|
| |
| CONTACTS: | NEWS RELEASE |
| | |
| Media Relations: | Investor Relations: |
| Brett Kerr | Bryan Kimzey |
| 713-830-8809 | 713-830-8777 |
| brett.kerr@calpine.com | bryan.kimzey@calpine.com |
CALPINE REPORTS STRONG THIRD QUARTER 2013 RESULTS, PROVIDES 2014 GUIDANCE,
ANNOUNCES $1 BILLION MULTI-YEAR SHARE REPURCHASE AUTHORIZATION AND REAFFIRMS 15-20% ADJUSTED FREE CASH FLOW PER SHARE COMPOUND ANNUAL GROWTH RATE
Summary of Third Quarter 2013 Financial Results (in millions, except per share amounts):
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | % Change | | 2013 | | 2012 | | % Change |
| | | | | | | | | | | | | |
| Operating Revenues | | $ | 2,050 |
| | $ | 1,996 |
| | 2.7 | % | | $ | 4,863 |
| | $ | 4,111 |
| | 18.3 | % |
| Commodity Margin | | $ | 985 |
| | $ | 897 |
| | 9.8 | % | | $ | 1,979 |
| | $ | 2,023 |
| | (2.2 | )% |
| Adjusted EBITDA | | $ | 802 |
| | $ | 706 |
| | 13.6 | % | | $ | 1,431 |
| | $ | 1,434 |
| | (0.2 | )% |
| Adjusted Free Cash Flow | | $ | 556 |
| | $ | 463 |
| | 20.1 | % | | $ | 551 |
| | $ | 523 |
| | 5.4 | % |
Per Share (diluted) | | $ | 1.27 |
| | $ | 0.99 |
| | 28.3 | % | | $ | 1.23 |
| | $ | 1.10 |
| | 11.8 | % |
Net Income1 | | $ | 306 |
| | $ | 437 |
| |
| | $ | 111 |
| | $ | 99 |
| | |
Per Share (diluted) | | $ | 0.70 |
| | $ | 0.94 |
| |
| | $ | 0.25 |
| | $ | 0.21 |
| |
|
Net Income, As Adjusted2 | | $ | 268 |
| | $ | 215 |
| | | | $ | 165 |
| | $ | 164 |
| | |
Narrowing 2013 and Providing 2014 Full Year Guidance (in millions, except per share amounts):
|
| | | |
| | 2013 | | 2014 |
| | | | |
| Adjusted EBITDA | $1,800 - 1,825 | | $1,800 - 1,900 |
| Adjusted Free Cash Flow | $645 - 670 | | $685 - 785 |
Per Share Estimate (diluted) | $1.50 | | $1.60 - 1.80 |
Recent Achievements:
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| — | Generated over 30 million MWh3 of electricity in the third quarter of 2013 |
| |
| — | Achieved record-low year-to-date fleetwide forced outage factor: 1.5% |
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| — | Delivered record-high year-to-date fleetwide starting reliability: 98.5% |
| |
| — | Reduced year-to-date plant operating expense4 and sales, general and administrative expense5 by ~7% each |
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| — | Successfully completed construction of more than 900 MW of combined-cycle capacity in California and began servicing related contracts with Pacific Gas and Electric |
| |
| — | Entered into a new five-year PPA with Celanese Ltd for approximately 50 MW commencing in 2014 and extended existing steam agreement for ten years beyond 2016 from our Clear Lake Power Plant |
| |
| — | Entered into a 100 MW financial PPA with a counterparty in PJM that commences in November 2013 and extends through 2016 |
| |
| — | Announcing new $1 billion multi-year share repurchase authorization |
| |
| — | Separately completed approximately $92 million of interim share repurchases since last earnings announcement |
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| — | Refinanced approximately $1.6 billion of Senior Secured Notes, achieving interest savings and extending maturities |
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 2
(HOUSTON, Texas) November 7, 2013 – Calpine Corporation (NYSE: CPN) today reported third quarter 2013 Adjusted EBITDA of $802 million, compared to $706 million in the prior year period, and Adjusted Free Cash Flow of $556 million, or $1.27 per diluted share, compared to $463 million, or $0.99 per diluted share, in the prior year period. Net Income1 for the third quarter of 2013 was $306 million, or $0.70 per diluted share, compared to $437 million, or $0.94 per diluted share, in the prior year period. Net Income, As Adjusted2, for the third quarter of 2013 was $268 million compared to $215 million in the prior year period. The increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As Adjusted2, were driven primarily by higher Commodity Margin resulting from increased regulatory capacity payments, new contracts and higher contribution from hedges, partially offset by the net impact of portfolio changes.
Year-to-date 2013 Adjusted EBITDA was $1,431 million, compared to $1,434 million in the prior year period, and Adjusted Free Cash Flow was $551 million, or $1.23 per diluted share, compared to $523 million, or $1.10 per diluted share, in the prior year period. Net Income1 for the first nine months of 2013 was $111 million, or $0.25 per diluted share, compared to $99 million, or $0.21 per diluted share, in the prior year period. Net Income, As Adjusted2, for the first nine months of 2013 was $165 million compared to $164 million in the prior year period. The comparable year-to-date results reflect the favorable year-over-year third quarter performance, as previously discussed, which offset comparatively lower first half results that were primarily related to portfolio changes and milder weather.
“The Calpine team remains focused on delivering on our 2013 financial commitments to shareholders through disciplined operational and commercial performance,” said Jack Fusco, Calpine’s Chief Executive Officer. “As reflected in our strong third quarter results, our plant personnel delivered a record-low fleetwide forced outage factor and record-high starting reliability, while exercising strict cost discipline. Our commercial operations team captured value through an effective hedging program, especially in Texas during this summer’s challenging market conditions. Finally, our construction team achieved commercial operations on two new contracted plants in California in August, further contributing to the quarter’s performance.
“We also remain intently focused on enhancing shareholder value through disciplined capital allocation. We remain confident that Calpine is strategically well positioned to benefit from the favorable fundamental and secular trends in our core competitive wholesale power markets. As we have made clear in the past, our approach to capital allocation includes analyzing M&A and development opportunities and evaluating them against our fundamental view when deciding whether the optimal allocation to earn superior returns for our shareholders is through growth investments or share repurchases. Over time, we expect it will be a mix, and of course, we will continue to divest non-strategic assets opportunistically. Accordingly, during the last few months, we repurchased approximately $92 million of our shares. More significantly, today we are announcing a further $1 billion multi-year share repurchase authorization, representing approximately 11% of our current market capitalization. In executing this authorization, we will continue to evaluate share repurchase against other opportunities.
“Finally, I would like to re-emphasize an important point we made at this time last year when we introduced our Adjusted Free Cash Flow Per Share growth target. Calpine’s Adjusted Free Cash Flow is levered, both operationally and financially, such that modest increases in Adjusted EBITDA can lead to strong growth in Adjusted Free Cash Flow Per Share, hence our 15 - 20% targeted multi-year compound annual growth rate. The updated 2013 and initial 2014 guidance we are providing today reaffirms this growth and, in our view, validates the Calpine investment thesis – the combination of a technologically and geographically well-positioned fleet, operational excellence, strong commercial execution and disciplined capital allocation translate into a compelling total shareholder return value proposition.”
__________
| |
1 | Reported as net income attributable to Calpine on our Consolidated Condensed Statements of Operations. |
| |
2 | Refer to Table 1 for further detail of Net Income, As Adjusted. |
| |
3 | Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants. |
| |
4 | Decrease in plant operating expense excludes changes in major maintenance expense, stock-based compensation expense, non-cash loss on disposition of assets and other costs. See the table titled “Consolidated Adjusted EBITDA Reconciliation” for the actual amounts of these items for the three and nine months ended September 30, 2013 and 2012. |
| |
5 | Decrease in sales, general and administrative expense excludes changes in stock-based compensation expense, amortization and other items. See the table titled “Consolidated Adjusted EBITDA Reconciliation” for the actual amounts of these items for the three and nine months ended September 30, 2013 and 2012. |
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 3
SUMMARY OF FINANCIAL PERFORMANCE
Third Quarter Results
Adjusted EBITDA for the third quarter of 2013 was $802 million, compared to $706 million in the prior year period. The year-over-year increase in Adjusted EBITDA was primarily related to an $88 million increase in Commodity Margin, which was primarily due to:
| |
| + | the acquisition of Bosque Energy Center in November 2012 and the positive impact from Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, partially offset by the sale of our Broad River and Riverside Energy Centers in December 2012 |
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| + | higher regulatory capacity revenue in the North |
| |
| + | higher revenue from contracts in our West and Southeast segments that became effective in January 2013 and |
| |
| + | higher contribution from hedges, partially offset by |
| |
| – | weaker market conditions across all segments due primarily to milder weather in July and August 2013 compared to the same months in 2012. |
Net Income1 was $306 million for the third quarter of 2013, compared to $437 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $268 million in the third quarter of 2013 compared to $215 million in the prior year period. This year-over-year increase was driven largely by:
| |
| + | higher Commodity Margin, as previously discussed, and |
| |
| + | lower interest expense due to a decrease in our annual effective interest rate associated with refinancings we have completed during the year, partially offset by |
| |
| – | higher income taxes resulting primarily from an increase in various state and foreign jurisdiction income tax expense and |
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| – | higher depreciation and amortization expense due to the acquisition of Bosque Energy Center and the commencement of commercial operations at our Russell City and Los Esteros power plants in August 2013. |
Adjusted Free Cash Flow was $556 million in the third quarter of 2013 compared to $463 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to the increase in Adjusted EBITDA, as previously discussed.
Year-to-Date Results
Adjusted EBITDA for the nine months ended September 30, 2013, was $1,431 million compared to $1,434 million in the prior year period. A $44 million year-over-year decrease in Commodity Margin was largely offset by a $38 million decrease in plant operating expense4. The decrease in Commodity Margin was primarily due to:
| |
| – | the sale of Broad River and Riverside Energy Centers in December 2012, partially offset by the acquisition of Bosque Energy Center in November 2012 and the positive impact from our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013 and |
| |
| – | weaker year-to-date market conditions in our Texas, North and Southeast segments, compared to the same period in 2012, partially offset by |
| |
| + | higher regulatory capacity revenue in the North |
| |
| + | higher revenue from contracts in our West and Southeast segments that became effective in January 2013 and |
| |
| + | higher contribution from hedges. |
The offsetting decrease in plant operating expense4 was primarily due to the reversal of previously recognized regulatory fees for which we determined that we have no obligation, as well as lower equipment failure costs and other miscellaneous expenses.
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 4
Net Income1 was $111 million for the nine months ended September 30, 2013, compared to $99 million in the prior year period. As detailed in Table 1, Net Income, As Adjusted2, was $165 million in the nine months ended September 30, 2013, compared to $164 million in the prior year period. The comparable year-to-date Net Income, As Adjusted2,
reflects:
| |
| – | lower Commodity Margin, as previously discussed, and |
| |
| – | higher depreciation and amortization expense primarily due to the acquisition of Bosque Energy Center and our Russell City and Los Esteros power plants commencing commercial operations in August 2013, partially offset by |
| |
| + | lower interest expense associated with a decrease in our annual effective interest rate |
| |
| + | lower plant operating expense, as previously discussed, and |
| |
| + | lower income tax expense primarily related to the expiration of applicable statutes of limitation related to uncertain tax positions. |
Adjusted Free Cash Flow was $551 million for the nine months ended September 30, 2013, compared to $523 million in the prior year period. Adjusted Free Cash Flow increased during the period primarily due to lower interest expense, as previously discussed.
Table 1: Net Income, As Adjusted
|
| | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | 2013 | | 2012 |
| | | (in millions) | | (in millions) |
| Net income attributable to Calpine | | $ | 306 |
| | $ | 437 |
| | $ | 111 |
| | $ | 99 |
|
Debt extinguishment costs(1) | | — |
| | — |
| | 68 |
| | 12 |
|
Unrealized MtM gain on derivatives(1) (2) | | (38 | ) | | (222 | ) | | (14 | ) | | (103 | ) |
Other items (1) (3) | | — |
| | — |
| | — |
| | 156 |
|
Net Income, As Adjusted(4) | | $ | 268 |
| | $ | 215 |
| | $ | 165 |
| | $ | 164 |
|
__________
| |
| (1) | Shown net of tax, assuming a 0% effective tax rate for these items. |
| |
| (2) | In addition to changes in market value on derivatives not designated as hedges, changes in unrealized (gain) loss also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. |
| |
| (3) | Other items include realized mark-to-market losses associated with the settlement of non-hedged interest rate swaps totaling $156 million for the nine months ended September 30, 2012. |
| |
| (4) | See “Regulation G Reconciliations” for further discussion of Net Income, As Adjusted. |
REGIONAL SEGMENT REVIEW OF RESULTS
Table 2: Commodity Margin by Segment (in millions)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | Variance | | 2013 | | 2012 | | Variance |
| West | | $ | 337 |
| | $ | 330 |
| | $ | 7 |
| | $ | 737 |
| | $ | 748 |
| | $ | (11 | ) |
| Texas | | 328 |
| | 218 |
| | 110 |
| | 537 |
| | 472 |
| | 65 |
|
| North | | 242 |
| | 266 |
| | (24 | ) | | 543 |
| | 591 |
| | (48 | ) |
| Southeast | | 78 |
| | 83 |
| | (5 | ) | | 162 |
| | 212 |
| | (50 | ) |
| Total | | $ | 985 |
| | $ | 897 |
| | $ | 88 |
| | $ | 1,979 |
| | $ | 2,023 |
| | $ | (44 | ) |
West Region
Third Quarter: Commodity Margin in our West segment increased by $7 million in the third quarter of 2013 compared to the prior year period. Primary drivers were:
| |
| + | higher revenue from a tolling contract that became effective in January 2013 and |
| |
| + | our contracted Russell City and Los Esteros power plants commencing commercial operations in August 2013, partially offset by |
| |
| – | lower contribution from hedges. |
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 5
Year-to-Date: Commodity Margin in our West segment decreased by $11 million for the nine months ended September 30, 2013, compared to the prior year period. Primary drivers were:
| |
| – | lower contribution from hedges, partially offset by |
| |
| + | our contracted Russell City and Los Esteros power plants commencing commercial operations in August 2013 |
| |
| + | higher revenue from a tolling contract that became effective in January 2013 and |
| |
| + | stronger market conditions in the first half of 2013 compared to the prior year period. |
Texas Region
Third Quarter: Commodity Margin in our Texas segment increased by $110 million in the third quarter of 2013 compared to the prior year period. Primary drivers were:
| |
| + | higher contribution from hedges and |
| |
| + | the acquisition of Bosque Energy Center in November 2012, partially offset by |
| |
| – | lower spark spreads resulting from weaker market conditions. |
Year-to-Date: Commodity Margin in our Texas segment increased by $65 million for the nine months ended September 30, 2013, compared to the prior year period. The year-to-date results were largely impacted by the same factors that drove comparative performance for the third quarter, as previously discussed.
North Region
Third Quarter: Excluding a $32 million decrease from the sale of our Riverside Energy Center in December 2012, Commodity Margin in our North segment increased by $8 million in the third quarter of 2013 compared to the prior year period. Primary drivers were:
| |
| + | higher regulatory capacity revenues, partially offset by |
| |
| – | lower spark spreads and lower generation output resulting from milder weather and a reversal of coal-to-gas switching due to higher natural gas prices. |
Year-to-Date: Excluding a $64 million decrease from the sale of our Riverside Energy Center in December 2012, Commodity Margin in our North segment increased by $16 million for the nine months ended September 30, 2013, compared to the prior year period. The year-to-date results were largely impacted by the same factors that drove comparative performance for the third quarter, as previously discussed.
Southeast Region
Third Quarter: Excluding a $20 million decrease from the sale of our Broad River Energy Center in December 2012, Commodity Margin in our Southeast segment increased by $15 million in the third quarter of 2013 compared to the prior year period. Primary drivers were:
| |
| + | higher revenue from a new contract that became effective in January 2013, partially offset by |
| |
| – | lower spark spreads and lower generation output resulting from milder weather and a reversal of coal-to-gas switching due to higher natural gas prices. |
Year-to-Date: Excluding a $44 million decrease from the sale of our Broad River Energy Center in December 2012, Commodity Margin in our Southeast segment decreased by $6 million in the nine months ended September 30, 2013, compared to the prior year period. Primary drivers were:
| |
| – | lower spark spreads and lower generation output resulting from milder weather and a reversal of coal-to-gas switching due to higher natural gas prices, partially offset by |
| |
| + | higher revenue from a new contract that became effective in January 2013. |
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 6
LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES
Table 3: Liquidity
|
| | | | | | | | |
| | | |
| | | September 30, | | December 31, |
| | | 2013 | | 2012 |
| | | (in millions) |
Cash and cash equivalents, corporate(1) | | $ | 829 |
| | $ | 1,153 |
|
| Cash and cash equivalents, non-corporate | | 195 |
| | 131 |
|
| Total cash and cash equivalents | | 1,024 |
| | 1,284 |
|
| Restricted cash | | 248 |
| | 253 |
|
| Corporate Revolving Facility availability | | 756 |
| | 757 |
|
CDHI letter of credit availability(2) | | — |
| | — |
|
| Total current liquidity availability | | $ | 2,028 |
| | $ | 2,294 |
|
__________
| |
| (1) | Includes $22 million and $11 million of margin deposits posted with us by our counterparties at September 30, 2013, and December 31, 2012, respectively. |
| |
| (2) | As a result of the completion of the sale of Riverside Energy Center, LLC, a wholly owned subsidiary of CDHI, on December 31, 2012, we are required to cash collateralize letters of credit issued in excess of $225 million until replacement collateral is contributed to the CDHI collateral package, which we are in the process of arranging. At September 30, 2013, we had $4 million in outstanding letters of credit issued in excess of $225 million under our CDHI letter of credit facility that were collateralized by cash. We do not believe that this change will have a material impact on our liquidity. |
Liquidity was approximately $2 billion as of September 30, 2013. Cash and cash equivalents declined during the first nine months of the year due largely to our deployment of capital, including the repurchase of $462 million of our common stock, in addition to the funding of construction payments related to our Garrison Energy Center and the expansion of our Deer Park and Channel Energy Centers. These expenditures were partially offset by $551 million in Adjusted Free Cash Flow earned during the period.
Table 4: Cash Flow Activities
|
| | | | | | | |
| | Nine Months Ended September 30, |
| | 2013 | | 2012 |
| | (in millions) |
| Beginning cash and cash equivalents | $ | 1,284 |
| | $ | 1,252 |
|
| Net cash provided by (used in): | | | |
| Operating activities | 415 |
| | 608 |
|
| Investing activities | (468 | ) | | (701 | ) |
| Financing activities | (207 | ) | | (62 | ) |
| Net decrease in cash and cash equivalents | (260 | ) | | (155 | ) |
| Ending cash and cash equivalents | $ | 1,024 |
| | $ | 1,097 |
|
Cash flows from operating activities in the nine months ended September 30, 2013, resulted in net inflows of $415 million compared to $608 million in the prior year period. The decrease was primarily due to an increase in working capital employed, largely as a result of higher net accounts receivable and accounts payable balances and margin deposits due to increased revenues and prices combined with higher inventory balances resulting from purchases of environmental allowances. Also contributing to the decrease were higher debt extinguishment costs in the first half of 2013 due to payments associated with the redemption of our CCFC notes.
Cash flows used in investing activities during the nine months ended September 30, 2013, were $468 million compared to $701 million in the prior year period. The decrease in outflows was primarily due to $156 million in non-hedging interest rate swap settlements paid in the prior year period that did not recur this year, as well as lower capital expenditures during the nine months ended September 30, 2013, compared to the prior year period, primarily due to the timing of our construction projects and turbine modernization program. Also contributing to the decrease in outflows
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 7
was $12 million of transmission credits related to the construction of our Russell City Energy Center that were purchased in the prior year period and did not recur this year.
Cash flows used in financing activities were $207 million and were primarily related to the execution of our share repurchase program, offset by net proceeds associated with the refinancing of our CCFC notes and the receipt of proceeds from project debt related to our Russell City and Los Esteros construction projects.
In October 2013, we launched a tender offer to repay our $1.08 billion 7.25% Senior Secured Notes due 2017 with proceeds from a concurrently launched $390 million 2020 Term Loan that bears interest at LIBOR + 3% and $750 million of 6% Senior Secured Notes due 2022. During the same month, we also issued $490 million of 5.875% Senior Secured Notes due 2024, the proceeds of which we intend to use to redeem 10% of our remaining Senior Secured Notes. “These refinancings continue to show Calpine’s focus on balance sheet management, and the interest savings produced will directly contribute to the growth of our Adjusted Free Cash Flow Per Share,” said Zamir Rauf, Calpine’s Chief Financial Officer.
CAPITAL ALLOCATION
Share Repurchase Program
Having previously authorized $600 million in repurchases of our common stock, in February 2013, our Board of Directors authorized the repurchase of an additional $400 million in shares of our common stock, bringing the cumulative authorization total to $1.0 billion. We completed the repurchase of the additional $400 million authorization in July 2013. Over the course of the aggregate $1.0 billion share repurchase program, we repurchased approximately 55.0 million shares of our outstanding common stock at an average price of $18.18 per share. Under a new $100 million share repurchase authorization approved by our Board of Directors in August 2013, we have repurchased approximately 4.7 million shares of our common stock for approximately $92 million at an average price of $19.51 per share as of the filing of this release. This brings our cumulative share repurchases to approximately $1.1 billion, representing approximately 59.7 million shares at an average price of $18.28 per share. In November 2013, our Board of Directors approved an additional $1.0 billion multi-year share repurchase authorization.
PLANT DEVELOPMENT
West:
Russell City Energy Center: Our Russell City Energy Center commenced commercial operations in August 2013 and brought on-line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. Russell City Energy Center is contracted to deliver its full output to PG&E under a ten-year PPA.
Los Esteros Critical Energy Facility: During 2009, we and PG&E negotiated a new PPA to replace the existing California Department of Water Resources contract and facilitate the modernization of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 309 MW combined-cycle generation power plant, which has increased the efficiency and environmental performance of the power plant by lowering the heat rate. Our Los Esteros Critical Energy Facility commenced commercial operations as a combined-cycle power plant in August 2013.
Texas:
Channel and Deer Park Expansions: In September and November 2011, we filed air permit applications with the Texas Commission on Environmental Quality (TCEQ) and the Environmental Protection Agency (EPA) to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW6 each. We received air permit approvals from the TCEQ for our Deer Park and Channel expansion projects in September and October 2012, respectively, and from the EPA in November 2012. Construction on both expansion projects commenced in the fourth quarter of 2012. We expect COD on the expansions of our Channel and Deer Park Energy Centers during the second quarter of 2014.
___________
6 Represents incremental baseload capacity at annual average conditions. Incremental summer peaking capacity is approximately 200 MW per unit, supplemented by incremental efficiencies across the balance of plant.
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 8
North:
Garrison Energy Center: Garrison Energy Center is a 309 MW combined-cycle project located in Delaware on a site secured by a long-term lease with the City of Dover. Construction commenced in April 2013, and we expect COD by the second quarter of 2015. The project’s capacity cleared PJM’s 2015/2016 and 2016/2017 base residual auctions. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility and system impact studies for this phase, and the facilities study is currently underway.
Mankato Power Plant Expansion: We are proposing a 345 MW expansion of the Mankato Power Plant in response to a competitive resource acquisition process established by the Minnesota Public Utilities Commission (MPUC). The process, which will be managed via a contested case hearing, is intended to address an anticipated capacity shortfall in the Northern States Power service territory of up to 500 MW over the 2017 to 2019 time frame. The MPUC will evaluate proposals for intermediate and/or peaking capacity to meet all or part of the 500 MW needed. We expect that winning bidders will be identified in the first quarter of 2014.
PJM Development Opportunities: We are currently evaluating development opportunities in the PJM market area. Our 158 MW Deepwater power plant, which is currently scheduled to be decommissioned, presents an opportunity to leverage the existing infrastructure to add approximately 370 MW of new combined-cycle capacity to our fleet. In addition, we are evaluating adding up to 760 MW of additional capacity on the site where our York power plant is located. These projects are continuing to advance entitlements (permits, zoning, transmission, etc.) for their potential development at a future date.
All Segments:
Turbine Modernization: We continue to move forward with our turbine modernization program. Through September 30, 2013, we have completed the upgrade of twelve Siemens and eight GE turbines totaling approximately 200 MW and have committed to upgrade approximately four additional turbines. Similarly, we have the opportunity at several of our power plants in Texas to implement further modernizations to add as much as 300 MW of incremental capacity across the region at attractive prices. Our decision to invest in these modernizations depends upon, among other things, further clarity on market design reforms currently being considered by the Public Utility Commission of Texas.
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 9
OPERATIONS UPDATE
Third Quarter 2013 Power Operations Achievements:
| |
| — | Maintained top quartile7 safety metrics: 0.85 Total Recordable Incident Rate year-to-date |
| |
| • | Availability Performance: |
| |
| — | Maintained impressive fleetwide forced outage factor: 1.4% |
| |
| — | Delivered remarkable fleetwide starting reliability: 98.8% |
| |
| — | Provided approximately 1.5 million MWh of renewable baseload generation during the quarter with a 0.7% forced outage factor |
| |
| • | Natural Gas-fired Generation: |
| |
| — | Osprey Energy Center: 100% starting reliability, 0% forced outage factor |
| |
| — | Pastoria Energy Center: 92% capacity factor, 99.8% availability |
Third Quarter 2013 Commercial Operations Achievements:
| |
| • | Customer-oriented Growth: |
| |
| — | Successfully completed construction of our Russell City and Los Esteros power plants in California and began servicing related contracts with Pacific Gas and Electric |
| |
| — | Entered into a 100 MW financial PPA with a counterparty in PJM that commences in November 2013 and extends through 2016 |
| |
| — | Entered into a new five-year PPA commencing in 2014 for approximately 50 MW and extended existing steam agreement for ten years beyond 2016 with Celanese Ltd from our Clear Lake Power Plant |
___________
7 According to EEI Safety Survey (2012).
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 10
2013 & 2014 FINANCIAL OUTLOOK
(in millions, except per share amounts)
|
| | | | | | |
| | | Full Year 2013 | | Full Year 2014 |
| Adjusted EBITDA | $ | 1,800 - 1,825 |
| $ | 1,800 - 1,900 |
|
| Less: | | | | |
| Operating lease payments | | 35 |
| | 35 |
|
Major maintenance expense and maintenance capital expenditures(1) | | 390 |
| | 380 |
|
Cash interest, net(2) | | 700 |
| | 675 |
|
| Cash taxes | | 20 |
| | 20 |
|
| Other | | 10 |
| | 5 |
|
| Adjusted Free Cash Flow | $ | 645 - 670 |
| $ | 685 -785 |
|
| Per Share Estimate (diluted) | $ | 1.50 |
| $ | 1.60 - 1.80 |
|
| | | | | |
| Growth capital expenditures (net of debt funding) | $ | 275 |
| $ | 200 |
|
| Debt amortization | $ | 130 |
| $ | 200 |
|
________
| |
| (1) | Includes projected major maintenance expense of $230 million and $220 million and maintenance capital expenditures of $160 million and $160 million in 2013 and 2014, respectively. Capital expenditures exclude major construction and development projects. 2013 figures exclude a non-recurring IT system upgrade. |
| |
| (2) | Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. |
As detailed above, today we are narrowing our 2013 guidance. We now project Adjusted EBITDA of $1,800 million to $1,825 million and Adjusted Free Cash Flow of $645 million to $670 million. Meanwhile, we are reaffirming our Adjusted Free Cash Flow Per Share guidance of $1.50, which would result in a 22% compound annual growth rate since 2011. In addition, we are updating our expected investment for growth-related projects during the year to $275 million to reflect changes in timing of payments. Overall project cost estimates remain unchanged.
Today, we are also initiating guidance for 2014. We expect Adjusted EBITDA of $1,800 million to $1,900 million, Adjusted Free Cash Flow of $685 million to $785 million and Adjusted Free Cash Flow Per Share of $1.60 to $1.80. We also expect to invest $200 million in our ongoing growth-related projects during the year, including the expected completion of our Deer Park and Channel Energy Center expansions and ongoing construction of our Garrison Energy Center.
INVESTOR CONFERENCE CALL AND WEBCAST
We will host a conference call to discuss our financial and operating results for the third quarter of 2013 on Thursday, November 7, 2013, 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) 447-0521 in the U.S. or (847) 413-3238 outside the U.S. The confirmation code is 35497707. 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 35497707. Presentation materials to accompany the conference call will be available on our website on November 7, 2013.
ABOUT CALPINE
Calpine Corporation generates more electricity than any other independent power producer in America, with a fleet of 93 power plants in operation or under construction, representing more than 28,000 megawatts of generation capacity. Serving customers in 20 states and Canada, we specialize in developing, constructing, owning and operating natural gas-fired and renewable geothermal power plants that use advanced technologies to generate power in a low-carbon and environmentally responsible manner. Our clean, efficient, modern and flexible fleet is uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, stricter environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. We focus on competitive wholesale power markets and advocate for market-driven solutions that result in nondiscriminatory forward price signals for investors. Please visit www.calpine.com to learn more about why Calpine is a generation ahead - today.
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 11
Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, has been filed with the Securities and Exchange Commission (SEC) and may be found on the SEC’s website at www.sec.gov.
FORWARD-LOOKING INFORMATION
In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:
| |
| • | Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability to 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 and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Term Loans and other existing financing obligations; |
| |
| • | Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies; |
| |
| • | Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of wastewater to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources; |
| |
| • | The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder; |
| |
| • | Competition, including risks associated with marketing and selling power in the evolving energy markets; |
| |
| • | The expiration or early termination of our PPAs and the related results on revenues; |
| |
| • | Future capacity revenues may not occur at expected levels; |
| |
| • | Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters; |
| |
| • | Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power; |
| |
| • | Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions; |
| |
| • | Our ability to attract, motivate and retain key employees; |
| |
| • | Present and possible future claims, litigation and enforcement actions; and |
| |
• | Other risks identified in this press release and in our 2012 Form 10-K. |
Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 12
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | 2013 | | 2012 |
| | | (in millions, except share and per share amounts) |
| Operating revenues: | | | | | | | | |
| Commodity revenue | | $ | 2,020 |
| | $ | 1,689 |
| | $ | 4,867 |
| | $ | 4,078 |
|
| Unrealized mark-to-market gain (loss) | | 26 |
| | 304 |
| | (14 | ) | | 24 |
|
| Other revenue | | 4 |
| | 3 |
| | 10 |
| | 9 |
|
| Operating revenues | | 2,050 |
| | 1,996 |
| | 4,863 |
| | 4,111 |
|
| Operating expenses: | | | | | | | | |
| Fuel and purchased energy expense: | | | | | | | | |
| Commodity expense | | 1,076 |
| | 812 |
| | 2,909 |
| | 2,073 |
|
| Unrealized mark-to-market (gain) loss | | (17 | ) | | 85 |
| | (29 | ) | | 73 |
|
| Fuel and purchased energy expense | | 1,059 |
| | 897 |
| | 2,880 |
| | 2,146 |
|
| Plant operating expense | | 200 |
| | 207 |
| | 684 |
| | 699 |
|
| Depreciation and amortization expense | | 150 |
| | 140 |
| | 441 |
| | 418 |
|
| Sales, general and other administrative expense | | 33 |
| | 36 |
| | 102 |
| | 104 |
|
| Other operating expenses | | 20 |
| | 18 |
| | 58 |
| | 58 |
|
| Total operating expenses | | 1,462 |
| | 1,298 |
| | 4,165 |
| | 3,425 |
|
| (Income) from unconsolidated investments in power plants | | (9 | ) | | (7 | ) | | (25 | ) | | (21 | ) |
| Income from operations | | 597 |
| | 705 |
| | 723 |
| | 707 |
|
| Interest expense | | 176 |
| | 183 |
| | 522 |
| | 552 |
|
| Loss on interest rate derivatives | | — |
| | — |
| | — |
| | 14 |
|
| Interest (income) | | (2 | ) | | (2 | ) | | (5 | ) | | (7 | ) |
| Debt extinguishment costs | | — |
| | — |
| | 68 |
| | 12 |
|
| Other (income) expense, net | | 7 |
| | 6 |
| | 15 |
| | 14 |
|
| Income before income taxes | | 416 |
| | 518 |
| | 123 |
| | 122 |
|
| Income tax expense | | 110 |
| | 81 |
| | 12 |
| | 23 |
|
| Net income | | 306 |
| | 437 |
| | 111 |
| | 99 |
|
| Net income attributable to the noncontrolling interest | | — |
| | — |
| | — |
| | — |
|
| Net income attributable to Calpine | | $ | 306 |
| | $ | 437 |
| | $ | 111 |
| | $ | 99 |
|
|
| | | | | | | | | | | | | | | | |
| Basic earnings per common share attributable to Calpine: | | | | | | | | |
| Weighted average shares of common stock outstanding (in thousands) | | 434,384 |
| | 462,307 |
| | 444,486 |
| | 470,589 |
|
| Net income per common share attributable to Calpine — basic | | $ | 0.70 |
| | $ | 0.95 |
| | $ | 0.25 |
| | $ | 0.21 |
|
| Diluted earnings per common share attributable to Calpine: | | | | | | | | |
| Weighted average shares of common stock outstanding (in thousands) | | 438,493 |
| | 465,953 |
| | 448,546 |
| | 474,131 |
|
| Net income per common share attributable to Calpine — diluted | | $ | 0.70 |
| | $ | 0.94 |
| | $ | 0.25 |
| | $ | 0.21 |
|
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 13
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2013 | | 2012 |
| | | (in millions, except share and per share amounts) |
| ASSETS | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 1,024 |
| | $ | 1,284 |
|
| Accounts receivable, net of allowance of $1 and $6 | | 657 |
| | 437 |
|
| Margin deposits and other prepaid expense | | 343 |
| | 244 |
|
| Restricted cash, current | | 185 |
| | 193 |
|
| Derivative assets, current | | 471 |
| | 339 |
|
| Inventory and other current assets | | 355 |
| | 335 |
|
| Total current assets | | 3,035 |
| | 2,832 |
|
| Property, plant and equipment, net | | 13,039 |
| | 13,005 |
|
| Restricted cash, net of current portion | | 63 |
| | 60 |
|
| Investments in power plants | | 95 |
| | 81 |
|
| Long-term derivative assets | | 148 |
| | 98 |
|
| Other assets | | 423 |
| | 473 |
|
| Total assets | | $ | 16,803 |
| | $ | 16,549 |
|
| LIABILITIES & STOCKHOLDERS’ EQUITY | | | | |
| Current liabilities: | | | | |
| Accounts payable | | $ | 451 |
| | $ | 382 |
|
| Accrued interest payable | | 123 |
| | 180 |
|
| Debt, current portion | | 154 |
| | 115 |
|
| Derivative liabilities, current | | 472 |
| | 357 |
|
| Other current liabilities | | 284 |
| | 284 |
|
| Total current liabilities | | 1,484 |
| | 1,318 |
|
| Debt, net of current portion | | 10,869 |
| | 10,635 |
|
| Long-term derivative liabilities | | 333 |
| | 293 |
|
| Other long-term liabilities | | 317 |
| | 247 |
|
| Total liabilities | | 13,003 |
| | 12,493 |
|
| | | | | |
| 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, 497,754,264 and 492,495,100 shares issued, respectively, and 437,262,887 and 457,048,970 shares outstanding, respectively | | 1 |
| | 1 |
|
| Treasury stock, at cost, 60,491,377 and 35,446,130 shares, respectively | | (1,069 | ) | | (594 | ) |
| Additional paid-in capital | | 12,380 |
| | 12,335 |
|
| Accumulated deficit | | (7,389 | ) | | (7,500 | ) |
| Accumulated other comprehensive loss | | (184 | ) | | (248 | ) |
| Total Calpine stockholders’ equity | | 3,739 |
| | 3,994 |
|
| Noncontrolling interest | | 61 |
| | 62 |
|
| Total stockholders’ equity | | 3,800 |
| | 4,056 |
|
| Total liabilities and stockholders’ equity | | $ | 16,803 |
| | $ | 16,549 |
|
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 14
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2013 | | 2012 |
| | | (in millions) |
| Cash flows from operating activities: | | | | |
| Net income | | $ | 111 |
| | $ | 99 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | |
Depreciation and amortization expense(1) | | 474 |
| | 449 |
|
| Debt extinguishment costs | | 28 |
| | — |
|
| Deferred income taxes | | 18 |
| | (7 | ) |
| Loss on disposition of assets | | 5 |
| | 10 |
|
| Unrealized mark-to-market activity, net | | (14 | ) | | (103 | ) |
| (Income) from unconsolidated investments in power plants | | (25 | ) | | (21 | ) |
| Return on unconsolidated investments in power plants | | 23 |
| | 20 |
|
| Stock-based compensation expense | | 28 |
| | 19 |
|
| Other | | (2 | ) | | 1 |
|
| Change in operating assets and liabilities: | | | | |
| Accounts receivable | | (219 | ) | | 96 |
|
| Derivative instruments, net | | 47 |
| | (114 | ) |
| Other assets | | (111 | ) | | 97 |
|
| Accounts payable and accrued expenses | | (11 | ) | | (119 | ) |
| Settlement of non-hedging interest rate swaps | | — |
| | 156 |
|
| Other liabilities | | 63 |
| | 25 |
|
| Net cash provided by operating activities | | 415 |
| | 608 |
|
| Cash flows from investing activities: | | | | |
| Purchases of property, plant and equipment | | (472 | ) | | (509 | ) |
| Settlement of non-hedging interest rate swaps | | — |
| | (156 | ) |
| Return of investment in unconsolidated investments in power plants | | 1 |
| | 5 |
|
| (Increase) decrease in restricted cash | | 5 |
| | (32 | ) |
| Purchases of deferred transmission credits | | — |
| | (12 | ) |
| Other | | (2 | ) | | 3 |
|
| Net cash used in investing activities | | $ | (468 | ) | | $ | (701 | ) |
(Table continues)
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 15
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS — (Continued)
(Unaudited)
|
| | | | | | | | |
| | | Nine Months Ended September 30, |
| | | 2013 | | 2012 |
| | | (in millions) |
| Cash flows from financing activities: | | | | |
| Repayment under First Lien Term Loans | | $ | (19 | ) | | $ | (12 | ) |
| Borrowings from CCFC Term Loans | | 1,197 |
| | — |
|
| Repayments under CCFC Term Loans | | (3 | ) | | — |
|
| Repayment of CCFC Notes | | (1,000 | ) | | — |
|
| Borrowings from project financing, notes payable and other | | 139 |
| | 312 |
|
| Repayments of project financing, notes payable and other | | (51 | ) | | (53 | ) |
| Financing costs | | (27 | ) | | (6 | ) |
| Stock repurchases | | (462 | ) | | (308 | ) |
| Proceeds from exercises of stock options | | 19 |
| | 4 |
|
| Other | | — |
| | 1 |
|
| Net cash used in financing activities | | (207 | ) | | (62 | ) |
| Net decrease in cash and cash equivalents | | (260 | ) | | (155 | ) |
| Cash and cash equivalents, beginning of period | | 1,284 |
| | 1,252 |
|
| Cash and cash equivalents, end of period | | $ | 1,024 |
| | $ | 1,097 |
|
| | | | | |
| Cash paid during the period for: | | | | |
| Interest, net of amounts capitalized | | $ | 547 |
| | $ | 565 |
|
| Income taxes | | $ | 22 |
| | $ | 14 |
|
| | | | | |
| Supplemental disclosure of non-cash investing activities: | | | | |
| Change in capital expenditures included in accounts payable | | $ | 10 |
| | $ | (3 | ) |
| Additions to property, plant and equipment through assumption of long-term note payable | | $ | — |
| | $ | 8 |
|
__________
| |
(1) | Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations. |
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 16
REGULATION G RECONCILIATIONS
Net Income, 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 measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance.
Net Income, As Adjusted, represents net income attributable to Calpine, adjusted for certain non-cash and non-recurring items as previously detailed in Table 1, including debt extinguishment costs, unrealized mark-to-market (gain) loss on derivatives, and other adjustments. Net Income, 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, As Adjusted, is not intended to represent net income, 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 and optimization activities including natural gas transactions hedging future power sales, but excludes the unrealized portion of our 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 it is a key operational measure reviewed by our chief operating decision maker. Commodity Margin does not intend to represent income (loss) 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 unrealized 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 or extinguishment of debt and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends.
In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.
Adjusted Free Cash Flow represents net income before interest, taxes, depreciation and amortization, as adjusted, less operating lease payments, major maintenance expense and maintenance capital expenditures, net cash interest, cash taxes and other adjustments, including non-recurring items. Adjusted Free Cash Flow is presented because we believe it is a useful tool for assessing the financial performance of our company in the current period. Adjusted Free Cash Flow is a performance measure and is not intended to represent net income (loss), the most directly comparable U.S. GAAP measure, or liquidity and is not necessarily comparable to similarly titled measures reported by other companies.
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 17
Commodity Margin Reconciliation
The following table reconciles our Commodity Margin to its U.S. GAAP results for the three months ended September 30, 2013 and 2012 (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, 2013 |
| | | | | | | | | | | Consolidation | | |
| | | | | | | | | | | And | | |
| | | West | | Texas | | North | | Southeast | | Elimination | | Total |
| Commodity Margin | | $ | 337 |
| | $ | 328 |
| | $ | 242 |
| | $ | 78 |
| | $ | — |
| | $ | 985 |
|
Add: Unrealized mark-to-market commodity activity, net and other(1) | | 16 |
| | (5 | ) | | (3 | ) | | 6 |
| | (8 | ) | | 6 |
|
| Less: | | | | | | | | | | | |
|
| Plant operating expense | | 80 |
| | 60 |
| | 40 |
| | 27 |
| | (7 | ) | | 200 |
|
| Depreciation and amortization expense | | 57 |
| | 42 |
| | 33 |
| | 18 |
| | — |
| | 150 |
|
| Sales, general and other administrative expense | | 4 |
| | 17 |
| | 6 |
| | 5 |
| | 1 |
| | 33 |
|
| Other operating expenses | | 11 |
| | 2 |
| | 9 |
| | 1 |
| | (3 | ) | | 20 |
|
| (Income) from unconsolidated investments in power plants | | — |
| | — |
| | (9 | ) | | — |
| | — |
| | (9 | ) |
| Income from operations | | $ | 201 |
| | $ | 202 |
| | $ | 160 |
| | $ | 33 |
| | $ | 1 |
| | $ | 597 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, 2012 |
| | | | | | | | | | | Consolidation | | |
| | | | | | | | | | | And | | |
| | | West | | Texas | | North | | Southeast | | Elimination | | Total |
Commodity Margin(2)(3) | | $ | 330 |
| | $ | 218 |
| | $ | 266 |
| | $ | 83 |
| | $ | — |
| | $ | 897 |
|
Add: Unrealized mark-to-market commodity activity, net and other(1) | | (40 | ) | | 249 |
| | (26 | ) | | 27 |
| | (8 | ) | | 202 |
|
| Less: | | | | | | | | | | | | |
| Plant operating expense | | 88 |
| | 49 |
| | 51 |
| | 29 |
| | (10 | ) | | 207 |
|
| Depreciation and amortization expense | | 52 |
| | 35 |
| | 33 |
| | 21 |
| | (1 | ) | | 140 |
|
| Sales, general and other administrative expense | | 9 |
| | 12 |
| | 8 |
| | 8 |
| | (1 | ) | | 36 |
|
| Other operating expenses | | 10 |
| | 1 |
| | 6 |
| | (1 | ) | | 2 |
| | 18 |
|
| (Income) from unconsolidated investments in power plants | | — |
| | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) |
| Income from operations | | $ | 131 |
| | $ | 370 |
| | $ | 149 |
| | $ | 53 |
| | $ | 2 |
| | $ | 705 |
|
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 18
The following table reconciles our Commodity Margin to its U.S. GAAP results for the nine months ended September 30, 2013 and 2012 (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended September 30, 2013 |
| | | | | | | | | | | Consolidation | | |
| | | | | | | | | | | And | | |
| | | West | | Texas | | North | | Southeast | | Elimination | | Total |
| Commodity Margin | | $ | 737 |
| | $ | 537 |
| | $ | 543 |
| | $ | 162 |
| | $ | — |
| | $ | 1,979 |
|
Add: Unrealized mark-to-market commodity activity, net and other(4) | | (2 | ) | | 18 |
| | (8 | ) | | 20 |
| | (24 | ) | | 4 |
|
| Less: | | | | | | | | | | | | |
| Plant operating expense | | 261 |
| | 224 |
| | 130 |
| | 92 |
| | (23 | ) | | 684 |
|
| Depreciation and amortization expense | | 160 |
| | 129 |
| | 98 |
| | 55 |
| | (1 | ) | | 441 |
|
| Sales, general and other administrative expense | | 11 |
| | 55 |
| | 18 |
| | 17 |
| | 1 |
| | 102 |
|
| Other operating expenses | | 31 |
| | 4 |
| | 23 |
| | 2 |
| | (2 | ) | | 58 |
|
| (Income) from unconsolidated investments in power plants | | — |
| | — |
| | (25 | ) | | — |
| | — |
| | (25 | ) |
| Income from operations | | $ | 272 |
| | $ | 143 |
| | $ | 291 |
| | $ | 16 |
| | $ | 1 |
| | $ | 723 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Nine Months Ended September 30, 2012 |
| | | | | | | | | | | Consolidation | | |
| | | | | | | | | | | And | | |
| | | West | | Texas | | North | | Southeast | | Elimination | | Total |
Commodity Margin(2)(3) | | $ | 748 |
| | $ | 472 |
| | $ | 591 |
| | $ | 212 |
| | $ | — |
| | $ | 2,023 |
|
Add: Unrealized mark-to-market commodity activity, net and other(4) | | (80 | ) | | 66 |
| | (17 | ) | | (5 | ) | | (22 | ) | | (58 | ) |
| Less: | | | | | | | | | | | | |
| Plant operating expense | | 281 |
| | 189 |
| | 154 |
| | 98 |
| | (23 | ) | | 699 |
|
| Depreciation and amortization expense | | 151 |
| | 104 |
| | 100 |
| | 66 |
| | (3 | ) | | 418 |
|
| Sales, general and other administrative expense | | 23 |
| | 36 |
| | 22 |
| | 23 |
| | — |
| | 104 |
|
| Other operating expenses | | 30 |
| | 4 |
| | 21 |
| | 2 |
| | 1 |
| | 58 |
|
| (Income) from unconsolidated investments in power plants | | — |
| | — |
| | (21 | ) | | — |
| | — |
| | (21 | ) |
| Income from operations | | $ | 183 |
| | $ | 205 |
| | $ | 298 |
| | $ | 18 |
| | $ | 3 |
| | $ | 707 |
|
_________
| |
| (1) | Includes $44 million and $16 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2013 and 2012, respectively. |
| |
| (2) | Our North segment includes Commodity Margin of $32 million and $64 million for the three and nine months ended September 30, 2012, related to Riverside Energy Center, LLC, which was sold in December 2012. |
| |
| (3) | Our Southeast segment includes Commodity Margin of $20 million and $44 million for the three and nine months ended September 30, 2012, related to Broad River, which was sold in December 2012. |
| |
| (4) | Includes $17 million and $7 million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 30, 2013 and 2012, respectively. |
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 19
Consolidated Adjusted EBITDA Reconciliation
In the following table, we have reconciled our Adjusted EBITDA and Adjusted Free Cash Flow to our net income attributable to Calpine for the three and nine months ended September 30, 2013 and 2012, as reported under U.S. GAAP.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | |
| Net income attributable to Calpine | | $ | 306 |
| | $ | 437 |
| | $ | 111 |
| | $ | 99 |
|
| Income tax expense | | 110 |
| | 81 |
| | 12 |
| | 23 |
|
| Debt extinguishment costs and other (income) expense, net | | 7 |
| | 6 |
| | 83 |
| | 26 |
|
| Loss on interest rate derivatives | | — |
| | — |
| | — |
| | 14 |
|
| Interest expense, net of interest income | | 174 |
| | 181 |
| | 517 |
| | 545 |
|
| Income from operations | | $ | 597 |
| | $ | 705 |
| | $ | 723 |
| | $ | 707 |
|
| Add: | | | | | | | | |
| Adjustments to reconcile income from operations to Adjusted EBITDA: | | | | | | | | |
Depreciation and amortization expense, excluding deferred financing costs(1) | | 149 |
| | 140 |
| | 441 |
| | 419 |
|
| Major maintenance expense | | 33 |
| | 31 |
| | 182 |
| | 158 |
|
| Operating lease expense | | 9 |
| | 9 |
| | 26 |
| | 26 |
|
| Unrealized (gain) loss on commodity derivative mark-to-market activity | | (43 | ) | | (219 | ) | | (15 | ) | | 49 |
|
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2) | | — |
| | 7 |
| | 13 |
| | 23 |
|
| Stock-based compensation expense | | 8 |
| | 6 |
| | 28 |
| | 19 |
|
| Loss on dispositions of assets | | 1 |
| | 5 |
| | 5 |
| | 9 |
|
| Acquired contract amortization | | 4 |
| | 4 |
| | 11 |
| | 11 |
|
| Other | | 44 |
| | 18 |
| | 17 |
| | 13 |
|
| Total Adjusted EBITDA | | $ | 802 |
| | $ | 706 |
| | $ | 1,431 |
| | $ | 1,434 |
|
| Less: | | | | | | | | |
| Operating lease payments | | 9 |
| | 9 |
| | 26 |
| | 26 |
|
Major maintenance expense and capital expenditures(3) | | 62 |
| | 43 |
| | 303 |
| | 298 |
|
Cash interest, net(4) | | 173 |
| | 190 |
| | 528 |
| | 571 |
|
| Cash taxes | | 1 |
| | (1 | ) | | 18 |
| | 10 |
|
| Other | | 1 |
| | 2 |
| | 5 |
| | 6 |
|
Adjusted Free Cash Flow(5) | | $ | 556 |
| | $ | 463 |
| | $ | 551 |
| | $ | 523 |
|
| | | | | | | | | |
| Weighted average shares of common stock outstanding (diluted, in thousands) | | 438,493 |
| | 465,953 |
| | 448,546 |
| | 474,131 |
|
| Adjusted Free Cash Flow Per Share (diluted) | | $ | 1.27 |
| | $ | 0.99 |
| | $ | 1.23 |
| | $ | 1.10 |
|
_________
| |
| (1) | Depreciation and amortization expense on our Consolidated Condensed Statements of Operations excludes amortization of other assets. |
| |
| (2) | Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized (gain) loss on mark-to-market activity of nil for each of the three and nine months ended September 30, 2013 and 2012. |
| |
| (3) | Includes $34 million and $185 million in major maintenance expense for the three and nine months ended September 30, 2013, respectively, and $28 million and $118 million in maintenance capital expenditures for the three and nine months ended September 30, 2013, respectively. Includes $19 million and $150 million in major maintenance expense for the three and nine months ended September 30, 2012, respectively, and $24 million and $148 million in maintenance capital expenditure for the three and nine months ended September 30, 2012, respectively. |
| |
| (4) | Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. |
| |
| (5) | Excludes an increase in working capital of $76 million and $380 million for the three and nine months ended September 30, 2013, respectively, and an increase in working capital of $4 million and a decrease in working capital of $16 million for the three and nine months ended September 30, 2012, respectively. Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. |
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 20
Consolidated Adjusted EBITDA Reconciliation (continued)
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 nine months ended September 30, 2013 and 2012. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | |
| Commodity Margin | | $ | 985 |
| | $ | 897 |
| | $ | 1,979 |
| | $ | 2,023 |
|
| Other revenue | | 3 |
| | 3 |
| | 9 |
| | 9 |
|
Plant operating expense(1) | | (160 | ) | | (167 | ) | | (480 | ) | | (518 | ) |
Sales, general and administrative expense(2) | | (28 | ) | | (34 | ) | | (87 | ) | | (94 | ) |
Other operating expenses(3) | | (11 | ) | | (9 | ) | | (32 | ) | | (30 | ) |
Adjusted EBITDA from unconsolidated investments in power plants(4) | | 15 |
| | 14 |
| | 44 |
| | 44 |
|
| Other | | (2 | ) | | 2 |
| | (2 | ) | | — |
|
| Adjusted EBITDA | | $ | 802 |
| | $ | 706 |
| | $ | 1,431 |
| | $ | 1,434 |
|
_________
| |
| (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. |
| |
| (4) | Amount is composed of income from unconsolidated investments in power plants, as well as adjustments to reflect Adjusted EBITDA from unconsolidated investments. |
Adjusted EBITDA and Adjusted Free Cash Flow Reconciliation for Guidance
|
| | | | | | |
| Full Year 2013 Range: | | Low | | High |
| | | (in millions) |
GAAP Net Income (1) | $ | 87 |
| $ | 112 |
|
| Plus: | | | | |
| Debt extinguishment costs | | 68 |
| | 68 |
|
| Interest expense, net of interest income | | 700 |
| | 700 |
|
| Depreciation and amortization expense | | 615 |
| | 615 |
|
| Major maintenance expense | | 230 |
| | 230 |
|
| Operating lease expense | | 35 |
| | 35 |
|
Other(2) | | 65 |
| | 65 |
|
| Adjusted EBITDA | $ | 1,800 |
| $ | 1,825 |
|
| Less: | | | | |
| Operating lease payments | | 35 |
| | 35 |
|
Major maintenance expense and maintenance capital expenditures(3) | | 390 |
| | 390 |
|
Cash interest, net(4) | | 700 |
| | 700 |
|
| Cash taxes | | 20 |
| | 20 |
|
| Other | | 10 |
| | 10 |
|
| Adjusted Free Cash Flow | $ | 645 |
| $ | 670 |
|
| | | | | |
| |
| (1) | For purposes of Net Income guidance reconciliation, unrealized mark-to-market adjustments are assumed to be nil. |
| |
| (2) | Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. |
| |
| (3) | Includes projected major maintenance expense of $230 million and maintenance capital expenditures of $160 million. Capital expenditures exclude major construction and development projects. 2013 figures exclude a non-recurring IT system upgrade. |
| |
| (4) | Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. |
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 21
|
| | | | | | |
| Full Year 2014 Range: | | Low | | High |
| | | (in millions) |
GAAP Net Income (1) | $ | 150 |
| $ | 250 |
|
| Plus: | | | | |
| Interest expense, net of interest income | | 695 |
| | 695 |
|
| Depreciation and amortization expense | | 610 |
| | 610 |
|
| Major maintenance expense | | 215 |
| | 215 |
|
| Operating lease expense | | 35 |
| | 35 |
|
Other(2) | | 95 |
| | 95 |
|
| Adjusted EBITDA | $ | 1,800 |
| $ | 1,900 |
|
| Less: | | | | |
| Operating lease payments | | 35 |
| | 35 |
|
Major maintenance expense and maintenance capital expenditures(3) | | 380 |
| | 380 |
|
Cash interest, net(4) | | 675 |
| | 675 |
|
| Cash taxes | | 20 |
| | 20 |
|
| Other | | 5 |
| | 5 |
|
| Adjusted Free Cash Flow | $ | 685 |
| $ | 785 |
|
| | | | | |
_________
| |
| (1) | For purposes of Net Income guidance reconciliation, unrealized mark-to-market adjustments are assumed to be nil. |
| |
| (2) | Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. |
| |
| (3) | Includes projected major maintenance expense of $220 million and maintenance capital expenditures of $160 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. |
Calpine Reports Third Quarter 2013 Results
November 7, 2013
Page 22
OPERATING PERFORMANCE METRICS
The table below shows the operating performance metrics for continuing operations:
|
| | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | 2013 | | 2012 |
Total MWh generated (in thousands)(1) | | 29,688 |
| | 32,291 |
| | 76,025 |
| | 87,027 |
|
| West | | 10,185 |
| | 9,817 |
| | 25,751 |
| | 24,211 |
|
| Texas | | 9,924 |
| | 10,025 |
| | 25,224 |
| | 28,257 |
|
| Southeast | | 4,597 |
| | 5,821 |
| | 12,092 |
| | 17,744 |
|
| North | | 4,982 |
| | 6,628 |
| | 12,958 |
| | 16,815 |
|
| | | | | | | | | |
| Average availability | | 97.6 | % | | 97.7 | % | | 92.0 | % | | 91.5 | % |
| West | | 97.9 | % | | 98.5 | % | | 91.9 | % | | 91.2 | % |
| Texas | | 97.8 | % | | 97.2 | % | | 89.5 | % | | 90.4 | % |
| Southeast | | 97.4 | % | | 98.3 | % | | 95.6 | % | | 94.4 | % |
| North | | 97.3 | % | | 96.9 | % | | 92.6 | % | | 90.5 | % |
| | | | | | | | | |
Average capacity factor, excluding peakers(1) | | 55.7 | % | | 61.0 | % | | 49.0 | % | | 55.7 | % |
| West | | 68.5 | % | | 70.7 | % | | 61.1 | % | | 58.7 | % |
| Texas | | 57.7 | % | | 64.7 | % | | 49.5 | % | | 61.3 | % |
| Southeast | | 40.7 | % | | 48.4 | % | | 36.0 | % | | 49.6 | % |
| North | | 50.0 | % | | 56.1 | % | | 45.4 | % | | 49.7 | % |
| | | | | | | | | |
| Steam adjusted heat rate (Btu/kWh) | | 7,414 |
| | 7,404 |
| | 7,402 |
| | 7,357 |
|
| West | | 7,317 |
| | 7,313 |
| | 7,335 |
| | 7,267 |
|
| Texas | | 7,226 |
| | 7,211 |
| | 7,193 |
| | 7,149 |
|
| Southeast | | 7,388 |
| | 7,325 |
| | 7,364 |
| | 7,302 |
|
| North | | 8,046 |
| | 7,943 |
| | 7,994 |
| | 7,918 |
|
________
| |
| (1) | Excludes generation from unconsolidated power plants and power plants owned but not operated by us. |
