Calpine Corporation (NYSE: CPN):
Summary of Second Quarter 2015 Financial Results (in
millions, except per share amounts):
Three Months Ended June 30, Six Months
Ended June 30, 2015 2014 %
Change 2015 2014 % Change
Operating Revenues $ 1,442 $ 1,939 (25.6 )% $ 3,088 $ 3,904
(20.9 )% Commodity Margin $ 657 $ 632 4.0 % $ 1,192 $ 1,277 (6.7 )%
Adjusted EBITDA $ 457 $ 413 10.7 % $ 795 $ 859 (7.5 )% Adjusted
Free Cash Flow $ 144 $ 99 45.5 % $ 169 $ 229 (26.2 )% Per Share
(diluted) $ 0.39 $ 0.23 69.6
%
$ 0.45 $ 0.54 (16.7 )% Net Income1 $ 19 $ 139 $ 9 $ 122 Per Share
(diluted) $ 0.05 $ 0.33 $ 0.02 $ 0.29 Net Income (Loss), As
Adjusted2 $ 33 $ (3 ) $ (29 ) $ 53
Narrowing 2015 Full Year Guidance (in millions, except per
share amounts):
2015 Adjusted EBITDA $1,950 - 2,050 Adjusted
Free Cash Flow $840 - 940 Per Share Estimate (diluted) $2.20 - 2.50
Recent Achievements:
- Power and Commercial Operations:—
Generated a second quarter record of approximately 28 million MWh3—
Achieved low second quarter fleetwide forced outage factor: 1.9%—
Delivered strong fleetwide starting reliability: 98%— Executed 50
MW ten-year PPA with Southern California Edison from our Geysers
assets
- Capital Allocation:— Announced
accretive acquisition of leading retail provider Champion Energy
for $240 million4— Completed approximately $475 million of share
repurchases year-to-date, an incremental $239 million since last
call— Refinanced approximately $1.6 billion of First Lien Term
Loans, reducing interest expense and extending maturity
- Portfolio Management:— Commenced
commercial operation of 309 MW Garrison Energy Center in June 2015—
Commenced construction of York 2 Energy Center; commercial
operations expected during second quarter of 2017— Received FERC
approval for January 2017 sale of Osprey Energy Center
Calpine Corporation (NYSE: CPN) today reported second quarter
2015 Adjusted EBITDA of $457 million, compared to $413 million in
the prior year period, and Adjusted Free Cash Flow of $144 million,
or $0.39 per diluted share, compared to $99 million, or $0.23 per
diluted share, in the prior year period. Net Income1 for the second
quarter of 2015 was $19 million, or $0.05 per diluted share,
compared to $139 million, or $0.33 per diluted share, in the prior
year period. Net Income, As Adjusted2, for the second quarter of
2015 was $33 million compared to Net Loss, As Adjusted2, of $3
million in the prior year period. The increases in Adjusted EBITDA,
Adjusted Free Cash Flow and Net Income, As Adjusted2, were
primarily due to higher Commodity Margin driven largely by
increased generation across all segments resulting from lower
natural gas prices in the East and Texas and stronger market
conditions in the West during June, as well as higher contribution
from hedges across all of our regions.
Year-to-date 2015 Adjusted EBITDA was $795 million, compared to
$859 million in the prior year period, and Adjusted Free Cash Flow
was $169 million, or $0.45 per diluted share, compared to $229
million, or $0.54 per diluted share, in the prior year period. Net
Income1 for the first half of 2015 was $9 million, or $0.02 per
diluted share, compared to $122 million, or $0.29 per diluted
share, in the prior year period. Net Loss, As Adjusted2, for the
first half of 2015 was $29 million compared to Net Income, As
Adjusted2, of $53 million in the prior year period. The decreases
in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As
Adjusted2, were primarily due to lower Commodity Margin driven
largely by a significant decrease in power and natural gas prices
in our East region in the first quarter of 2015, given the
unusually high price levels experienced during the polar vortex
events in the prior year period, as well as net portfolio changes
and lower regulatory capacity revenue in PJM.
“We are proud to report solid operational and financial results,
driven by strong execution by the Calpine team on all fronts,” said
Thad Hill, Calpine’s President and Chief Executive Officer. “For
the second consecutive quarter, we achieved record high generation
volume, reflecting the ability of our fleet to thrive in a low
natural gas price environment while more broadly highlighting the
industry shift away from traditional baseload resources and the
increasing need for our flexible natural gas fleet to help
integrate growing renewable capacity. Specifically, our Texas and
East fleets displaced uneconomic coal-fired generation, while our
California fleet demonstrated the value of dispatchable electricity
by helping maintain grid reliability during the historic
drought.
“On the strategic front, last week we announced the acquisition
of Champion Energy, the nation’s largest independent retail
electric provider, primarily concentrated in Texas and the
Mid-Atlantic. Champion represents an ideal platform to expand our
customer channels given its significant geographic overlap with
Calpine’s wholesale fleet. Champion’s award-winning customer
service mirrors Calpine’s focus on operational excellence. We
expect to close this highly accretive transaction by the fourth
quarter.
“I am also pleased to report that we remain on track to deliver
on our 2015 financial commitments to our shareholders and today are
tightening our Adjusted EBITDA and Free Cash Flow Per Share
guidance ranges while maintaining the midpoints,” added Hill.
“While commodity markets have sold off, including the Texas power
market, we remain optimistic about the next several years, given
structural improvement in capacity markets and the continuation of
the trend toward more reliance on gas-fired generation. We also
plan to continue adding value through disciplined and balanced
capital allocation and active management of our portfolio. As the
industry evolves, we are confident that the benefits of our
strategically aligned fleet will continue to generate significant
free cash flow for the foreseeable future.”
1 Reported as Net Income attributable to Calpine on our
Consolidated Condensed Statements of Operations.
2 Refer to Table 1 for further detail of Net Income (Loss), As
Adjusted.
3 Includes generation from power plants owned but not operated
by Calpine and our share of generation from unconsolidated power
plants.
4 Subject to working capital adjustments.
SUMMARY OF FINANCIAL
PERFORMANCE
Second Quarter Results
Adjusted EBITDA for the second quarter of 2015 was $457 million
compared to $413 million in the prior year period. The
year-over-year increase in Adjusted EBITDA was primarily related to
a $25 million increase in Commodity Margin, as well as a $14
million decrease in plant operating expense5. The lower plant
operating expense largely resulted from net portfolio changes. The
increase in Commodity Margin was primarily due to:
+ higher
generation across all segments driven by lower natural gas prices
in the East and Texas and stronger market conditions in June 2015
in the West resulting from warmer weather and a decrease in
hydroelectric generation in the Pacific Northwest and + higher
contribution from hedges across all of our regions, partially
offset by – the net impact of our portfolio management activities,
including the sale of six power plants with a total capacity of
3,498 MW in our East region in July 2014, the acquisition of our
Fore River Energy Center in November 2014, the commencement of
commercial operations at our Garrison Energy Center in June 2015
and the completion of the expansions of our Deer Park and Channel
Energy Centers in June 2014, and – lower regulatory capacity
revenue in PJM.
Net Income1 was $19 million for the second quarter of 2015,
compared to $139 million in the prior year period. As detailed in
Table 1, Net Income, As Adjusted2, was $33 million in the second
quarter of 2015 compared to Net Loss, As Adjusted2, of $3 million
in the prior year period. The year-over-year improvement in Net
Income, As Adjusted was driven largely by higher Commodity Margin,
as previously discussed.
Adjusted Free Cash Flow was $144 million in the second quarter
of 2015 compared to $99 million in the prior year period. Adjusted
Free Cash Flow increased during the period primarily due to the
increase in Adjusted EBITDA, as previously discussed.
Year-to-Date Results
Adjusted EBITDA for the six months ended June 30, 2015, was $795
million compared to $859 million in the prior year period. The
year-over-year decrease in Adjusted EBITDA was primarily related to
an $85 million decrease in Commodity Margin, partially offset by an
$18 million decrease in plant operating expense5. The plant
operating expense decline was largely the result of net portfolio
changes. The decrease in Commodity Margin was primarily due to:
– a significant
decrease in power and natural gas prices in our East region in the
first quarter of 2015 compared to the prior year period, given the
unusually high price levels experienced during the polar vortex
events in the first quarter of 2014 – the net impact of our
portfolio management activities, including the sale of six power
plants with a total capacity of 3,498 MW in our East region in July
2014, the acquisition of our Guadalupe and Fore River Energy
Centers in February and November 2014, respectively, the
commencement of commercial operations at our Garrison Energy Center
in June 2015 and the completion of the expansions of our Deer Park
and Channel Energy Centers in June 2014, and – lower regulatory
capacity revenue in PJM, partially offset by + higher contribution
from hedges that more than offset lower on-peak spark spreads
across all of our regions, excluding the impact of the polar vortex
events experienced during the first quarter of 2014, and + higher
generation in Texas resulting from lower natural gas prices, which
drove lower systemwide coal-fired generation during the first half
of 2015.
Net Income1 was $9 million for the six months ended June 30,
2015, compared to $122 million in the prior year period. As
detailed in Table 1, Net Loss, As Adjusted2, was $29 million in the
six months ended June 30, 2015, compared to Net Income, As
Adjusted2, of $53 million in the prior year period. The
year-over-year decline was driven largely by lower Commodity
Margin, as previously discussed.
Adjusted Free Cash Flow was $169 million for the six months
ended June 30, 2015, compared to $229 million in the prior year
period. Adjusted Free Cash Flow decreased during the period
primarily due to the decrease in Adjusted EBITDA, as previously
discussed.
5 Decrease in plant operating expense excludes changes in major
maintenance expense, stock-based compensation expense, non-cash
loss on disposition of assets and other costs. See the table titled
“Consolidated Adjusted EBITDA Reconciliation” for the actual
amounts of these items for the three months and six months ended
June 30, 2015 and 2014.
Table 1: Net Income (Loss), As Adjusted (in millions)
Three Months Ended June 30, Six Months
Ended June 30, 2015 2014 2015
2014 Net income attributable to Calpine $ 19 $ 139 $
9 $ 122 Debt modification and extinguishment costs(1) 13 — 32 1
Mark-to-market (gain) loss on derivatives(1)(2) 1 (142 ) (70
) (70 ) Net Income (Loss), As Adjusted(3) $ 33 $ (3 ) $ (29
) $ 53
__________
(1) Shown net of tax, assuming a 0% effective tax rate for these
items.
(2) In addition to changes in market value on derivatives not
designated as hedges, changes in mark-to-market (gain) loss also
includes de-designation of interest rate swap cash flow hedges and
related reclassification from AOCI into earnings, hedge
ineffectiveness and adjustments to reflect changes in credit
default risk exposure.
(3) Non-GAAP financial measure, 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 June 30, Six Months
Ended June 30, 2015 2014
Variance 2015 2014
Variance West $ 240 $ 228 $ 12 $ 458 $ 430 $ 28 Texas 170
177 (7 ) 319 298 21 East 247 227 20 415
549 (134 ) Total $ 657 $ 632 $ 25 $
1,192 $ 1,277 $ (85 )
West Region
Second Quarter: Commodity Margin in our West segment increased
by $12 million in the second quarter of 2015 compared to the prior
year period. Primary drivers were:
+ higher
contribution from hedges + increased generation due to stronger
market conditions in June 2015 driven by warmer weather and a
decrease in hydroelectric generation in the Pacific Northwest and +
higher renewable energy credit revenue associated with our Geysers
assets resulting from more favorable pricing in 2015.
Year-to-date: Commodity Margin in our West segment increased by
$28 million for the six months ended June 30, 2015, compared to the
prior year period. Primary drivers were:
+ higher
contribution from hedges and + higher renewable energy credit
revenue associated with our Geysers assets resulting from more
favorable pricing in 2015, partially offset by – lower on-peak
spark spreads resulting from lower natural gas prices.
Texas Region
Second Quarter: Commodity Margin in our Texas segment decreased
by $7 million in the second quarter of 2015 compared to the prior
year period. Primary drivers were:
– lower on-peak
spark spreads resulting from lower natural gas prices, partially
offset by + higher generation driven by lower natural gas prices
that drove lower systemwide coal-fired generation + higher
contribution from hedges and + the expansions of our Deer Park and
Channel Energy Centers, which were completed in June 2014.
Year-to-date: Commodity Margin in our Texas segment increased by
$21 million for the six months ended June 30, 2015, compared to the
prior year period. Primary drivers were:
+ the acquisition
of Guadalupe Energy Center in February 2014 and the expansions of
our Deer Park and Channel Energy Centers in June 2014 + higher
contribution from hedges and + higher generation driven by lower
natural gas prices and lower systemwide coal-fired generation,
partially offset by – lower on-peak spark spreads resulting from
lower natural gas prices.
East Region
Second Quarter: Commodity Margin in our East segment increased
by $62 million in the second quarter of 2015 compared to the prior
year period, after excluding a decrease of $42 million resulting
from the sale of six power plants with a total capacity of 3,498 MW
on July 3, 2014. Primary drivers were:
+ the acquisition
of Fore River Energy Center in November 2014 and the commencement
of commercial operations at our Garrison Energy Center in June 2015
+ higher spark spreads on our open position driven by lower natural
gas prices, which also drove higher generation, and + higher
contribution from hedges, partially offset by – lower regulatory
capacity revenues in PJM and – the retirements of Cedar, Missouri
Avenue and Middle Energy Centers in May 2015.
Year-to-date: Commodity Margin in our East segment decreased by
$53 million for the six months ended June 30, 2015, compared to the
prior year period, after excluding a decrease of $81 million
resulting from the sale of six power plants with a total capacity
of 3,498 MW on July 3, 2014. Primary drivers were:
– a significant
decrease in power and natural gas prices in our East region in the
first quarter of 2015 compared to the prior year period, given the
unusually high price levels experienced during the polar vortex
events in the first quarter of 2014 – lower regulatory capacity
revenues in PJM and – the retirements of Cedar, Missouri Avenue and
Middle Energy Centers in May 2015, partially offset by + the
acquisition of Fore River Energy Center in November 2014 and the
commencement of commercial operations at our Garrison Energy Center
in June 2015 and + higher contribution from hedges.
LIQUIDITY, CASH FLOW AND CAPITAL
RESOURCES
Table 3: Liquidity (in millions)
June 30, 2015 December 31, 2014 Cash
and cash equivalents, corporate(1) $ 345 $ 460 Cash and cash
equivalents, non-corporate 77 257 Total cash and cash
equivalents 422 717 Restricted cash 210 244 Corporate Revolving
Facility availability 1,321 1,277 CDHI letter of credit facility
availability 56 86 Total current liquidity availability $
2,009 $ 2,324
____________
(1) Includes $53 million and $47 million of margin deposits
posted with us by our counterparties at June 30, 2015, and
December 31, 2014, respectively.
Liquidity was approximately $2 billion as of June 30, 2015. Cash
and cash equivalents decreased during the first half of 2015
primarily due to the repurchases of our common stock, ongoing
investments in announced growth projects and the repurchase of a
portion of our outstanding 2023 First Lien Notes, partially offset
by the receipt of proceeds related to the issuance of our 5.5%
Senior Unsecured Notes due 2024 in February 2015.
Table 4: Cash Flow Activities (in millions)
Six Months Ended June 30, 2015
2014 Beginning cash and cash equivalents $ 717 $ 941
Net cash provided by (used in): Operating activities 19 349
Investing activities (246 ) (900 ) Financing activities (68 ) 52
Net decrease in cash and cash equivalents (295 ) (499 )
Ending cash and cash equivalents $ 422 $ 442
Cash flows provided by operating activities in the six months
ended June 30, 2015, were $19 million compared to $349 million in
the prior year period. The decrease in cash provided by operating
activities was primarily due to lower income from operations
(adjusted for non-cash items) primarily as a result of lower
Commodity Margin in our East region in the first quarter of 2015,
as previously discussed. In addition, working capital employed
related to cash used in operating activities increased during the
period primarily due to net margin requirements and greater
purchases of environmental allowances. Lastly, cash paid for
interest increased, primarily due to our refinancing activity and
the related timing of interest payments.
Cash flows used in investing activities were $246 million during
the six months ended June 30, 2015, compared to $900 million in the
prior year period. The decrease was primarily due to the $656
million purchase of our Guadalupe Energy Center in February 2014,
for which there was no corresponding activity in the first half of
2015.
Cash flows used in financing activities were $68 million during
the six months ended June 30, 2015, and were primarily related to
payments associated with the execution of our share repurchase
program, the repurchase of a portion of our 2023 First Lien Notes
and the repayment of our 2018 First Lien Term Loan. These were
partially offset by proceeds from the issuance of our 2024 Senior
Unsecured Notes and the issuance of our 2022 First Lien Term
Loan.
CAPITAL
ALLOCATION
Acquisition of Champion Energy
In July 2015, we entered into an agreement to purchase Champion
Energy for approximately $240 million, excluding working capital
adjustments. Champion Energy, a leading retail electric provider,
is expected to serve approximately 22 million MWh of commercial,
industrial and residential customer load in 2015, concentrated in
Texas, the Mid-Atlantic and the Northeast U.S. where Calpine has a
substantial power generation presence. The addition of this
well-established retail sales organization is expected to provide
us an important outlet for directly reaching a much greater portion
of the load we serve.
Share Repurchase Program
Returning capital to our shareholders by repurchasing shares of
our common stock is an integral component of our capital allocation
program. We view our stock as an attractive investment opportunity,
and we use the projected returns from share repurchases as the
benchmark against which all other investment decisions are
measured. Since 2011, we have repurchased approximately $2.8
billion of our common stock, representing approximately 28% of
shares outstanding.6
In 2015, through the issuance of this release, we have
repurchased a total of 23.3 million shares of our common stock for
approximately $475 million at an average price of $20.42 per
share.
2022 First Lien Term Loan
In May 2015, we repaid our 2018 First Lien Term Loans with the
proceeds from a newly issued 2022 First Lien Term Loan which
extended the maturity and reduced the interest rate on
approximately $1.6 billion of corporate debt.
Growth and Portfolio
Management
Texas:
Guadalupe Peaking Energy Center: In April 2015, we executed an
agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that
will facilitate the construction of a 418 MW natural gas-fired
peaking power plant to be co-located with our Guadalupe Energy
Center. Under the terms of the agreement, construction of the
Guadalupe Peaking Energy Center (“GPEC”) may commence at our
discretion, so long as the power plant reaches commercial operation
between the dates of June 1, 2017, and June 1, 2019. When the
power plant begins commercial operation, GVEC will purchase a 50%
ownership interest in GPEC. Once built, GPEC will feature two
fast-ramping combustion turbines capable of responding to peaks in
power demand. This project represents a mutually beneficial
response to our customer’s desire to have direct access to peaking
generation resources, as it leverages the benefits of our existing
site and development rights and our construction and operating
expertise, as well as our customer’s ability to fund its investment
at attractive rates, all while affording us the flexibility of
timing the plant’s construction in response to market pricing
signals.
East:
Garrison Energy Center: Garrison Energy Center commenced
commercial operations in June 2015, bringing online approximately
309 MW of combined-cycle, natural gas-fired capacity. The power
plant features one combustion turbine, one heat recovery steam
generator and one steam turbine and is expected to be dual fuel
capable by this winter. We are in the early stages of
development of a second phase of the Garrison Energy Center.
York 2 Energy Center: York 2 Energy Center is a 760 MW dual fuel
combined-cycle project that will be co-located with our York Energy
Center in Peach Bottom Township, Pennsylvania. Once complete, the
power plant will feature two combustion turbines, two heat recovery
steam generators and one steam turbine. The project’s capacity
cleared PJM’s 2017/2018 base residual auction. The project is now
under construction, and we expect commercial operations to commence
during the second quarter of 2017. PJM has completed the
feasibility study for increasing York 2 Energy Center’s planned
capacity by 70 MW, and the queue position has entered the system
impact study stage.
Mankato Power Plant Expansion: By order dated February 5,
2015, the Minnesota Public Utilities Commission concluded a
competitive resource acquisition proceeding and selected a 345 MW
expansion of our Mankato Power Plant, authorizing execution of a
20-year PPA between Calpine and Xcel Energy. The PPA was executed
in April 2015 and remains subject to approval by the North Dakota
Public Service Commission. Commercial operation of the expanded
capacity may commence as early as the summer of 2018, subject to
requisite regulatory approvals and applicable contract
conditions.
PJM and ISO-NE Development Opportunities: We are currently
evaluating opportunities to develop additional projects in the PJM
and ISO-NE market areas that feature cost advantages such as
existing infrastructure and favorable transmission queue positions.
These projects are continuing to advance entitlements (such as
permits, zoning and transmission) for their potential future
development when economical.
Osprey Energy Center: We executed an asset sale agreement during
the fourth quarter of 2014 for the sale of our Osprey Energy Center
to Duke Energy Florida, Inc. for approximately $166 million,
excluding working capital and other adjustments. In accordance with
the asset sale agreement, the sale will be consummated in January
2017 upon the conclusion of a 27-month PPA. In July 2015, the
transaction was approved by the FERC, and the Florida Public
Service Commission voted to approve the Florida Commission Hearing
Officer’s Recommended Order approving the transaction. This sale
represents a strategic disposition of a power plant in a wholesale
power market dominated by regulated utilities.
All Segments:
Turbine Modernization: We continue to move forward with our
turbine modernization program. Through June 30, 2015, we have
completed the upgrade of thirteen Siemens and eight GE turbines
totaling approximately 210 MW and have committed to upgrade three
additional turbines. In addition, we have begun a program to update
our dual-fueled turbines at certain of our power plants in our East
region.
6 Based upon 490.6 million shares outstanding as of June 30,
2011, immediately prior to announcement of our repurchase
program.
OPERATIONS UPDATE
Second Quarter 2015 Power Operations Achievements
- Safety Performance:— Maintained top
quartile7 safety metrics: 0.64 total recordable incident rate
- Availability Performance:— Achieved low
fleetwide forced outage factor: 1.9%— Delivered exceptional
fleetwide starting reliability: 98%
- Power Generation:— Seven gas-fired
plants with capacity factors greater than 70%: Channel, Hermiston,
Kennedy, Morgan, Pasadena, Pine Bluff, Russell City— Pine Bluff
Energy Center: 100% starting reliability and 0% forced outage
factor
Second Quarter 2015 Commercial Operations Achievements:
- Customer-oriented Growth:— Announced
accretive acquisition of retail electric provider Champion Energy
for $240 million,4 consistent with our stated goal of getting
closer to our end-use customers— Entered into a new ten-year PPA
with Southern California Edison for 50 MW of capacity and renewable
energy from our Geysers assets commencing in January 2018. The PPA
remains subject to approval by the CPUC.
7 According to EEI Safety Survey (2014).
2015 FINANCIAL
OUTLOOK
(in millions, except per share
amounts)
Full Year 2015 Adjusted EBITDA $ 1,950 - 2,050 Less:
Operating lease payments 35 Major maintenance expense and
maintenance capital expenditures(1) 415 Cash interest, net(2) 630
Cash taxes 25 Other 5 Adjusted Free Cash Flow $ 840 - 940
Per Share Estimate (diluted) $ 2.20 - 2.50 Debt amortization
and repayment (3) $ (460 ) Growth capital expenditures (net of debt
funding) $ (355 ) Acquisition of Champion Energy(4) $ (240 )
(1) Includes projected major maintenance expense of $250 million
and maintenance capital expenditures of $165 million in 2015.
Capital expenditures exclude major construction and development
projects.
(2) Includes commitment, letter of credit and other bank fees
from both consolidated and unconsolidated investments, net of
capitalized interest and interest income.
(3) Includes scheduled amortization of approximately $193
million, the repurchase of approximately $147 million of our 2023
First Lien Notes in February 2015 and expected exercise of 10% call
feature on 2023 First Lien Notes of approximately $120 million
(4) Subject to working capital adjustments.
As detailed above, today we are narrowing our 2015 guidance. We
expect Adjusted EBITDA of $1.95 billion to $2.05 billion, Adjusted
Free Cash Flow of $840 million to $940 million and Adjusted Free
Cash Flow Per Share of $2.20 to $2.50. We also expect to invest
$355 million in our ongoing growth-related projects during the
year, having now completed construction of our Garrison Energy
Center and commenced construction of our York 2 Energy Center.
INVESTOR CONFERENCE CALL AND
WEBCAST
We will host a conference call to discuss our financial and
operating results for the second quarter of 2015 on Thursday, July
30, 2015, at 10 a.m. Eastern time / 9 a.m. Central time. A
listen-only webcast of the call may be accessed through our website
at www.calpine.com, or by dialing
(888) 895-5271 in the U.S. or (847) 619-6547 outside the U.S. The
confirmation code is 40141927. 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 U.S. or (630) 652-3042 outside the
U.S. and providing confirmation code 40141927. Presentation
materials to accompany the conference call will be available on our
website on July 30, 2015.
ABOUT CALPINE
Calpine Corporation is America’s largest generator of
electricity from natural gas and geothermal resources. Our fleet of
83 power plants in operation or under construction represents
approximately 27,000 megawatts of generation capacity. Serving
customers in 18 states and Canada, we specialize in developing,
constructing, owning and operating natural gas-fired and renewable
geothermal power plants that use advanced technologies to generate
power in a low-carbon and environmentally responsible manner. Our
clean, efficient, modern and flexible fleet is uniquely positioned
to benefit from the secular trends affecting our industry,
including the abundant and affordable supply of clean natural gas,
stricter environmental regulation, aging power generation
infrastructure and the increasing need for dispatchable power
plants to successfully integrate intermittent renewables into the
grid. We focus on competitive wholesale power markets and advocate
for market-driven solutions that result in nondiscriminatory
forward price signals for investors. Please visit www.calpine.com to learn more about why Calpine is
a generation ahead - today.
Calpine’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2015, 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,
seasonality of demand, 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 and extent to which we hedge risks;
- Laws, regulations and market rules in
the markets in which we participate and our ability to effectively
respond to changes in laws, regulations or market rules or the
interpretation thereof including those related to the environment,
derivative transactions and market design in the regions in which
we operate;
- Our ability to manage our liquidity
needs, access the capital markets when necessary and comply with
covenants under our First Lien Notes, Senior Unsecured Notes,
Corporate Revolving Facility, First Lien Term Loans, CCFC Term
Loans and other existing financing obligations;
- Risks associated with the operation,
construction and development of power plants, including unscheduled
outages or delays and plant efficiencies;
- Risks related to our geothermal
resources, including the adequacy of our steam reserves, unusual or
unexpected steam field well and pipeline maintenance requirements,
variables associated with the injection of water 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;
- Structural changes in the supply and
demand of power, resulting from the development of new fuels or
technologies and demand-side management tools (such as distributed
generation, power storage and other technologies);
- 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, droughts 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 that may arise from
noncompliance with market rules promulgated by the SEC, CFTC, FERC
and other regulatory bodies; and
- Other risks identified in this press
release, in our 2014 Form 10-K and in other reports filed by us
with the SEC.
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 CONDENSED STATEMENTS OF OPERATIONS
(Unaudited) Three Months Ended June 30,
Six Months Ended June 30, 2015 2014
2015 2014
(in millions, except share and per
share amounts)
Operating revenues: Commodity revenue $ 1,407 $ 1,766 $ 3,045 $
3,814 Mark-to-market gain 31 169 34 83 Other revenue 4 4
9 7 Operating revenues 1,442 1,939
3,088 3,904 Operating expenses: Fuel and
purchased energy expense: Commodity expense 734 1,106 1,811 2,476
Mark-to-market (gain) loss 32 28 (35 ) 15 Fuel
and purchased energy expense 766 1,134 1,776
2,491 Plant operating expense 272 274 532 539 Depreciation
and amortization expense 160 147 318 300 Sales, general and other
administrative expense 30 38 67 71 Other operating expenses 20
21 40 43 Total operating expenses 1,248
1,614 2,733 3,444 (Income) from
unconsolidated investments in power plants (7 ) (4 ) (12 ) (13 )
Income from operations 201 329 367 473 Interest expense 158 169 312
335 Interest (income) (1 ) (2 ) (2 ) (3 ) Debt modification and
extinguishment costs 13 — 32 1 Other (income) expense, net 5
6 7 16 Income before income taxes 26 156 18
124 Income tax expense (benefit) 5 15 4 (4 )
Net income 21 141 14 128 Net income attributable to the
noncontrolling interest (2 ) (2 ) (5 ) (6 ) Net income attributable
to Calpine $ 19 $ 139 $ 9 $ 122
Basic earnings per common share attributable to Calpine: Weighted
average shares of common stock outstanding (in thousands) 366,975
416,507 369,938 418,296 Net income per
common share attributable to Calpine — basic $ 0.05 $ 0.33
$ 0.02 $ 0.29 Diluted earnings per
common share attributable to Calpine: Weighted average shares of
common stock outstanding (in thousands) 369,946 421,348
373,404 422,697 Net income per common share
attributable to Calpine — diluted $ 0.05 $ 0.33 $
0.02 $ 0.29
CALPINE CORPORATION AND
SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE
SHEETS (Unaudited) June 30,
December 31, 2015 2014 (in millions, except
share and per share amounts) ASSETS Current assets: Cash
and cash equivalents $ 422 $ 717 Accounts receivable, net of
allowance of $3 and $4 595 648 Inventories 477 447 Margin deposits
and other prepaid expense 152 148 Restricted cash, current 162 195
Derivative assets, current 1,607 2,058 Other current assets 32
7 Total current assets 3,447 4,220 Property, plant
and equipment, net 13,147 13,190 Restricted cash, net of current
portion 48 49 Investments in power plants 87 95 Long-term
derivative assets 637 439 Other assets 391 385 Total
assets $ 17,757 $ 18,378
LIABILITIES &
STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable $
443 $ 580 Accrued interest payable 133 165 Debt, current portion
198 199 Derivative liabilities, current 1,407 1,782 Other current
liabilities 355 473 Total current liabilities 2,536
3,199 Debt, net of current portion 11,493 11,083 Long-term
derivative liabilities 453 444 Other long-term liabilities 274
221 Total liabilities 14,756 14,947
Commitments and contingencies Stockholders’ equity: Preferred
stock, $0.001 par value per share; authorized 100,000,000 shares,
none issued and outstanding — — Common stock, $0.001 par value per
share; authorized 1,400,000,000 shares, 504,252,268 and 502,287,022
shares issued, respectively, and 361,150,393 and 381,921,264 shares
outstanding, respectively 1 1 Treasury stock, at cost, 143,101,875
and 120,365,758 shares, respectively (2,810 ) (2,345 ) Additional
paid-in capital 12,463 12,440 Accumulated deficit (6,531 ) (6,540 )
Accumulated other comprehensive loss (179 ) (178 ) Total Calpine
stockholders’ equity 2,944 3,378 Noncontrolling interest 57
53 Total stockholders’ equity 3,001 3,431
Total liabilities and stockholders’ equity $ 17,757 $ 18,378
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited) Six Months Ended June 30,
2015 2014 (in
millions) Cash flows from operating activities: Net income $ 14
$ 128 Adjustments to reconcile net income to net cash provided by
operating activities: Depreciation and amortization expense(1) 342
322 Deferred income taxes 3 (12 ) Mark-to-market activity, net (70
) (70 ) (Income) from unconsolidated investments in power plants
(12 ) (13 ) Return on unconsolidated investments in power plants 13
13 Stock-based compensation expense 12 22 Other 2 2 Change in
operating assets and liabilities: Accounts receivable 29 (212 )
Derivative instruments, net (36 ) (109 ) Other assets (118 ) (40 )
Accounts payable and accrued expenses (205 ) 378 Other liabilities
45 (60 ) Net cash provided by operating
activities 19 349 Cash flows from
investing activities: Purchases of property, plant and equipment
(279 ) (258 ) Purchase of Guadalupe Energy Center — (656 ) Decrease
in restricted cash 34 14 Other (1 ) — Net cash
used in investing activities (246 ) (900 ) Cash flows
from financing activities: Borrowings under CCFC Term Loans and
First Lien Term Loans
1,592
420 Repayment of CCFC Term Loans and First Lien Term Loans (1,613 )
(23 ) Borrowings under Senior Unsecured Notes 650 — Repurchase of
First Lien Notes (147 ) — Borrowings from project financing, notes
payable and other — 2 Repayments of project financing, notes
payable and other (85 ) (55 ) Financing costs (17 ) (10 ) Stock
repurchases (454 ) (297 ) Proceeds from exercises of stock options
6 15
Net cash provided by (used in) financing
activities
(68 ) 52 Net decrease in cash and cash
equivalents (295 ) (499 ) Cash and cash equivalents, beginning of
period 717 941 Cash and cash
equivalents, end of period $ 422 $ 442 Cash
paid during the period for: Interest, net of amounts capitalized $
322 $ 288 Income taxes $ 17 $ 16
Supplemental disclosure
of non-cash investing and financing activities: Change in
capital expenditures included in accounts payable $ (20 ) $ 13
Additions to property, plant and equipment
through capital lease
$ 9 $ —
__________
(1) Includes depreciation and amortization included in fuel and
purchased energy expense and interest expense on our Consolidated
Condensed Statements of Operations.
REGULATION G RECONCILIATIONS
In addition to disclosing financial results in accordance with
U.S. GAAP, the accompanying second quarter 2015 earnings release
contains non-GAAP financial measures. Net Income (Loss), As
Adjusted, Commodity Margin, Adjusted EBITDA and Adjusted Free Cash
Flow are non-GAAP financial measures that we use as measures of our
performance. These non-GAAP measures should be viewed as a
supplement to and not a substitute for our U.S. GAAP measures of
performance and the financial results calculated in accordance with
U.S. GAAP and reconciliations from these results should be
carefully evaluated.
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
mark-to-market (gain) loss on derivatives, debt modification and
extinguishment costs 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,
environmental compliance expense, and realized settlements from our
marketing, hedging, optimization and trading activities, but
excludes mark-to-market activity and other revenues. We believe
that Commodity Margin is a useful tool for assessing the
performance of our core operations and 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 net income (loss) attributable
to Calpine before net (income) loss attributable to the
noncontrolling interest, interest, taxes, depreciation and
amortization, adjusted for certain non-cash and non-recurring items
as detailed in the following reconciliation. 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.
We believe Adjusted EBITDA 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.
Additionally, we believe that investors commonly adjust EBITDA
information to eliminate the effect of restructuring and other
expenses, which vary widely from company to company and impair
comparability. As we define it, Adjusted EBITDA represents EBITDA
adjusted for the effects of impairment losses, gains or losses on
sales, dispositions or retirements of assets, any mark-to-market
gains or losses from accounting for derivatives, adjustments to
exclude the Adjusted EBITDA related to the noncontrolling interest,
stock-based compensation expense, operating lease expense, non-cash
gains and losses from foreign currency translations, major
maintenance expense, gains or losses on the repurchase,
modification or extinguishment of debt, non-cash GAAP-related
adjustments to levelize revenues from tolling agreements and any
extraordinary, unusual or non-recurring items plus adjustments to
reflect the Adjusted EBITDA from our unconsolidated investments. We
adjust for these items in our Adjusted EBITDA as our management
believes that these items would distort their ability to
efficiently view and assess our core operating trends.
In summary, 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.
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 and other
adjustments, including non-recurring items. Adjusted Free Cash Flow
is presented because we believe it is a useful tool for assessing
the financial performance of our company in the current period.
Adjusted Free Cash Flow is a performance measure and is not
intended to represent net income (loss), the most directly
comparable U.S. GAAP measure, or liquidity and is not necessarily
comparable to similarly titled measures reported by other
companies.
Commodity Margin Reconciliation
The following tables reconcile our Commodity Margin to its U.S.
GAAP results for the three months ended June 30, 2015 and 2014 (in
millions):
Three Months Ended June 30, 2015
Consolidation And West Texas
East Elimination Total Commodity Margin $ 240
$ 170 $ 247 $ — $ 657 Add: Mark-to-market commodity activity, net
and other(1) (14 ) 10 30 (7 ) 19 Less: Plant operating expense 120
82 77 (7 ) 272 Depreciation and amortization expense 65 50 45 — 160
Sales, general and other administrative expense 6 15 9 — 30 Other
operating expenses 10 2 8 — 20 (Income) from unconsolidated
investments in power plants — — (7 ) — (7 )
Income from operations $ 25 $ 31 $ 145 $ —
$ 201
Three Months Ended June 30, 2014
Consolidation And West Texas
East Elimination Total Commodity Margin(2) $
228 $ 177 $ 227 $ — $ 632 Add: Mark-to-market commodity activity,
net and other(1) 21 184 (24 ) (8 ) 173 Less: Plant operating
expense 95 83 103 (7 ) 274 Depreciation and amortization expense 58
48 40 1 147 Sales, general and other administrative expense 7 18 12
1 38 Other operating expenses 15 1 9 (4 ) 21 (Income) from
unconsolidated investments in power plants — — (4 ) —
(4 ) Income from operations $ 74 $ 211 $ 43
$ 1 $ 329
The following tables reconcile our Commodity Margin to its U.S.
GAAP results for the six months ended June 30, 2015 and 2014 (in
millions):
Six Months Ended June 30, 2015
Consolidation And West Texas
East Elimination Total Commodity Margin $ 458
$ 319 $ 415 $ — $ 1,192 Add: Mark-to-market commodity activity, net
and other(3) 105 51 (22 ) (14 ) 120 Less: Plant operating expense
226 171 149 (14 ) 532 Depreciation and amortization expense 132 99
87 — 318 Sales, general and other administrative expense 16 32 19 —
67 Other operating expenses 20 4 16 — 40 (Income) from
unconsolidated investments in power plants — — (12 )
— (12 ) Income from operations $ 169 $ 64 $
134 $ — $ 367
Six Months Ended June
30, 2014 Consolidation And West
Texas East Elimination Total Commodity
Margin(2) $ 430 $ 298 $ 549 $ — $ 1,277 Add: Mark-to-market
commodity activity, net and other(3) 50 138 (35 ) (17 ) 136 Less:
Plant operating expense 200 173 182 (16 ) 539 Depreciation and
amortization expense 118 90 91 1 300 Sales, general and other
administrative expense 17 30 24 — 71 Other operating expenses 27 3
16 (3 ) 43 (Income) from unconsolidated investments in power plants
— — (13 ) — (13 ) Income from operations $ 118
$ 140 $ 214 $ 1 $ 473
_________
(1) Includes $(18) million and $(27) million of lease
levelization and $3 million and $3 million of amortization expense
for the three months ended June 30, 2015 and 2014,
respectively.
(2) Commodity Margin related to the six power plants sold in our
East segment on July 3, 2014, was $42 million and $81 million for
the three and six months ended June 30, 2014,
respectively.
(3) Includes $(42) million and $(56) million of lease
levelization and $7 million and $7 million of amortization expense
for the six months ended June 30, 2015 and 2014,
respectively.
Consolidated Adjusted EBITDA Reconciliation
In the following table, we have reconciled our Adjusted EBITDA
and Adjusted Free Cash Flow to our net income (loss) attributable
to Calpine for the three and six months ended June 30, 2015 and
2014, as reported under U.S. GAAP (in millions):
Three Months Ended June 30, Six Months
Ended June 30, 2015 2014(6)
2015 2014(6) Net income attributable to
Calpine $ 19 $ 139 $ 9 $ 122 Net income attributable to the
noncontrolling interest 2 2 5 6 Income tax expense (benefit) 5 15 4
(4 ) Debt modification and extinguishment costs and other (income)
expense, net 18 6 39 17 Interest expense, net of interest income
157 167 310 332 Income from operations
$ 201 $ 329 $ 367 $ 473 Add: Adjustments to reconcile income from
operations to Adjusted EBITDA: Depreciation and amortization
expense, excluding deferred financing costs(1) 159 146 316 297
Major maintenance expense 90 72 168 153 Operating lease expense 8 8
17 17 Mark-to-market (gain) loss on commodity derivative activity 1
(141 ) (69 ) (68 ) Adjustments to reflect Adjusted EBITDA from
unconsolidated investments and exclude the noncontrolling
interest(2) 4 6 9 9 Stock-based compensation expense 1 12 12 22
Loss on dispositions of assets 2 1 3 1 Acquired contract
amortization 3 3 7 7 Other (12 ) (23 ) (35 ) (52 ) Total Adjusted
EBITDA $ 457 $ 413 $ 795 $ 859 Less:
Operating lease payments 8 8 17 17 Major maintenance expense and
capital expenditures(3) 136 126 279 259 Cash interest, net(4) 157
169 312 337 Cash taxes 11 8 17 14 Other 1 3 1
3 Adjusted Free Cash Flow(5) $ 144 $ 99 $ 169
$ 229 Weighted average shares of common stock
outstanding (diluted, in thousands) 369,946 421,348
373,404 422,697 Adjusted Free Cash Flow Per Share
(diluted) $ 0.39 $ 0.23 $ 0.45 $ 0.54
(1) Depreciation and amortization expense in the income from
operations calculation on our Consolidated Condensed Statements of
Operations excludes amortization of other assets.
(2) Adjustments to reflect Adjusted EBITDA from unconsolidated
investments include (gain) loss on mark-to-market activity of nil
for the three and six months ended June 30, 2015 and 2014.
(3) Includes $90 million and $169 million in major maintenance
expense for the three and six months ended June 30, 2015,
respectively, and $46 million and $110 million in maintenance
capital expenditure for the three and six months ended June 30,
2015, respectively. Includes $73 million and $156 million in major
maintenance expense for the three and six months ended June 30,
2014, respectively, and $53 million and $103 million in maintenance
capital expenditure for the three and six months ended June 30,
2014, respectively.
(4) Includes commitment, letter of credit and other bank fees
from both consolidated and unconsolidated investments, net of
capitalized interest and interest income.
(5) Excludes an increase in working capital of $165 million and
$251 million for the three and six months ended June 30, 2015,
respectively, and an increase in working capital of $36 million and
$42 million for the three and six months ended June 30, 2014,
respectively. Adjusted Free Cash Flow, as reported, excludes
changes in working capital, such that it is calculated on the same
basis as our guidance.
(6) Adjusted EBITDA related to the six power plants sold in our
East segment on July 3, 2014, was $23 million and $43 million for
the three and six months ended June 30, 2014,
respectively.
In the following table, we have reconciled our Adjusted EBITDA
to our Commodity Margin, both of which are non-GAAP measures, for
the three and six months ended June 30, 2015 and 2014.
Reconciliations for both Adjusted EBITDA and Commodity Margin to
comparable U.S. GAAP measures are provided above. Amounts below are
shown exclusive of the noncontrolling interest (in millions):
Three Months Ended June 30, Six Months
Ended June 30, 2015 2014 2015
2014 Commodity Margin $ 657 $ 632 $ 1,192 $ 1,277
Other revenue 5 4 9 7 Plant operating expense(1) (177 ) (191 ) (350
) (368 ) Sales, general and administrative expense(2) (32 ) (31 )
(62 ) (60 ) Other operating expenses(3) (11 ) (12 ) (21 ) (24 )
Adjusted EBITDA from unconsolidated investments in power plants 14
12 28 28 Other 1 (1 ) (1 ) (1 ) Adjusted EBITDA $ 457
$ 413 $ 795 $ 859
_________
(1) Shown net of major maintenance expense, stock-based
compensation expense, non-cash loss on dispositions of assets and
other costs.
(2) Shown net of stock-based compensation expense and other
costs.
(3) Shown net of operating lease expense, amortization and other
costs.
Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation
for Guidance (in millions)
Full Year 2015 Range: Low High GAAP Net
Income (1) $
298
$
398
Plus: Debt modification and extinguishment costs 32 32 Interest
expense, net of interest income 630 630 Depreciation and
amortization expense 630 630 Major maintenance expense 245 245
Operating lease expense 35 35 Other(2) 80 80 Adjusted EBITDA
$ 1,950 $ 2,050 Less: Operating lease payments 35 35 Major
maintenance expense and maintenance capital expenditures(3) 415 415
Cash interest, net(4) 630 630 Cash taxes 25 25 Other 5 5
Adjusted Free Cash Flow $ 840 $ 940
_________
(1) For purposes of Net Income guidance reconciliation,
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 $250 million
and maintenance capital expenditures of $165 million. Capital
expenditures exclude major construction and development
projects.
(4) Includes commitment, letter of credit and other bank fees
from both consolidated and unconsolidated investments, net of
capitalized interest and interest income.
OPERATING PERFORMANCE METRICS
The table below shows the operating performance metrics for the
periods presented:
Three Months Ended June 30, Six Months
Ended June 30, 2015 2014 2015
2014 Total MWh generated (in thousands)(1) 26,954
23,085 52,521 46,062 West 8,430 6,770 15,683 15,601 Texas 11,194
9,489 22,738 16,366 East 7,330 6,826 14,100 14,095 Average
availability 86.0 % 88.1 % 87.7 % 88.3 % West 82.8 % 91.6 % 85.6 %
90.3 % Texas 87.7 % 90.8 % 87.9 % 86.9 % East 87.0 % 83.6 % 89.3 %
88.0 % Average capacity factor, excluding peakers 53.4 %
41.7 % 52.7 % 42.4 % West 54.7 % 44.0 % 51.2 % 51.1 % Texas 55.8 %
48.9 % 57.0 % 44.2 % East 48.7 % 32.9 % 48.3 % 34.1 % Steam
adjusted heat rate (Btu/kWh) 7,329 7,433 7,296 7,393 West 7,325
7,377 7,314 7,301 Texas 7,078 7,282 7,087 7,227 East 7,738 7,694
7,629 7,678
________
(1) Excludes generation from unconsolidated power plants and
power plants owned but not operated by us.
View source
version on businesswire.com: http://www.businesswire.com/news/home/20150730005422/en/
Calpine CorporationMedia Relations:Brett Kerr,
713-830-8809brett.kerr@calpine.comorInvestor
Relations:Bryan Kimzey,
713-830-8777bryan.kimzey@calpine.com
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