Calpine Corporation (NYSE:CPN) today reported a year-over-year
increase in Adjusted EBITDA and Commodity Margin for the first
quarter of 2009, despite a decline in revenues. Adjusted EBITDA
increased to $331 million for the three months ended March 31,
2009, compared to $301 million in the same period of last year.
Commodity Margin for the first quarter 2009 was $529 million,
slightly above Commodity Margin of $513 million for the first
quarter of 2008. Meanwhile, operating revenues were $1.7 billion
for the first quarter of 2009, compared to $2.0 billion in the
prior year period. Net income1 was $32 million, or $0.07 per
diluted share, in the first quarter of 2009, an improvement of $246
million, or $0.51 per share, over the first quarter of 2008.
�I am pleased with our first quarter results, particularly when
viewed against the backdrop of a very difficult economic climate,�
said Jack Fusco, Calpine�s president and chief executive officer.
�Our ability to deliver improvement in profitability in this
environment demonstrates that we are reaping the benefits of the
cost management and hedging programs initiated over the last six
months. We believe that our financial discipline, near-term risk
aversion and flexible, geographically diverse fleet will not only
serve our shareholders well during this downturn, but leave us
well-positioned to benefit from an economic recovery as we continue
to help generate a sustainable future for America.�
1 Reported as net income (loss) attributable to Calpine on our
Consolidated Condensed Statements of Operations.
SUMMARY OF FINANCIAL
PERFORMANCE
Compared to the first quarter 2008, Adjusted EBITDA improved $30
million to $331 million in the first quarter 2009. Largely driving
the improvement in Adjusted EBITDA was an increase in Commodity
Margin, which rose to $529 million in the first quarter of 2009
from $513 million in the prior year period. Improved Commodity
Margin in our West region was primarily associated with benefits
from hedging as well as from the sale of surplus emission
allowances, while our Southeast region increased its Commodity
Margin primarily as a result of higher hedge prices and higher
market heat rates. These improvements were partially offset by
decreases in Commodity Margin in our Texas region, where weaker
demand and spark spreads resulted in a 33% reduction in generation
year-over-year.
The improvement in first quarter 2009 Adjusted EBITDA was
further due to higher Adjusted EBITDA from our unconsolidated
investments in power plants, which increased by $11 million
year-over-year, primarily as a result of the Greenfield Energy
Centre, which achieved its first full quarter of operations in the
2009 period. Lastly, sales, general and other administrative
expense (excluding depreciation and amortization and non-cash
stock-based compensation) decreased by $7 million year-over-year,
largely as a result of lower personnel costs.
Cash flows provided by operating activities were $80 million in
the first quarter 2009 compared to an outflow of $340 million in
the prior year period. The improvement was due in large part to a
year-over-year decrease of $244 million in cash paid for interest,
primarily as a result of the repayment of the Second Priority Debt
in 2008. In addition, working capital employed decreased by $91
million, after adjusting for debt-related balances and assets held
for sale, which did not impact cash provided by operating
activities. The adjusted working capital decrease was primarily due
to reductions in margin deposits, partially offset by current
derivative activity. Further contributing to the improvement in
cash flows provided by operating activities was a $64 million
decline in cash payments for reorganization items, as well as a $7
million improvement in gross profit (excluding unrealized
mark-to-market activity and depreciation and amortization
expense).
We believe that a comparison of net income (loss) as reported,
from the first quarter 2009 to the first quarter 2008 is not
meaningful, as the 2008 results include significant impacts
associated with restructuring and our emergence from bankruptcy
during that quarter. As detailed in Table 1 below, net loss,
excluding reorganization items, other one-time items and unrealized
mark-to-market gains or losses, improved by $37 million
year-over-year. This improvement was driven by gains from our
unconsolidated investments in power plants (as noted above), as
well as by a decline in interest expense (net of one-time items)
due to lower average debt balances and lower average interest rates
in the first quarter of 2009.
Table 1: Summarized
Consolidated Statements of Operations
� �
(Unaudited) Three Months Ended March 31,
2009 �
2008 (in millions) Operating revenues $
1,677 $ 1,951 Cost of revenue � 1,395 � � 1,980 � Gross profit
(loss) 282 (29 ) SG&A, income (loss) from unconsolidated
investments in power plants and other operating expense � 31 � � 53
� Income (loss) from operations 251 (82 ) Net interest expense and
other (income) expense � 208 � � 416 � Income (loss) before
reorganization items and income taxes 43 (498 ) Reorganization
items 3 (279 ) Income tax expense (benefit) � 9 � � (5 ) Net income
(loss) $ 31 $ (214 ) Add: Net loss attributable to the
noncontrolling interest � 1 � � � � Net income (loss) attributable
to Calpine $ 32 � $ (214 ) � Reorganization items(1) 3 (279 ) Other
one-time items(1)(2) � � � � 162 � Net income (loss), net of
reorganization items and other one-time items 35 (331 ) Unrealized
MtM (gains) losses on derivatives (1)(3) � (126 ) � 203 � Net loss,
net of reorganization items, other one-time items and unrealized
MtM impacts $ (91 ) $ (128 ) � (1) Shown net of tax, assuming a 0%
effective tax rate for these items. (2) One-time items in the first
quarter of 2008 include $135 million in post-petition interest
expense and $27 million in settlement obligations related to our
Canadian debtors and other foreign entities recorded prior to their
reconsolidation in February 2008, both of which were associated
with our emergence from bankruptcy. (3) Represents unrealized
mark-to-market (MtM) (gains) losses on contracts that do not
qualify for hedge accounting treatment.
REGIONAL SEGMENT REVIEW OF
RESULTS
� �
Table 2: Commodity Margin by Segment
�
Three Months Ended March 31, 2009 �
2008(1)
(in millions) West $ 297 $ 278 Texas 122 139 Southeast 61 35
North � 49 � 61 Total $ 529 $ 513 � (1) 2008 Commodity Margin as
previously reported has been recast to confirm to our current year
presentation.
West: Commodity Margin in our West segment increased by
$19 million, or 7%, for the three months ended March 31, 2009,
compared to the three months ended March 31, 2008. Although market
spark spreads for the first quarter of 2009 settled substantially
lower than the three months ended March 31, 2008, the West segment
financial performance improved in the first quarter of 2009
primarily as a result of higher hedge levels and higher average
hedge prices as compared to the same period for 2008, as well as
from the sale of surplus emission allowances.
Texas: Commodity Margin in our Texas segment decreased by
$17 million, or 12%, for the three months ended March 31, 2009,
compared to the three months ended March 31, 2008. The positive
impact of our hedging activities largely mitigated a weakening
market environment, due to soft demand and much weaker spark
spreads, resulting in a 33% reduction in generation for the three
months ended March 31, 2009. On-peak, market spark spreads were 55%
lower in the Houston zone in the first quarter of 2009 compared to
the first quarter of 2008, largely driven by reduced ERCOT demand
and significantly lower natural gas prices.
Southeast: Commodity Margin in our Southeast segment
increased by $26 million, or 74%, driven primarily by both higher
average hedge prices and higher market heat rates in the first
quarter of 2009 compared to 2008. The increase in market heat rates
as well as the 45% increase in generation for the three months
ended March 31, 2009, compared to 2008 were attributable in part to
gas generation displacement of coal generation in certain markets
and, to a lesser extent, a 3% increase in average availability.
Additionally, some of our plants benefited from the impact of
advantageous transmission, customer and transportation agreements
in the first quarter of 2009.
North: Commodity Margin in our North segment decreased by
$12 million, or 20%, primarily due to lower average hedge prices
during the three months ended March 31, 2009, compared to 2008.
LIQUIDITY AND CAPITAL
RESOURCES
� � �
Table 3: Corporate Liquidity �
March 31,
December 31, 2009 2008 (in millions)
Cash and cash equivalents, corporate(1) $ 1,424 $ 1,361 Cash and
cash equivalents, non-corporate � 202 � 296 Total cash and cash
equivalents 1,626 1,657 Restricted cash 476 503 Letter of credit
availability(2) 22 2 Revolver availability � 45 � 16 Total current
liquidity(3) $ 2,169 $ 2,178 � (1) Includes $18 million and $169
million of margin deposits held from counterparties as of March 31,
2009, and December 31, 2008, respectively. (2) Includes available
balances for Calpine Development Holdings, Inc. in both periods
shown and $20 million of available capacity under our Knock-in
Facility as of March 31, 2009. (3) Excludes contingent amounts of
$150 million under the Knock-in Facility and $200 million under the
Commodity Collateral Revolver in both periods shown.
Liquidity remained strong during the first quarter of 2009 at
$2.2 billion. As discussed above, operating activities resulted in
cash inflows of $80 million during the quarter. These inflows were
offset by, among other items, $51 million in maintenance capital
expenditures and $54 million in net repayments of debt at both the
corporate and project levels.
As part of our continued liquidity management efforts, we have
further increased the amount of hedges performed under our first
lien (or �right-way-risk�) program, which allows us to utilize our
corporate debt facility to satisfy collateral obligations rather
than posting cash. Under this program, we have increased our use of
right-way-risk hedges approximately 350% since September 2008.
PLANT
DEVELOPMENT
Russell City Energy Center: The 600 MW combined-cycle, natural
gas-fired Russell City plant is a joint development project to be
located in Hayward, California. We hold a 65% interest in the
project, and an affiliate of General Electric Capital Corporation
holds a 35% interest. In April 2009, the California Public
Utilities Commission (CPUC) approved the amended power purchase
agreement between Pacific Gas & Electric Company (PG&E) and
Russell City Energy Company, LLC, under which PG&E will take
100% of the plant�s generation for 10 years. All permits for the
projects have been issued and approved with the exception of a
certain air permit pending before the local air quality board.
Completion of the Russell City development project is dependent
upon obtaining the necessary permits, construction contracts and
construction funding under project financing facilities.
OPERATIONS
UPDATE
Power Operations Achievements: During the first quarter 2009,
our plants continued to demonstrate operational excellence on
several fronts:
- Safety: Delivered top-quartile
safety performance, achieving a fleet-wide lost time incident rate
of 0.19.
- Availability: Improved
fleet-wide availability to 91% during the first quarter 2009,
compared to 86% in the first quarter 2008.
- Geothermal Generation: Provided
over 1.5 million MWh of renewable baseload generation with a forced
outage factor of 0.25%.
- Natural Gas Generation: Improved
gas fleet forced outage factor by 63% compared to the first quarter
of 2008.
Commercial Operations Achievements: Our commercial operations
group continued to add value to our business during the first
quarter of 2009, as demonstrated by:
- Effective Hedging: Achieved
attractive hedged spark spreads for the quarter during difficult
market conditions, providing near-term stability to Adjusted EBITDA
and allowing us to outperform the prior year period despite lower
revenues and lower generation volume.
- Reduced Risk: Excellent
execution by commercial operations, coupled with management�s
conservative strategy, allowed us to significantly reduce covenant
risk associated with forward gas price exposure during the
recessionary environment.
- Disciplined Growth: Received
CPUC approval for Russell City power purchase agreement. Announced
turbine upgrade program, which will allow us to add incremental
capacity at certain of our plants while improving efficiency.
- Liquidity Management: Increased
usage of first lien program by approximately 350% since September
2008.
OUTLOOK FOR 2009
� � �
Table 4: Adjusted EBITDA and Adjusted Free Cash Flow
Guidance for 2009 �
Full Year 2009 Recurring
(in millions) Adjusted EBITDA $ 1,600 � 1,700 Less:
Operating lease payments 50 $ 50 Major maintenance expense and
capital expenditures(1) 350 ~300 Cash interest, net 755 750 Cash
taxes 5 10 Working capital and other adjustments(2) � 40 � Adjusted
Free Cash Flow $ 400 � 500 � (1) Includes Major Maintenance Expense
of $205 million and Capital Expenditures of $145 million in 2009.
Capital expenditures exclude major construction and development
projects. (2) Excludes changes in cash collateral for commodity
procurement and risk management activities.
We are reaffirming our 2009 Adjusted EBITDA guidance of $1.6 to
$1.7 billion and our 2009 Adjusted Free Cash Flow guidance of $400
to $500 million.
INVESTOR CONFERENCE CALL AND
WEBCAST
We will host a conference call to discuss our financial and
operating results for the first quarter 2009, on Friday, May 8,
2009, at 8:00 a.m. ET / 7:00 a.m. CT. A listen-only webcast of the
call may be accessed through our web site at www.calpine.com, or by
dialing 888-765-5547 (or 913-312-0646 for international listeners)
at least 10 minutes prior to the beginning of the call. An archived
recording of the call will be made available for a limited time on
the web site. It also can be accessed by dialing 888-203-1112 or
719-457-0820 (International) and providing Confirmation Code
3407359. In addition, presentation materials to accompany the
conference call will be made available on our web site on May 8,
2009.
ABOUT CALPINE
Calpine Corporation is helping meet the needs of an economy that
demands more and cleaner sources of electricity. Founded in 1984,
Calpine is a major U.S. power company, currently capable of
delivering over 24,000 megawatts of clean, cost-effective, reliable
and fuel-efficient power to customers and communities in 16 states
in the United States and Canada. Calpine owns, leases, and operates
low-carbon, natural gas-fired, and renewable geothermal power
plants. Using advanced technologies, Calpine generates power in a
reliable and environmentally responsible manner for the customers
and communities it serves. Please visit www.calpine.com for more
information.
Calpine�s Quarterly Report on Form 10-Q for the period ended
March 31, 2009, has been filed with the Securities and Exchange
Commission (SEC) and may be found on the SEC�s web site at
www.sec.gov.
FORWARD-LOOKING
INFORMATION
In addition to historical information, this Report contains
forward-looking statements within the meaning of Section 27A of the
Securities Act and Section 21E of the Exchange Act. We use words
such as �believe,� �intend,� �expect,� �anticipate,� �plan,� �may,�
�will� and similar expressions to identify forward-looking
statements. Such statements include, among others, those concerning
our expected financial performance and strategic and operational
plans, as well as all assumptions, expectations, predictions,
intentions or beliefs about future events. You are cautioned that
any such forward-looking statements are not guarantees of future
performance and that a number of risks and uncertainties could
cause actual results to differ materially from those anticipated in
the forward-looking statements. Such risks and uncertainties
include, but are not limited to:
- The uncertain length and
severity of the current general financial and economic downturn and
its impacts on our business including demand for our power and
steam products, the ability of our counterparties to perform under
their contracts with us and the cost and availability of capital
and credit;
- Fluctuations in prices for
commodities such as natural gas and power;
- The effects of fluctuations in
liquidity and volatility in the energy commodities markets
including our ability to hedge risks;
- The ability of our customers,
suppliers, service providers and other contractual counterparties
to perform under their contracts with us;
- Our ability to manage our
significant liquidity needs and to comply with covenants under our
Exit Credit Facility and other existing financing obligations;
- Financial results that may be
volatile and may not reflect historical trends due to, among other
things, general economic and market conditions outside of our
control, the ability of our counterparties to perform their
contracts with us and the effects of our Chapter 11
reorganization;
- Our ability to attract and
retain customers and counterparties, including suppliers and
service providers, and to manage our customer and counterparty
exposure and credit risk, including our commodity positions;
- Competition, including risks
associated with marketing and selling power in the evolving energy
markets;
- Regulation in the markets in
which we participate and our ability to effectively respond to
changes in laws and regulations or the interpretation thereof
including changing market rules and evolving federal, state and
regions laws and regulations including those related to GHG
emissions;
- Natural disasters such as
hurricanes, earthquakes and floods that may impact our power plants
or the markets our power plants serve;
- Seasonal fluctuations of our
results and exposure to variations in weather patterns;
- Disruptions in or limitations on
the transportation of natural gas and transmission of power;
- Our ability to attract, retain
and motivate key employees;
- Our ability to implement our new
business plan and strategy;
- Risks related to our geothermal
resources, including the adequacy of our steam reserves, unusual or
unexpected steam field well and pipeline maintenance requirements
and variables associated with the injection of waste water to the
steam reservoir;
- Present and possible future
claims, litigation and enforcement actions, including our ability
to complete the implementation of our Plan of Reorganization;
- The expiration or termination of
our PPAs and the related results on revenues; and
- Risks associated with the
operation, construction and development of power plants including
unscheduled outages or delays and plant efficiencies;
- Other risks identified in this
release or in our reports and registration statements filed with
the SEC, including, without limitation, the risk factors identified
in our Quarterly Report on Form 10-Q for the three months ended
March 31, 2009 and in our Annual Report on Form 10-K for the year
ended December 31, 2008.
Actual results or developments may differ materially from the
expectations expressed or implied in the forward-looking
statements, and we undertake no obligation to update any
forward-looking statements, whether as a result of new information,
future developments or otherwise. Unless specified otherwise, all
information set forth in this release is as of today�s date, and we
undertake no duty to update this information. For additional
information about our general business operations, please refer to
our Annual Report on Form 10-K for the fiscal year ended December
31, 2008 and any other recent report we have filed with the
Securities and Exchange Commission. These filings are available by
visiting the Securities and Exchange Commission�s web site at
www.sec.gov or our web site at www.calpine.com.
CALPINE CORPORATION AND SUBSIDIARIES � �
CONSOLIDATED
CONDENSED BALANCE SHEETS (Unaudited) �
March 31,
December 31, 2009 2008
(in millions,
exceptshare and per share amounts)
ASSETS Current assets: Cash and cash equivalents $ 1,626 $
1,657 Accounts receivable, net of allowance of $40 and $37 656 850
Inventory 166 163 Margin deposits and other prepaid expense 474 776
Restricted cash, current 421 337 Current derivative assets 4,614
3,653 Other current assets � 65 � � 64 � Total current assets 8,022
7,500 � Property, plant and equipment, net 11,849 11,908 Restricted
cash, net of current portion 55 166 Investments 163 144 Long-term
derivative assets 602 404 Other assets � 598 � � 616 � Total assets
$ 21,289 � $ 20,738 �
LIABILITIES & STOCKHOLDERS� EQUITY
Current liabilities: Accounts payable $ 442 $ 574 Accrued interest
payable 48 85 Debt, current portion 740 716 Current derivative
liabilities 4,436 3,799 Income taxes payable 9 5 Other current
liabilities � 259 � � 437 � Total current liabilities 5,934 5,616 �
Debt, net of current portion 9,735 9,756 Deferred income taxes, net
of current portion 89 93 Long-term derivative liabilities 766 698
Other long-term liabilities � 206 � � 203 � Total liabilities
16,730 16,366 � Commitments and contingencies Stockholders� equity:
Preferred stock, $.001 par value per share; 100,000,000 shares
authorized; none issued and outstanding at March 31, 2009 and
December 31, 2008 � � Common stock, $.001 par value per share;
1,400,000,000 shares authorized; 429,111,851 shares issued and
428,812,216 shares outstanding at March 31, 2009; 429,025,057
shares issued and 428,960,025 shares outstanding at December 31,
2008 1 1 Treasury stock, at cost, 299,635 shares at March 31, 2009
and 65,032 shares at December 31, 2008 (3 ) (1 ) Additional paid-in
capital 12,229 12,217 Accumulated deficit (7,657 ) (7,689 )
Accumulated other comprehensive loss � (12 ) � (158 ) Total Calpine
stockholders� equity 4,558 4,370 Noncontrolling interest � 1 � � 2
� Total stockholders� equity � 4,559 � � 4,372 � Total liabilities
and stockholders� equity $ 21,289 � $ 20,738 � �
CALPINE
CORPORATION AND SUBSIDIARIES �
CONSOLIDATED CONDENSED
STATEMENTS OF OPERATIONS (Unaudited) �
Three Months
Ended March 31, 2009 �
2008
(in millions, except share
andper share amounts)
Operating revenues $ 1,677 $ 1,951 � Cost of revenue: Fuel and
purchased energy expense 1,015 1,605 Plant operating expense 248
232 Depreciation and amortization expense 109 111 Other cost of
revenue � 23 � � 32 � Total cost of revenue � 1,395 � � 1,980 �
Gross profit (loss) 282 (29 ) Sales, general and other
administrative expense 45 48 (Income) loss from unconsolidated
investments in power plants (17 ) 3 Other operating expense � 3 � �
2 � Income (loss) from operations 251 (82 ) Interest expense 210
419 Interest (income) (6 ) (13 ) Other (income) expense, net � 4 �
� 10 � Income (loss) before reorganization items and income taxes
43 (498 ) Reorganization items � 3 � � (279 ) Income (loss) before
income taxes 40 (219 ) Income tax expense (benefit) � 9 � � (5 )
Net income (loss) 31 (214 ) Add: Net loss attributable to the
noncontrolling interest � 1 � � � � Net income (loss) attributable
to Calpine $ 32 � $ (214 ) � Basic earnings (loss) per common
share: Weighted average shares of common stock outstanding (in
thousands) � 485,362 � � 485,000 � Net income (loss) per common
share attributable to Calpine � basic $ 0.07 � $ (0.44 ) � Diluted
earnings (loss) per common share: Weighted average shares of common
stock outstanding (in thousands) � 485,595 � � 485,000 � Net income
(loss) per common share attributable to Calpine � diluted $ 0.07 �
$ (0.44 ) �
CALPINE CORPORATION AND
SUBSIDIARIES
CONSOLIDATED CONDENSED
STATEMENTS OF CASH FLOWS
(Unaudited)
�
Three Months Ended March 31, 2009 �
2008
(in millions) Cash flows from operating activities: Net
income (loss) $ 31 $ (214 ) Adjustments to reconcile net income
(loss) to net cash provided by (used in) operating activities:
Depreciation and amortization expense(1) 132 155 Deferred income
taxes 10 64 Loss on sale of assets, excluding reorganization items
10 � Mark-to-market activities, net (126 ) 203 (Income) loss from
unconsolidated investments in power plants (17 ) 3 Stock-based
compensation expense 13 6 Reorganization items � (325 ) Other 5 5
Change in operating assets and liabilities: Accounts receivable 194
255 Derivative instruments (114 ) (111
)
Other assets 300 (78 ) Accounts payable, LSTC and accrued expenses
(200 ) (21 ) Other liabilities � (158 ) � (282 ) Net cash provided
by (used in) operating activities � 80 � � (340 ) Cash flows from
investing activities: Purchases of property, plant and equipment
(51 ) (56 ) Disposals of property, plant and equipment � 4 Proceeds
from sale of power plants, turbines and investments � 398 Cash
acquired due to reconsolidation of Canadian Debtors and other
foreign entities � 64 Contributions to unconsolidated investments
(4 ) � Return of investment from unconsolidated investments � 24
Decrease in restricted cash 27 43 Other � 1 � � 6 � Net cash
provided by (used in) investing activities � (27 ) � 483 � Cash
flows from financing activities: Repayments of notes payable $ (54
) $ (49
)
Borrowings from notes payable � 5 Repayments of project financing
(50 ) (122
)
Borrowings from project financing 64 90 Repayments of DIP Facility
� (98
)
Borrowings under Exit Credit Facility � 2,723 Repayments on Exit
Credit Facility (15 ) (455
)
Repayments on Second Priority Debt � (3,672
)
Repayments on capital leases (22 ) (18 ) Redemptions of preferred
interests (4 ) (5 ) Financing costs � (175
)
Other � (3 ) � (1 ) Net cash used in financing activities (84 )
(1,777 ) Net decrease in cash and cash equivalents (31 ) (1,634 )
Cash and cash equivalents, beginning of period � 1,657 � � 1,915 �
Cash and cash equivalents, end of period $ 1,626 � $ 281 � Cash
paid (received) during the period for: Interest, net of amounts
capitalized $ 226 $ 470 Income taxes $ � $ 7 Reorganization items
included in operating activities, net $ 3 $ 67 Reorganization items
included in investing activities, net $ � $ (414 ) �
Supplemental disclosure of
non-cash investing and financing activities:
Settlement of commodity contract with project financing $ 79 $ �
Increase in deferred finance costs with project financing $ 7 $ �
Capital expenditures in accounts payable $ 10 $ 11 Settlement of
LSTC through issuance of reorganized Calpine Corporation common
stock $ � $ 5,200 DIP Facility borrowings converted into exit
financing under Exit Facilities $ � $ 3,872 Settlement of
Convertible Senior Notes and Unsecured Senior Notes with
reorganized Calpine Corporation common stock $ � $ 3,703 (1)
Includes depreciation and amortization that is also recorded in
sales, general and other administrative expense and interest
expense on our Consolidated Condensed Statements of Operations.
REGULATION G RECONCILIATIONS
Commodity Margin, Adjusted EBITDA and Adjusted Free Cash Flow
are non-GAAP financial measures that we use as measures of our
performance. These measures should not be viewed as alternatives to
GAAP measures of performance.
Commodity Margin includes our power and steam revenues, REC
revenue, transmission revenue and expenses, fuel and purchased
energy expense, and cash settlements from our marketing, hedging
and optimization activities that are included in mark-to-market
activity, but excludes the unrealized portion of our mark-to-market
activity and other revenue. Commodity Margin is presented because
we believe it is a useful tool for assessing the performance of our
core operations, and it is a key operational measure reviewed by
our chief operating decision maker. Commodity Margin does not
intend to represent gross profit (loss), the most comparable GAAP
measure, as an indicator of operating performance and is not
necessarily comparable to similarly-titled measures reported by
other companies.
Adjusted EBITDA represents net income 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. Adjusted EBITDA is not intended to represent cash
flows from operations or net income (loss) as defined by GAAP as an
indicator of operating performance. Furthermore, Adjusted EBITDA is
not necessarily comparable to similarly-titled measures reported by
other companies.
Adjusted Free Cash Flow represents net income before interest,
taxes, depreciation and amortization, as adjusted, less operating
lease payments, major maintenance expense and maintenance capital
expenditures, net cash interest, cash taxes, working capital and
other adjustments. Adjusted Free Cash Flow is presented because our
management uses this measure, among others, to make decisions about
capital allocation. Adjusted Free Cash Flow is not intended to
represent cash flows from operations as defined by GAAP as an
indicator of operating performance and is not necessarily
comparable to similarly-titled measures reported by other
companies.
Commodity Margin Reconciliation
The following table reconciles our Commodity Margin to its GAAP
results for the three months ended March 31, 2009 and 2008:
�
Three Months Ended March 31, 2009
(in millions)
� � � � � � �
Consolidation �
And West
Texas Southeast North Elimination
Total Commodity Margin $ 297 $ 122 $ 61 $ 49 $ � $ 529
Add: Mark-to-market commodity
activity, net andother revenue(1)
22 90 31 4 (14 ) 133 Less: Plant operating expense 127 78 32 20 (9
) 248 Depreciation and amortization expense 49 30 16 16 (2 ) 109
Other cost of revenue � 15 � 3 � 3 � 8 � (6 ) � 23 Gross profit $
128 $ 101 $ 41 $ 9 $ 3 � $ 282 � �
Three Months Ended March 31,
2008
(in millions)
� � � �
Consolidation �
And West Texas
Southeast North Elimination Total
Commodity Margin $ 278 $ 139 $ 35 $ 61 $ � $ 513
Add: Mark-to-market commodity
activity, net andother revenue(1)
(49 ) (125 ) (13 ) 23 (3 ) (167 ) Less: Plant operating expense 112
70 30 26 (6 ) 232 Depreciation and amortization expense 51 30 19 12
(1 ) 111 Other cost of revenue � 17 � � � � � 9 � � 6 � � � � 32 �
Gross profit (loss) $ 49 � $ (86 ) $ (36 ) $ 40 $ 4 � $ (29 ) � (1)
Mark-to-market commodity activity represents the unrealized portion
of our mark-to-market activity, net, as well as a non-cash gain
from amortization of prepaid power sales agreements included in
operating revenues and fuel and purchased energy expense on our
Consolidated Condensed Statements of Operations. �
Consolidated Adjusted EBITDA Reconciliation
The table below provides a reconciliation of Adjusted EBITDA to
our GAAP net income (loss) for the three months ended March 31,
2009 and 2008.
�
(Unaudited) Three Months Ended March 31,
2009
2008(1)
(in millions) GAAP net income (loss) $ 31 $ (214 ) Add:
Adjustments to reconcile GAAP net income (loss) to Adjusted EBITDA:
Interest expense, net of interest income 204 406 Depreciation and
amortization expense, excluding deferred financing costs(2) 113 122
Income tax expense (benefit) 9 (5 ) Reorganization items 3 (279 )
Major maintenance expense 62 54 Operating lease expense 12 12
Non-cash gains on derivatives(3) � (9 ) Unrealized (gains) losses
on commodity derivative mark-to-market activity (125 ) 187
Adjustments to reflect Adjusted EBITDA from unconsolidated
investments(4)(5) (2 ) 7 Stock-based compensation expense 13 6
Non-cash loss on dispositions of assets 8 6 Non-cash loss on
repurchase or extinguishment of debt � 7 Other(6) � 3 � 1 �
Adjusted EBITDA $ 331 $ 301 � � (1) Adjusted EBITDA for the three
months ended March 31, 2008, has been recast to conform to our
current year presentation. (2) Depreciation and amortization
expense in the GAAP net income (loss) calculation on our
Consolidated Condensed Statements of Operations excludes
amortization of other assets and amounts classified as sales,
general and other administrative expenses. (3) Includes realized
non-cash gains on derivatives that do not qualify for hedge
accounting. (4) Recorded on our Consolidated Condensed Statements
of Operations in (income) loss from unconsolidated investments in
power plants. (5) Adjustments to reflect Adjusted EBITDA from
unconsolidated investments include $(8) million and $1 million in
unrealized (gains) losses on mark-to-market activity for the three
months ended March 31, 2009 and 2008, respectively. (6) Other
includes foreign currency translation gains or losses, fees
associated with issuance of letters of credit and other items.
Adjusted EBITDA and Adjusted
Free Cash Flow Reconciliation for 2009 Guidance
� � �
Full Year 2009 Range: Low High
Recurring (in millions) GAAP Net Income $ 160 $ 260 Plus:
Interest expense, net of interest income 765 765 Depreciation and
amortization expense 475 475 Major maintenance expense 205 205
Operating lease expense 50 50 Other(1) � (55 ) � (55 ) Adjusted
EBITDA $ 1,600 $ 1,700 Less: Operating lease payments 50 50 $ 50
Major maintenance expense and maintenance capital expenditures(2)
350 350 ~300 Cash interest, net 755 755 750 Cash taxes 5 5 10
Working capital and other adjustments � 40 � � 40 � � Adjusted Free
Cash Flow $ 400 � $ 500 � � (1) Other includes stock-based
compensation expense and other adjustments. (2) Includes major
maintenance expense of $205 million and capital expenditures of
$145 million. Capital expenditures exclude major construction and
development projects funded with debt.
CASH FLOW ACTIVITIES
�
The following table summarizes our
cash flow activities for the three months ended March 31, 2009 and
2008:
� �
(Unaudited) Three Months Ended March 31,
2009 �
2008 (in millions) Beginning cash and
cash equivalents $ 1,657 � $ 1,915 � Net cash provided by (used
in): Operating activities 80 (340 ) Investing activities (27 ) 483
Financing activities � (84 ) � (1,777 ) Net decrease increase in
cash and cash equivalents � (31 ) � (1,634 ) Ending cash and cash
equivalents $ 1,626 � $ 281 �
OPERATING PERFORMANCE
METRICS
�
The table below shows the
operating performance metrics for continuing operations:
� �
Three Months Ended March 31, 2009 2008
Total MWh generated(1) (in thousands) 19,267 20,906 West 8,937
9,157 Texas 5,207 7,741 Southeast 3,879 2,670 North 1,244 1,338 �
Average availability 90.9 % 85.8 % West 90.4 % 83.3 % Texas 88.3 %
82.0 % Southeast 94.0 % 91.0 % North 92.0 % 92.0 % � Average
capacity factor, excluding peakers 43.2 % 46.2 % West 65.2 % 66.4 %
Texas 33.2 % 48.9 % Southeast 34.4 % 22.6 % North 31.8 % 34.3 % �
Steam adjusted Heat Rate 7,188 7,161 West 7,213 7,228 Texas 7,019
6,951 Southeast 7,228 7,461 North 7,634 7,419 (1) � MWh generated
is shown here as our net operating interest. Excludes Auburndale
Power Plant�s 186,393 MWh generation for 2008.
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