast asset sale, which generated approximately $1.53 billion in net proceeds.

“Looking at the balance of the year, our solid operations and robust hedging program continue to mitigate the effects of an unseasonably mild summer in Texas and the Mid-Atlantic, enabling us to reaffirm our 2014 guidance. Longer-term, Calpine remains well positioned to capture value as the sound fundamentals in each of our core markets reassert themselves,” said Hill.

“Complementing our strong operating and financial performance, we have also made significant progress on capital allocation and balance sheet management,” added Zamir Rauf, Calpine’s Chief Financial Officer. “Over the past several months, we have deployed or committed more than $1 billion of capital to growth projects, share repurchases and refinancings. More specifically, we repurchased $500 million of our stock, including more than $300 million from our largest shareholder pursuant to a repurchase authorization that supplemented our previously announced $1 billion program. In total, since 2011, we have repurchased approximately 19% of outstanding shares, including 5% since the end of the first quarter, and we still have $566 million authorization remaining. Finally, we recently completed a transformational refinancing through an inaugural unsecured debt offering that will improve our financial flexibility, extend our maturities and generate approximately $60 million in annual interest savings. In addition, we materially enhanced our liquidity by increasing our revolver capacity from $1 billion to $1.5 billion. Overall, we continue to execute on our commitment to maintain a balanced approach to capital allocation by investing in accretive growth and returning capital to shareholders, while prudently managing the balance sheet.”

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^{1 Reported as Net Income (Loss) attributable to Calpine on our Consolidated Condensed Statements of Operations.}

^{2 Refer to Table 1 for further detail of Net Income (Loss), As Adjusted.}

^{3 Assuming midpoint of 2014 guidance.}

^{4 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants.}

^{5 Net of spare parts, certain planned maintenance events and other transaction costs.}

SUMMARY OF FINANCIAL PERFORMANCE

Second Quarter Results

Adjusted EBITDA for the second quarter of 2014 was $413 million compared to $343 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to a $99 million increase in Commodity Margin, which was largely due to:

+	our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, the acquisition of Guadalupe Energy Center in February 2014 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014
+	stronger market conditions resulting in higher market spark spreads in the West and Texas
+	higher contribution from hedges and
+	higher regulatory capacity revenue in the North, partially offset by
–	the expiration of a tolling contract associated with our Delta Energy Center in December 2013.

Net Income¹ was $139 million for the second quarter of 2014, compared to a Net Loss¹ of $70 million in the prior year period. As detailed in Table 1, Net Loss, As Adjusted², was $3 million in the second quarter of 2014 compared to $33 million in the prior year period. The year-over-year improvement was driven largely by:

+	higher Commodity Margin, as previously discussed, partially offset by
–	higher income tax expense resulting from a decrease in income tax benefit associated with various state and foreign jurisdiction income taxes primarily related to an increase in our pre-tax income.

Adjusted Free Cash Flow was $99 million in the second quarter of 2014 compared to $38 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to the increase in Adjusted EBITDA, as previously discussed.

Year-to-Date Results

Adjusted EBITDA for the six months ended June 30, 2014, was $859 million compared to $629 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily due to a $283 million increase in Commodity Margin which was primarily due to:

+	stronger market conditions resulting in higher market spark spreads
+	higher contribution from our dual-fueled power plants in the North during the first quarter of 2014 when fuel oil prices were lower than natural gas prices
+	our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, the acquisition of Guadalupe Energy Center in February 2014 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014, and
+	higher regulatory capacity revenue in the North, partially offset by
–	lower contribution from hedges and
–	the expiration of a tolling contract associated with our Delta Energy Center in December 2013.

Net Income¹ was $122 million for the six months ended June 30, 2014, compared to a Net Loss¹ of $195 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted², was $53 million in the six months ended June 30, 2014, compared to a Net Loss, As Adjusted², of $103 million in the prior year period. The year-over-year improvement was driven largely by:

+	higher Commodity Margin, as previously discussed, partially offset by
–	lower income tax benefit driven by an increase in our pre-tax income during the first half of 2014, and
–	higher plant operating expense driven primarily by portfolio changes, and to a lesser extent, higher equipment failure expense related to outages and the reversal of previously recognized regulatory fees that benefited the first half of 2013 and did not recur in the first half of 2014.

Adjusted Free Cash Flow was $229 million for the six months ended June 30, 2014, compared to $(5) million in the prior year period. The increase in Adjusted Free Cash Flow during the period was primarily due to the increase in Adjusted EBITDA, as previously discussed.

Table 1: Net Income (Loss), As Adjusted

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Net income (loss) attributable to Calpine	$	139		$	(70	)	$	122		$	(195	)
Debt extinguishment costs^(1)	—			68			1			68
MtM (gain) loss on derivatives^(1)(2)	(142		)	(31		)	(70		)	24
Net Income (Loss), As Adjusted^(3)	$	(3	)	$	(33	)	$	53		$	(103	)

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^{(1) Shown net of tax, assuming a 0% effective tax rate for these items.}

^{(2) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market (gain) loss also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.}

^{(3) See “Regulation G Reconciliations” for further discussion of Net Income (Loss), As Adjusted.}

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014		2013		Variance		2014		2013		Variance
West	$	228	$	198	$	30	$	430	$	400	$	30
Texas	177		133		44		298		209		89
North	175		159		16		442		301		141
Southeast	52		43		9		107		84		23
Total	$	632	$	533	$	99	$	1,277	$	994	$	283

West Region

Second Quarter: Commodity Margin in our West segment increased by $30 million in the second quarter of 2014 compared to the prior year period. Primary drivers were:

+	the commencement of commercial operations at our contracted Russell City and Los Esteros power plants during the third quarter of 2013 and
+	higher spark spreads due to stronger market conditions resulting from lower hydroelectric generation, partially offset by
–	the expiration of a tolling contract associated with our Delta Energy Center in December 2013 and
–	lower contribution from hedges.

Year-to-Date: Commodity Margin in our West segment increased by $30 million for the six months ended June 30, 2014, compared to the prior year period. The year-to-date results were largely impacted by the same factors that drove comparative performance for the second quarter, as previously discussed.

Texas Region

Second Quarter: Commodity Margin in our Texas segment increased by $44 million in the second quarter of 2014 compared to the prior year period. Primary drivers were:

+	higher spark spreads resulting from stronger market conditions in April and May 2014
+	the acquisition of Guadalupe Energy Center in February 2014 and the expansions of our Deer Park and Channel Energy Centers, which were completed in June 2014 and
+	higher contribution from hedges, partially offset by
–	lower spark spreads resulting from weaker market conditions in June 2014.

Year-to-Date: Commodity Margin in our Texas segment increased by $89 million for the six months ended June 30, 2014, compared to the prior year period. Primary drivers were:

+	higher spark spreads resulting from stronger market conditions in the first five months of 2014
+	the acquisition of Guadalupe Energy Center in February 2014 and the expansions of our Deer Park and Channel Energy Centers, which were completed in June 2014.

North Region

Second Quarter: Commodity Margin in our North segment increased by $16 million in the second quarter of 2014 compared to the prior year period, due primarily to higher regulatory capacity revenues.

Year-to-Date: Commodity Margin in our North segment increased by $141 million for the six months ended June 30, 2014, compared to the prior year period. Primary drivers were:

+	higher spark spreads resulting from stronger market conditions due to colder than normal weather during the first quarter of 2014
+	higher contribution from our dual-fueled plants during the first quarter of 2014 when fuel oil prices were lower than natural gas prices and
+	higher regulatory capacity revenues, partially offset by
–	lower contribution from hedges.

Southeast Region

Second Quarter: Commodity Margin in our Southeast segment increased by $9 million in the second quarter of 2014 compared to the prior year period. Primary drivers were:

+	higher spark spreads resulting from stronger market conditions and
+	positive impact of new contracts which became effective in 2014.

Year-to-Date: Commodity Margin in our Southeast segment increased by $23 million for the six months ended June 30, 2014, compared to the prior year period. Primary drivers were:

+	higher spark spreads resulting from stronger market conditions due to colder than normal weather during the first quarter of 2014 and
+	positive impact of new contracts which became effective in 2014, partially offset by
–	lower contribution from hedges.

Because the divestiture of six of our plants in the Southeast did not close until July 3, 2014, neither the three nor six months ended June 30, 2014, were impacted by the sale.

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity

	June 30,		December 31,
	2014		2013
	(in millions)
Cash and cash equivalents, corporate^(1)	$	286	$	649
Cash and cash equivalents, non-corporate	156		292
Total cash and cash equivalents	442		941
Restricted cash	257		272
Corporate Revolving Facility availability	765		758
CDHI letter of credit availability	6		7
Total current liquidity availability	$	1,470	$	1,978

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^{(1) Includes $184 million and $5 million of margin deposits posted with us by our counterparties at June 30, 2014, and December 31, 2013, respectively.}

Liquidity was approximately $1.5 billion as of June 30, 2014. Cash and cash equivalents decreased during the first half of the year due largely to the use of $244 million in cash on hand to fund the purchase of Guadalupe Energy Center, $297 million in share repurchases, $95 million in payments to fund the construction of Garrison Energy Center and the expansions of our Channel and Deer Park Energy Centers as well as other seasonal variations in working capital, which cause fluctuations in our cash and cash equivalents.

On July 30, 2014, we enhanced our liquidity by amending our Corporate Revolving Facility to increase the capacity by an additional $500 million, bringing the total facility to $1.5 billion.

Table 4: Cash Flow Activities

	Six Months Ended June 30,
	2014			2013
	(in millions)
Beginning cash and cash equivalents	$	941		$	1,284
Net cash provided by (used in):
Operating activities	349			(175		)
Investing activities	(900		)	(281		)
Financing activities	52			(113		)
Net decrease in cash and cash equivalents	(499		)	(569		)
Ending cash and cash equivalents	$	442		$	715

Cash flows from operating activities in the six months ended June 30, 2014, resulted in net inflows of $349 million compared to net outflows of $175 million in the prior year period. The increase in cash provided by operating activities was primarily due to an increase in income from operations (adjusted for non-cash items). Also contributing to the increase was a decrease in working capital employed, largely due to lower net margin requirements partially offset by an increase in net accounts receivable/payable balances resulting from higher Commodity Margin. Also contributing to the increase, cash paid for interest decreased due to the timing of interest payments, and debt extinguishment payments decreased due to refinancing activity from the first half of 2013 that did not recur in the first half of 2014.

Cash flows used in investing activities during the six months ended June 30, 2014, were $900 million compared to $281 million in the prior year period. The increase in outflows was primarily due to the $656 million purchase of our Guadalupe Energy Center in 2014 with no corresponding acquisition activity in the first quarter of 2013.

Cash flows provided by financing activities were $52 million and were primarily related to the issuance of CCFC Term Loans used to fund a portion of the purchase price of our Guadalupe Energy Center, partially offset by payments associated with execution of our share repurchase program.

CAPITAL ALLOCATION

Sale of Six Southeast Power Plants

On July 3, 2014, we completed the sale of six of our power plants in the Southeast segment for a purchase price of approximately $1.57 billion in cash, subject to working capital and other adjustments. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets.

Share Repurchase Program

In November 2013, our Board of Directors authorized a new $1.0 billion multi-year share repurchase program, under which we have repurchased a total of 21,063,743 shares of our common stock for approximately $434 million at an average price of $20.60 per share, leaving $566 million of remaining authorization. In addition, our Board of Directors authorized the repurchase of 13,213,372 shares of our common stock from a shareholder for approximately $311 million in a private transaction that was completed in July 2014.

Refinancing of First Lien Notes with Senior Unsecured Notes

On July 22, 2014, we refinanced $2.8 billion of senior secured notes with an equivalent amount of senior unsecured notes. We issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering, representing the inaugural issuance of unsecured debt within our capital structure. We used the net proceeds, together with cash on hand, to repurchase our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes, which carried interest rates of 7.50% - 8.00%. In connection with this refinancing, we incurred approximately $350 million in early retirement premiums and fees, and we expect to achieve annual interest savings of approximately $60 million.

PLANT DEVELOPMENT

Texas:

Channel and Deer Park Expansions: In the second quarter of 2014, we completed the construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW⁶ each. Each power plant featured an oversized steam turbine that, along with existing plant infrastructure, allowed us to add capacity and improve the power plant’s overall efficiency at a meaningful discount to the market cost of building new capacity.

Guadalupe Energy Center: On February 26, 2014, we, through our indirect, wholly owned subsidiary Calpine Guadalupe GP, LLC, completed the purchase of a power plant owned by MinnTex Power Holdings, LLC with a capacity of 1,000 MW, for approximately $625 million, excluding working capital adjustments. We funded the acquisition with $425 million in incremental CCFC Term Loans and cash on hand. The addition of this modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment, which is one of our core markets. We also paid $15 million to acquire the rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker. Development efforts are ongoing and we are continuing to advance entitlements (such as permits, zoning and transmission).

North:

Garrison Energy Center: Garrison Energy Center is a 309 MW combined-cycle project located in Delaware on a site secured by a long-term lease with the City of Dover. Construction commenced in April 2013, and we expect commercial operations to commence during the second quarter of 2015. The project’s capacity has cleared each of PJM’s three most recent base residual auctions. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility and system impact studies for this phase, and the facilities study is currently underway.

York 2 Energy Center: York 2 Energy Center is a nominal 760 MW dual-fueled combined-cycle power plant that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. PJM has completed the project’s feasibility and system impact studies, and the facilities study is underway. The project’s capacity cleared PJM’s 2017/2018 base residual auction, and we expect commercial operations to commence during the second quarter of 2017. The project’s key permits and approvals are being actively pursued, and the air permit has been filed with the Pennsylvania Department of Environmental Protection.

Mankato Power Plant Expansion: We are proposing a 345 MW expansion of the Mankato Power Plant in response to a competitive resource acquisition process established by the Minnesota Public Utilities Commission (“MPUC”) to acquire up to approximately 500 MW of new capacity. The initial stage of the proceeding was managed via a contested case hearing. On March 27, 2014, the MPUC agreed in part and disagreed in part with the recommendation of the Administrative Law Judge and directed Xcel Energy (Northern States Power) to negotiate in parallel PPAs with Calpine and certain other entities, subject to final review and approval by the MPUC. A decision is expected in late 2014 or early 2015.

PJM Development Opportunities: We are currently evaluating opportunities to develop additional projects in the PJM market area that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development.

All Segments:

Turbine Modernization: We continue to move forward with our turbine modernization program. Through June 30, 2014, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade approximately three additional turbines. Similarly, we have the opportunity at several of our power plants in Texas to implement further turbine modernizations to add as much as 500 MW of incremental capacity across the region at attractive prices. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our North segment. Our decision to invest in these turbine modernizations depends upon, among other things, further clarity on market design reforms currently being considered.

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^{6 Represents incremental baseload capacity at annual average conditions. Incremental summer peaking capacity is approximately 200 MW per unit, supplemented by incremental efficiencies across the balance of plant.}

OPERATIONS UPDATE

Second Quarter 2014 Power Operations Achievements

• Safety Performance:
  — Maintained top quartile⁷ safety metrics: 0.83 Total Recordable Incident Rate year-to-date
  — No lost-time incidents year-to-date, a record low

• Availability Performance:
  — Achieved record-low fleetwide forced outage factor: 1.5%
  — Delivered record-high fleetwide starting reliability: 99%

• Power Generation:
  — Provided approximately 1.5 million MWh of renewable baseload generation from our Geysers geothermal plants
  — Successfully brought online additional efficient natural gas-fired capacity upon completion of expansions at Deer Park and Channel Energy Centers
  — Channel Energy Center: 100% starting reliability and 0% forced outage factor

Second Quarter 2014 Commercial Operations Achievements:

• Customer-oriented Growth:
  — Entered into a new ten-year PPA, subject to approval by the CPUC, with Southern California Edison to provide 225 MW of capacity and renewable energy from our Geysers assets commencing in June 2017
  — Entered into a new five-year PPA with Dairyland Power Cooperative to provide capacity and energy from our RockGen Energy Center commencing in June 2018. The capacity under contract will initially be 135 MW, then will increase to 235 MW for the final four years of the contract
  — Entered into a new six-year PPA with the City of San Marcos to provide power from our Texas power plant fleet commencing in July 2015
  — Entered into a new two-year PPA with Pedernales Electric Cooperative to provide approximately 70 MW of power from our Texas power plant fleet commencing in August 2016

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^{7 According to EEI Safety Survey (2013).}

2014 FINANCIAL OUTLOOK

(in millions, except per share amounts)

		Full Year 2014
Adjusted EBITDA	$	1,900 - 2,000
Less:
Operating lease payments		35
Major maintenance expense and maintenance capital expenditures^(1)		380
Cash interest, net^(2)		675
Cash taxes		20
Other		5
Adjusted Free Cash Flow	$	785 - 885
Per Share Estimate (diluted)	$	1.85 - 2.10
Debt amortization	$	(200)
Growth capital expenditures (net of debt funding)	$	(300)
Guadalupe Energy Center acquisition (net of debt funding)	$	(244)

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^{(1) Includes projected major maintenance expense of $220 million and maintenance capital expenditures of $160 million. Capital expenditures exclude major construction and development projects.}

^{(2) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income.}

As detailed above, today we are reaffirming our 2014 guidance of Adjusted EBITDA of $1,900 million to $2,000 million, Adjusted Free Cash Flow of $785 million to $885 million and Adjusted Free Cash Flow Per Share guidance of $1.85 to $2.10. With the announcement of our York 2 Energy Center in PJM, we now expect to invest $300 million (net of debt funding) in growth-related projects during the year, including the recently completed Deer Park and Channel Energy Center expansions, ongoing construction of our Garrison Energy Center and the start of construction at York 2.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the second quarter of 2014 on Friday, August 1, 2014, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing [phone] in the U.S. or [phone] outside the U.S. The confirmation code is 37498051. An archived recording of the call will be made available for a limited time on our website or by dialing [phone] in the U.S. or [phone] outside the U.S. and providing confirmation code 37498051. Presentation materials to accompany the conference call will be available on our website on August 1, 2014.

ABOUT CALPINE

Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources. Our fleet of 87 power plants in operation or under construction represents approximately 26,000 megawatts of generation capacity. Serving customers in 17 states and Canada, we specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. We focus on competitive wholesale power markets and advocate for market-driven solutions that result in nondiscriminatory forward price signals for investors. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today.

Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC’s website at www.sec.gov.

FORWARD-LOOKING INFORMATION

In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. 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:

• Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks;
• Laws, regulation and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
• Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Senior Unsecured Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Term Loans and other existing financing obligations;
• Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;
• 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 water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
• The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder;
• Competition, including risks associated with marketing and selling power in the evolving energy markets;
• Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools;
• The expiration or early termination of our PPAs and the related results on revenues;
• Future capacity revenues may not occur at expected levels;
• Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters;
• Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power;
• Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
• Our ability to attract, motivate and retain key employees;
• Present and possible future claims, litigation and enforcement actions; and
• Other risks identified in this press release and in our 2013 Form 10-K.

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 the date of this release. 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions, except share and per share amounts)
Operating revenues:
Commodity revenue	$	1,766		$	1,539		$	3,814		$	2,847
Mark-to-market gain (loss)	169			31			83			(40		)
Other revenue	4			2			7			6
Operating revenues	1,939			1,572			3,904			2,813
Operating expenses:
Fuel and purchased energy expense:
Commodity expense	1,106			998			2,476			1,833
Mark-to-market (gain) loss	28			2			15			(12		)
Fuel and purchased energy expense	1,134			1,000			2,491			1,821
Plant operating expense	274			257			539			484
Depreciation and amortization expense	147			145			300			291
Sales, general and other administrative expense	38			36			71			69
Other operating expenses	21			20			43			38
Total operating expenses	1,614			1,458			3,444			2,703
(Income) from unconsolidated investments in power plants	(4		)	(8		)	(13		)	(16		)
Income from operations	329			122			473			126
Interest expense	169			170			335			346
Interest (income)	(2		)	(1		)	(3		)	(3		)
Debt extinguishment costs	—			68			1			68
Other (income) expense, net	6			3			16			8
Income (loss) before income taxes	156			(118		)	124			(293		)
Income tax expense (benefit)	15			(48		)	(4		)	(98		)
Net income (loss)	141			(70		)	128			(195		)
Net income attributable to the noncontrolling interest	(2		)	—			(6		)	—
Net income (loss) attributable to Calpine	$	139		$	(70	)	$	122		$	(195	)
Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	416,507			447,558			418,296			449,620
Net income (loss) per common share attributable to Calpine — basic	$	0.33		$	(0.16	)	$	0.29		$	(0.43	)
Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)	421,348			447,558			422,697			449,620
Net income (loss) per common share attributable to Calpine — diluted	$	0.33		$	(0.16	)	$	0.29		$	(0.43	)

CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited)
	June 30,			December 31,
	2014			2013
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	442		$	941
Accounts receivable, net of allowance of $7 and $5	762			552
Inventories	374			364
Margin deposits and other prepaid expense	303			309
Restricted cash, current	191			203
Derivative assets, current	746			445
Current assets held for sale	808			—
Other current assets	76			42
Total current assets	3,702			2,856
Property, plant and equipment, net	12,844			12,995
Restricted cash, net of current portion	66			69
Investments in power plants	92			93
Long-term derivative assets	236			105
Other assets	430			441
Total assets	$	17,370		$	16,559
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	614		$	462
Accrued interest payable	189			162
Debt, current portion	189			204
Derivative liabilities, current	706			451
Current liabilities held for sale	9			—
Other current liabilities	439			252
Total current liabilities	2,146			1,531
Debt, net of current portion	11,260			10,908
Long-term derivative liabilities	248			243
Other long-term liabilities	302			309
Total liabilities	13,956			12,991
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding	—			—
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 500,563,630 and 497,841,056 shares issued, respectively, and 417,133,226 and 429,038,988 shares outstanding, respectively	1			1
Treasury stock, at cost, 83,430,404 and 68,802,068 shares, respectively	(1,535		)	(1,230		)
Additional paid-in capital	12,421			12,389
Accumulated deficit	(7,364		)	(7,486		)
Accumulated other comprehensive loss	(168		)	(160		)
Total Calpine stockholders’ equity	3,355			3,514
Noncontrolling interest	59			54
Total stockholders’ equity	3,414			3,568
Total liabilities and stockholders’ equity	$	17,370		$	16,559

CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited)
	Six Months Ended June 30,
	2014			2013
	(in millions)
Cash flows from operating activities:
Net income (loss)	$	128		$	(195	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense^(1)	322			315
Debt extinguishment costs	1			28
Deferred income taxes	(12		)	(15		)
Mark-to-market activity, net	(70		)	24
(Income) from unconsolidated investments in power plants	(13		)	(16		)
Return on unconsolidated investments in power plants	13			16
Stock-based compensation expense	22			20
Other	1			—
Change in operating assets and liabilities:
Accounts receivable	(212		)	(285		)
Derivative instruments, net	(109		)	1
Other assets	(40		)	(182		)
Accounts payable and accrued expenses	378			67
Other liabilities	(60		)	47
Net cash provided by (used in) operating activities	349			(175		)
Cash flows from investing activities:
Purchases of property, plant and equipment	(258		)	(335		)
Purchase of Guadalupe Energy Center, net of cash	(656		)	—
Decrease in restricted cash	14			55
Other	—			(1		)
Net cash used in investing activities		(900	)		(281	)
Cash flows from financing activities:
Borrowings under CCFC Term Loans		420			1,197
Repayment of CCFC Term Loans, CCFC Notes and First Lien Term Loans	(23		)	(1,012		)
Borrowings from project financing, notes payable and other	2			116
Repayments of project financing, notes payable and other	(55		)	(43		)
Financing costs	(10		)	(27		)
Stock repurchases	(297		)	(362		)
Proceeds from exercises of stock options	15			17
Other	—			1
Net cash provided by (used in) financing activities	52			(113		)
Net decrease in cash and cash equivalents	(499		)	(569		)
Cash and cash equivalents, beginning of period	941			1,284
Cash and cash equivalents, end of period	$	442		$	715
Cash paid during the period for:
Interest, net of amounts capitalized	$	288		$	334
Income taxes	$	16		$	21
Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable	$	13		$	17

__________

^{(1) Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations.}

REGULATION G RECONCILIATIONS

Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures that we use as measures of our performance. These measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance.

Net Income (Loss), As Adjusted, represents net income (loss) attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including mark-to-market (gain) loss on derivatives, and other adjustments. Net Income (Loss), As Adjusted, is presented because we believe it is a useful tool for assessing the operating performance of our company in the current period. Net Income (Loss), As Adjusted, is not intended to represent net income (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.

Commodity Margin includes our power and steam revenues, sales of purchased power and physical 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, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities including natural gas transactions hedging future power sales, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income (loss) from operations, 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 net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, adjusted for certain non-cash and non-recurring items as detailed in the following reconciliation. 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 and is not necessarily comparable to similarly titled measures reported by other companies.

We believe Adjusted EBITDA 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.

Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effects of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling contracts and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends.

In summary, our management uses Adjusted EBITDA 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, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.

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 and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies.

Commodity Margin Reconciliation

On July 3, 2014, we announced the closing of the sale of six power plants in our Southeast segment. Accordingly, during the third quarter of 2014, we plan to move the remaining four power plants in our Southeast segment, along with the historical results of the six power plants that were sold, to our North segment and change the name of this geographic segment to “East.” Thus, beginning in the third quarter of 2014, our reportable segments will be West (including geothermal), Texas and East (including North, Southeast and Canada). These changes will be made in conjunction with the manner in which our geographic information will be presented internally to our chief operating decision maker.

During the fourth quarter of 2013, we changed the methodology previously used during 2013 for allocating corporate expenses to our segments. This change had no impact to our Consolidated Condensed Statements of Operations for the three and six months ended June 30, 2013; however, segment amounts previously reported for the three and six months ended June 30, 2013 were adjusted by immaterial amounts.

The following tables reconcile our Commodity Margin to its U.S. GAAP results for the three months ended June 30, 2014 and 2013 (in millions):

	Three Months Ended June 30, 2014
												Consolidation
												And
	West		Texas			North			Southeast			Elimination				Total
Commodity Margin^(1)	$	228	$	177		$	175		$	52		$	—			$	632
Add: Mark-to-market commodity activity, net and other^(2)	21		184			(23		)	(1		)	(8		)		173
Less:
Plant operating expense	95		83			65			38			(7		)		274
Depreciation and amortization expense	58		48			32			8			1				147
Sales, general and other administrative expense	7		18			6			6			1				38
Other operating expenses	15		1			8			1			(4		)		21
(Income) from unconsolidated investments in power plants	—		—			(4		)	—			—				(4		)
Income (loss) from operations	$	74	$	211		$	45		$	(2	)	$	1			$	329
	Three Months Ended June 30, 2013
												Consolidation
												And
	West			Texas		North			Southeast			Elimination				Total
Commodity Margin^(1)	$	198		$	133	$	159		$	43		$	—			$	533
Add: Mark-to-market commodity activity, net and other^(2)	19			34		(12		)	7			(9			)	39
Less:
Plant operating expense	92			93		46			34			(8			)	257
Depreciation and amortization expense	53			42		32			18			—				145
Sales, general and other administrative expense	8			16		6			6			—				36
Other operating expenses	12			1		7			1			(1			)	20
(Income) from unconsolidated investments in power plants	—			—		(8		)	—			—				(8			)
Income (loss) from operations	$	52		$	15	$	64		$	(9	)	$	—			$	122

The following tables reconcile our Commodity Margin to its U.S. GAAP results for the six months ended June 30, 2014 and 2013 (in millions):

	Six Months Ended June 30, 2014
													Consolidation
													And
	West			Texas			North			Southeast			Elimination			Total
Commodity Margin^(3)	$	430		$	298		$	442		$	107		$	—		$	1,277
Add: Mark-to-market commodity activity, net and other^(4)		50			138			(40	)		5			(17	)		136
Less:
Plant operating expense		200			173			117			65			(16	)		539
Depreciation and amortization expense		118			90			65			26			1			300
Sales, general and other administrative expense		17			30			12			12			—			71
Other operating expenses		27			3			14			2			(3	)		43
(Income) from unconsolidated investments in power plants		—			—			(13	)		—			—			(13	)
Income from operations	$	118		$	140		$	207		$	7		$	1		$	473
	Six Months Ended June 30, 2013
													Consolidation
													And
	West			Texas			North			Southeast			Elimination			Total
Commodity Margin^(3)	$	400		$	209		$	301		$	84		$	—		$	994
Add: Mark-to-market commodity activity, net and other^(4)		(18	)		23			(5	)		14			(16	)		(2	)
Less:
Plant operating expense		187			158			89			65			(15	)		484
Depreciation and amortization expense		106			84			65			37			(1	)		291
Sales, general and other administrative expense		15			30			12			12			—			69
Other operating expenses		21			2			14			2			(1	)		38
(Income) from unconsolidated investments in power plants		—			—			(16	)		—			—			(16	)
Income (loss) from operations	$	53		$	(42	)	$	132		$	(18	)	$	1		$	126

_________

^{(1) Our Southeast segment includes Commodity Margin of $42 million and $32 million for the three months ended June 30, 2014 and 2013, respectively, related to the six power plants in our Southeast segment that were sold in July 2014.}

^{(2) Includes $(27) million and $(11) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended June 30, 2014 and 2013, respectively.}

^{(3) Our Southeast segment includes Commodity Margin of $81 million and $57 million for the six months ended June 30, 2014 and 2013, respectively, related to the six power plants in our Southeast segment that were sold in July 2014.}

^{(4) Includes $(56) million and $(27) million of lease levelization and $7 million and $7 million of amortization expense for the six months ended June 30, 2014 and 2013, respectively.}

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income (loss) attributable to Calpine for the three and six months ended June 30, 2014 and 2013, as reported under U.S. GAAP.

	Three Months Ended June 30,						Six Months Ended June 30,
	2014^(1)			2013			2014^(2)			2013
	(in millions)						(in millions)
Net income (loss) attributable to Calpine	$	139		$	(70	)	$	122		$	(195	)
Net income attributable to the noncontrolling interest	2			—			6			—
Income tax expense (benefit)	15			(48		)	(4		)	(98		)
Debt extinguishment costs and other (income) expense, net	6			71			17			76
Interest expense, net of interest income	167			169			332			343
Income from operations	$	329		$	122		$	473		$	126
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs^(3)	146			146			297			292
Major maintenance expense	72			83			153			149
Operating lease expense	8			8			17			17
Mark-to-market (gain) loss on commodity derivative activity	(141		)	(29		)	(68		)	28
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest^(4)	6			7			9			13
Stock-based compensation expense	12			12			22			20
Loss on dispositions of assets	1			2			1			4
Acquired contract amortization	3			3			7			7
Other	(23		)	(11		)	(52		)	(27		)
Total Adjusted EBITDA	$	413		$	343		$	859		$	629
Less:
Operating lease payments	8			8			17			17
Major maintenance expense and capital expenditures^(5)	126			105			259			241
Cash interest, net^(6)	169			175			337			355
Cash taxes	8			14			14			17
Other	3			3			3			4
Adjusted Free Cash Flow^(7)	$	99		$	38		$	229		$	(5	)
Weighted average shares of common stock outstanding (diluted, in thousands)	421,348			447,558			422,697			449,620
Adjusted Free Cash Flow Per Share (diluted)	$	0.23		$	0.08		$	0.54		$	(0.01	)

_________

^{(1) Our Southeast segment includes Adjusted EBITDA of $23 million and $15 million for the three months ended June 30, 2014 and 2013, respectively, related to the six power plants in our Southeast segment that were sold in July 2014.}

^{(2) Our Southeast segment includes Adjusted EBITDA of $43 million and $21 million for the six months ended June 30, 2014 and 2013, respectively, related to the six power plants in our Southeast segment that were sold in July 2014.}

^{(3) Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets.}

^{(4) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and six months ended June 30, 2014 and 2013.}

^{(5) Includes $73 million and $156 million in major maintenance expense for the three and six months ended June 30, 2014, respectively, and $53 million and $103 million in maintenance capital expenditure for the three and six months ended June 30, 2014, respectively. Includes $85 million and $151 million in major maintenance expense for the three and six months ended June 30, 2013, respectively, and $20 million and $90 million in maintenance capital expenditure for the three and six months ended June 30, 2013, 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 an increase in working capital of $36 million and $42 million for the three and six months ended June 30, 2014, respectively, and an increase in working capital of $112 million and $206 million for the three and six months ended June 30, 2013, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance.}

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 six months ended June 30, 2014 and 2013. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above.

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Commodity Margin	$	632		$	533		$	1,277		$	994
Other revenue	4			3			7			6
Plant operating expense^(1)	(191		)	(166		)	(368		)	(320		)
Sales, general and administrative expense^(2)	(31		)	(30		)	(60		)	(59		)
Other operating expenses^(3)	(12		)	(11		)	(24		)	(21		)
Adjusted EBITDA from unconsolidated investments in power plants^(4)	12			14			28			29
Other	(1		)	—			(1		)	—
Adjusted EBITDA	$	413		$	343		$	859		$	629

_________

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

^{(2) Shown net of stock-based compensation expense and other costs.}

^{(3) Shown net of operating lease expense, amortization and other costs.}

^{(4) Amount is composed of income from unconsolidated investments in power plants, as well as adjustments to reflect Adjusted EBITDA from unconsolidated investments.}

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance

Full Year 2014 Range:		Low			High
		(in millions)
GAAP Net Income ^(1)	$	680		$	780
Plus:
Debt extinguishment costs		340			340
Interest expense, net of interest income		675			675
Depreciation and amortization expense		610			610
Major maintenance expense		215			215
Operating lease expense		35			35
Gain on sale of assets, net		(750	)		(750	)
Other^(2)		95			95
Adjusted EBITDA	$	1,900		$	2,000
Less:
Operating lease payments		35			35
Major maintenance expense and maintenance capital expenditures^(3)		380			380
Cash interest, net^(4)		675			675
Cash taxes		20			20
Other		5			5
Adjusted Free Cash Flow	$	785		$	885

_________

^{(1) For purposes of Net Income guidance reconciliation, mark-to-market adjustments are assumed to be nil.}

^{(2) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items.}

^{(3) Includes projected major maintenance expense of $220 million and maintenance capital expenditures of $160 million. Capital expenditures exclude major construction and development projects.}

^{(4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income.}

OPERATING PERFORMANCE METRICS

The table below shows the operating performance metrics for the periods presented:

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Total MWh generated (in thousands)^(1)	23,085		22,339		46,062		46,337
West	6,770		7,229		15,601		15,566
Texas	9,489		7,270		16,366		15,300
North	3,332		4,067		6,977		7,976
Southeast	3,494		3,773		7,118		7,495
Average availability	88.1	%	88.2	%	88.3	%	89.2	%
West	91.6	%	88.8	%	90.3	%	88.7	%
Texas	90.8	%	83.5	%	86.9	%	85.4	%
North	79.0	%	88.2	%	83.6	%	90.2	%
Southeast	89.9	%	95.2	%	93.8	%	94.7	%
Average capacity factor, excluding peakers	41.7	%	43.4	%	42.4	%	45.5	%
West	44.0	%	52.5	%	51.1	%	57.0	%
Texas	48.9	%	42.8	%	44.2	%	45.3	%
North	35.1	%	42.9	%	36.8	%	43.1	%
Southeast	31.2	%	33.7	%	32.0	%	33.7	%
Steam adjusted heat rate (Btu/kWh)	7,433		7,447		7,393		7,394
West	7,377		7,414		7,301		7,345
Texas	7,282		7,184		7,227		7,173
North	8,061		8,015		8,014		7,963
Southeast	7,368		7,429		7,373		7,349

________

^{(1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.}