Calpine Corporation (NYSE:CPN):
Summary of 2011 Financial Results:
Three Months EndedSeptember 30,
2011
Nine Months EndedSeptember 30,
2011
(in millions) Operating Revenues $ 2,209 $ 5,341 Commodity Margin $
825 $ 1,921 Adjusted EBITDA $ 638 $ 1,347 Adjusted Recurring Free
Cash Flow $ 361 $ 381
Net Income (Loss)1
$ 190 $ (177 )
Net Income, As Adjusted2
$ 195 $ 30
Affirming 2011 Full Year Guidance and Providing 2012 Full
Year Guidance:
2011 2012 (in millions) Adjusted
EBITDA $ 1,700 – 1,750 $ 1,550 – 1,750 Adjusted Recurring Free Cash
Flow $ 475 – 525 $ 375 – 575
Recent Achievements:
– Produced 29 million MWh3 of electricity in
the third quarter of 2011– Delivered excellent forced outage
factor: Fleet-wide (1.9%), Texas (0.9%)– Achieved 99% fleet-wide
starting reliability
– Signed new contract with Southern
California Edison at our Pastoria Energy Center from 2013 –
2015
– Secured approximately $373 million credit
facility to finance the upgrade of our Los Esteros Critical Energy
Facility– Completed distribution of remaining bankruptcy reserve
shares– Announced and commenced $300 million share repurchase
program– Achieved S&P corporate secured debt rating upgrade to
BB-
Calpine Corporation (NYSE:CPN) today reported third quarter 2011
Adjusted EBITDA of $638 million, compared to $663 million in the
prior year period, and third quarter 2011 Adjusted Recurring Free
Cash Flow of $361 million, compared to $381 million in the prior
year period. Net Income1 for the third quarter of 2011 was $190
million, or $0.39 per diluted share, compared to $217 million, or
$0.45 per diluted share, in the prior year period. The declines in
the third quarter of 2011 as compared to the prior year period were
primarily due to the sale of our Colorado plants and a 25% interest
in our Freestone plant in December 2010. Net Income, As Adjusted2,
for the third quarter of 2011 was $195 million compared to $221
million in the prior year period.
“Our clean, efficient power generation fleet performed
exceptionally well during the peak summer period, producing 29
million MWh3 of power, while achieving starting reliability of 99%,
the highest third quarter on record,” said Jack Fusco, Calpine’s
President and Chief Executive Officer. “This is especially
noteworthy because it was achieved with the greatest number of
third quarter turbine starts on record, which exemplifies the
flexibility of our modern generation fleet. Consistent with this
performance, we are affirming our 2011 full-year guidance for
Adjusted EBITDA and Adjusted Recurring Free Cash Flow at $1,700
million to $1,750 million and $475 million to $525 million,
respectively.
“Meanwhile, this is an unprecedented time in the power
generation industry on both the environmental and competitive
market fronts. On the environmental front, the EPA’s Cross-State
Air Pollution Rule is being challenged by a group of coal
generators and states seeking to stay the rule from becoming
effective on January 1, 2012. Calpine has intervened to fully
support the EPA in its efforts to timely enforce this
well-publicized rule, for which the environmental control
technologies have been available for decades. On the competitive
power market front, Calpine continues to advocate for the
opportunity for markets to operate free of interference. Our
regulatory and legislative initiatives include structural market
reform in Texas, compensation for existing and flexible generation
in California and a commitment to maintaining the integrity of
competitive power markets in PJM.
“We are initiating our 2012 full-year guidance for Adjusted
EBITDA and Adjusted Recurring Free Cash Flow at $1,550 million to
$1,750 million and $375 million to $575 million, respectively. This
is a wider range than normal due to the more open hedge position we
will take into 2012, as well as the environmental and market
uncertainties. We anticipate our financial performance to resume
its upward trajectory in 2013 with the addition of Russell City and
Los Esteros, higher RPM capacity payments and the implementation of
carbon regulation in California.”
Zamir Rauf, Calpine’s Chief Financial Officer, added, “We have
continued to stay focused on enhancing shareholder value through
effective capital allocation using a variety of levers. For
example, during the third quarter, we completed a $373 million
project financing for the Los Esteros Critical Energy Facility,
minimizing the equity capital required for this valuable upgrade,
and we commenced a $300 million share repurchase program, allowing
us to opportunistically return capital to shareholders at price
levels that we believe provide investors with meaningful long-term
return. Lastly, it is worth noting that we completed the
distribution of the remaining bankruptcy reserve shares during the
quarter, thus fulfilling our remaining bankruptcy obligations.”
SUMMARY OF FINANCIAL
PERFORMANCE
Third Quarter Results
Adjusted EBITDA for the third quarter of 2011 was $638 million
compared to $663 million in the prior year period.
- The year-over-year decrease was
primarily due to a $27 million decline in Commodity Margin to $825
million in the third quarter of 2011 from $852 million in prior
year period. The year-over-year Commodity Margin decline was
primarily due to:
– Southeast segment: Decrease of $15 million
largely due to the expiration of certain hedge contracts that
benefited the third quarter of 2010 as well as the negative impact
of an unscheduled outage at one of our power plants in the third
quarter of 2011,– West segment: Decrease of $9 million, primarily
resulting from weaker price conditions resulting from increased
hydroelectric generation in California in the third quarter of
2011, and– Texas segment: Decrease of $3 million due to the sale of
a 25% undivided interest in our Freestone plant in December 2010,
which was largely offset by significantly higher power prices
driven by extreme heat and drought conditions that increased spark
spreads during the third quarter of 2011 on our relatively small
open position.
- Adjusted EBITDA was also negatively
impacted by a $20 million decrease in Adjusted EBITDA from
discontinued operations associated with the sale of our Colorado
plants in December 2010.
- These decreases were partially offset
by a $15 million decrease in plant operating expense4 due to fewer
unplanned outages in the third quarter of 2011 compared to the
prior year period.
Net Income1 declined to $190 million for the third quarter of
2011, compared to $217 million in the prior year period. As
detailed in Table 1, Net Income, As Adjusted, was $195 million in
the third quarter of 2011 compared to $221 million in the prior
year period. The year-over-year decline in Net Income, As Adjusted,
was driven largely by:
– lower Commodity Margin, as previously
discussed, and– an increase in plant operating expense due largely
to higher major maintenance expense resulting from our plant outage
schedule, partially offset by+ lower depreciation and amortization
expense driven primarily by assets that are now fully depreciated,
and+ lower interest expense resulting from a decrease in our
annualized effective interest rate.
Year-to-Date Results
Adjusted EBITDA for the nine months ended September 30, 2011,
was $1,347 million as compared to $1,326 million in the prior year
period.
- The year-over-year increase in Adjusted
EBITDA was primarily the result of a $106 million increase in
Commodity Margin to $1,921 million in the nine months ended
September 30, 2011, from $1,815 million in the prior year period,
which was due in large part to:
+ North segment: Increase of $188 million,
primarily driven by the acquisition of our Mid-Atlantic plants
which closed on July 1, 2010, and York Energy Center achieving
commercial operations in March 2011, partially offset by– Texas
segment: Decline of $43 million due primarily to unplanned outages
during an extreme cold weather event in early February 2011, as
well as the aforementioned Freestone sale, partially offset by
significantly higher power prices driven by extreme summer weather
in the third quarter of 2011 on our relatively small open position,
and– Southeast segment: Decrease of $28 million due to the
expiration of certain hedge contracts that benefited 2010.
- Partially offsetting the year-over-year
increase in Commodity Margin, Adjusted EBITDA was negatively
impacted by a $61 million decrease in Adjusted EBITDA from
discontinued operations associated with the sale of our Colorado
plants in December 2010.
- Plant operating expense4 from our
legacy plants decreased by $28 million in the first nine months of
2011, although this decrease was offset by plant operating expense
incurred for our Mid-Atlantic fleet, which was acquired as of July
1, 2010.
- Lastly, sales, general and
administrative expense5 increased by $8 million in the 2011 period,
primarily as a result of a $10 million bad debt allowance reversal
recorded in the first quarter of 2010 that did not recur in the
current year period.
Net Loss1 was $177 million for the nine months ended September
30, 2011, compared to net income of $55 million in the prior-year
period. As detailed in Table 1, Net Income, As Adjusted, was $30
million in the first nine months of 2011 compared to $25 million in
the prior year period. The year-over-year increase in Net Income,
As Adjusted, was primarily due to:
+ higher Commodity Margin, as previously
discussed, and+ lower depreciation and amortization expense due
largely to assets that are now fully depreciated, as well as a
revision in the expected settlement dates of the asset retirement
obligations of our power plants, partially offset by– an increase
in plant operating expense, driven by higher major maintenance
expenses and the addition of our Mid-Atlantic assets acquired as of
July 1, 2010.
__________
1
Reported as net income (loss) attributable
to Calpine on our Consolidated Condensed Statements of
Operations.
2
Refer to Table 1 for further detail of Net
Income, As Adjusted.
3
Includes generation from unconsolidated
power plants and plants owned but not operated by Calpine.
4
Decrease 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 nine months ended September 30, 2011 and
2010.
5
Increase 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 nine months ended September, 2011 and
2010.
Table 1: Summarized Consolidated
Condensed Statements of Operations
(Unaudited) Three Months Ended September 30,
Nine Months Ended September 30, 2011
2010 2011 2010 (in millions)
Operating revenues $ 2,209 $ 2,130 $ 5,341 $ 5,074 Operating
expenses (1,811 ) (1,558 ) (4,749 ) (4,257 ) Impairment losses — 19
— 19 (Income) loss from unconsolidated investments in power plants
(5 ) (1 ) (12 ) (14 ) Income from
operations 403 554 604 812 Net interest expense, (gain) loss on
interest rate derivatives, debt extinguishment costs, and other
(income) expense 193 335 825 750 Income
(loss) before income taxes and discontinued operations 210 219 (221
) 62 Income tax expense (benefit) 20 21 (45 )
38 Income (loss) before discontinued operations 190 198 (176
) 24 Discontinued operations, net of tax expense — 19
— 31 Net income (loss) $ 190 $ 217 $ (176 ) $ 55 Net
income attributable to the noncontrolling interest —
— (1 ) — Net income (loss) attributable to Calpine $
190 $ 217 $ (177 ) $ 55
Discontinued operations, net of tax
expense
— (19 ) — (31 ) Debt extinguishment costs(1) (4 ) 20 94 27
Unrealized MtM (gains) losses on derivatives(1)(2) (35 ) (35 ) 42
(97 )
Other items (1)(3)
44 38 71 71 Net Income, As Adjusted(4)
$ 195 $ 221 $ 30 $ 25
__________
(1)
Shown net of tax, assuming a 0% effective
tax rate for these items.
(2)
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.
(3)
Other items include realized
mark-to-market losses associated with the settlement of non-hedged
interest rate swaps totaling $44 million and $147 million for the
three and nine months ended September 30, 2011, respectively, and
$13 million and $27 million for the three and nine months ended
September 30, 2010, respectively. Other items for the nine months
ended September 30, 2011, also include a $(76) million federal
deferred income tax benefit associated with our election to
consolidate our CCFC subsidiary for tax reporting purposes. Other
items for the three and nine months ended September 30, 2010, also
include $6 million and $25 million, respectively, in costs
associated with the acquisition of our Mid-Atlantic fleet and $19
million in impairment of development costs related to a
pre-bankruptcy project.
(4)
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 September 30, Nine
Months Ended September 30, 2011 2010
Variance 2011 2010
Variance West $ 329 $ 338
$ (9 ) $ 798 $ 809 $ (11 ) Texas 162 165 (3 ) 357 400 (43 ) North
259 259 — 578 390 188 Southeast 75 90 (15 )
188 216 (28 ) Total $ 825 $ 852 $ (27 ) $
1,921 $ 1,815 $ 106
West Region
Third Quarter: Commodity Margin in our West segment decreased by
$9 million for the third quarter of 2011 compared to the prior year
period. Primary drivers included:
– lower spark spreads resulting from an
increase of hydroelectric generation in California during the third
quarter of 2011, partially offset by+ higher Commodity Margin
contribution from hedges and+ the positive impact of origination
activities for the third quarter of 2011 compared to the prior year
period.
Year-to-Date: Commodity Margin in our West segment for the nine
months ended September 30, 2011, was comparable to the prior year
period. Primary drivers included:
– lower spark spreads resulting from an
increase of hydroelectric generation in California in 2011 and– an
unscheduled outage at OMEC during the second quarter of 2011,
partially offset by+ higher Commodity Margin contribution from
hedges and+ the positive impacts from origination activities in
2011.
Texas Region
Third Quarter: Commodity Margin in our Texas segment for the
third quarter of 2011 was comparable to the prior year period.
Primary drivers included:
– the sale of a 25% undivided interest in the
assets of our Freestone power plant, largely offset by+
significantly higher power prices driven by extreme heat and
drought conditions, which increased spark spreads during the third
quarter of 2011 on our relatively small open position.
Year-to-Date: Commodity Margin in our Texas segment decreased by
$43 million for the nine months ended September 30, 2011, compared
to the prior year period. Primary drivers included:
– unplanned outages at some of our power
plants caused by an extreme cold weather event in February 2011
that required us to purchase physical replacement power at prices
substantially above our hedged prices, and– the sale of a 25%
undivided interest in the assets of our Freestone power plant, as
previously noted, partially offset by+ significantly higher power
prices driven by extreme heat and drought conditions, which
increased spark spreads during the third quarter of 2011 on our
relatively small open position, and+ higher Commodity Margin
contribution from hedges.
North Region
Third Quarter: Commodity Margin in our North segment for the
third quarter of 2011 was comparable to the prior year period.
Primary drivers included:
+ an increase in Commodity Margin at our York
Energy Center, which achieved commercial operations in March 2011,
offset by– lower spark spreads in the PJM market resulting from
milder weather during the third quarter of 2011 compared to the
same period in 2010.
Year-to-Date: Commodity Margin in our North segment increased by
$188 million for the nine months ended September 30, 2011, compared
to the prior year period. Primary drivers included:
+ the acquisition of our Mid-Atlantic fleet
as of July 1, 2010, and+ York Energy Center achieving commercial
operations in March 2011, as previously discussed.
Southeast Region
Third Quarter: Commodity Margin in our Southeast segment
decreased by $15 million for the third quarter of 2011, compared to
the prior year period. Primary drivers included:
– the expiration of certain hedge contracts
that benefited the third quarter of 2010 and– the negative impact
of an unscheduled outage at one of our power plants in the third
quarter of 2011.
Year-to-Date: Commodity Margin in our Southeast segment
decreased by $28 million for the nine months ended September 30,
2011, compared to the prior year period. The nine-month results
were largely impacted by the same factors that drove performance
for the third quarter, as previously discussed, along with
unscheduled outages in the second quarter of 2011.
LIQUIDITY AND CAPITAL
RESOURCES
Table 3: Liquidity
September 30, December 31, 2011
2010 (in millions) Cash and cash equivalents,
corporate(1) $ 977 $ 1,058 Cash and cash equivalents, non-corporate
308 269 Total cash and cash equivalents 1,285 1,327
Restricted cash 238 248 Revolving facility(ies) availability(2) 598
623 Letter of credit availability(3) 37 35 Total
current liquidity availability $ 2,158 $ 2,233 __________
(1)
Includes $5 million and $6 million of
margin deposits held by us posted by our counterparties at
September 30, 2011, and December 31, 2010, respectively.
(2)
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. 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 a third party. Our letters of
credit under our Corporate Revolving Facility at December 31, 2010,
include those that were back-stopped of approximately $83 million.
The back-stopped letters of credit were returned and extinguished
during the first quarter of 2011. The balance at December 31, 2010,
includes availability under the NDH Project Debt, which was retired
on March 9, 2011.
(3)
Includes availability under Calpine
Development Holdings, Inc.
Liquidity remained strong at $2.2 billion as of September 30,
2011, consistent with our liquidity levels as of December 31,
2010.
Cash flows provided by operating activities for the nine months
ended September 30, 2011, resulted in net inflows of $536 million
compared to $810 million for the prior year period. The change in
cash flows from operating activities was primarily due to a
reduction in margin requirements during the prior year period.
Cash flows from investing activities resulted in a net outflow
of $660 million in the nine months ended September 30, 2011, driven
largely by capital expenditures, including our growth projects at
Russell City, Los Esteros and York Energy Centers and our turbine
upgrade program.
Cash flows from financing activities resulted in a net inflow of
$82 million, primarily due to the corporate and subsidiary debt
refinancings completed in the first half of 2011, as well as the
issuance of project debt to fund our Russell City and Los Esteros
construction projects. Each of these project debt facilities
provides a construction loan that converts to a ten-year term loan
when the related project achieves commercial operation
designation.
Adjusted Recurring Free Cash Flow was $381 million for the nine
months ended September 30, 2011, compared to $499 million for the
prior year period. Despite a $21 million increase in Adjusted
EBITDA during the period, Adjusted Recurring Free Cash Flow
declined primarily due to a $132 million increase in major
maintenance costs (including expense and capital expenditures)
resulting from our plant outage schedule and unscheduled
outages.
SHARE REPURCHASE PROGRAM
During the third quarter of 2011, we announced that our Board of
Directors had authorized the repurchase of up to $300 million in
shares of our common stock. The announced program did not specify
an expiration date. Through October 27, 2011, we have executed
approximately 10% of the program, having repurchased a total of 2.1
million shares of our common stock at an average price of $13.65
per share. The shares repurchased as of October 27, 2011, were
purchased in open market transactions.
PLANT DEVELOPMENT
Russell City Energy Center: The Russell City Energy Center is
under construction and continues to move forward with expected COD
in 2013. Upon completion, this project will bring on line
approximately 429 MW of net interest baseload capacity (464 MW with
peaking capacity) representing our 75% share. We are in possession
of all required approvals and permits, and we closed on
construction financing on June 24, 2011. The project’s Prevention
of Significant Deterioration permit is currently the subject of an
ongoing appeal at the U.S. Court of Appeals for the Ninth Circuit
brought by Chabot-Las Positas Community College District against
the EPA. Upon completion, the Russell City Energy Center is
contracted to deliver its full output to PG&E under a ten-year
PPA.
Los Esteros: 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, which is final. The
Bay Area Air Quality Management District issued its renewal of the
Authority to Construct. We began construction in the second quarter
of 2011 and obtained construction financing on August 23, 2011. We
expect to achieve COD in 2013.
Turbine Upgrades: We continue to move forward with our turbine
upgrade program. Through September 30, 2011, we have completed
the upgrade of eight Siemens and five GE turbines and have agreed
to upgrade approximately eight 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. This upgrade program began in the
fourth quarter of 2009 and is scheduled through 2014. The upgraded
turbines have been operating with heat rates consistent with
expectations.
Geysers Assets Expansion: We continue to look to expand our
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
challenges have emerged that we are continuing to resolve, and we
are pursuing commercial arrangements which will need to be in place
prior to commencing expansion activities. We continue to
believe our northern Geysers assets have potential for development.
In the near term, we will connect the test wells to our existing
power plants to capture incremental production from those wells,
while continuing with the permitting process, baseline engineering
work and sales efforts for an expansion.
PJM: Given our view of the potential need for new generation in
the PJM region, driven both by market growth and the expected
impacts of environmental regulations on older, less efficient
generation within the region, we view the PJM region as a market
with an attractive growth profile. In order to capitalize on this
outlook, we are actively pursuing a set of development options,
including projects at:
- Edge Moor (Delaware): Recent completion
of the feasibility study by PJM for the addition of 300 MW of
combined-cycle capacity at our existing site, leveraging existing
infrastructure. The study results are being analyzed, and the
decision to proceed to system impact study phase is under
consideration.
- Garrison (Delaware): Actively
permitting 618 MW of new combined-cycle capacity at a development
site secured by a lease option with the City of Dover. PJM’s system
impact study for the first phase and the feasibility study for the
second phase will be completed shortly. Environmental permitting,
site development planning and development engineering are
underway.
- Talbert (Maryland): Existing
interconnect agreement for 200 MW of new simple-cycle capacity at a
development site secured by a lease option. Discussions regarding
construction of natural gas lateral to the project are in
progress.
- Powell (Maryland): Existing
interconnect agreement for up to 500 MW of new simple-cycle
capacity at a development site that is owned by Calpine. Fuel
supply options are being pursued with potential suppliers.
- Other locations that we feel provide
similar opportunity to position us for growth within the
region.
Mankato Power Plant Expansion Proposal: In March 2011, Xcel
Energy Inc. (Xcel) filed a proposal with the Minnesota Public
Utilities Commission (MPUC) to construct a new 700 MW natural-gas
fired, combined cycle facility to be located at its existing Black
Dog site. The MPUC required Xcel to also seek potential third-party
alternatives so that MPUC could compare any offers to Xcel’s
proposal. We proposed to expand our Mankato power plant, a 375 MW
natural gas-fired, combined-cycle power plant, by 345 MW under a
PPA with Xcel. We believe that our proposal is less expensive,
environmentally preferable and a closer match to Xcel’s demand
forecast than its self-build proposal. The MPUC is expected to make
a decision in 2012.
Channel and Deer Park Expansion: We continue to evaluate the
ERCOT market for expansion opportunities based on tightening
reserve margins and the potential impact of EPA regulations on
generation in Texas. At both our Deer Park and Channel Energy
Centers, we have the ability to install an additional combustion
turbine generator and connect to the existing steam turbine
generator to expand the capacity of these facilities and to improve
the overall efficiency. In September 2011, we submitted an air
permit application with the Texas Commission on Environmental
Quality (TCEQ) and the EPA to expand the Deer Park Energy Center by
approximately 275 MW. We anticipate filing similar permits in the
fourth quarter of 2011 with the TCEQ and the EPA to expand the
Channel Energy Center by approximately 275 MW.
OPERATIONS UPDATE
Third Quarter 2011 Power Operations Achievements:
– First quartile lost-time incident rate of
0.24 year-to-date– No lost time incidents during third quarter
- Availability Performance:
– 96% fleet-wide availability– Achieved
strong quarter fleet-wide starting reliability of 99%– Texas fleet
forced outage factor of 0.9%
– Achieved 100% starting reliability and
provided approximately 1.5 million MWh of renewable baseload
generation with 94% capacity factor
- Natural Gas-fired Generation:
– Channel, Deepwater, Edge Moor, Stony Brook,
California Peakers6: 0% forced outage factor + 100% starting
reliability
Third Quarter 2011 Commercial Operations Achievements:
- Customer-oriented Growth:
– Signed new contract with Southern
California Edison for our Pastoria Energy Center: Added energy toll
(750 MW, 2013 – 2015); Extended resource adequacy (715 MW, 2014 –
2015)
__________
6
Includes Yuba City, Feather River, Creed,
Goose Haven, and Lambie.
FINANCIAL OUTLOOK
Full Year 2011 Full Year 2012 (in
millions) Adjusted EBITDA $ 1,700 – 1,750 $ 1,550 – 1,750 Less:
Operating lease payments 30 35 Major maintenance expense and
capital expenditures(1) 390 350 Recurring cash interest, net 780
770 Cash taxes 15 10 Other 10 10 Adjusted Recurring
Free Cash Flow $ 475 - 525 $ 375 – 575 Non-recurring
interest rate swap payments(2) $ (175 ) $ (150 ) Growth Capital
Expenditures (net of debt funding) $ (155 ) $ (10 ) Riverside sale
proceeds $ 375 __________
(1)
Includes projected Major Maintenance
Expense of $235 million and $185 million in 2011 and 2012,
respectively, and maintenance Capital Expenditures of $155 million
and $165 million in 2011 and 2012, respectively. Capital
Expenditures exclude major construction and development projects.
2012 figures exclude amounts to be funded by project debt.
(2)
Interest payments related to legacy LIBOR
hedges associated with floating rate first lien credit facility,
which has been refinanced.
As detailed above, we are affirming our 2011 guidance of $1,700
million to $1,750 million of Adjusted EBITDA and $475 million to
$525 million of Adjusted Recurring Free Cash Flow. We are also
affirming our estimates of growth capital expenditures for the
year. We expect to invest $155 million, net of debt funding, in
growth-related projects during the year, including our York Energy
Center (now complete), our construction projects at Russell City
and Los Esteros and our ongoing turbine upgrade program.
Today, we are also initiating 2012 guidance. We expect Adjusted
EBITDA of $1,550 million to $1,750 million and Adjusted Recurring
Free Cash Flow of $375 million to $575 million. We also expect to
invest $10 million, net of debt funding, in growth-related projects
during the year. Though our construction projects at Russell City
and Los Esteros will continue through 2012, we have already met our
equity contribution requirements on these projects in 2011, such
that all costs incurred in 2012 and beyond will be funded from the
project debt we secured for these projects earlier this year.
Finally, we also expect to receive approximately $375 million
during the fourth quarter of 2012 as a deposit from one of our
customers toward their intended exercise of a call option to
purchase our Riverside Energy Center in 2013.
INVESTOR CONFERENCE CALL AND
WEBCAST
We will host a conference call to discuss our financial and
operating results for the third quarter of 2011 on Friday, October
28, 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 888-771-4371 in the U.S. or 847-585-4405 outside the U.S.
The confirmation code is 30885847. An archived recording of the
call will be made available for a limited time on our website or by
dialing 888-843-7419 (or 630-652-3042 outside the U.S.) and
providing confirmation code 30897052#. Presentation materials to
accompany the conference call will be made available on our website
on October 28, 2011.
ABOUT CALPINE
Founded in 1984, Calpine Corporation is a major U.S. power
company, currently capable of delivering approximately 28,000
megawatts of clean, cost-effective, reliable and fuel-efficient
power from its 92 operating plants to customers and communities in
20 U.S. states and Canada. Calpine 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 Quarterly Report on Form 10-Q for the quarter ended
September 30, 2011, has been filed with the Securities and Exchange
Commission (SEC) and may be found on the SEC’s website at
www.sec.gov.
FORWARD-LOOKING
INFORMATION
In addition to historical information, this release contains
“forward-looking statements” within the meaning of the Private
Securities Litigation Reform Act of 1995, Section 27A of the
U.S. Securities Act of 1933, as amended, and Section 21E of
the Exchange Act. Forward-looking statements may appear throughout
this report, including without limitation, “Management’s Discussion
and Analysis.” 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, changes in U.S. macroeconomic conditions, 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 the environment and
derivative transactions;
- The unknown future impact on our
business from the Dodd-Frank Act and the rules to be promulgated
under it;
- Our ability to manage our liquidity
needs and to comply with covenants under our First Lien Notes,
Corporate Revolving Facility, Term Loan, New Term Loan, 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 early termination of
our PPAs and the related results on revenues;
- Future capacity revenues may not occur
at expected levels;
- Natural disasters, such as hurricanes,
earthquakes and floods, acts of terrorism or cyber-attacks that may
impact our power plants or the markets our power plants serve and
our corporate headquarters;
- Disruptions in or limitations on the
transportation of natural gas, fuel oil and transmission of
power;
- Our ability to manage our customer and
counterparty exposure and credit risk, including our commodity
positions;
- Our ability to attract, motivate and
retain key employees;
- Present and possible future claims,
litigation and enforcement actions; and
- Other risks identified in this press
release and our 2010 Form 10-K.
Given the risks and uncertainties surrounding forward-looking
statements, you should not place undue reliance on these
statements. Many of these factors are beyond our ability to control
or predict. Our forward-looking statements speak only as of the
date 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 CONDENSED STATEMENTS OF
OPERATIONS
(Unaudited)
Three Months Ended September 30,
Nine Months Ended September 30, 2011
2010 2011 2010 (in millions, except
share and per share amounts) Operating revenues $ 2,209 $ 2,130
$ 5,341 $ 5,074 Operating expenses: Fuel and purchased
energy expense 1,401 1,143 3,470 3,016 Plant operating expense 212
199 711 630 Depreciation and amortization expense 143 152 405 423
Sales, general and other administrative expense 33 41 99 113 Other
operating expenses 22 23 64 75 Total
operating expenses 1,811 1,558 4,749
4,257 Impairment losses — 19 — 19 Income from unconsolidated
investments in power plants (5 ) (1 ) (12 )
(14 ) Income from operations 403 554 604 812 Interest
expense 192 230 575 635 (Gain) loss on interest rate derivatives,
net 3 84 149 87 Interest (income) (2 ) (2 ) (7 ) (8 ) Debt
extinguishment costs (4 ) 20 94 27 Other (income) expense, net
4 3 14 9 Income (loss) before income
taxes and discontinued operations 210 219 (221 ) 62 Income tax
expense (benefit) 20 21 (45 ) 38 Income
(loss) before discontinued operations 190 198 (176 ) 24
Discontinued operations, net of tax expense — 19
— 31 Net income (loss) 190 217 (176 ) 55 Net income
attributable to the noncontrolling interest — —
(1 ) — Net income (loss) attributable to Calpine $
190 $ 217 $ (177 ) $ 55 Basic earnings (loss) per common
share attributable to Calpine: Weighted average shares of common
stock outstanding (in thousands) 486,420 486,088 486,363 486,023
Income (loss) before discontinued operations attributable to
Calpine $ 0.39 $ 0.41 $ (0.36 ) $ 0.05 Discontinued operations, net
of tax expense attributable to Calpine — 0.04
— 0.06 Net income (loss) per common share attributable to
Calpine – basic $ 0.39 $ 0.45 $ (0.36 ) $ 0.11 Diluted
earnings (loss) per common share attributable to Calpine: Weighted
average shares of common stock outstanding (in thousands) 489,062
487,443 486,363 487,199 Income (loss) before discontinued
operations attributable to Calpine $ 0.39 $ 0.41 $ (0.36 ) $ 0.05
Discontinued operations, net of tax expense attributable to Calpine
— 0.04 — 0.06 Net income (loss) per
common share attributable to Calpine – diluted $ 0.39 $ 0.45 $
(0.36 ) $ 0.11
CALPINE CORPORATION AND
SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE
SHEETS
(Unaudited)
September 30, December 31,
2011 2010 (in millions, except share and
per share amounts) ASSETS Current assets: Cash and cash
equivalents $ 1,285 $ 1,327 Accounts receivable, net of allowance
of $8 and $2 755 669 Margin deposits and other prepaid expense 224
221 Restricted cash, current 195 195 Derivative assets, current 690
725 Inventory and other current assets 281
292 Total current assets 3,430 3,429 Property, plant and
equipment, net 13,010 12,978 Restricted cash, net of current
portion 43 53 Investments 75 80 Long-term derivative assets 134 170
Other assets 539 546 Total assets $ 17,231 $ 17,256
LIABILITIES & STOCKHOLDERS’ EQUITY Current liabilities:
Accounts payable $ 558 $ 514 Accrued interest payable 166 132 Debt,
current portion 101 152 Derivative liabilities, current 779 718
Other current liabilities 269 273 Total current
liabilities 1,873 1,789 Debt, net of current portion 10,303
10,104 Deferred income taxes, net of current 1 77 Long-term
derivative liabilities 303 370 Other long-term liabilities
232 247 Total liabilities 12,712 12,587 Commitments
and contingencies Stockholders’ equity: Preferred stock, $.001 par
value per share; 100,000,000 shares authorized; none issued and
outstanding — — Common stock, $.001 par value per share;
1,400,000,000 shares authorized; 490,552,649 and 444,883,356 shares
issued, respectively, and 489,779,285 and 444,435,198 shares
outstanding, respectively 1 1 Treasury stock, at cost, 773,364 and
448,158 shares, respectively (9 ) (5 ) Additional paid-in capital
12,299 12,281 Accumulated deficit (7,686 ) (7,509 ) Accumulated
other comprehensive loss (147 ) (125 ) Total Calpine
stockholders’ equity 4,458 4,643 Noncontrolling interest 61
26 Total stockholders’ equity 4,519 4,669
Total liabilities and stockholders’ equity
$
17,231 $ 17,256
CALPINE CORPORATION AND
SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF
CASH FLOWS
(Unaudited)
Nine Months Ended September 30,
2011 2010 (in millions) Cash flows from
operating activities: Net income (loss) $ (176
)
$ 55 Adjustments to reconcile net income (loss) to net cash
provided by operating activities: Depreciation and amortization
expense(1) 431 464 Debt extinguishment costs 82 27 Deferred income
taxes (56 ) 40 Impairment losses — 19 Loss on disposal of assets 18
11 Unrealized mark-to-market activity, net 42 (97 ) Income from
unconsolidated investments in power plants (12 ) (14 ) Return on
unconsolidated investments in power plants 6 11 Stock-based
compensation expense 18 18 Other 5 1 Change in operating assets and
liabilities: Accounts receivable (87 ) 34 Derivative instruments,
net (6 ) (42 ) Other assets 27 241 Accounts payable and accrued
expenses 95 (1 ) Liabilities related to non-hedging interest rate
swaps 147 27 Other liabilities 2 16 Net cash provided
by operating activities 536 810 Cash flows from
investing activities: Purchases of property, plant and equipment
(511 ) (191 ) Purchase of Conectiv assets — (1,634 ) Cash acquired
due to consolidation of OMEC — 8 Purchases of deferred transmission
credits (16 ) — Decrease in restricted cash 9 228 Settlement of
non-hedging interest rate swaps (147 ) (27 ) Other 5
4 Net cash used in investing activities (660 ) (1,612
) Cash flows from financing activities: Repayments of project
financing, notes payable and other $ (476 ) $ (472 ) Borrowings
from project financing, notes payable and other 223 1,272
Repayments on NDH Project Debt (1,283 ) — Borrowings under Term
Loan and New Term Loan 1,657 — Issuance of First Lien Notes 1,200
1,491 Repayments on First Lien Credit Facility (1,191 ) (1,507 )
Capital contributions from noncontrolling interest holder 34 —
Financing costs (78 ) (67 ) Refund of financing costs — 10 Other
(4 ) — Net cash provided by financing activities
82 727 Net decrease in cash and cash equivalents (42
) (75
)
Cash and cash equivalents, beginning of period 1,327
989 Cash and cash equivalents, end of period $ 1,285 $ 914 Cash
paid during the period for: Interest, net of amounts capitalized $
509 $ 488 Income taxes $ 15 $ 11
Supplemental disclosure of
non-cash investing and financing activities: Change in capital
expenditures included in accounts payable $ (13 ) $ (5 ) Purchase
of Conectiv assets included in accounts payable $ —
$
6
__________
(1)
Includes depreciation and amortization
that is also recorded in fuel and purchased energy expense,
interest expense and discontinued operations on our Consolidated
Condensed 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, debt extinguishment
costs, 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 physical natural gas, capacity revenue, revenue
from renewable energy credits, sales of surplus emission
allowances, transmission revenue and expenses, fuel and purchased
energy expense, fuel transportation expense, 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 income from operations, the
most comparable U.S. GAAP measure, as an indicator of operating
performance and is not necessarily comparable to similarly titled
measures reported by other companies.
Adjusted EBITDA represents 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 table reconciles our Commodity Margin to its U.S.
GAAP results for the three months ended September 30, 2011 and
2010:
Three Months Ended September 30,
2011(in millions)
Consolidation
And West Texas North
Southeast Elimination Total Commodity Margin
$
329 $ 162 $ 259 $ 75 $ — $ 825
Add: Mark-to-market commodity activity,
net and other(1)(2)
20 (21 ) (11 ) — (8 ) (20 ) Less: Plant operating expense 94 50 44
33 (9 ) 212 Depreciation and amortization expense 52 34 36 22 (1 )
143 Sales, general and other administrative expense 10 10 7 7 (1 )
33 Other operating expenses(3) 11 (1 ) 7 — 2 19 Income from
unconsolidated investments in power plants — —
(5 ) — — (5 ) Income from operations
$
182 $ 48 $ 159 $ 13 $ 1 $ 403
Three Months Ended September 30,
2010(in millions)
Consolidation And West Texas
North Southeast Elimination Total
Commodity Margin
$
338 $ 165 $ 259 $ 90 $ — $ 852 Add: Mark-to-market commodity
activity, net and other(1) 42 62 18 18 (6 ) 134 Less: Plant
operating expense 86 55 38 28 (8 ) 199 Depreciation and
amortization expense 52 37 37 28 (2 ) 152 Sales, general and other
administrative expense 10 13 12 5 1 41 Other operating expenses(3)
14 — 6 — 2 22 Impairment losses — — — 19 — 19 (Income) from
unconsolidated investments in power plants — —
(1 ) — — (1 ) Income from operations
$
218 $ 122 $ 185 $ 28 $ 1 $ 554
The following table reconciles our Commodity Margin to its U.S.
GAAP results for the nine months ended September 30, 2011 and
2010:
Nine Months Ended September 30,
2011(in millions)
Consolidation
And West Texas North Southeast
Elimination Total Commodity Margin $ 798 $ 357 $ 578
$ 188 $ — $ 1,921
Add: Mark-to-market commodity activity,
net and other revenue(1)(2)
36 (54 ) (12 ) (4 ) (23 ) (57
)
Less: Plant operating expense 297 193 136 107 (22 ) 711
Depreciation and amortization expense 140 99 102 67 (3 ) 405 Sales,
general and other administrative expense 29 33 19 18 — 99 Other
operating expenses(3) 30 2 23 3 (1 ) 57 (Income) from
unconsolidated investments in power plants — —
(12 ) — — (12
)
Income (loss) from operations $ 338 $ (24 ) $ 298 $ (11 ) $ 3 $ 604
Nine Months Ended September 30,
2010(in millions)
Consolidation And West Texas
North Southeast Elimination Total
Commodity Margin $ 809 $ 400 $ 390 $ 216 $ — $ 1,815 Add:
Mark-to-market commodity activity, net and other revenue(1) 60 148
18 31 (20 ) 237 Less: Plant operating expense 264 217 83 87 (21 )
630 Depreciation and amortization expense 155 113 76 84 (5 ) 423
Sales, general and other administrative expense 36 29 37 11 — 113
Other operating expenses(3) 43 2 21 2 1 69 Impairment losses — — —
19 — 19 (Income) from unconsolidated investments in power plants
— — (14 ) — — (14 )
Income from operations $ 371 $ 187 $ 205 $ 44 $ 5 $ 812
__________
(1)
Mark-to-market commodity activity
represents the unrealized portion of our mark-to-market activity,
net, included in operating revenues and fuel and purchased energy
expense on our Consolidated Condensed Statements of Operations.
(2)
Includes $11 million and $15 million of
lease levelization and $4 million and $5 million of contract
amortization for the three and nine months ended September 30,
2011, respectively, related to contracts that became effective in
2011.
(3)
Excludes $3 million and $1 million of RGGI
compliance costs and other environmental costs for the three months
ended September 30, 2011 and 2010, respectively, and $7 million and
$6 million for the nine months ended September 30, 2011 and 2010,
respectively, which are components 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 Loss for the three
and nine months ended September 30, 2011 and 2010, as reported
under U.S. GAAP.
Three Months Ended September 30, Nine
Months Ended September 30, 2011 2010
2011 2010 (in millions) Net income
(loss) attributable to Calpine $ 190 $ 217 $ (177 ) $ 55 Net income
attributable to noncontrolling interest — — 1 — Discontinued
operations, net of tax expense — (19 ) — (31 ) Income tax expense
(benefit) 20 21 (45 ) 38 Other (income) expense and debt
extinguishment costs, net — 23 108 36 (Gain) loss on interest rate
derivatives, net 3 84 149 87 Interest expense, net 190
228 568 627 Income from operations $ 403 $ 554
$ 604 $ 812 Add: Adjustments to reconcile income from operations to
Adjusted EBITDA: Depreciation and amortization expense, excluding
deferred financing costs(1) 143 151 406 424 Impairment losses — 19
— 19 Major maintenance expense 33 13 169 111 Operating lease
expense 9 11 26 33 Unrealized (gain) loss on commodity derivative
mark-to-market activity 9 (131 ) 48 (212 ) Adjustments to reflect
Adjusted EBITDA from unconsolidated investments(2) 9 10 30 25
Stock-based compensation expense 6 6 18 18 Loss on dispositions of
assets 8 2 17 7 Conectiv acquisition-related costs — 6 — 25
Contract amortization 4 — 5 — Other 14 2 24
3 Adjusted EBITDA from continuing operations 638 643 1,347
1,265 Adjusted EBITDA from discontinued operations —
20 — 61 Total Adjusted EBITDA $ 638 $ 663 $ 1,347 $
1,326 Less: Lease payments 9 11 26 33 Major maintenance expense and
capital expenditures(3) 72 69 335 203 Cash interest(4) 194 200 587
582 Cash taxes 1 2 11 10 Other 1 — 7 (1
) Adjusted Recurring Free Cash Flow(5) $ 361 $ 381 $ 381 $ 499
_________
(1)
Depreciation and amortization expense in
the income from operations calculation on our Consolidated
Condensed Statements of Operations excludes amortization of other
assets.
(2)
Adjustments to reflect Adjusted EBITDA
from unconsolidated investments include unrealized losses on
mark-to-market activity of $1 million for both the three and nine
months ended September 30, 2011 and 2010.
(3)
Includes $35 million and $174 million in
major maintenance expense for the three and nine months ended
September 30, 2011, respectively, and $37 million and $161 million
in maintenance capital expenditures for the three and nine months
ended September 30, 2011, respectively. Includes $5 million and
$110 million in major maintenance expense for the three and nine
months ended September 30, 2010, respectively, and $64 million and
$93 million in maintenance capital expenditures for the three and
nine months ended September 30, 2010, respectively.
(4)
Includes commitment, letter of credit and
other bank fees from both consolidated and unconsolidated
investments, net of capitalized interest and interest income.
(5)
Excludes increase in working capital of
$166 million and $21 million for the three and nine months ended
September 30, 2011, respectively, and a decrease in working capital
of $48 million and an increase in working capital of $32 million
for the three and nine months ended September 30, 2010,
respectively. Adjusted Recurring Free Cash Flow, as reported,
excludes changes in working capital, such that it is calculated on
the same basis as our guidance. 2010 Adjusted Recurring Free Cash
Flow has been recast to conform with current year presentation,
which excludes settlements of non-hedging interest rate swaps.
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 nine months ended September 30, 2011 and 2010.
Reconciliations for both Adjusted EBITDA and Commodity Margin to
comparable U.S. GAAP measures are provided above.
Three Months Ended September 30, Nine
Months Ended September 30, 2011 2010
2011 2010 (in millions) Commodity
Margin $ 825 $ 852 $ 1,921 $ 1,815 Other revenue 4 2 11 24 Plant
operating expense(1) (166 ) (181 ) (512 ) (504 ) Sales, general and
administrative expense(2) (30 ) (31 ) (85 ) (77 ) Other operating
expense(3) (11 ) (10 ) (30 ) (33 ) Adjusted EBITDA from
unconsolidated investments in power plants(4) 15 11 42 39 Adjusted
EBITDA from discontinued operations(5) — 20 — 61 Other 1
— — 1 Adjusted EBITDA $ 638 $ 663 $ 1,347 $
1,326 _________
(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 and acquisition-related costs.
(3)
Excludes $3 million and $1 million of RGGI
compliance costs and other environmental costs for the three months
ended September 30, 2011 and 2010, respectively, and $7 million and
$6 million for the nine months ended September 30, 2011 and 2010,
respectively, which are components of Commodity Margin.
(4)
Amount is comprised of income from
unconsolidated investments in power plants, as well as adjustments
to reflect Adjusted EBITDA from unconsolidated investments.
(5)
Represents Adjusted EBITDA from Blue
Spruce and Rocky Mountain power plants, which were sold in December
2010.
Adjusted EBITDA and Adjusted Recurring Free Cash Flow
Reconciliation for Guidance
Full Year 2011 Range: Low High
(in millions) GAAP Net Income (Loss)(1) $ (150 ) $ (100 )
Plus: (Gain) loss on interest rate derivatives, net 149 149 Debt
extinguishment costs 94 94 Interest expense, net of interest income
760 760 Depreciation and amortization expense 560 560 Major
maintenance expense 230 230 Operating lease expense 35 35 Other(2)
22 22 Adjusted EBITDA $ 1,700 $ 1,750 Less: Operating
lease payments 30 30 Major maintenance expense and maintenance
capital expenditures(3) 390 390 Recurring cash interest, net(4) 780
780 Cash taxes 15 15 Other 10 10 Adjusted Recurring
Free Cash Flow $ 475 $ 525 Non-recurring interest rate swap
payments(5) 175 175
__________
(1)
For purposes of Net Income guidance
reconciliation, unrealized mark-to-market adjustments are assumed
to be nil.
(2)
Other includes stock-based compensation
expense, adjustments to reflect Adjusted EBITDA from unconsolidated
investments, income tax expense and other items.
(3)
Includes projected major maintenance
expense of $235 million and maintenance capital expenditures of
$155 million. Capital expenditures exclude major construction and
development projects.
(4)
Includes fees for letters of credit, net
of interest income.
(5)
Interest payments related to legacy LIBOR
hedges associated with floating rate First Lien Credit Facility,
which has been refinanced. Does not include $17 million in interest
rate swap breakage costs related to the repayment of project debt
in June 2011.
Full Year 2012 Range: Low
High (in millions) GAAP Net Income (Loss)(1) $ (80 )
$ 120 Plus: Interest expense, net of interest income 765 765
Depreciation and amortization expense 555 555 Major maintenance
expense 185 185 Operating lease expense 35 35 Other(2) 90
90 Adjusted EBITDA $ 1,550 $ 1,750 Less: Operating lease
payments 35 35 Major maintenance expense and maintenance capital
expenditures(3) 350 350 Recurring cash interest, net(4) 770 770
Cash taxes 10 10 Other 10 10 Adjusted Recurring Free
Cash Flow $ 375 $ 575 Non-recurring interest rate swap payments(5)
150 150 __________
(1)
For purposes of Net Income guidance
reconciliation, unrealized mark-to-market adjustments are assumed
to be nil.
(2)
Other includes stock-based compensation
expense, adjustments to reflect Adjusted EBITDA from unconsolidated
investments, income tax expense and other items.
(3)
Includes projected major maintenance
expense of $185 million and maintenance capital expenditures of
$165 million. Capital expenditures exclude major construction and
development projects. 2012 figures exclude amounts to be funded by
project debt.
(4)
Includes fees for letters of credit, net
of interest income.
(5)
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
nine months ended September 30, 2011 and 2010:
Nine Months Ended September 30,
2011 2010 (in millions) Beginning cash
and cash equivalents $ 1,327 $ 989 Net cash provided by (used in):
Operating activities 536 810 Investing activities (660 ) (1,612 )
Financing activities 82 727 Net increase (decrease)
in cash and cash equivalents (42 ) (75
)
Ending cash and cash equivalents $ 1,285 $ 914
OPERATING PERFORMANCE METRICS
The table below shows the operating performance metrics for
continuing operations:
Three Months Ended September 30, Nine
Months Ended September 30, 2011 2010
2011 2010
Total MWh generated (in thousands(1))
28,400 28,208 65,921 67,813 West 6,540 8,093 16,189 22,795 Texas
10,833 9,533 24,019 24,419 Southeast 5,918 6,065 14,489 13,712
North 5,109 4,517 11,224 6,887 Average availability 95.9 %
95.9 % 89.8 % 91.5 % West 91.2 % 92.9 % 86.4 % 91.5 % Texas 98.2 %
96.5 % 88.8 % 89.1 % Southeast 96.6 % 97.4 % 92.0 % 93.4 % North
97.5 % 96.8 % 92.3 % 93.1 % Average capacity factor,
excluding peakers 53.8 % 54.3 % 42.9 % 47.9 % West 47.4 % 58.7 %
39.6 % 55.7 % Texas 70.1 % 60.0 % 52.5 % 51.9 % Southeast 48.9 %
49.3 % 41.0 % 38.4 % North 43.4 % 43.7 % 34.4 % 36.8 % Steam
adjusted heat rate (mmbtu/kWh) 7,464 7,415 7,434 7,328 West 7,479
7,345 7,488 7,315 Texas 7,296 7,305 7,256 7,222 Southeast 7,344
7,366 7,323 7,331 North 8,003 7,865 7,939 7,773 ________
(1)
Excludes generation from unconsolidated
power plants, plants owned but not operated and discontinued
operations.
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