Delaware | 1-12079 | 77-0212977 |
(State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) |
o | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
o | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
o | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
o | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
ITEM 2.02 — RESULTS OF OPERATIONS AND FINANCIAL CONDITION | ||
ITEM 9.01 — FINANCIAL STATEMENTS AND EXHIBITS | ||
SIGNATURES | ||
EXHIBIT INDEX |
(d) | Exhibits |
Exhibit No. | Description | |
99.1 | Calpine Corporation Press Release dated November 6, 2012.* |
* | Furnished herewith. |
By: | /s/ ZAMIR RAUF | |||
Zamir Rauf | ||||
Executive Vice President and | ||||
Chief Financial Officer | ||||
November 6, 2012 |
Exhibit No. | Description | |
99.1 | Calpine Corporation Press Release dated November 6, 2012.* |
* | Furnished herewith. |
CONTACTS: | NEWS RELEASE |
Media Relations: | Investor Relations: |
Norma F. Dunn | Bryan Kimzey |
713-830-8883 | 713-830-8777 |
norma.dunn@calpine.com | bryan.kimzey@calpine.com |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||
2012 | 2011 | % Change | 2012 | 2011 | % Change | |||||||||||||||||
Operating Revenues | $ | 1,996 | $ | 2,209 | (9.6 | )% | $ | 4,111 | $ | 5,341 | (23.0 | )% | ||||||||||
Commodity Margin | $ | 897 | $ | 825 | 8.7 | % | $ | 2,023 | $ | 1,921 | 5.3 | % | ||||||||||
Adjusted EBITDA | $ | 706 | $ | 638 | 10.7 | % | $ | 1,434 | $ | 1,347 | 6.5 | % | ||||||||||
Adjusted Recurring Free Cash Flow | $ | 463 | $ | 361 | 28.3 | % | $ | 523 | $ | 381 | 37.3 | % | ||||||||||
Per Share (diluted) | $ | 0.99 | $ | 0.74 | 33.8 | % | $ | 1.10 | $ | 0.78 | 41.0 | % | ||||||||||
Net Income (Loss)1 | $ | 437 | $ | 190 | $ | 99 | $ | (177 | ) | |||||||||||||
Net Income, As Adjusted2 | $ | 215 | $ | 195 | $ | 164 | $ | 30 |
2012 | 2013 | ||
(in millions) | |||
Adjusted EBITDA | $1,725 - 1,775 | $1,760 - 1,960 | |
Adjusted Recurring Free Cash Flow | $525 - 575 | $575 - 775 | |
Per Share Midpoint (diluted) | $1.16 | $1.45 |
• | Operations: |
— | Generated more than 33 million MWh3 of electricity in the third quarter of 2012, a record for the period and a 14% increase compared to the third quarter of 2011 |
— | Held year-to-date plant operating expense4 essentially flat, despite a 31% increase in generation3 |
— | Delivered lowest year-to-date fleetwide forced outage factor on record: 1.6% |
— | Produced highest year-to-date fleetwide starting reliability on record: 98.5% |
— | Achieved best year-to-date safety performance on record |
• | Commercial: |
— | Announcing sale of Broad River Energy Center, an 847 MW simple-cycle power plant in South Carolina, for $427 million5, or $504/kW |
— | Announced acquisition of Bosque Energy Center, an 800 MW combined-cycle power plant in Central Texas for $432 million5, or $540/kW |
— | Signed 15-year PPA for 260 MW of capacity, energy and ancillary services from our Oneta Energy Center commencing in June 2016 |
• | Capital Structure: |
— | Simplified capital structure by entering into $835 million first lien term loan at an attractive rate, using proceeds to redeem 10% of existing first lien notes and retire project-level BRSP debt |
1 | Reported as net income (loss) 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 | 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 nine months ended September 30, 2012 and 2011. |
5 | Amounts subject to adjustments upon close. |
+ | higher contribution from hedges in our Texas segment, and |
+ | higher regulatory capacity revenue in the Mid-Atlantic market. |
+ | higher Commodity Margin, as previously discussed, and |
+ | lower interest expense, primarily resulting from a decrease in our annual effective interest rate, partially offset by |
– | increased income tax expense due primarily to an increase in various state and foreign jurisdiction income taxes. |
+ | higher contribution from hedges, primarily in our Texas segment during the third quarter of 2012 compared to the prior year period |
+ | higher generation due to increased market opportunities, primarily driven by lower natural gas prices in all segments during the first half of 2012 compared to the same period in 2011, as well as lower hydroelectric generation and a nuclear power plant outage in California during the nine months ended September 30, 2012, and |
+ | an extreme cold weather event in Texas in February 2011 that negatively impacted our Commodity Margin in that period, which did not recur in the current year, partially offset by |
– | lower regulatory capacity revenues during the first half of 2012 compared to the prior year period and |
– | the expiration of contracts. |
+ | higher Commodity Margin, as previously discussed, and |
+ | lower interest expense, primarily resulting from a decrease in our annual effective interest rate. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions) | ||||||||||||||||
Net income (loss) attributable to Calpine | $ | 437 | $ | 190 | $ | 99 | $ | (177 | ) | |||||||
Debt extinguishment costs(1) | — | (4 | ) | 12 | 94 | |||||||||||
Unrealized MtM (gain) loss on derivatives(1) (2) | (222 | ) | (35 | ) | (103 | ) | 42 | |||||||||
Other items (1) (3) | — | 44 | 156 | 71 | ||||||||||||
Net Income, As Adjusted(4) | $ | 215 | $ | 195 | $ | 164 | $ | 30 |
(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 nil and $156 million for the three and nine months ended September 30, 2012, respectively, and $44 million and $147 million for the three and nine months ended September 30, 2011, respectively. Other items for the nine months ended September 30, 2011, also include a $76 million federal deferred income tax benefit associated with our election to consolidate our CCFC subsidiary for tax reporting purposes. |
(4) | See “Regulation G Reconciliations” for further discussion of Net Income, As Adjusted. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
2012 | 2011 | Variance | 2012 | 2011 | Variance | |||||||||||||||||||
West | $ | 330 | $ | 329 | $ | 1 | $ | 748 | $ | 798 | $ | (50 | ) | |||||||||||
Texas | 218 | 162 | 56 | 472 | 357 | 115 | ||||||||||||||||||
North | 266 | 259 | 7 | 591 | 578 | 13 | ||||||||||||||||||
Southeast | 83 | 75 | 8 | 212 | 188 | 24 | ||||||||||||||||||
Total | $ | 897 | $ | 825 | $ | 72 | $ | 2,023 | $ | 1,921 | $ | 102 |
+ | increased generation and higher spark spreads driven primarily by lower hydroelectric generation and a nuclear power plant outage in California during 2012, largely offset by |
– | lower contribution from hedges associated with our Geysers assets. |
– | lower contribution from hedges associated with our Geysers assets |
– | lower revenue due to the expiration of contracts and |
– | lower Commodity Margin associated with our Sutter Energy Center, which did not run in the first half of 2012, partially offset by |
+ | increased generation and higher spark spreads resulting from lower hydroelectric generation and a nuclear power plant outage in California during 2012. |
+ | higher contribution from hedging activities that secured favorable pricing despite lower market prices driven by milder weather. |
+ | higher contribution from hedging activities that secured favorable pricing despite lower market prices driven by milder weather in the third quarter of 2012 compared to the prior year period |
+ | higher generation driven by increased market opportunities primarily due to lower natural gas prices and |
+ | an extreme cold weather event in Texas in February 2011 that negatively impacted our Commodity Margin in the first quarter of the prior year, which did not recur in the current year. |
+ | higher regulatory capacity revenues and |
+ | to a far lesser extent, increased generation, the impact of which was mitigated by contracted plants that generated higher volumes, as well as lower margins experienced by the remaining plants. |
+ | higher contribution from hedges |
+ | York Energy Center achieving commercial operation in March 2011 and |
+ | increased generation driven by increased market opportunities primarily due to lower natural gas prices, partially offset by |
– | lower regulatory capacity revenues during the nine months ended September 30, 2012, compared to the prior year period. |
+ | higher contribution from hedges associated with lower natural gas prices, partially offset by |
– | the expiration of a contract. |
+ | higher contribution from hedges and |
+ | higher generation resulting from increased market opportunities due to lower natural gas prices. |
September 30, | December 31, | |||||||
2012 | 2011 | |||||||
(in millions) | ||||||||
Cash and cash equivalents, corporate(1) | $ | 886 | $ | 946 | ||||
Cash and cash equivalents, non-corporate | 211 | 306 | ||||||
Total cash and cash equivalents | 1,097 | 1,252 | ||||||
Restricted cash | 226 | 194 | ||||||
Corporate Revolving Facility availability | 720 | 560 | ||||||
Letter of credit availability(2) | 25 | 7 | ||||||
Total current liquidity availability | $ | 2,068 | $ | 2,013 |
(1) | Includes $9 million and $34 million of margin deposits held by us posted by our counterparties at September 30, 2012, and December 31, 2011, respectively. |
(2) | Includes availability under our CDHI letter of credit facility. On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016. |
• | Safety Performance: |
— | Maintained stellar safety metrics |
— | Recognized 10 years with no lost time incidents: Westbrook Energy Center, Pine Bluff Energy Center, Baytown Energy Center, Geysers plants – Aidlin, Sonoma, Cobb Creek, Quicksilver, Socrates |
• | Availability Performance: |
— | Delivered lowest year-to-date fleetwide forced outage factor on record: 1.6% |
— | Maintained impressive third quarter fleetwide starting reliability: 98.8% |
• | Cost Performance: |
— | Held year-to-date plant operating expense4 essentially flat, despite a 31% increase in generation3 |
• | Geothermal Generation: |
— | Provided over 1.5 million MWh of renewable baseload generation with a record 0.5% forced outage factor during the third quarter of 2012 |
• | Natural Gas-fired Generation: |
— | Increased combined-cycle capacity factor in the first nine months of 2012 to 54.3% compared to 40.9% in the prior year period |
— | Santa Rosa Energy Center: 100% starting reliability, 0.00% forced outage factor |
• | Customer-oriented Growth: |
— | Entered into a 15-year PPA with Public Service Company of Oklahoma to provide 260 MW of capacity, energy and ancillary services from our Oneta Energy Center commencing in June 2016 through May 2031 |
Full Year 2012 | Full Year 2013(1) | |||||
(in millions) | ||||||
Adjusted EBITDA | $ | 1,725 - 1,775 | $ | 1,760 - 1,960 | ||
Less: | ||||||
Operating lease payments | 35 | 35 | ||||
Major maintenance expense and maintenance capital expenditures(2) | 350 | 370 | ||||
Accelerated parts purchases to support upgrades(3) | 30 | - | ||||
Recurring cash interest, net(4) | 770 | 755 | ||||
Cash taxes | 10 | 15 | ||||
Other | 5 | 10 | ||||
Adjusted Recurring Free Cash Flow | $ | 525 - 575 | $ | 575 - 775 | ||
Per Share Midpoint | $ | 1.16 | $ | 1.45 | ||
Non-recurring interest rate swap payments(5) | $ | (156 | ) | $ | - | |
Growth capital expenditures (net of debt funding) | $ | (100 | ) | $ | (250 | ) |
Debt amortization | $ | (115 | ) | $ | (140 | ) |
Asset purchases | $ | (432 | ) | $ | - | |
Asset sale proceeds(6) | $ | 819 | $ | - |
(1) | 2013 guidance range reflects all pending acquisition and divestiture activity, including today’s announced sale of Broad River Energy Center, which we estimate would have contributed approximately $40 million of Adjusted EBITDA in 2013. |
(2) | Includes projected major maintenance expense of $200 million and $210 million and maintenance capital expenditures of $150 million and $160 million in 2012 and 2013, respectively. Capital expenditures exclude major construction and development projects. 2012 figures exclude amounts to be funded by project debt. 2013 figures exclude non-recurring IT system upgrade. |
(3) | Incremental impact on 2012 maintenance capital expenditures related to acceleration of future turbine upgrades into 2012 and deferral of use of on-hand parts to post-2012 periods. |
(4) | Includes fees for letters of credit, net of interest income. |
(5) | Interest payments related to legacy LIBOR hedges associated with floating rate first lien credit facility, which has been retired. |
(6) | Amounts subject to adjustments upon close. |
• | Financial results that may be volatile and may not reflect historical trends due to, among other things, 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; |
• | The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder; |
• | Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, First Lien Term Loans, 2019 First Lien Term Loan, CCFC Notes and other existing financing obligations; |
• | Risks associated with the continued economic and financial conditions affecting certain countries in Europe including financial institutions located within those countries and their ability to fund their financial commitments; |
• | 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; |
• | 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 2011 Form 10-K. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions, except share and per share amounts) | ||||||||||||||||
Operating revenues | $ | 1,996 | $ | 2,209 | $ | 4,111 | $ | 5,341 | ||||||||
Operating expenses: | ||||||||||||||||
Fuel and purchased energy expense | 893 | 1,401 | 2,137 | 3,470 | ||||||||||||
Plant operating expense | 207 | 212 | 699 | 711 | ||||||||||||
Depreciation and amortization expense | 140 | 143 | 418 | 405 | ||||||||||||
Sales, general and other administrative expense | 36 | 33 | 104 | 99 | ||||||||||||
Other operating expenses | 22 | 22 | 67 | 64 | ||||||||||||
Total operating expenses | 1,298 | 1,811 | 3,425 | 4,749 | ||||||||||||
(Income) from unconsolidated investments in power plants | (7 | ) | (5 | ) | (21 | ) | (12 | ) | ||||||||
Income from operations | 705 | 403 | 707 | 604 | ||||||||||||
Interest expense | 183 | 192 | 552 | 575 | ||||||||||||
Loss on interest rate derivatives | — | 3 | 14 | 149 | ||||||||||||
Interest (income) | (2 | ) | (2 | ) | (7 | ) | (7 | ) | ||||||||
Debt extinguishment costs | — | (4 | ) | 12 | 94 | |||||||||||
Other (income) expense, net | 6 | 4 | 14 | 14 | ||||||||||||
Income (loss) before income taxes | 518 | 210 | 122 | (221 | ) | |||||||||||
Income tax expense (benefit) | 81 | 20 | 23 | (45 | ) | |||||||||||
Net income (loss) | 437 | 190 | 99 | (176 | ) | |||||||||||
Net income attributable to the noncontrolling interest | — | — | — | (1 | ) | |||||||||||
Net income (loss) attributable to Calpine | $ | 437 | $ | 190 | $ | 99 | $ | (177 | ) |
Basic earnings (loss) per common share attributable to Calpine: | ||||||||||||||||
Weighted average shares of common stock outstanding (in thousands) | 462,307 | 486,420 | 470,589 | 486,363 | ||||||||||||
Net income (loss) per common share attributable to Calpine — basic | $ | 0.95 | $ | 0.39 | $ | 0.21 | $ | (0.36 | ) | |||||||
Diluted earnings (loss) per common share attributable to Calpine: | ||||||||||||||||
Weighted average shares of common stock outstanding (in thousands) | 465,953 | 489,062 | 474,131 | 486,363 | ||||||||||||
Net income (loss) per common share attributable to Calpine — diluted | $ | 0.94 | $ | 0.39 | $ | 0.21 | $ | (0.36 | ) |
September 30, | December 31, | |||||||
2012 | 2011 | |||||||
(in millions, except share and per share amounts) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,097 | $ | 1,252 | ||||
Accounts receivable, net of allowance of $10 and $13 | 500 | 598 | ||||||
Margin deposits and other prepaid expense | 143 | 193 | ||||||
Restricted cash, current | 163 | 139 | ||||||
Derivative assets, current | 487 | 1,051 | ||||||
Inventory and other current assets | 297 | 329 | ||||||
Total current assets | 2,687 | 3,562 | ||||||
Property, plant and equipment, net | 13,129 | 13,019 | ||||||
Restricted cash, net of current portion | 63 | 55 | ||||||
Investments | 79 | 80 | ||||||
Long-term derivative assets | 146 | 113 | ||||||
Other assets | 489 | 542 | ||||||
Total assets | $ | 16,593 | $ | 17,371 | ||||
LIABILITIES & STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 361 | $ | 435 | ||||
Accrued interest payable | 163 | 200 | ||||||
Debt, current portion | 105 | 104 | ||||||
Derivative liabilities, current | 457 | 1,144 | ||||||
Other current liabilities | 265 | 279 | ||||||
Total current liabilities | 1,351 | 2,162 | ||||||
Debt, net of current portion | 10,567 | 10,321 | ||||||
Long-term derivative liabilities | 286 | 279 | ||||||
Other long-term liabilities | 275 | 245 | ||||||
Total liabilities | 12,479 | 13,007 |
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, 492,072,137 and 490,468,815 shares issued, respectively, and 465,572,396 and 481,743,738 shares outstanding, respectively | 1 | 1 | ||||||
Treasury stock, at cost, 26,499,741 and 8,725,077 shares, respectively | (439 | ) | (125 | ) | ||||
Additional paid-in capital | 12,327 | 12,305 | ||||||
Accumulated deficit | (7,600 | ) | (7,699 | ) | ||||
Accumulated other comprehensive loss | (237 | ) | (178 | ) | ||||
Total Calpine stockholders’ equity | 4,052 | 4,304 | ||||||
Noncontrolling interest | 62 | 60 | ||||||
Total stockholders’ equity | 4,114 | 4,364 | ||||||
Total liabilities and stockholders’ equity | $ | 16,593 | $ | 17,371 |
Nine Months Ended September 30, | ||||||||
2012 | 2011 | |||||||
(in millions) | ||||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $ | 99 | $ | (176 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depreciation and amortization expense(1) | 449 | 431 | ||||||
Debt extinguishment costs | — | 82 | ||||||
Deferred income taxes | (7 | ) | (56 | ) | ||||
Loss on disposition of assets | 10 | 18 | ||||||
Unrealized mark-to-market activities, net | (103 | ) | 42 | |||||
(Income) from unconsolidated investments in power plants | (21 | ) | (12 | ) | ||||
Return on unconsolidated investments in power plants | 20 | 6 | ||||||
Stock-based compensation expense | 19 | 18 | ||||||
Other | 1 | 5 | ||||||
Change in operating assets and liabilities: | ||||||||
Accounts receivable | 96 | (87 | ) | |||||
Derivative instruments, net | (114 | ) | (6 | ) | ||||
Other assets | 97 | 27 | ||||||
Accounts payable and accrued expenses | (119 | ) | 95 | |||||
Settlement of non-hedging interest rate swaps | 156 | 147 | ||||||
Other liabilities | 25 | 2 | ||||||
Net cash provided by operating activities | 608 | 536 | ||||||
Cash flows from investing activities: | ||||||||
Purchases of property, plant and equipment | (509 | ) | (511 | ) | ||||
Settlement of non-hedging interest rate swaps | (156 | ) | (147 | ) | ||||
Return of investment in unconsolidated investment in power plants | 5 | — | ||||||
(Increase) decrease in restricted cash | (32 | ) | 9 | |||||
Purchases of deferred transmission credits | (12 | ) | (16 | ) | ||||
Other | 3 | 5 | ||||||
Net cash used in investing activities | $ | (701 | ) | $ | (660 | ) |
Nine Months Ended September 30, | ||||||||
2012 | 2011 | |||||||
(in millions) | ||||||||
Cash flows from financing activities: | ||||||||
Repayment of First Lien Term Loans | $ | (12 | ) | $ | — | |||
Borrowings under First Lien Term Loans | — | 1,657 | ||||||
Repayments on NDH Project Debt | — | (1,283 | ) | |||||
Issuance of 2023 First Lien Notes | — | 1,200 | ||||||
Repayments on First Lien Credit Facility | — | (1,191 | ) | |||||
Borrowings from project financing, notes payable and other | 312 | 223 | ||||||
Repayments of project financing, notes payable and other | (53 | ) | (476 | ) | ||||
Capital contributions from noncontrolling interest holder | — | 34 | ||||||
Financing costs | (6 | ) | (78 | ) | ||||
Stock repurchases | (308 | ) | — | |||||
Other | 5 | (4 | ) | |||||
Net cash provided by (used in) financing activities | (62 | ) | 82 | |||||
Net decrease in cash and cash equivalents | (155 | ) | (42 | ) | ||||
Cash and cash equivalents, beginning of period | 1,252 | 1,327 | ||||||
Cash and cash equivalents, end of period | $ | 1,097 | $ | 1,285 | ||||
Cash paid during the period for: | ||||||||
Interest, net of amounts capitalized | $ | 565 | $ | 509 | ||||
Income taxes | $ | 14 | $ | 15 | ||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||||
Change in capital expenditures included in accounts payable | $ | (3 | ) | $ | (13 | ) | ||
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. |
Three Months Ended September 30, 2012 | ||||||||||||||||||||||||
Consolidation | ||||||||||||||||||||||||
And | ||||||||||||||||||||||||
West | Texas | North | Southeast | Elimination | Total | |||||||||||||||||||
Commodity Margin(1) | $ | 330 | $ | 218 | $ | 266 | $ | 83 | $ | — | $ | 897 | ||||||||||||
Add: Mark-to-market commodity activity, net and other(2)(3) | (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(4) | 10 | 1 | 6 | (1 | ) | 2 | 18 | |||||||||||||||||
(Income) from unconsolidated investments in power plants | — | — | (7 | ) | — | — | (7 | ) | ||||||||||||||||
Income from operations | $ | 131 | $ | 370 | $ | 149 | $ | 53 | $ | 2 | $ | 705 |
Three Months Ended September 30, 2011 | ||||||||||||||||||||||||
Consolidation | ||||||||||||||||||||||||
And | ||||||||||||||||||||||||
West | Texas | North | Southeast | Elimination | Total | |||||||||||||||||||
Commodity Margin(1) | $ | 329 | $ | 162 | $ | 259 | $ | 75 | $ | — | $ | 825 | ||||||||||||
Add: Mark-to-market commodity activity, net and other(2)(3) | 20 | (21 | ) | (11 | ) | — | (8 | ) | (20 | ) | ||||||||||||||
Less: | ||||||||||||||||||||||||
Plant operating expense | 94 | 50 | 44 | 33 | (9 | ) | 212 | |||||||||||||||||
Depreciation and amortization expense | 52 | 34 | 36 | 22 | (1 | ) | 143 | |||||||||||||||||
Sales, general and other administrative expense | 10 | 10 | 7 | 7 | (1 | ) | 33 | |||||||||||||||||
Other operating expenses(4) | 11 | (1 | ) | 7 | — | 2 | 19 | |||||||||||||||||
(Income) from unconsolidated investments in power plants | — | — | (5 | ) | — | — | (5 | ) | ||||||||||||||||
Income from operations | $ | 182 | $ | 48 | $ | 159 | $ | 13 | $ | 1 | $ | 403 |
Nine Months Ended September 30, 2012 | ||||||||||||||||||||||||
Consolidation | ||||||||||||||||||||||||
And | ||||||||||||||||||||||||
West | Texas | North | Southeast | Elimination | Total | |||||||||||||||||||
Commodity Margin(1) | $ | 748 | $ | 472 | $ | 591 | $ | 212 | $ | — | $ | 2,023 | ||||||||||||
Add: Mark-to-market commodity activity, net and other(2)(5) | (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(4) | 30 | 4 | 21 | 2 | 1 | 58 | ||||||||||||||||||
(Income) from unconsolidated investments in power plants | — | — | (21 | ) | — | — | (21 | ) | ||||||||||||||||
Income from operations | $ | 183 | $ | 205 | $ | 298 | $ | 18 | $ | 3 | $ | 707 |
Nine Months Ended September 30, 2011 | ||||||||||||||||||||||||
Consolidation | ||||||||||||||||||||||||
And | ||||||||||||||||||||||||
West | Texas | North | Southeast | Elimination | Total | |||||||||||||||||||
Commodity Margin(1) | $ | 798 | $ | 357 | $ | 578 | $ | 188 | $ | — | $ | 1,921 | ||||||||||||
Add: Mark-to-market commodity activity, net and other(2)(5) | 36 | (54 | ) | (12 | ) | (4 | ) | (23 | ) | (57 | ) | |||||||||||||
Less: | ||||||||||||||||||||||||
Plant operating expense | 297 | 193 | 136 | 107 | (22 | ) | 711 | |||||||||||||||||
Depreciation and amortization expense | 140 | 99 | 102 | 67 | (3 | ) | 405 | |||||||||||||||||
Sales, general and other administrative expense | 29 | 33 | 19 | 18 | — | 99 | ||||||||||||||||||
Other operating expenses(4) | 30 | 2 | 23 | 3 | (1 | ) | 57 | |||||||||||||||||
(Income) from unconsolidated investments in power plants | — | — | (12 | ) | — | — | (12 | ) | ||||||||||||||||
Income (loss) from operations | $ | 338 | $ | (24 | ) | $ | 298 | $ | (11 | ) | $ | 3 | $ | 604 |
(1) | Our North segment includes Commodity Margin related to Riverside Energy Center, LLC, of $32 million and $31 million for the three months ended September 30, 2012 and 2011, respectively, and $64 million and $62 million for the nine months ended September 30, 2012 and 2011, respectively. |
(2) | Mark-to-market commodity activity represents the change in the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations. |
(3) | Includes $16 million and $11 million of lease levelization for the three months ended September 30, 2012 and 2011, respectively, and $4 million of amortization expense for each of the three months ended September 30, 2012 and 2011. |
(4) | Excludes $4 million and $3 million of RGGI compliance and other environmental costs for the three months ended September 30, 2012 and 2011, respectively, and $9 million and $7 million for the nine months ended September 30, 2012 and 2011, respectively, which are components of Commodity Margin. |
(5) | Includes $7 million and $15 million of lease levelization and $11 million and $5 million of amortization expense for the nine months ended September 30, 2012 and 2011, respectively. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions) | ||||||||||||||||
Net income (loss) attributable to Calpine | $ | 437 | $ | 190 | $ | 99 | $ | (177 | ) | |||||||
Net income attributable to the noncontrolling interest | — | — | — | 1 | ||||||||||||
Income tax expense (benefit) | 81 | 20 | 23 | (45 | ) | |||||||||||
Debt extinguishment costs and other (income) expense, net | 6 | — | 26 | 108 | ||||||||||||
Loss on interest rate derivatives | — | 3 | 14 | 149 | ||||||||||||
Interest expense, net of interest income | 181 | 190 | 545 | 568 | ||||||||||||
Income from operations | $ | 705 | $ | 403 | $ | 707 | $ | 604 | ||||||||
Add: | ||||||||||||||||
Adjustments to reconcile income from operations to Adjusted EBITDA: | ||||||||||||||||
Depreciation and amortization expense, excluding deferred financing costs(1) | 140 | 143 | 419 | 406 | ||||||||||||
Major maintenance expense | 31 | 33 | 158 | 169 | ||||||||||||
Operating lease expense | 9 | 9 | 26 | 26 | ||||||||||||
Unrealized (gain) loss on commodity derivative mark-to-market activity | (219 | ) | 9 | 49 | 48 | |||||||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)(3) | 7 | 9 | 23 | 30 | ||||||||||||
Stock-based compensation expense | 6 | 6 | 19 | 18 | ||||||||||||
Loss on dispositions of assets | 5 | 8 | 9 | 17 | ||||||||||||
Acquired contract amortization | 4 | 4 | 11 | 5 | ||||||||||||
Other | 18 | 14 | 13 | 24 | ||||||||||||
Total Adjusted EBITDA | $ | 706 | $ | 638 | $ | 1,434 | $ | 1,347 | ||||||||
Less: | ||||||||||||||||
Lease payments | 9 | 9 | 26 | 26 | ||||||||||||
Major maintenance expense and capital expenditures(4) | 43 | 72 | 298 | 335 | ||||||||||||
Cash interest, net(5) | 190 | 194 | 571 | 587 | ||||||||||||
Cash taxes | (1 | ) | 1 | 10 | 11 | |||||||||||
Other | 2 | 1 | 6 | 7 | ||||||||||||
Adjusted Recurring Free Cash Flow(6) | $ | 463 | $ | 361 | $ | 523 | $ | 381 | ||||||||
Weighted average shares of common stock outstanding (diluted, in thousands) | 465,953 | 489,062 | 474,131 | 486,363 | ||||||||||||
Adjusted Recurring Free Cash Flow Per Share (Diluted) | $ | 0.99 | $ | 0.74 | $ | 1.10 | $ | 0.78 |
(1) | Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets. |
(2) | Included on our Consolidated Condensed Statements of Operations in (income) from unconsolidated investments in power plants. |
(3) | 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, 2012, and $1 million for each of the three and nine months ended September 30, 2011. |
(4) | 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 expenditures for the three and nine months ended September 30, 2012, respectively. Includes $36 million and $174 million in major maintenance expense for the three and nine months ended September 30, 2011, respectively, and $36 million and $161 million in maintenance capital expenditures for the three and nine months ended September 30, 2011, respectively. |
(5) | Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income. |
(6) | Excludes 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, and increases in working capital of $166 million and $21 million for the three and nine months ended September 30, 2011, respectively. Adjusted Recurring Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
(in millions) | ||||||||||||||||
Commodity Margin | $ | 897 | $ | 825 | $ | 2,023 | $ | 1,921 | ||||||||
Other revenue | 3 | 4 | 9 | 11 | ||||||||||||
Plant operating expense(1) | (167 | ) | (166 | ) | (518 | ) | (512 | ) | ||||||||
Sales, general and administrative expense(2) | (34 | ) | (30 | ) | (94 | ) | (85 | ) | ||||||||
Other operating expenses(3) | (9 | ) | (11 | ) | (30 | ) | (30 | ) | ||||||||
Adjusted EBITDA from unconsolidated investments in power plants(4) | 14 | 15 | 44 | 42 | ||||||||||||
Other | 2 | 1 | — | — | ||||||||||||
Adjusted EBITDA | $ | 706 | $ | 638 | $ | 1,434 | $ | 1,347 |
(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, RGGI compliance and other costs. |
(4) | Amount is comprised of income from unconsolidated investments in power plants, as well as adjustments to reflect Adjusted EBITDA from unconsolidated investments. |
Full Year 2012 Range: | Low | High | ||||||
(in millions) | ||||||||
GAAP Net Income (1) | $ | 250 | $ | 300 | ||||
Plus: | ||||||||
Debt extinguishment costs | 12 | 12 | ||||||
Loss on interest rate derivatives | 14 | 14 | ||||||
Interest expense, net of interest income | 760 | 760 | ||||||
Depreciation and amortization expense | 575 | 575 | ||||||
Major maintenance expense | 205 | 205 | ||||||
Operating lease expense | 35 | 35 | ||||||
(Gain) on sale of assets | (210 | ) | (210 | ) | ||||
Other(2) | 84 | 84 | ||||||
Adjusted EBITDA | $ | 1,725 | $ | 1,775 | ||||
Less: | ||||||||
Operating lease payments | 35 | 35 | ||||||
Major maintenance expense and maintenance capital expenditures(3) | 350 | 350 | ||||||
Accelerated parts purchases to support upgrades(4) | 30 | 30 | ||||||
Recurring cash interest, net(5) | 770 | 770 | ||||||
Cash taxes | 10 | 10 | ||||||
Other | 5 | 5 | ||||||
Adjusted Recurring Free Cash Flow | $ | 525 | $ | 575 | ||||
Non-recurring interest rate swap payments(6) | $ | (156 | ) | $ | (156 | ) |
(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 $200 million and maintenance capital expenditures of $150 million. Capital expenditures exclude major construction and development projects. 2012 figures exclude amounts to be funded by project debt. |
(4) | Incremental impact on 2012 maintenance capital expenditures related to acceleration of future turbine upgrades into 2012 and deferral of use of on-hand parts to post-2012 periods. |
(5) | Includes fees for letters of credit, net of interest income. |
(6) | Interest payments related to legacy LIBOR hedges associated with floating rate First Lien Credit Facility, which has been retired. |
Full Year 2013 Range(1): | Low | High | ||||
(in millions) | ||||||
GAAP Net Income (2) | $ | 135 | $ | 335 | ||
Plus: | ||||||
Interest expense, net of interest income | 745 | 745 | ||||
Depreciation and amortization expense | 575 | 575 | ||||
Major maintenance expense | 205 | 205 | ||||
Operating lease expense | 35 | 35 | ||||
Other(3) | 65 | 65 | ||||
Adjusted EBITDA | $ | 1,760 | $ | 1,960 | ||
Less: | ||||||
Operating lease payments | 35 | 35 | ||||
Major maintenance expense and maintenance capital expenditures(4) | 370 | 370 | ||||
Recurring cash interest, net(5) | 755 | 755 | ||||
Cash taxes | 15 | 15 | ||||
Other | 10 | 10 | ||||
Adjusted Recurring Free Cash Flow | $ | 575 | $ | 775 | ||
(1) | 2013 guidance range reflects all pending acquisition and divestiture activity, including today’s announced sale of Broad River Energy Center, which we estimate would have contributed approximately $40 million of Adjusted EBITDA in 2013. |
(2) | For purposes of Net Income guidance reconciliation, unrealized mark-to-market adjustments are assumed to be nil. |
(3) | Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax expense and other items. |
(4) | Includes projected major maintenance expense of $210 million and maintenance capital expenditures of $160 million. Capital expenditures exclude major construction and development projects. 2013 figures exclude non-recurring IT system upgrade. |
(5) | Includes fees for letters of credit, net of interest income. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||
Total MWh generated (in thousands)(1) | 32,291 | 28,400 | 87,027 | 65,921 | ||||||||
West | 9,817 | 6,540 | 24,211 | 16,189 | ||||||||
Texas | 10,025 | 10,833 | 28,257 | 24,019 | ||||||||
Southeast | 5,821 | 5,918 | 17,744 | 14,489 | ||||||||
North | 6,628 | 5,109 | 16,815 | 11,224 | ||||||||
Average availability | 97.7 | % | 95.9 | % | 91.5 | % | 89.8 | % | ||||
West | 98.5 | % | 91.2 | % | 91.2 | % | 86.4 | % | ||||
Texas | 97.2 | % | 98.2 | % | 90.4 | % | 88.8 | % | ||||
Southeast | 98.3 | % | 96.6 | % | 94.4 | % | 92.0 | % | ||||
North | 96.9 | % | 97.5 | % | 90.5 | % | 92.3 | % | ||||
Average capacity factor, excluding peakers(1) | 61.0 | % | 53.8 | % | 55.7 | % | 42.9 | % | ||||
West | 70.7 | % | 47.4 | % | 58.7 | % | 39.6 | % | ||||
Texas | 64.7 | % | 70.1 | % | 61.3 | % | 52.5 | % | ||||
Southeast | 48.4 | % | 48.9 | % | 49.6 | % | 41.0 | % | ||||
North | 56.1 | % | 43.4 | % | 49.7 | % | 34.4 | % | ||||
Steam adjusted heat rate (mmbtu/kWh) | 7,404 | 7,464 | 7,357 | 7,434 | ||||||||
West | 7,313 | 7,479 | 7,267 | 7,488 | ||||||||
Texas | 7,211 | 7,296 | 7,149 | 7,256 | ||||||||
Southeast | 7,325 | 7,344 | 7,302 | 7,323 | ||||||||
North | 7,943 | 8,003 | 7,918 | 7,939 |
(1) | Excludes generation from unconsolidated power plants and power plants owned but not operated by us. |