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Calpine Reports Second Quarter Results, Narrows 2016 Guidance

07/29/2016

 

Summary of Second Quarter 2016 Financial Results (in millions, except per share amounts):

  Three Months Ended June 30,   Six Months Ended June 30,
2016   2015   % Change 2016   2015   % Change
 
Operating Revenues $ 1,164 $ 1,442 (19.3 )% $ 2,779 $ 3,088 (10.0 )%
Income from operations $ 140 $ 201 (30.3 )% $ 143 $ 367 (61.0 )%
Net Income (Loss)1 $ (29 ) $ 19 $ (227 ) $ 9
Commodity Margin2 $ 657 $ 657

 %

$ 1,237 $ 1,192 3.8

 %

Adjusted EBITDA2 $ 452 $ 457 (1.1 )% $ 826 $ 795 3.9

 %

Adjusted Free Cash Flow2 $ 158 $ 144 9.7

 %

$ 260 $ 169 53.8

 %

Net Income (Loss), As Adjusted2 $ 22 $ 33 $ (82 ) $ (29 )
 

2016 Full Year Guidance (in millions, except per share amounts):

  Previous Guidance

(as of April 29, 2016)

  Current Guidance
 
Adjusted EBITDA2 $1,800 - 1,950 $1,800 - 1,900
Adjusted Free Cash Flow2 $710 - 860 $710 - 810
 

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

HOUSTON--(BUSINESS WIRE)-- 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:

            +   a natural gas pipeline transportation billing credit received in the West segment and
+ 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
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

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.

 

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

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.

 

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)

  Three Months Ended June 30,   Six Months Ended June 30,
2016   2015   Variance 2016   2015   Variance
West $ 254 $ 240 $ 14 $ 451 $ 458 $ (7 )
Texas 160 170 (10 ) 313 319 (6 )
East 243   247   (4 ) 473   415   58  
Total $ 657   $ 657   $   $ 1,237   $ 1,192   $ 45  
 

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.

Source: Calpine Corporation

Calpine Corporation

Media Relations:

Brett Kerr, 713-830-8809

brett.kerr@calpine.com

or

Investor Relations:

Bryan Kimzey, 713-830-8777

bryan.kimzey@calpine.com