Calpine Corporation (NYSE:CPN):
Summary of 2011 Financial Results (in millions):
Three Months Ended December 31, Year
Ended December 31, 2011 2010
% Change 2011 2010
% Change Operating Revenues $ 1,459 $ 1,471
(0.8
)
%
$ 6,800 $ 6,545 3.9 % Commodity Margin $ 553 $ 576
(4.0
)
%
$ 2,474 $ 2,391 3.5 % Adjusted EBITDA $ 379 $ 386
(1.8
)
%
$ 1,726 $ 1,712 0.8 % Adjusted Recurring Free Cash Flow $ 108 $ 59
83.1 % $ 489 $ 558
(12.4
)
%
Net Income (Loss)1 $ (13 ) $ (24 ) $ (190 ) $ 31 Net Income (Loss),
As Adjusted2 $ (43 ) $ 62 $ (13 ) $ 87
Tightening 2012 Full Year Guidance:
Prior Guidance
(as of October 2011)
Current Guidance (in millions) Adjusted
EBITDA $1,550 - 1,750 $1,600 - 1,725 Adjusted Recurring Free Cash
Flow $375 - 575 $ 425 - 550
Recent Achievements:
- Operations:— Produced 94 million MWh3
of electricity in 2011— Delivered excellent 2011 fleetwide forced
outage factor of 2.5%— Achieved 98% fleetwide starting reliability
in 2011
- Commercial:— Signed five-year contract
for the full output of our Auburndale Peaking Energy Center
- Capital Structure:— Continued execution
of share repurchase program: $124 million (more than 40%) complete—
Increased CDHI letter of credit facility by $100 million and
extended its maturity to 2016— Resolved and formally closed
bankruptcy case
Calpine Corporation (NYSE:CPN) today reported fourth quarter
2011 Adjusted EBITDA of $379 million, compared to $386 million in
the prior year period, and Adjusted Recurring Free Cash Flow of
$108 million, compared to $59 million in the prior year period. Net
Loss1 for the fourth quarter narrowed to $13 million, or $0.03 per
diluted share, compared to $24 million, or $0.05 per diluted share,
in the prior year period. Net Loss, As Adjusted2, for the fourth
quarter of 2011 was $43 million compared to Net Income, As
Adjusted2, of $62 million in the prior year period, a decline
primarily related to a reduction in income tax benefit associated
with non-cash intraperiod tax allocations and an increase in
various state and foreign jurisdiction income taxes.
Full year 2011 Adjusted EBITDA was $1,726 million, compared to
$1,712 million in the prior year. Full year 2011 Adjusted Recurring
Free Cash Flow was $489 million, compared to $558 million in the
prior year, a decrease mainly due to higher scheduled major
maintenance expense and capital expenditures in 2011 compared to
2010. Net Loss1 for the year was $190 million, or $0.39 per diluted
share, compared to Net Income1 of $31 million, or $0.06 per diluted
share, in the prior year. Net Loss, As Adjusted2, for 2011 was $13
million compared to Net Income, As Adjusted2, of $87 million in the
prior year, a decline primarily due to a reduction in income tax
benefit, as previously discussed.
“We successfully delivered on our 2011 financial and operational
commitments to our shareholders and have effectively positioned the
company for continued growth in long term shareholder value,” said
Jack Fusco, Calpine's President and Chief Executive Officer. “Our
focus on operational excellence, commercial optimization of our
fleet of power plants and efficient capital allocation has enabled
us to continue to deliver results during a period of volatility in
the power and commodity markets and lethargic economic
recovery.
“With the successes of 2011 behind us, we have turned our
attention to 2012. It has been our thesis that unlike generators
dependent on dark spreads resulting from higher natural gas prices
in power markets where gas price is on the margin, Calpine's
modern, efficient and cost-effective fleet of natural gas-fired
plants allows it to benefit even in extended periods of low natural
gas prices due to the efficiency of our fleet and the increase in
generation volume as customers switch from coal to gas for economic
reasons. For 2012, we expect to offset the collapse in natural gas
prices with increased generation volume due to unprecedented levels
of coal-to-gas switching and through opportunistic hedging, thus
demonstrating Calpine's resilience despite low natural gas prices.
In short, we have seen our thesis begin to play out during the
recent steep decline in natural gas prices. As a result and due to
solid execution by our plants and commercial operations group, we
are able to tighten our 2012 full year guidance for Adjusted EBITDA
to a range of $1,600 million to $1,725 million and for Adjusted
Recurring Free Cash Flow to a range of $425 million to $550
million. Finally, in 2012 we will continue to make financially
disciplined capital allocation decisions to enhance shareholder
value through additional growth opportunities or additional share
repurchases.”
SUMMARY OF FINANCIAL
PERFORMANCE
Fourth Quarter Results
Adjusted EBITDA for the fourth quarter of 2011 was $379 million
compared to $386 million in the prior year period. The
year-over-year decrease in Adjusted EBITDA was primarily due
to:
- A $23 million decline in Commodity
Margin, driven largely by a North segment decrease of $19 million
primarily due to a decline in capacity payments received for our
Mid-Atlantic portfolio as determined by the PJM capacity auction
and
- A $14 million decrease in Adjusted
EBITDA from discontinued operations associated with the sale of our
Colorado plants in December 2010, partially offset by
- A $24 million decrease in plant
operating expense4 related to lower routine maintenance expense
compared to the prior year period and insurance recoveries
recognized in the fourth quarter of 2011.
Net Loss1 declined to $13 million for the fourth quarter of
2011, compared to $24 million in the prior year period. As detailed
in Table 1, Net Loss, As Adjusted, was $43 million in the fourth
quarter of 2011 compared to Net Income, As Adjusted, of $62 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 – a reduction in income tax
benefit related to the application of non-cash intraperiod tax
allocations and an increase in various state and foreign
jurisdiction income taxes, offset in part by + a decrease in major
maintenance expense resulting from our plant outage schedule in the
fourth quarter of 2011 versus the prior year period.
2011 Full Year Results
Adjusted EBITDA for the year ended December 31, 2011, was $1,726
million compared to $1,712 million in the prior year. The
year-over-year increase in Adjusted EBITDA was primarily the result
of:
- An $83 million increase in Commodity
Margin, which was due in large part to:
+
North segment: Increase of $169 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 $35
million due primarily to unplanned outages during an extreme cold
weather event in early February 2011, as well as the sale of a 25%
undivided interest in our Freestone power plant in December 2010,
partially offset by significantly higher power prices driven by
extreme heat and drought conditions in the third quarter of 2011 on
our relatively small open position, and – Southeast segment:
Decrease of $32 million due to the expiration of certain hedge
contracts that benefited 2010 and the negative impact of
unscheduled outages that occurred during the second and third
quarters of 2011.
- In addition, normal recurring plant
operating expense4 declined by $16 million, largely driven by lower
expenses among our legacy plants, partially offset by a full year
of expense incurred by our Mid-Atlantic fleet, which was acquired
as of July 1, 2010.
- Partially offsetting these
year-over-year improvements, Adjusted EBITDA was negatively
impacted by a $75 million decrease in Adjusted EBITDA from
discontinued operations associated with the sale of our Colorado
plants in December 2010.
Net Loss1 was $190 million for the year ended December 31, 2011,
compared to Net Income1 of $31 million in the prior year. As
detailed in Table 1, Net Loss, As Adjusted, was $13 million in 2011
compared to Net Income, As Adjusted, of $87 million in the prior
year. The year-over-year decrease was primarily due to:
– a reduction in
income tax benefit, as previously discussed, and – higher major
maintenance expense in connection with our plant outage schedule,
partially offset by + higher Commodity Margin, as previously
discussed, and + a decrease in depreciation and amortization
expense due to rotable parts being fully depreciated for some of
our units, which was partially offset by an increase related to our
Mid-Atlantic assets acquired in 2010.
____________
1 Reported as net income (loss) attributable to Calpine on our
Consolidated Statements of Operations.
2 Refer to Table 1 for further detail of Net Income (Loss), 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 months and years
ended December 31, 2011 and 2010.
Table 1: Summarized Consolidated Condensed Statements of
Operations
(Unaudited)
Three Months Ended December 31, Year Ended December
31, 2011 2010 2011
2010 (in millions) Operating revenues $ 1,459 $ 1,471
$ 6,800 $ 6,545 Operating expenses 1,272 1,406 6,021 5,663
Impairment losses, net gain on sale of assets, and (income) loss
from unconsolidated investments in power plants (9 ) (24 ) (21 )
(19 ) Income from operations 196 89 800 901 Net interest expense,
(gain) loss on interest rate derivatives, net, debt extinguishment
costs, and other (income) expense 186 381 1,011
1,131 Income (loss) before income taxes and
discontinued operations 10 (292 ) (211 ) (230 ) Income tax expense
(benefit) 23 (106 ) (22 ) (68 ) Loss before discontinued
operations (13 ) (186 ) (189 ) (162 ) Discontinued operations, net
of tax expense — 162 — 193 Net income
(loss) $ (13 ) $ (24 ) $ (189 ) $ 31 Net income attributable to the
noncontrolling interest — — (1 ) — Net income
(loss) attributable to Calpine $ (13 ) $ (24 ) $ (190 ) $ 31
Discontinued operations, net of tax expense — (162 ) — (193
) Debt extinguishment costs(1) — 64 94 91 (Gain) on sale of assets,
net(1) — (119 ) — (119 ) Impairment losses(1) — 97 — 116 Unrealized
MtM (gain) loss on derivatives(1) (2) (72 ) 153 (30 ) 56 Other
items (1) (3) 42 53 113 105 Net Income
(Loss), As Adjusted(4) $ (43 ) $ 62 $ (13 ) $ 87
____________
(1)
Shown net of tax, assuming a 0% effective
tax rate for these items.
(2)
Represents unrealized mark-to-market (MtM)
(gain) loss 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 $42 million and $189 million for the
three months and year ended December 31, 2011, respectively, and
$42 million and $69 million for the three months and year ended
December 31, 2010, respectively. Other items for the year ended
December 31, 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 months and year ended December 31, 2010, also include $11
million and $36 million, respectively, in costs associated with the
acquisition of our Mid-Atlantic fleet.
(4)
See “Regulation G Reconciliations” for
further discussion of Net Income (Loss), As Adjusted.
REGIONAL SEGMENT REVIEW OF
RESULTS
Table 2: Commodity Margin by Segment (in millions)
Three Months Ended December 31, Year
Ended December 31, 2011 2010
Variance 2011 2010
Variance West $ 263 $ 271
(8 ) $ 1,061 $ 1,080 (19 ) Texas 112
104 8 469 504 (35 ) North 126 145 (19 ) 704 535 169 Southeast 52
56 (4 ) 240 272 (32 ) Total $ 553
$ 576 (23 ) $ 2,474 $ 2,391 83
West Region
Fourth Quarter: Commodity Margin in our West segment decreased
by $8 million in the fourth quarter of 2011 compared to the prior
year period. Primary drivers included:
– lower average
hedge prices in the fourth quarter of 2011 and – lower generation
volume associated with weaker market conditions, partially offset
by + the positive impacts from origination activities in 2011.
Full Year: Commodity Margin in our West segment declined by $19
million in 2011 compared to 2010. Primary drivers included:
–
lower spark spreads resulting from an increase in
hydroelectric generation in California in 2011,
–
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
Fourth Quarter: Commodity Margin in our Texas segment increased
by $8 million in the fourth quarter of 2011 compared to the prior
year period. Primary drivers included:
+ higher Commodity
Margin contribution from hedges in the fourth quarter of 2011 and +
higher generation volume during off-peak hours associated with
higher market heat rates, partially offset by –
a decrease in Commodity Margin from our
steam products, largely driven by an outage experienced by one of
our steam hosts during the quarter.
Full Year: Commodity Margin in our Texas segment decreased by
$35 million in 2011 compared to 2010. 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
Fourth Quarter: Commodity Margin in our North segment decreased
by $19 million in the fourth quarter of 2011 compared to the prior
year period. Primary drivers included:
–
a decline in capacity payments received for our Mid-Atlantic
portfolio as determined by the PJM capacity auction and
–
a decline in Commodity Margin related to sales of natural gas in
the fourth quarter of 2010, when natural gas prices temporarily
rose high enough that selling a portion of our natural gas
inventory was more profitable than producing power, partially
offset by + an increase in Commodity Margin at our York Energy
Center, which achieved commercial operations in March 2011.
Full Year: Commodity Margin in our North segment increased by
$169 million in 2011 compared to 2010. 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, partially offset by
–
lower capacity prices in the second half
of 2011 compared to the same period in 2010.
Southeast Region
Fourth Quarter: Commodity Margin in our Southeast segment
declined by $4 million in the fourth quarter of 2011 compared to
the prior year period. Primary drivers included:
–
the expiration of certain hedge contracts that benefited the
fourth quarter of 2010 and
–
lower spark spreads resulting from milder
weather in the fourth quarter of 2011 as compared to the prior year
period.
Full Year: Commodity Margin in our Southeast segment decreased
by $32 million in 2011 compared to 2010. Primary drivers
included:
–
the expiration of certain hedge contracts that benefited
2010 and
–
the negative impact of unscheduled outages that occurred during the
second and third quarters of 2011.
LIQUIDITY AND CAPITAL
RESOURCES
Table 3: Liquidity
December 31, December 31,
2011 2010 (in millions) Cash and cash
equivalents, corporate(1) $ 946 $ 1,058 Cash and cash equivalents,
non-corporate 306 269 Total cash and cash equivalents 1,252
1,327 Restricted cash 194 248 Revolving facility(ies)
availability(2) 560 623 Letter of credit availability(3) 7
35 Total current liquidity availability $ 2,013 $ 2,233
__________
(1)
Includes $34 million and $6 million of
margin deposits held by us posted by our counterparties at December
31, 2011 and 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 under our
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 our CDHI
letter of credit facility. On January 10, 2012, we increased the
CDHI letter of credit facility to $300 million and extended the
maturity date to January 2, 2016.
Liquidity remained strong at $2.0 billion as of December 31,
2011, down modestly from $2.2 billion at December 31, 2010.
Cash flows provided by operating activities for the year ended
December 31, 2011, resulted in net inflows of $775 million compared
to $929 million for the prior year. The change in cash flows from
operating activities was primarily due to a decrease in working
capital during 2010 resulting from reduced margin requirements on
commodity transactions, partially offset by an increase in income
from operations, adjusted for non-cash items.
Cash flows used in investing activities were $836 million in
2011, compared to $831 million in 2010. The activity in 2011 was
driven largely by capital expenditures, including our growth
projects at our Russell City, Los Esteros and York Energy Centers
and our turbine upgrade program. In addition, in 2011 we paid $189
million associated with the settlement of non-hedging interest rate
swaps.
Cash flows used in financing activities were $14 million in
2011, 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. In addition, during 2011 we repurchased $119
million of common stock under our share repurchase program.
Adjusted Recurring Free Cash Flow was $489 million for the year
ended December 31, 2011, compared to $558 million for the prior
year. Despite a $14 million increase in Adjusted EBITDA during the
year, Adjusted Recurring Free Cash Flow declined primarily due to
an $80 million increase in major maintenance costs (including
expense and capital expenditures) resulting from our plant outage
schedule.
We continue to improve the quality of our liquidity, most
recently by increasing our CDHI letter of credit facility from $200
million to $300 million and extending its maturity from December
2012 to January 2016. In addition, in an effort to further simplify
our capital structure, during the fourth quarter, we executed
purchase agreements to purchase two of the third party equity
interests in our subsidiary associated with our California peaking
plants. The closing of these transactions are subject to FERC
approval and the terms of the agreements.
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 the issuance of this release, we had
repurchased approximately $124 million of stock, completing more
than 40% of the aggregate amount authorized under the program,
having repurchased a total of 8.5 million shares of our common
stock at an average price of $14.60 per share.
PLANT DEVELOPMENT
North:
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:
- 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 (309 MW) and the feasibility study
for the second phase (309 MW) have been completed. Both studies are
being reviewed internally. Environmental permitting, site
development planning and development engineering are underway.
- Edge Moor (Delaware): A nominal 300 MW
combined-cycle development project located at our Edge Moor
facility which will leverage existing infrastructure. PJM is
currently conducting a system impact study which will provide a
detailed report on the project's interconnection costs.
Mankato Power Plant Expansion Proposal: In March 2011, Xcel
Energy Inc. (Xcel) filed an application 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 matter was referred to a
contested case hearing. Xcel subsequently filed to withdraw its
application for the Black Dog expansion, which may affect the
status of our proposed Mankato expansion. Xcel's request is
currently pending review by an administrative law judge. A decision
is not expected until the second quarter of 2012.
West:
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. 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 ten-year 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.
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. We have received
Conditional Use Permits from Sonoma County and are pursuing the
additional required permitting. 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 meantime, we
have connected certain 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.
ERCOT:
Channel and Deer Park Expansions: We continue to evaluate the
ERCOT market for expansion opportunities based on tightening
reserve margins and 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 filed 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. In November 2011, we filed similar permits
with the TCEQ and the EPA to expand the Channel Energy Center by
approximately 275 MW.
All Markets:
Turbine Upgrades: We continue to move forward with our turbine
upgrade program. Through December 31, 2011, we have
completed the upgrade of ten Siemens and five GE turbines and have
agreed to upgrade approximately six 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.
OPERATIONS UPDATE
2011 Power Operations Achievements:
- Safety Performance:— First quartile
lost-time incident rate of 0.27
- Availability Performance:— Met
fleetwide forced outage factor target of 2.5% in 2011— Achieved
strong fourth quarter fleetwide starting reliability of 99%
- Cost Performance:— Reduced 2011 normal,
recurring plant operating expense for legacy fleet by $32 million
compared to 2010
- Geothermal Generation:— Provided
approximately 6 million MWh of renewable baseload generation with
94% capacity factor during 2011
- Natural Gas-fired Generation:—
Increased fleetwide capacity factor in fourth quarter of 2011 to
49% compared to 41% in the prior year period— Achieved 100%
starting reliability and 0.14% forced outage factor at Hidalgo
Energy Center for full year 2011— Achieved 100% starting
reliability and 0% forced outage factor at the King City
Cogeneration Plant during the fourth quarter of 2011
2011 Commercial Operations Achievements:
- Customer-oriented Growth:— Signed
ten-year contract with Entergy Texas, Inc., to provide 485 MW of
power from our Carville Energy Center— Signed new contract with
Southern California Edison for our Pastoria Energy Center: Added
energy toll (750 MW, 2013 - 2015) and extended resource adequacy
(715 MW, 2014 - 2015)— Signed a five-year contract with Tampa
Electric Company for the full output of our Auburndale Peaking
Energy Center
FINANCIAL OUTLOOK
Full Year 2012 (in millions) Adjusted EBITDA $
1,600 - 1,725 Less: Operating lease payments 35 Major maintenance
expense and capital expenditures(1) 350 Recurring cash interest,
net 770 Cash taxes 10 Other 10 Adjusted Recurring Free Cash
Flow $ 425 - 550 Non-recurring interest rate swap
payments(2) $ 150 Growth capital expenditures (net of debt funding)
$ 10 Riverside sale proceeds $ 392
__________
(1)
Includes projected major maintenance
expense of $185 million and maintenance capital expenditures of
$165 million in 2012. 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, today we are tightening our 2012 guidance,
including raising the lower end. We now project Adjusted EBITDA of
$1,600 million to $1,725 million and Adjusted Recurring Free Cash
Flow of $425 million to $550 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 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
have secured for these projects. Finally, we also expect to receive
approximately $392 million during the fourth quarter of 2012 from
one of our customers related to 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 fourth quarter and full year 2011 on
Friday, February 10, 2012, at 11 a.m. ET / 10 a.m. CT. A
listen-only webcast of the call may be accessed through our website
at www.calpine.com, or by dialing
(800) 447-0521 in the United States or (847) 413-3238 outside the
United States. The confirmation code is 31536947. An archived
recording of the call will be made available for a limited time on
our website or by dialing (888) 843-7419 in the United States or
(630) 652-3042 outside the United States and providing confirmation
code 31536947. Presentation materials to accompany the conference
call will be available on our website on February 10, 2012.
ABOUT CALPINE
Calpine Corporation is the largest independent power producer in
the U.S., with a fleet of 93 power generation plants representing
more than 28,000 megawatts of generation capacity. Last year our
plants generated more than 94 million megawatt hours of power for
our wholesale customers in 20 states and Canada. Our 91 operating
plants as well as two under construction consist primarily of
natural gas-fired and renewable geothermal power plants that use
advanced technologies to generate power in a low-carbon and
environmentally responsible manner. Our modern, clean, efficient
and cost-effective fleet stands ready to respond to the increased
need for cleaner and more affordable power as the economy recovers,
as new environmental rules are implemented and force older, dirtier
plants to retire or reduce generation, as variable renewable power
generation from wind and solar grows and with it the need for
flexible natural gas generation to assure firm supply to the grid,
and finally, as natural gas becomes economically competitive with
coal as a fuel for power generation. Please visit www.calpine.com to learn more about why Calpine is
a generation ahead - today.
Calpine's Annual Report on Form 10-K for the year ended December
31, 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
Securities Act, and Section 21E of the Exchange Act.
Forward-looking statements may appear throughout this release. We
use words such as “believe,” “intend,” “expect,” “anticipate,”
“plan,” “may,” “will,” “should,” “estimate,” “potential,” “project”
and similar expressions to identify forward-looking statements.
Such statements include, among others, those concerning our
expected financial performance and strategic and operational plans,
as well as all assumptions, expectations, predictions, intentions
or beliefs about future events. You are cautioned that any such
forward-looking statements are not guarantees of future performance
and that a number of risks and uncertainties could cause actual
results to differ materially from those anticipated in the
forward-looking statements. Such risks and uncertainties include,
but are not limited to:
- Financial results that may be volatile
and may not reflect historical trends due to, among other things,
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 continued
economic and financial conditions affecting certain countries in
Europe including financial institutions located within those
countries and their ability to fund their financial
commitments;
- 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 2011 Form 10-K.
Given the risks and uncertainties surrounding forward-looking
statements, you should not place undue reliance on these
statements. Many of these factors are beyond our ability to control
or predict. Our forward-looking statements speak only as of the
date of this release. Other than as required by law, we undertake
no obligation to update or revise forward-looking statements,
whether as a result of new information, future events, or
otherwise.
CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED
STATEMENTS OF OPERATIONS (in millions, except share and per
share amounts) (Unaudited)
Three Months Ended December 31, Year Ended December
31, 2011 2010 2011
2010 Operating revenues $ 1,459 $ 1,471 $ 6,800 $
6,545 Operating expenses: Fuel and purchased energy expense 879 958
4,349 3,974 Plant operating expense 193 238 904 868 Depreciation
and amortization expense 145 147 550 570 Sales, general and other
administrative expense 32 38 131 151 Other operating expenses
23 25 87 100 Total
operating expenses 1,272 1,406 6,021
5,663 Impairment losses — 97 — 116 (Gain) on sale of
assets, net — (119 ) — (119 ) (Income) from unconsolidated
investments in power plants (9 ) (2 ) (21 ) (16 )
Income from operations 196 89 800 901 Interest expense 185 178 760
813 (Gain) loss on interest rate derivatives, net (4 ) 136 145 223
Interest (income) (2 ) (3 ) (9 ) (11 ) Debt extinguishment costs —
64 94 91 Other (income) expense, net 7 6
21 15 Income (loss) before income taxes and
discontinued operations 10 (292 ) (211 ) (230 ) Income tax expense
(benefit) 23 (106 ) (22 ) (68 ) Income (loss)
before discontinued operations (13 ) (186 ) (189 ) (162 )
Discontinued operations, net of tax expense — 162
— 193 Net income (loss) (13 ) (24 )
(189 ) 31 Net (income) attributable to the noncontrolling interest
— — (1 ) — Net income (loss)
attributable to Calpine $ (13 ) $ (24 ) $ (190 ) $ 31 Basic
earnings (loss) per common share attributable to Calpine: Weighted
average shares of common stock outstanding (in thousands) 482,468
486,106 485,381 486,044 Income (loss) before discontinued
operations attributable to Calpine $ (0.03 ) $ (0.38 )
$
(0.39 ) $ (0.33 ) Discontinued operations, net of tax expense
attributable to Calpine — 0.33 — 0.39
Net income (loss) per common share attributable to Calpine - basic
$ (0.03 ) $ (0.05 )
$
(0.39 ) $ 0.06 Diluted earnings (loss) per common
share attributable to Calpine: Weighted average shares of common
stock outstanding (in thousands) 482,468 487,589 485,381 487,294
Income (loss) before discontinued operations attributable to
Calpine $ (0.03 ) $ (0.38 )
$
(0.39 ) $ (0.33 ) Discontinued operations, net of tax expense
attributable to Calpine — 0.33 — 0.39
Net income (loss) per common share attributable to Calpine -
diluted $ (0.03 ) $ (0.05 )
$
(0.39 ) $ 0.06
CALPINE CORPORATION AND
SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31, 2011 and 2010 (in millions, except share and
per share amounts) 2011
2010 ASSETS Current assets: Cash and cash equivalents
$ 1,252 $ 1,327 Accounts receivable, net of allowance of $13 and $2
598 669 Margin deposits and other prepaid expense 193 221
Restricted cash, current 139 195 Derivative assets, current 1,051
725 Inventory and other current assets 329 292
Total current assets 3,562 3,429 Property, plant and
equipment, net 13,019 12,978 Restricted cash, net of current
portion 55 53 Investments 80 80 Long-term derivative assets 113 170
Other assets 542 546 Total assets $
17,371 $ 17,256
LIABILITIES & STOCKHOLDERS'
EQUITY Current liabilities: Accounts payable $ 435 $ 514
Accrued interest payable 200 132 Debt, current portion 104 152
Derivative liabilities, current 1,144 718 Income taxes payable 3 5
Other current liabilities 276 268 Total
current liabilities 2,162 1,789 Debt, net of current portion 10,321
10,104 Deferred income tax liability, non-current — 77 Long-term
derivative liabilities 279 370 Other long-term liabilities
245 247 Total liabilities 13,007 12,587
Commitments and contingencies Stockholders' equity: Preferred
stock, $0.001 par value per share; authorized 100,000,000 shares,
none issued and outstanding at December 31, 2011 and 2010 — —
Common stock, $0.001 par value per share; authorized 1,400,000,000
shares, 490,468,815 shares issued and 481,743,738 shares
outstanding at December 31, 2011, and 444,883,356 shares issued and
444,435,198 shares outstanding at December 31, 2010 1 1 Treasury
stock, at cost, 8,725,077 and 448,158 shares, respectively (125 )
(5 ) Additional paid-in capital 12,305 12,281 Accumulated deficit
(7,699 ) (7,509 ) Accumulated other comprehensive loss (178
) (125 ) Total Calpine stockholders' equity 4,304 4,643
Noncontrolling interest 60 26 Total
stockholders' equity 4,364 4,669 Total
liabilities and stockholders' equity $ 17,371 $ 17,256
CALPINE CORPORATION AND
SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH
FLOWS
For the Years Ended December 31, 2011
and 2010
(in millions)
2011 2010 Cash flows from
operating activities: Net income (loss) $ (189 ) $ 31 Adjustments
to reconcile net income (loss) to net cash provided by operating
activities: Depreciation and amortization expense(1) 587 615 Debt
extinguishment costs 82 91 Deferred income taxes (21 ) (26 )
Impairment losses — 116 (Gain) loss on sale of power plants and
other, net 13 (314 ) Unrealized mark-to-market activity, net (30 )
56 (Income) from unconsolidated investments in power plants (21 )
(16 ) Return on unconsolidated investments in power plants 6 11
Stock-based compensation expense 24 24 Other 6 1 Change in
operating assets and liabilities, net of effects of acquisitions:
Accounts receivable 74 91 Derivative instruments, net 15 (52 )
Other assets 1 277 Accounts payable and accrued expenses 28 (43 )
Settlement of non-hedging interest rate swaps 189 69 Other
liabilities 11 (2 ) Net cash provided by
operating activities 775 929 Cash flows
from investing activities: Purchases of property, plant and
equipment (683 ) (369 ) Proceeds from sale of power plants,
interests and other 13 954 Purchase of Conectiv assets and BRSP,
net of cash acquired — (1,680 ) Cash acquired due to consolidation
of OMEC — 8 Settlement of non-hedging interest rate swaps (189 )
(69 ) Decrease in restricted cash 54 322 Purchase of deferred
transmission credits (31 ) — Other — 3
Net cash used in investing activities
(836 )
(831 ) Cash flows from financing activities: Borrowings under Term
Loan and New Term Loan
1,657
— Repayments on NDH Project Debt (1,283 ) — Issuance of First Lien
Notes 1,200 3,491 Repayments on First Lien Credit Facility (1,195 )
(3,477 ) Borrowings from project financing, notes payable and other
327 1,272 Repayments of project financing, notes payable and other
(550 ) (937 ) Capital contributions from noncontrolling interest
holder 33 17 Financing costs (81 ) (136 ) Stock repurchases (119 )
— Refund of financing costs — 10 Other (3 ) —
Net cash provided by (used in) financing activities (14 )
240 Net increase (decrease) in cash and cash
equivalents (75 ) 338 Cash and cash equivalents, beginning of
period 1,327 989 Cash and cash equivalents,
end of period $ 1,252 $ 1,327 Cash paid during the
period for: Interest, net of amounts capitalized $ 656 $ 635 Income
taxes $ 18 $ 21
Supplemental disclosure of non-cash
investing and financing activities: Change in capital
expenditures included in accounts payable $ (24 ) $ 1 Liabilities
assumed in BRSP acquisition $ — $ 85
Conversion of project debt to
noncontrolling interest
$ — $ 11
__________
(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 (Loss), 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 (Loss), As Adjusted, represents net income (loss)
attributable to Calpine, adjusted for certain non-cash and
non-recurring items as previously detailed in Table 1, including
discontinued operations, net of tax expense, debt extinguishment
costs, unrealized mark-to-market (gain) loss on derivatives, and
other adjustments. Net Income (Loss), As Adjusted, is presented
because we believe it is a useful tool for assessing the operating
performance of our company in the current period. Net Income
(Loss), As Adjusted, is not intended to represent net income
(loss), the most comparable U.S. GAAP measure, as an indicator of
operating performance and is not necessarily comparable to
similarly titled measures reported by other companies.
Commodity Margin includes our power and steam revenues, sales of
purchased power and physical natural gas, capacity revenue, revenue
from renewable energy credits, sales of surplus emission
allowances, transmission revenue and expenses, fuel and purchased
energy expense, fuel transportation expense, RGGI compliance and
other environmental costs and cash settlements from our marketing,
hedging and optimization activities including natural gas
transactions hedging future power sales 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 as a measure of operating performance to assist in comparing
performance from period to period on a consistent basis and to
readily view operating trends, as a measure for planning and
forecasting overall expectations and for evaluating actual results
against such expectations, and in communications with our Board of
Directors, shareholders, creditors, analysts and investors
concerning our financial performance. 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 December 31, 2011 and 2010
(in millions):
Three Months Ended December 31, 2011
Consolidation And West
Texas North Southeast Elimination
Total Commodity Margin $ 263 $ 112 $ 126 $ 52 $ — $ 553 Add:
Mark-to-market commodity activity, net and other(1)(2) 77 (48 ) (1
) 5 (9 ) 24 Less: Plant operating expense 83 42 41 34 (7 ) 193
Depreciation and amortization expense 52 36 36 23 (2 ) 145 Sales,
general and other administrative expense 14 10 5 4 (1 ) 32 Other
operating expenses(3) 11 1 7 2 (1 ) 20 (Income) from unconsolidated
investments in power plants — — (9 ) — —
(9 ) Income (loss) from operations $ 180 $ (25 ) $ 45
$ (6 ) $ 2 $ 196
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(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 expenses(3) 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
The following table reconciles our Commodity Margin to its U.S.
GAAP results for the years ended December 31, 2011 and 2010 (in
millions):
Year Ended December 31, 2011
Consolidation
And West Texas North
Southeast Elimination Total Commodity Margin $
1,061 $ 469 $ 704 $ 240 $ — $ 2,474 Add: Mark-to-market commodity
activity, net and other (1)(2) 113 (102 ) (13 ) 1 (32 ) (33 ) Less:
Plant operating expense 380 235 177 141 (29 ) 904 Depreciation and
amortization expense 192 135 138 90 (5 ) 550 Sales, general and
other administrative expense 43 43 24 22 (1 ) 131 Other operating
expenses(3) 41 3 30 5 (2 ) 77 (Income) from unconsolidated
investments in power plants — — (21 ) — —
(21 ) Income (loss) from operations $ 518 $ (49 ) $
343 $ (17 ) $ 5 $ 800
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 (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 expenses(3) 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
__________
(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 Statements of Operations for the three
months and years ended December 31, 2011 and 2010.
(2)
Includes $(3) million and $12 million of
lease levelization and $3 million and $8 million of contract
amortization for the three months and year ended December 31, 2011,
respectively, related to contracts that became effective in
2011.
(3)
Excludes RGGI compliance and other
environmental costs of $3 million for each of the three months
ended December 31, 2011 and 2010, respectively, and $10 million and
$9 million for the years ended December 31, 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 income (loss)
attributable to Calpine for the three months and years ended
December 31, 2011 and 2010, as reported under U.S. GAAP.
Three Months Ended December 31,
Year Ended December 31, 2011
2010 2011 2010 (in
millions) Net income (loss) attributable to Calpine $ (13 ) $
(24 ) $ (190 ) $ 31 Net income attributable to the noncontrolling
interest — — 1 — Discontinued operations, net of tax expense — (162
) — (193 ) Income tax expense (benefit) 23 (106 ) (22 ) (68 ) Other
(income) expense and debt extinguishment costs, net 7 70 115 106
(Gain) loss on interest rate derivatives, net (4 ) 136 145 223
Interest expense, net 183 175 751 802
Income from operations $ 196 $ 89 $ 800 $ 901 Add: Adjustments to
reconcile income from operations to Adjusted EBITDA: Depreciation
and amortization expense, excluding deferred financing costs(1) 146
149 552 573 Impairment losses — 97 — 116 Major maintenance expense
36 46 205 157 Operating lease expense 9 12 35 45 Unrealized (gain)
loss on commodity derivative mark-to-market activity (23 ) 69 25
(143 ) Gain on sale of assets — (119 ) — (119 ) Adjustments to
reflect Adjusted EBITDA from unconsolidated investments(2)(3) 6 9
36 34 Stock-based compensation expense 6 6 24 24 (Gain) loss on
dispositions of assets (1 ) 3 16 10 Conectiv acquisition-related
costs(4) — 11 — 36 Contract amortization 3 — 8 — Other 1 —
25 3 Adjusted EBITDA from continuing
operations 379 372 1,726 1,637 Adjusted EBITDA from discontinued
operations — 14 — 75 Total Adjusted
EBITDA $ 379 $ 386 $ 1,726 $ 1,712 Less: Lease payments 9 12 35 45
Major maintenance expense and capital expenditures(5) 62 114 397
317 Cash interest, net(6) 194 186 781 768 Cash taxes 2 7 13 17
Other 4 8 11 7 Adjusted Recurring Free
Cash Flow(7) $ 108 $ 59 $ 489 $ 558
_________
(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 (gain) loss on
mark-to-market activity of nil for each of the three months ended
December 31, 2011 and 2010, and $1 million for each of the years
ended December 31, 2011 and 2010.
(4)
Includes $2 million and $26 million
included in sales, general and other administrative expenses and $9
million and $10 million included in plant operating expense for the
three months and years ended December 31, 2010, respectively.
(5)
Includes $27 million and $201 million in
major maintenance expense for the three months and year ended
December 30, 2011, respectively, and $35 million and $196 million
in maintenance capital expenditures for the three months and year
ended December 30, 2011, respectively. Includes $49 million and
$159 million in major maintenance expense for the three months and
year ended December 31, 2010, respectively, and $65 million and
$158 million in maintenance capital expenditures for the three
months and year ended December 31, 2010, respectively.
(6)
Includes commitment, letter of credit and
other bank fees from both consolidated and unconsolidated
investments, net of capitalized interest and interest income.
(7)
Excludes decrease in working capital of $8
million and increase in working capital of $13 million for the
three months and year ended December 31, 2011, respectively, and a
decrease in working capital of $76 million and $44 million for the
three months and year ended December 31, 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 months and years ended December 31, 2011 and 2010.
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, 2011
2010 2011 2010 (in
millions) Commodity Margin $ 553 $ 576 $ 2,474 $ 2,391 Other
revenue 2 3 13 27 Plant operating expense(1) (154 ) (178 ) (666 )
(682 ) Sales, general and administrative expense(2) (28 ) (31 )
(113 ) (108 ) Other operating expense(3) (10 ) (10 ) (40 ) (43 )
Adjusted EBITDA from unconsolidated investments in power plants(4)
15 11 57 50 Adjusted EBITDA from discontinued operations(5) - 14 -
75 Other 1 1 1 2 Adjusted EBITDA $ 379
$ 386 $ 1,726 $ 1,712
_________
(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 RGGI compliance and other
environmental costs of $3 million for each of the three months
ended December 31, 2011 and 2010, respectively, and $10 million and
$9 million for the years ended December 31, 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.
Adjusted EBITDA and Adjusted Recurring Free Cash Flow
Reconciliation for Guidance
Full Year 2012 Range: Low
High (in millions) GAAP Net Income (Loss)(1) $ (50 )
$ 75 Plus: Interest expense, net of interest income 765 765
Depreciation and amortization expense 575 575 Major maintenance
expense 185 185 Operating lease expense 35 35 Other(2) 90 90
Adjusted EBITDA $ 1,600 $ 1,725 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 $ 425 $ 550 Non-recurring interest rate swap
payments(5) 150 150
__________
(1)
For purposes of Net Income (Loss) 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
years ended December 31, 2011 and 2010:
2011 2010 (in
millions) Beginning cash and cash equivalents $ 1,327 $
989 Net cash provided by (used in): Operating activities 775
929 Investing activities (836 ) (831 ) Financing activities (14 )
240 Net increase (decrease) in cash and cash equivalents (75
) 338 Ending cash and cash equivalents $ 1,252 $
1,327
OPERATING PERFORMANCE METRICS
The table below shows the operating performance metrics for
continuing operations:
Three Months Ended December 31,
Year Ended December 31, 2011
2010 2011 2010 Total MWh
generated (in thousands)(1) 24,954 20,510 90,875 88,323 West 7,634
8,114 23,823 30,909 Texas 8,533 5,750 32,552 30,169 Southeast 4,494
4,275 18,983 17,987 North 4,293 2,371 15,517 9,258 Average
availability 91.4 % 87.5 % 90.1 % 90.4 % West 95.8 % 91.1 % 88.2 %
91.5 % Texas 89.4 % 83.1 % 89.0 % 87.6 % Southeast 91.5 % 89.9 %
91.9 % 92.5 % North 89.4 % 86.7 % 91.6 % 90.7 % Average
capacity factor, excluding peakers 48.7 % 40.7 % 44.3 % 46.0 % West
55.3 % 59.1 % 43.6 % 56.5 % Texas 55.2 % 36.6 % 53.2 % 48.1 %
Southeast 39.2 % 36.8 % 40.6 % 38.0 % North 40.3 % 25.1 % 35.9 %
32.8 % Steam adjusted heat rate (mmbtu/kWh) 7,358 7,374
7,412 7,338 West 7,287 7,319 7,418 7,316 Texas 7,203 7,292 7,243
7,236 Southeast 7,279 7,264 7,312 7,315 North 7,867 7,947 7,919
7,819
________
(1)
Excludes generation from unconsolidated
power plants, plants owned but not operated and discontinued
operations.
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