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(Mark One) | ||
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the fiscal year ended December 31, 2004 | ||
or | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to |
(1) Designated portions of the Proxy Statement relating to the 2005 Annual Meeting of Shareholders | Part III (Items 10, 11, 12, 13 and 14) |
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Item 1. | Business |
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• | Continue to focus on our liquidity position as our second highest priority after integrity; | |
• | Continue to improve our balance sheet through the extinguishment or repurchase of debt; | |
• | Complete our current construction program and start construction of new projects in strategic locations only when power contracts and financing are available and attractive returns are expected; | |
• | Put excess gas turbines to work in new projects, subject to the conditions stipulated above, or sell them; | |
• | Continue to lower operating and overhead costs per megawatt hour (“MWh”) produced and improve operating performance with an increasingly efficient power plant fleet; | |
• | Utilize our marketing and sales capabilities to selectively increase our power contract portfolio; and | |
• | Grow our services businesses to complement our integrated power operations. |
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Air Pollutant Emission Rates — Pounds of Pollutant Emitted per MWh of Electricity Generated | |||||||||||||||||||||
Average US | Calpine Power Plants | ||||||||||||||||||||
Coal, Oil & | |||||||||||||||||||||
Gas-Fired | Combined-Cycle | % Less Than | Geothermal | % Less Than | |||||||||||||||||
Air Pollutants | Power Plant (1) | Power Plant (2) | Avg US Plant | Power Plant (3) | Avg US Plant | ||||||||||||||||
Nitrogen Oxides, NOx | |||||||||||||||||||||
Acid rain, smog and fine particulate formation | 3.53 | 0.24 | 93.2% Less | 0.00074 | 99.9% Less | ||||||||||||||||
Sulphur Dioxide, SO2 | |||||||||||||||||||||
Acid rain and fine particulate formation | 8.51 | 0.005 | 99.9% Less | 0.00015 | 99.9% Less | ||||||||||||||||
Mercury, Hg | |||||||||||||||||||||
Neurotoxin | 0.000037 | 0 | 100% Less | 0.000008 | 78.4% Less | ||||||||||||||||
Carbon Dioxide, CO2 | |||||||||||||||||||||
Principal greenhouse gas — contributor to climate change | 1,930 | 890 | 53.9% Less | 85.6 | 95.6% Less | ||||||||||||||||
Particulate Matter, PM | |||||||||||||||||||||
Respiratory health effects | 0.5 | 0.038 | 92.4% Less | 0.014 | 97.2% Less |
(1) | The US fossil fuel fleet’s emission rates were obtained from the United States Department of Energy’s Electric Power Annual Report for 2003. Emission rates are based on 2003 emissions and net generation. |
(2) | Calpine’s combined-cycle power plant emission rates are based on 2003 data. |
(3) | Calpine’s geothermal power plant emission rates are based on 2003 data and include expected results from the mercury abatement program currently in process. |
• | Calpine’s Board of Directors unanimously adopted a resolution restricting investments in low carbon dioxide emitting power plants. | |
• | PSM is developing gas turbine components to improve turbine efficiency and to reduce emissions. | |
• | Calpine Power Company has instituted a program of proprietary operating procedures to reduce gas consumption and lower air pollutant emissions per MWh of electricity generated. | |
• | Calpine and its Chairman, President and CEO, Peter Cartwright, received the designation of “Clean Air Champion” from the New York League of Conservation Voters in recognition of our efforts to improve the quality of New York’s air. | |
• | Peter Cartwright was recognized as the “Business Leader of the Year” byScientific American Magazinefor his commitment to low carbon technologies. |
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• | The American Lung Associations of the Bay Area selected Calpine and its Geysers geothermal operation for the 2004 Clean Air Award for Technology Development to recognize “Calpine’s commitment to clean renewable energy, which improves air quality and helps us all breathe easier.” | |
• | Calpine and General Electric Co. teamed up for the North America launch of GE’s most advanced gas turbine technology, theH Systemtm, which will utilize a more efficient gas turbine combined-cycle system. The 775-MW project located in Southern California is expected to enter commercial operation in 2008. | |
• | Calpine joined the US Environmental Protection Agency’s Climate Leaders Program, which is intended to encourage climate change strategies, help establish future greenhouse gas (“GHG”) emission reduction goals, and increase energy efficiency among participants. As part of Climate Leaders, Calpine will submit data on 2003 carbon dioxide (CO2) emissions from all its natural gas-fired power plants, for The Geysers — Calpine’s geothermal power generating plants in Northern California, and for Calpine natural gas production facilities located throughout the United States. | |
• | Calpine became the first independent power producer to earn the distinction ofClimate Action Leadertm by certifying its 2003 CO2 emissions inventory with the California Climate Action Registry. Calpine is now publicly and voluntarily reporting its CO2 emissions from generation of electricity in California under this rigorous registry program. |
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Market Share | ||||||||||||
NERC Region/ Country | Projects | Megawatts | (NERC/UK) | |||||||||
WECC | 49 | 8,382 | 5 | % | ||||||||
ERCOT | 12 | 7,572 | 9 | % | ||||||||
SERC | 11 | 6,365 | 4 | % | ||||||||
MAIN | 5 | 2,292 | 3 | % | ||||||||
SPP | 3 | 1,674 | 4 | % | ||||||||
NEPOOL | 5 | 1,272 | 4 | % | ||||||||
FRCC | 3 | 875 | 2 | % | ||||||||
MAAC | 5 | 865 | 1 | % | ||||||||
ECAR | 1 | 700 | * | |||||||||
MAPP | 1 | 375 | 1 | % | ||||||||
NYPOOL | 5 | 334 | 1 | % | ||||||||
NPCC | 1 | 7 | * | |||||||||
TOTAL NERC | 101 | 30,713 | 3 | % | ||||||||
UK | 1 | 1,200 | 2 | % | ||||||||
Mexico | 1 | 236 | 1 | % | ||||||||
TOTAL | 103 | 32,149 | 3 | % | ||||||||
* | less than 1%. |
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Megawatts | ||||||||||||||||||||||
Calpine Net | ||||||||||||||||||||||
With | Calpine Net | Interest | ||||||||||||||||||||
Number | Baseload | Peaking | Interest | with | ||||||||||||||||||
of Plants | Capacity | Capacity | Baseload | Peaking | ||||||||||||||||||
In operation | ||||||||||||||||||||||
Geothermal power plants | 19 | 750 | 750 | 750 | 750 | |||||||||||||||||
Gas-fired power plants | 73 | 21,930 | 27,189 | 20,753 | 25,899 | |||||||||||||||||
Under construction | ||||||||||||||||||||||
New facilities | 11 | 5,181 | 5,789 | 4,892 | 5,500 | |||||||||||||||||
Total | 103 | 27,861 | 33,728 | 26,395 | 32,149 | |||||||||||||||||
Country, | Calpine Net | ||||||||||||||||||||||||||||
US | With | Calpine Net | Interest | ||||||||||||||||||||||||||
State or | Baseload | Peaking | Calpine | Interest | with | Total 2004 | |||||||||||||||||||||||
Can. | Capacity | Capacity | Interest | Baseload | Peaking | Generation | |||||||||||||||||||||||
Power Plant | Province | (MW) | (MW) | Percentage | (MW) | (MW) | MWh(1) | ||||||||||||||||||||||
Geothermal Power Plants | |||||||||||||||||||||||||||||
Sonoma County (12 plants) | CA | 456.0 | 456.0 | 100.0 | % | 456.0 | 456.0 | 4,135,181 | |||||||||||||||||||||
Lake County (2 plants) | CA | 131.0 | 131.0 | 100.0 | % | 131.0 | 131.0 | 1,114,292 | |||||||||||||||||||||
Calistoga | CA | 70.0 | 70.0 | 100.0 | % | 70.0 | 70.0 | 620,520 | |||||||||||||||||||||
Sonoma | CA | 35.0 | 35.0 | 100.0 | % | 35.0 | 35.0 | 375,733 | |||||||||||||||||||||
West Ford Flat | CA | 26.0 | 26.0 | 100.0 | % | 26.0 | 26.0 | 227,453 | |||||||||||||||||||||
Bear Canyon | CA | 16.0 | 16.0 | 100.0 | % | 16.0 | 16.0 | 142,204 | |||||||||||||||||||||
Aidlin | CA | 16.0 | 16.0 | 100.0 | % | 16.0 | 16.0 | 139,256 | |||||||||||||||||||||
Total Geothermal Power Plants (19) | 750.0 | 750.0 | 750.0 | 750.0 | 6,754,639 | ||||||||||||||||||||||||
Gas-Fired Power Plants | |||||||||||||||||||||||||||||
Saltend Energy Centre | UK | 1,200.0 | 1,200.0 | 100.0 | % | 1,200.0 | 1,200.0 | 9,008,046 | |||||||||||||||||||||
Freestone Energy Center | TX | 1,022.0 | 1,022.0 | 100.0 | % | 1,022.0 | 1,022.0 | 4,569,089 | |||||||||||||||||||||
Deer Park Energy Center | TX | 792.0 | 1,019.0 | 100.0 | % | 792.0 | 1,019.0 | 4,798,265 | |||||||||||||||||||||
Oneta Energy Center | OK | 994.0 | 994.0 | 100.0 | % | 994.0 | 994.0 | 827,661 | |||||||||||||||||||||
Delta Energy Center | CA | 799.0 | 882.0 | 100.0 | % | 799.0 | 882.0 | 5,765,080 | |||||||||||||||||||||
Morgan Energy Center | AL | 722.0 | 852.0 | 100.0 | % | 722.0 | 852.0 | 848,933 | |||||||||||||||||||||
Decatur Energy Center | AL | 793.0 | 852.0 | 100.0 | % | 793.0 | 852.0 | 311,531 | |||||||||||||||||||||
Baytown Energy Center | TX | 742.0 | 830.0 | 100.0 | % | 742.0 | 830.0 | 4,632,478 | |||||||||||||||||||||
Broad River Energy Center | SC | — | 847.0 | 100.0 | % | — | 847.0 | 426,705 | |||||||||||||||||||||
Pasadena Power Plant | TX | 776.0 | 777.0 | 100.0 | % | 776.0 | 777.0 | 3,932,210 | |||||||||||||||||||||
Magic Valley Generating Station | TX | 700.0 | 751.0 | 100.0 | % | 700.0 | 751.0 | 2,802,004 | |||||||||||||||||||||
Hermiston Power Project | OR | 546.0 | 642.0 | 100.0 | % | 546.0 | 642.0 | 4,073,944 | |||||||||||||||||||||
Columbia Energy Center | SC | 464.0 | 641.0 | 100.0 | % | 464.0 | 641.0 | 542,376 | |||||||||||||||||||||
Rocky Mountain Energy Center | CO | 479.0 | 621.0 | 100.0 | % | 479.0 | 621.0 | 2,080,538 | |||||||||||||||||||||
Osprey Energy Center | FL | 530.0 | 609.0 | 100.0 | % | 530.0 | 609.0 | 1,492,792 | |||||||||||||||||||||
Acadia Energy Center | LA | 1,092.0 | 1,210.0 | 50.0 | % | 546.0 | 605.0 | 2,521,934 | |||||||||||||||||||||
Riverside Energy Center | WI | 518.0 | 603.0 | 100.0 | % | 518.0 | 603.0 | 689,659 |
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Country, | Calpine Net | |||||||||||||||||||||||||||
US | With | Calpine Net | Interest | |||||||||||||||||||||||||
State or | Baseload | Peaking | Calpine | Interest | with | Total 2004 | ||||||||||||||||||||||
Can. | Capacity | Capacity | Interest | Baseload | Peaking | Generation | ||||||||||||||||||||||
Power Plant | Province | (MW) | (MW) | Percentage | (MW) | (MW) | MWh(1) | |||||||||||||||||||||
Aries Power Project | MO | 523.0 | 590.0 | 100.0 | % | 523.0 | 590.0 | 839,176 | ||||||||||||||||||||
Ontelaunee Energy Center | PA | 561.0 | 584.0 | 100.0 | % | 561.0 | 584.0 | 1,343,393 | ||||||||||||||||||||
Channel Energy Center | TX | 527.0 | 574.0 | 100.0 | % | 527.0 | 574.0 | 3,467,759 | ||||||||||||||||||||
Brazos Valley Power Plant | TX | 450.0 | 570.0 | 100.0 | % | 450.0 | 570.0 | 2,441,071 | ||||||||||||||||||||
Los Medanos Energy Center | CA | 497.0 | 566.0 | 100.0 | % | 497.0 | 566.0 | 3,683,759 | ||||||||||||||||||||
Sutter Energy Center | CA | 535.0 | 543.0 | 100.0 | % | 535.0 | 543.0 | 3,475,986 | ||||||||||||||||||||
Corpus Christi Energy Center | TX | 414.0 | 537.0 | 100.0 | % | 414.0 | 537.0 | 2,297,928 | ||||||||||||||||||||
Texas City Power Plant | TX | 457.0 | 534.0 | 100.0 | % | 457.0 | 534.0 | 2,389,041 | ||||||||||||||||||||
Carville Energy Center | LA | 455.0 | 531.0 | 100.0 | % | 455.0 | 531.0 | 1,755,790 | ||||||||||||||||||||
South Point Energy Center | AZ | 520.0 | 530.0 | 100.0 | % | 520.0 | 530.0 | 2,900,047 | ||||||||||||||||||||
Westbrook Energy Center | ME | 528.0 | 528.0 | 100.0 | % | 528.0 | 528.0 | 3,451,414 | ||||||||||||||||||||
Zion Energy Center | IL | — | 513.0 | 100.0 | % | — | 513.0 | 29,978 | ||||||||||||||||||||
RockGen Energy Center | WI | — | 460.0 | 100.0 | % | — | 460.0 | 240,072 | ||||||||||||||||||||
Clear Lake Power Plant | TX | 344.0 | 400.0 | 100.0 | % | 344.0 | 400.0 | 1,397,923 | ||||||||||||||||||||
Hidalgo Energy Center | TX | 392.0 | 392.0 | 78.5 | % | 307.7 | 307.7 | 1,931,793 | ||||||||||||||||||||
Blue Spruce Energy Center | CO | — | 285.0 | 100.0 | % | — | 285.0 | 149,316 | ||||||||||||||||||||
Goldendale Energy Center | WA | 237.0 | 271.0 | 100.0 | % | 237.0 | 271.0 | 210,601 | ||||||||||||||||||||
Tiverton Power Plant | RI | 267.0 | 267.0 | 100.0 | % | 267.0 | 267.0 | 1,860,478 | ||||||||||||||||||||
Rumford Power Plant | ME | 263.0 | 263.0 | 100.0 | % | 263.0 | 263.0 | 1,664,835 | ||||||||||||||||||||
Santa Rosa Energy Center | FL | 250.0 | 250.0 | 100.0 | % | 250.0 | 250.0 | 17,848 | ||||||||||||||||||||
Hog Bayou Energy Center | AL | 235.0 | 237.0 | 100.0 | % | 235.0 | 237.0 | 120,000 | ||||||||||||||||||||
Pine Bluff Energy Center | AR | 184.0 | 215.0 | 100.0 | % | 184.0 | 215.0 | 1,450,765 | ||||||||||||||||||||
Los Esteros Critical Energy Center | CA | — | 188.0 | 100.0 | % | — | 188.0 | 278,873 | ||||||||||||||||||||
Dighton Power Plant | MA | 170.0 | 170.0 | 100.0 | % | 170.0 | 170.0 | 639,784 | ||||||||||||||||||||
Morris Power Plant | IL | 137.0 | 156.0 | 100.0 | % | 137.0 | 156.0 | 562,882 | ||||||||||||||||||||
Auburndale Power Plant | FL | 150.0 | 150.0 | 100.0 | % | 150.0 | 150.0 | 901,206 | ||||||||||||||||||||
Gilroy Peaking Energy Center | CA | — | 135.0 | 100.0 | % | — | 135.0 | 72,388 | ||||||||||||||||||||
Gilroy Power Plant | CA | 117.0 | 128.0 | 100.0 | % | 117.0 | 128.0 | 274,311 | ||||||||||||||||||||
King City Power Plant | CA | 120.0 | 120.0 | 100.0 | % | 120.0 | 120.0 | 952,050 | ||||||||||||||||||||
Parlin Power Plant | NJ | 98.0 | 118.0 | 100.0 | % | 98.0 | 118.0 | 109,994 | ||||||||||||||||||||
Auburndale Peaking Energy Center | FL | — | 116.0 | 100.0 | % | — | 116.0 | 9,495 | ||||||||||||||||||||
Kennedy International Airport Power Plant (“KIAC”) | NY | 99.0 | 105.0 | 100.0 | % | 99.0 | 105.0 | 577,632 | ||||||||||||||||||||
Pryor Power Plant | OK | 38.0 | 90.0 | 100.0 | % | 38.0 | 90.0 | 342,127 | ||||||||||||||||||||
Grays Ferry Power Plant | PA | 166.0 | 175.0 | 50.0 | % | 83.0 | 87.5 | 618,319 | ||||||||||||||||||||
Calgary Energy Centre | AB | 252.0 | 286.0 | 30.0 | % | 75.6 | 85.8 | 891,629 | ||||||||||||||||||||
Island Cogeneration | BC | 219.0 | 250.0 | 30.0 | % | 65.7 | 75.0 | 1,663,518 | ||||||||||||||||||||
Pittsburg Power Plant | CA | 64.0 | 64.0 | 100.0 | % | 64.0 | 64.0 | 211,005 | ||||||||||||||||||||
Bethpage Power Plant | NY | 55.0 | 56.0 | 100.0 | % | 55.0 | 56.0 | 271,594 | ||||||||||||||||||||
Newark Power Plant | NJ | 50.0 | 56.0 | 100.0 | % | 50.0 | 56.0 | 203,019 | ||||||||||||||||||||
Greenleaf 1 Power Plant | CA | 49.5 | 49.5 | 100.0 | % | 49.5 | 49.5 | 341,427 | ||||||||||||||||||||
Greenleaf 2 Power Plant | CA | 49.5 | 49.5 | 100.0 | % | 49.5 | 49.5 | 328,262 |
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Country, | Calpine Net | ||||||||||||||||||||||||||||
US | With | Calpine Net | Interest | ||||||||||||||||||||||||||
State or | Baseload | Peaking | Calpine | Interest | with | Total 2004 | |||||||||||||||||||||||
Can. | Capacity | Capacity | Interest | Baseload | Peaking | Generation | |||||||||||||||||||||||
Power Plant | Province | (MW) | (MW) | Percentage | (MW) | (MW) | MWh(1) | ||||||||||||||||||||||
Wolfskill Energy Center | CA | — | 48.0 | 100.0 | % | — | 48.0 | 21,900 | |||||||||||||||||||||
Yuba City Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 18,558 | |||||||||||||||||||||
Feather River Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 17,034 | |||||||||||||||||||||
Creed Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 10,483 | |||||||||||||||||||||
Lambie Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 16,156 | |||||||||||||||||||||
Goose Haven Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 11,193 | |||||||||||||||||||||
Riverview Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 17,637 | |||||||||||||||||||||
Stony Brook Power Plant | NY | 45.0 | 47.0 | 100.0 | % | 45.0 | 47.0 | 329,168 | |||||||||||||||||||||
Bethpage Peaking Energy Center | NY | — | 46.0 | 100.0 | % | — | 46.0 | 112,033 | |||||||||||||||||||||
King City Peaking Energy Center | CA | — | 45.0 | 100.0 | % | — | 45.0 | 21,545 | |||||||||||||||||||||
Androscoggin Energy Center | ME | 136.0 | 136.0 | 32.3 | % | 44.0 | 44.0 | 680,898 | |||||||||||||||||||||
Watsonville Power Plant | CA | 29.0 | 30.0 | 100.0 | % | 29.0 | 30.0 | 206,244 | |||||||||||||||||||||
Agnews Power Plant | CA | 28.0 | 28.0 | 100.0 | % | 28.0 | 28.0 | 197,810 | |||||||||||||||||||||
Philadelphia Water Project | PA | — | 23.0 | 83.0 | % | — | 19.1 | — | |||||||||||||||||||||
Whitby Cogeneration | ON | 50.0 | 50.0 | 15.0 | % | 7.5 | 7.5 | — | |||||||||||||||||||||
Total Gas-Fired Power Plants(73) | 21,930.0 | 27,189.0 | 20,753.0 | 25,899.0 | 97,371,392 | ||||||||||||||||||||||||
Total Operating Power Plants(92) | 22,680.0 | 27,939.0 | 21,503.0 | 26,649.0 | 104,126,031 | ||||||||||||||||||||||||
Consolidated Projects including plants with operating leases | 21,236.0 | 26,368.0 | 20,822.0 | 25,905.0 | |||||||||||||||||||||||||
Equity (Unconsolidated) Projects | 1,444.0 | 1,571.0 | 681.0 | 744.0 |
(1) | Generation MWh is shown here as 100% of each plant’s gross generation in MWh. |
Calpine Net | |||||||||||||||||||||||||
With | Calpine Net | Interest | |||||||||||||||||||||||
Baseload | Peaking | Calpine | Interest | With | |||||||||||||||||||||
Capacity | Capacity | Interest | Baseload | Peaking | |||||||||||||||||||||
Power Plant | US State | (MW) | (MW) | Percentage | (MW) | (MW) | |||||||||||||||||||
Projects Under Construction | |||||||||||||||||||||||||
Hillabee Energy Center | AL | 710.0 | 770.0 | 100.0 | % | 710.0 | 770.0 | ||||||||||||||||||
Pastoria Energy Center | CA | 759.0 | 769.0 | 100.0 | % | 759.0 | 769.0 | ||||||||||||||||||
Fremont Energy Center | OH | 550.0 | 700.0 | 100.0 | % | 550.0 | 700.0 | ||||||||||||||||||
Metcalf Energy Center | CA | 556.0 | 602.0 | 100.0 | % | 556.0 | 602.0 | ||||||||||||||||||
Otay Mesa Energy Center | CA | 510.0 | 593.0 | 100.0 | % | 510.0 | 593.0 | ||||||||||||||||||
Washington Parish Energy Center | LA | 509.0 | 565.0 | 100.0 | % | 509.0 | 565.0 | ||||||||||||||||||
Fox Energy Center | WI | 490.0 | 560.0 | 100.0 | % | 490.0 | 560.0 | ||||||||||||||||||
Mankato Power Plant | MN | 292.0 | 375.0 | 100.0 | % | 292.0 | 375.0 | ||||||||||||||||||
Freeport Energy Center | TX | 200.0 | 250.0 | 100.0 | % | 200.0 | 250.0 | ||||||||||||||||||
Valladolid III Energy Center | Mexico | 525.0 | 525.0 | 45.0 | % | 236.3 | 236.3 | ||||||||||||||||||
Bethpage Energy Center 3 | NY | 79.9 | 79.9 | 100.0 | % | 79.9 | 79.9 | ||||||||||||||||||
Total Projects Under Construction | 5,180.9 | 5,788.9 | 4,892.2 | 5,500.2 | |||||||||||||||||||||
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PURPA |
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• | limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our growth strategy, or other purposes; | |
• | limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt; | |
• | increasing our vulnerability to general adverse economic and industry conditions; | |
• | limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in government regulation; | |
• | limiting our ability or increasing the costs to refinance indebtedness; and | |
• | limiting our ability to enter into marketing, hedging, optimization and trading transactions by reducing the number of counterparties with whom we can transact as well as the volume of those transactions. |
• | incur additional indebtedness and issue preferred stock; | |
• | make prepayments on or purchase indebtedness in whole or in part; | |
• | pay dividends and other distributions with respect to our capital stock or repurchase our capital stock or make other restricted payments; | |
• | make certain investments; | |
• | enter into transactions with affiliates; | |
• | create or incur liens to secure debt; | |
• | consolidate or merge with another entity, or allow one of our subsidiaries to do so; | |
• | lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales; |
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• | incur dividend or other payment restrictions affecting certain subsidiaries; | |
• | make capital expenditures; | |
• | engage in certain business activities; and | |
• | acquire facilities or other businesses. |
• | Certain of our indentures place conditions on our ability to issue indebtedness if our interest coverage ratio (as defined in those indentures) is below 2:1. Currently, our interest coverage ratio (as so defined) is below 2:1 and, consequently, we generally would not be allowed to issue new debt, except for (i) certain types of new indebtedness that refinances or replaces existing indebtedness, and (ii) non-recourse debt and preferred equity interests issued by our subsidiaries for purposes of financing certain types of capital expenditures, including plant development, construction and acquisition expenses. In addition, if and so long as our interest coverage ratio is below 2:1, our ability to invest in unrestricted subsidiaries and non-subsidiary affiliates and make certain other types of restricted payments will be limited. Moreover, certain of our indentures will prohibit any further investments in non-subsidiary affiliates if and for so long as our interest coverage ratio (as defined therein) is below 1.75:1 and, as of December 31, 2004, such interest coverage ratio had fallen below 1.75:1. | |
• | Certain of our indebtedness issued in the last half of 2004 was permitted under our indentures on the basis that the proceeds would be used to repurchase or redeem existing indebtedness. While we completed a portion of such repurchases during the fourth quarter of 2004 and the first quarter of 2005, we are still in the process of completing the required amount of repurchases. While the amount of indebtedness that must still be repurchased will ultimately depend on the market price of our outstanding indebtedness at the time the indebtedness is repurchased, based on current market conditions, we currently anticipate that we will spend up to approximately $202.9 million on additional repurchases in order to fully satisfy this requirement. Our bond purchase requirement was estimated to be approximately $270 million as of December 31, 2004, and this amount has been classified as a current liability on our consolidated balance sheet. | |
• | When we or one of our subsidiaries sells a significant asset or issues preferred equity, our indentures generally require that the net proceeds of the transaction be used to make capital expenditures or to repurchase or repay certain types of subsidiary indebtedness, in each case within 365 days of the closing date of the transaction. In light of this requirement, and taking into account the amount of capital expenditures currently budgeted for 2005, we anticipate that we will need to use approximately $250.0 million of the net proceeds of the $360.0 million Two-Year Redeemable Preferred Shares issued on October 26, 2004 and approximately $200.0 million of the net proceeds of the $260.0 million Redeemable Preferred Shares issued on January 31, 2005, to repurchase or repay certain subsidiary indebtedness. The $250.0 million has been classified as a current liability on our consolidated balance sheet as of December 31, 2004. The actual amount of the net proceeds that will be required to be used to repurchase or repay subsidiary debt will depend upon the actual amount of the net proceeds that is used to make capital expenditures, which may be more or less than the amount currently budgeted. |
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• | general economic and capital market conditions; | |
• | conditions in energy markets; | |
• | regulatory developments; | |
• | credit availability from banks or other lenders for us and our industry peers, as well as the economy in general; | |
• | investor confidence in the industry and in us; | |
• | the continued success of our current power generation facilities; and | |
• | provisions of tax and securities laws that are conducive to raising capital. |
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• | necessary power generation equipment; | |
• | governmental permits and approvals; | |
• | fuel supply and transportation agreements; | |
• | sufficient equity capital and debt financing; | |
• | electrical transmission agreements; | |
• | water supply and wastewater discharge agreements; and | |
• | site agreements and construction contracts. |
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• | start-up problems; | |
• | the breakdown or failure of equipment or processes; and | |
• | performance below expected levels of output or efficiency. |
• | the cessation or abandonment of the development, construction, maintenance or operation of the facility; | |
• | failure of the facility to achieve construction milestones by agreed upon deadlines, subject to extensions due to force majeure events; | |
• | failure of the facility to achieve commercial operation by agreed upon deadlines, subject to extensions due to force majeure events; | |
• | failure of the facility to achieve certain output minimums; | |
• | failure by the facility to make any of the payments owing to the utility under the PSA or to establish, maintain, restore, extend the term of, or increase the posted security if required by the PSA; | |
• | a material breach of a representation or warranty or failure by the facility to observe, comply with or perform any other material obligation under the PSA; | |
• | failure of the facility to obtain material permits and regulatory approvals by agreed upon deadlines; or | |
• | the liquidation, dissolution, insolvency or bankruptcy of the project entity. |
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• | the heat content of the extractable steam or fluids; | |
• | the geology of the reservoir; | |
• | the total amount of recoverable reserves; | |
• | operating expenses relating to the extraction of steam or fluids; | |
• | price levels relating to the extraction of steam or fluids or power generated; and | |
• | capital expenditure requirements relating primarily to the drilling of new wells. |
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• | fluctuations in currency valuation; | |
• | currency inconvertibility; | |
• | expropriation and confiscatory taxation; | |
• | increased regulation; and | |
• | approval requirements and governmental policies limiting returns to foreign investors. |
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• | seasonal variations in energy prices; | |
• | variations in levels of production; | |
• | the timing and size of acquisitions; and | |
• | the completion of development and construction projects. |
• | general conditions in our industry, the power markets in which we participate, or the worldwide economy; | |
• | announcements of developments related to our business or sector; | |
• | fluctuations in our results of operations; | |
• | our debt-to-equity ratios and other leverage ratios; | |
• | effects of significant events relating to the energy sector in general; |
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• | issuances, including though sales or lending facilities, of substantial amounts of our common stock or other securities into the marketplace; | |
• | dilution or potential dilution caused by stock-for-debt exchanges or issuances of indebtedness convertible into our common stock, including any exchanges or convertible debt transactions relating to the outstanding HIGH TIDES III; | |
• | an outbreak of war or hostilities; | |
• | a shortfall in revenues or earnings compared to securities analysts’ expectations; | |
• | changes in analysts’ recommendations or projections; and | |
• | announcements of new acquisitions or development projects by us. |
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Summary of Key Activities |
Finance — New Issuances and Amendments: |
Date | Amount | Description | ||||||
1/9/04 | $ | 250.0 million | An initial purchaser of the 4.75% Convertible Senior Notes due 2023 exercises in full its purchase option | |||||
2/20/04 | $ | 250.0 million | Complete a non-recourse project financing for Rocky Mountain Energy Center at a rate of LIBOR plus 250 basis points, refinanced in June 2004 | |||||
3/23/04 | $ | 2.6 billion | CalGen completes its offering of secured institutional term loans, notes and revolving credit facility | |||||
4/26/04 | Successfully complete consent solicitation to effect certain amendments to the Indentures governing the Senior Notes issued between 1996 and 1999 | |||||||
6/2/04 | $ | 85.0 million | Power Contract Financing III, LLC issues zero coupon notes | |||||
6/29/04 | $ | 661.5 million | Rocky Mountain Energy Center, LLC, and Riverside Energy Center, LLC, close an offering of First Priority Secured Floating Rate Term Loans Due 2011 and a letter of credit-linked deposit facility | |||||
8/5/04 | $ | 250.0 million | Calpine Energy Management, L.P. enters into a letter of credit facility with Deutsche Bank that expires October 2005 | |||||
9/30/04 | $ | 785.0 million | Receive funding on offering of 95/8% First Priority Senior Secured Notes due 2014, offered at 99.212% of par | |||||
9/30/04 | $ | 736.0 million | Receive funding on offering of Contingent Convertible Notes due 2014 offered at 83.9% of par | |||||
9/30/04 | Enter into a ten-year Share Lending Agreement, loaning 89 million shares of newly issued Calpine common stock to Deutsche Bank AG London in connection with the issuance of the Contingent Convertible Notes due 2014 | |||||||
9/30/04 | $ | 255.0 million | Establish a new Cash Collateralized Letter of Credit Facility with Bayerische Landesbank | |||||
10/26/04 | $ | 360.0 million | Calpine (Jersey) Limited completes an offering of Two-Year Redeemable Preferred Shares priced at 3-month US LIBOR plus 700 basis points |
Finance — Repurchases and Extinguishments: |
Date | Amount | Description | ||||||
5/04 | $ | 78.8 million | Retirement of Newark and Parlin Power Plants project financing | |||||
5/04 | $ | 82.0 million | Redemption of King City preferred interest due to lease restructuring | |||||
9/04 | $ | 266.2 million | Repurchase $266.2 million in principal amount of outstanding 4.75% Convertible Senior Notes due 2023 in exchange for $177.0 million in cash | |||||
9/04 | $ | 115.0 million | Repurchase $115.0 million par value of HIGH TIDES III for $111.6 million in cash | |||||
9/04 | $ | 199.5 million | Mandatory paydown of 51/8% First Priority Senior Secured Term Loan B due 2007 pursuant to debt covenants governing asset sales of natural gas reserves | |||||
9/04 | $ | 100.0 million | Mandatory paydown of 55/8% First Priority Letter of Credit Facility pursuant to covenants governing asset sales of natural gas reserves | |||||
10/04 | $ | 276.0 million | Redeem outstanding 53/4% HIGH TIDES I preferred securities | |||||
10/04 | $ | 360.0 million | Redeem outstanding 51/2% HIGH TIDES II preferred securities | |||||
4/04-7/04 | $ | 95.0 million | Exchange 24.3 million Calpine common shares in privately negotiated transactions for approximately $40.0 million par value of HIGH TIDES I and approximately $75.0 million par value of HIGH TIDES II | |||||
1/04-12/04 | $ | 658.7 million | Repurchase $658.7 million in principal amount of outstanding 2006 Convertible Senior Notes for $657.7 million in cash | |||||
1/04-12/04 | $743.4 million | Repurchase $743.4 million in principal of amount various Senior Notes issuances for $559.3 million in cash |
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Asset Sales and Other: |
Date | Description | |||
1/04 | Complete sale of 50% interest in Lost Pines 1 Power Project for a cash payment of $148.6 million | |||
2/04 | Close on the sale of natural gas properties to CNGT for a net cash payment of Cdn$33.8 million (US$29.2 million) | |||
2/04 | Enter into a one-year agreement with Cleco Power LLC to supply up to 500 MW of electricity | |||
2/04 | Enter into five power sales contracts to supply approximately 350 MW of electricity to five New England- based electric distribution companies for delivery in 2004 | |||
3/04 | Enter into a 20-year purchase power agreement to provide 365 MW of electricity to Northern States Power | |||
3/04 | Acquire the remaining 50% interest in the Aries Power Plant from Aquila, Inc. | |||
3/04 | Complete the acquisition of the remaining 20% interest in Calpine Cogeneration Company for approximately $2.5 million | |||
3/04 | Enter into a three-year power sales agreement with Safeway Inc. to supply up to 200 MW of electricity to Safeway facilities throughout California | |||
3/04 | Close on the purchase of Brazos Valley Power Plant for approximately $181.1 million in a tax deferred like-kind exchange under IRS Section 1031, largely with the proceeds of the Lost Pines I Power Project sale | |||
5/04 | Restructure King City lease | |||
5/04 | Sign a 25-year agreement to sell up to 200 MW of electricity and 1 million pounds per hour of steam to The Dow Chemical Company | |||
5/04 | Existing JCPL tolling arrangements with the Newark and Parlin Power Plants are terminated, resulting in a gain of $100.6 million before transaction costs | |||
5/04 | Sell Utility Contract Funding II, a wholly-owned subsidiary of CES, which had entered into a long-term power purchase agreement related to Newark and Parlin Power Plants, for a pre-tax gain of $85.4 million before transaction costs | |||
6/04 | Receive approval from the CPUC for a tolling agreement with San Diego Gas and Electric Company that provides for the delivery of up to 615 MW of capacity for ten years beginning in 2008 | |||
6/04 | Partially terminate the gas contract between Citrus Trading Corp. and the Auburndale facility for a net gain of $11.7 million | |||
7/04 | Enter into a five and a half year agreement with Snapping Shoals EMC for 200 MW of capacity and electricity | |||
7/04 | Announce the amendment of an eleven-year tolling agreement with Wisconsin Public Service for up to 500 MW of capacity, electricity and ancillary services, subject to approval by the Public Service Commission of Wisconsin | |||
9/04 | Complete sale of natural gas reserves in Colorado Piceance Basin and New Mexico San Juan Basin for net cash payments of approximately $218.7 million | |||
9/04 | Complete sale of all Canadian natural gas reserves and petroleum assets and interest in CNGT for cash payments of approximately Cdn$808.1 million (US$626.4 million) | |||
10/04 | Announce energy service agreement with Newmarket Services Company, LLC | |||
11/04 | Sign a letter of intent with GE Energy for joint construction of the world’s first power plant based on the 60-hertz version of GE’s most advanced gas turbine technology, theH Systemtm | |||
11/04 | Announce CPSI awarded contract to operate and maintain two Hoosier Energy natural gas-fired power plants | |||
12/04 | Announce two-year power sales contract with National Aeronautics and Space Administration Johnson Space Center in Houston, Texas, for an estimated peak load of up to 23 MW a day of electricity |
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Power Plant Development and Construction: |
Date | Project | Description | ||||||
1/04 | Morgan Energy Center Expansion | Commercial operation | ||||||
5/04 | Osprey Energy Center | Commercial operation | ||||||
5/04 | Columbia Energy Center | Commercial operation | ||||||
5/04 | Rocky Mountain Energy Center | Commercial operation | ||||||
5/04 | Valladolid III IP | Construction began | ||||||
6/04 | Riverside Energy Center | Commercial operation | ||||||
6/04 | Deer Park Energy Center Expansion | Commercial operation | ||||||
6/04 | Freeport Energy Center | Construction began | ||||||
9/04 | Goldendale Energy Center | Commercial operation |
Annual Meeting of Stockholders on May 26, 2004 |
Stockholders’ Voting Results |
• | Proposal to amend the Company’s Amended and Restated Certificate of Incorporation to increase the number of authorized shares of Common Stock — approved | |
• | Proposal to amend the Company’s 1996 Stock Incentive Plan to increase the number of shares of the Company’s Common Stock available for grants of options and other stock-based awards under such plan — approved | |
• | Proposal to amend the Company’s 2000 Employee Stock Purchase Plan to increase the number of shares of the Company’s Common Stock available for grants of purchase rights under such plan — approved | |
• | Proposal that the Company cease and desist geothermal development activities in the Medicine Lake Highlands and requesting the Company to adopt an indigenous peoples policy — rejected | |
• | Proposal that the Company’s Compensation Committee of its Board of Directors utilize performance and time-based restricted share programs in lieu of stock options in developing future senior executive equity compensation plans — rejected | |
• | Proposal requesting the Company’s Board of Directors to study and report on the feasibility of enabling stockholders to imitate the voting decisions of an institutional investor — rejected | |
• | Ratification of the appointment of PricewaterhouseCoopers LLP as independent registered public accounting firm for the fiscal year ending December 31, 2004 — approved |
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Item 2. | Properties |
As of December 31, 2004 | |||||||||
Oil and NGLs | |||||||||
(MMBbls) | Gas (Bcf) | ||||||||
United States | |||||||||
Proved developed | 1.4 | 255 | |||||||
Proved undeveloped | 1.2 | 118 | |||||||
Total | 2.6 | (1) | 373 | ||||||
(1) | 2.6 MMBbls of oil is equivalent to 15.6 Bcf of gas using a conversion factor of six thousand cubic feet of gas to one barrel of crude oil and natural gas liquids. On an equivalent basis, proved reserves at year-end totaled 389 Bcfe. |
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Productive | ||||||||||||||||||||||||
Undeveloped Acres | Developed Acres | Wells | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
United States | ||||||||||||||||||||||||
Arkansas | 80 | 80 | 3,759 | 1,555 | 32 | 15 | ||||||||||||||||||
California | 14,321 | 13,158 | 49,745 | 40,495 | 167 | 139 | ||||||||||||||||||
Colorado | 22,193 | 19,665 | 640 | 640 | 1 | 1 | ||||||||||||||||||
Kansas(1) | 94,746 | 93,809 | — | — | — | — | ||||||||||||||||||
Louisiana | 2,998 | 647 | 9,023 | 1,947 | 27 | 5 | ||||||||||||||||||
Mississippi | 4,645 | 874 | 12,842 | 2,416 | 13 | 3 | ||||||||||||||||||
Missouri(1) | 23,848 | 21,892 | — | — | — | — | ||||||||||||||||||
Montana | 37,260 | 35,377 | 960 | 240 | 2 | 1 | ||||||||||||||||||
Offshore | 5,000 | 5,000 | 23,260 | 16,141 | 34 | 24 | ||||||||||||||||||
Oklahoma | 185 | 52 | 9,321 | 2,625 | 43 | 12 | ||||||||||||||||||
Texas | 40,620 | 21,130 | 99,606 | 51,813 | 601 | 299 | ||||||||||||||||||
Utah | 315 | 315 | — | — | — | — | ||||||||||||||||||
Wyoming | 50,430 | 50,430 | 600 | 2 | — | — | ||||||||||||||||||
Total United States | 296,641 | 262,429 | 209,756 | 117,874 | 920 | 499 | ||||||||||||||||||
(1) | Company has determined that it will not develop the acreage reflected and shall let such expire per lease terms. Acreage was fully impaired for accounting purposes. |
2005 | 2006 | 2007 | Thereafter | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
United States | 36,921 | 28,215 | 29,721 | 27,494 | 114,537 | 111,695 | 115,462 | 95,025 |
Exploratory | Development | ||||||||||||||||||||||||
Productive | Dry | Total | Productive | Dry | Total | ||||||||||||||||||||
2004 | |||||||||||||||||||||||||
United States | 8 | 2 | 10 | 40 | 2 | 42 | |||||||||||||||||||
Canada | 13 | 1 | 14 | 31 | 2 | 33 | |||||||||||||||||||
�� | |||||||||||||||||||||||||
Total | 21 | 3 | 24 | 71 | 4 | 75 | |||||||||||||||||||
2003 | |||||||||||||||||||||||||
United States | 17 | 8 | 25 | 20 | 5 | 25 | |||||||||||||||||||
Canada | 1 | 2 | 3 | 158 | 3 | 161 | |||||||||||||||||||
Total | 18 | 10 | 28 | 178 | 8 | 186 | |||||||||||||||||||
2002 | |||||||||||||||||||||||||
United States | — | 6 | 6 | 41 | 4 | 45 | |||||||||||||||||||
Canada | 1 | 1 | 2 | 87 | 8 | 95 | |||||||||||||||||||
Total | 1 | 7 | 8 | 128 | 12 | 140 | |||||||||||||||||||
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Exploratory | Development | ||||||||||||||||||||||||
Productive | Dry | Total | Productive | Dry | Total | ||||||||||||||||||||
2004 | |||||||||||||||||||||||||
United States | 4.3 | 1.0 | 5.3 | 21.1 | 2.0 | 23.1 | |||||||||||||||||||
Canada | 8.7 | 0.5 | 9.2 | 14.7 | 1.5 | 16.2 | |||||||||||||||||||
Total | 13.0 | 1.5 | 14.5 | 35.8 | 3.5 | 39.3 | |||||||||||||||||||
2003 | |||||||||||||||||||||||||
United States | 14.0 | 4.5 | 18.5 | 18.5 | 3.4 | 21.9 | |||||||||||||||||||
Canada | 0.3 | 0.7 | 1.0 | 42.5 | 1.0 | 43.5 | |||||||||||||||||||
Total | 14.3 | 5.2 | 19.5 | 61.0 | 4.4 | 65.4 | |||||||||||||||||||
2002 | |||||||||||||||||||||||||
United States | — | 3.9 | 3.9 | 36.4 | 2.8 | 39.2 | |||||||||||||||||||
Canada | 0.5 | 0.5 | 1.0 | 38.9 | 4.2 | 43.1 | |||||||||||||||||||
Total | 0.5 | 4.4 | 4.9 | 75.3 | 7.0 | 82.3 | |||||||||||||||||||
With Hedges | Without Hedges | |||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |||||||||||||||||||||
NORTH AMERICA | ||||||||||||||||||||||||||
Sales price | ||||||||||||||||||||||||||
Natural gas (per Mcf)(1) | $ | 6.02 | $ | 5.33 | $ | 2.78 | $ | 6.02 | $ | 5.33 | $ | 2.82 | ||||||||||||||
Oil and condensate (per barrel) | $ | 39.08 | $ | 35.06 | $ | 51.22 | $ | 39.08 | $ | 35.06 | $ | 50.98 | ||||||||||||||
Lease operating cost (per Mcfe)(2) | $ | 1.03 | $ | 0.78 | $ | 0.73 | $ | 1.03 | $ | 0.78 | $ | 0.73 | ||||||||||||||
Production taxes (per Mcfe) | $ | 0.11 | $ | 0.06 | $ | 0.05 | $ | 0.11 | $ | 0.06 | $ | 0.05 | ||||||||||||||
Total production cost (per Mcfe)(3) | $ | 1.14 | $ | 0.84 | $ | 0.78 | $ | 1.14 | $ | 0.84 | $ | 0.78 |
(1) | Thousand cubic feet. |
(2) | Includes lifting costs, treating and transportation and workover costs. |
(3) | Thousand cubic feet equivalent. |
Item 3. | Legal Proceedings |
Item 4. | Submission of Matters to a Vote of Security Holders |
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Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
High | Low | |||||||
2004 | ||||||||
First Quarter | $ | 6.42 | $ | 4.35 | ||||
Second Quarter | 4.98 | 3.04 | ||||||
Third Quarter | 4.46 | 2.87 | ||||||
Fourth Quarter | 4.08 | 2.24 | ||||||
2003 | ||||||||
First Quarter | $ | 4.42 | $ | 2.51 | ||||
Second Quarter | 7.25 | 3.33 | ||||||
Third Quarter | 8.03 | 4.76 | ||||||
Fourth Quarter | 5.25 | 3.28 |
Total Number | Maximum | |||||||||||||||
of Units/Notes | Number of | |||||||||||||||
Purchased as | Units/Notes | |||||||||||||||
Part of Publicly | that may yet be | |||||||||||||||
Total Number of | Announced | Purchased | ||||||||||||||
Units/Notes | Price Paid per | Plans or | under the Plans | |||||||||||||
Period | Purchased | Unit/Note | Programs | or Programs | ||||||||||||
10/1/04 – 10/31/04 | 13,112,660 | $ | 50 | — | — | |||||||||||
11/1/04 – 11/30/04 | — | — | — | — | ||||||||||||
12/1/04 – 12/31/04 | 70,800 | $ | 1,000 | — | — |
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Item 6. | Selected Financial Data |
Years Ended December 31, | |||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||||||||
(In thousands, except earnings per share) | |||||||||||||||||||||
Statement of Operations data: | |||||||||||||||||||||
Total revenue | $ | 9,229,888 | $ | 8,871,033 | $ | 7,349,753 | $ | 6,565,893 | $ | 2,264,495 | |||||||||||
Income before discontinued operations and cumulative effect of a change in accounting principle | $ | (440,826 | ) | $ | 86,110 | $ | 26,722 | $ | 527,772 | $ | 315,148 | ||||||||||
Discontinued operations, net of tax | 198,365 | 14,969 | 91,896 | 94,684 | 53,936 | ||||||||||||||||
Cumulative effect of a change in accounting principle | — | 180,943 | — | 1,036 | — | ||||||||||||||||
Net income | $ | (242,461 | ) | $ | 282,022 | $ | 118,618 | $ | 623,492 | $ | 369,084 | ||||||||||
Basic earnings per common share: | |||||||||||||||||||||
Income before discontinued operations and cumulative effect of a change in accounting principle | $ | (1.02 | ) | $ | 0.22 | $ | 0.07 | $ | 1.74 | $ | 1.12 | ||||||||||
Discontinued operations, net of tax | 0.46 | 0.04 | 0.26 | 0.31 | 0.19 | ||||||||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | 0.46 | — | — | — | ||||||||||||||||
Net income | $ | (0.56 | ) | $ | 0.72 | $ | 0.33 | $ | 2.05 | $ | 1.31 | ||||||||||
Diluted earnings per common share: | |||||||||||||||||||||
Income before discontinued operations and cumulative effect of a change in accounting principle | $ | (1.02 | ) | $ | 0.22 | $ | 0.07 | $ | 1.54 | $ | 1.02 | ||||||||||
Discontinued operations, net of tax provision | 0.46 | 0.04 | 0.26 | 0.26 | 0.16 | ||||||||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | 0.45 | — | — | — | ||||||||||||||||
Net income | $ | (0.56 | ) | $ | 0.71 | $ | 0.33 | $ | 1.80 | $ | 1.18 | ||||||||||
Balance Sheet data: | |||||||||||||||||||||
Total assets | $ | 27,216,088 | $ | 27,303,932 | $ | 23,226,992 | $ | 21,937,227 | $ | 10,610,232 | |||||||||||
Short-term debt and capital lease obligations | 1,033,956 | 349,128 | 1,651,448 | 903,307 | 64,525 | ||||||||||||||||
Long-term debt and capital lease obligations | 16,940,809 | 17,328,181 | 12,462,290 | 12,490,175 | 5,018,044 | ||||||||||||||||
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts(1) | $ | — | $ | — | $ | 1,123,969 | $ | 1,122,924 | $ | 1,122,390 |
(1) | Included in long-term debt as of December 31, 2003 and 2004. See Note 12 of the Notes to Consolidated Financial Statements for more information. |
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Years Ended December 31, | |||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||||||||
(In thousands) | |||||||||||||||||||||
Reconciliation of GAAP cash provided from operating activities to EBITDA, as adjusted(1): | |||||||||||||||||||||
Cash provided by operating activities | $ | 9,895 | $ | 290,559 | $ | 1,068,466 | $ | 423,569 | $ | 875,751 | |||||||||||
Less: Changes in operating assets and liabilities, excluding the effects of acquisitions(2) | (137,614 | ) | (609,840 | ) | 480,193 | (359,640 | ) | 277,696 | |||||||||||||
Less: Additional adjustments to reconcile net income to net cash provided by operating activities, net(2) | 389,970 | 618,377 | 469,655 | 159,717 | 228,971 | ||||||||||||||||
GAAP net income | $ | (242,461 | ) | $ | 282,022 | $ | 118,618 | $ | 623,492 | $ | 369,084 | ||||||||||
(Income) loss from unconsolidated investments in power projects and oil and gas properties | 13,525 | (75,804 | ) | 16,552 | 16,946 | 28,796 | |||||||||||||||
Distributions from unconsolidated investments in power projects and oil and gas properties | 29,869 | 141,627 | 14,117 | 5,983 | 29,979 | ||||||||||||||||
Adjusted net income | $ | (199,067 | ) | $ | 347,845 | $ | 116,183 | $ | 612,529 | $ | 370,267 | ||||||||||
Interest expense | 1,140,802 | 706,307 | 402,677 | 190,971 | 78,373 | ||||||||||||||||
1/3 of operating lease expense | 35,295 | 37,357 | 37,007 | 33,173 | 21,154 | ||||||||||||||||
Distributions on trust preferred securities | — | 46,610 | 62,632 | 62,412 | 45,076 | ||||||||||||||||
Provision (benefit) for income taxes | (276,549 | ) | 8,495 | 10,835 | 273,137 | 211,670 | |||||||||||||||
Depreciation, depletion and amortization expense | 840,916 | 568,204 | 423,102 | 275,396 | 169,278 | ||||||||||||||||
Interest expense, provision for income taxes and depreciation from discontinued operations | 112,487 | 84,489 | 128,900 | 165,217 | 127,914 | ||||||||||||||||
EBITDA, as adjusted(1) | $ | 1,653,885 | $ | 1,799,307 | $ | 1,181,336 | $ | 1,612,835 | $ | 1,023,732 | |||||||||||
(1) | This non-GAAP measure is presented not as a measure of operating results, but rather as a measure of our ability to service debt and to raise additional funds. It should not be construed as an alternative to either (i) income from operations or (ii) cash flows from operating activities. It is defined as net income less income from unconsolidated investments, plus cash received from unconsolidated investments, plus provision for tax, plus interest expense (including distributions on trust preferred securities and one-third of operating lease expense, which is management’s estimate of the component of operating lease expense that constitutes interest expense,) plus depreciation, depletion and amortization. The interest, tax and depreciation and amortization components of discontinued operations are added back in calculating EBITDA, as adjusted. |
For the year ended December 31, 2004, EBITDA, as adjusted, includes a $246.9 million gain from the repurchase of debt, offset by approximately $223.4 million of certain charges, consisting primarily of foreign currency transaction losses, write-off of deferred financing costs not related to the bonds repurchased, equipment cancellation and impairment costs, certain mark-to-market activity, and minority interest expense, some of which required, or will require cash settlement. | |
For the year ended December 31, 2003, EBITDA, as adjusted, includes a $180.9 million (net of tax) gain from the cumulative effect of a change in accounting principle and a $278.6 million gain from the repurchase of debt, offset by approximately $273.0 million of certain charges, consisting primarily of foreign currency transaction losses, equipment cancellation and impairment costs, certain mark-to- |
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market activity, and minority interest expense, some of which required, or will require cash settlement. EBITDA, as adjusted for the year ended December 31, 2002, includes a non-cash equipment cancellation charge of $404.7 million, a $118.0 million gain on the repurchase of debt, and approximately $55.0 million of certain charges, some of which required, or will require cash settlement. |
(2) | See the Consolidated Statements of Cash Flows for further detail of these items. |
Years Ended December 31, | ||||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | ||||||||||||||||||
(Dollars in thousands, except production and pricing data) | ||||||||||||||||||||||
Power Plants(1): | ||||||||||||||||||||||
Electricity and steam (“E&S”) revenues: | ||||||||||||||||||||||
Energy | $ | 4,224,463 | $ | 3,361,095 | $ | 2,273,524 | $ | 1,701,533 | $ | 1,220,684 | ||||||||||||
Capacity | 991,142 | 844,195 | 781,127 | 525,174 | 376,085 | |||||||||||||||||
Thermal and other | 467,458 | 475,107 | 182,859 | 158,617 | 99,297 | |||||||||||||||||
Subtotal | $ | 5,683,063 | $ | 4,680,397 | $ | 3,237,510 | $ | 2,385,324 | $ | 1,696,066 | ||||||||||||
Spread on sales of purchased power(2) | 164,747 | 24,118 | 527,546 | 345,834 | 11,262 | |||||||||||||||||
Adjusted E&S revenues | $ | 5,847,810 | $ | 4,704,515 | $ | 3,765,056 | $ | 2,731,158 | $ | 1,707,328 | ||||||||||||
MWh produced | 96,488,984 | 82,423,422 | 72,767,280 | 42,393,726 | 22,749,588 | |||||||||||||||||
All-in electricity price per MWh generated | $ | 60.61 | $ | 57.08 | $ | 51.74 | $ | 64.42 | $ | 75.05 |
(1) | From continuing operations only. Discontinued operations are excluded. |
(2) | From hedging, balancing and optimization activities related to our generating assets. |
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Year Ended December 31, | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
Total revenue | $ | 9,229,888 | $ | 8,871,033 | $ | 7,349,753 | ||||||
Sales of purchased power for hedging and optimization(1) | 1,651,767 | 2,714,187 | 3,145,991 | |||||||||
As a percentage of total revenue | 17.9 | % | 30.6 | % | 42.8 | % | ||||||
Sale of purchased gas for hedging and optimization | 1,728,301 | 1,320,902 | 870,466 | |||||||||
As a percentage of total revenue | 18.7 | % | 14.9 | % | 11.8 | % | ||||||
Total cost of revenue (“COR”) | 8,874,795 | 8,106,796 | 6,388,269 | |||||||||
Purchased power expense for hedging and optimization(1) | 1,487,020 | 2,690,069 | 2,618,445 | |||||||||
As a percentage of total COR | 16.8 | % | 33.2 | % | 41.0 | % | ||||||
Purchased gas expense for hedging and optimization | 1,716,714 | 1,279,568 | 821,065 | |||||||||
As a percentage of total COR | 19.3 | % | 15.8 | % | 12.9 | % |
(1) | On October 1, 2003, we adopted on a prospective basis EITF Issue No. 03-11 and netted purchases of power against sales of purchased power. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of our application of EITF Issue No. 03-11. |
Nine Months | |||||||||
Ended | Year Ended | ||||||||
September 30, | December 31, | ||||||||
2003 | 2002 | ||||||||
(In thousands) | |||||||||
Sales to NEPOOL from power we generated | $ | 258,945 | $ | 294,634 | |||||
Sales to NEPOOL from hedging and other activity | 117,345 | 106,861 | |||||||
Total sales to NEPOOL | $ | 376,290 | $ | 401,495 | |||||
Total purchases from NEPOOL | $ | 310,025 | $ | 360,113 |
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Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
• | preserving and enhancing our liquidity while spark spreads (the differential between power revenues and fuel costs) are depressed, | |
• | selectively adding new load-serving entities and power users to our customer list as we increase our power contract portfolio, | |
• | continuing to add value through prudent risk management and optimization activities, and | |
• | lowering our costs of production through various efficiency programs. |
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Year Ended December 31, 2004, Compared to Year Ended December 31, 2003 |
Revenue |
2004 | 2003 | $ Change | % Change | |||||||||||||
Total revenue | $ | 9,230.0 | $ | 8,871.0 | $ | 359.0 | 4.0 | % |
2004 | 2003 | $ Change | % Change | ||||||||||||||
Electricity and steam revenue | $ | 5,683.1 | $ | 4,680.4 | $ | 1,002.7 | 21.4 | % | |||||||||
Transmission sales revenue | 20.0 | 15.3 | 4.7 | 30.7 | % | ||||||||||||
Sales of purchased power for hedging and optimization | 1,651.8 | 2,714.2 | (1,062.4 | ) | (39.1 | )% | |||||||||||
Total electric generation and marketing revenue | $ | 7,354.9 | $ | 7,409.9 | $ | (55.0 | ) | (1 | )% | ||||||||
2004 | 2003 | $ Change | % Change | ||||||||||||||
Oil and gas sales | $ | 63.2 | $ | 59.2 | $ | 4.0 | 6.8 | % | |||||||||
Sales of purchased gas for hedging and optimization | 1,728.3 | 1,320.9 | 407.4 | 30.8 | % | ||||||||||||
Total oil and gas production and marketing revenue | $ | 1,791.5 | $ | 1,380.1 | $ | 411.4 | 29.8 | % | |||||||||
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2004 | 2003 | $ Change | % Change | ||||||||||||||
Realized gain on power and gas mark-to-market transactions, net | $ | 48.2 | $ | 24.3 | $ | 23.9 | 98.4 | % | |||||||||
Unrealized (loss) on power and gas mark-to-market transactions, net | (34.7 | ) | (50.7 | ) | 16.0 | 31.6 | % | ||||||||||
Mark-to-market activities, net | $ | 13.5 | $ | (26.4 | ) | $ | 39.9 | 151.1 | % | ||||||||
2004 | 2003 | $ Change | % Change | |||||||||||||
Other revenue | $ | 70.1 | $ | 107.5 | $ | (37.4 | ) | (34.8 | )% |
Cost of Revenue |
2004 | 2003 | $ Change | % Change | |||||||||||||
Cost of revenue | $ | 8,874.8 | $ | 8,106.8 | $ | (768.0 | ) | (9.5 | )% |
2004 | 2003 | $ Change | % Change | ||||||||||||||
Plant operating expense | $ | 796.0 | $ | 663.0 | $ | (133.0 | ) | (20.1 | )% | ||||||||
Royalty expense | 28.7 | 24.9 | (3.8 | ) | (15.3 | )% | |||||||||||
Transmission purchase expense | 85.5 | 46.5 | (39.0 | ) | (83.9 | )% | |||||||||||
Purchased power expense for hedging and optimization | 1,487.0 | 2,690.1 | 1,203.1 | 44.7 | % | ||||||||||||
Total electric generation and marketing expense | $ | 2,397.2 | $ | 3,424.5 | $ | 1,027.3 | 30.0 | % | |||||||||
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2004 | 2003 | $ Change | % Change | |||||||||||||||
Oil and gas production expense | $ | 48.9 | $ | 56.3 | $ | 7.4 | 13.1 | % | ||||||||||
Oil and gas exploration expense | 7.9 | 19.2 | 11.3 | 58.9 | % | |||||||||||||
Oil and gas operating expense | $ | 56.8 | $ | 75.5 | $ | 18.7 | 24.8 | % | ||||||||||
Purchased gas expense for hedging and optimization | 1,716.7 | 1,279.6 | (437.1 | ) | (34.2 | )% | ||||||||||||
Total oil and gas operating and marketing expense | $ | 1,773.5 | $ | 1,355.1 | $ | (418.4 | ) | (30.9 | )% | |||||||||
2004 | 2003 | $ Change | % Change | ||||||||||||||
Fuel expense | |||||||||||||||||
Cost of oil and gas burned by power plants | $ | 3,732.6 | $ | 2,677.2 | $ | (1,055.4 | ) | (39.4 | )% | ||||||||
Recognized (gain) on gas hedges | (1.5 | ) | (11.6 | ) | (10.1 | ) | (87.1 | )% | |||||||||
Total fuel expense | $ | 3,731.1 | $ | 2,665.6 | $ | (1,065.5 | ) | (40.0 | )% | ||||||||
2004 | 2003 | $ Change | % Change | |||||||||||||
Depreciation, depletion and amortization expense | $ | 574.2 | $ | 504.4 | $ | (69.8 | ) | (13.8 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Oil and gas impairment | $ | 202.1 | $ | 2.9 | $ | (199.2 | ) | (6,869.0 | )% |
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2004 | 2003 | $ Change | % Change | |||||||||||||
Operating lease expense | $ | 105.9 | $ | 112.1 | $ | 6.2 | 5.5 | % |
2004 | 2003 | $ Change | % Change | |||||||||||||
Other cost of revenue | $ | 90.7 | $ | 42.3 | $ | (48.4 | ) | (114.4 | )% |
(Income)/ Expense |
2004 | 2003 | $ Change | % Change | |||||||||||||
(Income) loss from unconsolidated investments in power projects and oil and gas properties | $ | 13.5 | $ | (75.8 | ) | $ | (89.3 | ) | (117.8 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Equipment cancellation and impairment cost | $ | 42.4 | $ | 64.4 | $ | 22.0 | 34.2 | % |
2004 | 2003 | $ Change | % Change | |||||||||||||
Long-term service agreement cancellation charge | $ | 11.3 | $ | 16.4 | $ | 5.1 | 31.1 | % |
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2004 | 2003 | $ Change | % Change | |||||||||||||
Project development expense | $ | 24.4 | $ | 21.8 | $ | (2.6 | ) | (11.9 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Research and development expense | $ | 18.4 | $ | 10.6 | $ | (7.8 | ) | (73.6 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Sales, general and administrative expense | $ | 239.3 | $ | 216.5 | $ | (22.8 | ) | (10.5 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Interest expense | $ | 1,140.8 | $ | 706.3 | $ | (434.5 | ) | (61.5 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Distributions on trust preferred securities | $ | — | $ | 46.6 | $ | 46.6 | (100 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Interest (income) | $ | (56.4 | ) | $ | (39.7 | ) | $ | 16.7 | 42.1 | % |
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2004 | 2003 | $ Change | % Change | |||||||||||||
Minority interest expense | $ | 34.7 | $ | 27.3 | $ | (7.4 | ) | (27.1 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
(Income) from the repurchase of various issuances of debt | $ | (246.9 | ) | $ | (278.6 | ) | $ | (31.7 | ) | (11.4 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Other (income), net | $ | (149.1 | ) | $ | (46.1 | ) | $ | 103.0 | 223.4 | % |
2004 | 2003 | $ Change | % Change | |||||||||||||
Provision (benefit) for income taxes | $ | (276.5 | ) | $ | 8.5 | $ | 285.0 | 3,352.9 | % |
2004 | 2003 | $ Change | % Change | |||||||||||||
Discontinued operations, net of tax | $ | 198.4 | $ | 15.0 | $ | (183.4 | ) | (1,222.7 | )% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Cumulative effect of a change in accounting principle, net of tax | $ | — | $ | 180.9 | $ | (180.9 | ) | (100.0 | )% |
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Net Income (Loss) |
2004 | 2003 | $ Change | % Change | |||||||||||||
Net income (loss) | $ | (242.5 | ) | $ | 282.0 | $ | (524.5 | ) | (186.0 | )% |
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Year Ended December 31, 2003, Compared to Year Ended December 31, 2002 |
Revenue |
2003 | 2002 | $ Change | % Change | |||||||||||||
Total revenue | $ | 8,871.0 | $ | 7,349.8 | $ | 1,521.2 | 20.7 | % |
2003 | 2002 | $ Change | % Change | ||||||||||||||
Electricity and steam revenue | $ | 4,680.4 | $ | 3,237.5 | $ | 1,442.9 | 44.6 | % | |||||||||
Transmission sale revenue | 15.3 | — | 15.3 | 100.0 | % | ||||||||||||
Sales of purchased power for hedging and optimization | 2,714.2 | 3,146.0 | (431.8 | ) | (13.7 | )% | |||||||||||
Total electric generation and marketing revenue | $ | 7,409.9 | $ | 6,383.5 | $ | 1,026.4 | 16.1 | % | |||||||||
2003 | 2002 | $ Change | % Change | ||||||||||||||
Oil and gas sales | $ | 59.2 | $ | 63.5 | $ | (4.3 | ) | (6.8 | )% | ||||||||
Sales of purchased gas for hedging and optimization | 1,320.9 | 870.5 | 450.4 | 51.7 | % | ||||||||||||
Total oil and gas production and marketing revenue | $ | 1,380.1 | $ | 934.0 | $ | 446.1 | 47.8 | % | |||||||||
2003 | 2002 | $ Change | % Change | ||||||||||||||
Realized gain on power and gas transactions, net | $ | 24.3 | $ | 26.1 | $ | (1.8 | ) | (6.9 | )% | ||||||||
Unrealized loss on power and gas transactions, net | (50.7 | ) | (4.6 | ) | (46.1 | ) | (1,002.2 | )% | |||||||||
Mark-to-market activities, net | $ | (26.4 | ) | $ | 21.5 | $ | (47.9 | ) | (222.8 | )% | |||||||
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2003 | 2002 | $ Change | % Change | |||||||||||||
Other revenue | $ | 107.5 | $ | 10.8 | $ | 96.7 | 895.4 | % |
Cost of Revenue |
2003 | 2002 | $ Change | % Change | |||||||||||||
Total cost of revenue | $ | 8,106.8 | $ | 6,388.3 | $ | (1,718.5 | ) | (26.9 | )% |
2003 | 2002 | $ Change | % Change | ||||||||||||||
Plant operating expense | $ | 663.0 | $ | 522.9 | $ | (140.1 | ) | (26.8 | )% | ||||||||
Royalty expense | 24.9 | 17.6 | (7.3 | ) | (41.5 | )% | |||||||||||
Transmission purchase expense | 46.5 | 25.5 | (21.0 | ) | (82.4 | )% | |||||||||||
Purchased power expense for hedging and optimization | 2,690.1 | 2,618.4 | (71.7 | ) | (2.7 | )% | |||||||||||
Total electric generation and marketing expense | $ | 3,424.5 | $ | 3,184.4 | $ | (240.1 | ) | (7.5 | )% | ||||||||
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2003 | 2002 | $ Change | % Change | |||||||||||||||
Oil and gas production expense | $ | 56.3 | $ | 56.8 | $ | 0.5 | 1.0 | % | ||||||||||
Oil and gas exploration expense | 19.2 | 13.0 | (6.2 | ) | (47.7 | )% | ||||||||||||
Oil and gas operating expense | $ | 75.5 | $ | 69.8 | $ | (5.7 | ) | (8.2 | )% | |||||||||
Purchased gas expense for hedging and optimization | 1,279.6 | 821.1 | (458.5 | ) | (55.8 | )% | ||||||||||||
Total oil and gas operating and marketing expense | $ | 1,355.1 | $ | 890.9 | $ | (464.2 | ) | (52.1 | )% | |||||||||
2003 | 2002 | $ Change | % Change | ||||||||||||||
Fuel expense | |||||||||||||||||
Cost of oil and gas burned by power plants | $ | 2,677.2 | $ | 1,659.3 | $ | (1,017.9 | ) | (61.3 | )% | ||||||||
Recognized (gain) loss on gas hedges | (11.6 | ) | 133.0 | 144.6 | 108.7 | % | |||||||||||
Total fuel expense | $ | 2,665.6 | $ | 1,792.3 | $ | (873.3 | ) | (48.7 | )% | ||||||||
2003 | 2002 | $ Change | % Change | |||||||||||||
Depreciation, depletion and amortization expense | $ | 504.4 | $ | 398.9 | $ | (105.5 | ) | (26.4 | )% |
2003 | 2002 | $ Change | % Change | |||||||||||||
Oil and gas impairment | $ | 2.9 | $ | 3.4 | $ | 0.5 | 14.7 | % |
2003 | 2002 | $ Change | % Change | |||||||||||||
Operating lease expense | $ | 112.1 | $ | 111.0 | $ | (1.1 | ) | (1.0 | )% |
2003 | 2002 | $ Change | % Change | |||||||||||||
Other cost of revenue | $ | 42.3 | $ | 7.3 | $ | (35.0 | ) | (479.5 | )% |
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(Income)/ Expenses |
2003 | 2002 | $ Change | % Change | |||||||||||||
(Income) from unconsolidated investments in power projects and oil and gas properties | $ | (75.8 | ) | $ | (16.6 | ) | $ | 59.2 | 356.6 | % |
2003 | 2002 | $ Change | % Change | |||||||||||||
Equipment cancellation and impairment cost | $ | 64.4 | $ | 404.7 | $ | 340.3 | 84.1 | % |
2003 | 2002 | $ Change | % Change | |||||||||||||
Long-term service agreement cancellation charges | $ | 16.4 | $ | — | $ | (16.4 | ) | (100.0 | )% |
2003 | 2002 | $ Change | % Change | |||||||||||||
Project development expense | $ | 21.8 | $ | 67.0 | $ | 45.2 | 67.5 | % |
2003 | 2002 | $ Change | % Change | |||||||||||||
Research and development expense | $ | 10.6 | $ | 10.0 | $ | (0.6 | ) | (6.0 | )% |
2003 | 2002 | $ Change | % Change | |||||||||||||
Sales, general and administrative expense | $ | 216.5 | $ | 186.1 | $ | (30.4 | ) | (16.3 | )% |
2003 | 2002 | $ Change | % Change | |||||||||||||
Interest expense | $ | 706.3 | $ | 402.7 | $ | (303.6 | ) | (75.4 | )% |
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2003 | 2002 | $ Change | % Change | |||||||||||||
Distributions on trust preferred securities | $ | 46.6 | $ | 62.6 | $ | (16.0 | ) | (25.6 | )% |
2003 | 2002 | $ Change | % Change | |||||||||||||
Interest income | $ | (39.7 | ) | $ | (43.1 | ) | $ | (3.4 | ) | (7.9 | )% |
2003 | 2002 | $ Change | % Change | |||||||||||||
Minority interest expense | $ | 27.3 | $ | 2.7 | $ | (24.6 | ) | (911.1 | )% |
2003 | 2002 | $ Change | % Change | |||||||||||||
(Income) from repurchase of various issuances of debt | $ | (278.6 | ) | $ | (118.0 | ) | $ | 160.6 | 136.1 | % |
2003 | 2002 | $ Change | % Change | |||||||||||||
Other (income), net | $ | (46.1 | ) | $ | (34.2 | ) | $ | 11.9 | 34.8 | % |
2003 | 2002 | $ Change | % Change | |||||||||||||
Provision for income taxes | $ | 8.5 | $ | 10.8 | $ | 2.3 | 21.3 | % |
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2003 | 2002 | $ Change | % Change | |||||||||||||
Discontinued operations, net of tax | $ | 15.0 | $ | 91.9 | $ | 76.9 | 83.7 | % |
2003 | 2002 | $ Change | % Change | |||||||||||||
Cumulative effect of a change in accounting principle, net of tax | $ | 180.9 | $ | — | $ | 180.9 | 100.0 | % |
Net Income |
2003 | 2002 | $ Change | % Change | |||||||||||||
Net income | $ | 282.0 | $ | 118.6 | $ | 163.4 | 137.8 | % |
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Years Ended December 31, | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(In thousands) | |||||||||||||
Beginning cash and cash equivalents | $ | 991,806 | $ | 579,486 | $ | 1,594,144 | |||||||
Net cash provided by: | |||||||||||||
Operating activities | $ | 9,895 | $ | 290,559 | $ | 1,068,466 | |||||||
Investing activities | (401,426 | ) | (2,515,365 | ) | (3,837,827 | ) | |||||||
Financing activities | 167,052 | 2,623,986 | 1,757,396 | ||||||||||
Effect of exchange rates changes on cash and cash equivalents | 16,101 | 13,140 | (2,693 | ) | |||||||||
Net increase (decrease) in cash and cash equivalents | $ | (208,378 | ) | $ | 412,320 | $ | (1,014,658 | ) | |||||
Ending cash and cash equivalents | $ | 783,428 | $ | 991,806 | $ | 579,486 | |||||||
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• | Refinanced CCFC II project debt through the issuance of $2.6 billion of Calpine Generating Company secured institutional term loans, notes and revolving credit facility; | |
• | Completed approximately $2.1 billion of liquidity transactions including the sale of our Canadian and certain U.S. natural gas reserves for $870.1 million; | |
• | Redeemed in full $598.5 million of HIGH TIDES I and II, and purchased a portion of HIGH TIDES III, totaling $115.0 million; and | |
• | Repurchased approximately $1.8 billion of existing corporate debt, resulting in a net gain of $246.9 million after the write-off of unamortized discounts and deferred financing costs. |
• | Obtained a $100 million, non-recourse credit facility to complete construction of the Metcalf Energy Center in San Jose, California. This was the first single-asset, merchant project financing in California since the 2000-2001 energy crisis; | |
• | Received funding on Calpine European Funding (Jersey) Limited’s $260 million offering of Redeemable Preferred Shares due on July 30, 2005. The net proceeds from this offering will ultimately be used as permitted by our existing bond indentures; | |
• | Completed a $400 million, 25-year, non-recourse sale/leaseback transaction for the 560-MW Fox Energy Center under construction in Kaukauna, Wisconsin; and | |
• | Completed a $195 million, non-recourse project financing for construction of the 525-MW Valladolid III Energy Center in Valladolid, Mexico. |
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Amounts of Commitment Expiration per Period | |||||||||||||||||||||||||||||
Total | |||||||||||||||||||||||||||||
Amounts | |||||||||||||||||||||||||||||
Commercial Commitments | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Committed | ||||||||||||||||||||||
Guarantee of subsidiary debt | $ | 18,333 | $ | 16,284 | $ | 18,798 | $ | 1,930,657 | $ | 19,848 | $ | 1,133,896 | $ | 3,137,817 | |||||||||||||||
Standby letters of credit | 579,607 | 3,641 | 2,802 | 400 | — | — | 586,450 | ||||||||||||||||||||||
Surety bonds | — | — | — | — | — | 12,531 | 12,531 | ||||||||||||||||||||||
Guarantee of subsidiary operating lease payments | 83,169 | 81,772 | 82,487 | 115,604 | 113,977 | 1,163,783 | 1,640,792 | ||||||||||||||||||||||
Total | $ | 681,109 | $ | 101,697 | $ | 104,087 | $ | 2,046,661 | $ | 133,825 | $ | 2,310,210 | $ | 5,377,589 | |||||||||||||||
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2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | |||||||||||||||||||||||
Other Contractual Obligations | $ | 60,418 | $ | 7,995 | $ | 2,089 | $ | 2,096 | $ | 2,500 | $ | 85,408 | $ | 160,506 | |||||||||||||||
Total operating lease obligations(1) | $ | 266,399 | $ | 252,511 | $ | 252,849 | $ | 250,238 | $ | 244,601 | $ | 2,321,106 | $ | 3,588,199 | |||||||||||||||
Debt: | |||||||||||||||||||||||||||||
Unsecured Senior Notes(2) | $ | 705,949 | $ | 264,258 | $ | 360,878 | $ | 1,968,660 | $ | 221,539 | $ | 1,273,333 | $ | 4,794,617 | |||||||||||||||
Second Priority Senior Secured Notes(2) | 12,500 | 12,500 | 1,209,375 | — | — | 2,443,150 | 3,677,525 | ||||||||||||||||||||||
First Priority Senior Secured Notes(2) | — | — | — | — | — | 778,971 | 778,971 | ||||||||||||||||||||||
Total Senior Notes | $ | 718,449 | $ | 276,758 | $ | 1,570,253 | $ | 1,968,660 | $ | 221,539 | $ | 4,495,454 | $ | 9,251,113 | |||||||||||||||
CCFC 1(4) | 3,208 | 3,208 | 3,208 | 3,208 | 365,349 | 408,569 | 786,750 | ||||||||||||||||||||||
CALGEN(4) | — | — | 4,174 | 12,050 | 829,875 | 1,549,233 | 2,395,332 | ||||||||||||||||||||||
Convertible Senior Notes Due 2006, 2014 and 2023(2) | — | 1,326 | — | — | — | 1,253,972 | 1,255,298 | ||||||||||||||||||||||
Notes payable and borrowings under lines of credit(4)(5) | 197,016 | 188,756 | 143,962 | 104,555 | 106,221 | 108,277 | 848,787 | ||||||||||||||||||||||
Notes payable to Calpine Capital Trusts(2) | — | — | — | — | — | 517,500 | 517,500 | ||||||||||||||||||||||
Preferred interests(4) | 8,641 | 369,480 | 8,990 | 12,236 | 16,228 | 90,962 | 506,537 | ||||||||||||||||||||||
Capital lease obligation(4) | 5,490 | 6,538 | 7,428 | 9,765 | 10,925 | 248,773 | 288,919 | ||||||||||||||||||||||
Construction/project financing(4)(6) | 93,393 | 89,355 | 103,423 | 100,340 | 105,299 | 1,507,241 | 1,999,051 | ||||||||||||||||||||||
Total debt(5)(9)(3) | $ | 1,026,197 | $ | 935,421 | $ | 1,841,438 | $ | 2,210,814 | $ | 1,655,436 | $ | 10,179,981 | $ | 17,849,287 | |||||||||||||||
Interest payments on debt obligations | $ | 1,473,629 | $ | 1,462,291 | $ | 1,356,035 | $ | 1,130,214 | $ | 1,003,534 | $ | 3,422,874 | $ | 9,848,577 | |||||||||||||||
Interest rate swap agreement payments | 20,964 | 13,945 | 11,770 | 10,051 | 9,036 | 14,102 | 79,868 | ||||||||||||||||||||||
Purchase obligations: | |||||||||||||||||||||||||||||
Turbine commitments | 27,463 | 4,862 | 977 | — | — | — | 33,302 | ||||||||||||||||||||||
Commodity purchase obligations(7) | 1,659,425 | 1,071,778 | 965,222 | 805,946 | 680,345 | 1,003,102 | 6,185,818 | ||||||||||||||||||||||
Land leases | 4,592 | 4,786 | 4,967 | 5,504 | 5,998 | 375,114 | 400,961 | ||||||||||||||||||||||
Long-term service agreements | 73,541 | 93,675 | 120,385 | 74,448 | 70,544 | 710,137 | 1,142,730 | ||||||||||||||||||||||
Costs to complete construction projects | 699,174 | 449,312 | 189,806 | — | — | — | 1,338,292 | ||||||||||||||||||||||
Other purchase obligations | 55,202 | 26,853 | 25,481 | 25,172 | 24,985 | 470,524 | 628,217 | ||||||||||||||||||||||
Total purchase obligations(8) | $ | 2,469,397 | $ | 1,651,266 | $ | 1,306,838 | $ | 911,070 | $ | 781,872 | $ | 2,558,877 | $ | 9,729,320 | |||||||||||||||
(1) | Included in the total are future minimum payments for power plant operating leases, office and equipment leases and two tolling agreements with Acadia Energy Center accounted for as leases (See Note 7 of the Notes to Consolidated Financial Statements for more information). | |
(2) | An obligation of or with recourse to Calpine Corporation. |
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(3) | The table above does not reflect the repurchases of $80.6 million convertible Senior Notes and Senior Notes subsequent to December 31, 2004. | |
(4) | Structured as an obligation(s) of certain subsidiaries of Calpine Corporation without recourse to Calpine Corporation. However, default on these instruments could potentially trigger cross-default provisions in certain other debt instruments. | |
(5) | A note payable totaling $125.5 million associated with the sale of the PG&E note receivable to a third party is excluded from notes payable and borrowings under lines of credit for this purpose as it is a noncash liability. If the $125.5 million is summed with the $848.8 (total notes payable and borrowings under lines of credit) million from the table above, the total notes payable and borrowings under lines of credit would be $974.3 million, which agrees to the Consolidated Balance Sheet sum of the current and long-term notes payable and borrowings under lines of credit balances on the Consolidated Balance Sheet. See Note 8 of the Notes to Consolidated Financial Statements for more information concerning this note. Total debt of $17,849.3 million from the table above summed with the $125.5 million totals $17,974.8 million, which agrees to the total debt amount in Note 11 of the Notes to Consolidated Financial Statements. | |
(6) | Included in the total are guaranteed amounts of $275.1 million and $282.9 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant. | |
(7) | The amounts presented here include contracts for the purchase, transportation, or storage of commodities accounted for as executory contracts or normal purchase and sales and, therefore, not recognized as liabilities on our Consolidated Balance Sheet. See “Financial Market Risks” for a discussion of our commodity derivative contracts recorded at fair value on our Consolidated Balance Sheet. | |
(8) | The amounts included above for purchase obligations include the minimum requirements under contract. Also included in purchase obligations are employee agreements. Agreements that we can cancel without significant cancellation fees are excluded. | |
(9) | See Item 1. “Business — Risk Factors” for a discussion of the estimated amount of debt that must be repurchased pursuant to our indentures. |
(10) | Interest payments on debt obligations have not been decreased for the requirement to repurchase or redeem approximately $520 million of indebtedness, per current estimates, pursuant to our indentures, as the specific debt instruments are not known. However, the $520 million of indebtedness is reflected in this table as due in 2005. |
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2004 | 2003 | |||||||||||||||
Principal | Amount | Principal | Amount | |||||||||||||
Debt Security and HIGH TIDES | Amount | Paid | Amount | Paid | ||||||||||||
2006 Convertible Senior Notes | $ | 658.7 | $ | 657.7 | $ | 474.9 | $ | 458.8 | ||||||||
2023 Convertible Senior Notes | 266.2 | 177.0 | — | — | ||||||||||||
81/4% Senior Notes Due 2005 | 38.9 | 34.9 | 25.0 | 24.5 | ||||||||||||
101/2% Senior Notes Due 2006 | 13.9 | 12.4 | 5.2 | 5.1 | ||||||||||||
75/8% Senior Notes Due 2006 | 103.1 | 96.5 | 35.3 | 32.5 | ||||||||||||
83/4% Senior Notes Due 2007 | 30.8 | 24.4 | 48.9 | 45.0 | ||||||||||||
77/8% Senior Notes Due 2008 | 78.4 | 56.5 | 74.8 | 58.3 | ||||||||||||
81/2% Senior Notes Due 2008 | 344.3 | 249.4 | 48.3 | 42.3 | ||||||||||||
83/8% Senior Notes Due 2008 | 6.1 | 4.0 | 59.2 | 46.6 | ||||||||||||
73/4% Senior Notes Due 2009 | 11.0 | 8.1 | 97.2 | 75.9 | ||||||||||||
85/8% Senior Notes Due 2010 | — | — | 210.4 | 170.7 | ||||||||||||
81/2% Senior Notes Due 2011 | 116.9 | 73.1 | 648.4 | 521.3 | ||||||||||||
87/8% Senior Notes Due 2011 | — | — | 125.8 | 94.3 | ||||||||||||
HIGH TIDES III | 115.0 | 111.6 | — | — | ||||||||||||
$ | 1,783.3 | $ | 1,505.6 | $ | 1,853.4 | $ | 1,575.3 | |||||||||
2004 | 2003 | |||||||||||||||
Common | Common | |||||||||||||||
Principal | Stock | Principal | Stock | |||||||||||||
Debt Securities and HIGH TIDES | Amount | Issued | Amount | Issued | ||||||||||||
2006 Convertible Senior Notes | $ | — | — | $ | 65.0 | 12.0 | ||||||||||
81/2% Senior Notes Due 2008 | — | — | 55.0 | 8.1 | ||||||||||||
81/2% Senior Notes Due 2011 | — | — | 25.0 | 3.4 | ||||||||||||
HIGH TIDES I | 40.0 | 8.5 | 37.5 | 6.5 | ||||||||||||
HIGH TIDES II | 75.0 | 15.8 | — | — | ||||||||||||
$ | 115.0 | 24.3 | $ | 182.5 | 30.0 | |||||||||||
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Calpine | ||||||||||||||||
Corporation | ||||||||||||||||
and Restricted | Unrestricted | |||||||||||||||
Subsidiaries | Subsidiaries | Eliminations | Total | |||||||||||||
Assets | $ | 27,020,662 | $ | 438,955 | $ | (224,385 | ) | $ | 27,235,232 | |||||||
Liabilities | $ | 22,000,516 | $ | 253,598 | $ | — | $ | 22,254,114 | ||||||||
Total revenue | $ | 9,225,922 | $ | 19,213 | $ | (15,247 | ) | $ | 9,229,888 | |||||||
Total cost of revenue | (8,867,987 | ) | (23,927 | ) | 17,119 | (8,874,795 | ) | |||||||||
Interest income | 45,760 | 25,824 | (15,172 | ) | 56,412 | |||||||||||
Interest expense | (1,127,009 | ) | (13,793 | ) | — | (1,140,802 | ) | |||||||||
Other | 490,224 | (3,388 | ) | — | 486,836 | |||||||||||
Net income (loss) | $ | (233,090 | ) | $ | 3,929 | $ | (13,300 | ) | $ | (242,461 | ) | |||||
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2004 | ||||
Assets | $ | 72,367 | ||
Liabilities | $ | 56,222 | ||
Total revenue(1) | $ | 667 | ||
Total cost of revenue | $ | — | ||
Interest expense | $ | 7,378 | ||
Net (loss) | $ | (56,167 | ) |
(1) | CNEM’s contracts are derivatives and are recorded on a net mark-to-market basis on our financial statements under SFAS No. 133, notwithstanding that economically they are fully hedged. |
2004 | ||||
Assets | $ | 1,109,825 | ||
Liabilities | $ | 1,245,538 | ||
Total revenue | $ | 513,832 | ||
Total cost of revenue | $ | 469,632 | ||
Interest expense | $ | 66,116 | ||
Net (loss) | $ | (21,188 | ) |
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2004 | ||||
Assets | $ | 624,132 | ||
Liabilities | $ | 285,604 | ||
Total revenue | $ | 110,532 | ||
Total cost of revenue | $ | 54,214 | ||
Interest expense | $ | 20,567 | ||
Net income | $ | 36,864 |
2004 | ||||
Assets | $ | 481,482 | ||
Liabilities | $ | 102,742 |
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2004 | ||||
Assets | $ | 438,955 | ||
Liabilities | $ | 253,598 |
2004 | ||||
Assets | $ | 2,701 | ||
Liabilities | $ | 52,388 |
2004 | ||||
Assets | $ | 35,851 | ||
Liabilities | $ | 34,816 |
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Rocky Mountain | ||||
2004 | ||||
Assets | $ | 416,662 | ||
Liabilities | $ | 277,157 |
Riverside | ||||
2004 | ||||
Assets | $ | 909,687 | ||
Liabilities | $ | 431,700 |
Calpine Riverside | ||||
Holdings, LLC | ||||
2004 | ||||
Assets | $ | 241,893 | ||
Liabilities | $ | — |
Calpine Fox, LLC | ||||
2004 | ||||
Assets | $ | 480,685 | ||
Liabilities | $ | 274,724 |
Calpine Fox | ||||
Holdings, LLC | ||||
2004 | ||||
Assets | $ | 102,980 | ||
Liabilities | $ | — |
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Equipment | Project | |||||||||||||||||||
# of | Included in | Development | Unassigned | |||||||||||||||||
Projects | CIP(1) | CIP | Costs | Equipment | ||||||||||||||||
Projects in construction(2) | 10 | $ | 3,194,530 | $ | 1,094,490 | $ | — | $ | — | |||||||||||
Projects in advanced development | 10 | 670,806 | 520,036 | 102,829 | — | |||||||||||||||
Projects in suspended development | 6 | 421,547 | 168,985 | 38,398 | — | |||||||||||||||
Projects in early development | 2 | — | — | 8,952 | — | |||||||||||||||
Other capital projects | NA | 35,094 | — | — | — | |||||||||||||||
Unassigned equipment | NA | — | — | — | 66,073 | |||||||||||||||
Total construction and development costs | $ | 4,321,977 | $ | 1,783,511 | $ | 150,179 | $ | 66,073 | ||||||||||||
(1) | Construction in Progress (“CIP”). |
(2) | We have a total of 11 projects in construction. This includes the 10 projects above that are recorded in CIP and 1 project that is recorded in investments in power projects. Work and the capitalization of interest on one of the construction projects has been suspended or delayed due to current market conditions. The CIP balance on this project was $461.5 million as of December 31, 2004. Subsequent to December 31, 2004, work and the capitalization of interest on two additional construction projects was suspended or delayed. Total CIP on these two projects was $683.0 million as of December 31, 2004. |
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• | Total deliveries of power. We both generate power that we sell to third parties and purchase power for sale to third parties in hedging, balancing and optimization (“HBO”) transactions. The former sales are recorded as electricity and steam revenue and the latter sales are recorded as sales of purchased power for hedging and optimization. The volumes in MWh for each are key indicators of our respective levels of generation and HBO activity and the sum of the two, our total deliveries of power, is relevant because there are occasions where we can either generate or purchase power to fulfill contractual sales commitments. Prospectively beginning October 1, 2003, in accordance with EITF Issue No. 03-11, certain sales of purchased power for hedging and optimization are shown net of purchased power expense for hedging and optimization in our consolidated statement of operations. Accordingly, we have also netted HBO volumes on the same basis as of October 1, 2003, in the table below. | |
• | Average availability and average baseload capacity factor. Availability represents the percent of total hours during the period that our plants were available to run after taking into account the downtime associated with both scheduled and unscheduled outages. The baseload capacity factor is calculated by dividing (a) total MWh generated by our power plants (excluding peakers) by the product of multiplying (b) the weighted average MW in operation during the period by (c) the total hours in the period. The average baseload capacity factor is thus a measure of total actual generation as a percent of total potential generation. If we elect not to generate during periods when electricity pricing is too low |
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or gas prices too high to operate profitably, the baseload capacity factor will reflect that decision as well as both scheduled and unscheduled outages due to maintenance and repair requirements. | ||
• | Average heat rate for gas-fired fleet of power plants expressed in Btu’s of fuel consumed per kilowatt hour (“KWh”) generated. We calculate the average heat rate for our gas-fired power plants (excluding peakers) by dividing (a) fuel consumed in Btu’s by (b) KWh generated. The resultant heat rate is a measure of fuel efficiency, so the lower the heat rate, the better. We also calculate a “steam-adjusted” heat rate, in which we adjust the fuel consumption in Btu’s down by the equivalent heat content in steam or other thermal energy exported to a third party, such as to steam hosts for our cogeneration facilities. Our goal is to have the lowest average heat rate in the industry. | |
• | Average all-in realized electric price expressed in dollars per MWh generated. Our risk management and optimization activities are integral to our power generation business and directly impact our total realized revenues from generation. Accordingly, we calculate the all-in realized electric price per MWh generated by dividing (a) adjusted electricity and steam revenue, which includes capacity revenues, energy revenues, thermal revenues and the spread on sales of purchased electricity for hedging, balancing, and optimization activity, by (b) total generated MWh in the period. | |
• | Average cost of natural gas expressed in dollars per millions of Btu’s of fuel consumed. Our risk management and optimization activities related to fuel procurement directly impact our total fuel expense. The fuel costs for our gas-fired power plants are a function of the price we pay for fuel purchased and the results of the fuel hedging, balancing, and optimization activities by CES. Accordingly, we calculate the cost of natural gas per millions of Btu’s of fuel consumed in our power plants by dividing (a) adjusted fuel expense which includes the cost of fuel consumed by our plants (adding back cost of inter-company “equity” gas from Calpine Natural Gas, which is eliminated in consolidation), and the spread on sales of purchased gas for hedging, balancing, and optimization activity by (b) the heat content in millions of Btu’s of the fuel we consumed in our power plants for the period. | |
• | Average spark spread expressed in dollars per MWh generated. Our risk management activities focus on managing the spark spread for our portfolio of power plants, the spread between the sales price for electricity generated and the cost of fuel. We calculate the spark spread per MWh generated by subtracting (a) adjusted fuel expense from (b) adjusted E&S revenue and dividing the difference by (c) total generated MWh in the period. | |
• | Average plant operating expense per normalized MWh. To assess trends in electric power plant operating expense (“POX”) per MWh, we normalize the results from period to period by assuming a constant 70% total company-wide capacity factor (including both baseload and peaker capacity) in deriving normalized MWh. By normalizing the cost per MWh with a constant capacity factor, we can better analyze trends and the results of our program to realize economies of scale, cost reductions and efficiencies at our electric generating plants. For comparison purposes we also include POX per actual MWh. |
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Years Ended December 31, | |||||||||||||||
2004 | 2003 | 2002 | |||||||||||||
(In thousands) | |||||||||||||||
Operating Performance Metrics; | |||||||||||||||
Total deliveries of power: | |||||||||||||||
MWh generated | 96,489 | 82,423 | 72,767 | ||||||||||||
HBO and trading MWh sold | 51,175 | 77,232 | 75,740 | ||||||||||||
MWh delivered | 147,664 | 159,655 | 148,507 | ||||||||||||
Average availability | 92.6 | % | 91.2 | % | 91.8 | % | |||||||||
Average baseload capacity factor: | |||||||||||||||
Average total MW in operation | 24,690 | 20,092 | 14,346 | ||||||||||||
Less: Average MW of pure peakers | 2,951 | 2,672 | 1,708 | ||||||||||||
Average baseload MW in operation | 21,739 | 17,420 | 12,638 | ||||||||||||
Hours in the period | 8,784 | 8,760 | 8,760 | ||||||||||||
Potential baseload generation (MWh) | 190,955 | 152,599 | 110,709 | ||||||||||||
Actual total generation (MWh) | 96,489 | 82,423 | 72,767 | ||||||||||||
Less: Actual pure peakers’ generation (MWh) | 1,453 | 1,290 | 979 | ||||||||||||
Actual baseload generation (MWh) | 95,036 | 81,133 | 71,788 | ||||||||||||
Average baseload capacity factor | 49.8 | % | 53.2 | % | 64.8 | % | |||||||||
Average heat rate for gas-fired power plants (excluding peakers) (Btu’s/ KWh): | |||||||||||||||
Not steam adjusted | 8,193 | 8,007 | 7,928 | ||||||||||||
Steam adjusted | 7,120 | 7,253 | 7,239 | ||||||||||||
Average all-in realized electric price: | |||||||||||||||
Electricity and steam revenue | $ | 5,683,063 | $ | 4,680,397 | $ | 3,237,510 | |||||||||
Spread on sales of purchased power for hedging and optimization | 164,747 | 24,118 | 527,546 | ||||||||||||
Adjusted electricity and steam revenue (in thousands) | $ | 5,847,810 | $ | 4,704,515 | $ | 3,765,056 | |||||||||
MWh generated (in thousands) | 96,489 | 82,423 | 72,767 | ||||||||||||
Average all-in realized electric price per MWh | $ | 60.61 | $ | 57.08 | $ | 51.74 | |||||||||
Average cost of natural gas: | |||||||||||||||
Fuel expense (in thousands) | $ | 3,731,108 | $ | 2,665,620 | $ | 1,792,323 | |||||||||
Fuel cost elimination | 208,170 | 284,951 | 141,263 | ||||||||||||
Spread on sales of purchased gas for hedging and optimization | (11,587 | ) | (41,334 | ) | (49,401 | ) | |||||||||
Adjusted fuel expense | $ | 3,927,691 | $ | 2,909,237 | $ | 1,884,185 | |||||||||
Million Btu’s (“MMBtu”) of fuel consumed by generating plants (in thousands) | 657,762 | 560,508 | 511,354 | ||||||||||||
Average cost of natural gas per MMBtu | $ | 5.97 | $ | 5.19 | $ | 3.68 | |||||||||
MWh generated (in thousands) | 96,489 | 82,423 | 72,767 | ||||||||||||
Average cost of adjusted fuel expense per MWh | $ | 40.71 | $ | 35.30 | $ | 25.89 | |||||||||
Average spark spread: | |||||||||||||||
Adjusted electricity and steam revenue (in thousands) | $ | 5,847,810 | $ | 4,704,515 | $ | 3,765,056 | |||||||||
Less: Adjusted fuel expense (in thousands) | 3,927,691 | 2,909,237 | 1,884,185 | ||||||||||||
Spark spread (in thousands) | $ | 1,920,119 | $ | 1,795,278 | $ | 1,880,871 | |||||||||
MWh generated (in thousands) | 96,489 | 82,423 | 72,767 | ||||||||||||
Average spark spread per MWh | $ | 19.90 | $ | 21.78 | $ | 25.85 | |||||||||
Add: Equity gas contribution(1) | $ | 129,255 | $ | 174,922 | $ | 42,769 | |||||||||
Spark spread with equity gas benefits (in thousands) | $ | 2,049,374 | $ | 1,970,200 | $ | 1,923,640 | |||||||||
Average spark spread with equity gas benefits per MWh | $ | 21.24 | $ | 23.90 | $ | 26.44 | |||||||||
Average plant operating expense (“POX”) per normalized MWh (for comparison purposes we also include POX per actual MWh): | |||||||||||||||
Average total consolidated MW in operations | 24,690 | 20,092 | 14,346 | ||||||||||||
Hours per year | 8,784 | 8,760 | 8,760 | ||||||||||||
Total potential MWh | 216,877 | 176,006 | 125,671 | ||||||||||||
Normalized MWh (at 70% capacity factor) | 151,814 | 123,204 | 87,970 | ||||||||||||
Plant operating expense (POX) | $ | 795,975 | $ | 663,045 | $ | 522,906 | |||||||||
POX per normalized MWh | $ | 5.24 | $ | 5.38 | $ | 5.94 | |||||||||
POX per actual MWh | $ | 8.25 | $ | 8.04 | $ | 7.19 |
(1) | Equity gas contribution margin from continuing operations: |
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Years Ended December 31, | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(In thousands) | |||||||||||||
Oil and gas sales | $ | 63,153 | $ | 59,156 | $ | 63,514 | |||||||
Add: Fuel cost eliminated in consolidation | 208,170 | 284,951 | 141,263 | ||||||||||
Subtotal | $ | 271,323 | $ | 344,107 | $ | 204,777 | |||||||
Less: Oil and gas operating expense | 56,843 | 75,453 | 69,840 | ||||||||||
Less: Depletion, depreciation and amortization(a) | 85,225 | 93,732 | 92,168 | ||||||||||
Equity gas contribution margin | $ | 129,255 | $ | 174,922 | $ | 42,769 | |||||||
MWh generated (in thousands) | 96,489 | 82,423 | 72,767 | ||||||||||
Equity gas contribution margin per MWh | $ | 1.34 | $ | 2.12 | $ | 0.59 |
(a) | Excludes oil and gas impairment of $202.1 million, $2.9 million and $3.4 million, respectively. |
Years Ended December 31, | |||||||||||||||
2004 | 2003 | 2002 | |||||||||||||
(In thousands) | |||||||||||||||
Realized: | |||||||||||||||
Power activity | |||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | 52,390 | $ | 52,559 | $ | 12,175 | |||||||||
Other mark-to-market activity(1) | (12,158 | ) | (26,059 | ) | — | ||||||||||
Total realized power activity | $ | 40,232 | $ | 26,500 | $ | 12,175 | |||||||||
Gas activity | |||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | 8,025 | $ | (2,166 | ) | $ | 13,915 | ||||||||
Other mark-to-market activity(1) | — | — | — | ||||||||||||
Total realized gas activity | $ | 8,025 | $ | (2,166 | ) | $ | 13,915 | ||||||||
Total realized activity: | |||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | 60,415 | $ | 50,393 | $ | 26,090 | |||||||||
Other mark-to-market activity(1) | (12,158 | ) | (26,059 | ) | — | ||||||||||
Total realized activity | $ | 48,257 | $ | 24,334 | $ | 26,090 | |||||||||
Unrealized: | |||||||||||||||
Power activity | |||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | (18,075 | ) | $ | (55,450 | ) | $ | 12,974 | |||||||
Ineffectiveness related to cash flow hedges | 1,814 | (5,001 | ) | (4,934 | ) | ||||||||||
Other mark-to-market activity(1) | (13,591 | ) | (1,243 | ) | — | ||||||||||
Total unrealized power activity | $ | (29,852 | ) | $ | (61,694 | ) | $ | 8,040 | |||||||
Gas activity | |||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | (10,700 | ) | $ | 7,768 | $ | (14,792 | ) | |||||||
Ineffectiveness related to cash flow hedges | 5,827 | 3,153 | 2,147 | ||||||||||||
Other mark-to-market activity(1) | — | — | — | ||||||||||||
Total unrealized gas activity | $ | (4,873 | ) | $ | 10,921 | $ | (12,645 | ) | |||||||
Total unrealized activity: | |||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | (28,775 | ) | $ | (47,682 | ) | $ | (1,818 | ) | ||||||
Ineffectiveness related to cash flow hedges | 7,641 | (1,848 | ) | (2,787 | ) | ||||||||||
Other mark-to-market activity(1) | (13,591 | ) | (1,243 | ) | — | ||||||||||
Total unrealized activity | $ | (34,725 | ) | $ | (50,773 | ) | $ | (4,605 | ) | ||||||
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Years Ended December 31, | ||||||||||||||
2004 | 2003 | 2002 | ||||||||||||
(In thousands) | ||||||||||||||
Total mark-to-market activity: | ||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | 31,640 | $ | 2,711 | $ | 24,272 | ||||||||
Ineffectiveness related to cash flow hedges | 7,641 | (1,848 | ) | (2,787 | ) | |||||||||
Other mark-to-market activity(1) | (25,749 | ) | (27,302 | ) | — | |||||||||
Total mark-to-market activity | $ | 13,532 | $ | (26,439 | ) | $ | 21,485 | |||||||
(1) | Activity related to our assets but does not qualify for hedge accounting. |
Fair value of contracts outstanding at January 1, 2004 | $ | 76,541 | |||
Cash losses recognized or otherwise settled during the period(1) | 30,569 | ||||
Non-cash losses recognized or otherwise settled during the period(2) | (34,394 | ) | |||
Changes in fair value attributable to new contracts | (28,896 | ) | |||
Changes in fair value attributable to price movements | (25,260 | ) | |||
Fair value of contracts outstanding at December 31, 2004(3) | $ | 18,560 | |||
Realized cash flow from fair value hedges(4) | $ | 171,096 |
(1) | Recognized (losses) from commodity cash flow hedges of $(89.2) million (represents realized value of cash flow hedge activity of $(70.2) million as disclosed in Note 23 of the Notes to Consolidated Financial Statements, net of non-cash other comprehensive income (“OCI”) items relating to terminated derivatives of $8.1 million and equity method hedges of $10.9 million) and realized gains of $58.6 million on mark-to-market activity, (represents realized value of mark-to-market activity of $48.3 million, as reported in the Consolidated Statements of Operations under mark-to-market activities, net of $(10.3) million of non-cash realized mark-to-market activity). |
(2) | This represents the non-cash amortization of deferred items embedded in our derivative assets and liabilities. |
(3) | Net commodity derivative assets reported in Note 23 of the Notes to Consolidated Financial Statements. |
(4) | Not included as part of the roll-forward of net derivative assets and liabilities because changes in the hedge instrument and hedged item move in equal and offsetting directions to the extent the fair value hedges are perfectly effective. |
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Fair Value Source | 2005 | 2006-2007 | 2008-2009 | After 2009 | Total | |||||||||||||||
Prices actively quoted | $ | 34,636 | $ | 57,175 | $ | — | $ | — | $ | 91,811 | ||||||||||
Prices provided by other external sources | (55,308 | ) | (18,845 | ) | 14,678 | (30,666 | ) | (90,141 | ) | |||||||||||
Prices based on models and other valuation methods | — | 7,800 | 9,090 | — | 16,890 | |||||||||||||||
Total fair value | $ | (20,672 | ) | $ | 46,130 | $ | 23,768 | $ | (30,666 | ) | $ | 18,560 | ||||||||
Credit Quality (Based on Standard & Poor’s Ratings | ||||||||||||||||||||
as of December 31, 2004) | 2005 | 2006-2007 | 2008-2009 | After 2009 | Total | |||||||||||||||
Investment grade | $ | (30,186 | ) | $ | 46,357 | $ | 23,768 | $ | (30,666 | ) | $ | 9,273 | ||||||||
Non-investment grade | 8,676 | 632 | — | — | 9,308 | |||||||||||||||
No external ratings | 838 | (859 | ) | — | — | (21 | ) | |||||||||||||
Total fair value | $ | (20,672 | ) | $ | 46,130 | $ | 23,768 | $ | (30,666 | ) | $ | 18,560 | ||||||||
Fair Value After | ||||||||||
10% Adverse | ||||||||||
Fair Value | Price Change | |||||||||
At December 31, 2004: | ||||||||||
Electricity | $ | (70,457 | ) | $ | (227,624 | ) | ||||
Natural gas | 89,017 | 4,505 | ||||||||
Total | $ | 18,560 | $ | (223,119 | ) | |||||
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Variable to Fixed Swaps |
Weighted Average | Weighted Average | ||||||||||||||||
Notional | Interest Rate | Interest Rate | Fair Market | ||||||||||||||
Maturity Date | Principal Amount | (Pay) | (Receive) | Value | |||||||||||||
2011 | $ | 58,178 | 4.5 | % | 3-month US$ | LIBOR | $ | (1,734 | ) | ||||||||
2011 | 291,897 | 4.5 | % | 3-month US$ | LIBOR | (8,753 | ) | ||||||||||
2011 | 209,833 | 4.4 | % | 3-month US$ | LIBOR | (4,916 | ) | ||||||||||
2011 | 41,822 | 4.4 | % | 3-month US$ | LIBOR | (980 | ) | ||||||||||
2011 | 38,479 | 6.9 | % | 3-month US$ | LIBOR | (4,089 | ) | ||||||||||
2012 | 105,840 | 6.5 | % | 3-month US$ | LIBOR | (11,680 | ) | ||||||||||
2016 | 21,120 | 7.3 | % | 3-month US$ | LIBOR | (3,654 | ) | ||||||||||
2016 | 14,080 | 7.3 | % | 3-month US$ | LIBOR | (2,436 | ) | ||||||||||
2016 | 42,240 | 7.3 | % | 3-month US$ | LIBOR | (7,308 | ) | ||||||||||
2016 | 28,160 | 7.3 | % | 3-month US$ | LIBOR | (4,872 | ) | ||||||||||
2016 | 35,200 | 7.3 | % | 3-month US$ | LIBOR | (6,092 | ) | ||||||||||
Total | $ | 886,849 | 7.3 | % | $ | (56,514 | ) | ||||||||||
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Fixed to Variable Swaps |
Weighted Average | Weighted Average | ||||||||||||||||
Notional | Interest Rate | Interest Rate | Fair Market | ||||||||||||||
Maturity Date | Principal Amount | (Pay) | (Receive) | Value | |||||||||||||
2011 | $ | 100,000 | 6-month US$ | LIBOR | 8.5 | % | $ | (5,406 | ) | ||||||||
2011 | 100,000 | 6-month US$ | LIBOR | 8.5 | % | (3,699 | ) | ||||||||||
2011 | 200,000 | 6-month US$ | LIBOR | 8.5 | % | (7,740 | ) | ||||||||||
2011 | 100,000 | 6-month US$ | LIBOR | 8.5 | % | (6,508 | ) | ||||||||||
Total | $ | 500,000 | 8.5 | % | $ | (23,353 | ) | ||||||||||
Fair Value After a 1.0% | ||||
(100 Basis Points) Adverse | ||||
Net Fair Value as of December 31, 2004 | Interest Rate Change | |||
$(79,867) | $ | (97,567 | ) |
Impact to Pre-Tax Net Income | ||||
After 10% Adverse Exchange | ||||
Currency Exposure | Rate Change | |||
GBP-Euro | $ | (15,982 | ) | |
GBP-$US | (10,781 | ) | ||
$Cdn-$US | (72,294 | ) | ||
Other | (2,241 | ) |
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Year Ended December 31, 2004, Compared to Year Ended December 31, 2003: |
2004 | 2003 | |||||||
Gain (Loss) from $Cdn-$US fluctuations: | $ | (42.8 | ) | $ | (22.6 | ) | ||
Gain (Loss) from GBP-Euro fluctuations: | 0.8 | (12.2 | ) | |||||
Gain (Loss) from GBP-$US fluctuations: | 16.7 | — | ||||||
Gain (Loss) from other currency fluctuations: | 0.2 | 1.5 |
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Year Ended December 31, 2003, Compared to Year Ended December 31, 2002: |
2003 | 2002 | |||||||
Gain (Loss) from $Cdn-$US fluctuations: | $ | (22.6 | ) | $ | (1.3 | ) | ||
Gain (Loss) from GBP-Euro fluctuations: | (12.2 | ) | 0.3 | |||||
Gain (Loss) from other currency fluctuations: | 1.5 | — |
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2005 | 2006 | 2007 | 2008 | |||||||||||||||||
3-month US $LIBOR weighted average interest rate basis(4) | ||||||||||||||||||||
MEP Pleasant Hill Term Loan, Tranche A | $ | 6,700 | $ | 7,482 | $ | 8,132 | $ | 9,271 | ||||||||||||
Saltend preferred interest | — | 360,000 | — | — | ||||||||||||||||
Total of 3-month US $LIBOR rate debt | 6,700 | 367,482 | 8,132 | 9,271 | ||||||||||||||||
1-month EURLIBOR weighted average interest rate basis(4) | ||||||||||||||||||||
Thomassen revolving line of credit | 3,332 | — | — | — | ||||||||||||||||
Total of 1-month EURLIBOR rate debt | 3,332 | — | — | — | ||||||||||||||||
1-month US $LIBOR weighted average interest rate basis(4) | ||||||||||||||||||||
First Priority Secured Floating Rate Notes Due 2009 (CalGen) | — | — | 1,175 | 2,350 | ||||||||||||||||
Total of 1-month US $LIBOR rate debt | — | — | 1,175 | 2,350 | ||||||||||||||||
6-month US $LIBOR weighted average interest rate basis(4) | ||||||||||||||||||||
Third Priority Secured Floating Rate Notes Due 2011 (CalGen) | — | — | — | — | ||||||||||||||||
Total of 6-month US $LIBOR rate debt | — | — | — | — | ||||||||||||||||
5-month US $LIBOR weighted average interest rate basis(4) | ||||||||||||||||||||
Riverside Energy Center project financing | 3,685 | 3,685 | 3,685 | 3,685 | ||||||||||||||||
Rocky Mountain Energy Center project financing | 2,642 | 2,649 | 2,649 | 2,649 | ||||||||||||||||
Total of 6-month US $LIBOR rate debt | 6,327 | 6,334 | 6,334 | 6,334 | ||||||||||||||||
(1)(4) | ||||||||||||||||||||
First Priority Secured Institutional Term Loan Due 2009 (CCFC I) | 3,208 | 3,208 | 3,208 | 3,208 | ||||||||||||||||
Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I) | — | — | — | — | ||||||||||||||||
Total of variable rate debt as defined at(1) below | 3,208 | 3,208 | 3,208 | 3,208 | ||||||||||||||||
(2)(4) | ||||||||||||||||||||
Second Priority Senior Secured Term Loan B Notes Due 2007 | 7,500 | 7,500 | 725,625 | — | ||||||||||||||||
Total of variable rate debt as defined at(2) below | 7,500 | 7,500 | 725,625 | — | ||||||||||||||||
(3)(4) | ||||||||||||||||||||
Second Priority Senior Secured Floating Due 2007 | 5,000 | 5,000 | 483,750 | — | ||||||||||||||||
Blue Spruce Energy Center project financing | 1,875 | 3,750 | 3,750 | 3,750 | ||||||||||||||||
Total of variable rate debt as defined at(3) below | 6,875 | 8,750 | 487,500 | 3,750 | ||||||||||||||||
(5)(4) | ||||||||||||||||||||
First Priority Secured Term Loans Due 2009 (CalGen) | — | — | 3,000 | 6,000 | ||||||||||||||||
Second Priority Secured Floating Rate Notes Due 2010 (CalGen) | — | — | — | 3,200 | ||||||||||||||||
Second Priority Secured Term Loans Due 2010 (CalGen) | — | — | — | 500 | ||||||||||||||||
Total of variable rate debt as defined at(5) below | — | — | 3,000 | 9,700 | ||||||||||||||||
(6)(4) | ||||||||||||||||||||
Island Cogen | 9,954 | — | — | — | ||||||||||||||||
Total of variable rate debt as defined at(6) below | 9,954 | — | — | — | ||||||||||||||||
(6)(4) | ||||||||||||||||||||
Contra Costa | 168 | 175 | 182 | 190 | ||||||||||||||||
Total of variable rate debt as defined at(6) below | 168 | 175 | 182 | 190 | ||||||||||||||||
Grand total variable-rate debt instruments | $ | 44,064 | $ | 393,449 | $ | 1,235,156 | $ | 34,803 | ||||||||||||
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Fair Value | |||||||||||||||
December 31, | |||||||||||||||
2009 | Thereafter | 2004(7) | |||||||||||||
3-month US $LIBOR weighted average interest rate basis(4) | |||||||||||||||
MEP Pleasant Hill Term Loan, Tranche A | $ | 9,433 | $ | 85,802 | $ | 126,820 | |||||||||
Saltend preferred interest | — | — | 360,000 | ||||||||||||
Total of 3-month US $LIBOR rate debt | 9,433 | 85,802 | 486,820 | ||||||||||||
1-month EURLIBOR weighted average interest rate basis(4) | |||||||||||||||
Thomassen revolving line of credit | — | — | 3,332 | ||||||||||||
Total of 1-month EURLIBOR rate debt | — | — | 3,332 | ||||||||||||
1-month US $LIBOR weighted average interest rate basis(4) | |||||||||||||||
First Priority Secured Floating Rate Notes Due 2009 (CalGen) | 231,475 | — | 235,000 | ||||||||||||
Total of 1-month US $LIBOR rate debt | 231,475 | — | 235,000 | ||||||||||||
6-month US $LIBOR weighted average interest rate basis(4) | |||||||||||||||
Third Priority Secured Floating Rate Notes Due 2011 (CalGen) | — | 680,000 | 680,000 | ||||||||||||
Total of 6-month US $LIBOR rate debt | — | 680,000 | 680,000 | ||||||||||||
5-month US $LIBOR weighted average interest rate basis(4) | |||||||||||||||
Riverside Energy Center project financing | 3,685 | 350,075 | 368,500 | ||||||||||||
Rocky Mountain Energy Center project financing | 2,649 | 251,662 | 264,900 | ||||||||||||
Total of 6-month US $LIBOR rate debt | 6,334 | 601,737 | 633,400 | ||||||||||||
(1)(4) | |||||||||||||||
First Priority Secured Institutional Term Loan Due 2009 (CCFC I) | 365,350 | — | 378,182 | ||||||||||||
Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I) | — | 408,568 | 408,568 | ||||||||||||
Total of variable rate debt as defined at(1) below | 365,350 | 408,568 | 786,750 | ||||||||||||
(2)(4) | |||||||||||||||
Second Priority Senior Secured Term Loan B Notes Due 2007 | — | — | 677,672 | ||||||||||||
Total of variable rate debt as defined at(2) below | — | — | 677,672 | ||||||||||||
(3)(4) | |||||||||||||||
Second Priority Senior Secured Floating Due 2007 | — | — | 449,313 | ||||||||||||
Blue Spruce Energy Center project financing | 3,750 | 81,397 | 98,272 | ||||||||||||
Total of variable rate debt as defined at(3) below | 3,750 | 81,397 | 547,585 | ||||||||||||
(5)(4) | |||||||||||||||
First Priority Secured Term Loans Due 2009 (CalGen) | 591,000 | — | 600,000 | ||||||||||||
Second Priority Secured Floating Rate Notes Due 2010 (CalGen) | 6,400 | 622,039 | 631,639 | ||||||||||||
Second Priority Secured Term Loans Due 2010 (CalGen) | 1,000 | 97,194 | 98,694 | ||||||||||||
Total of variable rate debt as defined at(5) below | 598,400 | 719,233 | 1,330,333 | ||||||||||||
(6)(4) | |||||||||||||||
Island Cogen | — | — | 9,954 | ||||||||||||
Total of variable rate debt as defined at(6) below | — | — | 9,954 | ||||||||||||
(6)(4) | |||||||||||||||
Contra Costa | 197 | 1,364 | 2,276 | ||||||||||||
Total of variable rate debt as defined at(6) below | 197 | 1,364 | 2,276 | ||||||||||||
Grand total variable-rate debt instruments | $ | 1,214,939 | $ | 2,578,101 | $ | 5,393,122 | |||||||||
(1) | British Bankers Association LIBOR Rate for deposit in US dollars for a period of six months. |
(2) | U.S. prime rate in combination with the Federal Funds Effective Rate. |
(3) | British Bankers Association LIBOR Rate for deposit in US dollars for a period of three months. |
(4) | Actual interest rates include a spread over the basis amount. |
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(5) | Choice of 1-month US $LIBOR, 2-month US $LIBOR, 3-month US $LIBOR, 6-month US $LIBOR, 12-month US $LIBOR or a base rate. |
(6) | Bankers Acceptance Rate. |
(7) | Fair value equals carrying value, with the exception of the Second-Priority Senior Secured Term B Loans Due 2007 and Second-Priority Senior Secured Floating Rate Notes Due 2007 which are shown at quoted trading values as of December 31, 2004. |
Fair Value of Energy Marketing and Risk Management Contracts and Derivatives |
Credit Reserves |
Liquidity Reserves |
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Accounting for Commodity Contracts |
Normal Purchases and Sales |
97
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Fair Value Hedges |
Cash Flow Hedges |
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Undesignated Derivatives |
• | transactions executed at a location where we do not have an associated natural long (generation capacity) or short (fuel consumption requirements) position of sufficient quantity for the entire term of the transaction (e.g., power sales where we do not own generating assets or intend to acquire transmission rights for delivery from other assets for any portion of the contract term), and | |
• | transactions executed with the intent to profit from short-term price movements, and | |
• | discontinuance (de-designation) of hedge treatment prospectively consistent with paragraphs 25 and 32 of SFAS No. 133. In circumstances where we believe the hedge relationship is no longer necessary, we will remove the hedge designation and close out the hedge positions by entering into an equal and offsetting derivative position. Prospectively, the two derivative positions should generally have no net earnings impact because the changes in their fair values are offsetting. | |
• | any other transactions that do not qualify for hedge accounting |
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Accounting for Long-Lived Assets |
Plant Useful Lives |
Impairment of Long-Lived Assets, Including Intangibles |
Turbine Impairment Charges |
100
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Oil and Gas Property Valuations |
101
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Capitalized Interest |
Accounting for Income and Other Taxes |
102
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Variable Interest Entities and Primary Beneficiary |
103
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Joint Venture Investments and Operating Leases with Fixed Price Options |
Significant Long-Term Power Sales and Tolling Agreements |
Preferred Interests issued from Wholly-Owned Subsidiaries |
Investments in Special Purpose Entities |
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Stock Based Compensation |
105
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106
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2014 | 2023 | |||||||
Convertible | Convertible | |||||||
Notes | Senior Notes | |||||||
Size of issuance | $ | 736,000,000 | $ | 633,775,000 | ||||
Conversion price per share | $ | 3.85 | $ | 6.50 | ||||
Conversion rate | 259.7403 | 153.8462 | ||||||
Trigger price (20% over conversion price) | $ | 4.62 | $ | 7.80 |
Additional Shares |
2014 | 2023 | |||||||||||||||||||
Convertible | Convertible | Share | Dilution in | |||||||||||||||||
Future Calpine Common Stock Price | Notes* | Senior Notes | Subtotal | Share Increase | EPS | |||||||||||||||
$5.00 | 43,968,831 | 0 | 43,968,831 | 9.8 | % | 8.9 | % | |||||||||||||
$7.50 | 93,035,498 | 13,000,542 | 106,036,040 | 23.7 | % | 19.2 | % | |||||||||||||
$10.00 | 117,568,831 | 34,126,375 | 151,695,207 | 33.9 | % | 25.3 | % | |||||||||||||
$20.00 | 154,368,831 | 65,815,125 | 220,183,957 | 49.2 | % | 33.0 | % | |||||||||||||
$40.00 | 172,768,831 | 81,659,500 | 254,428,332 | 56.9 | % | 36.2 | % | |||||||||||||
$100.00 | 183,808,831 | 91,166,125 | 274,974,957 | 61.4 | % | 38.1 | % | |||||||||||||
Basic earnings per share base at December 31, 2004 | 447,509,231 |
* | In the case of the 2014 Convertible Notes, since the conversion value is set for any given common stock price, more shares would be issued when the accreted value is less than $1,000 than in the table above since the accreted value (initially $839 per bond) is paid in cash, and the balance of the conversion value is paid in shares. The incremental shares assuming conversion when the accreted value is only $839 per bond are shown in the table below: |
Incremental | ||||
Future Calpine Common Stock Price | Shares | |||
$5.00 | 23,699,200 | |||
$7.50 | 15,799,467 | |||
$10.00 | 11,849,600 | |||
$20.00 | 5,924,800 | |||
$40.00 | 2,962,400 | |||
$100.00 | 1,184,960 |
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Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
Item 8. | Financial Statements and Supplementary Data |
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |
Item 9A. | Controls and Procedures |
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• | Complete the implementation of the CorpTax computer application to automate more of the tax analysis and provision processes and improve clarity of supporting documentation and reports; | |
• | Will add resources in the tax and accounting departments as well as additional tax accounting training for key personnel and will continue to monitor staffing levels in the future; and | |
• | Engage third party tax experts to review the details of the income tax calculations. |
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Item 9B. | Other Information |
Item 10. | Directors and Executive Officers of the Registrant |
Item 11. | Executive Compensation |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
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Number of Securities | ||||||||||||||
Remaining Available | ||||||||||||||
for Future Issuance | ||||||||||||||
Number of Securities | Under Equity | |||||||||||||
to be Issued Upon | Weighted Average | Compensation Plans | ||||||||||||
Exercise of | Exercise Price of | (Excluding | ||||||||||||
Outstanding Options, | Outstanding Options, | Securities Reflected | ||||||||||||
Plan Category | Warrants, and Rights | Warrants and Rights | in Column(a)) | |||||||||||
Equity compensation plans approved by security holders | ||||||||||||||
Calpine Corporation 1992 Stock Incentive Plan(1) | 1,752,590 | $ | 1.070 | — | ||||||||||
Encal Energy Ltd. Stock Option Plan(2) | 87,274 | $ | 35.692 | — | ||||||||||
Calpine Corporation 1996 Stock Incentive Plan | 32,937,993 | $ | 8.734 | 22,205,905 | ||||||||||
Calpine Corporation 2000 Employee Stock Purchase Plan | — | $ | — | 15,859,702 | ||||||||||
Equity compensation plans not approved by security holders | — | — | — | |||||||||||
Total | 34,777,857 | $ | 8.42 | 38,065,607 | ||||||||||
(1) | The Calpine Corporation 1992 Stock Incentive Plan was approved in 1992 by the Company’s sole security holder at the time, Electrowatt Ltd. |
(2) | In connection with the merger with Encal Energy Ltd., which closed in 2001, we assumed the Encal Energy Fifth Amended and Restated Stock Option Plan. 87,274 shares of our common stock are subject to issuance upon exercise of options granted pursuant to this plan at a weighted average exercise price of $35.692. Other than the shares reserved for future issuance upon the exercise of these options, there are no securities available for future issuance under this Plan. |
Item 13. | Certain Relationships and Related Transactions |
Item 14. | Principal Accounting Fees and Services |
Item 15. | Exhibits, Financial Statement Schedules |
Reports of Independent Registered Public Accounting Firms | |
Consolidated Balance Sheets December 31, 2004 and 2003 | |
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003, and 2002 |
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Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003, and 2002 | |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002 | |
Notes to Consolidated Financial Statements for the Years Ended December 31, 2004, 2003, and 2002 | |
Supplemental Oil and Gas Disclosures |
Exhibit | ||||
Number | Description | |||
2 | .1 | Purchase and Sale Agreement, dated July 1, 2004, among Calpine Corporation (the “Company”), Calpine Natural Gas L.P. and Pogo Producing Company.(a) | ||
2 | .2 | Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Natural Gas L.P. and Bill Barrett Corporation.(a) | ||
2 | .3 | Asset and Trust Unit Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Canada Natural Gas Partnership, Calpine Energy Holdings Limited, PrimeWest Gas Corp. and PrimeWest Energy Trust.(a) | ||
3 | .1 | Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004.(b) | ||
3 | .2 | Amended and Restated By-laws of the Company.(c) | ||
4 | .1.1 | Indenture dated as of May 16, 1996, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(d) | ||
4 | .1.2 | First Supplemental Indenture dated as of August 1, 2000, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(e) | ||
4 | .1.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(f) | ||
4 | .2.1 | Indenture dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(g) | ||
4 | .2.2 | Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(h) | ||
4 | .2.3 | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e) | ||
4 | .2.4 | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f) | ||
4 | .3.1 | Indenture dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(i) | ||
4 | .3.2 | Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(i) | ||
4 | .3.3 | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e) | ||
4 | .3.4 | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f) | ||
4 | .4.1 | Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(j) |
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Exhibit | ||||
Number | Description | |||
4 | .4.2 | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e) | ||
4 | .4.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f) | ||
4 | .5.1 | Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(j) | ||
4 | .5.2 | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e) | ||
4 | .5.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f) | ||
4 | .6.1 | Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(k) | ||
4 | .6.2 | First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(e) | ||
4 | .6.3 | Second Supplemental Indenture dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee.(l) | ||
4 | .7.1 | Amended and Restated Indenture dated as of October 16, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee.(m) | ||
4 | .7.2 | Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(n) | ||
4 | .7.3 | First Amendment, dated as of October 16, 2001, to Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(m) | ||
4 | .8.1 | Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(m) | ||
4 | .8.2 | First Supplemental Indenture, dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(m) | ||
4 | .8.3 | Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(m) | ||
4 | .8.4 | First Amendment, dated as of October 18, 2001, to Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(m) | ||
4 | .9 | Indenture, dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(o) | ||
4 | .10 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o) | ||
4 | .11 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o) | ||
4 | .12 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o) | ||
4 | .13.1 | Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee, including form of Notes.(p) | ||
4 | .13.2 | Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(p) | ||
4 | .13.3 | Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q) |
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Exhibit | ||||
Number | Description | |||
4 | .13.4 | Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q) | ||
4 | .14 | Indenture, dated as of September 30, 2003, among Gilroy Energy Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy Center, as Guarantors, and Wilmington Trust Company, as Trustee and Collateral Agent, including form of Notes.(p) | ||
4 | .15 | Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(q) | ||
4 | .16.1 | Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(q) | ||
4 | .16.2 | Registration Rights Agreement, dated as of November 14, 2003, between the Company and Deutsche Bank Securities, Inc., as Representative of the Initial Purchasers.(q) | ||
4 | .17.1 | First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q) | ||
4 | .17.2 | Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q) | ||
4 | .17.3 | Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q) | ||
4 | .18 | Indenture, dated as of June 2, 2004, between Power Contract Financing III, LLC and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(b) | ||
4 | .19 | Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r) | ||
4 | .20.1 | Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(s) | ||
4 | .20.2 | Amendment No. 1 to Rights Agreement, dated as of September 28, 2004, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(l) | ||
4 | .20.3 | Amendment No. 2 to Rights Agreement, dated as of March 18, 2005, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(bb) | ||
4 | .21 | Memorandum and Articles of Association of Calpine (Jersey) Limited.(t) | ||
4 | .22 | Memorandum and Articles of Association of Calpine European Funding (Jersey) Limited.(t) | ||
4 | .23 | High Tides III | ||
4 | .23.1 | Amended and Restated Certificate of Trust of Calpine Capital Trust III, a Delaware statutory trust, filed July 19, 2000.(u) | ||
4 | .23.2 | Declaration of Trust of Calpine Capital Trust III dated June 28, 2000, among the Company, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee and the Administrative Trustees named therein.(u) | ||
4 | .23.3 | Amendment No. 1 to the Declaration of Trust of Calpine Capital Trust III dated July 19, 2000, among the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein.(u) | ||
4 | .23.4 | Indenture dated as of August 9, 2000, between the Company and Wilmington Trust Company, as Trustee.(u) | ||
4 | .23.5 | Remarketing Agreement dated as of August 9, 2000, among the Company, Calpine Capital Trust III, Wilmington Trust Company, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(u) | ||
4 | .23.6 | Registration Rights Agreement dated as August 9, 2000, between the Company, Calpine Capital Trust III, Credit Suisse First Boston Corporation, ING Barings LLC and CIBC World Markets Corp.(u) |
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Exhibit | ||||
Number | Description | |||
4 | .23.7 | Amended and Restated Declaration of Trust of Calpine Capital Trust III dated as of August 9, 2000, the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein, including the form of Preferred Security and form of Common Security.(u) | ||
4 | .23.8 | Preferred Securities Guarantee Agreement dated as of August 9, 2000, between the Company, as Guarantor, and Wilmington Trust Company, as Guarantee Trustee.(u) | ||
4 | .24 | Pass Through Certificates (Tiverton and Rumford) | ||
4 | .24.1 | Pass Through Trust Agreement dated as of December 19, 2000, among Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of Certificate.(e) | ||
4 | .24.2 | Participation Agreement dated as of December 19, 2000, among the Company, Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership, PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee.(e) | ||
4 | .24.3 | Appendix A — Definitions and Rules of Interpretation.(e) | ||
4 | .24.4 | Indenture of Trust, Mortgage and Security Agreement, dated as of December 19, 2000, between PMCC Calpine New England Investment LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, including the forms of Lessor Notes.(e) | ||
4 | .24.5 | Calpine Guaranty and Payment Agreement (Tiverton) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(e) | ||
4 | .24.6 | Calpine Guaranty and Payment Agreement (Rumford) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(e) | ||
4 | .25 | Pass Through Certificates (South Point, Broad River and RockGen) | ||
4 | .25.1 | Pass Through Trust Agreement A dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 8.400% Pass Through Certificate, Series A.(c) | ||
4 | .25.2 | Pass Through Trust Agreement B dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 9.825% Pass Through Certificate, Series B.(c) | ||
4 | .25.3 | Participation Agreement (SP-1) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.4 | Participation Agreement (SP-2) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) |
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Exhibit | ||||
Number | Description | |||
4 | .25.5 | Participation Agreement (SP-3) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.6 | Participation Agreement (SP-4) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.7 | Participation Agreement (BR-1) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.8 | Participation Agreement (BR-2) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.9 | Participation Agreement (BR-3) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.10 | Participation Agreement (BR-4) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.11 | Participation Agreement (RG-1) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.12 | Participation Agreement (RG-2) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) |
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Exhibit | ||||
Number | Description | |||
4 | .25.13 | Participation Agreement (RG-3) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.14 | Participation Agreement (RG-4) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.15 | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c) | ||
4 | .25.16 | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c) | ||
4 | .25.17 | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c) | ||
4 | .25.18 | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c) | ||
4 | .25.19 | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c) | ||
4 | .25.20 | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c) | ||
4 | .25.21 | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c) | ||
4 | .25.22 | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c) | ||
4 | .25.23 | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c) | ||
4 | .25.24 | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c) |
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Exhibit | ||||
Number | Description | |||
4 | .25.25 | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c) | ||
4 | .25.26 | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c) | ||
4 | .25.27 | Calpine Guaranty and Payment Agreement (South Point SP-1) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.28 | Calpine Guaranty and Payment Agreement (South Point SP-2) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.29 | Calpine Guaranty and Payment Agreement (South Point SP-3) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.30 | Calpine Guaranty and Payment Agreement (South Point SP-4) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.31 | Calpine Guaranty and Payment Agreement (Broad River BR-1) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.32 | Calpine Guaranty and Payment Agreement (Broad River BR-2) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.33 | Calpine Guaranty and Payment Agreement (Broad River BR-3) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.34 | Calpine Guaranty and Payment Agreement (Broad River BR-4) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.35 | Calpine Guaranty and Payment Agreement (RockGen RG-1) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.36 | Calpine Guaranty and Payment Agreement (RockGen RG-2) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.37 | Calpine Guaranty and Payment Agreement (RockGen RG-3) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) |
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Exhibit | ||||
Number | Description | |||
4 | .25.38 | Calpine Guaranty and Payment Agreement (RockGen RG-4) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
10 | .1 | Financing and Term Loan Agreements | ||
10 | .1.1 | Share Lending Agreement, dated as of September 28, 2004, among the Company, as Lender, Deutsche Bank AG London, as Borrower, through Deutsche Bank Securities Inc., as agent for the Borrower, and Deutsche Bank Securities Inc., in its capacity as Collateral Agent and Securities Intermediary.(l) | ||
10 | .1.2 | Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(q) | ||
10 | .1.3.1 | Letter of Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent.(o) | ||
10 | .1.3.2 | Amendment to Letter of Credit Agreement, dated as of September 30, 2004, between the Company and The Bank of Nova Scotia, as Administrative Agent.(v) | ||
10 | .1.4 | Letter of Credit Agreement, dated as of September 30, 2004, between the Company and Bayerische Landesbank, acting through its Cayman Islands Branch, as the Issuer.(v) | ||
10 | .1.5 | Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents.(o) | ||
10 | .1.6.1 | Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(p) | ||
10 | .1.6.2 | Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(p) | ||
10 | .1.6.3 | Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q) | ||
10 | .1.6.4 | Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q) | ||
10 | .1.7 | Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(q) | ||
10 | .1.8 | Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(q) |
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Number | Description | |||
10 | .1.9 | Credit Agreement, dated as of June 24, 2004, among Riverside Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(*) | ||
10 | .1.10 | Credit Agreement, dated as of June 24, 2004, among Rocky Mountain Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(*) | ||
10 | .1.11 | Credit Agreement, dated as of February 25, 2005, among Calpine Steamboat Holdings, LLC, the Lenders named therein, Calyon New York Branch, as a Lead Arranger, Underwriter, Co-Book Runner, Administrative Agent, Collateral Agent and LC Issuer, CoBank, ACB, as a Lead Arranger, Underwriter, Co-Syndication Agent and Co-Book Runner, HSH Nordbank AG, as a Lead Arranger, Underwriter and Co-documentation Agent, UFJ Bank Limited, as a Lead Arranger, Underwriter and Co-Documentation Agent, and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as a Lead Arranger, Underwriter and Co-Syndication Agent.(*) | ||
10 | .2 | Security Agreements | ||
10 | .2.1 | Guarantee and Collateral Agreement, dated as of July 16, 2003, made by the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.2 | First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.3 | First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.4.1 | Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.4.2 | Amendment No. 1 to the Second Amendment Pledge Agreement (Stock Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(q) | ||
10 | .2.5.1 | Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.5.2 | Amendment No. 1 to the Second Amendment Pledge Agreement (Membership Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(q) | ||
10 | .2.6 | First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.7.1 | Collateral Trust Agreement, dated as of July 16, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.7.2 | First Amendment to the Collateral Trust Agreement, dated as of November 18, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(q) | ||
10 | .2.8 | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee.(o) |
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Exhibit | ||||
Number | Description | |||
10 | .2.9 | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.10 | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.11 | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.12 | Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.13 | Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.14 | Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.15 | Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.16 | Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from the Company to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.17 | Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.18 | Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.19 | Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.20 | Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.21 | Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.22 | Designated Asset Sale Proceeds Account Control Agreement, dated as of July 16, 2003, among the Company, Union Bank of California, N.A., and The Bank of New York, as Collateral Agent.(q) | ||
10 | .3 | Management Contracts or Compensatory Plans or Arrangements. | ||
10 | .3.1.1 | Employment Agreement, dated as of January 1, 2005, between the Company and Mr. Peter Cartwright.(w)(x) | ||
10 | .3.1.2 | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Peter Cartwright.(y)(x) | ||
10 | .3.2 | Employment Agreement, dated as of January 1, 2000, between the Company and Ms. Ann B. Curtis.(c)(x) | ||
10 | .3.3 | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Ron A. Walter.(c)(x) |
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Exhibit | ||||
Number | Description | |||
10 | .3.4 | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Robert D. Kelly.(c)(x) | ||
10 | .3.5 | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Thomas R. Mason.(c)(x) | ||
10 | .3.6.1 | Consulting Contract, dated as of January 1, 2005, between the Company and Mr. George J. Stathakis.(*)(x) | ||
10 | .3.6.2 | Consulting Contract, dated as of January 1, 2004, between the Company and Mr. George J. Stathakis.(q)(x) | ||
10 | .3.7 | Form of Indemnification Agreement for directors and officers.(z)(x) | ||
10 | .3.8 | Form of Indemnification Agreement for directors and officers.(c)(x) | ||
10 | .3.9 | Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(q)(x) | ||
10 | .3.10 | Base Salary, Bonus, Stock Option Grant and Restricted Stock Summary Sheet.(w)(x) | ||
10 | .3.11 | Form of Stock Option Agreement.(w)(x) | ||
10 | .3.12 | Form of Restricted Stock Agreement.(w)(x) | ||
10 | .3.13 | Calpine Corporation 2003 Management Incentive Plan.(*)(x) | ||
10 | .3.14 | 2000 Employee Stock Purchase Plan.(aa)(x) | ||
12 | .1 | Statement on Computation of Ratio of Earnings to Fixed Charges.(*) | ||
21 | .1 | Subsidiaries of the Company.(*) | ||
23 | .1 | Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm.(*) | ||
23 | .2 | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.(*) | ||
23 | .3 | Consent of Netherland, Sewell & Associates, Inc., independent engineer.(*) | ||
23 | .4 | Consent of Gilbert Laustsen Jung Associates Ltd., independent engineer.(*) | ||
24 | .1 | Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this report).(*) | ||
31 | .1 | Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*) | ||
31 | .2 | Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*) | ||
32 | .1 | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*) | ||
99 | .1 | Acadia Power Partners, LLC and Subsidiary, Consolidated Financial Statements, December 31, 2003, 2002 and 2001.(*) | ||
99 | .2 | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.(*) |
(*) | Filed herewith. | |
(a) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K/ A filed with the SEC on September 14, 2004. | |
(b) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004. | |
(c) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2001, filed with the SEC on March 29, 2002. | |
(d) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-06259) filed with the SEC on June 19, 1996. | |
(e) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001. |
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(f) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2004, filed with the SEC on May 10, 2004. | |
(g) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997. | |
(h) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-41261) filed with the SEC on November 28, 1997. | |
(i) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-61047) filed with the SEC on August 10, 1998. | |
(j) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-72583) filed with the SEC on March 8, 1999. | |
(k) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17, 2002. | |
(l) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 30, 2004. | |
(m) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001. | |
(n) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-57338) filed with the SEC on April 19, 2001. | |
(o) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003. | |
(p) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003. | |
(q) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004. | |
(r) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on October 6, 2004. | |
(s) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form 8-A/ A (Registration No. 001-12079) filed with the SEC on September 28, 2001. | |
(t) | This document has been omitted in reliance on Item 601(b)(4)(iii) of Regulation S-K. Calpine Corporation agrees to furnish a copy of such document to the SEC upon request. | |
(u) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration Statement No. 333-47068) filed with the SEC on September 29, 2000. | |
(v) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2004, filed with the SEC on November 9, 2004. | |
(w) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 17, 2005. | |
(x) | Management contract or compensatory plan or arrangement. | |
(y) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, filed with the SEC on February 29, 2000. | |
(z) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-1/ A (Registration Statement No. 333-07497) filed with the SEC on August 22, 1996. | |
(aa) | Incorporated by reference to Calpine Corporation’s Definitive Proxy Statement on Schedule 14A dated April 13, 2000, filed with the SEC on April 13, 2000. | |
(bb) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 23, 2005. |
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CALPINE CORPORATION |
By: | /s/ ROBERT D. KELLY |
Robert D. Kelly | |
Executive Vice President and | |
Chief Financial Officer |
Signature | Title | Date | ||||
/s/ PETER CARTWRIGHT | Chairman, President, Chief Executive and Director (Principal Executive Officer) | March 31, 2005 | ||||
/s/ANN B. CURTIS | Executive Vice President, Vice Chairman and Director | March 31, 2005 | ||||
/s/ ROBERT D. KELLY | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | March 31, 2005 | ||||
/s/ CHARLES B. CLARK, JR. | Senior Vice President and Corporate Controller (Principal Accounting Officer) | March 31, 2005 |
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Signature | Title | Date | ||||
Director | ||||||
Director | ||||||
/s/ GERALD GREENWALD | Director | March 31, 2005 | ||||
/s/ SUSAN C. SCHWAB | Director | March 31, 2005 | ||||
/s/ GEORGE J. STATHAKIS | Director | March 31, 2005 | ||||
/s/ SUSAN WANG | Director | March 31, 2005 | ||||
/s/ JOHN O. WILSON | Director | March 31, 2005 |
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2004 | 2003 | |||||||||
(In thousands, except | ||||||||||
share and per | ||||||||||
share amounts) | ||||||||||
ASSETS | ||||||||||
Current assets: | ||||||||||
Cash and cash equivalents | $ | 783,428 | $ | 991,806 | ||||||
Accounts receivable, net of allowance of $8,679 and $7,614 | 1,097,157 | 988,947 | ||||||||
Margin deposits and other prepaid expense | 452,432 | 385,348 | ||||||||
Inventories | 179,395 | 137,740 | ||||||||
Restricted cash | 593,304 | 383,788 | ||||||||
Current derivative assets | 324,206 | 496,967 | ||||||||
Current assets held for sale | — | 2,565 | ||||||||
Other current assets | 133,643 | 89,593 | ||||||||
Total current assets | 3,563,565 | 3,476,754 | ||||||||
Restricted cash, net of current portion | 157,868 | 575,027 | ||||||||
Notes receivable, net of current portion | 203,680 | 213,629 | ||||||||
Project development costs | 150,179 | 139,953 | ||||||||
Investments in power projects and oil and gas properties | 374,032 | 444,150 | ||||||||
Deferred financing costs | 422,606 | 400,732 | ||||||||
Prepaid lease, net of current portion | 424,586 | 414,058 | ||||||||
Property, plant and equipment, net | 20,636,394 | 19,478,650 | ||||||||
Goodwill | 45,160 | 45,160 | ||||||||
Other intangible assets, net | 73,190 | 89,924 | ||||||||
Long-term derivative assets | 506,050 | 673,979 | ||||||||
Long-term assets held for sale | — | 743,149 | ||||||||
Other assets | 658,778 | 608,767 | ||||||||
Total assets | $ | 27,216,088 | $ | 27,303,932 | ||||||
LIABILITIES & STOCKHOLDERS’ EQUITY | ||||||||||
Current liabilities: | ||||||||||
Accounts payable | $ | 1,014,350 | $ | 938,644 | ||||||
Accrued payroll and related expense | 88,719 | 96,693 | ||||||||
Accrued interest payable | 385,794 | 321,176 | ||||||||
Income taxes payable | 82,958 | 18,026 | ||||||||
Notes payable and borrowings under lines of credit, current portion | 204,775 | 254,292 | ||||||||
Preferred interests, current portion | 8,641 | 11,220 | ||||||||
CCFC I financing, current portion | 3,208 | 3,208 | ||||||||
Capital lease obligation, current portion | 5,490 | 4,008 | ||||||||
Construction/project financing, current portion | 93,393 | 61,900 | ||||||||
Senior notes and term loans, current portion | 718,449 | 14,500 | ||||||||
Current derivative liabilities | 364,965 | 456,688 | ||||||||
Current liabilities held for sale | — | 221 | ||||||||
Other current liabilities | 314,650 | 334,827 | ||||||||
Total current liabilities | 3,285,392 | 2,515,403 | ||||||||
Notes payable and borrowings under lines of credit, net of current portion | 769,490 | 873,571 | ||||||||
Notes payable to Calpine Capital Trusts | 517,500 | 1,153,500 | ||||||||
Preferred interests, net of current portion | 497,896 | 232,412 | ||||||||
Capital lease obligation, net of current portion | 283,429 | 193,741 | ||||||||
CCFC I financing, net of current portion | 783,542 | 785,781 | ||||||||
CalGen/ CCFC II financing | 2,395,332 | 2,200,358 | ||||||||
Construction/project financing, net of current portion | 1,905,658 | 1,209,506 | ||||||||
Convertible Senior Notes Due 2006 | 1,326 | 660,059 | ||||||||
Convertible Senior Notes Due 2014 | 620,197 | — | ||||||||
Convertible Senior Notes Due 2023 | 633,775 | 650,000 | ||||||||
Senior notes, net of current portion | 8,532,664 | 9,369,253 | ||||||||
Deferred income taxes, net of current portion | 1,021,739 | 1,310,335 | ||||||||
Deferred lease incentive | — | 50,228 | ||||||||
Deferred revenue | 114,202 | 116,001 | ||||||||
Long-term derivative liabilities | 526,598 | 692,088 | ||||||||
Long-term liabilities held for sale | — | 17,828 | ||||||||
Other liabilities | 346,230 | 241,723 | ||||||||
Total liabilities | 22,234,970 | 22,271,787 | ||||||||
Commitments and contingencies (see Note 25) | ||||||||||
Minority interests | 393,445 | 410,892 | ||||||||
Stockholders’ equity: | ||||||||||
Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and outstanding in 2004 and 2003 | — | — | ||||||||
Common stock, $.001 par value per share; authorized 2,000,000,000 shares in 2003; issued and outstanding 536,509,231 shares in 2004 and 415,010,125 shares in 2003 | 537 | 415 | ||||||||
Additional paid-in capital | 3,151,577 | 2,995,735 | ||||||||
Additional paid-in capital, loaned shares | 258,100 | — | ||||||||
Additional paid-in capital, returnable shares | (258,100 | ) | — | |||||||
Retained earnings | 1,326,048 | 1,568,509 | ||||||||
Accumulated other comprehensive income | 109,511 | 56,594 | ||||||||
Total stockholders’ equity | 4,587,673 | 4,621,253 | ||||||||
Total liabilities and stockholders’ equity | $ | 27,216,088 | $ | 27,303,932 | ||||||
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For the Years Ended | ||||||||||||||||
December 31, | ||||||||||||||||
2004 | 2003 | 2002 | ||||||||||||||
(In thousands, except per | ||||||||||||||||
share amounts) | ||||||||||||||||
Revenue: | ||||||||||||||||
Electric generation and marketing revenue | ||||||||||||||||
Electricity and steam revenue | $ | 5,683,063 | $ | 4,680,397 | $ | 3,237,510 | ||||||||||
Transmission sales revenue | 20,003 | 15,347 | — | |||||||||||||
Sales of purchased power for hedging and optimization | 1,651,767 | 2,714,187 | 3,145,991 | |||||||||||||
Total electric generation and marketing revenue | 7,354,833 | 7,409,931 | 6,383,501 | |||||||||||||
Oil and gas production and marketing revenue | ||||||||||||||||
Oil and gas sales | 63,153 | 59,156 | 63,514 | |||||||||||||
Sales of purchased gas for hedging and optimization | 1,728,301 | 1,320,902 | 870,466 | |||||||||||||
Total oil and gas production and marketing revenue | 1,791,454 | 1,380,058 | 933,980 | |||||||||||||
Mark-to-market activities, net | 13,532 | (26,439 | ) | 21,485 | ||||||||||||
Other revenue | 70,069 | 107,483 | 10,787 | |||||||||||||
Total revenue | 9,229,888 | 8,871,033 | 7,349,753 | |||||||||||||
Cost of revenue: | ||||||||||||||||
Electric generation and marketing expense | ||||||||||||||||
Plant operating expense | 795,975 | 663,045 | 522,906 | |||||||||||||
Royalty expense | 28,673 | 24,932 | 17,615 | |||||||||||||
Transmission purchase expense | 85,514 | 46,455 | 25,486 | |||||||||||||
Purchased power expense for hedging and optimization | 1,487,020 | 2,690,069 | 2,618,445 | |||||||||||||
Total electric generation and marketing expense | 2,397,182 | 3,424,501 | 3,184,452 | |||||||||||||
Oil and gas operating and marketing expense | ||||||||||||||||
Oil and gas operating expense | 56,843 | 75,453 | 69,840 | |||||||||||||
Purchased gas expense for hedging and optimization | 1,716,714 | 1,279,568 | 821,065 | |||||||||||||
Total oil and gas operating and marketing expense | 1,773,557 | 1,355,021 | 890,905 | |||||||||||||
Fuel expense | 3,731,108 | 2,665,620 | 1,792,323 | |||||||||||||
Depreciation, depletion and amortization expense | 574,200 | 504,383 | 398,889 | |||||||||||||
Oil and gas impairment | 202,120 | 2,931 | 3,399 | |||||||||||||
Operating lease expense | 105,886 | 112,070 | 111,022 | |||||||||||||
Other cost of revenue | 90,742 | 42,270 | 7,279 | |||||||||||||
Total cost of revenue | 8,874,795 | 8,106,796 | 6,388,269 | |||||||||||||
Gross profit | 355,093 | 764,237 | 961,484 | |||||||||||||
(Income) loss from unconsolidated investments in power projects and oil and gas properties | 13,525 | (75,804 | ) | (16,552 | ) | |||||||||||
Equipment cancellation and impairment cost | 42,374 | 64,384 | 404,737 | |||||||||||||
Long-term service agreement cancellation charge | 11,334 | 16,355 | — | |||||||||||||
Project development expense | 24,409 | 21,803 | 66,981 | |||||||||||||
Research and development expense | 18,396 | 10,630 | 9,986 | |||||||||||||
Sales, general and administrative expense | 239,347 | 216,471 | 186,056 | |||||||||||||
Income from operations | 5,708 | 510,398 | 310,276 | |||||||||||||
Interest expense | 1,140,802 | 706,307 | 402,677 | |||||||||||||
Distributions on trust preferred securities | — | 46,610 | 62,632 | |||||||||||||
Interest (income) | (56,412 | ) | (39,716 | ) | (43,086 | ) | ||||||||||
Minority interest expense | 34,735 | 27,330 | 2,716 | |||||||||||||
(Income) from repurchase of various issuances of debt | (246,949 | ) | (278,612 | ) | (118,020 | ) | ||||||||||
Other (income), net | (149,093 | ) | (46,126 | ) | (34,200 | ) | ||||||||||
Income (loss) before provision (benefit) for income taxes | (717,375 | ) | 94,605 | 37,557 | ||||||||||||
Provision (benefit) for income taxes | (276,549 | ) | 8,495 | 10,835 | ||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | (440,826 | ) | 86,110 | 26,722 | ||||||||||||
Discontinued operations, net of tax provision (benefit) of $50,095, $(14,416) and $17,104 | 198,365 | 14,969 | 91,896 | |||||||||||||
Cumulative effect of a change in accounting principle, net of tax provision of $ — , $110,913, and $ — | — | 180,943 | — | |||||||||||||
Net income (loss) | $ | (242,461 | ) | $ | 282,022 | $ | 118,618 | |||||||||
Basic earnings per common share: | ||||||||||||||||
Weighted average shares of common stock outstanding | 430,775 | 390,772 | 354,822 | |||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (1.02 | ) | $ | 0.22 | $ | 0.07 | |||||||||
Discontinued operations, net of tax | $ | 0.46 | $ | 0.04 | $ | 0.26 | ||||||||||
Cumulative effect of a change in accounting principle, net of tax | $ | — | $ | 0.46 | $ | — | ||||||||||
Net income (loss) | $ | (0.56 | ) | $ | 0.72 | $ | 0.33 | |||||||||
Diluted earnings per common share: | ||||||||||||||||
Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities | 430,775 | 396,219 | 362,533 | |||||||||||||
Income (loss) before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle | $ | (1.02 | ) | $ | 0.22 | $ | 0.07 | |||||||||
Dilutive effect of certain convertible securities(1) | $ | — | $ | — | $ | — | ||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (1.02 | ) | $ | 0.22 | $ | 0.07 | |||||||||
Discontinued operations, net of tax | $ | 0.46 | $ | 0.04 | $ | 0.26 | ||||||||||
Cumulative effect of a change in accounting principle, net of tax | $ | — | $ | 0.45 | $ | — | ||||||||||
Net income(loss) | $ | (0.56 | ) | $ | 0.71 | $ | 0.33 | |||||||||
(1) | See Note 24 of the Notes to Consolidated Financial Statements for further information. |
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Accumulated | |||||||||||||||||||||||||
Other | |||||||||||||||||||||||||
Additional | Comprehensive | Total | Comprehensive | ||||||||||||||||||||||
Common | Paid-In | Retained | Income | Stockholders’ | Income | ||||||||||||||||||||
Stock | Capital | Earnings | (Loss) | Equity | (Loss) | ||||||||||||||||||||
(In thousands, except share amounts) | |||||||||||||||||||||||||
Balance, January 1, 2002 | $ | 307 | $ | 2,040,833 | $ | 1,167,869 | $ | (240,880 | ) | $ | 2,968,129 | ||||||||||||||
Issuance of 73,757,381 shares of common stock, net of issuance costs | 74 | 751,721 | — | 751,795 | |||||||||||||||||||||
Tax benefit from stock options exercised and other | — | 9,949 | 9,949 | ||||||||||||||||||||||
Comprehensive income: | |||||||||||||||||||||||||
Net income | — | — | 118,618 | — | 118,618 | $ | 118,618 | ||||||||||||||||||
Other comprehensive income | 3,423 | 3,423 | 3,423 | ||||||||||||||||||||||
Total comprehensive income | — | — | — | $ | 122,041 | ||||||||||||||||||||
Balance, December 31, 2002 | 381 | 2,802,503 | 1,286,487 | (237,457 | ) | 3,851,914 | |||||||||||||||||||
Issuance of 34,194,063 shares of common stock, net of issuance costs | 34 | 175,063 | — | — | 175,097 | ||||||||||||||||||||
Tax benefit from stock options exercised and other | — | 2,097 | — | — | 2,097 | ||||||||||||||||||||
Stock compensation expense | — | 16,072 | — | — | 16,072 | ||||||||||||||||||||
Comprehensive income: | |||||||||||||||||||||||||
Net income | — | — | 282,022 | — | 282,022 | $ | 282,022 | ||||||||||||||||||
Other comprehensive income | 294,051 | 294,051 | 294,051 | ||||||||||||||||||||||
Total comprehensive income | — | — | — | — | — | $ | 576,073 | ||||||||||||||||||
Balance, December 31, 2003 | $ | 415 | $ | 2,995,735 | $ | 1,568,509 | $ | 56,594 | $ | 4,621,253 | |||||||||||||||
Issuance of 32,499,106 shares of common stock, net of issuance costs | 33 | 130,141 | — | — | 130,174 | ||||||||||||||||||||
Issuance of 89,000,000 shares of loaned common stock | 89 | 258,100 | — | — | 258,189 | ||||||||||||||||||||
Returnable shares | (258,100 | ) | — | — | (258,100 | ) | |||||||||||||||||||
Tax benefit from stock options exercised and other | — | 4,773 | — | — | 4,773 | ||||||||||||||||||||
Stock compensation expense | 20,928 | 20,928 | |||||||||||||||||||||||
Comprehensive loss: | |||||||||||||||||||||||||
Net loss | — | — | (242,461 | ) | (242,461 | ) | $ | (242,461 | ) | ||||||||||||||||
Other comprehensive income | 52,917 | 52,917 | 52,917 | ||||||||||||||||||||||
Total comprehensive loss | — | — | — | — | — | $ | (189,544 | ) | |||||||||||||||||
Balance, December 31, 2004 | $ | 537 | $ | 3,151,577 | $ | 1,326,048 | $ | 109,511 | $ | 4,587,673 | |||||||||||||||
F-7
Table of Contents
2004 | 2003 | 2002 | ||||||||||||||
(In thousands) | ||||||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | (242,461 | ) | $ | 282,022 | $ | 118,618 | |||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||
Depreciation, depletion and amortization(1) | 833,375 | 732,410 | 538,777 | |||||||||||||
Oil and gas impairment | 202,120 | 2,931 | 3,399 | |||||||||||||
Equipment cancellation and asset impairment cost | 42,374 | 53,058 | 404,737 | |||||||||||||
Development cost write off | — | 3,400 | 56,427 | |||||||||||||
Deferred income taxes, net | (226,454 | ) | 150,323 | 23,206 | ||||||||||||
Gain on sale of assets | (349,611 | ) | (65,351 | ) | (97,377 | ) | ||||||||||
Foreign currency transaction loss (gain) | 25,122 | 33,346 | (986 | ) | ||||||||||||
Cumulative change in accounting principle | — | (180,943 | ) | — | ||||||||||||
Income from repurchase of various issuances of debt | (246,949 | ) | (278,612 | ) | (118,020 | ) | ||||||||||
Minority interests | 34,735 | 27,330 | 2,716 | |||||||||||||
Change in net derivative liability | 14,743 | 59,490 | (340,851 | ) | ||||||||||||
(Income) loss from unconsolidated investments in power projects and oil and gas properties | 9,717 | (76,704 | ) | (16,490 | ) | |||||||||||
Distributions from unconsolidated investments in power projects and oil and gas properties | 29,869 | 141,627 | 14,117 | |||||||||||||
Stock compensation expense | 20,929 | 16,072 | — | |||||||||||||
Change in operating assets and liabilities, net of effects of acquisitions: | ||||||||||||||||
Accounts receivable | (99,447 | ) | (221,243 | ) | 229,187 | |||||||||||
Other current assets | (118,790 | ) | (160,672 | ) | 405,515 | |||||||||||
Other assets | (95,699 | ) | (143,654 | ) | (305,908 | ) | ||||||||||
Accounts payable and accrued expense | 231,827 | (111,901 | ) | (48,804 | ) | |||||||||||
Other liabilities | (55,505 | ) | 27,630 | 200,203 | ||||||||||||
Net cash provided by operating activities | 9,895 | 290,559 | 1,068,466 | |||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Purchases of property, plant and equipment | (1,545,480 | ) | (1,886,013 | ) | (4,036,254 | ) | ||||||||||
Disposals of property, plant and equipment | 1,066,481 | 206,804 | 400,349 | |||||||||||||
Disposal of subsidiary | 85,412 | — | — | |||||||||||||
Acquisitions, net of cash acquired | (187,786 | ) | (6,818 | ) | — | |||||||||||
Advances to joint ventures | (8,788 | ) | (54,024 | ) | (68,088 | ) | ||||||||||
Sale of collateral securities | 93,963 | — | — | |||||||||||||
Project development costs | (29,308 | ) | (35,778 | ) | (105,182 | ) | ||||||||||
Redemption of HIGH TIDES | (110,592 | ) | — | — | ||||||||||||
Cash flows from derivatives not designated as hedges | 16,499 | 42,342 | 26,091 | |||||||||||||
(Increase) decrease in restricted cash | 210,762 | (766,841 | ) | (73,848 | ) | |||||||||||
(Increase) decrease in notes receivable | 10,235 | (21,135 | ) | 8,926 | ||||||||||||
Other | (2,824 | ) | 6,098 | 10,179 | ||||||||||||
Net cash used in investing activities | (401,426 | ) | (2,515,365 | ) | (3,837,827 | ) | ||||||||||
Cash flows from financing activities: | ||||||||||||||||
Repurchase of Zero-Coupon Convertible Debentures Due 2021 | — | — | (869,736 | ) | ||||||||||||
Borrowings from notes payable and lines of credit | 101,781 | 1,672,871 | 1,348,798 | |||||||||||||
Repayments of notes payable and lines of credit | (353,236 | ) | (1,769,072 | ) | (126,404 | ) | ||||||||||
Borrowings from project financing | 3,743,930 | 1,548,601 | 725,111 | |||||||||||||
Repayments of project financing | (3,006,374 | ) | (1,638,519 | ) | (286,293 | ) | ||||||||||
Proceeds from issuance of Convertible Senior Notes | 867,504 | 650,000 | 100,000 | |||||||||||||
Repurchases of Convertible Senior Notes Due 2006 | (834,765 | ) | (455,447 | ) | — | |||||||||||
Repurchases of senior notes | (871,309 | ) | (1,139,812 | ) | — | |||||||||||
Proceeds from issuance of senior notes | 878,814 | 3,892,040 | — | |||||||||||||
Proceeds from preferred interests | 360,000 | — | — | |||||||||||||
Repayment of HIGH TIDES | (483,500 | ) | — | — | ||||||||||||
Proceeds from issuance of common stock | 98 | 15,951 | 751,795 | |||||||||||||
Proceeds from income trust offerings | — | 159,727 | 169,677 | |||||||||||||
Financing costs | (204,139 | ) | (323,167 | ) | (42,783 | ) | ||||||||||
Other | (31,752 | ) | 10,813 | (12,769 | ) | |||||||||||
Net cash provided by financing activities | 167,052 | 2,623,986 | 1,757,396 | |||||||||||||
Effect of exchange rate changes on cash and cash equivalents | 16,101 | 13,140 | (2,693 | ) | ||||||||||||
Net increase (decrease) in cash and cash equivalents | (208,378 | ) | 412,320 | (1,014,658 | ) | |||||||||||
Cash and cash equivalents, beginning of period | 991,806 | 579,486 | 1,594,144 | |||||||||||||
Cash and cash equivalents, end of period | $ | 783,428 | $ | 991,806 | $ | 579,486 | ||||||||||
Cash paid during the period for: | ||||||||||||||||
Interest, net of amounts capitalized | $ | 939,243 | $ | 462,714 | $ | 325,334 | ||||||||||
Income taxes | $ | 22,877 | $ | 18,415 | $ | 15,451 |
(1) | Includes depreciation and amortization that is also recorded in sales, general and administrative expense and interest expense. |
• | 2004 issuance of 24.3 million shares of common stock in exchange for $40.0 million par value of HIGH TIDES I and $75.0 million par value of HIGH TIDES II | |
• | 2004 capital lease entered into for the King City facility for an initial asset balance of $114.9 million | |
• | 2004 issuance of 89 million shares of Calpine common stock pursuant to a Share Lending Agreement. See Note 17 for more information regarding the 89 million shares issued | |
• | 2004 acquired the remaining 50% interest in the Aries Power Plant for $3.7 million cash and $220.0 million of assumed liabilities, including debt of $173.2 million | |
• | 2003 issuance of 30 million shares of common stock in exchange for $182.5 million of debt, convertible debt and preferred securities | |
• | 2002 non-cash consideration of $88.4 million in tendered Company debt received upon the sale of its British Columbia oil and gas properties |
F-8
Table of Contents
1. | Organization and Operations of the Company |
2. | Summary of Significant Accounting Policies |
F-9
Table of Contents
F-10
Table of Contents
F-11
Table of Contents
F-12
Table of Contents
Bankruptcy-Remote Subsidiary | 2004 | |||
Power Contracting Finance, LLC | $ | 175.6 | ||
Gilroy Energy Center, LLC | 53.5 | |||
Rocky Mountain Energy Center, LLC | 18.1 | |||
Riverside Energy Center, LLC | 7.1 | |||
Calpine Energy Management, L.P. | 6.9 | |||
Calpine King City Cogen, LLC | 6.7 | |||
Calpine Northbrook Energy Marketing, LLC | 6.0 | |||
Power Contracting Finance III, LLC | 1.5 | |||
Creed Energy Center, LLC | 0.3 | |||
Goose Haven Energy Center, LLC | 0.3 |
F-13
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F-14
Table of Contents
Accounting for Commodity Contracts |
F-15
Table of Contents
F-16
Table of Contents
Year Ended December 31, | ||||||||
2004 | 2003 | |||||||
Sales of purchased power for hedging and optimization | $ | 1,676,003 | $ | 256,573 | ||||
Purchased power expense for hedging and optimization | $ | 1,676,003 | $ | 265,573 | ||||
F-17
Table of Contents
New Accounting Pronouncements |
SFAS No. 144 |
FIN 46 and FIN 46-R |
F-18
Table of Contents
Joint Venture Investments and Operating Leases with Fixed Price Options |
Significant Long-Term Power Sales and Tolling Agreements |
Preferred Interests issued from Wholly-Owned Subsidiaries |
F-19
Table of Contents
Investments in Special Purpose Entities |
F-20
Table of Contents
FIN 46-R | Sale or | |||||||
Treatment | Financing | |||||||
CNEM | Consolidate | N/A | ||||||
PCF | Deconsolidate | Financing | ||||||
PCF III | Deconsolidate | Financing | ||||||
Trust I, Trust II and Trust III | Deconsolidate | Financing |
EITF Issue No. 04-07 |
EITF Issue No. 04-08 |
F-21
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SFAS No. 128-R |
(i) normal conversion assuming a combination of cash and a variable number of shares; and | |
(ii) conversion during certain limited events of default assuming 100% shares at the fixed conversion rate, or, in the case of the 2023 Convertible Senior Notes, meeting a put entirely with shares of stock. |
EITF Issue No. 03-13 |
EITF Issue No. 03-06 |
F-22
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EITF Issue No. 04-10 |
SFAS No. 123-R |
• | If settlement of an award creates a tax deduction that exceeds compensation cost, the additional tax benefit would be recorded as a contribution to paid-in-capital. | |
• | If the compensation cost exceeds the actual tax deduction, the write-off of the unrealized excess tax benefits would first reduce any available paid-in capital arising from prior excess tax benefits, and any remaining amount would be charged against the tax provision in the income statement. |
F-23
Table of Contents
SFAS No. 151 |
F-24
Table of Contents
SFAS No. 153 |
3. | Available-for-Sale Debt Securities |
Collateral Debt Securities |
HIGH TIDES Securities Held |
F-25
Table of Contents
December 31, 2004 | ||||||||||||||||||||
Gross Unrealized | ||||||||||||||||||||
Gains in Other | Realized | |||||||||||||||||||
Repurchase | Comprehensive | Gains on | ||||||||||||||||||
Price(1) | Income/ (Loss) | Redemption | Redemptions | Fair Value | ||||||||||||||||
HIGH TIDES I | $ | 75,020 | $ | — | $ | 2,480 | $ | (77,500 | ) | $ | — | |||||||||
HIGH TIDES II | 71,341 | — | 3,659 | (75,000 | ) | — | ||||||||||||||
HIGH TIDES III | 110,592 | 958 | — | — | $ | 111,550 | ||||||||||||||
$ | 958 | $ | 6,139 | $ | (152,500 | ) | $ | 111,550 | ||||||||||||
(1) | The repurchase price is shown net of accrued interest. The repurchased amount for HIGH TIDES I was $75.4 million less $0.4 million of accrued interest. The repurchased amount for HIGH TIDES II was $72.0 million less $0.7 million of accrued interest. The repurchased amount for HIGH TIDES III was $111.6 million less $1 million of accrued interest. |
2004 | 2003 | |||||||
Buildings, machinery, and equipment | $ | 16,449,029 | $ | 13,137,550 | ||||
Oil and gas properties, including pipelines | 1,189,626 | 1,176,796 | ||||||
Geothermal properties | 474,869 | 460,602 | ||||||
Other | 218,177 | 234,758 | ||||||
18,331,701 | 15,009,706 | |||||||
Less: Accumulated depreciation and depletion | (2,122,371 | ) | (1,388,225 | ) | ||||
16,209,330 | 13,621,481 | |||||||
Land | 105,087 | 95,037 | ||||||
Construction in progress | 4,321,977 | 5,762,132 | ||||||
Property, plant and equipment, net | $ | 20,636,394 | $ | 19,478,650 | ||||
F-26
Table of Contents
Buildings, Machinery, and Equipment |
Oil and Gas Properties |
F-27
Table of Contents
Geothermal Properties |
Other |
Construction in Progress |
F-28
Table of Contents
Capital Spending — Development and Construction |
Equipment | Project | |||||||||||||||||||
# of | Included in | Development | Unassigned | |||||||||||||||||
Projects | CIP | CIP | Costs | Equipment | ||||||||||||||||
Projects in construction(1) | 10 | $ | 3,194,530 | $ | 1,094,490 | $ | — | $ | — | |||||||||||
Projects in advanced development | 10 | 670,806 | 520,036 | 102,829 | — | |||||||||||||||
Projects in suspended development | 6 | 421,547 | 168,985 | 38,398 | — | |||||||||||||||
Projects in early development | 2 | — | — | 8,952 | — | |||||||||||||||
Other capital projects | NA | 35,094 | — | — | — | |||||||||||||||
Unassigned equipment | NA | — | — | — | 66,073 | |||||||||||||||
Total construction and development costs | $ | 4,321,977 | $ | 1,783,511 | $ | 150,179 | $ | 66,073 | ||||||||||||
(1) | The Company has a total of 11 projects in construction. This includes the 10 projects above that are recorded in CIP and 1 project that is recorded in investments in power projects. Construction activities and the capitalization of interest on one of the construction projects has been suspended or delayed due to current market conditions. The CIP balance on this project was $461.5 million as of December 31, 2004. Subsequent to December 31, 2004, construction activities and the capitalization of interest on two additional construction projects was suspended or delayed. Total CIP on these two projects was $683.0 million as of December 31, 2004. |
F-29
Table of Contents
F-30
Table of Contents
Asset Retirement Obligations |
Asset retirement obligation at January 1, 2003 | $ | 33,929 | |||
Liabilities incurred | 4,311 | ||||
Liabilities settled | (1,397 | ) | |||
Accretion expense | 3,842 | ||||
Revisions in the estimated cash flows | 1,799 | ||||
Other (primarily foreign currency translation) | (6,815 | ) | |||
Asset retirement obligation at December 31, 2003 | $ | 35,669 | |||
Liabilities incurred | 4,207 | ||||
Liabilities settled | (1,279 | ) | |||
Accretion expense | 6,430 | ||||
Revisions in the estimated cash flows | (329 | ) | |||
Other (primarily foreign currency translation) | (2,350 | ) | |||
Asset retirement obligation at December 31, 2004 | $ | 42,348 | |||
5. | Goodwill and Other Intangible Assets |
F-31
Table of Contents
2004 | 2003 | ||||||||
Electric Generation and Marketing | $ | — | $ | — | |||||
Oil and Gas Production and Marketing | — | — | |||||||
Corporate, Other and Eliminations | 45,160 | 45,160 | |||||||
Total | $ | 45,160 | $ | 45,160 | |||||
Weighted | As of December 31, 2004 | As of December 31, 2003 | |||||||||||||||||||
Average | |||||||||||||||||||||
Useful Life/ | Carrying | Accumulated | Carrying | Accumulated | |||||||||||||||||
Contract Life | Amount(1) | Amortization(1) | Amount(1) | Amortization(1) | |||||||||||||||||
Patents | 5 | $ | 485 | $ | (417 | ) | $ | 485 | $ | (320 | ) | ||||||||||
Power sales agreements | 23 | 85,099 | (43,115 | ) | 86,962 | (40,180 | ) | ||||||||||||||
Fuel supply and fuel management contracts | 23 | 5,000 | (1,826 | ) | 22,198 | (4,991 | ) | ||||||||||||||
Geothermal lease rights | 20 | 19,518 | (550 | ) | 19,518 | (450 | ) | ||||||||||||||
Steam purchase agreement | 14 | 6,223 | (1,456 | ) | 5,766 | (944 | ) | ||||||||||||||
Other | 15 | 4,755 | (526 | ) | 2,088 | (208 | ) | ||||||||||||||
Total | $ | 121,080 | $ | (47,890 | ) | $ | 137,017 | $ | (47,093 | ) | |||||||||||
(1) | Fully amortized intangible assets are not included. |
6. | Acquisitions |
F-32
Table of Contents
Calpine Cogeneration Company Transaction |
Aries Transaction |
Current assets | $ | 1,028 | ||
Contracts | 2,505 | |||
Property, plant and equipment | 100,793 | |||
Other assets | 1,902 | |||
Current liabilities | (1,978 | ) | ||
Derivative liability | (16,022 | |||
Long-term debt | $ | (88,228 | ) | |
Brazos Valley Power Plant Transaction |
F-33
Table of Contents
Thomassen Turbine Systems Transaction |
Pro Forma Effects of Acquisitions |
2004 | 2003 | 2002 | ||||||||||
Total revenue | $ | 9,254,727 | $ | 8,958,416 | $ | 7,408,668 | ||||||
Income (loss) before discontinued operations and cumulative effect of accounting changes | $ | (448,541 | ) | $ | 70,831 | $ | 28,562 | |||||
Net income (loss) | $ | (250,176 | ) | $ | 266,743 | $ | 120,458 | |||||
Net income (loss) per basic share | $ | (0.58 | ) | $ | 0.68 | $ | 0.34 | |||||
Net income (loss) per diluted share | $ | (0.58 | ) | $ | 0.67 | $ | 0.33 |
7. | Investments in Power Projects and Oil and Gas Properties |
F-34
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F-35
Table of Contents
Ownership | Investment Balance at | ||||||||||||
Interest as of | December 31, | ||||||||||||
December 31, | |||||||||||||
2004 | 2004 | 2003 | |||||||||||
Acadia Energy Center(1) | 50.0 | % | $ | 214,501 | $ | 221,038 | |||||||
Valladolid III Energy Center | 45.0 | % | 77,401 | 67,320 | |||||||||
Grays Ferry Power Plant | 50.0 | % | 48,558 | 53,272 | |||||||||
Whitby Cogeneration(2) | 15.0 | % | 32,528 | 31,033 | |||||||||
Aries Power Plant(3) | 100.0 | % | — | 58,205 | |||||||||
Androscoggin Energy Center(4) | 32.3 | % | — | 11,823 | |||||||||
Other | — | 1,044 | 1,459 | ||||||||||
Total investments in power projects and oil and gas properties | $ | 374,032 | $ | 444,150 | |||||||||
(1) | On May 12, 2003, the Company completed the restructuring of its interest in Acadia. As part of the transaction, the partnership terminated its 580-megawatt, 20-year tolling arrangement with a subsidiary of Aquila, Inc. in return for a cash payment of $105.5 million. Acadia recorded a gain of $105.5 million and then made a $105.5 million distribution to Calpine. Contemporaneously, the Company’s wholly owned subsidiary, CES, entered into a new 20-year, 580-megawatt tolling contract with Acadia. CES now markets all of the output from the Acadia Power Project under the terms of this new contract and an existing 20-year tolling agreement. Cleco receives a priority cash distributions as its consideration for the restructuring. Also, as a result of this transaction, the Company recorded, as its share of the termination payment from the Aquila subsidiary, a $52.8 million gain as of December 31, 2003, which was recorded within “Income from unconsolidated investments in power projects and oil and gas properties” in the Consolidated Statement of Operations. Due to the restructuring of its interest in Acadia, the Company was required to reconsider its investment in the entity under FIN 46 and determined that it is not the Primary Beneficiary and accordingly will continue to account for its investment using the equity method. See Note 2 for further information. See Note 25 for a legal proceeding involving Acadia Energy Center. |
(2) | Whitby is owned 50% by the Company but a 70% economic share in the Company’s ownership interest has been effectively transferred to Calpine Power, Inc. (“CPI”) through a loan from CPI to the Company’s entity which holds the investment interest in Whitby. |
(3) | On March 26, 2004, the Company acquired the remaining 50 percent interest in Aries Power Plant. See Note 6 for a discussion of the acquisition. |
(4) | Excludes certain Notes Receivable (see Note 8). |
F-36
Table of Contents
December 31, | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
Condensed statements of operations: | |||||||||||||
Revenue | $ | 240,527 | $ | 417,395 | $ | 372,212 | |||||||
Gross profit | 47,339 | 147,782 | 151,784 | ||||||||||
Income from continuing operations before extraordinary items and cumulative effect of a change in accounting principle | (7,951 | ) | 175,154 | 70,596 | |||||||||
Net income (loss) | (7,951 | ) | 175,154 | 70,596 | |||||||||
Condensed balance sheets: | |||||||||||||
Current assets | $ | 67,928 | $ | 87,538 | |||||||||
Non-current assets | 903,681 | 1,474,607 | |||||||||||
Total assets | $ | 971,609 | $ | 1,562,145 | |||||||||
Current liabilities | $ | 150,845 | $ | 91,051 | |||||||||
Non-current liabilities | 114,620 | 727,827 | |||||||||||
Total liabilities | $ | 265,465 | $ | 818,878 | |||||||||
F-37
Table of Contents
Income (loss) from | |||||||||||||||||||||||||
Unconsolidated Investments | |||||||||||||||||||||||||
in Power Projects and | |||||||||||||||||||||||||
Oil and Gas Properties | Distributions | ||||||||||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||
Acadia Power Partners, LLC | $ | 14,142 | $ | 75,272 | $ | 14,590 | $ | 21,394 | $ | 136,977 | $ | 11,969 | |||||||||||||
Valladolid III Energy Center | 76 | — | — | — | — | — | |||||||||||||||||||
Grays Ferry Power Plant | (2,761 | ) | (1,380 | ) | (1,499 | ) | — | — | — | ||||||||||||||||
Whitby Cogeneration | 1,433 | 303 | 411 | 1,499 | — | — | |||||||||||||||||||
Aries Power Plant | (4,264 | ) | (3,442 | ) | (43 | ) | — | — | — | ||||||||||||||||
Calpine Natural Gas Trust | — | — | — | 6,127 | 1,959 | — | |||||||||||||||||||
Androscoggin Energy Center | (23,566 | ) | (7,478 | ) | (3,951 | ) | — | — | |||||||||||||||||
Gordonsville Power Plant | — | 11,985 | 5,763 | — | 2,672 | 2,125 | |||||||||||||||||||
Lockport Power Plant | — | — | 1,570 | — | — | — | |||||||||||||||||||
Other | 575 | 79 | (351 | ) | 849 | 19 | 23 | ||||||||||||||||||
Total | $ | (14,365 | ) | $ | 75,339 | $ | 16,490 | $ | 29,869 | $ | 141,627 | $ | 14,117 | ||||||||||||
Interest income on loans to power projects(1) | $ | 840 | $ | 465 | $ | 62 | |||||||||||||||||||
Total | $ | (13,525 | ) | $ | 75,804 | $ | 16,552 | ||||||||||||||||||
(1) | At December 31, 2004 and 2003, loans to power projects represented an outstanding loan to the Company’s 32.3% owned investment, AELLC, in the amounts of $4.0 million and $13.3 million, respectively, after impairment charges and reserves. |
Related-Party Transactions with Unconsolidated Investments in Power Projects and Oil and Gas Properties |
Operation and Maintenance Agreements — The Company operates and maintains the Acadia and Androscoggin Energy Centers. This includes routine maintenance, but not major maintenance, which is typically performed under agreements with the equipment manufacturers. Responsibilities include development of annual budgets and operating plans. Payments include reimbursement of costs, including Calpine’s internal personnel and other costs, and annual fixed fees. | |
Construction Management Services Agreements — The Company provides construction management services to the Valladolid III Energy Center. Payments include reimbursement of costs, including the Company’s internal personnel and other costs. |
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Administrative Services Agreements — The Company handles administrative matters such as bookkeeping for certain unconsolidated investments. Payment is on a cost reimbursement basis, including Calpine’s internal costs, with no additional fee. | |
Power Marketing Agreements — Under agreements with Androscoggin Energy LLC, CES can either market the plant’s power as the power facility’s agent or buy the power directly. Terms of any direct purchase are to be agreed upon at the time and incorporated into a transaction confirmation. Historically, CES has generally bought the power from the power facility rather than acting as its agent. | |
Gas Supply Agreement — CES can be directed to supply gas to the Androscoggin Energy Center facility pursuant to transaction confirmations between the facility and CES. Contract terms are reflected in individual transaction confirmations. |
2005 | $ | 63,967 | |||
2006 | 63,967 | ||||
2007 | 65,902 | ||||
2008 | 67,836 | ||||
2009 | 67,836 | ||||
Thereafter | 847,952 | ||||
Total | $ | 1,177,460 | |||
2004 | 2003 | |||||||
As of December 31, | ||||||||
Accounts receivable | $ | 765 | $ | 1,156 | ||||
Accounts payable | 9,489 | 12,172 | ||||||
Interest receivable | — | 2,074 | ||||||
Note Receivable | 4,037 | 13,262 | ||||||
Other receivables | — | 8,794 |
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2004 | 2003 | 2002 | ||||||||||
For the Years Ended December 31, | ||||||||||||
Revenue | $ | 1,241 | $ | 3,493 | $ | 4,729 | ||||||
Cost of Revenue | 115,008 | 82,205 | 36,290 | |||||||||
Interest income | 840 | 1,117 | 132 | |||||||||
Gain on sale of assets | 6,240 | 62,176 | — |
8. | Notes Receivable |
2004 | 2003 | ||||||||
PG&E (Gilroy) note | $ | 145,853 | $ | 155,901 | |||||
Panda note | 38,644 | 38,644 | |||||||
Eastman note | 19,748 | — | |||||||
Androscoggin note | 4,037 | 13,262 | |||||||
Mitsui & Co., Ltd note | — | 8,779 | |||||||
Other | 7,168 | 8,506 | |||||||
Total notes receivable | 215,450 | 225,092 | |||||||
Less: Notes receivable, current portion included in other current assets | (11,770 | ) | (11,463 | ) | |||||
Notes receivable, net of current portion | $ | 203,680 | $ | 213,629 | |||||
Gilroy Note |
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Panda Note |
Eastman Note |
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Androscoggin Note |
Mitsui Note |
9. | Canadian Power and Gas Trusts |
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10. | Discontinued Operations |
Corporate and Other |
Oil and Gas Production and Marketing |
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Electric Generation and Marketing |
Summary |
2004 | ||||||||||||||||
Electric | Oil and Gas | |||||||||||||||
Generation | Production | Corporate | ||||||||||||||
and Marketing | and Marketing | and Other | Total | |||||||||||||
Total revenue | $ | 2,679 | $ | 32,415 | $ | — | $ | 35,094 | ||||||||
Gain on disposal before taxes | $ | 35,326 | $ | 208,172 | $ | — | $ | 243,498 | ||||||||
Operating income from discontinued operations before taxes | 24 | 4,938 | — | 4,962 | ||||||||||||
Income from discontinued operations before taxes | $ | 35,350 | $ | 213,110 | $ | — | $ | 248,460 | ||||||||
Income tax provision | $ | (12,394 | ) | $ | (37,701 | ) | $ | — | $ | (50,095 | ) | |||||
Income from discontinued operations, net of tax | $ | 22,956 | $ | 175,409 | $ | — | $ | 198,365 | ||||||||
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2003 | ||||||||||||||||
Electric | Oil and Gas | |||||||||||||||
Generation | Production | Corporate | ||||||||||||||
and Marketing | and Marketing | and Other | Total | |||||||||||||
Total revenue | $ | 72,968 | $ | 49,656 | $ | 3,748 | $ | 126,372 | ||||||||
Loss on disposal before taxes | $ | — | $ | (235 | ) | $ | (11,571 | ) | $ | (11,806 | ) | |||||
Operating income (loss) from discontinued operations before taxes | 4,147 | 15,130 | (6,918 | ) | 12,359 | |||||||||||
Income (loss) from discontinued operations before taxes | $ | 4,147 | $ | 14,895 | $ | (18,489 | ) | $ | 553 | |||||||
Income tax (provision) benefit | (1,453 | ) | 8,651 | 7,218 | 14,416 | |||||||||||
Income from discontinued operations, net of tax | $ | 2,694 | $ | 23,546 | $ | (11,271 | ) | $ | 14,969 | |||||||
2002 | ||||||||||||||||
Electric | Oil and Gas | |||||||||||||||
Generation | Production | Corporate | ||||||||||||||
and Marketing | and Marketing | and Other | Total | |||||||||||||
Total revenue | $ | 75,004 | $ | 134,200 | $ | 7,653 | $ | 216,857 | ||||||||
Gain on disposal before taxes | $ | 35,840 | $ | 59,288 | $ | — | $ | 95,128 | ||||||||
Operating income (loss) from discontinued operations before taxes | 16,388 | 14,452 | (16,968 | ) | 13,872 | |||||||||||
Income (loss) from discontinued operations before taxes | $ | 52,228 | $ | 73,740 | $ | (16,968 | ) | $ | 109,000 | |||||||
Income tax (provision) benefit | (20,151 | ) | (3,868 | ) | 6,915 | (17,104 | ) | |||||||||
Income from discontinued operations, net of tax | $ | 32,077 | $ | 69,872 | $ | (10,053 | ) | $ | 91,896 | |||||||
2003 | ||||||||||||||||
Electric | Oil and Gas | |||||||||||||||
Generation | Production | Corporate | ||||||||||||||
and Marketing | and Marketing | and Other | Total | |||||||||||||
Current assets of discontinued operations | $ | 651 | $ | 1,914 | $ | — | $ | 2,565 | ||||||||
Long-term assets of discontinued operations | 112,148 | 631,001 | — | 743,149 | ||||||||||||
Total assets of discontinued operations | $ | 112,799 | $ | 632,915 | $ | — | $ | 745,714 | ||||||||
Current liabilities of discontinued operations | $ | — | $ | 221 | $ | — | $ | 221 | ||||||||
Long-term liabilities of discontinued operations | 161 | 17,667 | — | 17,828 | ||||||||||||
Total liabilities of discontinued operations | $ | 161 | $ | 17,888 | $ | — | $ | 18,049 | ||||||||
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11. | Debt |
2005 | $ | 1,033,956 | |||
2006 | 944,046 | ||||
2007 | 1,851,022 | ||||
2008 | 2,221,435 | ||||
2009 | 1,667,272 | ||||
Thereafter | 10,257,034 | ||||
Total | $ | 17,974,765 | |||
• | Certain of the Company’s indentures place conditions on its ability to issue indebtedness if the Company’s interest coverage ratio (as defined in those indentures) is below 2:1. Currently, the Company’s interest coverage ratio (as so defined) is below 2:1 and, consequently, the Company generally would not be allowed to issue new debt, except for (i) certain types of new indebtedness that refinances or replaces existing indebtedness, and (ii) non-recourse debt and preferred equity interests issued by the Company’s subsidiaries for purposes of financing certain types of capital expenditures, including plant development, construction and acquisition expenses. In addition, if and so long as the Company’s interest coverage ratio is below 2:1, the Company’s ability to invest in unrestricted subsidiaries and non-subsidiary affiliates and make certain other types of restricted payments will be limited. As of December 31, 2004, the Company’s interest coverage ratio (as so defined) has fallen below 1.75:1 and, until the ratio is greater than 1.75:1, certain of the Company’s indentures will prohibit any further investments in non-subsidiary affiliates. | |
• | Certain of the Company’s indebtedness issued in the last half of 2004 was permitted under the Company’s indentures on the basis that the proceeds would be used to repurchase or redeem existing indebtedness. While the Company completed a portion of such repurchases during the fourth quarter of 2004 and the first quarter of 2005, the Company is still in the process of completing the required amount of repurchases. While the amount of indebtedness that must still be repurchased will ultimately depend on the market price of the Company’s outstanding indebtedness at the time the indebtedness is repurchased, based on current market conditions, the Company currently anticipates that it will spend up to approximately $202.9 million on additional repurchases in order to fully satisfy this requirement. The Company’s bond purchase requirement was estimated to be approximately |
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$270 million as of December 31, 2004, and this amount has been classified as Senior Notes, current portion on the Company’s consolidated balance sheet. | ||
• | When the Company or one of its subsidiaries sells a significant asset or issues preferred equity, the Company’s indentures generally require that the net proceeds of the transaction be used to make capital expenditures or to repurchase or repay certain types of subsidiary indebtedness, in each case within 365 days of the closing date of the transaction. In light of this requirement, and taking into account the amount of capital expenditures currently budgeted for 2005, the Company anticipates that it will need to use approximately $250.0 of the net proceeds of the $360.0 million Two-Year Redeemable Preferred Shares issued on October 26, 2004, and approximately $200.0 million of the net proceeds of the $260.0 million Redeemable Preferred Shares issued on January 31, 2005, to repurchase or repay certain subsidiary indebtedness. The $250.0 million of long-term debt has been reclassified as Senior Notes, current portion liability on the Company’s consolidated balance sheet. The actual amount of the net proceeds that will be required to be used to repurchase or repay subsidiary debt will depend upon the actual amount of the net proceeds that is used to make capital expenditures, which may be more or less than the amount currently budgeted. |
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12. | Notes Payable and Borrowings Under Lines of Credit, Notes Payable to Calpine Capital Trusts and Preferred Interests |
Letters of Credit | ||||||||||||||||||
Borrowings Outstanding | Outstanding | |||||||||||||||||
December 31, | December 31, | |||||||||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||||||||
Corporate Cash Collateralized Letter of Credit Facility | $ | — | $ | — | $ | 233,271 | $ | — | ||||||||||
Power Contract Financing, L.L.C. | 688,366 | 802,246 | — | — | ||||||||||||||
Gilroy note payable(1) | 125,478 | 132,385 | — | — | ||||||||||||||
Siemens Westinghouse Power Corporation | — | 107,994 | — | — | ||||||||||||||
Calpine Northbrook Energy Marketing, LLC (“CNEM”) note | 52,294 | 74,632 | — | — | ||||||||||||||
Corporate revolving lines of credit | — | — | — | 135,600 | ||||||||||||||
Power Contract Financing III, LLC | 51,592 | — | — | — | ||||||||||||||
Calpine Commercial Trust | 34,255 | — | — | — | ||||||||||||||
Other | 22,280 | 10,606 | 6,158 | 603 | ||||||||||||||
Total notes payable and borrowings under lines of credit | 974,265 | 1,127,863 | 239,429 | 136,203 | ||||||||||||||
Total notes payable to Calpine Capital Trusts | 517,500 | 1,153,500 | — | — | ||||||||||||||
Preferred interest in Saltend Energy Centre | 360,000 | — | — | — | ||||||||||||||
Preferred interest in Auburndale Power Plant | 79,135 | 87,632 | — | — | ||||||||||||||
Preferred interest in King City Power Plant | — | 82,000 | — | — | ||||||||||||||
Preferred interest in Gilroy Energy Center, LLC | 67,402 | 74,000 | — | — | ||||||||||||||
Total preferred interests | 506,537 | 243,632 | — | — | ||||||||||||||
Total notes payable and borrowings under lines of credit, notes payable to Calpine Capital Trusts, preferred interests, and term loan | $ | 1,998,302 | $ | 2,524,995 | $ | 239,429 | $ | 136,203 | ||||||||||
Less: notes payable and borrowings under lines of credit, current portion, notes payable to Calpine Capital Trusts, current portion and preferred interests, current portion | 213,416 | 265,512 | ||||||||||||||||
Notes payable and borrowings under lines of credit, net of current portion, notes payable to Calpine Capital Trusts, net of current portion, preferred interests, net of current portion, and term loan | $ | 1,784,886 | $ | 2,259,483 | ||||||||||||||
(1) | See Note 8 for information regarding this note. |
Notes Payable and Borrowings Under Lines of Credit and Term Loan |
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Notes Payable to Calpine Capital Trusts |
Effective | Conversion | |||||||||||||||||||||||||||||||||||
Interest Rate | Ratio — | |||||||||||||||||||||||||||||||||||
per Annum | Number of | |||||||||||||||||||||||||||||||||||
Stated | as of | Balance | Balance | Common | Initial | |||||||||||||||||||||||||||||||
Interest | December 31, | December 31, | December 31, | Shares per 1 | First | Redemption | ||||||||||||||||||||||||||||||
Issue Date | Shares | Rate | 2004 | 2004 | 2003 | High Tide | Redemption Date | Price | ||||||||||||||||||||||||||||
HIGH TIDES I | October 1999 | 5,520,000 | 5.75 | % | 5.38 | % | $ | — | $ | 276,000 | 3.4620 | November 5, 2002 | 101.440 | % | ||||||||||||||||||||||
HIGH TIDES II | January and | |||||||||||||||||||||||||||||||||||
February 2000 | 7,200,000 | 5.50 | % | 5.79 | % | — | 360,000 | 1.9524 | February 5, 2003 | 101.375 | % | |||||||||||||||||||||||||
HIGH TIDES III | August 2000 | 10,350,000 | 5.00 | % | 5.09 | % | 517,500 | 517,500 | 1.1510 | August 5, 2003 | 101.250 | % | ||||||||||||||||||||||||
23,070,000 | $ | 517,500 | $ | 1,153,500 | (1) | |||||||||||||||||||||||||||||||
(1) | Prior to the adoption of FIN 46 as of December 31, 2003, the Trusts were consolidated in the Company’s Consolidated Balance Sheet, and the HIGH TIDES were recorded between total liabilities and stockholders equity as Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts. However, upon adoption of FIN 46 as of December 31, 2003, the Company deconsolidated the Trusts as of October 1, 2003, and therefore no longer records the HIGH TIDES in its Consolidated Balance Sheet. As a result, the Company’s convertible subordinated debentures (as discussed below) issued to the Trusts were no longer eliminated in consolidation and were reflected as notes payable to Calpine Capital Trusts in the Company’s Consolidated Balance Sheet with an outstanding balance of $1.2 billion and $517.5 million at December 31, 2003 and December 31, 2004, respectively. During 2003 and 2004, the Company exchanged 30.8 million Calpine common shares in privately negotiated transactions for approximately $77.5 million par value of HIGH TIDES I, and $75.0 million of HIGH TIDES II. The Company also repurchased $115.0 million par value of HIGH TIDES III for cash of $111.6 million. The repurchased HIGH TIDES III are reflected in the Company’s consolidated balance sheet in Other Assets as available-for-sale securities as the repurchase did not meet the debt extinguishment criteria in SFAS No. 140. See Note 2 for further information regarding the adoption of FIN 46 and Note 3 regarding the Company’s available-for-sale securities. |
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Preferred Interests |
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13. | Capital Lease Obligations |
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King City | ||||||||||||||
Capital Lease | ||||||||||||||
with related | Other Capital | |||||||||||||
party | Leases | Total | ||||||||||||
Years Ending December 31: | ||||||||||||||
2005 | $ | 16,699 | $ | 19,154 | $ | 35,853 | ||||||||
2006 | 16,458 | 19,760 | 36,218 | |||||||||||
2007 | 16,552 | 19,918 | 36,470 | |||||||||||
2008 | 16,199 | 21,753 | 37,952 | |||||||||||
2009 | 16,592 | 21,600 | 38,192 | |||||||||||
Thereafter | 175,492 | 268,317 | 443,809 | |||||||||||
Total minimum lease payments | 257,992 | 370,502 | 628,494 | |||||||||||
Less: Amount representing interest(1) | 162,095 | 177,480 | 339,575 | |||||||||||
Present value of net minimum lease payments | 95,897 | 193,022 | 288,919 | |||||||||||
Less: Capital lease obligation, current portion | 1,199 | 4,291 | 5,490 | |||||||||||
Capital lease obligation, net of current portion | $ | 94,698 | $ | 188,731 | $ | 283,429 | ||||||||
(1) | Amount necessary to reduce net minimum lease payments to present value calculated at the incremental borrowing rate at the time of acquisition. |
14. | CCFC I Financing |
Outstanding at | ||||||||||
December 31, | ||||||||||
2004 | 2003 | |||||||||
Calpine Construction Finance Company I Second Priority Senior Secured Floating Rate Notes Due 2011 | $ | 408,568 | $ | 407,598 | ||||||
First Priority Secured Institutional Term Loans Due 2009 | 378,182 | 381,391 | ||||||||
Total | 786,750 | 788,989 | ||||||||
Less: Current portion | 3,208 | 3,208 | ||||||||
CCFC I financing, net of current portion | $ | 783,542 | $ | 785,781 | ||||||
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15. | CalGen/ CCFC II Financing |
Letters of Credit | |||||||||||||||||
Outstanding at | Outstanding at | ||||||||||||||||
December 31, | December 31, | ||||||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||||||
Calpine Generating Company, LLC | |||||||||||||||||
Third Priority Secured Floating Rate Notes Due 2011 | $ | 680,000 | $ | — | $ | — | $ | — | |||||||||
Second Priority Secured Floating Rate Notes Due 2010 | 631,639 | — | — | — | |||||||||||||
First Priority Secured Term Loans Due 2009 | 600,000 | — | — | — | |||||||||||||
First Priority Secured Floating Rate Notes Due 2009 | 235,000 | — | — | — | |||||||||||||
Third Priority Secured Fixed Rate Notes Due 2011 | 150,000 | — | — | — | |||||||||||||
Second Priority Secured Term Loans Due 2010 | 98,693 | — | — | — | |||||||||||||
First Priority Secured Revolving Loans | — | — | 189,958 | �� | — | ||||||||||||
Calpine Construction Finance Company II Revolver | — | 2,200,358 | — | 53,190 | |||||||||||||
Total CalGen/ CCFC II financing | $ | 2,395,332 | $ | 2,200,358 | $ | 189,958 | $ | 53,190 | |||||||||
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Description | Interest Rate | |||
First Priority Secured Floating Rate Notes Due 2009 | LIBOR plus 375 basis points | |||
Second Priority Secured Floating Rate Notes Due 2010 | LIBOR plus 575 basis points | |||
Third Priority Secured Floating Rate Notes Due 2011 | LIBOR plus 900 basis points | |||
Third Priority Secured Notes Due 2011 | 11.50% | |||
First Priority Secured Term Loans due 2009 | LIBOR plus 375 basis points(1) | |||
Second Priority Secured Term Loans due 2010 | LIBOR plus 575 basis points(2) |
(1) | The Company may also elect a Base Rate plus 275 basis points. |
(2) | The Company may also elect a Base Rate plus 475 basis points. |
2004 Effective Interest | ||||||||
Interest Rate at | Rate after Amortization of | |||||||
December 31, 2004 | Deferred Financing Costs | |||||||
First Priority Secured Floating Rate Notes Due 2009 | 6.0 | % | 5.8 | % | ||||
Second Priority Secured Floating Rate Notes Due 2010 | 8.0 | % | 8.1 | % | ||||
Third Priority Secured Floating Rate Notes Due 2011 | 11.2 | % | 10.9 | % | ||||
Third Priority Secured Fixed Rate Notes Due 2011 | 11.5 | % | 11.8 | % | ||||
First Priority Secured Term Loans Due 2009 | 6.0 | % | 5.8 | % | ||||
Second Priority Secured Term Loans Due 2010 | 8.0 | % | 8.0 | % | ||||
First Priority Secured Revolving Loans | — | 17.5 | % |
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16. | Other Construction/ Project Financing |
Letters of Credit | |||||||||||||||||
Outstanding at | Outstanding at | ||||||||||||||||
December 31, | December 31, | ||||||||||||||||
Projects | 2004 | 2003 | 2004 | 2003 | |||||||||||||
Riverside Energy Center, LLC | $ | 368,500 | $ | 165,347 | $ | — | $ | — | |||||||||
Pasadena Cogeneration, L.P. | 282,896 | 289,115 | — | — | |||||||||||||
Broad River Energy LLC | 275,112 | 291,612 | — | — | |||||||||||||
Fox Energy Company LLC | 266,075 | — | 75,000 | — | |||||||||||||
Rocky Mountain Energy Center, LLC | 264,900 | — | — | — | |||||||||||||
Gilroy Energy Center, LLC, 4% Senior Secured Notes Due 2011 | 261,382 | 298,065 | — | — | |||||||||||||
Aries Power Plant | 174,914 | — | — | — | |||||||||||||
Blue Spruce Energy Center, LLC | 98,272 | 140,000 | — | — | |||||||||||||
Otay Mesa Energy Center, LLC — Ground Lease | 7,000 | 7,000 | — | — | |||||||||||||
Calpine Newark, LLC | — | 47,816 | — | — | |||||||||||||
Calpine Parlin, LLC | — | 32,451 | — | — | |||||||||||||
Total | 1,999,051 | 1,271,406 | $ | 75,000 | $ | — | |||||||||||
Less: Current portion | 93,393 | 61,900 | |||||||||||||||
Long-term construction/project financing | $ | 1,905,658 | $ | 1,209,506 | |||||||||||||
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17. | Convertible Senior Notes |
4% Convertible Senior Notes Due 2006 |
43/4% Contingent Convertible Senior Notes Due 2023 |
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6% Contingent Convertible Notes Due 2014 |
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18. | Senior Notes |
Fair Value as of | ||||||||||||||||||||||||||||
December 31, | December 31, (3) | |||||||||||||||||||||||||||
Interest | First Call | |||||||||||||||||||||||||||
Rates | Date | 2004 | 2003 | 2004 | 2003 | |||||||||||||||||||||||
First Priority Senior Secured Notes | ||||||||||||||||||||||||||||
First Priority Senior Secured Notes Due 2014 | 95/8 | % | (12) | $ | 778,971 | $ | — | $ | 801,367 | $ | — | |||||||||||||||||
First Priority Senior Secured Term Loan B Notes Due 2007 | (4) | (2) | — | 199,500 | — | 202,243 | ||||||||||||||||||||||
Total First Priority Senior Secured Notes | 778,971 | 199,500 | 801,367 | 202,243 | ||||||||||||||||||||||||
Second Priority Senior Secured Notes | ||||||||||||||||||||||||||||
Second Priority Senior Secured Term Loan B Notes Due 2007 | (5) | (8) | 740,625 | 748,125 | 677,672 | 727,552 | ||||||||||||||||||||||
Second Priority Senior Secured Floating Rate Notes Due 2007 | (6) | (7) | 493,750 | 498,750 | 449,313 | 488,775 | ||||||||||||||||||||||
Second Priority Senior Secured Notes Due 2010 | 81/2 | % | (7) | 1,150,000 | 1,150,000 | 987,563 | 1,127,000 | |||||||||||||||||||||
Second Priority Senior Secured Notes Due 2013 | 83/4 | % | (7) | 900,000 | 900,000 | 740,250 | 877,500 | |||||||||||||||||||||
Second Priority Senior Secured Notes Due 2011 | 97/8 | % | (1) | 393,150 | 392,159 | 344,006 | 401,963 | |||||||||||||||||||||
Total Second Priority Senior Secured Notes | 3,677,525 | 3,689,034 | 3,198,804 | 3,622,790 | ||||||||||||||||||||||||
Unsecured Senior Notes | ||||||||||||||||||||||||||||
Senior Notes Due 2005 | 81/4 | % | (2) | 185,949 | 224,679 | 188,424 | 215,692 | |||||||||||||||||||||
Senior Notes Due 2006 | 101/2 | % | 2001 | 152,695 | 166,575 | 151,359 | 163,243 | |||||||||||||||||||||
Senior Notes Due 2006 | 75/8 | % | (1) | 111,563 | 214,613 | 109,332 | 191,006 | |||||||||||||||||||||
Senior Notes Due 2007 | 83/4 | % | 2002 | 195,305 | 226,120 | 177,728 | 187,679 | |||||||||||||||||||||
Senior Notes Due 2007(9) | 83/4 | % | (2) | 165,572 | 154,120 | 150,671 | 114,049 | |||||||||||||||||||||
Senior Notes Due 2008 | 77/8 | % | (1) | 227,071 | 305,323 | 191,875 | 236,624 | |||||||||||||||||||||
Senior Notes Due 2008 | 81/2 | % | (2) | 1,581,539 | 1,925,067 | 1,347,472 | 1,540,053 | |||||||||||||||||||||
Senior Notes Due 2008(10) | 83/8 | % | (2) | 160,050 | 154,140 | 121,638 | 114,064 | |||||||||||||||||||||
Senior Notes Due 2009 | 73/4 | % | (1) | 221,539 | 232,520 | 177,231 | 179,041 | |||||||||||||||||||||
Senior Notes Due 2010 | 85/8 | % | (2) | 496,973 | 496,909 | 402,548 | 390,074 | |||||||||||||||||||||
Senior Notes Due 2011 | 81/2 | % | (2) | 1,063,850 | 1,179,911 | 792,568 | 932,130 | |||||||||||||||||||||
Senior Notes Due 2011(11) | 87/8 | % | (2) | 232,511 | 215,242 | 167,989 | 157,127 | |||||||||||||||||||||
Total Unsecured Senior Notes | 4,794,617 | 5,495,219 | 3,978,835 | 4,420,782 | ||||||||||||||||||||||||
Total Senior Notes | 9,251,113 | 9,383,753 | 7,979,006 | 8,245,815 | ||||||||||||||||||||||||
Less: Senior Notes, current portion | 718,449 | 14,500 | 198,449 | 14,500 | ||||||||||||||||||||||||
Senior Notes, net of current portion | $ | 8,532,664 | $ | 9,369,253 | $ | 7,780,557 | $ | 8,231,315 | ||||||||||||||||||||
(1) | Not redeemable prior to maturity. | |
(2) | Redeemable by the Company at any time prior to maturity. |
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(3) | Represents the market values of the Senior Notes at the respective dates. | |
(4) | 3-month US$ LIBOR, plus a spread. | |
(5) | U.S. Prime Rate in combination with the Federal Funds Effective Rate, plus a spread. | |
(6) | British Bankers Association LIBOR Rate for deposit in U.S. dollars for a period of three months, plus a spread. | |
(7) | At any time before July 15, 2005, with respect to the Second Priority Senior Secured Floating Rate Notes Due 2007 (the “2007 notes”) and before July 15, 2006, with respect to the Second Priority Senior Secured Notes Due 2010 (the “2010 notes”) and the Second Priority Senior Secured Notes Due 2013 (the “2013 notes”), on one or more occasions, the Company can choose to redeem up to 35% of the outstanding principal amount of the applicable series of notes, including any additional notes issued in such series, with the net cash proceeds of any one or more public equity offerings so long as (1) the Company pays holders of the notes a redemption price equal to par plus the applicable Eurodollar rate then in effect with respect to the 2007 notes, 108.500% with respect to the 2010 notes, and 108.750% with respect to the 2013 notes, at the face amount of the notes the Company redeems, plus accrued interest; (2) the Company must redeem the notes within 45 days of such public equity offering; and (3) at least 65% of the aggregate principal amount of the applicable series of notes originally issued under the applicable indenture, including the principal amount of any additional notes, remains outstanding immediately after each such redemption. | |
(8) | The Company may not voluntarily prepay these notes prior to July 15, 2005, except that the Company may on any one or more occasions make such prepayment with the proceeds of one or more public equity offerings. | |
(9) | Issued in Canadian dollars. |
(10) | Issued in Euros. |
(11) | Issued in Sterling. |
(12) | The Company may redeem some or all of the notes at any time on or after October 1, 2009 at specified redemption prices. At any time prior to October 1, 2009, the Company may redeem some or all of the notes at a price equal to 100% of their principal amount and the applicable premium plus accrued and unpaid interest. In addition, at any time prior to October 1, 2007, the Company may redeem up to 35% of the aggregate principal amount of the notes with the net proceeds from one or more public equity offerings at a stated redemption price. |
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2004 | 2003 | |||||||||||||||
Principal | Amount | Principal | Amount | |||||||||||||
Debt Security | Amount | Paid | Amount | Paid | ||||||||||||
81/4% Senior Notes Due 2005 | $ | 38.9 | $ | 34.9 | $ | 25.0 | $ | 24.5 | ||||||||
101/2% Senior Notes Due 2006 | 13.9 | 12.4 | 5.2 | 5.1 | ||||||||||||
75/8% Senior Notes Due 2006 | 103.1 | 96.5 | 35.3 | 32.5 | ||||||||||||
83/4% Senior Notes Due 2007 | 30.8 | 24.4 | 48.9 | 45.0 | ||||||||||||
77/8% Senior Notes Due 2008 | 78.4 | 56.5 | 74.8 | 58.3 | ||||||||||||
81/2% Senior Notes Due 2008(1) | 344.3 | 249.4 | 48.3 | 42.3 | ||||||||||||
83/8% Senior Notes Due 2008(1) | 6.1 | 4.0 | 59.2 | 46.6 | ||||||||||||
73/4% Senior Notes Due 2009 | 11.0 | 8.1 | 97.2 | 75.9 | ||||||||||||
85/8% Senior Notes Due 2010 | — | — | 210.4 | 170.7 | ||||||||||||
81/2% Senior Notes Due 2011 | 116.9 | 73.1 | 648.4 | 521.3 | ||||||||||||
87/8% Senior Notes Due 2011(1) | — | — | 125.8 | 94.3 | ||||||||||||
$ | 743.4 | $ | 559.3 | $ | 1,378.5 | $ | 1,116.5 | |||||||||
(1) | $395.5 million of such repurchased notes have been pledged as security as part of the transactions relating to the issuance by Calpine (Jersey) Limited of Redeemable Preferred Shares. See Note 12 for additional information on such issuance of Redeemable Preferred Shares. |
Principal | Common Stock | |||||||
Debt Security | Amount | Issued | ||||||
81/2% Senior Notes Due 2008 | $ | 55.0 | 8.1 | |||||
81/2% Senior Notes Due 2011 | 25.0 | 3.4 | ||||||
$ | 80.0 | 11.5 | ||||||
First Priority Senior Secured Notes Due 2014 |
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Table of Contents
First Priority Senior Secured Term Loan B Notes Due 2007 |
Second Priority Senior Secured Term Loan B Notes Due 2007 |
Second Priority Senior Secured Floating Rate Notes Due 2007 |
Second Priority Senior Secured Notes Due 2010 |
F-68
Table of Contents
Second Priority Senior Secured Notes Due 2011 |
Second Priority Senior Secured Notes Due 2013 |
Senior Notes Due 2005 |
Senior Notes Due 2006 |
Senior Notes Due 2007 |
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Table of Contents
Senior Notes Due 2008 |
Senior Notes Due 2009 |
Senior Notes Due 2010 |
Senior Notes Due 2011 |
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Table of Contents
19. | Provision for Income Taxes |
2004 | 2003 | 2002 | |||||||||||
U.S. | $ | (552,849 | ) | $ | 35,207 | $ | 25,225 | ||||||
International | (164,526 | ) | 59,398 | 12,332 | |||||||||
Income (loss) before provision for income taxes | $ | (717,375 | ) | $ | 94,605 | $ | 37,557 | ||||||
2004 | 2003 | 2002 | |||||||||||||
Current: | |||||||||||||||
Federal | $ | — | $ | 350 | $ | (72,835 | ) | ||||||||
State | 1,198 | (21,305 | ) | 3,837 | |||||||||||
Foreign | 9,975 | — | — | ||||||||||||
Total Current | 11,173 | (20,955 | ) | (68,998 | ) | ||||||||||
Deferred: | |||||||||||||||
Federal | (161,542 | ) | 413 | 75,377 | |||||||||||
State | (6,194 | ) | 23,089 | 13,964 | |||||||||||
Foreign | (119,986 | ) | 5,948 | (9,508 | ) | ||||||||||
Total Deferred | (287,722 | ) | 29,450 | 79,833 | |||||||||||
Total provision (benefit) | $ | (276,549 | ) | $ | 8,495 | $ | 10,835 | ||||||||
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2004 | 2003 | 2002 | ||||||||||
Expected tax (benefit) rate at United States statutory tax rate | (35.00 | )% | 35.00 | % | 35.00 | % | ||||||
State income tax (benefit), net of federal benefit | (0.45 | )% | 1.23 | % | 30.81 | % | ||||||
Depletion and other permanent items | 1.38 | % | 0.90 | % | (0.20 | )% | ||||||
Valuation allowances | (4.84 | )% | — | — | ||||||||
Tax credits | (0.21 | )% | (2.62 | )% | — | |||||||
Foreign tax at rates other than U.S. statutory rate | 0.57 | % | (34.44 | )% | (36.76 | )% | ||||||
Other, net (including U.S. tax on Foreign Income) | — | 8.91 | % | — | ||||||||
Effective income tax (benefit) rate | (38.55 | )% | 8.98 | % | 28.85 | % | ||||||
2004 | 2003 | |||||||||
Deferred tax assets: | ||||||||||
Net operating loss and credit carryforwards | $ | 1,098,446 | $ | 478,118 | ||||||
Taxes related to risk management activities and SFAS No. 133 | 77,017 | 77,905 | ||||||||
Other differences | 324,040 | 105,280 | ||||||||
Deferred tax assets before valuation allowance | 1,499,503 | 661,303 | ||||||||
Valuation allowance | (62,822 | ) | (19,335 | ) | ||||||
Total Deferred tax assets | 1,436,681 | 641,968 | ||||||||
Deferred tax liabilities: | ||||||||||
Property differences | (2,382,813 | ) | (1,968,012 | ) | ||||||
Total Deferred tax liabilities | (2,382,813 | ) | (1,968,012 | ) | ||||||
Net deferred tax liability | (946,132 | ) | (1,326,044 | ) | ||||||
Less: Current portion: asset/(liability)(1) | (75,608 | ) | 15,709 | |||||||
Deferred income taxes, net of current portion | $ | (1,021,740 | ) | $ | (1,310,335 | ) | ||||
(1) | Current portion of net deferred income taxes are classified within other current assets in 2004 and other current liabilities in 2003 on the Consolidated Balance Sheet. |
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Table of Contents
20. | Employee Benefit Plans |
Retirement Savings Plan |
2000 Employee Stock Purchase Plan |
1996 Stock Incentive Plan |
F-73
Table of Contents
Weighted | ||||||||||||||
Available for | Outstanding | Average | ||||||||||||
Option or | Number of | Exercise | ||||||||||||
Award | Options | Price | ||||||||||||
Outstanding January 1, 2002 | 2,855,949 | 27,690,564 | $ | 9.32 | ||||||||||
Additional shares reserved | 15,070,588 | |||||||||||||
Granted | (8,997,720 | ) | 8,997,720 | 7.20 | ||||||||||
Exercised | — | (5,112,535 | ) | 0.77 | ||||||||||
Canceled | 1,470,802 | (1,470,802 | ) | 26.53 | ||||||||||
Canceled options(1) | (237,705 | ) | — | — | ||||||||||
Outstanding December 31, 2002 | 10,161,914 | 30,104,947 | $ | 9.30 | ||||||||||
Granted | (5,998,585 | ) | 5,998,585 | 3.93 | ||||||||||
Exercised | — | (536,730 | ) | 2.01 | ||||||||||
Canceled | 1,725,221 | (1,725,221 | ) | 13.59 | ||||||||||
Canceled options(1) | (72,470 | ) | ||||||||||||
Awards issued | — | (3,150 | ) | 4.03 | ||||||||||
Outstanding December 31, 2003 | 5,816,080 | 33,838,431 | $ | 8.25 | ||||||||||
Additional shares reserved | 21,000,000 | — | — | |||||||||||
Granted | (5,660,262 | ) | 5,660,262 | 5.47 | ||||||||||
Exercised | — | (3,629,824 | ) | 0.83 | ||||||||||
Canceled | 1,089,032 | (1,089,032 | ) | 18.21 | ||||||||||
Canceled options(1) | (38,945 | ) | — | — | ||||||||||
Awards issued | — | (1,980 | ) | 4.33 | ||||||||||
Outstanding December 31, 2004 | 22,205,905 | 34,777,857 | 8.42 | |||||||||||
Options exercisable: | ||||||||||||||
December 31, 2002 | 19,418,239 | 7.14 | ||||||||||||
December 31, 2003 | 22,953,781 | 8.02 | ||||||||||||
December 31, 2004 | 22,949,497 | 9.30 |
(1) | Represents cessation of options awarded under the Encal stock option plan |
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Table of Contents
Weighted | ||||||||||||||||||||
Average | Weighted | Weighted | ||||||||||||||||||
Number of | Remaining | Average | Number of | Average | ||||||||||||||||
Options | Contractual | Exercise | Options | Exercise | ||||||||||||||||
Range of Exercise Prices | Outstanding | Life in Years | Price | Exercisable | Price | |||||||||||||||
$ 0.645-$ 2.150 | 4,073,196 | 2.55 | $ | 1.606 | 4,072,693 | $ | 1.606 | |||||||||||||
$ 2.240-$ 3.860 | 5,220,014 | 3.58 | 3.321 | 5,166,889 | 3.321 | |||||||||||||||
$ 3.910-$ 3.980 | 5,254,837 | 8.02 | 3.980 | 1,720,183 | 3.980 | |||||||||||||||
$ 4.010-$ 5.240 | 3,036,785 | 7.36 | 5.157 | 1,691,122 | 5.094 | |||||||||||||||
$ 5.250-$ 5.560 | 5,397,275 | 9.15 | 5.560 | 152,350 | 5.549 | |||||||||||||||
$ 5.565-$ 7.640 | 3,854,747 | 5.97 | 7.561 | 2,847,889 | 7.538 | |||||||||||||||
$ 7.750-$13.850 | 3,735,013 | 4.86 | 10.595 | 3,465,918 | 10.343 | |||||||||||||||
$13.917-$48.150 | 4,063,810 | 5.00 | 31.054 | 3,705,184 | 29.569 | |||||||||||||||
$48.188-$56.920 | 140,330 | 6.23 | 51.292 | 125,419 | 51.271 | |||||||||||||||
$56.990-$56.990 | 1,850 | 6.33 | 56.990 | 1,850 | 56.990 | |||||||||||||||
$ 0.645-$56.990 | 34,777,857 | 5.90 | $ | 8.416 | 22,949,497 | $ | 9.299 | |||||||||||||
21. | Stockholders’ Equity |
Common Stock |
Preferred Stock and Preferred Share Purchase Rights |
F-75
Table of Contents
Stock-Based Compensation |
F-76
Table of Contents
2004 | 2003 | 2002 | ||||||||||||
Net income (loss) | ||||||||||||||
As reported | $ | (242,461 | ) | $ | 282,022 | $ | 118,618 | |||||||
Pro Forma | (247,316 | ) | 270,418 | 83,025 | ||||||||||
Earnings (loss) per share data: | ||||||||||||||
Basic earnings (loss) per share | ||||||||||||||
As reported | $ | (0.56 | ) | $ | 0.72 | $ | 0.33 | |||||||
Pro Forma | (0.57 | ) | 0.69 | 0.23 | ||||||||||
Diluted earnings per share | ||||||||||||||
As reported | $ | (0.56 | ) | $ | 0.71 | $ | 0.33 | |||||||
Pro Forma | (0.57 | ) | 0.68 | 0.23 | ||||||||||
Stock-based compensation cost included in net income (loss), as reported | $ | 12,734 | $ | 9,724 | $ | — | ||||||||
Stock-based compensation cost included in net income (loss), pro forma | 17,589 | 21,328 | 35,593 |
Comprehensive Income (Loss) |
F-77
Table of Contents
Total | ||||||||||||||||||||||
Accumulated | ||||||||||||||||||||||
Foreign | Other | |||||||||||||||||||||
Cash Flow | Available-For- | Currency | Comprehensive | Comprehensive | ||||||||||||||||||
Hedges(1) | Sale Investments | Translation | Income (Loss) | Income (Loss) | ||||||||||||||||||
Accumulated other comprehensive loss at January 1, 2002 | $ | (180,819 | ) | $ | — | $ | (60,061 | ) | $ | (240,880 | ) | |||||||||||
Net income | $ | 118,618 | ||||||||||||||||||||
Cash flow hedges: | ||||||||||||||||||||||
Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment | 96,905 | |||||||||||||||||||||
Reclassification adjustment for gain included in net income | (169,205 | ) | ||||||||||||||||||||
Income tax benefit | 28,705 | |||||||||||||||||||||
(43,595 | ) | (43,595 | ) | (43,595 | ) | |||||||||||||||||
Foreign currency translation gain | 47,018 | 47,018 | 47,018 | |||||||||||||||||||
Total comprehensive income | $ | 122,041 | ||||||||||||||||||||
Accumulated other comprehensive loss at December 31, 2002 | $ | (224,414 | ) | $ | (13,043 | ) | $ | (237,457 | ) | |||||||||||||
Net income | $ | 282,022 | ||||||||||||||||||||
Cash flow hedges: | ||||||||||||||||||||||
Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment | 112,481 | |||||||||||||||||||||
Reclassification adjustment for loss included in net income | 55,620 | |||||||||||||||||||||
Income tax provision | (74,106 | ) | ||||||||||||||||||||
93,995 | 93,995 | 93,995 | ||||||||||||||||||||
Foreign currency translation gain | 200,056 | 200,056 | 200,056 | |||||||||||||||||||
Total comprehensive income | $ | 576,073 | ||||||||||||||||||||
Accumulated other comprehensive gain (loss) at December 31, 2003 | $ | (130,419 | ) | $ | 187,013 | $ | 56,594 | |||||||||||||||
Net loss | $ | (242,461 | ) | |||||||||||||||||||
Cash flow hedges: | ||||||||||||||||||||||
Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment | (106,071 | ) | ||||||||||||||||||||
Reclassification adjustment for loss included in net loss | 89,888 | |||||||||||||||||||||
Income tax provision | 6,451 | |||||||||||||||||||||
(9,732 | ) | (9,732 | ) | (9,732 | ) | |||||||||||||||||
Available-for-sale investments: | ||||||||||||||||||||||
Comprehensive pre-tax gain on available-for-sale investments before reclassification adjustment | 19,239 | |||||||||||||||||||||
Reclassification adjustment for gain included in net loss | (18,281 | ) | ||||||||||||||||||||
Income tax provision | (376 | ) | ||||||||||||||||||||
582 | 582 | 582 | ||||||||||||||||||||
Foreign currency translation gain | 62,067 | 62,067 | 62,067 | |||||||||||||||||||
Total comprehensive loss | $ | (189,544 | ) | |||||||||||||||||||
Accumulated other comprehensive gain (loss) at December 31, 2004 | $ | (140,151 | ) | $ | 582 | $ | 249,080 | $ | 109,511 | |||||||||||||
(1) | Includes AOCI from cash flow hedges held by unconsolidated investees. At December 31, 2004, 2003 and 2002, these amounts were $1,698, $6,911 and $12,018, respectively. |
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Table of Contents
22. | Customers |
Significant Customer |
Counterparty Exposure |
California Department of Water Resources |
Lease Income |
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Table of Contents
2005 | $ | 123,435 | |||
2006 | 175,349 | ||||
2007 | 213,431 | ||||
2008 | 285,386 | ||||
2009 | 288,516 | ||||
Thereafter | 2,844,717 | ||||
Total | $ | 3,930,834 | |||
Credit Evaluations |
23. | Derivative Instruments |
Commodity Derivative Instruments |
F-80
Table of Contents
Interest Rate and Currency Derivative Instruments |
F-81
Table of Contents
Summary of Derivative Values |
Commodity | ||||||||||||||
Interest Rate | Derivative | Total | ||||||||||||
Derivative | Instruments | Derivative | ||||||||||||
Instruments | Net | Instruments | ||||||||||||
Current derivative assets | $ | 620 | $ | 323,586 | $ | 324,206 | ||||||||
Long-term derivative assets | — | 506,050 | 506,050 | |||||||||||
Total assets | $ | 620 | $ | 829,636 | $ | 830,256 | ||||||||
Current derivative liabilities | $ | 21,578 | $ | 343,387 | $ | 364,965 | ||||||||
Long-term derivative liabilities | 58,909 | 467,689 | 526,598 | |||||||||||
Total liabilities | $ | 80,487 | $ | 811,076 | $ | 891,563 | ||||||||
Net derivative assets (liabilities) | $ | (79,867 | ) | $ | 18,560 | $ | (61,307 | ) | ||||||
• | Tax effect of OCI — When the values and subsequent changes in values of derivatives that qualify as effective hedges are recorded into OCI, they are initially offset by a derivative asset or liability. Once in OCI, however, these values are tax effected against a deferred tax liability or asset account, thereby creating an imbalance between net OCI and net derivative assets and liabilities. | |
• | Derivatives not designated as cash flow hedges and hedge ineffectiveness — Only derivatives that qualify as effective cash flow hedges will have an offsetting amount recorded in OCI. Derivatives not designated as cash flow hedges and the ineffective portion of derivatives designated as cash flow hedges will be recorded into earnings instead of OCI, creating a difference between net derivative assets and liabilities and pre-tax OCI from derivatives. | |
• | Termination of effective cash flow hedges prior to maturity — Following the termination of a cash flow hedge, changes in the derivative asset or liability are no longer recorded to OCI. At this point, an AOCI balance remains that is not recognized in earnings until the forecasted initially hedged transactions occur. As a result, there will be a temporary difference between OCI and derivative assets and liabilities on the books until the remaining OCI balance is recognized in earnings. |
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Table of Contents
Net derivative liabilities | $ | (61,307 | ) | |
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness | (86,496 | ) | ||
Cash flow hedges terminated prior to maturity | (75,725 | ) | ||
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges | 77,640 | |||
AOCI from unconsolidated investees | 5,737 | |||
Accumulated other comprehensive loss from derivative instruments, net of tax(1) | $ | (140,151 | ) | |
(1) | Amount represents one portion of the Company’s total AOCI balance. See Note 21 for further information. |
December 31, 2004 | ||||||||||
Gross | Net | |||||||||
Current derivative assets | $ | 844,050 | $ | 323,586 | ||||||
Long-term derivative assets | 967,089 | 506,050 | ||||||||
Total derivative assets | $ | 1,811,139 | $ | 829,636 | ||||||
Current derivative liabilities | $ | 863,850 | $ | 343,387 | ||||||
Long-term derivative liabilities | 928,729 | 467,689 | ||||||||
Total derivative liabilities | $ | 1,792,579 | $ | 811,076 | ||||||
Net commodity derivative assets | $ | 18,560 | $ | 18,560 | ||||||
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Table of Contents
2004 | 2003 | 2002 | |||||||||||||||||||||||||||||||||||
Hedge | Undesignated | Hedge | Undesignated | Hedge | Undesignated | ||||||||||||||||||||||||||||||||
Ineffectiveness | Derivatives | Total | Ineffectiveness | Derivatives | Total | Ineffectiveness | Derivatives | Total | |||||||||||||||||||||||||||||
Natural gas derivatives(1) | $ | 5,827 | $ | (10,700 | ) | $ | (4,873 | ) | $ | 3,153 | $ | 7,768 | $ | 10,921 | $ | 2,147 | $ | (14,792 | ) | $ | (12,645 | ) | |||||||||||||||
Power derivatives(1) | 1,814 | (31,666 | ) | (29,852 | ) | (5,001 | ) | (56,693 | ) | (61,694 | ) | (4,934 | ) | 12,974 | 8,040 | ||||||||||||||||||||||
Interest rate derivatives(2) | 1,492 | 6,035 | 7,527 | (974 | ) | — | (974 | ) | (810 | ) | — | (810 | ) | ||||||||||||||||||||||||
Currency derivatives | — | (12,897 | ) | (12,897 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||||
Total | $ | 9,133 | $ | (49,228 | ) | $ | (40,095 | ) | $ | (2,822 | ) | $ | (48,925 | ) | $ | (51,747 | ) | $ | (3,597 | ) | $ | (1,818 | ) | $ | (5,415 | ) | |||||||||||
(1) | Represents the unrealized portion of mark-to-market activity on gas and power transactions. The unrealized portion of mark-to-market activity is combined with the realized portions of mark-to-market activity and presented in the Consolidated Statements of Operations as mark-to-market activities, net. |
(2) | Recorded within Other Income |
2004 | 2003 | 2002 | |||||||||||
Natural gas and crude oil derivatives | $ | 58,308 | $ | 40,752 | $ | (119,419 | ) | ||||||
Power derivatives | (128,556 | ) | (79,233 | ) | 304,073 | ||||||||
Interest rate derivatives | (17,625 | ) | (27,727 | ) | (10,993 | ) | |||||||
Foreign currency derivatives | (2,015 | ) | 10,588 | (4,456 | ) | ||||||||
Total derivatives | $ | (89,888 | ) | $ | (55,620 | ) | $ | 169,205 | |||||
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Table of Contents
2010 & | |||||||||||||||||||||||||||||
2005 | 2006 | 2007 | 2008 | 2009 | After | Total | |||||||||||||||||||||||
Gas OCI | $ | (29,476 | ) | $ | 55,612 | $ | 1,111 | $ | 702 | $ | 343 | $ | 250 | $ | 28,542 | ||||||||||||||
Power OCI | (88,357 | ) | (80,619 | ) | (3,854 | ) | (589 | ) | (343 | ) | (94 | ) | (173,856 | ) | |||||||||||||||
Interest rate OCI | (17,745 | ) | (10,960 | ) | (7,941 | ) | (5,170 | ) | (4,126 | ) | (20,855 | ) | (66,797 | ) | |||||||||||||||
Foreign currency OCI | (2,014 | ) | (2,014 | ) | (1,624 | ) | (28 | ) | — | — | (5,680 | ) | |||||||||||||||||
Total pre-tax OCI | $ | (137,592 | ) | $ | (37,981 | ) | $ | (12,308 | ) | $ | (5,085 | ) | $ | (4,126 | ) | $ | (20,699 | ) | $ | (217,791 | ) | ||||||||
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24. | Earnings per Share |
For the Years Ended December 31, | |||||||||||||||||||||||||||||||||||||
2003 | 2002 | ||||||||||||||||||||||||||||||||||||
2004 | |||||||||||||||||||||||||||||||||||||
Net | Net | ||||||||||||||||||||||||||||||||||||
Net Income | Shares | EPS | Income | Shares | EPS | Income | Shares | EPS | |||||||||||||||||||||||||||||
Basic earnings (loss) per common share: | |||||||||||||||||||||||||||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (440,826 | ) | 430,775 | $ | (1.02 | ) | $ | 86,110 | 390,772 | $ | 0.22 | $ | 26,722 | 354,822 | $ | 0.07 | ||||||||||||||||||||
Discontinued operations, net of tax | 198,365 | — | 0.46 | 14,969 | — | 0.04 | 91,896 | — | 0.26 | ||||||||||||||||||||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | — | — | 180,943 | — | 0.46 | — | — | — | ||||||||||||||||||||||||||||
Net income | $ | (242,461 | ) | 430,775 | $ | (0.56 | ) | $ | 282,022 | 390,772 | $ | 0.72 | $ | 118,618 | 354,822 | $ | 0.33 | ||||||||||||||||||||
Diluted earnings per common share: | |||||||||||||||||||||||||||||||||||||
Common shares issuable upon exercise of stock options using treasury stock method | — | 5,447 | 7,711 | ||||||||||||||||||||||||||||||||||
Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle | $ | (440,826 | ) | 430,775 | $ | (1.02 | ) | $ | 86,110 | 396,219 | $ | 0.22 | $ | 26,722 | 362,533 | $ | 0.07 | ||||||||||||||||||||
Dilutive effect of certain convertible securities | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||
Income before discontinued operations and cumulative effect of a change in accounting principle | (440,826 | ) | 430,775 | (1.02 | ) | 86,110 | 396,219 | 0.22 | 26,722 | 362,533 | 0.07 | ||||||||||||||||||||||||||
Discontinued operations, net of tax | 198,365 | — | 0.46 | 14,969 | — | 0.04 | 91,896 | — | 0.26 | ||||||||||||||||||||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | — | — | 180,943 | — | 0.45 | — | — | — | ||||||||||||||||||||||||||||
Net income | $ | (242,461 | ) | 430,775 | $ | (0.56 | ) | $ | 282,022 | 396,219 | $ | 0.71 | $ | 118,618 | 362,533 | $ | 0.33 | ||||||||||||||||||||
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F-87
Table of Contents
25. | Commitments and Contingencies |
Three Months Ended | ||||||||||||
December 31, 2002 | ||||||||||||
Total | ||||||||||||
Turbine | Turbine | |||||||||||
Turbine CIP | Restructuring | Restructuring | ||||||||||
Description | Write-Off | Accrual | Charge | |||||||||
Turbine write-offs and contract restructuring charges | $ | 182,534 | $ | 24,824 | $ | 207,358 |
As of | As of | |||||||||||||||
December 31, | Adjustments to | December 31, | ||||||||||||||
2002 | Payments | Accrual(1) | 2003 | |||||||||||||
Turbine restructuring accrual | $ | 24,824 | $ | (15,805 | ) | $ | (473 | ) | $ | 8,546 |
(1) | In March 2003, it was determined that the actual invoices for the steam turbine equipment cancellations were less than the amount which had been accrued as of December 31, 2002. |
As of | As of | |||||||||||||||
December 31, | Adjustments to | December 31, | ||||||||||||||
2003 | Payments | Accrual(1) | 2004 | |||||||||||||
Turbine restructuring accrual | $ | 8,546 | $ | (4,498 | ) | $ | — | $ | 4,048 |
Units to be | |||||||||
Year | Total | Delivered | |||||||
(In thousands) | |||||||||
2005 | $ | 27,463 | 1 | ||||||
2006 | 4,862 | — | |||||||
2007 | 977 | — | |||||||
Total | $ | 33,302 | 1 | ||||||
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Table of Contents
As of | Reclass | As of | ||||||||||||||||||||||
December 31, | from | Adjustments | December 31, | |||||||||||||||||||||
2002 | Additions | Long-term | Amortization | to Accrual | 2003 | |||||||||||||||||||
Accrued rent — Short-term | $ | 4,009 | $ | 2,062 | $ | 825 | $ | (3,718 | ) | $ | (166 | ) | $ | 3,012 | ||||||||||
Accrued rent — Long-term | 2,370 | 8,341 | (825 | ) | (162 | ) | 195 | 9,919 | ||||||||||||||||
Total accrued rent liability | $ | 6,379 | $ | 10,403 | $ | — | $ | (3,880 | ) | $ | 29 | $ | 12,931 | |||||||||||
As of | Reclass | As of | ||||||||||||||||||||||||||
December 31, | from | Adjustments | December 31, | |||||||||||||||||||||||||
2003 | Additions | Long-term | Amortization | Accretion | to Accrual | 2004 | ||||||||||||||||||||||
Accrued rent — Short-term | $ | 3,012 | $ | 1,313 | $ | 2,512 | $ | (2,585 | ) | $ | — | $ | 12 | $ | 4,264 | |||||||||||||
Accrued rent — Long-term | 9,919 | 354 | (2,512 | ) | — | 1,325 | 54 | 9,140 | ||||||||||||||||||||
Total accrued rent liability | $ | 12,931 | $ | 1,667 | $ | — | $ | (2,585 | ) | $ | 1,325 | $ | 66 | $ | 13,404 | |||||||||||||
As of | As of | |||||||||||||||||||
December 31, | December 31, | |||||||||||||||||||
2002 | Additions | Payments | Adjustments | 2003 | ||||||||||||||||
Severance liability | $ | 1,556 | $ | 3,914 | $ | (5,191 | ) | $ | 414 | $ | 693 |
As of | As of | |||||||||||||||||||
December 31, | December 31, | |||||||||||||||||||
2003 | Additions | Payments | Adjustments | 2004 | ||||||||||||||||
Severance liability | $ | 693 | $ | 6,154 | $ | (5,292 | ) | $ | (1,555 | ) | $ | — |
F-89
Table of Contents
Initial | |||||||||||||||||||||||||||||||||
Year | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | ||||||||||||||||||||||||||
Watsonville | 1995 | $ | 2,905 | $ | 2,905 | $ | 2,905 | $ | 2,905 | $ | 4,065 | $ | — | $ | 15,685 | ||||||||||||||||||
Greenleaf | 1998 | 8,723 | 8,650 | 8,650 | 7,495 | 8,490 | 29,643 | 71,651 | |||||||||||||||||||||||||
Geysers | 1999 | 55,890 | 47,991 | 47,150 | 42,886 | 34,566 | 106,017 | 334,500 | |||||||||||||||||||||||||
KIAC | 2000 | 24,077 | 23,875 | 23,845 | 24,473 | 24,537 | 240,082 | 360,889 | |||||||||||||||||||||||||
Rumford/ Tiverton | 2000 | 44,942 | 45,000 | 45,000 | 45,000 | 45,000 | 563,292 | 788,234 | |||||||||||||||||||||||||
South Point | 2001 | 9,620 | 9,620 | 9,620 | 9,620 | 9,620 | 307,190 | 355,290 | |||||||||||||||||||||||||
RockGen | 2001 | 27,031 | 26,088 | 27,478 | 28,732 | 29,360 | 169,252 | 307,941 | |||||||||||||||||||||||||
Total | $ | 173,188 | $ | 164,129 | $ | 164,648 | $ | 161,111 | $ | 155,638 | $ | 1,415,476 | $ | 2,234,190 | |||||||||||||||||||
F-90
Table of Contents
2005 | $ | 29,244 | |||
2006 | 24,415 | ||||
2007 | 22,299 | ||||
2008 | 21,291 | ||||
2009 | 21,127 | ||||
Thereafter | 58,172 | ||||
Total | $ | 176,548 | |||
F-91
Table of Contents
Commitments Expiring | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | ||||||||||||||||||||||
Guarantee of subsidiary debt | $ | 18,333 | $ | 16,284 | $ | 18,798 | $ | 1,930,657 | $ | 19,848 | $ | 1,133,896 | $ | 3,137,817 | |||||||||||||||
Standby letters of credit(1)(3) | 579,607 | 3,641 | 2,802 | 400 | — | — | 586,450 | ||||||||||||||||||||||
Surety bonds(2)(3) | — | — | — | — | — | 12,531 | 12,531 | ||||||||||||||||||||||
Guarantee of subsidiary operating lease payments(3) | 83,169 | 81,772 | 82,487 | 115,604 | 113,977 | 1,163,783 | 1,640,792 | ||||||||||||||||||||||
Total | $ | 681,109 | $ | 101,697 | $ | 104,087 | $ | 2,046,661 | $ | 133,825 | $ | 2,310,210 | $ | 5,377,589 | |||||||||||||||
(1) | The standby letters of credit disclosed above include those disclosed in Notes 12, 15 and 16. |
(2) | The surety bonds do not have expiration or cancellation dates. |
(3) | These are off balance sheet obligations. |
Balance at December 31, | ||||||||
2004 | 2003 | |||||||
Guarantee of subsidiary debt | $ | 3,137,817 | $ | 4,102,829 | ||||
Standby letters of credit | 586,450 | 410,803 | ||||||
Surety bonds | 12,531 | 70,480 | ||||||
$ | 3,736,798 | $ | 4,584,112 | |||||
F-92
Table of Contents
F-93
Table of Contents
Litigation |
F-94
Table of Contents
F-95
Table of Contents
F-96
Table of Contents
F-97
Table of Contents
F-98
Table of Contents
F-99
Table of Contents
F-100
Table of Contents
F-101
Table of Contents
26. | Operating Segments |
F-102
Table of Contents
Electric | Oil and Gas | |||||||||||||||
Generation | Production | Corporate | ||||||||||||||
and Marketing | and Marketing | and Other | Total | |||||||||||||
(In thousands) | ||||||||||||||||
2004 | ||||||||||||||||
Revenue from external customers | $ | 9,102,959 | $ | 63,153 | $ | 63,776 | $ | 9,229,888 | ||||||||
Intersegment revenues | — | 208,170 | — | 208,170 | ||||||||||||
Depreciation and amortization | 486,927 | 85,225 | 2,048 | 574,200 | ||||||||||||
Oil and gas impairment | — | 202,120 | — | 202,120 | ||||||||||||
(Income) from unconsolidated investments in power projects and oil and gas properties | 13,525 | — | — | 13,525 | ||||||||||||
Equipment cancellation and impairment costs | 42,374 | — | — | 42,374 | ||||||||||||
Interest expense | 1,055,767 | 41,867 | 43,168 | 1,140,802 | ||||||||||||
Interest (income) | (52,207 | ) | (2,070 | ) | (2,135 | ) | (56,412 | ) | ||||||||
(Income) from repurchase of various issuances of debt | — | — | (246,949 | ) | (246,949 | ) | ||||||||||
Other (income) expense | (222,515 | ) | 5,221 | 68,201 | (149,093 | ) | ||||||||||
Income before taxes | (818,865 | ) | (207,602 | ) | 309,092 | (717,375 | ) | |||||||||
Provision (benefit) for income taxes | (112,150 | ) | (167,654 | ) | 3,255 | (276,549 | ) | |||||||||
Discontinued operations, net of tax | 22,956 | 175,409 | — | 198,365 | ||||||||||||
Total assets | 25,187,414 | 998,810 | 1,029,864 | 27,216,088 | ||||||||||||
Investments in power projects and oil and gas properties | 374,032 | — | — | 374,032 | ||||||||||||
Property additions | 1,465,400 | 60,197 | 23,760 | 1,549,357 | ||||||||||||
2003 | ||||||||||||||||
Revenue from external customers | $ | 8,773,574 | $ | 59,156 | $ | 38,303 | $ | 8,871,033 | ||||||||
Intersegment revenues | — | 284,951 | — | 284,951 | ||||||||||||
Depreciation and amortization | 407,547 | 93,733 | 3,103 | 504,383 | ||||||||||||
Oil and gas impairment | — | 2,931 | — | 2,931 | ||||||||||||
(Income) from unconsolidated investments in power projects and oil and gas properties | (75,804 | ) | — | — | (75,804 | ) | ||||||||||
Equipment cancellation and impairment cost | 64,384 | — | — | 64,384 | ||||||||||||
Interest expense | 621,912 | 47,177 | 37,218 | 706,307 | ||||||||||||
Interest (income) | (34,971 | ) | (2,652 | ) | (2,093 | ) | (39,716 | ) | ||||||||
(Income) from repurchase of various issuances of debt | — | — | (278,612 | ) | (278,612 | ) | ||||||||||
Other (income) expense | (44,961 | ) | (47,941 | ) | 46,776 | (46,126 | ) | |||||||||
Income before taxes | 124,627 | 135,459 | (165,481 | ) | 94,605 | |||||||||||
Provision (benefit) for income taxes | (23,497 | ) | (45,243 | ) | 77,235 | 8,495 | ||||||||||
Discontinued operations, net of tax | 2,694 | 23,546 | (11,271 | ) | 14,969 | |||||||||||
Cumulative effect of a change in accounting principle, net of tax | 183,270 | (1,443 | ) | (884 | ) | 180,943 | ||||||||||
Total assets | 24,041,450 | 1,823,751 | 1,438,731 | 27,303,932 | ||||||||||||
Investments in power plants and oil and gas properties | 444,150 | — | — | 444,150 | ||||||||||||
Property Additions | 1,737,159 | 107,644 | 15,822 | 1,860,625 |
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Electric | Oil and Gas | |||||||||||||||
Generation | Production | Corporate | ||||||||||||||
and Marketing | and Marketing | and Other | Total | |||||||||||||
(In thousands) | ||||||||||||||||
2002 | ||||||||||||||||
Revenue from external customers | $ | 7,103,972 | $ | 243,889 | $ | 1,892 | $ | 7,349,753 | ||||||||
Intersegment revenues | — | 141,263 | — | 141,263 | ||||||||||||
Depreciation and amortization | 298,928 | 91,926 | 8,035 | 398,889 | ||||||||||||
Oil and gas impairment | — | 3,399 | — | 3,399 | ||||||||||||
(Income) from unconsolidated investments in power projects and oil and gas properties | (16,552 | ) | — | — | (16,552 | ) | ||||||||||
Equipment cancellation and impairment costs | 404,737 | — | — | 404,737 | ||||||||||||
Interest expense | 331,066 | 19,501 | 52,110 | 402,677 | ||||||||||||
Interest (income) | (34,500 | ) | (3,182 | ) | (5,404 | ) | (43,086 | ) | ||||||||
(Income) from repurchase of various issuances of debt | — | — | (118,020 | ) | (118,020 | ) | ||||||||||
Other (income) expense | (41,043 | ) | (7,674 | ) | 14,517 | (34,200 | ) | |||||||||
Income before taxes | 175,960 | (6,127 | ) | (132,276 | ) | 37,557 | ||||||||||
Provision (benefit) for income taxes | 95,590 | (107,882 | ) | 23,126 | 10,835 | |||||||||||
Discontinued operations, net of tax | 32,077 | 69,872 | (10,053 | ) | 91,896 |
Geographic Area Information |
United States | Canada | Europe | Total | |||||||||||||
(In thousands) | ||||||||||||||||
2004 | ||||||||||||||||
Total Revenue | $ | 8,704,249 | $ | 93,071 | $ | 432,568 | $ | 9,229,888 | ||||||||
Property, plant and equipment, net | 19,041,875 | 498,136 | 1,096,383 | 20,636,394 | ||||||||||||
2003 | ||||||||||||||||
Total Revenue | $ | 8,436,176 | $ | 121,219 | $ | 313,638 | $ | 8,871,033 | ||||||||
Property, plant and equipment, net | 17,959,466 | 474,280 | 1,044,904 | 19,478,650 | ||||||||||||
2002 | ||||||||||||||||
Total Revenue | $ | 7,073,283 | $ | 70,586 | $ | 205,884 | $ | 7,349,753 |
27. | California Power Market |
F-104
Table of Contents
F-105
Table of Contents
F-106
Table of Contents
28. | Subsequent Events |
F-107
Table of Contents
29. | Quarterly Consolidated Financial Data (unaudited) |
Quarter Ended | |||||||||||||||||
December 31, | September 30, | June 30, | March 31, | ||||||||||||||
(In thousands, except per share amounts) | |||||||||||||||||
2004 Common stock price per share: | |||||||||||||||||
High | $ | 4.08 | $ | 4.46 | $ | 4.98 | $ | 6.42 | |||||||||
Low | 2.24 | 2.87 | 3.04 | 4.35 | |||||||||||||
2004, Restated (for periods through September 30, 2004) | |||||||||||||||||
Total revenue | $ | 2,336,181 | $ | 2,557,200 | $ | 2,304,215 | $ | 2,032,292 | |||||||||
Oil and gas impairment | 201,475 | — | 645 | — | |||||||||||||
(Income) from repurchase of various issuances of debt | (76,401 | ) | (167,154 | ) | (2,559 | ) | (835 | ) | |||||||||
Gross profit (loss) | (68,314 | ) | 254,403 | 56,851 | 112,152 | ||||||||||||
Income (loss) from operations | (189,242 | ) | 162,419 | (12,586 | ) | 45,117 | |||||||||||
Income (loss) before discontinued operations | (290,113 | ) | 14,587 | (58,069 | ) | (107,231 | ) | ||||||||||
Discontinued operations, net of tax | 6,416 | 126,538 | 29,371 | 36,040 | |||||||||||||
Net income (loss) | $ | (283,696 | ) | $ | 141,125 | $ | (28,698 | ) | $ | (71,192 | ) | ||||||
Basic earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations | $ | (0.65 | ) | $ | 0.03 | $ | (0.14 | ) | $ | (0.26 | ) | ||||||
Discontinued operations, net of tax | 0.01 | 0.29 | 0.07 | 0.09 | |||||||||||||
Net income (loss) | (0.64 | ) | 0.32 | (0.07 | ) | (0.17 | ) | ||||||||||
Diluted earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities | $ | (0.65 | ) | $ | 0.03 | $ | (0.14 | ) | $ | (0.26 | ) | ||||||
Dilutive effect of certain trust preferred securities | — | — | — | — | |||||||||||||
Income (loss) before discontinued operations | (0.65 | ) | 0.03 | (0.14 | ) | (0.26 | ) | ||||||||||
Discontinued operations, net of tax | 0.01 | 0.29 | 0.07 | 0.09 | |||||||||||||
Net income (loss) | (0.64 | ) | 0.32 | (0.07 | ) | (0.17 | ) | ||||||||||
2004, As Reported(i) | |||||||||||||||||
Total revenue | $ | 2,336,181 | $ | 2,557,200 | $ | 2,314,634 | $ | 2,042,738 | |||||||||
Oil and gas impairment | 201,475 | — | 645 | — | |||||||||||||
(Income) from repurchase of various issuances of debt | (76,401 | ) | (167,154 | ) | (2,559 | ) | (835 | ) | |||||||||
Gross profit (loss) | (68,314 | ) | 254,403 | 67,690 | 120,544 | ||||||||||||
Income (loss) from operations | (189,242 | ) | 162,418 | (3,167 | ) | 51,911 | |||||||||||
Income (loss) before discontinued operations | (258,807 | ) | (47,532 | ) | (28,896 | ) | (94,049 | ) |
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Table of Contents
Quarter Ended | |||||||||||||||||
December 31, | September 30, | June 30, | March 31, | ||||||||||||||
(In thousands, except per share amounts) | |||||||||||||||||
Discontinued operations, net of tax | 31,507 | 62,551 | 198 | 22,857 | |||||||||||||
Net income (loss) | $ | (227,301 | ) | $ | 15,019 | $ | (28,698 | ) | $ | (71,192 | ) | ||||||
Basic earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations | $ | (0.58 | ) | $ | (0.11 | ) | $ | (0.07 | ) | $ | (0.23 | ) | |||||
Discontinued operations, net of tax | 0.07 | 0.14 | — | 0.06 | |||||||||||||
Net income (loss) | (0.51 | ) | 0.03 | (0.07 | ) | (0.17 | ) | ||||||||||
Diluted earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities | $ | (0.58 | ) | $ | (0.11 | ) | $ | (0.07 | ) | $ | (0.23 | ) | |||||
Dilutive effect of certain trust preferred securities | — | — | — | — | |||||||||||||
Income (loss) before discontinued operations | (0.58 | ) | (0.11 | ) | (0.07 | ) | (0.23 | ) | |||||||||
Discontinued operations, net of tax | 0.07 | 0.14 | — | 0.06 | |||||||||||||
Net income (loss) | (0.51 | ) | 0.03 | (0.07 | ) | (0.17 | ) | ||||||||||
2003 Common stock price per share: | |||||||||||||||||
High | $ | 5.25 | $ | 8.03 | $ | 7.25 | $ | 4.42 | |||||||||
Low | 3.28 | 4.76 | 3.33 | 2.51 | |||||||||||||
2003, Restated | |||||||||||||||||
Total revenue | $ | 1,909,598 | $ | 2,656,588 | $ | 2,152,478 | $ | 2,152,368 | |||||||||
Oil and gas impairment | 2,931 | — | — | — | |||||||||||||
(Income) from repurchase of various issuances of debt | (64,611 | ) | (207,238 | ) | (6,763 | ) | — | ||||||||||
Gross profit | 117,979 | 338,872 | 162,900 | 144,486 | |||||||||||||
Income (loss) from operations | (19,818 | ) | 287,096 | 142,760 | 100,360 | ||||||||||||
Income (loss) before discontinued operations | (21,476 | ) | 176,530 | (14,729 | ) | (54,215 | ) | ||||||||||
Discontinued operations, net of tax | (39,316 | ) | 61,252 | (8,637 | ) | 1,670 | |||||||||||
Cumulative effect of a change in accounting principle | 180,414 | — | — | 529 | |||||||||||||
Net income (loss) | $ | 119,622 | $ | 237,782 | $ | (23,366 | ) | $ | (52,016 | ) | |||||||
Basic earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (0.05 | ) | $ | 0.45 | $ | (0.04 | ) | $ | (0.14 | ) | ||||||
Discontinued operations, net of tax | (0.10 | ) | 0.16 | (0.02 | ) | — | |||||||||||
Cumulative effect of a change in accounting principle | 0.44 | — | — | — | |||||||||||||
Net income (loss) | 0.29 | 0.61 | (0.06 | ) | (0.14 | ) | |||||||||||
Diluted earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities | $ | (0.05 | ) | $ | 0.45 | $ | (0.04 | ) | $ | (0.14 | ) | ||||||
Dilutive effect of certain trust preferred securities | — | (0.09 | ) | — | — | ||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | (0.05 | ) | 0.36 | (0.04 | ) | (0.14 | ) | ||||||||||
Discontinued operations, net of tax | (0.10 | ) | 0.15 | (0.02 | ) | — | |||||||||||
Cumulative effect of a change in accounting principle | 0.44 | — | — | — | |||||||||||||
Net income (loss) | 0.29 | 0.51 | (0.06 | ) | (0.14 | ) | |||||||||||
2003, As Reported(i) | |||||||||||||||||
Total revenue | $ | 1,920,575 | $ | 2,656,588 | $ | 2,165,308 | $ | 2,165,933 | |||||||||
Oil and gas impairment(ii) | 2,931 | — | — | — | |||||||||||||
(Income) from repurchase of various issuances of debt | (64,611 | ) | (207,238 | ) | (6,763 | ) | — |
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Quarter Ended | |||||||||||||||||
December 31, | September 30, | June 30, | March 31, | ||||||||||||||
(In thousands, except per share amounts) | |||||||||||||||||
Gross profit | 126,691 | 338,872 | 175,593 | 165,137 | |||||||||||||
Income (loss) from operations | (20,032 | ) | 287,096 | 153,471 | 119,040 | ||||||||||||
Income (loss) before discontinued operations | (59,827 | ) | 237,701 | (16,375 | ) | (51,538 | ) | ||||||||||
Discontinued operations, net of tax | (967 | ) | 81 | (6,991 | ) | (1,007 | ) | ||||||||||
Cumulative effect of a change in accounting principle | 180,414 | — | — | 529 | |||||||||||||
Net income (loss) | $ | 119,622 | $ | 237,782 | $ | (23,366 | ) | $ | (52,016 | ) | |||||||
Basic earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (0.15 | ) | $ | 0.61 | $ | (0.04 | ) | $ | (0.14 | ) | ||||||
Discontinued operations, net of tax | — | — | (0.02 | ) | — | ||||||||||||
Cumulative effect of a change in accounting principle | 0.44 | — | — | — | |||||||||||||
Net income (loss) | 0.29 | 0.61 | (0.06 | ) | (0.14 | ) | |||||||||||
Diluted earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations and dilutive effect of certain trust preferred securities | $ | (0.15 | ) | $ | 0.60 | $ | (0.04 | ) | $ | (0.14 | ) | ||||||
Dilutive effect of certain trust preferred securities | — | (0.09 | ) | — | — | ||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | (0.15 | ) | 0.51 | (0.04 | ) | (0.14 | ) | ||||||||||
Discontinued operations, net of tax | — | — | (0.02 | ) | — | ||||||||||||
Cumulative effect of a change in accounting principle | 0.44 | — | — | — | |||||||||||||
Net income (loss) | 0.29 | 0.51 | (0.06 | ) | (0.14 | ) |
(i) | As reported in 2004 Form 10-Q filings for quarters ended March 31, 2004, June 30, 2004 and September 30, 2004. The consolidated financial statements for the three and nine months ended September 30, 2004 and as of September 30, 2004 were restated to correct the tax provision. |
(ii) | Oil and gas impairment for quarter ended December 31, 2003, was previously a component of Depreciation Expense. |
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Charged to | |||||||||||||||||||||||||
Accumulated | |||||||||||||||||||||||||
Balance at | Other | ||||||||||||||||||||||||
Beginning | Charged to | Comprehensive | Balance at | ||||||||||||||||||||||
Description | of Year | Expense | Loss | Reductions(1) | Other(2) | End of Year | |||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||
Year ended December 31, 2004 | |||||||||||||||||||||||||
Allowance for doubtful accounts | $ | 7,614 | $ | 8,412 | $ | — | $ | (7,828 | ) | $ | 481 | $ | 8,679 | ||||||||||||
Reserve for notes receivable | 273 | 2,637 | — | — | — | 2,910 | |||||||||||||||||||
Gross reserve for California Refund Liability | 12,905 | — | — | — | — | 12,905 | |||||||||||||||||||
Reserve for impairment of investment in Androscoggin Energy Center | — | $ | 5,000 | — | — | — | $ | 5,000 | |||||||||||||||||
Reserve for derivative assets | 7,454 | 2,825 | 173 | (7,184 | ) | — | 3,268 | ||||||||||||||||||
Repayment reserve for third-party default on emission reduction credits’ settlement | 3,000 | 2,850 | — | (5,850 | ) | — | — | ||||||||||||||||||
Deferred tax asset valuation allowance | 19,335 | 43,487 | — | — | — | 62,822 | |||||||||||||||||||
Year ended December 31, 2003 | |||||||||||||||||||||||||
Allowance for doubtful accounts | $ | 5,955 | $ | 3,278 | $ | — | $ | (2,099 | ) | $ | 480 | $ | 7,614 | ||||||||||||
Reserve for notes receivable | — | 273 | — | — | 273 | ||||||||||||||||||||
Gross reserve for California Refund Liability | 10,700 | 2,205 | — | — | 12,905 | ||||||||||||||||||||
Reserve for derivative assets | 16,452 | 19,459 | 3,640 | (32,097 | ) | 7,454 | |||||||||||||||||||
Gain reserved on certain Enron transactions | 17,862 | — | — | (17,862 | ) | — | |||||||||||||||||||
Repayment reserve for third-party default on emission reduction credits’ settlement | — | 3,000 | — | — | 3,000 | ||||||||||||||||||||
Deferred tax asset valuation allowance | 26,665 | — | — | (7,330 | ) | — | 19,335 | ||||||||||||||||||
Year Ended December 31, 2002 | |||||||||||||||||||||||||
Allowance for doubtful accounts | $ | 15,422 | $ | 1,636 | $ | — | $ | (11,246 | ) | $ | 143 | $ | 5,955 | ||||||||||||
Gross reserve for California Refund Liability | — | 10,700 | — | — | 10,700 | ||||||||||||||||||||
Reserve for derivative assets | 1,583 | 17,253 | 8,444 | (10,828 | ) | 16,452 | |||||||||||||||||||
Gain reserved on certain Enron transactions | 17,862 | — | — | — | 17,862 | ||||||||||||||||||||
Reserve for third-party default on emission reduction credits | 17,677 | — | — | (17,677 | ) | — | |||||||||||||||||||
Deferred tax asset valuation allowance | 26,665 | — | — | — | — | 26,665 |
(1) | Represents write-offs of accounts considered to be uncollectible and recoveries of amounts previously written off or reserved. |
(2) | Primarily relates to foreign currency translation adjustments. |
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• | controls over and processes for the collection and processing of all pertinent operating data and documents needed by our independent reservoir engineers to estimate our proved reserves; | |
• | engagement of well qualified and independent reservoir engineers for review of our operating data and documents and preparation of reserve reports annually in accordance with all SEC reserve estimation guidelines; and | |
• | review by our senior reservoir engineer and his staff of the independent reservoir engineers’ reserves reports for completion and accuracy. |
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Capitalized Costs Relating to Oil and Gas Producing Activities |
Continuing Operations | |||||||||||||||||
2004 | 2003 | 2002 | 2001 | ||||||||||||||
Proved properties | $ | 1,095,022 | $ | 1,084,499 | $ | 909,494 | $ | 853,857 | |||||||||
Unproved properties | 10,538 | 11,283 | 268,983 | 260,454 | |||||||||||||
Total | 1,105,560 | 1,095,782 | 1,178,477 | 1,114,311 | |||||||||||||
Less: Accumulated depreciation, depletion and amortization | (500,722 | ) | (237,374 | ) | (220,376 | ) | (145,467 | ) | |||||||||
Net capitalized costs | $ | 604,838 | $ | 858,408 | $ | 958,101 | $ | 968,844 | |||||||||
Company’s share of equity method investees’ net capitalized costs | $ | 1,160 | $ | 1,255 | $ | — | $ | — | |||||||||
Discontinued Operations | |||||||||||||||||
2004 | 2003 | 2002 | 2001 | ||||||||||||||
Proved properties | $ | — | $ | 995,372 | $ | 759,132 | $ | 1,059,168 | |||||||||
Unproved properties | — | 51,860 | 36,656 | 62,281 | |||||||||||||
Total | — | 1,047,232 | 795,788 | 1,121,449 | |||||||||||||
Less: Accumulated depreciation, depletion and amortization | — | (466,207 | ) | (305,324 | ) | (374,280 | ) | ||||||||||
Net capitalized costs | $ | — | $ | 581,025 | $ | 490,464 | $ | 747,169 | |||||||||
Company’s share of equity method investees’ net capitalized costs | $ | — | $ | 53,228 | $ | — | $ | — | |||||||||
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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities |
United | Continuing | Discontinued | |||||||||||||||||
States | Canada | Operations | Operations | ||||||||||||||||
December 31, 2004: | |||||||||||||||||||
Acquisition costs of properties | |||||||||||||||||||
Proved | $ | 1,425 | $ | — | $ | 1,425 | $ | 3,571 | |||||||||||
Unproved | 3,060 | — | 3,060 | 105 | |||||||||||||||
Subtotal | 4,485 | — | 4,485 | 3,676 | |||||||||||||||
Exploration costs | 22,471 | 50 | 22,521 | 1,313 | |||||||||||||||
Development costs | 42,038 | 5,554 | 47,592 | 37,243 | |||||||||||||||
Total | $ | 68,994 | $ | 5,604 | $ | 74,598 | $ | 42,232 | |||||||||||
Company’s share of equity method investees’ costs of property acquisition, exploration and development | $ | 56 | $ | — | $ | 56 | $ | 2,020 | |||||||||||
December 31, 2003: | |||||||||||||||||||
Acquisition costs of properties | |||||||||||||||||||
Proved | $ | 8,178 | $ | — | $ | 8,178 | $ | 13,087 | |||||||||||
Unproved | 13,597 | — | 13,597 | 3,324 | |||||||||||||||
Subtotal | 21,775 | — | 21,775 | 16,411 | |||||||||||||||
Exploration costs | 33,364 | 603 | 33,967 | 6,235 | |||||||||||||||
Development costs | 41,911 | 13,199 | 55,110 | 55,006 | |||||||||||||||
Total | $ | 97,050 | $ | 13,802 | $ | 110,852 | $ | 77,652 | |||||||||||
Company’s share of equity method investees’ costs of property acquisition, exploration and development | $ | 1,268 | $ | — | $ | 1,268 | $ | 53,039 | |||||||||||
December 31, 2002: | |||||||||||||||||||
Acquisition costs of properties | |||||||||||||||||||
Proved | $ | 3,415 | $ | — | $ | 3,415 | $ | 8,998 | |||||||||||
Unproved | 14,769 | — | 14,769 | (4,615 | ) | ||||||||||||||
Subtotal | 18,184 | — | 18,184 | 4,383 | |||||||||||||||
Exploration costs | 10,958 | 1,818 | 12,776 | 5,741 | |||||||||||||||
Development costs | 44,309 | 11,084 | 55,393 | 60,802 | |||||||||||||||
Total | $ | 73,451 | $ | 12,902 | $ | 86,353 | $ | 70,926 | |||||||||||
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Results of Operations for Oil and Gas Producing Activities |
United States | Canada | Total | |||||||||||||
December 31, 2004: | |||||||||||||||
Oil and gas production revenues | |||||||||||||||
Third-party | $ | 57,644 | $ | 5,461 | $ | 63,105 | |||||||||
Intercompany | 190,143 | 3,458 | 193,601 | ||||||||||||
Total revenues | 247,787 | 8,919 | 256,706 | ||||||||||||
Exploration expenses, including dry hole | 8,175 | — | 8,175 | ||||||||||||
Production costs | 43,016 | 3,521 | 46,537 | ||||||||||||
Depreciation, depletion and amortization | 81,590 | 776 | 82,366 | ||||||||||||
Oil and gas impairment | 202,120 | — | 202,120 | ||||||||||||
Income (loss) before income taxes | (87,114 | ) | 4,622 | (82,492 | ) | ||||||||||
Income tax provision (benefit) | (33,289 | ) | 1,949 | (31,340 | ) | ||||||||||
Results of continuing operations | $ | (53,825 | ) | $ | 2,673 | $ | (51,152 | ) | |||||||
Results of discontinued operations | $ | 7,162 | $ | 14,103 | $ | 21,265 | |||||||||
Company’s share of equity method investees’ results of operations for producing activities | $ | 324 | $ | — | $ | 324 | |||||||||
December 31, 2003: | |||||||||||||||
Oil and gas production revenues | |||||||||||||||
Third-party | $ | 56,162 | $ | 10,030 | $ | 66,192 | |||||||||
Intercompany | 223,532 | 47,379 | 270,911 | ||||||||||||
Total revenues | 279,694 | 57,409 | 337,103 | ||||||||||||
Exploration expenses, including dry hole | 16,753 | 2,443 | 19,196 | ||||||||||||
Production costs | 40,956 | 12,384 | 53,340 | ||||||||||||
Depreciation, depletion and amortization | 72,766 | 16,823 | 89,589 | ||||||||||||
Oil and gas impairment | 2,931 | — | 2,931 | ||||||||||||
Income before income taxes | 146,288 | 25,759 | 172,047 | ||||||||||||
Income tax provision | 55,620 | 16,450 | 72,070 | ||||||||||||
Results of continuing operations | $ | 90,668 | $ | 9,309 | $ | 99,977 | |||||||||
Results of discontinued operations | $ | 6,903 | $ | 21,764 | $ | 28,667 | |||||||||
Company’s share of equity method investees’ results of operations for producing activities | $ | 86 | $ | 101 | $ | 187 | |||||||||
December 31, 2002: | |||||||||||||||
Oil and gas production revenues | |||||||||||||||
Third-party | $ | 37,716 | $ | 35,541 | $ | 73,257 | |||||||||
Intercompany | 126,833 | 5,262 | 132,095 | ||||||||||||
Total revenues | 164,549 | 40,803 | 205,352 | ||||||||||||
Exploration expenses, including dry hole | 10,204 | 2,797 | 13,001 | ||||||||||||
Production costs | 33,249 | 15,214 | 48,463 | ||||||||||||
Depreciation, depletion and amortization | 67,060 | 23,631 | 90,691 | ||||||||||||
Oil and gas impairment | 3,399 | — | 3,399 | ||||||||||||
Income (loss) before income taxes | 50,637 | (839 | ) | 49,798 | |||||||||||
Income tax provision | 19,749 | 5,708 | 25,457 | ||||||||||||
Results of continuing operations | $ | 30,888 | $ | (6,547 | ) | $ | 24,341 | ||||||||
Results of discontinued operations | $ | (330 | ) | $ | 28,281 | $ | 27,951 |
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Net Proved and Proved Developed Reserve Summary |
United | Continuing | Discontinued | ||||||||||||||||
States | Canada | Operations | Operations | |||||||||||||||
Natural gas (Bcf)(1): | ||||||||||||||||||
Net proved reserves at December 31, 2001 | 509 | 72 | 581 | 454 | ||||||||||||||
Revisions of previous estimates | (24 | ) | 20 | (4 | ) | (20 | ) | |||||||||||
Purchases in place | — | — | — | — | ||||||||||||||
Extensions, discoveries and other additions | 41 | 1 | 42 | 44 | ||||||||||||||
Sales in place | — | — | — | (122 | ) | |||||||||||||
Production | (47 | ) | (12 | ) | (59 | ) | (40 | ) | ||||||||||
Net proved reserves at December 31, 2002 | 479 | 81 | 560 | 316 | ||||||||||||||
Revisions of previous estimates | (21 | ) | (1 | ) | (22 | ) | (25 | ) | ||||||||||
Purchases in place | 1 | — | 1 | 9 | ||||||||||||||
Extensions, discoveries and other additions | 51 | — | 51 | 21 | ||||||||||||||
Sales in place | (5 | ) | (60 | ) | (65 | ) | (4 | ) | ||||||||||
Production | (50 | ) | (8 | ) | (58 | ) | (28 | ) | ||||||||||
Net proved reserves at December 31, 2003 | 455 | 12 | 467 | 289 | ||||||||||||||
Revisions of previous estimates | (60 | ) | — | (60 | ) | 17 | ||||||||||||
Purchases in place | 1 | — | 1 | 3 | ||||||||||||||
Extensions, discoveries and other additions | 17 | — | 17 | 5 | ||||||||||||||
Sales in place | (2 | ) | (12 | ) | (14 | ) | (296 | ) | ||||||||||
Production | (37 | ) | — | (37 | ) | (18 | ) | |||||||||||
Net proved reserves at December 31, 2004 | 374 | — | 374 | — | ||||||||||||||
Natural gas liquids and crude oil (MBbl)(2)(3): | ||||||||||||||||||
Net proved reserves at December 31, 2001 | 3,640 | 3,986 | 7,626 | 35,564 | ||||||||||||||
Revisions of previous estimates | 269 | 1,192 | 1,461 | (414 | ) | |||||||||||||
Purchases in place | — | — | — | — | ||||||||||||||
Extensions, discoveries and other additions | 165 | 49 | 214 | 796 | ||||||||||||||
Sales in place | — | — | — | (23,967 | ) | |||||||||||||
Production | (543 | ) | (655 | ) | (1,198 | ) | (3,080 | ) | ||||||||||
Net proved reserves at December 31, 2002 | 3,531 | 4,572 | 8,103 | 8,899 | ||||||||||||||
Revisions of previous estimates | (338 | ) | (254 | ) | (592 | ) | (647 | ) | ||||||||||
Purchases in place | 18 | — | 18 | 12 | ||||||||||||||
Extensions, discoveries and other additions | 133 | — | 133 | 822 | ||||||||||||||
Sales in place | (8 | ) | (3,775 | ) | (3,783 | ) | (118 | ) | ||||||||||
Production | (434 | ) | (542 | ) | (976 | ) | (960 | ) | ||||||||||
Net proved reserves at December 31, 2003 | 2,902 | 1 | 2,903 | 8,008 | ||||||||||||||
Revisions of previous estimates | 260 | — | 260 | (929 | ) | |||||||||||||
Purchases in place | 3 | — | 3 | — | ||||||||||||||
Extensions, discoveries and other additions | 48 | — | 48 | 422 | ||||||||||||||
Sales in place | (2 | ) | (1 | ) | (3 | ) | (6,862 | ) | ||||||||||
Production | (600 | ) | — | (600 | ) | (639 | ) | |||||||||||
Net proved reserves at December 31, 2004 | 2,611 | — | 2,611 | — | ||||||||||||||
(1) | Billion cubic feet or billion cubic feet equivalent, as applicable. |
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United | Continuing | Discontinued | ||||||||||||||||
States | Canada | Operations | Operations | |||||||||||||||
(Bcfe)(1) equivalents(4): | ||||||||||||||||||
Net proved reserves at December 31, 2001 | 530 | 96 | 626 | 668 | ||||||||||||||
Revisions of previous estimates | (23 | ) | 23 | — | (17 | ) | ||||||||||||
Purchases in place | — | — | — | — | ||||||||||||||
Extensions, discoveries and other additions | 42 | 2 | 44 | 48 | ||||||||||||||
Sales in place | — | — | — | (266 | ) | |||||||||||||
Production | (50 | ) | (12 | ) | (62 | ) | (63 | ) | ||||||||||
Net proved reserves at December 31, 2002 | 499 | 109 | 608 | 370 | ||||||||||||||
Revisions of previous estimates | (23 | ) | (1 | ) | (24 | ) | (30 | ) | ||||||||||
Purchases in place | 1 | — | 1 | 9 | ||||||||||||||
Extensions, discoveries and other additions | 52 | — | 52 | 26 | ||||||||||||||
Sales in place | (5 | ) | (83 | ) | (88 | ) | (5 | ) | ||||||||||
Production | (52 | ) | (11 | ) | (63 | ) | (35 | ) | ||||||||||
Net proved reserves at December 31, 2003 | 472 | 14 | 486 | 335 | ||||||||||||||
Revisions of previous estimates | (58 | ) | — | (58 | ) | 12 | ||||||||||||
Purchases in place | 1 | — | 1 | 3 | ||||||||||||||
Extensions, discoveries and other additions | 17 | — | 17 | 7 | ||||||||||||||
Sales in place | (2 | ) | (14 | ) | (16 | ) | (335 | ) | ||||||||||
Production | (41 | ) | — | (41 | ) | (22 | ) | |||||||||||
Net proved reserves at December 31, 2004 | 389 | — | 389 | — | ||||||||||||||
Company’s proportional interest in reserves of investees accounted for by the equity method — December 31, 2004 | 1 | — | 1 | — | ||||||||||||||
Net proved developed reserves: | ||||||||||||||||||
Natural gas (Bcf)(1) | ||||||||||||||||||
December 31, 2002 | 318 | 75 | 393 | 247 | ||||||||||||||
December 31, 2003 | 306 | 12 | 318 | 227 | ||||||||||||||
December 31, 2004 | 256 | — | 256 | — | ||||||||||||||
Natural gas liquids and crude oil (MBbl)(2)(3) | ||||||||||||||||||
December 31, 2002 | 2,030 | 4,271 | 6,301 | 7,831 | ||||||||||||||
December 31, 2003 | 1,508 | 219 | 1,727 | 6,963 | ||||||||||||||
December 31, 2004 | 1,402 | — | 1,402 | — | ||||||||||||||
Bcf(1) equivalents(4) | ||||||||||||||||||
December 31, 2002 | 330 | 100 | 430 | 295 | ||||||||||||||
December 31, 2003 | 315 | 13 | 328 | 268 | ||||||||||||||
December 31, 2004 | 264 | — | 264 | — |
(1) | Billion cubic feet or billion cubic feet equivalent, as applicable. |
(2) | Thousand barrels. |
(3) | Includes crude oil, condensate and natural gas liquids. |
(4) | Natural gas liquids and crude oil volumes have been converted to equivalent gas volumes using a conversion factor of six cubic feet of gas to one barrel of natural gas liquids and crude oil. |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves |
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United | Continuing | Discontinued | |||||||||||||||
States | Canada | Operations | Operations | ||||||||||||||
December 31, 2004: | |||||||||||||||||
Future cash inflows | $ | 2,427 | $ | — | $ | 2,427 | $ | — | |||||||||
Future production costs | (568 | ) | — | (568 | ) | — | |||||||||||
Future development costs | (190 | ) | — | (190 | ) | — | |||||||||||
Future net cash flows before income taxes | 1,669 | — | 1,669 | — | |||||||||||||
Future income taxes | (474 | ) | — | (474 | ) | — | |||||||||||
Future net cash flows | 1,195 | — | 1,195 | — | |||||||||||||
Discount to present value at 10% annual rate | (542 | ) | — | (542 | ) | — | |||||||||||
Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves | $ | 653 | $ | — | $ | 653 | $ | — | |||||||||
Company’s share of equity method investees’ standardized measure of discounted future net cash flows | $ | 2 | $ | — | $ | 2 | $ | — | |||||||||
United | Continuing | Discontinued | |||||||||||||||
States | Canada | Operations | Operations | ||||||||||||||
December 31, 2003: | |||||||||||||||||
Future cash inflows | $ | 2,752 | $ | 62 | $ | 2,814 | $ | 1,784 | |||||||||
Future production costs | (563 | ) | (14 | ) | (577 | ) | (573 | ) | |||||||||
Future development costs | (200 | ) | (10 | ) | (210 | ) | (118 | ) | |||||||||
Future net cash flows before income taxes | 1,989 | 38 | 2,027 | 1,093 | |||||||||||||
Future income taxes | (553 | ) | (8 | ) | (561 | ) | (240 | ) | |||||||||
Future net cash flows | 1,436 | 30 | 1,466 | 853 | |||||||||||||
Discount to present value at 10% annual rate | (661 | ) | (7 | ) | (668 | ) | (310 | ) | |||||||||
Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves | $ | 775 | $ | 23 | $ | 798 | $ | 543 | |||||||||
Company’s share of equity method investees’ standardized measure of discounted future net cash flows | $ | 2 | $ | — | $ | 2 | $ | 18 | |||||||||
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December 31, 2002: | |||||||||||||||||
Future cash inflows | $ | 2,391 | $ | 439 | $ | 2,830 | $ | 1,537 | |||||||||
Future production costs | (538 | ) | (95 | ) | (633 | ) | (434 | ) | |||||||||
Future development costs | (156 | ) | (11 | ) | (167 | ) | (53 | ) | |||||||||
Future net cash flows before income taxes | 1,697 | 333 | 2,030 | 1,050 | |||||||||||||
Future income taxes | (480 | ) | (110 | ) | (590 | ) | (337 | ) | |||||||||
Future net cash flows | 1,217 | 223 | 1,440 | 713 | |||||||||||||
Discount to present value at 10% annual rate | (537 | ) | (77 | ) | (614 | ) | (280 | ) | |||||||||
Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves | $ | 680 | $ | 146 | $ | 826 | $ | 433 | |||||||||
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Changes in Standardized Measure of Discounted Future Net Cash Flows |
United | Continuing | Discontinued | |||||||||||||||
States | Canada | Operations | Operations | ||||||||||||||
Balance, December 31, 2001 | $ | 402 | $ | 63 | $ | 465 | $ | 514 | |||||||||
Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs | (131 | ) | (26 | ) | (157 | ) | (126 | ) | |||||||||
Net changes in prices and production costs | 491 | 63 | 554 | 615 | |||||||||||||
Extensions, discoveries, additions and improved recovery, net of related costs | 96 | — | 96 | 68 | |||||||||||||
Development costs incurred | 36 | — | 36 | (11 | ) | ||||||||||||
Revisions of previous quantity estimates and development costs | (81 | ) | 15 | (66 | ) | (10 | ) | ||||||||||
Accretion of discount | 40 | 3 | 43 | 7 | |||||||||||||
Net change in income taxes | (173 | ) | (23 | ) | (196 | ) | (50 | ) | |||||||||
Purchases of reserves in place | — | — | — | 2 | |||||||||||||
Sales of reserves in place | — | — | — | (521 | ) | ||||||||||||
Changes in timing and other | — | 51 | 51 | (55 | ) | ||||||||||||
Balance, December 31, 2002 | $ | 680 | $ | 146 | $ | 826 | $ | 433 | |||||||||
Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs | (239 | ) | (45 | ) | (284 | ) | (119 | ) | |||||||||
Net changes in prices and production costs | 248 | (27 | ) | 221 | 17 | ||||||||||||
Extensions, discoveries, additions and improved recovery, net of related costs | 117 | — | 117 | 60 | |||||||||||||
Development costs incurred | 48 | — | 48 | 41 | |||||||||||||
Revisions of previous quantity estimates and development costs | (80 | ) | (11 | ) | (91 | ) | (69 | ) | |||||||||
Accretion of discount | 68 | 2 | 70 | 44 | |||||||||||||
Net change in income taxes | (28 | ) | 74 | 46 | 95 | ||||||||||||
Purchases of reserves in place | 2 | — | 2 | 19 | |||||||||||||
Sales of reserves in place | (6 | ) | (124 | ) | (130 | ) | (42 | ) | |||||||||
Changes in timing and other | (35 | ) | 8 | (27 | ) | 64 | |||||||||||
Balance, December 31, 2003 | $ | 775 | $ | 23 | $ | 798 | $ | 543 | |||||||||
Sales and transfers of gas, natural gas liquids and crude oil produced, net of production costs | (205 | ) | (5 | ) | (210 | ) | (81 | ) | |||||||||
Net changes in prices and production costs | 39 | 7 | 46 | 128 | |||||||||||||
Extensions, discoveries, additions and improved recovery, net of related costs | 60 | — | 60 | 15 | |||||||||||||
Development costs incurred | 25 | — | 25 | 29 | |||||||||||||
Revisions of previous quantity estimates and development costs | (193 | ) | — | (193 | ) | 6 | |||||||||||
Accretion of discount | 78 | 2 | 80 | 71 | |||||||||||||
Net change in income taxes | 39 | — | 39 | 60 | |||||||||||||
Purchases of reserves in place | 2 | — | 2 | 3 | |||||||||||||
Sales of reserves in place | (5 | ) | (23 | ) | (28 | ) | (733 | ) | |||||||||
Changes in timing and other | 38 | (4 | ) | 34 | (41 | ) | |||||||||||
Balance, December 31, 2004 | $ | 653 | $ | — | $ | 653 | $ | — | |||||||||
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Exhibit | ||||
Number | Description | |||
2 | .1 | Purchase and Sale Agreement, dated July 1, 2004, among Calpine Corporation (the “Company”), Calpine Natural Gas L.P. and Pogo Producing Company.(a) | ||
2 | .2 | Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Natural Gas L.P. and Bill Barrett Corporation.(a) | ||
2 | .3 | Asset and Trust Unit Purchase and Sale Agreement, dated July 1, 2004, among the Company, Calpine Canada Natural Gas Partnership, Calpine Energy Holdings Limited, PrimeWest Gas Corp. and PrimeWest Energy Trust.(a) | ||
3 | .1 | Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004.(b) | ||
3 | .2 | Amended and Restated By-laws of the Company.(c) | ||
4 | .1.1 | Indenture dated as of May 16, 1996, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(d) | ||
4 | .1.2 | First Supplemental Indenture dated as of August 1, 2000, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(e) | ||
4 | .1.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and U.S. Bank (as successor trustee to Fleet National Bank), as Trustee.(f) | ||
4 | .2.1 | Indenture dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(g) | ||
4 | .2.2 | Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(h) | ||
4 | .2.3 | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e) | ||
4 | .2.4 | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f) | ||
4 | .3.1 | Indenture dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(i) | ||
4 | .3.2 | Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(i) | ||
4 | .3.3 | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e) | ||
4 | .3.4 | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f) | ||
4 | .4.1 | Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(j) | ||
4 | .4.2 | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e) | ||
4 | .4.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f) | ||
4 | .5.1 | Indenture dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(j) | ||
4 | .5.2 | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(e) | ||
4 | .5.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(f) | ||
4 | .6.1 | Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(k) | ||
4 | .6.2 | First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(e) |
Table of Contents
Exhibit | ||||
Number | Description | |||
4 | .6.3 | Second Supplemental Indenture dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee.(l) | ||
4 | .7.1 | Amended and Restated Indenture dated as of October 16, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee.(m) | ||
4 | .7.2 | Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(n) | ||
4 | .7.3 | First Amendment, dated as of October 16, 2001, to Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(m) | ||
4 | .8.1 | Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(m) | ||
4 | .8.2 | First Supplemental Indenture, dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(m) | ||
4 | .8.3 | Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(m) | ||
4 | .8.4 | First Amendment, dated as of October 18, 2001, to Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(m) | ||
4 | .9 | Indenture, dated as of June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(o) | ||
4 | .10 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o) | ||
4 | .11 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o) | ||
4 | .12 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(o) | ||
4 | .13.1 | Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee, including form of Notes.(p) | ||
4 | .13.2 | Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(p) | ||
4 | .13.3 | Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q) | ||
4 | .13.4 | Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(q) | ||
4 | .14 | Indenture, dated as of September 30, 2003, among Gilroy Energy Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy Center, as Guarantors, and Wilmington Trust Company, as Trustee and Collateral Agent, including form of Notes.(p) | ||
4 | .15 | Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(q) | ||
4 | .16.1 | Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(q) | ||
4 | .16.2 | Registration Rights Agreement, dated as of November 14, 2003, between the Company and Deutsche Bank Securities, Inc., as Representative of the Initial Purchasers.(q) | ||
4 | .17.1 | First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q) | ||
4 | .17.2 | Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q) |
Table of Contents
Exhibit | ||||
Number | Description | |||
4 | .17.3 | Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(q) | ||
4 | .18 | Indenture, dated as of June 2, 2004, between Power Contract Financing III, LLC and Wilmington Trust Company, as Trustee, Accounts Agent, Paying Agent and Registrar, including form of Notes.(b) | ||
4 | .19 | Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r) | ||
4 | .20.1 | Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(s) | ||
4 | .20.2 | Amendment No. 1 to Rights Agreement, dated as of September 28, 2004, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(l) | ||
4 | .20.3 | Amendment No. 2 to Rights Agreement, dated as of March 18, 2005, between Calpine Corporation and Equiserve Trust Company, N.A., as Rights Agent.(bb) | ||
4 | .21 | Memorandum and Articles of Association of Calpine (Jersey) Limited.(t) | ||
4 | .22 | Memorandum and Articles of Association of Calpine European Funding (Jersey) Limited.(t) | ||
4 | .23 | High Tides III | ||
4 | .23.1 | Amended and Restated Certificate of Trust of Calpine Capital Trust III, a Delaware statutory trust, filed July 19, 2000.(u) | ||
4 | .23.2 | Declaration of Trust of Calpine Capital Trust III dated June 28, 2000, among the Company, as Depositor and Debenture Issuer, The Bank of New York (Delaware), as Delaware Trustee, The Bank of New York, as Property Trustee and the Administrative Trustees named therein.(u) | ||
4 | .23.3 | Amendment No. 1 to the Declaration of Trust of Calpine Capital Trust III dated July 19, 2000, among the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein.(u) | ||
4 | .23.4 | Indenture dated as of August 9, 2000, between the Company and Wilmington Trust Company, as Trustee.(u) | ||
4 | .23.5 | Remarketing Agreement dated as of August 9, 2000, among the Company, Calpine Capital Trust III, Wilmington Trust Company, as Tender Agent, and Credit Suisse First Boston Corporation, as Remarketing Agent.(u) | ||
4 | .23.6 | Registration Rights Agreement dated as August 9, 2000, between the Company, Calpine Capital Trust III, Credit Suisse First Boston Corporation, ING Barings LLC and CIBC World Markets Corp.(u) | ||
4 | .23.7 | Amended and Restated Declaration of Trust of Calpine Capital Trust III dated as of August 9, 2000, the Company, as Depositor and Debenture Issuer, Wilmington Trust Company, as Delaware Trustee, Wilmington Trust Company, as Property Trustee, and the Administrative Trustees named therein, including the form of Preferred Security and form of Common Security.(u) | ||
4 | .23.8 | Preferred Securities Guarantee Agreement dated as of August 9, 2000, between the Company, as Guarantor, and Wilmington Trust Company, as Guarantee Trustee.(u) | ||
4 | .24 | Pass Through Certificates (Tiverton and Rumford) | ||
4 | .24.1 | Pass Through Trust Agreement dated as of December 19, 2000, among Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of Certificate.(e) | ||
4 | .24.2 | Participation Agreement dated as of December 19, 2000, among the Company, Tiverton Power Associates Limited Partnership, Rumford Power Associates Limited Partnership, PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee.(e) | ||
4 | .24.3 | Appendix A — Definitions and Rules of Interpretation.(e) |
Table of Contents
Exhibit | ||||
Number | Description | |||
4 | .24.4 | Indenture of Trust, Mortgage and Security Agreement, dated as of December 19, 2000, between PMCC Calpine New England Investment LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, including the forms of Lessor Notes.(e) | ||
4 | .24.5 | Calpine Guaranty and Payment Agreement (Tiverton) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(e) | ||
4 | .24.6 | Calpine Guaranty and Payment Agreement (Rumford) dated as of December 19, 2000, by the Company, as Guarantor, to PMCC Calpine New England Investment LLC, PMCC Calpine NEIM LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(e) | ||
4 | .25 | Pass Through Certificates (South Point, Broad River and RockGen) | ||
4 | .25.1 | Pass Through Trust Agreement A dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 8.400% Pass Through Certificate, Series A.(c) | ||
4 | .25.2 | Pass Through Trust Agreement B dated as of October 18, 2001, among South Point Energy Center, LLC, Broad River Energy LLC, RockGen Energy LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including the form of 9.825% Pass Through Certificate, Series B.(c) | ||
4 | .25.3 | Participation Agreement (SP-1) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.4 | Participation Agreement (SP-2) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.5 | Participation Agreement (SP-3) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.6 | Participation Agreement (SP-4) dated as of October 18, 2001, among the Company, South Point Energy Center, LLC, South Point OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.7 | Participation Agreement (BR-1) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) |
Table of Contents
Exhibit | ||||
Number | Description | |||
4 | .25.8 | Participation Agreement (BR-2) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.9 | Participation Agreement (BR-3) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.10 | Participation Agreement (BR-4) dated as of October 18, 2001, among the Company, Broad River Energy LLC, Broad River OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.11 | Participation Agreement (RG-1) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-1, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.12 | Participation Agreement (RG-2) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-2, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.13 | Participation Agreement (RG-3) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-3, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.14 | Participation Agreement (RG-4) dated as of October 18, 2001, among the Company, RockGen Energy LLC, RockGen OL-4, LLC, Wells Fargo Bank Northwest, National Association, as Lessor Manager, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, including Appendix A — Definitions and Rules of Interpretation.(c) | ||
4 | .25.15 | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c) | ||
4 | .25.16 | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c) | ||
4 | .25.17 | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c) |
Table of Contents
Exhibit | ||||
Number | Description | |||
4 | .25.18 | Indenture of Trust, Deed of Trust, Assignment of Rents and Leases, Security Agreement and Financing Statement, dated as of October 18, 2001, between South Point OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of South Point Lessor Notes.(c) | ||
4 | .25.19 | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c) | ||
4 | .25.20 | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c) | ||
4 | .25.21 | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c) | ||
4 | .25.22 | Indenture of Trust, Mortgage, Security Agreement and Fixture Filing, dated as of October 18, 2001, between Broad River OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee, Mortgagee and Account Bank, including the form of Broad River Lessor Notes.(c) | ||
4 | .25.23 | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-1, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c) | ||
4 | .25.24 | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-2, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c) | ||
4 | .25.25 | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-3, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c) | ||
4 | .25.26 | Indenture of Trust, Mortgage and Security Agreement, dated as of October 18, 2001, between RockGen OL-4, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Indenture Trustee and Account Bank, including the form of RockGen Lessor Notes.(c) | ||
4 | .25.27 | Calpine Guaranty and Payment Agreement (South Point SP-1) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.28 | Calpine Guaranty and Payment Agreement (South Point SP-2) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.29 | Calpine Guaranty and Payment Agreement (South Point SP-3) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.30 | Calpine Guaranty and Payment Agreement (South Point SP-4) dated as of October 18, 2001, by Calpine, as Guarantor, to South Point OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) |
Table of Contents
Exhibit | ||||
Number | Description | |||
4 | .25.31 | Calpine Guaranty and Payment Agreement (Broad River BR-1) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.32 | Calpine Guaranty and Payment Agreement (Broad River BR-2) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.33 | Calpine Guaranty and Payment Agreement (Broad River BR-3) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.34 | Calpine Guaranty and Payment Agreement (Broad River BR-4) dated as of October 18, 2001, by Calpine, as Guarantor, to Broad River OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.35 | Calpine Guaranty and Payment Agreement (RockGen RG-1) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-1, LLC, SBR OP-1, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.36 | Calpine Guaranty and Payment Agreement (RockGen RG-2) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-2, LLC, SBR OP-2, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.37 | Calpine Guaranty and Payment Agreement (RockGen RG-3) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-3, LLC, SBR OP-3, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
4 | .25.38 | Calpine Guaranty and Payment Agreement (RockGen RG-4) dated as of October 18, 2001, by Calpine, as Guarantor, to RockGen OL-4, LLC, SBR OP-4, LLC, State Street Bank and Trust Company of Connecticut, as Indenture Trustee, and State Street Bank and Trust Company of Connecticut, as Pass Through Trustee.(c) | ||
10 | .1 | Financing and Term Loan Agreements | ||
10 | .1.1 | Share Lending Agreement, dated as of September 28, 2004, among the Company, as Lender, Deutsche Bank AG London, as Borrower, through Deutsche Bank Securities Inc., as agent for the Borrower, and Deutsche Bank Securities Inc., in its capacity as Collateral Agent and Securities Intermediary.(l) | ||
10 | .1.2 | Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(q) | ||
10 | .1.3.1 | Letter of Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent.(o) | ||
10 | .1.3.2 | Amendment to Letter of Credit Agreement, dated as of September 30, 2004, between the Company and The Bank of Nova Scotia, as Administrative Agent.(v) | ||
10 | .1.4 | Letter of Credit Agreement, dated as of September 30, 2004, between the Company and Bayerische Landesbank, acting through its Cayman Islands Branch, as the Issuer.(v) |
Table of Contents
Exhibit | ||||
Number | Description | |||
10 | .1.5 | Credit Agreement, dated as of July 16, 2003, among the Company, the Lenders named therein, Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner and Administrative Agent, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-Thuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agents.(o) | ||
10 | .1.6.1 | Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(p) | ||
10 | .1.6.2 | Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(p) | ||
10 | .1.6.3 | Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q) | ||
10 | .1.6.4 | Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(q) | ||
10 | .1.7 | Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(q) | ||
10 | .1.8 | Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(q) | ||
10 | .1.9 | Credit Agreement, dated as of June 24, 2004, among Riverside Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(*) | ||
10 | .1.10 | Credit Agreement, dated as of June 24, 2004, among Rocky Mountain Energy Center, LLC, the Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent.(*) | ||
10 | .1.11 | Credit Agreement, dated as of February 25, 2005, among Calpine Steamboat Holdings, LLC, the Lenders named therein, Calyon New York Branch, as a Lead Arranger, Underwriter, Co-Book Runner, Administrative Agent, Collateral Agent and LC Issuer, CoBank, ACB, as a Lead Arranger, Underwriter, Co-Syndication Agent and Co-Book Runner, HSH Nordbank AG, as a Lead Arranger, Underwriter and Co-documentation Agent, UFJ Bank Limited, as a Lead Arranger, Underwriter and Co-Documentation Agent, and Bayerische Hypo-Und Vereinsbank AG, New York Branch, as a Lead Arranger, Underwriter and Co-Syndication Agent.(*) | ||
10 | .2 | Security Agreements | ||
10 | .2.1 | Guarantee and Collateral Agreement, dated as of July 16, 2003, made by the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.2 | First Amendment Pledge Agreement, dated as of July 16, 2003, made by JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada Holdings LLC in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.3 | First Amendment Assignment and Security Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o) |
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Exhibit | ||||
Number | Description | |||
10 | .2.4.1 | Second Amendment Pledge Agreement (Stock Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.4.2 | Amendment No. 1 to the Second Amendment Pledge Agreement (Stock Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(q) | ||
10 | .2.5.1 | Second Amendment Pledge Agreement (Membership Interests), dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.5.2 | Amendment No. 1 to the Second Amendment Pledge Agreement (Membership Interests), dated as of November 18, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(q) | ||
10 | .2.6 | First Amendment Note Pledge Agreement, dated as of July 16, 2003, made by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.7.1 | Collateral Trust Agreement, dated as of July 16, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.7.2 | First Amendment to the Collateral Trust Agreement, dated as of November 18, 2003, among the Company, JOQ Canada, Inc., Quintana Minerals (USA) Inc., Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee, The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and The Bank of New York, as Collateral Trustee.(q) | ||
10 | .2.8 | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Denis O’Meara and James Trimble, as Trustees, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.9 | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.10 | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.11 | Form of Amended and Restated Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of July 16, 2003, from the Company to Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.12 | Form of Amended and Restated Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.13 | Form of Amended and Restated Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filings (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, as Trustee, and The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.14 | Form of Deed to Secure Debt, Assignment of Rents and Security Agreement (Georgia), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.15 | Form of Mortgage, Assignment of Rents and Security Agreement (Florida), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.16 | Form of Deed of Trust, Assignment of Rents and Security Agreement and Fixture Filing (Texas), dated as of July 16, 2003, from the Company to Malcolm S. Morris, as Trustee, in favor of The Bank of New York, as Collateral Trustee.(o) |
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Exhibit | ||||
Number | Description | |||
10 | .2.17 | Form of Deed of Trust, Assignment of Rents and Security Agreement (Washington), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.18 | Form of Deed of Trust, Assignment of Rents, and Security Agreement (California), dated as of July 16, 2003, from the Company to Chicago Title Insurance Company, in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.19 | Form of Mortgage, Collateral Assignment of Leases and Rents, Security Agreement and Financing Statement (Louisiana), dated as of July 16, 2003, from the Company to The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.20 | Amended and Restated Hazardous Materials Undertaking and Indemnity (Multistate), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.21 | Amended and Restated Hazardous Materials Undertaking and Indemnity (California), dated as of July 16, 2003, by the Company in favor of The Bank of New York, as Collateral Trustee.(o) | ||
10 | .2.22 | Designated Asset Sale Proceeds Account Control Agreement, dated as of July 16, 2003, among the Company, Union Bank of California, N.A., and The Bank of New York, as Collateral Agent.(q) | ||
10 | .3 | Management Contracts or Compensatory Plans or Arrangements. | ||
10 | .3.1.1 | Employment Agreement, dated as of January 1, 2005, between the Company and Mr. Peter Cartwright.(w)(x) | ||
10 | .3.1.2 | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Peter Cartwright.(y)(x) | ||
10 | .3.2 | Employment Agreement, dated as of January 1, 2000, between the Company and Ms. Ann B. Curtis.(c)(x) | ||
10 | .3.3 | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Ron A. Walter.(c)(x) | ||
10 | .3.4 | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Robert D. Kelly.(c)(x) | ||
10 | .3.5 | Employment Agreement, dated as of January 1, 2000, between the Company and Mr. Thomas R. Mason.(c)(x) | ||
10 | .3.6.1 | Consulting Contract, dated as of January 1, 2005, between the Company and Mr. George J. Stathakis.(*)(x) | ||
10 | .3.6.2 | Consulting Contract, dated as of January 1, 2004, between the Company and Mr. George J. Stathakis.(q)(x) | ||
10 | .3.7 | Form of Indemnification Agreement for directors and officers.(z)(x) | ||
10 | .3.8 | Form of Indemnification Agreement for directors and officers.(c)(x) | ||
10 | .3.9 | Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(q)(x) | ||
10 | .3.10 | Base Salary, Bonus, Stock Option Grant and Restricted Stock Summary Sheet.(w)(x) | ||
10 | .3.11 | Form of Stock Option Agreement.(w)(x) | ||
10 | .3.12 | Form of Restricted Stock Agreement.(w)(x) | ||
10 | .3.13 | Calpine Corporation 2003 Management Incentive Plan.(*)(x) | ||
10 | .3.14 | 2000 Employee Stock Purchase Plan.(aa)(x) | ||
12 | .1 | Statement on Computation of Ratio of Earnings to Fixed Charges.(*) | ||
21 | .1 | Subsidiaries of the Company.(*) | ||
23 | .1 | Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm.(*) | ||
23 | .2 | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.(*) | ||
23 | .3 | Consent of Netherland, Sewell & Associates, Inc., independent engineer.(*) | ||
23 | .4 | Consent of Gilbert Laustsen Jung Associates Ltd., independent engineer.(*) | ||
24 | .1 | Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this report).(*) |
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Exhibit | ||||
Number | Description | |||
31 | .1 | Certification of the Chairman, President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*) | ||
31 | .2 | Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*) | ||
32 | .1 | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*) | ||
99 | .1 | Acadia Power Partners, LLC and Subsidiary, Consolidated Financial Statements, December 31, 2003, 2002 and 2001.(*) | ||
99 | .2 | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.(*) |
(*) | Filed herewith. | |
(a) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K/ A filed with the SEC on September 14, 2004. | |
(b) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004. | |
(c) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2001, filed with the SEC on March 29, 2002. | |
(d) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-06259) filed with the SEC on June 19, 1996. | |
(e) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001. | |
(f) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2004, filed with the SEC on May 10, 2004. | |
(g) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997. | |
(h) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-41261) filed with the SEC on November 28, 1997. | |
(i) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration Statement No. 333-61047) filed with the SEC on August 10, 1998. | |
(j) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration Statement No. 333-72583) filed with the SEC on March 8, 1999. | |
(k) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880) filed with the SEC on January 17, 2002. | |
(l) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 30, 2004. | |
(m) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated October 16, 2001, filed with the SEC on November 13, 2001. | |
(n) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-57338) filed with the SEC on April 19, 2001. | |
(o) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003. | |
(p) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003. | |
(q) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on March 25, 2004. | |
(r) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on October 6, 2004. | |
(s) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form 8-A/ A (Registration No. 001-12079) filed with the SEC on September 28, 2001. |
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(t) | This document has been omitted in reliance on Item 601(b)(4)(iii) of Regulation S-K. Calpine Corporation agrees to furnish a copy of such document to the SEC upon request. | |
(u) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration Statement No. 333-47068) filed with the SEC on September 29, 2000. | |
(v) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2004, filed with the SEC on November 9, 2004. | |
(w) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 17, 2005. | |
(x) | Management contract or compensatory plan or arrangement. | |
(y) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999, filed with the SEC on February 29, 2000. | |
(z) | Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-1/ A (Registration Statement No. 333-07497) filed with the SEC on August 22, 1996. | |
(aa) | Incorporated by reference to Calpine Corporation’s Definitive Proxy Statement on Schedule 14A dated April 13, 2000, filed with the SEC on April 13, 2000. | |
(bb) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 23, 2005. |