Calpine Corporation (NYSE: CPN):
Summary of Second Quarter 2016 Financial Results (in millions, except
per share amounts):
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Three Months Ended June 30,
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Six Months Ended June 30,
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2016
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2015
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% Change
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2016
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|
2015
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% Change
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|
|
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Operating Revenues
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$
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1,164
|
|
|
$
|
1,442
|
|
|
(19.3
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)%
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|
$
|
2,779
|
|
|
$
|
3,088
|
|
|
(10.0
|
)%
|
|
Income from operations
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$
|
140
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|
|
$
|
201
|
|
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(30.3
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)%
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$
|
143
|
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$
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367
|
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(61.0
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)%
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|
Net Income (Loss)1
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$
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(29
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)
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$
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19
|
|
|
|
|
$
|
(227
|
)
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|
$
|
9
|
|
|
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|
Commodity Margin2
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|
$
|
657
|
|
|
$
|
657
|
|
|
—
|
%
|
|
$
|
1,237
|
|
|
$
|
1,192
|
|
|
3.8
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%
|
|
Adjusted EBITDA2
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|
$
|
452
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|
|
$
|
457
|
|
|
(1.1
|
)%
|
|
$
|
826
|
|
|
$
|
795
|
|
|
3.9
|
%
|
|
Adjusted Free Cash Flow2
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|
$
|
158
|
|
|
$
|
144
|
|
|
9.7
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%
|
|
$
|
260
|
|
|
$
|
169
|
|
|
53.8
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%
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|
Net Income (Loss), As Adjusted2
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$
|
22
|
|
|
$
|
33
|
|
|
|
|
$
|
(82
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)
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|
$
|
(29
|
)
|
|
|
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|
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2016 Full Year Guidance (in millions, except per share amounts):
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|
Previous Guidance
(as of April 29, 2016)
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|
Current Guidance
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|
|
|
|
|
|
|
Adjusted EBITDA2
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|
$1,800 - 1,950
|
|
$1,800 - 1,900
|
|
Adjusted Free Cash Flow2
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|
$710 - 860
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|
$710 - 810
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|
|
|
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|
Recent Achievements:
-
Power and Commercial Operations:
— Generated approximately 27
million MWh3 in the second quarter of 2016
— Achieved
top quartile4 safety metrics: 0.86 total recordable
incident rate through second quarter
— Delivered strong second
quarter fleetwide starting reliability: 97.4%
— Texas fleet set a
record for highest second quarter capacity factor of 62%
—
Northern California peaker fleet set a record for most starts in a
second quarter
— Received approval from California Public
Utilities Commission for our ten-year PPA with Southern California
Edison for 50 MW of capacity and renewable energy from our Geysers
assets commencing in January 2018
— Geysers wildfire recovery on
track for full capacity with insurance proceeds throughout the year
-
Portfolio and Balance Sheet Management:
— Announcing plan to file
with ERCOT for retirement of our 400 MW Clear Lake Power Plant no
later than summer of 2018, and possibly sooner depending on
negotiations with the facility's bilateral counterparties
—
Continued construction of our 760 MW York 2 Energy Center in PJM,
targeting COD in the third quarter of 2017
— Advanced development
of 345 MW contracted expansion of our Mankato Power Plant in
Minnesota, targeting COD by June 2019
— Successfully refinanced
approximately $1.2 billion of term loans, ensuring no corporate
maturities until 2022
Calpine Corporation (NYSE: CPN) today reported a Net Loss1 of
$29 million, or $0.08 per diluted share, for the second quarter of 2016
compared to Net Income of $19 million, or $0.05 per diluted share, in
the prior year period. Net Loss for the first half of 2016 was $227
million, or $0.64 per diluted share, compared to Net Income of $9
million, or $0.02 per diluted share, in the prior year period. The
increase in Net Loss during the second quarter and first half of 2016
was primarily due to net mark-to-market losses driven by increases in
forward power and natural gas prices.
Adjusted EBITDA2 for the second quarter was $452 million,
roughly consistent with $457 million in the prior year period. Adjusted
Free Cash Flow2 was $158 million compared to $144 million in
the prior year period. The increase in Adjusted Free Cash Flow was
primarily driven by a decrease in major maintenance expense and capital
expenditures. Net Income, As Adjusted2, for the second
quarter of 2016 was $22 million compared to $33 million in the prior
year period. The decrease in Net Income, As Adjusted, was
primarily due to a decrease in commodity revenue, net of commodity
expense, partially offset by an increase in income tax benefit
associated with an increase in pre-tax losses.
Adjusted EBITDA in the first half of 2016 was $826 million, compared to
$795 million in the prior year period, and Adjusted Free Cash Flow was
$260 million compared to $169 million in the prior year period. The
increase in Adjusted EBITDA was largely due to higher Commodity Margin2
driven primarily by a gas transportation credit and portfolio changes,
partially offset by higher plant operating expenses5, largely
driven by portfolio changes. The increase in Adjusted Free Cash Flow was
primarily driven by higher Commodity Margin, as discussed, and a
decrease in major maintenance expense and capital expenditures. Net
Loss, As Adjusted, for the first half of 2016 was $82 million compared
to $29 million in the prior year period. The increase in Net Loss, As
Adjusted, was primarily due to an increase in depreciation
and amortization expense and an increase in estimated income tax expense
in state jurisdictions where we do not have net operating losses.
“I am proud to report solid second quarter results as our business
continues to perform well on all fronts,” said Thad Hill, Calpine’s
President and Chief Executive Officer. “Supported by strong operational
performance, our second quarter Adjusted EBITDA of $452 million was in
line with last year, and we delivered 10% growth in Adjusted Free Cash
Flow. These results demonstrate the benefits of our strategic portfolio
changes, as well as the strength of our assets and our team.
“With this performance, we’ve had a very strong first half of the year,
which combined with a good hedging program, has enabled us to remain
within our original guidance range, despite weak summer liquidations.
Today, we are narrowing our guidance range for this year to $1.8 billion
to $1.9 billion of Adjusted EBITDA and $710 million to $810 million of
Adjusted Free Cash Flow.
“Longer term, our portfolio of reliable, flexible assets and, as
importantly, our people are responding to the secular trends of our
industry. Baseload resources continue to be threatened by a combination
of lower gas prices, increasingly stringent environmental regulations
and further penetration of renewables. Our flexible assets are rising to
the challenge of meeting our customers’ needs for reliable, clean energy
in an evolving landscape. In Texas, our fleet achieved a record second
quarter capacity factor, and in California, our peaker fleet set a
second quarter record for number of starts. Our assets clearly continue
to be critical for reliability of the grid. We are also taking steps to
enhance value over the long term by evolving our portfolio, leveraging
our customer relationships, actively advocating to be fairly compensated
and maintaining best-in-class operations.”
_________
1 Reported as Net Income (Loss) attributable to Calpine on our
Consolidated Condensed Statements of Operations.
2 Non-GAAP financial measure, see “Regulation G Reconciliations”
for further details.
3 Includes generation from power plants owned but not operated by
Calpine and our share of generation from unconsolidated power plants.
4 According to EEI Safety Survey (2015).
SUMMARY OF FINANCIAL PERFORMANCE
Second Quarter Results
Adjusted EBITDA for the second quarter of 2016 was $452 million, roughly
consistent with $457 million in the prior year period. Commodity Margin
was flat year over year, reflecting:
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|
|
|
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+
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|
a natural gas pipeline transportation billing credit received in the
West segment and
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|
|
|
|
|
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+
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the impact of our portfolio management activities, including a
full-quarter of energy and capacity revenue associated with the
operation of our 695 MW Granite Ridge Energy Center, which was
acquired on February 5, 2016, and two additional months of energy
and capacity revenue associated with the operation of our 309 MW
Garrison Energy Center, which commenced commercial operations in
June 2015, offset by
|
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|
|
|
|
|
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–
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the net impact of our contracts, including the expiration of a PPA
at our Pastoria Energy Center and of the Greenleaf operating lease,
partially offset by a new PPA at our Morgan Energy Center and
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|
|
|
|
|
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–
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|
lower energy margins due to a decrease in generation and lower
realized spark spreads, primarily in the West segment resulting
from an increase in hydroelectric generation in the region,
partially offset by an increase in generation in the Texas segment
driven by higher market spark spreads and lower natural gas prices.
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Adjusted Free Cash Flow was $158 million in the second quarter of 2016
compared to $144 million in the prior year period. Adjusted Free Cash
Flow increased during the period primarily due to a decrease in major
maintenance expense and capital expenditures resulting from our plant
outage schedule.
Year-to-Date Results
Adjusted EBITDA for the six months ended June 30, 2016, was $826 million
compared to $795 million in the prior year period. The year-over-year
increase in Adjusted EBITDA was primarily related to a $45 million
increase in Commodity Margin, partially offset by an $11 million
increase in plant operating expense5 that was largely driven
by portfolio changes. The increase in Commodity Margin was primarily due
to:
|
|
|
|
|
|
|
+
|
|
a natural gas pipeline transportation billing credit received in the
West segment,
|
|
|
|
|
|
|
|
+
|
|
the impact of our portfolio management activities, including
approximately five months of energy and capacity revenue
associated with both our 695 MW Granite Ridge Energy Center, which
was acquired on February 5, 2016, and our 309 MW Garrison Energy
Center, which commenced commercial operations in June 2015, and
|
|
|
|
|
|
|
|
+
|
|
higher regulatory capacity revenue primarily in PJM and ISO-NE at
our power plants that were fully operational period-over-period,
partially offset by
|
|
|
|
|
|
|
|
–
|
|
the net impact of our contracts, including the expiration of a PPA
at our Pastoria Energy Center and of the Greenleaf operating lease,
partially offset by a new PPA at our Morgan Energy Center and
|
|
|
|
|
|
|
|
–
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|
lower energy margins due to a decrease in generation and lower
realized spark spreads, primarily in the West segment resulting
from an increase in hydroelectric generation in the region,
partially offset by increased contribution from hedging activity,
including retail.
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|
|
|
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|
Adjusted Free Cash Flow was $260 million for the six months ended June
30, 2016, compared to $169 million in the prior year period. Adjusted
Free Cash Flow increased during the period primarily due to higher
Commodity Margin, as previously discussed, and a decrease in major
maintenance expense and capital expenditures.
___________
5 Increase 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 and six months ended June 30, 2016 and 2015.
REGIONAL SEGMENT REVIEW OF RESULTS
Table 1: Commodity Margin by Segment (in millions)
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|
Three Months Ended June 30,
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Six Months Ended June 30,
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2016
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|
2015
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|
Variance
|
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2016
|
|
2015
|
|
Variance
|
|
West
|
|
$
|
254
|
|
|
$
|
240
|
|
|
$
|
14
|
|
|
$
|
451
|
|
|
$
|
458
|
|
|
$
|
(7
|
)
|
|
Texas
|
|
160
|
|
|
170
|
|
|
(10
|
)
|
|
313
|
|
|
319
|
|
|
(6
|
)
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|
East
|
|
243
|
|
|
247
|
|
|
(4
|
)
|
|
473
|
|
|
415
|
|
|
58
|
|
|
Total
|
|
$
|
657
|
|
|
$
|
657
|
|
|
$
|
—
|
|
|
$
|
1,237
|
|
|
$
|
1,192
|
|
|
$
|
45
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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|
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|
West Region
Second Quarter: Commodity Margin in our West segment increased by
$14 million in the second quarter of 2016 compared to the prior year
period. Primary drivers were:
|
|
|
|
|
|
|
+
|
|
a natural gas pipeline transportation billing credit, partially
offset by
|
|
|
|
|
|
|
|
–
|
|
lower energy margins due to a decrease in generation and lower
realized spark spreads resulting from an increase in hydroelectric
generation,
|
|
|
|
|
|
|
|
–
|
|
lower realized power prices at our Geysers assets due to lower
natural gas prices,
|
|
|
|
|
|
|
|
–
|
|
the expiration of a PPA associated with our Pastoria Energy Center
in December 2015 and
|
|
|
|
|
|
|
|
–
|
|
the expiration of the operating lease related to the Greenleaf power
plants in June 2015.
|
|
|
|
|
|
|
|
|
|
|
Year-to-Date: Commodity Margin in our West segment decreased by
$7 million for the six months ended June 30, 2016, compared to the prior
year period. Primary drivers were:
|
|
|
|
|
|
|
–
|
|
lower energy margins due to a decrease in generation and lower
realized spark spreads resulting from an increase in hydroelectric
generation,
|
|
|
|
|
|
|
|
–
|
|
lower realized power prices at our Geysers assets due to lower
natural gas prices,
|
|
|
|
|
|
|
|
–
|
|
the expiration of a PPA associated with our Pastoria Energy Center
in December 2015 and
|
|
|
|
|
|
|
|
–
|
|
the expiration of the operating lease related to the Greenleaf power
plants in June 2015, partially offset by
|
|
|
|
|
|
|
|
+
|
|
a natural gas pipeline transportation billing credit.
|
|
|
|
|
|
|
|
|
|
|
Texas Region
Second Quarter: Commodity Margin in our Texas segment decreased
by $10 million in the second quarter of 2016 compared to the prior year
period. Primary drivers were:
|
|
|
|
|
|
|
–
|
|
lower contribution from wholesale hedges, partially offset by
|
|
|
|
|
|
|
|
+
|
|
higher contribution from our retail hedging activity and
|
|
|
|
|
|
|
|
+
|
|
an increase in generation driven by higher spark spreads and lower
natural gas prices.
|
|
|
|
|
|
|
|
|
|
|
Year-to-Date: Commodity Margin in our Texas segment decreased by
$6 million for the six months ended June 30, 2016, compared to the prior
year period. Primary drivers were:
|
|
|
|
|
|
|
–
|
|
lower contribution from wholesale hedges, partially offset by
|
|
|
|
|
|
|
|
+
|
|
higher contribution from our retail hedging activity.
|
|
|
|
|
|
|
|
|
|
|
East Region
Second Quarter: Commodity Margin in our East segment decreased by
$4 million in the second quarter of 2016 compared to the prior year
period. Primary drivers were:
|
|
|
|
|
|
|
–
|
|
lower market spark spreads resulting from cooler weather in April
2016 and local natural gas price differentials, partially offset by
|
|
|
|
|
|
|
|
+
|
|
a full quarter of operation of our 695 MW Granite Ridge Energy
Center, which was acquired on February 5, 2016, and two additional
months of operation of our 309 MW Garrison Energy Center, which
commenced commercial operations in June 2015,
|
|
|
|
|
|
|
|
+
|
|
higher contribution from our retail hedging activity and
|
|
|
|
|
|
|
|
+
|
|
the positive impact of a new PPA associated with our Morgan Energy
Center, which became effective in February 2016.
|
|
|
|
|
|
|
|
|
|
|
Year-to-Date: Commodity Margin in our East segment increased by
$58 million for the six months ended June 30, 2016, compared to the
prior year period. Primary drivers were:
|
|
|
|
|
|
|
+
|
|
higher contribution from hedging including retail,
|
|
|
|
|
|
|
|
+
|
|
five months of operation of both our 695 MW Granite Ridge Energy
Center, which was acquired on February 5, 2016, and our 309 MW
Garrison Energy Center, which commenced commercial operations in
June 2015,
|
|
|
|
|
|
|
|
+
|
|
the positive impact of a new PPA associated with our Morgan Energy
Center, which became effective in February 2016 and
|
|
|
|
|
|
|
|
+
|
|
higher regulatory capacity revenue in PJM and ISO-NE, partially
offset by
|
|
|
|
|
|
|
|
–
|
|
a decrease in generation at our power plants that were fully
operational period-over-period due to lower market spark spreads
primarily driven by milder weather in the first quarter of 2016.
|
|
|
|
|
|
|
|
|
|
|
LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES
Table 2: Liquidity (in millions)
|
|
|
June 30, 2016
|
|
December 31, 2015
|
|
Cash and cash equivalents, corporate(1)
|
|
$
|
138
|
|
|
$
|
850
|
|
Cash and cash equivalents, non-corporate
|
|
77
|
|
|
56
|
|
Total cash and cash equivalents(2)
|
|
215
|
|
|
906
|
|
Restricted cash
|
|
168
|
|
|
228
|
|
Corporate Revolving Facility availability(3)
|
|
1,374
|
|
|
1,184
|
|
CDHI letter of credit facility availability
|
|
39
|
|
|
59
|
|
Total current liquidity availability(4)
|
|
$
|
1,796
|
|
|
$
|
2,377
|
____________
(1) Includes $9 million and $35 million of margin deposits posted
with us by our counterparties at June 30, 2016, and December 31, 2015,
respectively.
(2) Cash and cash equivalents decreased during the six months ended
June 30, 2016, primarily resulting from the acquisition of Granite Ridge
Energy Center, payments to fund growth projects and other seasonal
variations in working capital, which cause fluctuations in our cash and
cash equivalents.
(3) On February 8, 2016, we amended our Corporate Revolving
Facility, extending the maturity by two years to June 27, 2020, and
increasing the capacity by an additional $178 million to $1,678 million
through June 27, 2018, reverting back to $1,520 million through the
maturity date. Further, we increased the letter of credit sublimit by
$250 million to $1.0 billion and extended the maturity by two years to
June 27, 2020. Our ability to use availability under our Corporate
Revolving Facility is unrestricted.
(4) Our ability to use corporate cash and cash equivalents is
unrestricted. Our $300 million CDHI letter of credit facility is
restricted to support certain obligations under PPAs, power transmission
and natural gas transportation agreements.
Liquidity was approximately $1.8 billion as of June 30, 2016. Cash and
cash equivalents decreased during the first half of 2016 primarily due
to the acquisition of Granite Ridge Energy Center, payments to fund
growth projects and other seasonal variations in working capital.
Table 3: Cash Flow Activities (in millions)
|
|
|
Six Months Ended June 30,
|
|
|
|
2016
|
|
2015
|
|
Beginning cash and cash equivalents
|
|
$
|
906
|
|
|
$
|
717
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
Operating activities
|
|
120
|
|
|
19
|
|
|
Investing activities
|
|
(676
|
)
|
|
(246
|
)
|
|
Financing activities
|
|
(135
|
)
|
|
(68
|
)
|
|
Net decrease in cash and cash equivalents
|
|
(691
|
)
|
|
(295
|
)
|
|
Ending cash and cash equivalents
|
|
$
|
215
|
|
|
$
|
422
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities was $120 million in the first half
of 2016 compared to $19 million in the prior year. The increase in cash
provided by operating activities was primarily due to an increase in
income from operations, adjusted for non-cash items, a reduction in cash
paid for interest due to our refinancing activities and a reduction in
debt modification and extinguishment payments, partially offset by an
increase in working capital largely associated with net margining
requirements.
Cash used in investing activities was $676 million in the first half of
2016 compared to $246 million in the prior year period. The increase was
primarily related to the purchase of Granite Ridge Energy Center for
$526 million, partially offset by a $56 million decrease in capital
expenditures on construction projects and outages.
Cash used in financing activities was $135 million during the first half
of 2016 and was primarily related to scheduled repayments of debt and
the repayment of our 2019 and 2020 First Lien Term Loans with the
proceeds from the issuance of our new 2023 First Lien Term Loan and 2026
First Lien Notes.
CAPITAL ALLOCATION
Our capital allocation philosophy seeks to maximize levered cash returns
to equity while maintaining a strong balance sheet. We strive to enhance
shareholder value through the combination of investing for growth at
attractive returns, managing the balance sheet through debt pay down and
returning capital to shareholders. 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. We are committed to remaining fiscally
disciplined and balanced in our capital allocation decisions.
Term Loan Refinancing
On May 31, 2016, we issued $625 million in aggregate principal amount of
5.25% senior secured notes due 2026 in a private placement. We
concurrently entered into a $562 million first lien senior secured term
loan which bears interest at LIBOR plus 3.00% per annum (with no LIBOR
floor) and matures on May 31, 2023. We used the proceeds from these
issuances to repay our 2019 and 2020 First Lien Term Loans.
Growth and Portfolio Management
East:
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
last three base residual auctions. The project is now under
construction, and we are targeting COD during the third quarter of 2017.
PJM has completed the interconnection study process for an additional 68
MW of planned capacity at the York 2 Energy Center. This incremental 68
MW of planned capacity cleared the last two base residual auctions and
we expect to receive the final air permit in the third quarter of 2016.
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
satisfied final regulatory approval requirements in March 2016.
Commercial operation of the expanded capacity is expected by June 1,
2019.
PJM and ISO-NE Development Opportunities: We continue to evaluate
development projects in the PJM and ISO-NE market areas that feature
cost-advantages, such as existing infrastructure and favorable
transmission queue positions. These projects continue to advance
entitlements (such as permits, zoning and transmission) for potential
future development when/if economic as compared to purchasing existing
power plants in the region.
Osprey Energy Center: We executed an asset sale agreement in 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, which will be consummated in January 2017
upon the conclusion of a PPA with a term of 27 months. The sale has
received FERC and state regulatory approvals and represents a strategic
disposition of a power plant in a wholesale power market dominated by
regulated utilities.
Texas:
Clear Lake Power Plant: We plan to file with ERCOT to retire our
400-MW Clear Lake Power Plant. Built in 1985, Clear Lake is an older
technology. Due to growing maintenance costs and lack of adequate
compensation in Texas, we have chosen to retire the power plant. We are
working together with the facility's bilateral counterparties to
mutually agree on a date to cease commercial operations, which will take
place no later than the summer of 2018.
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 by 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.
West:
South Point Energy Center: On April 1, 2016, we entered into an
asset sale agreement for the sale of substantially all of the assets
comprising our South Point Energy Center to Nevada Power Company d/b/a
NV Energy for approximately $76 million plus the assumption by the
purchaser of existing transmission capacity contracts with a future net
present value payment obligation of approximately $112 million,
approximately $9 million in remaining tribal lease costs and
approximately $21 million in near-term repairs, maintenance and capital
improvements to restore the power plant to full capacity. The sale is
subject to certain conditions precedent, as well as federal and state
regulatory approvals, and is expected to close no later than the first
quarter of 2017. The natural gas-fired, combined-cycle plant is located
on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and
features a summer peak capacity of 504 MW. This transaction supports our
effort to divest non-core assets outside our strategic concentration.
OPERATIONS UPDATE
Second Quarter Power Operations Achievements:
-
Safety Performance:
— Maintained top quartile4 safety
metrics: 0.86 total recordable incident rate year to date
-
Availability Performance:
— Northern California peaker fleet set
a record for most starts (232) in a second quarter
— Delivered
strong fleetwide starting reliability: 97.4%
-
Power Generation:
— Texas fleet set a second quarter generation
record of 12.6 million MWh3
— Three Texas merchant
plants achieved greater than 75% net capacity factor: Pasadena,
Freestone and Bosque
Geysers Wildfire Impact
In September 2015, a wildfire spread to our Geysers assets in Lake and
Sonoma counties, California. The wildfire affected five of our 14 power
plants in the region, which sustained damage to ancillary structures
such as cooling towers and communication/electric deliverability
infrastructure. Our Geysers assets are currently generating renewable
power for our customers at approximately 95% of the normal operating
capacity and should be restored to pre-fire levels by the end of 2016.
We believe the repair and replacement costs, as well as our net revenue
losses relating to the wildfire, will be limited to our insurance
deductibles of approximately $36 million, all of which was recognized in
2015. Any losses incurred in 2016 related to the wildfire will be
primarily offset by insurance proceeds, when such proceeds are
realizable. We record insurance proceeds in the same financial statement
line as the related loss is incurred and recorded approximately $8
million in business interruption proceeds as operating revenues during
the three and six months ended June 30, 2016. We do not anticipate the
wildfire or timing of insurance proceeds recovery to have a material
impact on our financial condition, results of operations or cash flows.
Second Quarter Commercial Operations Achievements:
-
Customer Relationships:
— Our ten-year PPA with Southern
California Edison for 50 MW of capacity and renewable energy from our
Geysers assets commencing in January 2018 was approved by the CPUC in
the second quarter of 2016.
2016 FINANCIAL OUTLOOK
(in
millions, except per share amounts)
|
|
|
|
Full Year 2016
|
|
Adjusted EBITDA
|
|
$
|
1,800 - 1,900
|
|
|
Less:
|
|
|
|
|
Operating lease payments
|
|
|
25
|
|
|
Major maintenance expense and maintenance capital expenditures(1)
|
|
|
410
|
|
|
Cash interest, net(2)
|
|
|
635
|
|
|
Cash taxes
|
|
|
15
|
|
|
Other
|
|
|
5
|
|
|
Adjusted Free Cash Flow
|
|
$
|
710 - 810
|
|
|
|
|
|
|
|
Debt amortization and repayment (3)
|
|
$
|
(435
|
)
|
|
Growth capital expenditures
|
|
$
|
(285
|
)
|
____________
(1) Includes projected major maintenance expense of $270 million
and maintenance capital expenditures of $140 million in 2016. Capital
expenditures exclude major construction and development projects.
(2) Includes commitment, letter of credit and other fees from
consolidated and unconsolidated investments, net of capitalized interest
and interest income.
(3) Includes $210 million of recurring amortization, as well as
$225 million of proceeds from our 2023 First Lien Term Loan that we
intend to use to repay project and corporate debt.
Today we are narrowing our 2016 guidance range. We expect Adjusted
EBITDA of $1.8 billion to $1.9 billion and Adjusted Free Cash Flow of
$710 million to $810 million. We expect to invest $285 million in our
growth projects throughout 2016, primarily the construction of 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 on Friday, July 29, 2016, 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 (800) 446-1671 in the U.S. or (847) 413-3362 outside the
U.S. The confirmation code is 42863696. 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 42863696. Presentation materials to
accompany the conference call will be available on our website on July
29, 2016.
ABOUT CALPINE
Calpine Corporation is America’s largest generator of electricity from
natural gas and geothermal resources. Our fleet of 84 power plants in
operation or under construction represents more than 27,000 megawatts of
generation capacity. Through wholesale power operations and our retail
business, Champion Energy, we serve customers in 21 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. Please
visit www.calpine.com
to learn more about why Calpine is a generation ahead - today, or visit www.championenergyservices.com
for details on Champion’s award-winning retail electric services.
Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30,
2016, has been filed with the Securities and Exchange Commission (SEC)
and is available 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 Senior
Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate
Revolving Facility, 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 from renewable sources of power,
interference by states in competitive power markets through subsidies
or similar support for new or existing power plants, and other 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 revenue may not occur at expected levels;
-
Natural disasters, such as hurricanes, earthquakes, droughts,
wildfires and floods, acts of terrorism or cyber-attacks that may
impact our power plants or the markets our power plants or retail
operations serve and our corporate headquarters;
-
Disruptions in or limitations on the transportation of natural gas
or fuel oil and the 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 Annual Report
on Form 10-K for the year ended December 31, 2015, in our Quarterly
Report on Form 10-Q for the three months ended June 30, 2016, 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,
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
(in millions, except share and per share amounts)
|
|
Operating revenues:
|
|
|
|
|
|
|
|
|
|
Commodity revenue
|
|
$
|
1,551
|
|
|
$
|
1,407
|
|
|
$
|
3,136
|
|
|
$
|
3,045
|
|
|
Mark-to-market gain (loss)
|
|
(391
|
)
|
|
31
|
|
|
(366
|
)
|
|
34
|
|
|
Other revenue
|
|
4
|
|
|
4
|
|
|
9
|
|
|
9
|
|
|
Operating revenues
|
|
1,164
|
|
|
1,442
|
|
|
2,779
|
|
|
3,088
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
Fuel and purchased energy expense:
|
|
|
|
|
|
|
|
|
|
Commodity expense
|
|
897
|
|
|
734
|
|
|
1,903
|
|
|
1,811
|
|
|
Mark-to-market (gain) loss
|
|
(355
|
)
|
|
32
|
|
|
(235
|
)
|
|
(35
|
)
|
|
Fuel and purchased energy expense
|
|
542
|
|
|
766
|
|
|
1,668
|
|
|
1,776
|
|
|
Plant operating expense
|
|
271
|
|
|
272
|
|
|
526
|
|
|
532
|
|
|
Depreciation and amortization expense
|
|
162
|
|
|
160
|
|
|
342
|
|
|
318
|
|
|
Sales, general and other administrative expense
|
|
35
|
|
|
30
|
|
|
73
|
|
|
67
|
|
|
Other operating expenses
|
|
17
|
|
|
20
|
|
|
37
|
|
|
40
|
|
|
Total operating expenses
|
|
1,027
|
|
|
1,248
|
|
|
2,646
|
|
|
2,733
|
|
|
(Income) from unconsolidated investments in power plants
|
|
(3
|
)
|
|
(7
|
)
|
|
(10
|
)
|
|
(12
|
)
|
|
Income from operations
|
|
140
|
|
|
201
|
|
|
143
|
|
|
367
|
|
|
Interest expense
|
|
157
|
|
|
158
|
|
|
314
|
|
|
312
|
|
|
Interest (income)
|
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
Debt modification and extinguishment costs
|
|
15
|
|
|
13
|
|
|
15
|
|
|
32
|
|
|
Other (income) expense, net
|
|
7
|
|
|
5
|
|
|
13
|
|
|
7
|
|
|
Income (loss) before income taxes
|
|
(38
|
)
|
|
26
|
|
|
(197
|
)
|
|
18
|
|
|
Income tax expense (benefit)
|
|
(14
|
)
|
|
5
|
|
|
21
|
|
|
4
|
|
|
Net income (loss)
|
|
(24
|
)
|
|
21
|
|
|
(218
|
)
|
|
14
|
|
|
Net income attributable to the noncontrolling interest
|
|
(5
|
)
|
|
(2
|
)
|
|
(9
|
)
|
|
(5
|
)
|
|
Net income (loss) attributable to Calpine
|
|
$
|
(29
|
)
|
|
$
|
19
|
|
|
$
|
(227
|
)
|
|
$
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per common share attributable to Calpine:
|
|
|
|
|
|
|
|
|
|
Weighted average shares of common stock outstanding (in thousands)
|
|
354,066
|
|
|
366,975
|
|
|
353,784
|
|
|
369,938
|
|
|
Net income (loss) per common share attributable to Calpine — basic
|
|
$
|
(0.08
|
)
|
|
$
|
0.05
|
|
|
$
|
(0.64
|
)
|
|
$
|
0.02
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per common share attributable to Calpine:
|
|
|
|
|
|
|
|
|
|
Weighted average shares of common stock outstanding (in thousands)
|
|
354,066
|
|
|
369,946
|
|
|
353,784
|
|
|
373,404
|
|
|
Net income (loss) per common share attributable to Calpine — diluted
|
|
$
|
(0.08
|
)
|
|
$
|
0.05
|
|
|
$
|
(0.64
|
)
|
|
$
|
0.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
CONDENSED BALANCE SHEETS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
December 31,
|
|
|
|
2016
|
|
2015
|
|
|
|
(in millions, except share and per share amounts)
|
|
ASSETS
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
215
|
|
|
$
|
906
|
|
|
Accounts receivable, net of allowance of $4 and $2
|
|
720
|
|
|
644
|
|
|
Inventories
|
|
522
|
|
|
475
|
|
|
Margin deposits and other prepaid expense
|
|
193
|
|
|
137
|
|
|
Restricted cash, current
|
|
148
|
|
|
216
|
|
|
Derivative assets, current
|
|
1,231
|
|
|
1,698
|
|
|
Current assets held for sale
|
|
206
|
|
|
—
|
|
|
Other current assets
|
|
53
|
|
|
19
|
|
|
Total current assets
|
|
3,288
|
|
|
4,095
|
|
|
Property, plant and equipment, net
|
|
13,341
|
|
|
13,012
|
|
|
Restricted cash, net of current portion
|
|
20
|
|
|
12
|
|
|
Investments in power plants
|
|
74
|
|
|
79
|
|
|
Long-term derivative assets
|
|
369
|
|
|
313
|
|
|
Long-term assets held for sale
|
|
—
|
|
|
130
|
|
|
Other assets
|
|
887
|
|
|
1,040
|
|
|
Total assets
|
|
$
|
17,979
|
|
|
$
|
18,681
|
|
|
LIABILITIES & STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
Accounts payable
|
|
$
|
531
|
|
|
$
|
552
|
|
|
Accrued interest payable
|
|
130
|
|
|
129
|
|
|
Debt, current portion
|
|
197
|
|
|
221
|
|
|
Derivative liabilities, current
|
|
1,360
|
|
|
1,734
|
|
|
Other current liabilities
|
|
355
|
|
|
412
|
|
|
Total current liabilities
|
|
2,573
|
|
|
3,048
|
|
|
Debt, net of current portion
|
|
11,644
|
|
|
11,716
|
|
|
Long-term derivative liabilities
|
|
512
|
|
|
473
|
|
|
Other long-term liabilities
|
|
298
|
|
|
277
|
|
|
Total liabilities
|
|
15,027
|
|
|
15,514
|
|
|
|
|
|
|
|
|
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, 359,662,911 and 356,755,747 shares issued, respectively, and
359,139,948 and 356,662,004 shares outstanding, respectively
|
|
—
|
|
|
—
|
|
|
Treasury stock, at cost, 522,963 and 93,743 shares, respectively
|
|
(7
|
)
|
|
(1
|
)
|
|
Additional paid-in capital
|
|
9,611
|
|
|
9,594
|
|
|
Accumulated deficit
|
|
(6,532
|
)
|
|
(6,305
|
)
|
|
Accumulated other comprehensive loss
|
|
(183
|
)
|
|
(179
|
)
|
|
Total Calpine stockholders’ equity
|
|
2,889
|
|
|
3,109
|
|
|
Noncontrolling interest
|
|
63
|
|
|
58
|
|
|
Total stockholders’ equity
|
|
2,952
|
|
|
3,167
|
|
|
Total liabilities and stockholders’ equity
|
|
$
|
17,979
|
|
|
$
|
18,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
(in millions)
|
|
Cash flows from operating activities:
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(218
|
)
|
|
$
|
14
|
|
|
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
|
|
|
|
|
|
Depreciation and amortization(1)
|
|
459
|
|
|
342
|
|
|
Debt extinguishment costs
|
|
15
|
|
|
—
|
|
|
Income taxes
|
|
11
|
|
|
3
|
|
|
Mark-to-market activity, net
|
|
130
|
|
|
(70
|
)
|
|
(Income) from unconsolidated investments in power plants
|
|
(10
|
)
|
|
(12
|
)
|
|
Return on unconsolidated investments in power plants
|
|
18
|
|
|
13
|
|
|
Stock-based compensation expense
|
|
17
|
|
|
12
|
|
|
Other
|
|
(1
|
)
|
|
2
|
|
|
Change in operating assets and liabilities, net of effect of
acquisition:
|
|
|
|
|
|
Accounts receivable
|
|
(78
|
)
|
|
29
|
|
|
Derivative instruments, net
|
|
(69
|
)
|
|
(36
|
)
|
|
Other assets
|
|
(116
|
)
|
|
(118
|
)
|
|
Accounts payable and accrued expenses
|
|
(90
|
)
|
|
(205
|
)
|
|
Other liabilities
|
|
52
|
|
|
45
|
|
|
Net cash provided by operating activities
|
|
120
|
|
|
19
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
Purchases of property, plant and equipment
|
|
(223
|
)
|
|
(279
|
)
|
|
Purchase of Granite Ridge Energy Center
|
|
(526
|
)
|
|
—
|
|
|
Decrease in restricted cash
|
|
60
|
|
|
34
|
|
|
Other
|
|
13
|
|
|
(1
|
)
|
|
Net cash used in investing activities
|
|
|
(676
|
)
|
|
|
(246
|
)
|
|
Cash flows from financing activities:
|
|
|
|
|
|
Borrowings under First Lien Term Loans
|
|
|
556
|
|
|
|
1,592
|
|
|
Repayment of CCFC Term Loans and First Lien Term Loans
|
|
(1,209
|
)
|
|
(1,613
|
)
|
|
Borrowings under Senior Unsecured Notes
|
|
—
|
|
|
650
|
|
|
Borrowings under First Lien Notes
|
|
625
|
|
|
—
|
|
|
Repurchase of First Lien Notes
|
|
—
|
|
|
(147
|
)
|
|
Repayments of project financing, notes payable and other
|
|
(81
|
)
|
|
(85
|
)
|
|
Financing costs
|
|
(26
|
)
|
|
(17
|
)
|
|
Stock repurchases
|
|
—
|
|
|
(454
|
)
|
|
Other
|
|
—
|
|
|
6
|
|
|
Net cash used in financing activities
|
|
(135
|
)
|
|
(68
|
)
|
|
Net decrease in cash and cash equivalents
|
|
(691
|
)
|
|
(295
|
)
|
|
Cash and cash equivalents, beginning of period
|
|
906
|
|
|
717
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
215
|
|
|
$
|
422
|
|
|
|
|
|
|
|
|
Cash paid during the period for:
|
|
|
|
|
|
Interest, net of amounts capitalized
|
|
$
|
289
|
|
|
$
|
322
|
|
|
Income taxes
|
|
$
|
8
|
|
|
$
|
17
|
|
|
|
|
|
|
|
|
Supplemental disclosure of non-cash investing and financing
activities:
|
|
|
|
|
|
Change in capital expenditures included in accounts payable
|
|
$
|
24
|
|
|
$
|
(20
|
)
|
|
Additions to property, plant and equipment through capital lease
|
|
$
|
—
|
|
|
$
|
9
|
|
__________
(1) Includes amortization recorded in Commodity revenue and
Commodity expense associated with intangible assets and amortization
recorded in interest expense associated with debt issuance costs and
discounts.
REGULATION G RECONCILIATIONS
In addition to disclosing financial results in accordance with U.S.
GAAP, the accompanying second quarter 2016 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, 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 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.
Net Income (Loss), As Adjusted Reconciliation
The following table reconciles our Net Income (Loss), As Adjusted, to
its U.S. GAAP results for the three and six months ended June 30, 2016
and 2015 (in millions):
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Net income (loss) attributable to Calpine
|
|
$
|
(29
|
)
|
|
$
|
19
|
|
|
$
|
(227
|
)
|
|
$
|
9
|
|
|
Debt modification and extinguishment costs(1)
|
|
15
|
|
|
13
|
|
|
15
|
|
|
32
|
|
|
Mark-to-market (gain) loss on derivatives(1)(2)
|
|
36
|
|
|
1
|
|
|
130
|
|
|
(70
|
)
|
|
Net Income (Loss), As Adjusted
|
|
$
|
22
|
|
|
$
|
33
|
|
|
$
|
(82
|
)
|
|
$
|
(29
|
)
|
__________
(1) Assumes 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 include
hedge ineffectiveness and adjustments to reflect changes in credit
default risk exposure.
Commodity Margin Reconciliation
The following tables reconcile our Commodity Margin to its U.S. GAAP
results for the three and six months ended June 30, 2016 and 2015 (in
millions):
|
|
|
|
|
|
|
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
Consolidation
|
|
|
|
|
|
|
|
|
|
|
|
And
|
|
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Elimination
|
|
Total
|
|
Commodity Margin
|
|
$
|
254
|
|
|
$
|
160
|
|
|
$
|
243
|
|
|
$
|
—
|
|
|
$
|
657
|
|
|
Add: Mark-to-market commodity activity, net and other(1)
|
|
(62
|
)
|
|
7
|
|
|
28
|
|
|
(8
|
)
|
|
(35
|
)
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Plant operating expense
|
|
98
|
|
|
85
|
|
|
96
|
|
|
(8
|
)
|
|
271
|
|
|
Depreciation and amortization expense
|
|
56
|
|
|
53
|
|
|
53
|
|
|
—
|
|
|
162
|
|
|
Sales, general and other administrative expense
|
|
8
|
|
|
14
|
|
|
12
|
|
|
1
|
|
|
35
|
|
|
Other operating expenses
|
|
7
|
|
|
2
|
|
|
10
|
|
|
(2
|
)
|
|
17
|
|
|
(Income) from unconsolidated investments in power plants
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|
Income from operations
|
|
$
|
23
|
|
|
$
|
13
|
|
|
$
|
103
|
|
|
$
|
1
|
|
|
$
|
140
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
Consolidation
|
|
|
|
|
|
|
|
|
|
|
|
And
|
|
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Elimination
|
|
Total
|
|
Commodity Margin
|
|
$
|
451
|
|
|
$
|
313
|
|
|
$
|
473
|
|
|
$
|
—
|
|
|
$
|
1,237
|
|
|
Add: Mark-to-market commodity activity, net and other(2)
|
|
(16
|
)
|
|
(103
|
)
|
|
7
|
|
|
(14
|
)
|
|
(126
|
)
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Plant operating expense
|
|
189
|
|
|
171
|
|
|
180
|
|
|
(14
|
)
|
|
526
|
|
|
Depreciation and amortization expense
|
|
125
|
|
|
106
|
|
|
111
|
|
|
—
|
|
|
342
|
|
|
Sales, general and other administrative expense
|
|
18
|
|
|
30
|
|
|
24
|
|
|
1
|
|
|
73
|
|
|
Other operating expenses
|
|
15
|
|
|
4
|
|
|
20
|
|
|
(2
|
)
|
|
37
|
|
|
(Income) from unconsolidated investments in power plants
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
|
Income (loss) from operations
|
|
$
|
88
|
|
|
$
|
(101
|
)
|
|
$
|
155
|
|
|
$
|
1
|
|
|
$
|
143
|
|
|
|
|
|
|
|
|
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(2)
|
|
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
|
|
_________
(1) Includes $(20) million and $(18) million of lease levelization
and $27 million and $3 million of amortization expense for the three
months ended June 30, 2016 and 2015, respectively.
(2) Includes $(42) million and $(42) million of lease levelization
and $54 million and $7 million of amortization expense for the six
months ended June 30, 2016 and 2015, 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, 2016 and 2015, as reported
under U.S. GAAP (in millions):
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Net income (loss) attributable to Calpine
|
|
$
|
(29
|
)
|
|
$
|
19
|
|
|
$
|
(227
|
)
|
|
$
|
9
|
|
|
Net income attributable to the noncontrolling interest
|
|
5
|
|
|
2
|
|
|
9
|
|
|
5
|
|
|
Income tax expense (benefit)
|
|
(14
|
)
|
|
5
|
|
|
21
|
|
|
4
|
|
|
Debt modification and extinguishment costs and other (income)
expense, net
|
|
22
|
|
|
18
|
|
|
28
|
|
|
39
|
|
|
Interest expense, net of interest income
|
|
156
|
|
|
157
|
|
|
312
|
|
|
310
|
|
|
Income from operations
|
|
$
|
140
|
|
|
$
|
201
|
|
|
$
|
143
|
|
|
$
|
367
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Adjustments to reconcile income from operations to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization expense, excluding deferred financing
costs(1)
|
|
160
|
|
|
159
|
|
|
339
|
|
|
316
|
|
|
Major maintenance expense
|
|
79
|
|
|
90
|
|
|
143
|
|
|
168
|
|
|
Operating lease expense
|
|
7
|
|
|
8
|
|
|
13
|
|
|
17
|
|
|
Mark-to-market (gain) loss on commodity derivative activity
|
|
36
|
|
|
1
|
|
|
131
|
|
|
(69
|
)
|
|
Adjustments to reflect Adjusted EBITDA from unconsolidated
investments and exclude the noncontrolling interest(2)
|
|
7
|
|
|
4
|
|
|
12
|
|
|
9
|
|
|
Stock-based compensation expense
|
|
8
|
|
|
1
|
|
|
17
|
|
|
12
|
|
|
Loss on dispositions of assets
|
|
3
|
|
|
2
|
|
|
5
|
|
|
3
|
|
|
Contract amortization
|
|
27
|
|
|
3
|
|
|
54
|
|
|
7
|
|
|
Other
|
|
(15
|
)
|
|
(12
|
)
|
|
(31
|
)
|
|
(35
|
)
|
|
Total Adjusted EBITDA
|
|
$
|
452
|
|
|
$
|
457
|
|
|
$
|
826
|
|
|
$
|
795
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
Operating lease payments
|
|
7
|
|
|
8
|
|
|
13
|
|
|
17
|
|
|
Major maintenance expense and capital expenditures(3)
|
|
122
|
|
|
136
|
|
|
227
|
|
|
279
|
|
|
Cash interest, net(4)
|
|
159
|
|
|
157
|
|
|
317
|
|
|
312
|
|
|
Cash taxes
|
|
6
|
|
|
11
|
|
|
8
|
|
|
17
|
|
|
Other
|
|
—
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
Adjusted Free Cash Flow(5)
|
|
$
|
158
|
|
|
$
|
144
|
|
|
$
|
260
|
|
|
$
|
169
|
|
_________
(1) Excludes depreciation and amortization expense attributable to
the non-controlling interest.
(2) Adjustments to reflect Adjusted EBITDA from unconsolidated
investments include (gain) loss on mark-to-market activity of nil for
each of the three and six months ended June 30, 2016 and 2015.
(3) Includes $81 million and $146 million in major maintenance
expense for the three and six months ended June 30, 2016, respectively,
and $41 million and $81 million in maintenance capital expenditures for
the three and six months ended June 30, 2016, respectively. 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 expenditures for the three and six months
ended June 30, 2015, 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 increases in working capital of $69 million and $127
million for the three and six months ended June 30, 2016, respectively,
and increases in working capital of $165 million and $251 million for
the three and six months ended June 30, 2015, respectively. Adjusted
Free Cash Flow, as reported, excludes changes in working capital, such
that it is calculated on the same basis as our guidance.
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, 2016 and 2015. 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,
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Commodity Margin
|
|
$
|
657
|
|
|
$
|
657
|
|
|
$
|
1,237
|
|
|
$
|
1,192
|
|
|
Other revenue
|
|
4
|
|
|
5
|
|
|
9
|
|
|
9
|
|
|
Plant operating expense(1)
|
|
(180
|
)
|
|
(177
|
)
|
|
(361
|
)
|
|
(350
|
)
|
|
Sales, general and administrative expense(2)
|
|
(31
|
)
|
|
(32
|
)
|
|
(64
|
)
|
|
(62
|
)
|
|
Other operating expenses(3)
|
|
(12
|
)
|
|
(11
|
)
|
|
(25
|
)
|
|
(21
|
)
|
|
Adjusted EBITDA from unconsolidated investments in power plants
|
|
15
|
|
|
14
|
|
|
31
|
|
|
28
|
|
|
Other
|
|
(1
|
)
|
|
1
|
|
|
(1
|
)
|
|
(1
|
)
|
|
Adjusted EBITDA
|
|
$
|
452
|
|
|
$
|
457
|
|
|
$
|
826
|
|
|
$
|
795
|
|
_________
(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 2016 Range:
|
|
Low
|
|
High
|
|
GAAP Net Income (1)
|
$
|
70
|
|
$
|
170
|
|
Plus:
|
|
|
|
|
|
Debt extinguishment costs
|
|
15
|
|
|
15
|
|
Interest expense, net of interest income
|
|
640
|
|
|
640
|
|
Depreciation and amortization expense
|
|
655
|
|
|
655
|
|
Major maintenance expense
|
|
265
|
|
|
265
|
|
Operating lease expense
|
|
25
|
|
|
25
|
|
Other(2)
|
|
130
|
|
|
130
|
|
Adjusted EBITDA
|
$
|
1,800
|
|
$
|
1,900
|
|
Less:
|
|
|
|
|
|
Operating lease payments
|
|
25
|
|
|
25
|
|
Major maintenance expense and maintenance capital expenditures(3)
|
|
410
|
|
|
410
|
|
Cash interest, net(4)
|
|
635
|
|
|
635
|
|
Cash taxes
|
|
15
|
|
|
15
|
|
Other
|
|
5
|
|
|
5
|
|
Adjusted Free Cash Flow
|
$
|
710
|
|
$
|
810
|
_________
(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 $270 million
and maintenance capital expenditures of $140 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,
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Total MWh generated (in thousands)(1)(2)
|
|
26,355
|
|
|
26,954
|
|
|
50,480
|
|
|
52,521
|
|
|
West
|
|
5,035
|
|
|
8,430
|
|
|
11,453
|
|
|
15,683
|
|
|
Texas
|
|
12,387
|
|
|
11,194
|
|
|
23,636
|
|
|
22,738
|
|
|
East
|
|
8,933
|
|
|
7,330
|
|
|
15,391
|
|
|
14,100
|
|
|
|
|
|
|
|
|
|
|
|
|
Average availability(2)
|
|
85.6
|
%
|
|
86.0
|
%
|
|
87.8
|
%
|
|
87.7
|
%
|
|
West
|
|
85.6
|
%
|
|
82.8
|
%
|
|
88.0
|
%
|
|
85.6
|
%
|
|
Texas
|
|
88.9
|
%
|
|
87.7
|
%
|
|
87.8
|
%
|
|
87.9
|
%
|
|
East
|
|
82.4
|
%
|
|
87.0
|
%
|
|
87.7
|
%
|
|
89.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Average capacity factor, excluding peakers
|
|
50.2
|
%
|
|
53.4
|
%
|
|
48.8
|
%
|
|
52.7
|
%
|
|
West
|
|
33.1
|
%
|
|
54.7
|
%
|
|
38.0
|
%
|
|
51.2
|
%
|
|
Texas
|
|
61.7
|
%
|
|
55.8
|
%
|
|
58.9
|
%
|
|
57.0
|
%
|
|
East
|
|
51.7
|
%
|
|
48.7
|
%
|
|
46.3
|
%
|
|
48.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Steam adjusted heat rate (Btu/kWh)(2)
|
|
7,313
|
|
|
7,329
|
|
|
7,289
|
|
|
7,296
|
|
|
West
|
|
7,316
|
|
|
7,325
|
|
|
7,324
|
|
|
7,314
|
|
|
Texas
|
|
7,138
|
|
|
7,078
|
|
|
7,095
|
|
|
7,087
|
|
|
East
|
|
7,570
|
|
|
7,738
|
|
|
7,581
|
|
|
7,629
|
|
________
(1) Excludes generation from unconsolidated power plants and power
plants owned but not operated by us.
(2) Generation, average availability and steam adjusted heat rate
exclude power plants and units that are inactive.
View source version on businesswire.com: http://www.businesswire.com/news/home/20160729005167/en/
Copyright Business Wire 2016
