Calpine Corporation (NYSE:CPN) today reported 2010 Adjusted
EBITDA of $1,712 million, compared to $1,782 million in the prior
year. The company also reported 2010 Adjusted Recurring Free Cash
Flow of $558 million, compared to $602 million in 2009. Net income2
for the year was $31 million, or $0.06 per diluted share, compared
to $149 million, or $0.31 per diluted share, in 2009.
“We had a successful year in 2010: we executed on our strategic
initiatives, strengthened our balance sheet, achieved solid
operating performance and enhanced shareholder value. Additionally,
we increased market share despite significant challenges posed by
the overall economic environment and related impacts on power
markets. The combination of our ability to execute, mounting
optimism on economic recovery and increasing environmental pressure
on the country’s aging power generation fleet should trend towards
even greater utilization of our modern, clean, efficient natural
gas-fired plants. Indeed, I believe that we are at the crossroads
of a structural change in wholesale power generation that should
bode well for the future of Calpine,” said Jack Fusco, Calpine’s
President and Chief Executive Officer.
“On the operating front, in 2010, we had an impressive
fleet-wide availability of 91% and starting reliability of 98%,
enabling us to generate over 94 million MWh1 of power for our
customers. On the strategic and growth front, in 2009 we made clear
our strategic goal to achieve scale in a third region to provide
better geographic and weather diversity, and in July 2010 we
acquired 19 plants in the Mid-Atlantic giving us that foothold in
PJM, an acquisition that has proven to be even more accretive than
expected. But that is not the end of our growth story – we
continued to invest in high-return upgrade projects and, after the
successful culmination of the permitting processes, our Russell
City Energy Center and the upgrade to our Los Esteros Energy
Center, both of which are now under construction. We are also well
on the way to an early completion of our York Energy Center.
Finally, in 2010 we also began an effort to reposition our asset
base by opportunistically shedding non-core assets or monetizing
core assets where economically sensible. During the year, we
successfully divested non-core assets in Colorado and an undivided
interest in our North Texas Freestone plant at very attractive
prices.
“On the financing front, we have now completed the refinancing
of the First Lien Credit Facility and, in the process, achieved an
investment grade-like covenant structure while improving our
capital allocation flexibility by, among other things, adding the
ability to return capital to shareholders under appropriate
conditions. Overall, we have made significant progress in
positioning Calpine for the future.”
SUMMARY OF FINANCIAL
PERFORMANCE
Full Year Results
Adjusted EBITDA for the year ended December 31, 2010, was $1,712
million, compared to $1,782 million in the prior year period. The
year-over-year decline in Adjusted EBITDA was primarily caused by a
$70 million decrease in Commodity Margin, due in large part to our
West and Texas segments, where Commodity Margin decreased by $165
million and $140 million, respectively. Lower average hedge
margins, as well as lower realized spark spreads on open positions
due to lower realized heat rates attributable to weaker market
conditions resulting from milder weather and an overall increase in
installed generation capacity, impacted both regions. In addition,
the year-over-year Commodity Margin variance in the West segment
was negatively impacted by a $102 million decrease attributable to
the expiration of the PCF arrangement at the end of 2009, offset,
in part, by Commodity Margin increases of $80 million from Otay
Mesa Energy Center (OMEC), which achieved commercial operation in
October 2009 and was consolidated on January 1, 2010, and $50
million related to higher renewable energy credit (REC) revenue
from new contracts associated with our Geysers power plants. The
Commodity Margin declines in the West and Texas segments were
offset, in part, by a $267 million increase in Commodity Margin
from our North segment, which was primarily driven by the
acquisition of our Mid-Atlantic fleet, which closed on July 1,
2010, as well as strong performance from our incumbent plants in
the region which benefited from weather-driven demand increases in
2010.
Aside from the decline in Commodity Margin, Adjusted EBITDA in
2010 was also negatively impacted by a $25 million year-over-year
increase in plant operating expense3, most of which was due to the
addition of our Mid-Atlantic plants in July 2010 and the start-up
of OMEC in October 2009. This increase was offset by a $43 million
decrease in sales, general and administrative expense4 that
resulted primarily from lower personnel and consulting expenses, as
well as a contract settlement that benefited the first quarter of
2010.
Cash flows provided by operating activities for the twelve
months ended December 31, 2010, improved to $929 million compared
to $761 million for the same period in 2009. The improvement in
cash provided by operating activities was primarily due to a
decrease of approximately $188 million in working capital employed
and a decrease of $126 million of cash paid for interest (inclusive
of interest rate swaps in hedging relationships). These
improvements were partially offset by a $43 million decrease in
income from operations, adjusted for non-cash items, and a $54
million increase in net cash paid for taxes.
Net income2 decreased to $31 million for the year ended December
31, 2010, from $149 million in the prior year period. As detailed
in Table 1, Net Income, As Adjusted, was unchanged year-over-year
at $87 million. Though offset, we experienced negative
year-over-year variances that include a $70 million decline in
Commodity Margin, as previously discussed, as well as a $114
million increase in depreciation expense associated with the
acquisition of our Mid-Atlantic fleet, the consolidation of OMEC
and revisions in certain areas of our depreciation methods and
asset lives. In addition, income from unconsolidated investments in
power plants declined $34 million year-over-year, primarily as a
result of the consolidation of OMEC as of January 1, 2010.
Offsetting these declines was an $83 million decline in income tax
expense, primarily resulting from a decrease of $129 million
related to non-cash intraperiod tax allocation partially offset by
an increase in federal income tax of $43 million for the CCFC group
for the year ended December 31, 2010 compared to the year ended
December 31, 2009. In addition, interest expense (excluding
unrealized mark-to-market (gains) losses) decreased by $55 million
in 2010 compared to 2009 due to the repayment of our PCF financing,
the refinancing of our CCFC debt, and a decrease in the annualized
effective interest rates on our consolidated debt (excluding the
impacts of capitalized interest), offset, in part, by increases
related to the 2010 addition of a term loan that was used to fund
our Mid-Atlantic fleet acquisition as well as the consolidation of
OMEC on January 1, 2010. Finally, sales, general and administrative
expenses (net of acquisition-related costs incurred in 2010),
declined by $49 million year-over-year, due to factors previously
discussed.
Fourth Quarter Results
Adjusted EBITDA declined to $386 million in the fourth quarter
of 2010 compared to $408 million in the prior year period. The
year-over-year decline was primarily due to a $14 million decrease
in Commodity Margin, which was largely driven by declines of $56
million and $35 million in our West and Texas segments,
respectively. The declines in the West resulted from the expiration
of the PCF arrangement in the fourth quarter of 2009, as well as
lower average hedge prices and lower realized spark spreads
associated with weaker market conditions in the fourth quarter of
2010 as compared to the same period in 2009. Partially offsetting
these declines, the West region benefited from an $11 million
increase related to higher REC revenue from new contracts
associated with our Geysers plants and an increase of $24 million
related to the consolidation of our OMEC facility as of January 1,
2010. Meanwhile, Commodity Margin in our Texas segment declined due
to lower average hedge prices in the fourth quarter of 2010
compared to the prior year period. The declines in our West and
Texas segments were offset, in part, by improvements in our North
segment, where Commodity Margin increased $92 million in 2010, due
largely to the integration of our Mid-Atlantic fleet as of the
third quarter and strong performance by our legacy plants
associated with cold weather late in the fourth quarter of
2010.
Net loss2 decreased to $24 million for the three months ended
December 31, 2010, compared to $43 million in the prior year
period. As detailed in Table 1, Net Income, As Adjusted, improved
from a net loss of $34 million in 2009 to net income of $51 million
in 2010. The improvement was primarily attributable to a $104
million increase in income tax benefit in the fourth quarter of
2010 compared to the prior year period, which was largely due to
the application of intraperiod non-cash tax allocation. In
addition, interest expense (excluding unrealized mark-to-market
(gains) losses) decreased by $15 million in the fourth quarter of
2010, due largely to the same factors that influenced the full-year
period, while sales, general and administrative expenses (net of
acquisition-related costs in 2010) declined by $14 million, due
primarily to lower personnel and consulting expenses. These
benefits were partially offset by a $21 million decline in income
from unconsolidated investments in power plants, primarily
resulting from the consolidation of OMEC as of January 1, 2010; a
$15 million increase in depreciation expense, driven by the same
factors that influenced the full-year period; and a $14 million
decrease in Commodity Margin, as previously discussed.
1 Includes generation from unconsolidated power plants, plants
owned but not operated and discontinued operations.2 Reported as
net income (loss) attributable to Calpine on our Consolidated
Statements of Operations.3 Increase in plant operating expense
excludes changes in major maintenance expense, stock-based
compensation expense, non-cash loss on disposition of assets and
acquisition related costs. See the table titled “Consolidated
Adjusted EBITDA Reconciliation” for the actual amounts of these
items for the three and twelve months ended December 31, 2010 and
2009.4 Decrease in sales, general and administrative expense
excludes changes in stock-based compensation and
acquisition-related costs. See the table titled “Consolidated
Adjusted EBITDA Reconciliation” for the actual amounts of these
items for the three and twelve months ended December 31, 2010 and
2009.
Table 1: Summarized Consolidated
Statements of Operations
(Unaudited)
Three Months Ended December 31,
Year Ended December 31, 2010
2009 2010 2009 (in millions)
Operating revenues $ 1,471 $ 1,544 $ 6,545 $ 6,463 Operating
expenses 1,406 1,366 5,663 5,496
Impairment losses, net gain on sale of
assets, and (income) loss from unconsolidated investments in power
plants
(24 ) (19 ) (19 ) (46 ) Income from
operations 89 197 901 1,013 Net interest expense, debt
extinguishment costs, loss on interest rate derivatives, and other
(income) expense 381 243 1,131 889
Income (loss) before reorganization items, income taxes and
discontinued operations (292 ) (46 ) (230 ) 124 Reorganization
items — 1 — (1 ) Income tax expense (benefit) (106 )
(2 ) (68 ) 15 Income (loss) before discontinued
operations (186 ) (45 ) (162 ) 110 Discontinued operations, net of
tax expense 162 1 193 35 Net income
(loss) (24 ) (44 ) 31 145 Net loss attributable to the
noncontrolling interest — 1 — 4 Net
income (loss) attributable to Calpine $ (24 ) $ (43 ) $ 31 $ 149
Discontinued operations, net of tax expense (162 ) (1 ) (193
) (35 )
Reorganization items(1)
— 1 — (1 ) Debt extinguishment costs(1)(2) 64 27 91 57
Gain on sale of assets, net(1)
(119 ) — (119 ) —
Impairment losses(1)
97 4 116 4 Unrealized MtM (gains) losses on derivatives(1)(3) 153
(22 ) 56 (87 )
Other items (1)(4)
42 — 105 — Net Income (Loss), As
Adjusted(5) $ 51 $ (34 ) $ 87 $ 87
(1) Shown net of tax, assuming a 0%
effective tax rate for these items (other than those referenced in
note 2 below).
(2) Debt extinguishment costs in the full
year 2009 period include $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.
(4) Other items for the three and twelve
months ended December 31, 2010, include $11 million and $36
million, respectively, in costs related to the Mid-Atlantic fleet
acquisition and $31 million and $69 million, respectively, in
realized mark-to-market losses associated with the settlement of
non-hedged interest rate swaps.
(5) See “Regulation G Reconciliations” for
further discussion of Net Income, As Adjusted.
REGIONAL SEGMENT REVIEW OF
RESULTS
Table 2: Commodity Margin by Segment
(in millions)
Three Months Ended December 31,
Year Ended December 31, 2010
2009 2010 2009 West $ 271
$ 327 $ 1,080 $ 1,245 Texas 104 139 504 644 North 145 53 535 268
Southeast 56 71 272 304 Total $ 576 $
590 $ 2,391 $ 2,461
West: Commodity Margin in our West segment decreased by
$165 million in 2010 compared to 2009, primarily resulting from a
decrease of $102 million related to the expiration of the PCF
arrangement in the fourth quarter of 2009. In addition, the
year-over-year variance was impacted by lower average hedge prices
in 2010 compared to 2009 and lower realized spark spreads on our
open positions due to lower market heat rates caused primarily by
cooler temperatures in 2010 compared to 2009 and an overall
increase in installed generation capacity and higher hydroelectric
generation volumes in California in 2010. Also contributing to the
unfavorable period-over-period change was a decrease of $11 million
for the sale of surplus emission allowances in the first quarter of
2009, which did not reoccur in the same period in 2010. The
decrease in Commodity Margin was partially offset by an increase of
$50 million related to higher REC revenue from new contracts
associated with our Geysers assets; $80 million from OMEC, which
achieved commercial operation in October 2009 and was consolidated
on January 1, 2010; and a $12 million credit recognized in the
second quarter of 2010 related to overcharges associated with a gas
transportation contract.
Commodity Margin in our West segment decreased by $56 million
for the three months ended December 31, 2010, compared to the same
period in 2009, primarily resulting from a decrease of $25 million
related to the expiration of the PCF arrangement in the fourth
quarter of 2009, lower average hedge prices for the fourth quarter
of 2010 compared to 2009, and lower realized spark spreads on our
open positions primarily driven by lower gas prices in the fourth
quarter of 2010. The decrease in Commodity Margin was partially
offset by increases of $11 million related to higher REC revenue
from our Geysers assets and $24 million from OMEC.
Texas: Commodity Margin in our Texas segment
decreased by $140 million in 2010 compared to 2009, primarily
resulting from lower average hedge prices and lower realized spark
spreads on open positions. The lower realized spark spreads were
due to lower market heat rates, particularly with regard to June
2010, which did not benefit from the extreme heat,
congestion-driven pricing and tighter reserve margin that occurred
in June 2009, as well as an overall increase in installed
generation capacity in ERCOT.
Commodity Margin in our Texas segment decreased by $35 million
for the three months ended December 31, 2010, compared to the same
period in 2009, primarily resulting from lower average hedge prices
for the fourth quarter of 2010 compared to the same period in
2009.
North: Commodity Margin in our North segment increased by
$267 million in 2010 primarily due to the acquisition of our
Mid-Atlantic fleet, which closed on July 1, 2010, and higher
realized spark spreads on open positions driven by much warmer
weather in the second and third quarters of 2010, as well as colder
weather in the latter fourth quarter of 2010 compared to the same
periods in 2009.
Commodity Margin in our North segment increased by $92 million
for the three months ended December 31, 2010, compared to the same
period in 2009. The three-month results were largely impacted by
the Mid-Atlantic fleet acquisition and the strong performance of
our legacy plants driven by a very cold late fourth quarter.
Southeast: Commodity Margin in our Southeast segment
decreased by $32 million in 2010 compared to 2009. Our power plants
in the western half of the region experienced lower realized spark
spreads on open positions, driven by lower market heat rates.
Partially offsetting these negative impacts, our power plants in
the eastern half of the region experienced higher realized spark
spreads on open positions, driven by higher market heat rates
caused primarily by warmer weather in May and June 2010 and cooler
weather in the fourth quarter of 2010 compared to the same periods
in 2009. In addition, the overall decrease in Commodity Margin was
partially offset by the non-recurring negative impact from the
settlement of a disputed steam contract in the second quarter of
2009.
Commodity Margin in our Southeast segment for the three months
ended December 31, 2010, decreased by $15 million compared to the
same period in 2009. The modest decrease resulted primarily from
lower average hedge prices for the three months ended December 31,
2010, compared to the same period in 2009.
LIQUIDITY AND CAPITAL
RESOURCES
Table 3: Corporate Liquidity
December 31, December 31, 2010
2009 (in millions) Cash and cash equivalents,
corporate(1) $ 1,058 $ 725 Cash and cash equivalents, non-corporate
269 264 Total cash and cash equivalents 1,327 989
Restricted cash 248 562 Letter of credit availability(2) 35 34
Revolver availability(3) 623 794 Total current
liquidity availability $ 2,233 $ 2,379
(1) Includes $6 million and $9 million of
margin deposits held by us posted by our counterparties as of
December 31, 2010 and 2009, respectively.
(2) Additional available balances for
Calpine Development Holdings, Inc. letter of credit were increased
by $50 million to $200 million on June 30, 2010.
(3) On December 10, 2010, we executed our
$1.0 billion Corporate Revolving Facility, which replaced our $1.0
billion revolver under our First Lien Credit Facility and allows
for up to $750 million of availability for the issuance of letters
of credit and up to $50 million as a swingline subfacility. At
December 31, 2010, the letters of credit issued under our First
Lien Credit Facility were either replaced by letters of credit
issued by the Corporate Revolving Facility or back-stopped by an
irrevocable standby letter of credit issued by Deutsche Bank AG New
York Branch. Our letters of credit under our Corporate Revolving
Facility as of December 31, 2010 include those that were
back-stopped of approximately $83 million; however, we expect that
the back-stopped letters of credit will be returned and
extinguished in early 2011.
Liquidity at December 31, 2010 remained strong at $2.2 billion,
down modestly from $2.4 billion at December 31, 2009. As previously
discussed, operating activities for 2010 resulted in net cash
proceeds of $929 million, compared to $761 million in 2009.
Meanwhile, cash flows from investing activities resulted in a net
outflow of $831 million during 2010 compared to an outflow of $250
million in 2009. The 2010 activity was driven largely by the
previously mentioned purchase of our Mid-Atlantic fleet during the
third quarter, offset in part by cash inflows from the strategic
sales of our Colorado plants and Freestone equity interest, which
collectively generated $954 million in cash proceeds during
December 2010, and reduced restricted cash balances associated
primarily with the maturity of our PCF project financing
instrument. Cash flows from financing activities for the twelve
months ended December 31, 2010, resulted in a net inflow of $240
million, primarily as a result of the addition of a term loan whose
proceeds were used to fund a portion of our Mid-Atlantic
acquisition, offset primarily by our repayment of project-level
debt associated with the Colorado plants that we sold, our
repayment of the PCF financing, and other payments that we made
under project debt waterfall provisions.
During 2010, we generated $558 million of Adjusted Recurring
Free Cash Flow, compared to $602 million in 2009. The
year-over-year decline was primarily the result of the $70 million
decrease in Adjusted EBITDA, as previously discussed, and a $22
million increase in cash taxes, net, due primarily to the addition,
through our Mid-Atlantic acquisition, of operations in states where
we do not have state-level net operating losses. These decreases
were partially offset by a $32 million decrease in major
maintenance expense and capital expenditures from 2009 to 2010 as a
result of year-over-year differences in maintenance project
requirements as dictated by our plant maintenance cycle and a $14
million decrease in cash interest, net, primarily due to the
refinancing of our First Lien Term Loan, which was replaced with
fixed rate bonds.
CORPORATE DEBT
REFINANCING
Over the course of 2010 and early 2011, we strengthened our
capital structure through the opportunistic placement of $4.7
billion in Senior Secured Notes and the replacement of our $1.0
billion revolver, which allowed us to fully retire our First Lien
Credit Facility. “As a result of the successful refinancing of the
First Lien Term Loan and Revolver, we now have a flexible,
investment grade-like covenant package that provides us with a
wider array of capital allocation options, placing us in a stronger
position to enhance shareholder value,” said Zamir Rauf, Calpine’s
Chief Financial Officer.
PLANT DEVELOPMENT
York Energy Center: We acquired the 565 MW dual-fuel,
combined-cycle power plant under construction in Peach Bottom
Township, Pennsylvania, formerly referred to as the Delta Project,
as part of our acquisition of our Mid-Atlantic fleet. All permits
have been received and COD is expected in March 2011, three months
early and approximately $20 million under budget. The plant will
sell its power under a six-year Power Purchase Agreement (PPA) with
a third party beginning in June 2011.
Russell City Energy Center: In December 2010, we began
construction on this 619 MW natural gas-fired, combined-cycle power
plant in Hayward, California. We are currently in possession of all
material permits, subject to ongoing judicial appeals, and are now
in the process of obtaining project financing. The Russell City
Energy Center is contracted to deliver its full output to PG&E
under a ten year PPA and the expected COD is in 2013. We are a
majority partner in this project; our minority partner, a General
Electric affiliate, currently owns a 35% interest, though they are
currently funding their construction obligations at 25%. Our
partner’s ownership interest will no longer fluctuate and will
finalize upon closing of construction financing in 2011. Upon
completion, this project will bring on line approximately 429 MW of
net interest baseload capacity (464 MW with peaking capacity)
representing our expected 75% share.
Los Esteros Expansion: During 2009, we and PG&E negotiated a
new PPA to replace the existing California Department of Water
Resources contract and facilitate the upgrade of our Los Esteros
Critical Energy Facility from a 188 MW simple-cycle generation
power plant to a 308 MW combined-cycle generation power plant,
which will also increase the efficiency and environmental
performance of the power plant by lowering the heat rate. The PPA
and related agreements with PG&E have received all of the
necessary approvals and licenses, which are now effective. The
California Energy Commission has renewed our license and emission
limits, but the appeal period has not yet expired. In addition, we
are in the process of procuring equipment and selecting the
engineering, procurement and construction contractors. We expect
COD during the third quarter of 2013.
Turbine Upgrades: We continue to move forward with our turbine
upgrade program and have entered an agreement to upgrade select GE
and Siemens turbines. We have completed the upgrade of six Siemens
turbines and have agreed to upgrade approximately 15 additional
Siemens and GE turbines (and may upgrade additional turbines in the
future). Our turbine upgrade program is expected to increase our
generation capacity in total by approximately 275 MW. These
upgrades began in the fourth quarter of 2009 and are scheduled
through 2014. The upgraded turbines have been operating with heat
rates falling in line with expectations.
Geysers Assets Expansion: We continue to look to expand
production from our Geysers assets. Beginning in the fourth quarter
of 2009, we conducted an exploratory drilling program, which
effectively proved the commercial viability of the steam field in
the northern part of our Geysers assets; however, permitting delays
have emerged that we are working to resolve. We were planning to
target a 2013 COD for an expansion of our Geysers assets and had
been, in parallel, negotiating commercial arrangements to support
that, but the permitting delay has increased the risk we will not
meet a target 2013 COD. We continue to believe our northern Geysers
assets have potential for development. In the near term, we will
work to connect the test wells we have drilled over the last year
to our existing power plants and will work to capture incremental
MW from those wells, while continuing with the permitting process,
baseline engineering work and sales efforts for an expansion target
COD subsequent to 2013.
OPERATIONS UPDATE
2010 Power Operations Achievements:
- Safety Performance: Achieved eighth
consecutive year of top-quartile safety performance with 2010
lost-time incident rate of 0.23
- Availability Performance:
- Maintained 2010 fleet-wide average
availability factor of nearly 91%
- Achieved fleet-wide natural gas-fired
starting reliability of 98% in 2010, compared to 97% in 2009
- Cost Management
Performance: Maintained flat plant operating expense
year-over-year, despite addition of Mid-Atlantic fleet and
full-year operation at OMEC
- Geothermal Generation: Provided
approximately 6 million MWh of renewable baseload generation with
94% capacity factor, 98% availability factor and 0.23% forced
outage factor in 2010
- Natural Gas-fired Generation:
- Increased production from gas-fired
plants by over 3 million MWh1, or 4%, in 2010
- Achieved 100% availability and 100%
starting reliability at Carville Energy Center during the fourth
quarter of 2010
- Achieved 100% starting reliability and
0% forced outage factor at Los Medanos Energy Center during the
fourth quarter of 2010
- Began construction of our Russell City
Energy Center in December 2010
- Earned OSHA Star Worksite designation
at the Westbrook Energy Center under the stringent federal
Voluntary Protection Program, recognizing the plant’s exemplary
workplace health and safety efforts
2010 Commercial Operations Achievements:
- Customer-oriented Growth:
- Received approval of our PPA contracts
totaling 1,250 MW with SDG&E and PG&E from the California
Public Utility Commission
- Entered into a seven-year PPA with Xcel
Energy to provide 200 MW of power generated by our Oneta Energy
Center to Southwestern Public Service Company
- Signed a PPA with Bonneville Power
Administration to provide up to 75 MW of wind power generation
flexibility
- Portfolio Optimization:
- Completed the sale of a 25% undivided
interest in 1,038 MW Freestone Energy Center for $215 million
($830/kW) plus operating and energy management fees
- Completed the sale of Blue Spruce
Energy Center and Rocky Mountain Energy Center to PSCo. for $739
million ($794/kW)
FINANCIAL OUTLOOK
Table 4: Adjusted EBITDA and Adjusted
Recurring Free Cash Flow Guidance
Full Year 2011 (in millions) Adjusted EBITDA $
1,700 – 1,800 Less: Operating lease payments 30 Major maintenance
expense and capital expenditures(1) 390 Recurring cash interest,
net 825 Cash taxes 15 Adjusted Recurring Free Cash Flow $
440 - 540
Non-recurring interest rate swap payments(2) 165
(1) Includes projected Major Maintenance
Expense of $235 million and maintenance Capital Expenditures of
$155 million. Capital Expenditures exclude major construction and
development projects.
(2) Interest payments related to legacy
LIBOR hedges associated with floating rate First Lien Credit
Facility, which has been refinanced.
We are reaffirming our 2011 guidance, which includes Adjusted
EBITDA of $1,700 million to $1,800 million and Adjusted Recurring
Free Cash Flow of $440 million to $540 million. We expect to invest
approximately $155 million5 in growth-related projects during the
year, including our ongoing turbine upgrade program, our 565 MW
York Energy Center, our 619 MW Russell City Energy Center and the
120 MW upgrade of our Los Esteros plant.
5 Growth capital expenditure projections shown net of financing,
assuming project financing for Russell City and Los Esteros is
completed in 2011. Actual amounts spent during 2011 may exceed our
current projections depending upon the timing and terms of
financing.
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 2010 on
Friday, February 18, 2011, at 10 a.m. ET/9 a.m. CT. A listen-only
webcast of the call may be accessed through our website at
www.calpine.com or by dialing 888-364-3108 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 4461703. Presentation materials to accompany the conference
call will be made available on our website at www.calpine.com on
February 18, 2011.
ANNUAL MEETING DATE
Calpine’s Annual Meeting of Shareholders will be held on
Wednesday, May 11, 2011, at 10:00 a.m. CT in Houston, Texas, at a
location to be announced. Shareholders as of March 14, 2011, will
be eligible to vote at this year’s meeting.
ABOUT CALPINE
Founded in 1984, Calpine Corporation is a major U.S. power
company, currently capable of delivering approximately 27,500
megawatts of clean, cost-effective, reliable and fuel-efficient
power from its 91 operating plants to customers and communities in
20 U.S. states and Canada. Calpine Corporation is committed to
helping meet the needs of an economy that demands more and cleaner
sources of electricity. Calpine owns, leases and operates primarily
low-carbon, natural gas-fired and renewable geothermal power
plants. Using advanced technologies, Calpine generates power in a
reliable and environmentally responsible manner for the customers
and communities it serves. Please visit our website at
www.calpine.com for more information.
Calpine’s Annual Report on Form 10-K for the year ended December
31, 2010, may be found on the Securities and Exchange Commission’s
(SEC) website at www.sec.gov.
FORWARD-LOOKING
INFORMATION
In addition to historical information, this Report contains
“forward-looking statements” within the meaning of Section 27A
of the Securities Act and Section 21E of the Exchange Act. We
use words such as “believe,” “intend,” “expect,” “anticipate,”
“plan,” “may,” “will,” “should,” “estimate,” “potential,” “project”
and similar expressions to identify forward-looking statements.
Such statements include, among others, those concerning our
expected financial performance and strategic and operational plans,
as well as all assumptions, expectations, predictions, intentions
or beliefs about future events. You are cautioned that any such
forward-looking statements are not guarantees of future performance
and that a number of risks and uncertainties could cause actual
results to differ materially from those anticipated in the
forward-looking statements. Such risks and uncertainties include,
but are not limited to:
- Financial results that may be volatile
and may not reflect historical trends due to, among other things,
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;
- 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 climate change, GHG
emissions and derivative transactions;
- The unknown impact on our business from
the Dodd-Frank Wall Street Reform and Consumer Protection Act and
the rules to be promulgated under it;
- Our ability to manage our significant
liquidity needs and to comply with covenants under our First Lien
Credit Facility, First Lien Notes, NDH Project Debt, CCFC Notes and
other existing financing obligations;
- Risks associated with the operation,
construction and development of power plants including unscheduled
outages or delays and plant efficiencies;
- Risks related to our geothermal
resources, including the adequacy of our steam reserves, unusual or
unexpected steam field well and pipeline maintenance requirements,
variables associated with the injection of 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;
- Competition, including risks associated
with marketing and selling power in the evolving energy
markets;
- The expiration or termination of our
Power Purchase Agreements and the related results on revenues;
- Future capacity revenues may not occur
at expected levels;
- 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;
- Disruptions in or limitations on the
transportation of natural gas, fuel oil and transmission of
power;
- Our ability to manage our customer and
counterparty exposure and credit risk, including our commodity
positions;
- Our ability to attract, motivate and
retain key employees;
- Present and possible future claims,
litigation and enforcement actions; and
- Other risks identified in this release
or in our reports and registration statements filed with the SEC,
including, without limitation, the risk factors identified in our
Annual Report on Form 10-K for the year ended December 31,
2010.
Given the risks and uncertainties surrounding forward-looking
statements, you should not place undue reliance on these
statements. Many of these factors are beyond our ability to control
or predict. Our forward-looking statements speak only as of the
date hereof. Other than as required by law, we undertake no
obligation to update or revise forward-looking statements, whether
as a result of new information, future events, or otherwise.
CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED
STATEMENTS OF OPERATIONS (Unaudited)
Three Months Ended December 31,
Year Ended December 31, 2010 2009
2010 2009 (in millions, except share and
per share amounts) Operating revenues $ 1,471 $ 1,544 $ 6,545 $
6,463 Operating expenses: Fuel and purchased energy expense
958 930 3,974 3,897 Plant operating expense 238 230 868 868
Depreciation and amortization expense 147 132 570 456 Sales,
general and other administrative expense 38 50 151 174 Other
operating expense 25 24 100 101 Total operating expense
1,406 1,366 5,663 5,496 Impairment losses 97 4 116 4 (Gain)
on sale of assets, net (119 ) — (119 ) — (Income) loss from
unconsolidated investments in power plants (2 ) (23 ) (16 ) (50 )
Income from operations 89 197 901 1,013 Interest expense 165 211
789 815 (Gain) loss on interest rate derivatives, net 149 — 247 —
Interest (income) (3 ) (3 ) (11 ) (16 ) Debt extinguishment costs
64 27 91 76 Other (income) expense, net 6 8 15 14 Income (loss)
before reorganization items, income taxes and discontinued
operations (292 ) (46 ) (230 ) 124 Reorganization items — 1 — (1 )
Income (loss) before income taxes and discontinued operations (292
) (47 ) (230 ) 125 Income tax expense (benefit) (106 ) (2 ) (68 )
15 Income (loss) before discontinued operations (186 ) (45 ) (162 )
110 Discontinued operations, net of tax expense 162 1 193 35 Net
income (loss) (24 ) (44 ) 31 145 Net loss attributable to the
noncontrolling interest — 1 — 4
Net income (loss) attributable to
Calpine
$ (24 ) $ (43 ) $ 31 $ 149 Basic earnings (loss) per common
share attributable to Calpine: Weighted average shares of common
stock outstanding (in thousands) 486,106 485,776 486,044 485,659
Income (loss) before discontinued operations attributable to
Calpine $ (0.38 ) $ (0.09 ) $ (0.33 ) $ 0.24 Discontinued
operations, net of tax expense, attributable to Calpine 0.33 — 0.39
0.07 Net income (loss) per common share – basic $ (0.05 ) $ (0.09 )
$ 0.06 $ 0.31 Diluted earnings (loss) per common share
attributable to Calpine: Weighted average shares of common stock
outstanding (in thousands) 487,589 485,776 487,294 486,319 Income
(loss) before discontinued operations attributable to Calpine $
(0.38 ) $ (0.09 ) $ (0.33 ) $ 0.24 Discontinued operations, net of
tax expense, attributable to Calpine 0.33 — 0.39 0.07 Net income
(loss) per common share – diluted $ (0.05 ) $ (0.09 ) $ 0.06 $ 0.31
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS December 31, 2010 and
2009 2010 2009 (in millions,
except share and per share amounts) ASSETS
Current assets: Cash and cash equivalents $ 1,327 $ 989 Accounts
receivable, net of allowance of $2 and $14 669 750 Margin deposits
and other prepaid expense 221 490 Restricted cash, current 195 508
Derivative assets, current 725 1,119 Inventory and other current
assets 292 243 Total current assets 3,429 4,099
Property, plant and equipment, net 12,978 11,583 Restricted cash,
net of current portion 53 54 Investments 80 214 Long-term
derivative assets 170 127 Other assets 546 573 Total assets $
17,256 $ 16,650
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities: Accounts payable $ 514 $ 578 Accrued interest
payable 132 54 Debt, current portion 152 463 Derivative
liabilities, current 718 1,360 Income taxes payable 5 7 Other
current liabilities 268 287 Total current liabilities 1,789 2,749
Debt, net of current portion 10,104 8,996 Deferred income
tax liability, net of current 77 54 Long-term derivative
liabilities 370 197 Other long-term liabilities 247 208 Total
liabilities 12,587 12,204 Commitments and contingencies
Stockholders’ equity: Preferred stock, $.001 par value per share;
authorized 100,000,000 shares; none issued and outstanding at
December 31, 2010 and 2009 — — Common stock, $.001 par value per
share; authorized 1,400,000,000 shares; 444,883,356 shares issued
and 444,435,198 shares outstanding at December 31, 2010, and
443,325,827 shares issued and 442,998,255 shares outstanding at
December 31, 2009 1 1 Treasury stock, at cost, 448,158 and 327,572
shares, respectively (5 ) (3 ) Additional paid-in capital 12,281
12,256 Accumulated deficit (7,509 ) (7,540 ) Accumulated other
comprehensive loss (125 ) (266 ) Total Calpine stockholders’ equity
4,643 4,448 Noncontrolling interest 26 (2 ) Total stockholders’
equity 4,669 4,446 Total liabilities and stockholders’ equity $
17,256 $ 16,650
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS For the
Years Ended December 31, 2010 and 2009 2010
2009 (in millions) Cash flows from
operating activities: Net income $
31
$ 145 Adjustments to reconcile net income to net cash provided by
operating activities: Depreciation and amortization expense(1) 615
556 Debt extinguishment costs 91 37 Deferred income taxes (26 ) 16
Impairment loss 116 4 (Gain) loss on sale of power plants and
other, net (314 ) 37 Unrealized mark-to-market activities, net 56
(89 ) (Income) loss from unconsolidated investments in power
projects (16 ) (50 ) Return on investment in unconsolidated
subsidiaries 11 11 Stock-based compensation expense 24 38
Reorganization items —
(6
)
Other
1
6 Change in operating assets and liabilities, net of effects of
acquisitions: Accounts receivable
91
108
Derivative instruments (52 ) (118 ) Other assets 277 235 Accounts
payable, LSTC and accrued expenses 26 (19 ) Other liabilities (2 )
(150 ) Net cash provided by operating activities 929 761 Cash flows
from investing activities: Purchases of property, plant and
equipment (369 ) (179 ) Proceeds from sale of power plants,
interests and other 954 — Purchase of Conectiv assets and BRSP, net
of cash acquired (1,680 ) — Cash acquired due to reconsolidation of
OMEC 8 — Contributions to unconsolidated investments — (19 ) Return
of investment from unconsolidated investments — 9 Settlement of
non-hedging interest rate swaps (69 ) — (Increase) decrease in
restricted cash 322 (59 ) Other 3 (2 ) Net cash (used in) investing
activities (831 ) (250 ) Cash flows from financing activities:
Repayments of project financing, notes payable and other (937 )
(1,361 ) Borrowings from project financing, notes payable and other
1,272 1,034 Repayments on First Lien Credit Facilities (3,477 )
(785 ) Contributions from noncontrolling interest holder 17 —
Issuance of First Lien Notes 3,491 — Financing costs (136 ) (65 )
Refund of financing costs 10 — Other — (2 ) Net cash provided by
(used in) financing activities 240 (1,179 ) Net increase (decrease)
in cash and cash equivalents 338 (668 ) Cash and cash equivalents,
beginning of period 989 1,657 Cash and cash equivalents, end of
period $ 1,327 $ 989 Cash paid (received) during the period for:
Interest, net of amounts capitalized $ 635 $ 761 Income taxes $ 21
$ 7 Reorganization items included in operating activities, net $ —
$ 5
Supplemental disclosure of non-cash investing and
financing activities: Settlement of commodity contract with
project financing $ — $ 79 Change in capital expenditures included
in accounts payable $ 1 $ 6 Liabilities assumed in BRSP acquisition
$ 85 $ — Conversion of Project Debt to Noncontrolling Interest $ 11
$ — Issuance of First Lien Notes in exchange for First Lien Credit
Facility term loans $ — $ 1,200 Amended Steamboat project debt $ —
$ 448
(1) Includes depreciation and amortization
included in fuel and purchased energy expense, interest expense and
discontinued operations on our Consolidated Statements of
Operations.
REGULATION G RECONCILIATIONS
Net Income, As Adjusted, Commodity Margin, Adjusted EBITDA and
Adjusted Recurring Free Cash Flow are non-GAAP financial measures
that we use as measures of our performance. These measures should
be viewed as a supplement to and not a substitute for our U.S. GAAP
measures of performance.
Net Income, As Adjusted, represents net income (loss)
attributable to Calpine, adjusted for certain non-cash and
non-recurring items as previously detailed in Table 1, including
discontinued operations, net of tax expense, reorganization items,
debt extinguishment costs, gain on sale of assets, net, impairment
losses, unrealized mark-to-market (gains) losses on derivatives,
and other adjustments. Net Income, As Adjusted, is presented
because we believe it is a useful tool for assessing the operating
performance of our company in the current period. Net Income, As
Adjusted, is not intended to represent net income (loss), the most
comparable U.S. GAAP measure, as an indicator of operating
performance and is not necessarily comparable to similarly titled
measures reported by other companies.
Commodity Margin includes our power and steam revenues, sales of
purchased power and natural gas, capacity revenue, revenue from
renewable energy credits, sales of surplus emission allowances,
transmission revenue and expenses, fuel and purchased energy
expense, fuel transportation expense, RGGI compliance and other
environmental costs and cash settlements from our marketing,
hedging and optimization activities that are included in
mark-to-market activity, but excludes the unrealized portion of our
mark-to-market activity and other revenues. Commodity Margin is
presented because we believe it is a useful tool for assessing the
performance of our core operations, and it is a key operational
measure reviewed by our chief operating decision maker. Commodity
Margin does not intend to represent gross profit (loss), the most
comparable U.S. GAAP measure, as an indicator of operating
performance and is not necessarily comparable to similarly titled
measures reported by other companies.
Adjusted EBITDA represents earnings before interest, taxes,
depreciation and amortization, adjusted for certain non-cash and
non-recurring items as detailed in the following reconciliation.
Adjusted EBITDA is presented because our management uses Adjusted
EBITDA (i) as a measure of operating performance to assist in
comparing performance from period to period on a consistent basis
and to readily view operating trends; (ii) as a measure for
planning and forecasting overall expectations and for evaluating
actual results against such expectations; and (iii) in
communications with our Board of Directors, shareholders,
creditors, analysts and investors concerning our financial
performance. We believe Adjusted EBITDA is also used by and is
useful to investors and other users of our financial statements in
evaluating our operating performance because it provides them with
an additional tool to compare business performance across companies
and across periods. We believe that EBITDA is widely used by
investors to measure a company’s operating performance without
regard to items such as interest expense, taxes, depreciation and
amortization, which can vary substantially from company to company
depending upon accounting methods and book value of assets, capital
structure and the method by which assets were acquired. Adjusted
EBITDA is not a measure calculated in accordance with U.S. GAAP and
should be viewed as a supplement to and not a substitute for our
results of operations presented in accordance with U.S. GAAP.
Adjusted EBITDA is not intended to represent cash flows from
operations or net income (loss) as defined by U.S. GAAP as an
indicator of operating performance and is not necessarily
comparable to similarly titled measures reported by other
companies.
Adjusted Recurring Free Cash Flow represents net income before
interest, taxes, depreciation and amortization, as adjusted, less
operating lease payments, major maintenance expense and maintenance
capital expenditures, net cash interest, cash taxes, working
capital and other adjustments. Adjusted Recurring Free Cash Flow is
presented because our management uses this measure, among others,
to make decisions about capital allocation. Adjusted Recurring Free
Cash Flow is not intended to represent cash flows from operations
as defined by U.S. GAAP as an indicator of operating performance
and is not necessarily comparable to similarly titled measures
reported by other companies.
Commodity Margin Reconciliation
The following tables reconcile our Commodity Margin to its U.S.
GAAP results for the three months ended December 31, 2010 and 2009
(in millions):
Three Months Ended December 31, 2010
Consolidation And West
Texas North Southeast Elimination
Total Commodity Margin $ 271 $ 104 $ 145 $ 56 $ — $ 576 Add:
Mark-to-market commodity activity, net and other revenue(1) 9 (59 )
3 (9 ) (10 ) (66 ) Less: Plant operating expense 87 68 55 36 (8 )
238 Depreciation and amortization expense 52 37 35 25 (2 ) 147
Sales, general and other administrative expense 19 9 8 1 1 38 Other
operating expense(2) 16 — 7 2 (3 ) 22 Impairment losses 97 — — — —
97 (Gain) on sale of assets, net — (119 ) — — — (119 ) (Income)
from unconsolidated investments in power plants — —
(2 ) — — (2 ) Income (loss) from
operations $ 9 $ 50 $ 45 $ (17 ) $ 2 $ 89
Three Months Ended December 31, 2009 Consolidation
And West Texas North Southeast
Elimination Total Commodity Margin $ 327 $ 139 $ 53 $
71 $ — $ 590 Add: Mark-to-market commodity activity, net and other
revenue(1) 23 8 9 (7 ) (9 ) 24 Less: Plant operating expense 98 69
30 40 (7 ) 230 Depreciation and amortization expense 49 37 20 29 (3
) 132 Sales, general and other administrative expense 23 18 4 5 —
50 Other operating expense(2) 16 1 7 4 (4 ) 24 Impairment losses 4
— — — — 4 (Income) from unconsolidated investments in power plants
(19 ) — (4 ) — — (23 )
Income (loss) from operations $ 179 $ 22 $ 5 $ (14 ) $ 5 $ 197
(1) Mark-to-market commodity activity
represents the unrealized portion of our mark-to-market activity,
net, for the three months ended December 31, 2010 and 2009,
included in operating revenues and fuel and purchased energy
expense on our Consolidated Statements of Operations.
(2) Excludes $3 million and nil of RGGI
compliance and other environmental costs for both the three months
ended December 31, 2010 and 2009, respectively, which are included
as a component of Commodity Margin.
The following tables reconcile our Commodity Margin to its U.S.
GAAP results for the twelve months ended December 31, 2010 and 2009
(in millions):
Year Ended December 31, 2010
Consolidation And West
Texas North Southeast Elimination
Total Commodity Margin $ 1,080 $ 504 $ 535 $ 272 $ — $ 2,391
Add: Mark-to-market commodity activity, net and other revenue(1) 69
89 21 22 (30 ) 171 Less: Plant operating expense 351 285 138 123
(29 ) 868 Depreciation and amortization expense 207 150 111 109 (7
) 570 Sales, general and other administrative expense 55 38 45 12 1
151 Other operating expense(2) 59 2 28 4 (2 ) 91 Impairment losses
97 — — 19 — 116 (Gain) on sale of assets, net — (119 ) — — — (119 )
(Income) from unconsolidated investments in power plants —
— (16 ) — — (16 ) Income from
operations $ 380 $ 237 $ 250 $ 27 $ 7 $ 901
Year
Ended December 31, 2009 Consolidation And
West Texas North Southeast
Elimination Total Commodity Margin $ 1,245 $ 644 $
268 $ 304 $ — $ 2,461 Add: Mark-to-market commodity activity, net
and other revenue(1) 143 (40 ) 46 (5 ) (44 ) 100 Less: Plant
operating expense 408 232 91 134 3 868 Depreciation and
amortization expense 188 129 67 80 (8 ) 456 Sales, general and
other administrative expense 66 63 18 27 — 174 Other operating
expense(2) 73 14 30 11 (32 ) 96 Impairment losses 4 — — — — 4
(Income) from unconsolidated investments in power plants (32
) — (18 ) — — (50 ) Income from
operations $ 681 $ 166 $ 126 $ 47 $ (7 ) $ 1,013
(1) Mark-to-market commodity activity
represents the unrealized portion of our mark-to-market activity,
net, for the years ended December 31, 2010 and 2009, included in
operating revenues and fuel and purchased energy expense on our
Consolidated Statements of Operations.
(2) Excludes $9 million and $5 million of
RGGI compliance and other environmental costs for the years ended
December 31, 2010 and 2009, respectively, which are included as a
component of Commodity Margin.
Consolidated Adjusted EBITDA Reconciliation
In the following table, we have reconciled our Adjusted EBITDA
and Adjusted Recurring Free Cash Flow to our net income
attributable to Calpine for the three and twelve months ended
December 31, 2010 and 2009, as reported under U.S. GAAP.
Three Months Ended December 31, Year Ended
December 31, 2010 2009 2010
2009 (in millions) Net income (loss) attributable to
Calpine $ (24 ) $ (43 ) $ 31 $ 149 Net loss attributable to
noncontrolling interest — (1 ) — (4 ) Discontinued operations, net
of tax expense (162 ) (1 ) (193 ) (35 ) Income tax expense
(benefit) (106 ) (2 ) (68 ) 15 Reorganization items — 1 — (1 )
Other (income) expense and debt extinguishment costs, net 70 35 106
90 (Gain) loss on interest rate derivatives, net 149 — 247 —
Interest expense, net 162 208 778 799
Income from operations $ 89 $ 197 $ 901 $ 1,013 Add: Adjustments to
reconcile income from operations to Adjusted EBITDA: Depreciation
and amortization expense, excluding deferred financing costs(1) 149
133 573 459 Impairment loss 97 4 116 4 Major maintenance expense 46
42 157
163
Operating lease expense 12 12 45 47 Unrealized (gains) losses on
commodity derivative mark-to-market activity 69 (19 ) (143 ) (79 )
Gain on sale of assets (119 ) — (119 ) — Adjustments to reflect
Adjusted EBITDA from unconsolidated investments(2)(3) 9 6 34 17
Stock-based compensation expense 6 8 24 38 Non-cash loss on
dispositions of assets 3 3 10 32 Conectiv acquisition-related costs
11 — 36 — Other(4) — 3 3
6
Adjusted EBITDA from continuing operations 372 389 1,637 1,700
Adjusted EBITDA from discontinued operations 14 19 75 82 Total
adjusted EBITDA $ 386 $ 408 $ 1,712 $ 1,782 Less: Lease payments 12
12 45 47 Major maintenance expense and capital expenditures(5) 106
76 317 349 Cash interest, net(6) 167 213 768 782 Cash taxes(7) 7 —
17 (5 ) Other 8 — 7 7 Adjusted Recurring Free Cash Flow(8) $ 86 $
107 $ 558 $ 602
(1) Depreciation and amortization expense
in the income from operations calculation on our Consolidated
Statements of Operations excludes amortization of other assets.
(2) Included in our Consolidated
Statements of Operations in income from unconsolidated investments
in power plants.
(3) Adjustments to reflect Adjusted EBITDA
from unconsolidated investments include unrealized (gains) losses
on mark-to-market activity of nil and $(13) million for the three
months ended December 31, 2010 and 2009, respectively, and $1
million and $(47) million for the years ended December 31, 2010 and
2009, respectively.
(4) Includes fees for letters of
credit.
(5) Includes $51 million and $171 million
in major maintenance expense for the three and twelve months ended
December 31, 2010, respectively, and $55 million and $146 million
in maintenance capital expenditures for the three and twelve months
ended December 31, 2010, respectively. Includes $51 million and
$183 million in major maintenance expense for the three and twelve
months ended December 31, 2009, respectively, and $25 million and
$166 million in maintenance capital expenditures for the three and
twelve months ended December 31, 2009, respectively.
(6) Includes commitment, letter of credit
and other bank fees from both consolidated and unconsolidated
investments, net of capitalized interest and interest income.
(7) Cash taxes for the twelve months ended
December 31, 2009 excludes a $32 million tax refund related to our
foreign operations.
(8) Excludes decrease in working capital
of $76 million and $44 million for the three and twelve months
ended December 31, 2010, and $79 million and $70 million for the
three and twelve months ended December 31, 2009.
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, 2010 and 2009.
Reconciliations for both Adjusted EBITDA and Commodity Margin to
comparable U.S. GAAP measures are provided above.
Three Months Ended December 31, Year Ended
December 31, 2010 2009 2010
2009 (in millions) Commodity Margin $ 576 $ 590 $
2,391 $ 2,461 Other revenue 3 5 27 21 Plant operating expense(1)
(178 ) (181 ) (682 ) (657 ) Sales, general and administrative
expense(2) (31 ) (44 ) (108 ) (151 ) Other operating expense(3) (10
) (14 ) (43 ) (46 ) Adjusted EBITDA from unconsolidated investments
in power plants(4) 11 29 50 67 Adjusted EBITDA from discontinued
operations(5) 14 19 75 82 Other 1 4 2 5
Adjusted EBITDA $ 386 $ 408 $ 1,712 $ 1,782
(1) Shown net of major maintenance
expense, stock-based compensation expense, non-cash loss on
dispositions of assets and acquisition-related costs.
(2) Shown net of stock-based compensation
expense, reorganization items and acquisition-related costs.
(3) Excludes $3 million and nil of RGGI
compliance and other environmental costs for the three months ended
December 31, 2010 and 2009, respectively, and $9 million and $5
million for the years ended December 31, 2010 and 2009,
respectively, which are included as a component of Commodity
Margin.
(4) Amount is comprised of income from
unconsolidated investments in power plants, as well as adjustments
to reflect Adjusted EBTIDA from unconsolidated investments.
(5) Represents Adjusted EBITDA from Blue
Spruce and Rocky Mountain.
Adjusted EBITDA and Adjusted Recurring
Free Cash Flow Reconciliation for Guidance
Full Year 2011 Range: Low High
(in millions) GAAP Net Income (Loss) $ (25 ) $ 75 Plus:
Interest expense, net of interest income 820 820 Depreciation and
amortization expense 560 560 Major maintenance expense 230 230
Operating lease expense 35 35 Other(1) 80 80 Adjusted
EBITDA $ 1,700 $ 1,800 Less: Operating lease payments 30 30 Major
maintenance expense and maintenance capital expenditures(2) 390 390
Recurring cash interest, net(3) 825 825 Cash taxes 15
15 Adjusted Recurring Free Cash Flow $ 440 $ 540 Non-recurring
interest rate swap payments(4) 165 165
(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 $235 million and maintenance capital expenditures of
$155 million. Capital expenditures exclude major construction and
development projects.
(3) Includes fees for letters of credit,
net of interest income.
(4) Interest payments related to legacy
LIBOR hedges associated with floating rate First Lien Credit
Facility, which has been refinanced.
CASH FLOW ACTIVITIES
The following table summarizes our cash flow activities for the
years ended December 31, 2010 and 2009:
2010 2009 (in
millions) Beginning cash and cash equivalents $ 989 $ 1,657 Net
cash provided by (used in): Operating activities 929 761 Investing
activities (831 ) (250 ) Financing activities 240
(1,179 ) Net decrease in cash and cash equivalents 338
(668 ) Ending cash and cash equivalents $ 1,327 $ 989
OPERATING PERFORMANCE METRICS
The table below shows the operating performance metrics for
continuing operations:
Three Months Ended December 31,
Year Ended December 31, 2010 2009
2010 2009
Total MWh generated (in thousands)(1)
20,510
20,901 88,323 84,376 West 8,114 9,204 30,909
32,070 Texas
5,750
6,629 30,169 29,687 Southeast 4,275 3,529 17,987 17,370 North
2,371
1,539 9,258 5,249 Average availability 87.5% 90.3% 90.4%
92.1% West 91.2% 94.3% 91.5% 92.1% Texas 83.1% 83.9% 87.6% 90.0%
Southeast 89.9% 92.9% 92.5% 93.2% North 86.7% 92.5% 90.7% 94.7%
Average capacity factor, excluding peakers 40.8% 47.6% 46.0%
48.2% West 59.2% 73.2% 56.5% 64.0% Texas 36.6% 42.0% 48.1% 47.4%
Southeast 36.8% 31.0% 38.0% 37.9% North 25.1% 36.3% 32.8% 31.1%
Steam adjusted heat rate (mmbtu/kWh) 7,374 7,255 7,338 7,264
West 7,319 7,305 7,316 7,314 Texas 7,292 7,118 7,236 7,142
Southeast 7,264 7,331 7,315 7,299 North 7,947 7,441 7,819 7,614
(1) Does not include generation from
unconsolidated power plants, plants owned but not operated and
discontinued operations.
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