12:04 | 25.02.2010
Calpine Corp. Reports Strong Fourth Quarter and Full Year 2009 Results, Exceeding Guidance
Calpine Corporation (NYSE: CPN) today reported 2009 Adjusted EBITDA of
$1,782 million, up $83 million, or 5%, over the prior year despite
recessionary influences. Although 2009 commodity prices were lower than
in 2008 and annual U.S. power demand was down nearly 4% year-over-year,
our Commodity Margin of $2,562 million was relatively unchanged from
2008. The company also reported strong 2009 Adjusted Free Cash Flow of
$609 million, an increase of 23% over 2008 results. Additionally,
corporate liquidity increased by more than $200 million in 2009 to
$2,379 million. Net income1 during the year was $149 million,
or $0.31 per diluted share, compared to net income of $10 million, or
$0.02 per diluted share, in 2008.
“Our exceptional 2009 operating and commercial performance translated
into a strong financial performance, particularly given the depressed
general market and economic environment. We have made significant
progress toward our goal of being ‘best in class’,” said Jack Fusco,
Calpine’s President and Chief Executive Officer. “We improved on several
key operating metrics, including our forced outage and availability
factors, demonstrating our commitment to delivering clean, efficient and
reliable energy and services to our customers. Our strong financial
results reflect the effectiveness of our hedging program as well as the
success of our efficiency initiatives in 2009. During the year, we also
accomplished several noteworthy achievements, including the successful
commissioning of our Otay Mesa Energy Center, the opportunistic
refinancing of approximately $3.0 billion of debt and the origination of
several important contracts with key customers throughout the country.
“Looking ahead to 2010, today we are reaffirming our Adjusted EBITDA
guidance of $1.5 to $1.6 billion and our Adjusted Free Cash Flow
guidance of $400 to $500 million. I am pleased that our proactive
hedging efforts have substantially mitigated our exposure to natural gas
price risk in 2010, allowing us to continue to focus on excellence in
operations, customer-focused origination and disciplined strategic
growth,” Fusco said.
“Our growth projects include our turbine upgrade program, expansion at
The Geysers, and construction of the Russell City Energy Center as well
as the expansion of our Los Esteros Critical Energy Facility, both
located in California. These projects reaffirm Calpine’s position as a
long-term leader in environmental stewardship through operation of and
investment in clean technologies.”
SUMMARY OF FINANCIAL PERFORMANCEFull Year Results
Adjusted EBITDA for the year ended December 31, 2009, was $1,782
million, compared to $1,699 million in the prior year period. The $83
million improvement year-over-year was primarily due to three factors.
First, Commodity Margin increased by $38 million during the 2009 period.
This improvement was due to higher average hedge margins in 2009
compared to 2008 and strong performance by our Southeast segment, which
experienced a 35% increase in generation in 2009 largely due to higher
natural gas generation displacement of coal generation in certain
sub-markets of that segment, caused by lower natural gas prices
resulting in higher market heat rates.
Secondly, in the 2009 period, we reduced aggregate plant operating
expense2, sales, general and administrative expense2,
and components of other cost of revenue by $61 million, after excluding
a $29 million decrease in reimbursements for insurance claims from prior
periods that reduced plant operating expense in the 2008 period and, to
a much lesser extent, the 2009 period. These cost improvements were due,
in large part, to efficiency efforts that we implemented over the course
of 2009. Finally, Adjusted EBITDA from unconsolidated investments
increased by $41 million in 2009 compared to the corresponding 2008
period, primarily as a result of Greenfield Energy Centre achieving
commercial operations in the fourth quarter of 2008 and Otay Mesa Energy
Center achieving commercial operations in the fourth quarter of 2009.
These increases were offset, in part by a $36 million decrease in other
revenue associated with declines in revenues from operations and
maintenance and construction management projects and royalty income on
oil and gas producing properties.
Net income1 increased to $149 million for the year ended
December 31, 2009, from $10 million in the prior year period. As
detailed in Table 1, net income, excluding reorganization items,
discontinued operations, other items and unrealized mark-to-market gains
or losses, increased from $62 million in 2008 to $141 million in 2009.
The improvement is primarily attributable to income from unconsolidated
investments in power plants, which increased by $99 million, excluding
an impairment loss of $180 million in 2008. In addition, the increase
was due to the $38 million improvement in Commodity Margin previously
noted. Offsetting these improvements, income tax expense increased by
$62 million in 2009 compared to 2008, primarily due to non-cash changes
in our intraperiod tax allocations.
Cash flows provided by operating activities for the twelve months ended
December 31, 2009, improved to $761 million compared to $494 million for
the 2008 period. Cash paid for interest decreased by $299 million in
2009, primarily due to the repayment of the Second Priority Debt, and,
to a lesser extent, lower interest rates for the comparable period in
2009. In addition, cash payments for reorganization items decreased by
$115 million. Meanwhile, working capital employed, after adjusting for
debt-related balances and derivative activities, which did not impact
cash provided by operating activities, increased by approximately $152
million for the 2009 period compared to 2008. The increase was primarily
due to a reduction in assets held for sale during 2008 for which there
was not a corresponding change in 2009, offset by a net reduction in
working capital employed in 2009 for margins and net accounts receivable
and payable. Finally, cash payments for debt extinguishment costs in
2009 were $39 million related to the CCFC Refinancing, compared to cash
payments of $6 million related to the refinancing of Blue Spruce and
Metcalf in 2008.
Fourth Quarter Results
Adjusted EBITDA for the fourth quarter of 2009 was $408 million, up $83
million from the prior year period. The year-over-year improvement was
primarily due to a $79 million increase in Commodity Margin to $615
million in 2009 from $536 million in 2008. The Commodity Margin
improvement was primarily attributable to our West region, which
benefited from strong hedges, despite a weaker commodity price
environment. In addition, our Southeast segment also benefited from
hedge positions.
Adjusted EBITDA was also favorably impacted by a $22 million increase in
Adjusted EBITDA from unconsolidated investments, primarily associated
with our Otay Mesa plant, which achieved commercial operation in the
fourth quarter of 2009.
These improvements were offset, in part, by a $17 million decline in
other revenue from the fourth quarter of 2008 to the fourth quarter of
2009, primarily the result of lower royalty income on oil and gas
producing properties.
Net loss1 decreased from $109 million in the fourth quarter
of 2008 to $43 million in the fourth quarter of 2009. As detailed in
Table 1, net loss, excluding reorganization items, other items and
unrealized mark-to-market gains or losses, decreased from $177 million
in the fourth quarter of 2008 to $12 million in the fourth quarter of
2009. This improvement was primarily associated with the $79 million
year-over-year increase in Commodity Margin, as previously noted. In
addition, income from unconsolidated investments in power plants
increased by $62 million, excluding a $1 million impairment loss in
2008. Plant operating expense and sales, general and administrative
expense, as reported, decreased by $39 million and $9 million,
respectively, due, in part, to the efficiency efforts previously
mentioned. These benefits were offset, in part, by the $17 million
decline in other revenue noted above.
1 Reported as net income (loss) attributable to Calpine on
our Consolidated Statements of Operations.
2 Plant operating expense and sales, general and
administrative expense exclude, in the aggregate, decreases in major
maintenance expense of $16 million, decreases in stock-based
compensation expense of $12 million, decreases in non-cash loss on
dispositions of assets of $2 million, and decreases in depreciation and
amortization of $2 million. See the table titled “Consolidated Adjusted
EBITDA Reconciliation” for the actual amounts of these items in 2008 and
2009.
Table 1: Summarized Consolidated Condensed Statements of Operations
(Unaudited)
Three Months Ended December 31,
Year Ended December 31,
2009
2008
2009
2008
(in millions)
Operating revenues
$
1,569
$
1,968
$
6,564
$
9,937
Cost of revenue
1,335
1,791
5,349
8,779
Gross profit
234
177
1,215
1,158
SG&A, (income) loss from unconsolidated investments in power
plants and other operating expense
33
112
151
470
Income from operations
201
65
1,064
688
Net interest expense, debt extinguishment costs and other (income)
expense
246
223
905
1,051
Income (loss) before reorganization items, income taxes and
discontinued operations
(45
)
(158
)
159
(363
)
Reorganization items
1
(39
)
(1
)
(302
)
Income (loss) before income taxes and discontinued operations
(46
)
(119
)
160
(61
)
Income tax expense (benefit)
(2
)
13
15
(47
)
Income (loss) before discontinued operations
(44
)
(132
)
145
(14
)
Discontinued operations, net of tax provision of $14 in 2008
—
23
—
23
Net income (loss)
$
(44
)
$
(109
)
$
145
$
9
Net loss attributable to the noncontrolling interest
1
—
4
1
Net income (loss) attributable to Calpine
$
(43
)
$
(109
)
$
149
$
10
Reorganization items(1)
1
(39
)
(1
)
(302
)
Discontinued operations, net
—
(23
)
—
(23
)
Other items(1)(2)
52
34
82
401
Net income (loss), net of reorganization items, discontinued
operations and other items
10
(137
)
230
86
Unrealized MtM (gains) losses on derivatives(1)(3)
(22
)
(40
)
(89
)
(24
)
Net income (loss), net of reorganization items, discontinued
operations, other items and unrealized MtM impacts
$
(12
)
$
(177
)
$
141
$
62
(1) Shown net of tax, assuming a 0% effective tax rate for
these items (other than those referenced in note 2 below).(2) Other items in the fourth quarter of 2008 include an
impairment charge of approximately $33 million related to the
Auburndale peaker power plant and a $1 million impairment loss
associated with our interest in the Auburndale power plant, which
was sold during 2008. Other items in the full year 2008 include
the $33 million impairment charge related to the Auburndale peaker
power plant, a cumulative impairment loss of $180 million
associated with our interest in the Auburndale power plant, $13
million in settlement costs, $13 million in debt extinguishment
costs, as well as $135 million in post-petition interest expense
and $27 million in settlement obligations related to the Canadian
debtors and other deconsolidated foreign entities recorded prior
to their reconsolidation in February 2008, both of which were
associated with our emergence from bankruptcy. Other items in the
fourth quarter 2009 include $25 million in additional depreciation
expense associated with a change in the estimated useful lives and
salvage values of our power plants and related equipment and
changing our Geysers Assets depreciation method, as well as $27
million in debt extinguishment costs. Other items in the full year
2009 period also include debt extinguishment costs of $49 million
associated with the refinancing of CCFC, shown net of tax assuming
a 38.4% effective tax rate.(3) Represents unrealized mark-to-market (MtM) (gains) losses
on contracts that did not qualify as hedges under the hedge
accounting guidelines or qualified under the hedge accounting
guidelines and the hedge accounting designation had not been
elected.
REGIONAL SEGMENT REVIEW OF RESULTSTable 2: Commodity Margin by Segment (in millions)
Year Ended December 31,
2009
2008
West
$
1,346
$
1,255
Texas
644
726
Southeast
304
264
North
268
279
Total
$
2,562
$
2,524
West: Commodity Margin in our West segment increased by $91
million for the year ended December 31, 2009 compared to the year ended
December 31, 2008. The increase was primarily a result of higher hedge
levels and prices, sales of surplus emission allowances in the first
quarter of 2009 and higher resource adequacy and renewable energy credit
revenues in 2009 compared to 2008. Market heat rates remained relatively
unchanged across periods, and lower natural gas prices resulted in lower
market spark spreads for the year ended December 31, 2009 compared to
2008. In addition, the current period benefited from the non-recurrence
in 2009 of an unfavorable natural gas storage inventory price adjustment
in September 2008.
Texas: Commodity Margin in our Texas segment decreased by $82
million for the year ended December 31, 2009 compared to 2008. This
decrease is primarily attributable to weaker natural gas prices that
were 56% lower in 2009 compared to 2008. Overall, market heat rates were
relatively unchanged in 2009 compared to 2008; however, market heat
rates were higher in the third quarter of 2009 compared to the same
period in 2008 due to warmer than average weather and lower in the
second quarter of 2009 compared to the same period in 2008 due to the
congestion-driven pricing environment of the second quarter of 2008.
Also contributing to the overall decrease in Commodity Margin was lower
steam sales resulting from weaker industrial demand in 2009 compared to
2008.
Southeast: Commodity Margin in our Southeast segment increased by
$40 million for the year ended December 31, 2009 compared to 2008. The
increase was driven by a 35% increase in generation, which resulted from
higher natural gas generation displacement of coal generation in certain
sub-markets in our Southeast segment primarily caused by lower natural
gas prices resulting in higher market heat rates in 2009 compared to
2008. Commodity Margin in the Southeast was also positively affected in
2009 compared to 2008, by the favorable impact of an off-take agreement
at one of our power plants and incremental natural gas hedges. The
benefit from these positive performance factors was partially offset by
the negative impact from the settlement of a disputed steam contract,
which adversely impacted operating revenues in 2009. In addition, a gain
of $21 million related to the temporary assignment of a transmission
capacity contract in the second quarter of 2008 led to a reduction in
relative year-over-year performance.
North: Commodity Margin in our North segment decreased by $11
million for the year ended December 31, 2009 compared to 2008. Although
market spark spreads were lower in 2009 compared to 2008, the impact was
largely mitigated by our hedge position as well as the favorable impact
of the reconsolidation of RockGen in December 2008.
LIQUIDITY AND CAPITAL RESOURCESTable 3: Corporate Liquidity
December 31,
December 31,
2009
2008
(in millions)
Cash and cash equivalents, corporate(1)
$
725
$
1,361
Cash and cash equivalents, non-corporate
264
296
Total cash and cash equivalents
989
1,657
Restricted cash
562
503
Letter of credit availability(2)
34
2
Revolver availability(3)
794
16
Total current liquidity(4)
$
2,379
$
2,178
(1) Includes $9 million and $169 million of margin deposits
held by us posted by our counterparties as of December 31, 2009
and 2008, respectively.(2) Additional available balances for Calpine Development
Holdings, Inc. As of December 31, 2009, we have the option to
increase our availability by an additional $50 million under this
letter of credit by satisfying certain conditions.(3) We repaid $725 million previously drawn on our First Lien
Credit Facility revolver on September 28, 2009.(4) Excludes contingent amounts of $150 million under the
Knock-in Facility and $200 million under the Commodity Collateral
Revolver as of December 31, 2008.
Liquidity improved by more than $200 million during 2009, from $2.2
billion at December 31, 2008 to $2.4 billion at December 31, 2009.
Consistent with our efforts to maintain strong liquidity, during the
fourth quarter of 2009, we extended the letter of credit facility at our
subsidiary, Calpine Development Holdings, Inc., which was previously
scheduled to mature in 2010 but will now mature in 2012.
During 2009, we generated $609 million of Adjusted Free Cash Flow,
representing an improvement of $114 million over 2008 results and
exceeding our guidance for the year. The year-over-year improvement in
Adjusted Free Cash Flow was primarily the result of the $83 million
increase in Adjusted EBITDA, as previously discussed, as well as a $48
million decrease in cash tax payments from 2008 to 2009. Operating
activities resulted in net cash proceeds of $761 million during the 2009
period, compared to $494 million in 2008. In addition, cash flows used
in investing activities resulted in a net outflow of $250 million in
2009, driven largely by $179 million in capital expenditures, which were
primarily related to maintenance across the fleet, growth investments in
our turbine upgrade program and improvements to company systems.
During the fourth quarter of 2009, we continued our efforts toward
managing near-term debt maturities by amending and extending our
approximately $499 million Steamboat credit facility. The credit
facility, originally scheduled to mature in 2011, is now due in 2017 and
was refinanced on favorable terms. Including the Steamboat refinancing
in the fourth quarter, we successfully refinanced approximately $3
billion of capital during 2009. “We entered 2009 with a goal of
de-risking the balance sheet by opportunistically addressing near-term
maturities while maintaining a strong liquidity balance,” said Zamir
Rauf, Calpine’s Chief Financial Officer. “I am pleased to report that we
achieved this goal. First, we refinanced approximately $3 billion of
debt at very attractive rates while simplifying the balance sheet in the
process. In addition, we improved our liquidity by $200 million. I would
like to commend our team for the progress made on this front,
particularly considering the uncertain nature of the economy and capital
markets just a year ago.”
PLANT DEVELOPMENTRussell City Energy Center: On February 4, 2010, we received the
Prevention of Significant Deterioration air permit, the final permit
necessary, to begin construction of our Russell City Energy Center
(RCEC), a proposed 600 MW, natural gas-fired power plant to be located
in Hayward, California in which we own a 65% share. Under the terms of
the permit, RCEC is intended to become the first power plant in the
United States with a federal limit on greenhouse gas emissions, and will
be designed to operate in a way that produces 25% fewer greenhouse gas
emissions than the California Public Utilities Commission standard. The
power plant will use 100% reclaimed water from the City of Hayward’s
Water Pollution Control Facility for cooling and boiler makeup, which
will prevent nearly four million gallons of wastewater per day from
being discharged into the San Francisco Bay. We hope to complete
financing and break ground for this new state-of-the-art power plant
during 2010 with commercial operations scheduled to begin in 2013.
OPERATIONS UPDATE2009 Power Operations Achievements:
Safety Performance: Achieved seventh consecutive year of top-quartile
safety performance with 2009 lost-time incident rate of 0.24
Availability Performance:
Improved fleet-wide average availability factor to 92.1% in 2009,
compared to 90.5% in 2008
Achieved fleet-wide forced outage factor of 2.03% in 2009,
compared to 3.29% in 2008
Delivered full-year natural gas-fired fleet starting reliability
of 97% in 2009
Geothermal Generation: Provided approximately 6.0 million MWh of
renewable baseload generation with 94% capacity factor and 0.26%
forced outage factor
Natural Gas-fired Generation:
Increased production from gas-fired plants by nearly 3.0 million
MWh, or 4%, despite reduced nationwide electric consumption
Successfully commissioned Otay Mesa Energy Center in California
Six Calpine facilities recognized during fourth quarter by the
Texas Commission on Environmental Quality with Bronze Level
membership in the Clean Texas Program
Sustainable Cost Reductions: Reduced plant operating expense2,
sales, general and administrative expense2 and components
of other cost of revenue, largely through efficiency efforts and
disciplined cost controls
2009 Commercial Operations Achievements:
Customer-oriented growth:
Signed or began serving term contracts covering over 5,300 MW of
capacity across our portfolio, leveraging the flexible nature of
our fleet to provide value for our customers
Developed innovative solution for Los Angeles Department of Water
and Power to offer wind integration services, helping our customer
meet renewables targets while providing a reliable energy product
Effective hedging: Maintained stable year-over-year Commodity Margin,
despite declining commodity prices
FINANCIAL OUTLOOKTable 4: Adjusted EBITDA and Adjusted Free Cash Flow Guidance
Full Year 2010
(in millions)
Adjusted EBITDA
$
1,500 – 1,600
Less:
Operating lease payments
50
Major maintenance expense and capital expenditures(1)
290
Cash interest, net
750
Cash taxes
10
Adjusted Free Cash Flow
$
400 – 500
(1) Includes projected Major Maintenance Expense of $178
million and maintenance Capital Expenditures of $112 million.
Capital expenditures exclude major construction and development
projects.(2) Excludes changes in cash collateral for commodity
procurement and risk management activities.
Today we are reaffirming our 2010 guidance, which includes Adjusted
EBITDA of $1.5 billion to $1.6 billion, and Adjusted Free Cash Flow of
$400 million to $500 million. We are also updating estimates of our
growth capital for 2010. We expect to invest $135 million in
growth-related projects during the year, including our ongoing turbine
upgrade program, the addition of incremental steam wells at The Geysers,
and the anticipated commencement of construction on the 120 MW upgrade
of our Los Esteros plant and on our proposed 600 MW Russell City Energy
Center.
INVESTOR CONFERENCE CALL AND WEBCAST
We will host a conference call to discuss our financial and operating
results for the fourth quarter and full year 2009, on Thursday, February
25, 2010, at 9:00 a.m. ET / 8:00 a.m. CT. A listen-only webcast of the
call may be accessed through our website at www.calpine.com,
or by dialing 888-695-0608 (or 719-325-2236 for international listeners)
at least 10 minutes prior to the beginning of the call. An archived
recording of the call will be made available for a limited time on our
website. The recording also can be accessed by dialing 888-203-1112 (or
719-457-0820 for international listeners) and providing Confirmation
Code 1737034. Presentation materials to accompany the conference call
will be made available on our website on February 25, 2010.
ANNUAL MEETING DATE
Calpine’s Annual Meeting of Shareholders will be held on Wednesday, May
19, 2010, at 10:00 a.m. CT in Houston, Texas, at a location to be
announced.
ABOUT CALPINE
Founded in 1984, Calpine Corporation is a major U.S. power company,
currently capable of delivering nearly 25,000 megawatts of clean,
cost-effective, reliable and fuel-efficient power to customers and
communities in 16 states in the United States and Canada. Calpine
Corporation is committed to helping meet the needs of an economy that
demands more and cleaner sources of electricity. Calpine owns, leases
and operates low-carbon, natural gas-fired and renewable geothermal
power plants. Using advanced technologies, Calpine generates power in a
reliable and environmentally responsible manner for the customers and
communities it serves. Please visit our website at www.calpine.com
for more information.
Calpine’s Annual Report on Form 10-K for the year ended December 31,
2009, has been filed with the Securities and Exchange Commission (SEC)
and may be found on the SEC’s website at www.sec.gov.
FORWARD-LOOKING INFORMATIONIn addition to historical information, this release contains
forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended and Section 21E of the Securities
Exchange Act of 1934, as amended. We use words such as “believe,”
“intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,”
“estimate,” “potential,” “project” and similar expressions to identify
forward-looking statements. Such statements include, among others, those
concerning our expected financial performance and strategic and
operational plans, as well as all assumptions, expectations,
predictions, intentions or beliefs about future events. You are
cautioned that any such forward-looking statements are not guarantees of
future performance and that a number of risks and uncertainties could
cause actual results to differ materially from those anticipated in the
forward-looking statements. Such risks and uncertainties include, but
are not limited to:The uncertain length and severity of the current general financial
and economic downturn, the timing and strength of an economic
recovery, if any, and their impacts on our business including demand
for our power and steam products, the ability of customers, suppliers,
service providers and other contractual counterparties to perform
under their contracts with us and the cost and availability of capital
and credit;Financial results that may be volatile and may not reflect
historical trends due to, among other things, fluctuations in prices
for commodities such as natural gas and power, fluctuations in
liquidity and volatility in the energy commodities markets and our
ability to hedge risks;Our ability to manage our customer and counterparty exposure and
credit risk, including our commodity positions;Our ability to manage our significant liquidity needs and to comply
with covenants under our First Lien Credit Facility, our First Lien
Notes and other existing financing obligations;Competition, including risks associated with marketing and selling
power in the evolving energy markets;Regulation in the markets in which we participate and our ability
to effectively respond to changes in laws and regulations or the
interpretation thereof including changing market rules and evolving
federal, state and regional laws and regulations including those
related to greenhouse gas emissions and derivative transactions;Natural disasters such as hurricanes, earthquakes and floods, or
acts of terrorism that may impact our power plants or the markets our
power plants serve;Seasonal fluctuations of our results and exposure to variations in
weather patterns;Disruptions in or limitations on the transportation of natural gas
and transmission of power;Our ability to attract, retain and motivate key employees;Our ability to implement our business plan and strategy;Risks related to our geothermal resources, including the adequacy
of our steam reserves, unusual or unexpected steam field well and
pipeline maintenance requirements, variables associated with the
injection of wastewater to the steam reservoir and potential
regulations or other requirements related to seismicity concerns that
may delay or increase the cost of developing or operating geothermal
resources;Risks associated with the operation, construction and development
of power plants including unscheduled outages or delays and plant
efficiencies;Present and possible future claims, litigation and enforcement
actions;The expiration or termination of our power purchase agreements and
the related results on revenues; andOther risks identified in this release or in our reports and
registration statements filed with the Securities and Exchange
Commission (SEC), including, without limitation, the risk factors
identified in our Annual Report on Form 10-K for the year ended
December 31, 2009.Actual results or developments may differ materially from the
expectations expressed or implied in the forward-looking statement.Unless
specified otherwise, all information set forth in this release is as of
today’s date, and we undertake no obligation to update any
forward-looking statements, whether as a result of new information,
future developments or otherwise.For additional information
about our general business operations, please refer to our Annual Report
on Form 10-K for the year ended December 31, 2009, and any other recent
report we have filed with the SEC.These filings are available by
visiting the SEC’s web site at www.sec.gov
or our web site at www.calpine.com.
CALPINE CORPORATION AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended December 31,
Year Ended December 31,
2009
2008
2009
2008
(in millions, except share and per share amounts)
Operating revenues
$
1,569
$
1,968
$
6,564
$
9,937
Cost of revenue:
Fuel and purchased energy expense
930
1,346
3,897
7,281
Plant operating expense
243
282
897
918
Depreciation and amortization expense
137
104
467
433
Operating asset impairments
4
33
4
33
Other cost of revenue
21
26
84
114
Total cost of revenue
1,335
1,791
5,349
8,779
Gross profit
234
177
1,215
1,158
Sales, general and other administrative expense
52
61
183
215
(Income) loss from unconsolidated investments in power plants
(23
)
40
(50
)
229
Other operating expense
4
11
18
26
Income from operations
201
65
1,064
688
Interest expense
214
234
829
1,071
Interest (income)
(3
)
(9
)
(16
)
(47
)
Debt extinguishment costs
27
—
76
13
Other (income) expense, net
8
(2
)
16
14
Income (loss) before reorganization items, income taxes and
discontinued operations
(45
)
(158
)
159
(363
)
Reorganization items
1
(39
)
(1
)
(302
)
Income(loss) before income taxes and discontinued operations
(46
)
(119
)
160
(61
)
Income tax expense (benefit)
(2
)
13
15
(47
)
Income (loss) before discontinued operations
(44
)
(132
)
145
(14
)
Discontinued operations, net of tax expense of $14 in 2008
—
23
—
23
Net income
$
(44
)
$
(109
)
$
145
$
9
Net loss attributable to the noncontrolling interest
1
—
4
1
Net income attributable to Calpine
$
(43
)
$
(109
)
$
149
$
10
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding (in thousands)
485,776
485,135
485,659
485,054
Income (loss) before discontinued operations attributable to
Calpine
(0.09
)
(0.27
)
0.31
(0.03
)
Discontinued operations, net of tax, attributable to Calpine
—
0.05
—
0.05
Net income (loss) per common share attributable to Calpine – basic
$
(0.09
)
$
(0.22
)
$
0.31
$
0.02
Diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding (in thousands)
485,776
485,135
486,319
485,546
Income (loss) before discontinued operations attributable to
Calpine
(0.09
)
(0.27
)
0.31
(0.03
)
Discontinued operations, net of tax, attributable to Calpine
—
0.05
—
0.05
Net income (loss) per common share attributable to Calpine –
diluted
$
(0.09
)
$
(0.22
)
$
0.31
$
0.02
CALPINE CORPORATION AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETSDecember 31, 2009 and 2008
2009
2008
(in millions, exceptshare and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents
$
989
$
1,657
Accounts receivable, net of allowance of $14 and $42
747
846
Accounts receivable, related party
3
4
Inventory
209
163
Margin deposits and other prepaid expense
490
776
Restricted cash, current
508
337
Derivative assets, current
1,119
3,653
Other current assets
34
64
Total current assets
4,099
7,500
Property, plant and equipment, net
11,583
11,908
Restricted cash, net of current portion
54
166
Investments
214
144
Long-term derivative assets
127
404
Other assets
573
616
Total assets
$
16,650
$
20,738
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable
$
578
$
574
Accrued interest payable
54
85
Debt, current portion
463
716
Derivative liabilities, current
1,360
3,799
Income taxes payable
7
5
Other current liabilities
287
437
Total current liabilities
2,749
5,616
Debt, net of current portion
8,996
9,756
Deferred income taxes, net of current portion
54
93
Long-term derivative liabilities
197
698
Other long-term liabilities
208
203
Total liabilities
12,204
16,366
Stockholders’ equity:
Preferred stock, $.001 par value per share; authorized 100,000,000
shares, none issued and outstanding at December 31, 2009 and 2008
—
—
Common stock, $.001 par value per share; authorized 1,400,000,000
shares, 443,325,827 shares issued and 442,998,255 shares
outstanding at December 31, 2009 and 429,025,057 shares issued and
428,960,025 shares outstanding at December 31, 2008
1
1
Treasury stock, at cost, 327,572 shares and 65,032 shares at
December 31, 2009 and December 31, 2008, respectively
(3
)
(1
)
Additional paid-in capital
12,256
12,217
Accumulated deficit
(7,540
)
(7,689
)
Accumulated other comprehensive loss
(266
)
(158
)
Total Calpine stockholders’ equity
4,448
4,370
Noncontrolling interest
(2
)
2
Total stockholders’ equity
4,446
4,372
Total liabilities and stockholders’ equity
$
16,650
$
20,738
CALPINE CORPORATION AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWSFor the Years Ended December 31, 2009 and 2008
2009
2008
(in millions)
Cash flows from operating activities:
Net income
$
145
$
9
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization expense(1)
556
544
(Income) loss from unconsolidated investments in power plants
(50
)
229
Debt extinguishment costs
37
7
Deferred income taxes
16
27
Impairment loss
4
46
Gain on sale of discontinued operations
—
(37
)
Loss on disposal of assets, excluding reorganization items
37
36
Unrealized mark-to-market activity, net
(89
)
(24
)
Return on investment in unconsolidated subsidiaries
11
—
Stock-based compensation expense
38
50
Reorganization items
(6
)
(359
)
Other
6
16
Change in operating assets and liabilities, net of effects of
acquisitions:
Accounts receivable
108
375
Derivative instruments
(118
)
234
Other assets
235
(101
)
Accounts payable, liabilities subject to compromise and accrued
expenses
(19
)
(215
)
Other liabilities
(150
)
(343
)
Net cash provided by operating activities
761
494
Cash flows from investing activities:
Purchases of property, plant and equipment
(179
)
(143
)
Proceeds from sale of power plants, turbines and investments
—
413
Proceeds from sale of discontinued operations
—
79
Cash acquired due to reconsolidation of the Canadian Debtors and
other deconsolidated foreign entities
—
64
Contributions to unconsolidated investments
(19
)
(17
)
Return of investment from unconsolidated investments
9
27
(Increase) decrease in restricted cash
(59
)
78
Cash effect of deconsolidation of VIEs
—
(2
)
Other
(2
)
17
Net cash provided by (used in) investing activities
(250
)
516
Cash flows from financing activities:
Repayments of notes payable
(106
)
(99
)
Borrowings from CCFC New Notes
955
—
Repayments of CCFC Old Notes
(781
)
(4
)
Borrowings from project financing
79
357
Repayments of project financing
(121
)
(275
)
Repayments of DIP Facility
—
(98
)
Borrowings under First Lien Facilities
—
4,248
Repayments on First Lien Facilities
(785
)
(1,475
)
Borrowings under Commodity Collateral Revolver
—
100
Repayments of Second Priority Debt
—
(3,672
)
Repayments on capital leases
(43
)
(42
)
Redemptions of preferred interests
(310
)
(166
)
Financing costs
(65
)
(207
)
Derivative contracts classified as financing activities
—
64
Other
(2
)
1
Net cash used in financing activities
(1,179
)
(1,268
)
Net decrease in cash and cash equivalents
(668
)
(258
)
Cash and cash equivalents, beginning of period
1,657
1,915
Cash and cash equivalents, end of period
$
989
$
1,657
Cash paid (received) during the period for:
Interest, net of amounts capitalized
$
761
$
1,060
Income taxes
$
7
$
74
Reorganization items included in operating activities, net
$
5
$
120
Reorganization items included in investing activities, net
$
—
$
(418
)
Supplemental disclosure of non-cash investing and financing
activities:
Settlement of commodity contract with project financing
$
79
$
—
Change in capital expenditures included in accounts payable
$
6
$
13
Issuance of First Lien Notes in exchange for First Lien Credit
Facility term loans
$
1,200
$
—
Amended Steamboat project debt
$
448
$
—
Settlement of liabilities subject to compromise through issuance
of reorganized Calpine Corporation common stock
$
—
$
5,200
DIP Facility borrowings converted into exit financing under our
First Lien Facilities
$
—
$
3,872
Settlement of Convertible Senior Notes and Unsecured Senior Notes
with reorganized Calpine Corporation common stock
$
—
$
3,703
(1) Includes depreciation and amortization that is recorded
in sales, general and other administrative expense and interest
expense on our Consolidated Statements of Operations.
REGULATION G RECONCILIATIONS
Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow are
non-GAAP financial measures that we use as measures of our performance.
These measures should be viewed as a supplement to and not a substitute
for our GAAP measures of performance.
Commodity Margin includes our power and steam revenues, sales of
purchased power and natural gas, capacity revenue, revenue from
renewable energy credits, sales of surplus emission allowances,
transmission revenue and expenses, fuel and purchased energy expense,
RGGI compliance costs and cash settlements from our marketing, hedging
and optimization activities that are included in mark-to-market
activity, but excludes the unrealized portion of our mark-to-market
activity and other revenues. Commodity Margin is presented because we
believe it is a useful tool for assessing the performance of our core
operations, and it is a key operational measure reviewed by our chief
operating decision maker. Commodity Margin does not intend to represent
gross profit (loss), the most comparable GAAP measure, as an indicator
of operating performance and is not necessarily comparable to
similarly-titled measures reported by other companies.
Adjusted EBITDA represents net income (loss) before interest, taxes,
depreciation and amortization, adjusted for certain non-cash and
non-recurring items as detailed in the following reconciliation.
Adjusted EBITDA is presented because our management uses Adjusted EBITDA
(i) as a measure of operating performance to assist in comparing
performance from period to period on a consistent basis and to readily
view operating trends; (ii) as a measure for planning and forecasting
overall expectations and for evaluating actual results against such
expectations; and (iii) in communications with our Board of Directors,
shareholders, creditors, analysts and investors concerning our financial
performance. We believe Adjusted EBITDA is also used by and is useful to
investors and other users of our financial statements in evaluating our
operating performance because it provides them with an additional tool
to compare business performance across companies and across periods. We
believe that EBITDA is widely used by investors to measure a company’s
operating performance without regard to items such as interest expense,
taxes, depreciation and amortization, which can vary substantially from
company to company depending upon accounting methods and book value of
assets, capital structure and the method by which assets were acquired.
Adjusted EBITDA is not a measure calculated in accordance with GAAP, and
should be viewed as a supplement to and not a substitute for our results
of operations presented in accordance with GAAP. Adjusted EBITDA is not
intended to represent cash flows from operations or net income (loss) as
defined by GAAP as an indicator of operating performance. Furthermore,
Adjusted EBITDA is not necessarily comparable to similarly-titled
measures reported by other companies.
Adjusted Free Cash Flow represents net income before interest, taxes,
depreciation and amortization, as adjusted, less operating lease
payments, major maintenance expense and maintenance capital
expenditures, net cash interest, cash taxes, working capital and other
adjustments. Adjusted Free Cash Flow is presented because our management
uses this measure, among others, to make decisions about capital
allocation. Adjusted Free Cash Flow is not intended to represent cash
flows from operations as defined by GAAP as an indicator of operating
performance and is not necessarily comparable to similarly-titled
measures reported by other companies.
Commodity Margin Reconciliation
The following table reconciles our Commodity Margin to its GAAP results
for the three months ended December 31, 2009 and 2008:
Three Months Ended December 31, 2009(in millions)
Consolidation
And
West
Texas
Southeast
North
Elimination
Total
Commodity Margin
$
352
$
139
$
71
$
53
$
—
$
615
Add: Mark-to-market commodity activity, net and other revenue(1)
23
8
(7
)
9
(9
)
24
Less:
Plant operating expense
111
69
40
30
(7
)
243
Depreciation and amortization expense
55
37
29
19
(3
)
137
Other cost of revenue(2)
17
2
3
7
(4
)
25
Gross profit (loss)
$
192
$
39
$
(8
)
$
6
$
5
$
234
Three Months Ended December 31, 2008(in millions)
Consolidation
And
West
Texas
Southeast
North
Elimination
Total
Commodity Margin
$
290
$
139
$
56
$
51
$
—
$
536
Add: Mark-to-market commodity activity, net and other revenue(1)
(1
)
81
30
(16
)
(8
)
86
Less:
Plant operating expense
125
89
44
35
(11
)
282
Depreciation and amortization expense
47
30
15
16
(4
)
104
Other cost of revenue(2)
17
3
36
5
(2
)
59
Gross profit (loss)
$
100
$
98
$
(9
)
$
(21
)
$
9
$
177
(1) Mark-to-market commodity activity represents the
unrealized portion of our mark-to-market activity, net, as well as
a non-cash gain from amortization of prepaid power sales
agreements included in operating revenues and fuel and purchased
energy expense on our Consolidated Statements of Operations.(2) Includes operating asset impairments of $4 million and
$33 million for the three months ended December 31, 2009 and 2008,
respectively.
The following table reconciles our Commodity Margin to its GAAP results
for the years ended December 31, 2009 and 2008:
Year Ended December 31, 2009(in millions)
Consolidation
And
West
Texas
Southeast
North
Elimination
Total
Commodity Margin
$
1,346
$
644
$
304
$
268
$
—
$
2,562
Add: Mark-to-market commodity activity, net and other revenue(1)
143
(40
)
(5
)
46
(44
)
100
Less:
Plant operating expense
437
232
134
91
3
897
Depreciation and amortization expense
205
125
79
66
(8
)
467
Other cost of revenue(2)
62
13
10
30
(32
)
83
Gross profit
$
785
$
234
$
76
$
127
$
(7
)
$
1,215
Year Ended December 31, 2008(in millions)
Consolidation
And
West
Texas
Southeast
North
Elimination
Total
Commodity Margin
$
1,255
$
726
$
264
$
279
$
—
$
2,524
Add: Mark-to-market commodity activity, net and other revenue(1)
(31
)
195
36
(40
)
(28
)
132
Less:
Plant operating expense
434
267
128
108
(19
)
918
Depreciation and amortization expense
190
124
69
56
(6
)
433
Other cost of revenue(2)
71
12
59
26
(21
)
147
Gross profit
$
529
$
518
$
44
$
49
$
18
$
1,158
(1) Mark-to-market commodity activity represents the
unrealized portion of our mark-to-market activity, net, as well as
a non-cash gain from amortization of prepaid power sales
agreements included in operating revenues and fuel and purchased
energy expense on our Consolidated Statements of Operations for
the years ended December 31, 2009 and 2008.(2) Excludes $5 million and nil of RGGI compliance costs for
the years ended December 31, 2009 and 2008, respectively, which
were included as a component of Commodity Margin and includes
operating asset impairments of $4 million and $33 million for the
years ended December 31, 2009 and 2008, respectively.
Consolidated Adjusted EBITDA Reconciliation
In the following table, we have reconciled our Adjusted EBITDA and
Adjusted Free Cash Flow to our Net Income for the three and twelve
months ended December 31, 2009 and 2008, as reported under GAAP.
Three Months Ended December 31,
Year Ended December 31,
2009
2008
2009
2008
(in millions)
Net income attributable to Calpine
$
(43
)
$
(109
)
$
149
$
10
Net loss attributable to noncontrolling interest
(1
)
—
(4
)
(1
)
Discontinued operations, net of tax expense
—
(23
)
—
(23
)
Income tax expense (benefit)
(2
)
13
15
(47
)
Reorganization items
1
(39
)
(1
)
(302
)
Other (income) expense and debt extinguishment costs, net
35
(2
)
92
27
Interest expense, net
211
225
813
1,024
Income from operations
$
201
$
65
$
1,064
$
688
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred
financing costs(1)
141
110
480
467
Impairment loss
4
41
4
226
Major maintenance expense
50
72
174
190
Operating lease expense
12
11
47
46
Non-cash realized gains on derivatives
—
(7
)
—
(40
)
Unrealized (gains) losses on commodity derivative mark-to-market
activity
(19
)
(57
)
(79
)
(35
)
Adjustments to reflect Adjusted EBITDA from unconsolidated
investments(2),(3)
6
47
17
76
Stock-based compensation expense
8
14
38
50
Non-cash loss on dispositions of assets
3
25
32
34
Other(4)
2
4
5
(3
)
Adjusted EBITDA
$
408
$
325
$
1,782
$
1,699
Less:
Lease payments
12
47
46
Major maintenance expense and capital expenditures(5)
77
351
321
Cash interest(6)
206
773
794
Cash taxes
—
(5
)
43
Other
—
7
—
Adjusted Free Cash Flow(7)(8)
$
113
$
609
$
495
(1) Depreciation and amortization expense in the income from
operations calculation on our Consolidated Condensed Statements of
Operations excludes amortization of other assets and amounts
classified as sales, general and other administrative expenses.
(2) Included in our Consolidated Statements of Operations in
(income) loss from unconsolidated investments in power plants.
(3) Adjustments to reflect Adjusted EBITDA from
unconsolidated investments include $(13) million and $61 million
in unrealized (gains) losses on mark-to-market activity for the
three months ended December 31, 2009 and 2008, respectively, and
$(47) million and $55 million in unrealized (gains) losses on
mark-to-market activity for the years ended December 31, 2009 and
2008, respectively.
(4) Includes fees for letters of credit.
(5) Includes $52 million and $183 million in major
maintenance expense for the three and twelve months ended December
31, 2009, respectively, and $25 million and $168 million in
maintenance capital expenditures for the three and twelve months
ended December 31, 2009, respectively. Includes $191 million in
major maintenance expense and $130 million in maintenance capital
expenditures for the twelve months ended December 31, 2008.
(6) Includes commitment, letter of credit and other bank fees
from both consolidated and unconsolidated investments, net of
capitalized interest and interest income.
(7) Excludes decrease (increase) in working capital of $71
million and $70 million for the three and twelve months ended
December 31, 2009 and $(44) million for the twelve months ended
December 31, 2008.
(8) Adjusted Free Cash Flow, as reported, excludes changes in
working capital, such that it is calculated on the same basis as
our guidance. Results for the year ended December 31, 2008 have
been recast to conform to this method.
In the following table, we have reconciled our Adjusted EBITDA to our
Commodity Margin, both of which are non-GAAP measures, for the three and
twelve months ended December 31, 2009 and 2008. Reconciliations for both
Adjusted EBITDA and Commodity Margin to comparable GAAP measures are
provided above.
Three Months Ended December 31,
Year Ended December 31,
2009
2008
2009
2008
(in millions)
Commodity Margin
$
615
$
536
$
2,562
$
2,524
Other revenue
5
22
21
57
Plant operating expense(1)
(186
)
(180
)
(675
)
(670
)
Other cost of revenue(2)
(7
)
(12
)
(28
)
(46
)
Sales, general and administrative expense(3)
(46
)
(49
)
(152
)
(178
)
Adjusted EBITDA from unconsolidated investments in power plants(4)
29
7
67
26
Other operating expense(5)
(4
)
(3
)
(18
)
(11
)
Other
2
4
5
(3
)
Adjusted EBITDA
$
408
$
325
$
1,782
$
1,699
(1) Shown net of major maintenance expense, stock-based
compensation expense, and non-cash loss on dispositions of assets.(2) Shown net of operating lease expense and depreciation and
amortization. Excludes $5 million and nil of RGGI compliance costs
for the years ended December 31, 2009 and 2008, respectively,
which were included as a component of Commodity Margin.(3) Shown net of depreciation and amortization and
stock-based compensation expense.(4) Shown net of impairments in 2008. Amount is comprised of
income from unconsolidated investments in power plants, as well as
adjustments to reflect Adjusted EBTIDA from unconsolidated
investments.(5) Shown net of impairments in 2008.
Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for
GuidanceFull Year 2010 Range:
Low
High
(in millions)
GAAP Net Income
$
(30
)
$
70
Plus:
Interest expense, net of interest income
750
750
Depreciation and amortization expense
465
465
Major maintenance expense
180
180
Operating lease expense
50
50
Other(1)
85
85
Adjusted EBITDA
$
1,500
$
1,600
Less:
Operating lease payments
50
50
Major maintenance expense and maintenance capital expenditures(2)
290
290
Cash interest, net(3)
750
750
Cash taxes
10
10
Adjusted Free Cash Flow
$
400
$
500
(1) Other includes stock-based compensation expense,
adjustments to reflect Adjusted EBITDA from unconsolidated
investments, and other items.(2) Includes projected Major Maintenance Expense of $178
million and maintenance Capital Expenditures of $112 million.
Capital expenditures exclude major construction and development
projects.(3) Includes fees for letters of credit, net of interest
income.
CASH FLOW ACTIVITIES
The following table summarizes our cash flow activities for the years
ended December 31, 2009 and 2008:
Year Ended December 31,
2009
2008
(in millions)
Beginning cash and cash equivalents
$
1,657
$
1,915
Net cash provided by (used in):
Operating activities
761
494
Investing activities
(250
)
516
Financing activities
(1,179
)
(1,268
)
Net decrease in cash and cash equivalents
(668
)
(258
)
Ending cash and cash equivalents
$
989
$
1,657
OPERATING PERFORMANCE METRICS
The table below shows the operating performance metrics for continuing
operations:
Three Months Ended December 31,
Year Ended December 31,
2009
2008
2009
2008
Total MWh generated (1) (in thousands)
21,622
19,872
88,339
87,762
West
9,925
9,435
36,033
37,137
Texas
6,629
5,360
29,687
32,408
Southeast
3,528
3,762
17,370
12,820
North
1,540
1,315
5,249
5,397
Average availability
89.9
%
89.7
%
92.1
%
90.5
%
West
92.3
%
87.6
%
92.3
%
89.1
%
Texas
83.9
%
84.8
%
90.0
%
88.8
%
Southeast
92.9
%
96.5
%
93.2
%
93.6
%
North
92.5
%
94.2
%
94.7
%
92.6
%
Average capacity factor, excluding peakers
47.5
%
43.5
%
48.7
%
47.9
%
West
70.4
%
66.4
%
64.1
%
65.9
%
Texas
41.9
%
34.0
%
47.4
%
51.6
%
Southeast
31.0
%
32.6
%
37.9
%
26.6
%
North
36.3
%
32.4
%
31.1
%
32.8
%
Steam adjusted Heat Rate (mmbtu/kWh)
7,263
7,183
7,263
7,231
West
7,318
7,208
7,304
7,267
Texas
7,118
7,040
7,142
7,082
Southeast
7,331
7,210
7,299
7,388
North
7,441
7,545
7,614
7,584
(1) MWh generated is shown here as our net operating interest
for plants that we both consolidate and operate. Excludes
generation at RockGen from January 1 to September 30, 2008, as the
plant was deconsolidated during this period.
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