Calpine Corp. Reports Excellent 2009 Third Quarter Operating Results; Updates 2009 and Provides 2010 Guidance

http://www.businesswire.com/news/home/20091030005246/en

Recent Achievements:

* Increased fleet-wide capacity factor to 60.7% during third quarter of 2009,
compared to 55.2% in third quarter of 2008
* Produced 1.5 million MWh of renewable generation during third quarter of 2009
at The Geysers with 99% availability factor
* Achieved commercial operation at Otay Mesa Energy Center in San Diego County,
Calif.
* Signed new and restructured contracts with key customers for approximately
2,800 MW of capacity
* Announced upgrade of Los Esteros Critical Energy Facility in San Jose, Calif.,
to add 120 MW of clean, reliable capacity and improve plant efficiency
* Successfully issued approximately $1.2 billion of Senior Secured Notes due
2017 to retire an equal principal amount of term loans due 2014

September 2009 YTD Financial Results:

* $1,374 million of Adjusted EBITDA
* $1,947 million of Commodity Margin
* $520 million of Adjusted Free Cash Flow
* $192 million of Net Income1

Third Quarter 2009 Financial Results:

* $586 million of Adjusted EBITDA
* $768 million of Commodity Margin
* $363 million of Adjusted Free Cash Flow
* $238 million of Net Income1

Raising and Tightening 2009 Full Year Guidance and Providing 2010 Full Year
Guidance:

* 2009 Adjusted EBITDA guidance of $1,710 - $1,735 million
* 2009 Adjusted Free Cash Flow guidance of $530 - $580 million
* 2010 Adjusted EBITDA guidance of $1,500 - $1,600 million
* 2010 Adjusted Free Cash Flow guidance of $400 - $500 million

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

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

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

SUMMARY OF FINANCIAL PERFORMANCE

Third Quarter Results

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

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

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

Year-to-Date Results

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

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

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

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

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

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

Table 1: Summarized Consolidated Condensed Statements of Operations

(Unaudited)
Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 2009 2008
(in millions)
Operating revenues $ 1,847 $ 3,190 $ 4,995 $ 7,969
Cost of revenue 1,354 2,656 4,014 6,988
Gross profit 493 534 981 981
SG&A, (income) loss from unconsolidated investments in 56 262 118 358

power plants and other operating expense
Income from operations 437 272 863 623
Net interest expense, debt extinguishment costs and other (income) expense 215 219 659 828
Income (loss) before reorganization items and income taxes 222 53 204 (205 )
Reorganization items (8 ) (2 ) (2 ) (263 )
Income tax expense (benefit) (7 ) (80 ) 17 (60 )
Net income $ 237 $ 135 $ 189 $ 118

Net loss attributable to the noncontrolling interest 1 1 3 1
Net income attributable to Calpine $ 238 $ 136 $ 192 $ 119

Reorganization items(1) (8 ) (2 ) (2 ) (263 )
Other one-time items(1)(2) 10 192 30 367
Net income (loss), net of reorganization items and other one-time items 240 326 220 223
Unrealized MtM (gains) losses on derivatives(1)(3) (44 ) (47 ) (67 ) 16
Net income, net of reorganization items other one-time items and unrealized MtM impacts $ 196 $ 279 $ 153 $ 239

(1) Shown net of tax, assuming a 0% effective tax rate for
these items (other than those referenced in note 2 below).
(2) One-time items in the three and nine months ended
September 30, 2009, include $16 million and $49 million,
respectively, in debt extinguishment costs, shown net of tax
assuming a 38.4% effective tax rate. One-time items in both the
three and nine months ended September 30, 2008, include an
impairment loss of $179 million associated with our Auburndale
plant and $13 million in settlement costs. One-time items in the
nine months ended September 30, 2008, also include $13 million in
debt extinguishment costs, as well as $135 million in
post-petition interest expense and $27 million in settlement
obligations related to the Canadian debtors and other
deconsolidated foreign entities recorded prior to their
reconsolidation in February 2008, both of which were associated
with our emergence from bankruptcy.
(3) Represents unrealized mark-to-market (MtM) (gains) losses
on contracts that did not qualify as hedges under the hedge
accounting guidelines or qualified under the hedge accounting
guidelines and the hedge accounting designation had not been
elected.

REGIONAL SEGMENT REVIEW OF RESULTS
Table 2: Commodity Margin by Segment (in millions)

Three Months Ended September 30, Nine Months Ended September 30,
2009 2008(1) 2009 2008(1)

West $ 393 $ 372 $ 994 $ 965
Texas 187 233 505 587
Southeast 92 95 233 208
North 96 100 215 228
Total $ 768 $ 800 $ 1,947 $ 1,988

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

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

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

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

Table 3: Corporate Liquidity

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

(1) Includes $1 million and $169 million of margin deposits
held by us posted by our counterparties as of September 30, 2009,
and December 31, 2008, respectively.
(2) Includes available balances for Calpine Development
Holdings, Inc.
(3) Excludes contingent amounts of $150 million under the
Knock-in Facility and $200 million under the Commodity Collateral
Revolver as of December 31, 2008.

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

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

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

PLANT DEVELOPMENT

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

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

OPERATIONS UPDATE

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

* Safety Performance: Maintained top-quartile safety performance with
year-to-date lost-time incident rate of 0.19
* Availability Performance:

* Provided 99% or higher availability on nearly 60% of our capacity during the
third quarter
* Achieved fleet-wide forced outage factor of only 2.19%
* Delivered natural gas fleet starting reliability of 98.1%

* Geothermal Generation: Provided 1.5 million MWh of renewable baseload
generation with 93% capacity factor and 0.21% forced outage factor
* Sustainable Cost Reductions: Reduced controllable expenses2 as a component of
plant operating expense by $19 million in the third quarter of 2009 compared to
the third quarter of 2008, after accounting for $15 million of prior period
insurance proceeds that benefited the 2008 period

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

* Customer-led growth: Worked with key customers toward significant new and
amended long-term contracts covering approximately 2,800 MW of capacity in
California

* Extended term and increased volume of existing contracts with PG&E at The
Geysers geothermal plants
* Entered into replacement contract with PG&E for our California peaking plants
* Signed new agreement with PG&E for our Los Esteros plant, under which we will
upgrade the existing plant
* Entered into a new tolling agreement with PG&E for all the capacity at our
Delta plant
* Executed a resource adequacy agreement for all of the capacity from our
Pastoria power plant with Southern California Edison

* Effective hedging: Maintained stable year-over-year Adjusted EBITDA, despite
declining commodity prices

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

FINANCIAL OUTLOOK

Table 4: Adjusted EBITDA and Adjusted Free Cash Flow Guidance

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

(1) Includes projected Major Maintenance Expense of $200
million and $180 million in 2009 and 2010, respectively, and
maintenance Capital Expenditures of $150 million and $110 million
in 2009 and 2010, respectively. Capital expenditures exclude major
construction and development projects.
(2) Excludes changes in cash collateral for commodity
procurement and risk management activities.

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

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

INVESTOR CONFERENCE CALL AND WEBCAST

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

ABOUT CALPINE

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

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

FORWARD-LOOKING INFORMATION

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

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

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

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 2009 2008
(in millions, except share and per share amounts)
Operating revenues $ 1,847 $ 3,190 $ 4,995 $ 7,969

Cost of revenue:
Fuel and purchased energy expense 1,030 2,322 2,967 5,935
Plant operating expense 196 198 654 636
Depreciation and amortization expense 108 110 330 329
Other cost of revenue 20 26 63 88
Total cost of revenue 1,354 2,656 4,014 6,988
Gross profit 493 534 981 981
Sales, general and other administrative expense 38 58 131 154
(Income) loss from unconsolidated investments in power plants 13 202 (27 ) 189
Other operating expense 5 2 14 15
Income from operations 437 272 863 623
Interest expense 198 212 615 837
Interest (income) (3 ) (11 ) (13 ) (38 )
Debt extinguishment costs 16 - 49 13
Other (income) expense, net 4 18 8 16
Income (loss) before reorganization items and income taxes 222 53 204 (205 )
Reorganization items (8 ) (2 ) (2 ) (263 )
Income before income taxes 230 55 206 58
Income tax expense (benefit) (7 ) (80 ) 17 (60 )
Net income $ 237 $ 135 $ 189 $ 118
Net loss attributable to the noncontrolling interest 1 1 3 1
Net income attributable to Calpine $ 238 $ 136 $ 192 $ 119

Basic earnings per common share:
Weighted average shares of common stock outstanding (in thousands) 485,736 485,076 485,619 485,027
Net income per common share attributable to Calpine - basic $ 0.49 $ 0.28 $ 0.40 $ 0.25

Diluted earnings per common share:
Weighted average shares of common stock outstanding (in thousands) 486,585 485,744 486,171 485,588
Net income per common share attributable to Calpine - diluted $ 0.49 $ 0.28 $ 0.39 $ 0.25

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

September 30, December 31,
2009 2008
(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 913 $ 1,657
Accounts receivable, net of allowance of $19 and $42 880 850
Inventory 164 163
Margin deposits and other prepaid expense 418 776
Restricted cash, current 461 337
Current derivative assets 2,032 3,653
Other current assets 37 64
Total current assets 4,905 7,500

Property, plant and equipment, net 11,683 11,908
Restricted cash, net of current portion 44 166
Investments 210 144
Long-term derivative assets 288 404
Other assets 571 616
Total assets $ 17,701 $ 20,738
LIABILITIES & STOCKHOLDERS` EQUITY
Current liabilities:
Accounts payable $ 605 $ 574
Accrued interest payable 71 85
Debt, current portion 421 716
Current derivative liabilities 2,097 3,799
Income taxes payable 7 5
Other current liabilities 245 437
Total current liabilities 3,446 5,616

Debt, net of current portion 9,064 9,756
Deferred income taxes, net of current portion 64 93
Long-term derivative liabilities 421 698
Other long-term liabilities 207 203
Total liabilities 13,202 16,366

Stockholders` equity:
Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding at September 30, 2009 and December 31, 2008 - -
Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 442,699,628 shares issued and 442,372,296 shares outstanding at September 30, 2009; 429,025,057 shares issued and 428,960,025 shares outstanding at December 31, 2008 1 1
Treasury stock, at cost; 327,332 shares at September 30, 2009 and 65,032 shares at December 31, 2008 (3 ) (1 )
Additional paid-in capital 12,249 12,217
Accumulated deficit (7,497 ) (7,689 )
Accumulated other comprehensive loss (250 ) (158 )
Total Calpine stockholders` equity 4,500 4,370
Noncontrolling interest (1 ) 2
Total stockholders` equity 4,499 4,372
Total liabilities and stockholders` equity $ 17,701 $ 20,738

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

Nine Months Ended September 30,
2009 2008
(in millions)
Cash flows from operating activities:
Net income $ 189 $ 118
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1) 399 411
(Income) loss from unconsolidated investments in power plants (27 ) 189
Debt extinguishment costs 9 7
Deferred income taxes 15 (60 )
Loss on disposal of assets, excluding reorganization items 29 6
Mark-to-market activity, net (67 ) 15
Stock-based compensation expense 30 36
Reorganization items (7 ) (331 )
Other 6 21
Change in operating assets and liabilities:
Accounts receivable (23 ) 126
Derivative instruments (239 ) (45 )
Other assets 387 96
Accounts payable, LSTC and accrued expenses 13 (76 )
Other liabilities (177 ) (158 )
Net cash provided by operating activities 537 355
Cash flows from investing activities:
Purchases of property, plant and equipment (140 ) (108 )
Disposals of property, plant and equipment - 16
Proceeds from sale of power plants, turbines and investments - 398
Cash acquired due to reconsolidation of the Canadian Debtors and other deconsolidated foreign entities - 64
Contributions to unconsolidated investments (19 ) (14 )
Return of investment from unconsolidated investments - 26
(Increase) decrease in restricted cash (2 ) 145
Other (3 ) 7
Net cash provided by (used in) investing activities (164 ) 534
Cash flows from financing activities:
Repayments of notes payable (106 ) (98 )
Repayments of project financing (889 ) (274 )
Borrowings from project financing 1,028 356
Repayments of DIP Facility - (98 )
Borrowings under First Lien Facilities - 3,523
Repayments on First Lien Facilities (770 ) (1,460 )
Borrowings under Commodity Collateral Revolver - 100
Repayments on Second Priority Debt - (3,672 )
Repayments on capital leases (34 ) (29 )
Redemptions of preferred interests (310 ) (166 )
Financing costs (34 ) (207 )
Derivative contracts classified as financing activities - 70
Other 2 2
Net cash used in financing activities (1,117 ) (1,953 )
Net decrease in cash and cash equivalents (744 ) (1,064 )
Cash and cash equivalents, beginning of period 1,657 1,915
Cash and cash equivalents, end of period $ 913 $ 851

Cash paid (received) during the period for:
Interest, net of amounts capitalized $ 563 $ 873
Income taxes $ 6 $ 16
Reorganization items included in operating activities, net $ 5 $ 124
Reorganization items included in investing activities, net $ - $ (414 )

Supplemental disclosure of non-cash investing and financing activities:
Settlement of commodity contract with project financing $ 79 $ -
Change in capital expenditures included in accounts payable $ 3 $ 13
Settlement of LSTC through issuance of reorganized Calpine Corporation common stock $ - $ 5,200
DIP Facility borrowings converted into exit financing under First Lien Facilities $ - $ 3,872
Settlement of Convertible Senior Notes and Unsecured Senior Notes with reorganized Calpine Corporation common stock $ - $ 3,703

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

REGULATION G RECONCILIATIONS

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

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

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

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

Commodity Margin Reconciliation

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

Three Months Ended September 30, 2009
(in millions)
Consolidation
And
West Texas Southeast North Elimination Total
Commodity Margin $ 393 $ 187 $ 92 $ 96 $ - $768
Add: Mark-to-market commodity activity, net and other revenue(1) 41 2 (4 ) 21 (12 ) 48
Less:
Plant operating expense 99 35 27 18 17 196
Depreciation and amortization expense 49 27 17 16 (1 ) 108
Other cost of revenue(2) 18 6 3 10 (18 ) 19
Gross profit $ 268 $ 121 $ 41 $ 73 $ (10 ) $493

Three Months Ended September 30, 2008
(in millions)
Consolidation
And
West Texas Southeast North Elimination Total
Commodity Margin $ 372 $ 233 $ 95 $ 100 $ - $800
Add: Mark-to-market commodity activity, net and other revenue(1) (45 ) 188 3 (69 ) (9 ) 68
Less:
Plant operating expense 96 56 31 23 (8 ) 198
Depreciation and amortization expense 48 31 16 15 - 110
Other cost of revenue(2) 19 3 5 8 (9 ) 26
Gross profit (loss) $ 164 $ 331 $ 46 $ (15 ) $ 8 $534

(1) Mark-to-market commodity activity represents the
unrealized portion of our mark-to-market activity, net, as well as
a non-cash gain from amortization of prepaid power sales
agreements included in operating revenues and fuel and purchased
energy expense on our Consolidated Condensed Statements of
Operations.
(2) Excludes $1 million and nil of RGGI compliance costs for
the three months ended September 30, 2009 and 2008, respectively,
which were included as a component of Commodity Margin.

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

Nine Months Ended September 30, 2009
(in millions)
Consolidation
And
West Texas Southeast North Elimination Total
Commodity Margin $ 994 $ 505 $ 233 $ 215 $ - $ 1,947
Add: Mark-to-market commodity activity, net and other revenue(1) 120 (48 ) 2 37 (35 ) 76
Less:
Plant operating expense 326 163 94 61 10 654
Depreciation and amortization expense 150 88 50 47 (5 ) 330
Other cost of revenue(2) 45 11 7 23 (28 ) 58
Gross profit $ 593 $ 195 $ 84 $ 121 $ (12 ) $ 981

Nine Months Ended September 30, 2008
(in millions)
Consolidation
And
West Texas Southeast North Elimination Total
Commodity Margin $ 965 $ 587 $ 208 $ 228 $ - $ 1,988
Add: Mark-to-market commodity activity, net and other revenue(1) (30 ) 114 6 (24 ) (20 ) 46
Less:
Plant operating expense 309 178 84 73 (8 ) 636
Depreciation and amortization expense 143 94 54 40 (2 ) 329
Other cost of revenue(2) 54 9 23 21 (19 ) 88
Gross profit $ 429 $ 420 $ 53 $ 70 $ 9 $ 981

(1)  Mark-to-market commodity activity represents the
unrealized portion of our mark-to-market activity, net, as well as
a non-cash gain from amortization of prepaid power sales
agreements included in operating revenues and fuel and purchased
energy expense on our Consolidated Condensed Statements of
Operations.
(2)  Excludes $5 million and nil of RGGI compliance costs for
the nine months ended September 30, 2009 and 2008, respectively,
which were included as a component of Commodity Margin.

Consolidated Adjusted EBITDA Reconciliation

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

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

(1) Adjusted EBITDA for the three and nine months ended
September 30, 2008, has been recast to conform to our current
period definition.
(2) Depreciation and amortization expense in the income from
operations calculation on our Consolidated Condensed Statements of
Operations excludes amortization of other assets and amounts
classified as sales, general and other administrative expenses.
(3) Included in our Consolidated Condensed Statements of
Operations in (income) loss from unconsolidated investments in
power plants.
(4) Adjustments to reflect Adjusted EBITDA from
unconsolidated investments include $14 million and $12 million in
unrealized (gains) losses on mark-to-market activity for the three
months ended September 30, 2009 and 2008, respectively, and $(14)
million and $4 million for the nine months ended September 30,
2009 and 2008, respectively.
(5) Includes $22 million and $124 million in major
maintenance expense for the three and nine months ended September
30, 2009, respectively, and $45 million and $140 million in
capital expenditures for the three and nine months ended September
30, 2009, respectively.
(6) Includes fees for letters of credit, net of interest
income.

Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance

Full Year 2009 Range: Low High
(in millions)
GAAP Net Income $ 80 $ 105
Plus:
Interest expense, net of interest income 795 795
Depreciation and amortization expense 455 455
Major maintenance expense 200 200
Operating lease expense 50 50
Other(1) 130 130
Adjusted EBITDA $ 1,710 $ 1,735
Less:
Operating lease payments 50 50
Major maintenance expense and maintenance capital expenditures(2) 350 350
Cash interest, net(3) 775 775
Cash taxes 5 5
Working capital and other adjustments - (25 )
Adjusted Free Cash Flow $ 530 $ 580

Full Year 2010 Range: Low High
(in millions)
GAAP Net Income $ (30 ) $ 70
Plus:
Interest expense, net of interest income 750 750
Depreciation and amortization expense 465 465
Major maintenance expense 180 180
Operating lease expense 50 50
Other(1) 85 85
Adjusted EBITDA $ 1,500 $ 1,600
Less:
Operating lease payments 50 50
Major maintenance expense and maintenance capital expenditures(2) 290 290
Cash interest, net(3) 750 750
Cash taxes 10 10
Adjusted Free Cash Flow $ 400 $ 500

(1) Other includes stock-based compensation expense and other
adjustments.
(2) Includes projected Major Maintenance Expense of $200
million and $180 million in 2009 and 2010, respectively and
maintenance Capital Expenditures of $150 million and $110 million
in 2009 and 2010, respectively. Capital expenditures exclude major
construction and development projects.
(3) Includes fees for letters of credit, net of interest
income.

CASH FLOW ACTIVITIES

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

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

OPERATING PERFORMANCE METRICS

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

Three Months Ended September 30, Nine Months Ended September 30,
2009 2008 2009 2008
Total MWh generated(1) (in thousands) 28,051 25,773 66,717 67,890
West 10,447 10,563 26,108 27,702
Texas 10,246 9,830 23,058 27,048
Southeast 6,006 3,753 13,842 9,058
North 1,352 1,627 3,709 4,082

Average availability 97.1 % 96.6 % 92.9 % 90.8 %
West 95.2 % 95.8 % 92.3 % 89.6 %
Texas 97.5 % 96.9 % 92.1 % 90.1 %
Southeast 98.2 % 97.4 % 93.3 % 92.6 %
North 98.5 % 96.7 % 95.5 % 92.0 %

Average capacity factor, excluding peakers 60.7 % 55.2 % 49.0 % 49.0 %
West 73.0 % 73.9 % 62.3 % 65.9 %
Texas 64.0 % 61.4 % 48.5 % 56.7 %
Southeast 51.0 % 29.8 % 40.0 % 24.5 %
North 31.5 % 39.1 % 30.1 % 33.8 %

Steam adjusted Heat Rate 7,268 7,274 7,246 7,237
West 7,302 7,314 7,299 7,287
Texas 7,227 7,147 7,149 7,090
Southeast 7,187 7,335 7,214 7,409
North 7,758 7,722 7,693 7,596

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

Calpine Corporation
Media Relations:
Norma F. Dunn, 713-830-8883
norma.dunn@calpine.com
or
Investor Relations:
Andre K. Walker, 713-830-8775
andrew@calpine.com

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