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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, 2005 | ||
or | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to |
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Abbreviation | Definition | |
2004 Form 10-K | Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 31, 2005, as modified by its Current Report on Form 8-K dated December 31, 2004, filed with the SEC on October 17, 2005, to reflect the effect of certain discontinued operations | |
2006 Convertible Notes | 4% Convertible Senior Notes Due 2006 | |
2014 Convertible Notes | Contingent Convertible Notes Due 2014 | |
2015 Convertible Notes | 73/4% Contingent Convertible Notes Due 2015 | |
2023 Convertible Notes | 43/4% Contingent Convertible Senior Notes Due 2023 | |
Acadia PP | Acadia Power Partners, LLC | |
AELLC | Androscoggin Energy LLC | |
AICPA | American Institute of Certified Public Accountants | |
AMS | Aquila Merchant Services, Inc. | |
AOCI | Accumulated Other Comprehensive Income | |
APB | Accounting Principles Board | |
Aries | MEP Pleasant Hill, LLC | |
ARO | Asset Retirement Obligation | |
Auburndale PP | Auburndale Power Partners, L.P. | |
Bankruptcy Code | United States Bankruptcy Code | |
Bankruptcy Courts | The U.S. Bankruptcy Court and the Canadian Court | |
BBPTS | Babcock Borsig Power Turbine Services | |
Bcfe | Billion cubic feet equivalent | |
Bear Stearns | Bear Stearns Companies, Inc. | |
BPA | Bonneville Power Administration | |
Btu(s) | British thermal unit(s) | |
CAISO | California Independent System Operator | |
CalBear | CalBear Energy, LP | |
CalGen | Calpine Generating Company, LLC, formerly Calpine Construction Finance Company II LLC | |
Calpine Capital Trusts | Trust I, Trust II and Trust III | |
Calpine Cogen | Calpine Cogeneration Corporation, formerly Cogen America | |
Calpine Debtor(s) | The U.S. Debtors and the Canadian Debtors | |
Calpine Jersey I | Calpine (Jersey) Limited | |
Calpine Jersey II | Calpine European Funding (Jersey) Limited | |
CalPX | California Power Exchange | |
CalPX Price | CalPX zonal day-ahead clearing price | |
Canadian Court | The Court of Queen’s Bench of Alberta, Judicial District of Calgary | |
Canadian Debtor(s) | The subsidiaries and affiliates of Calpine Corporation that have been granted creditor protection under the CCAA in the Canadian Court |
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Abbreviation | Definition | |
Cash Collateral Order | Second Amended Final Order of the U.S. Bankruptcy Court Authorizing Use of Cash Collateral and Granting Adequate Protection, dated February 24, 2006 | |
CCAA | Companies’ Creditors Arrangement Act (Canada) | |
CCFC | Calpine Construction Finance Company, L.P | |
CCFCP | CCFC Preferred Holdings, LLC | |
CCRC | Calpine Canada Resources Company, formerly Calpine Canada Resources Ltd. | |
CDWR | California Department of Water Resources | |
CEC | California Energy Commission | |
CEM | Calpine Energy Management, L.P. | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act, as amended, also called “Superfund” | |
CES | Calpine Energy Services, L.P. | |
CESCP | Calpine Energy Services Canada Partnership | |
CFE | Comision Federal de Electricidad (Mexico) | |
Chapter 11 | Chapter 11 of the Bankruptcy Code | |
Chubu | Chubu Electric Power Company, Inc. | |
CIP | Construction in Progress | |
Clean Air Act | Federal Clean Air Act of 1970 | |
Cleco | Cleco Corp. | |
CMSC | Calpine Merchant Services Company, Inc. | |
CNEM | Calpine Northbrook Energy Marketing, LLC | |
CNGLP | Calpine Natural Gas L.P. | |
CNGT | Calpine Natural Gas Trust | |
Cogen America | Cogeneration Corporation of America, now called Calpine Cogeneration Corporation | |
CPIF | Calpine Power Income Fund | |
CPLP | Calpine Power, L.P. | |
CPSI | Calpine Power Services, Inc. | |
CPUC | California Public Utilities Commission | |
Creed | Creed Energy Center, LLC | |
CTA | Cumulative Translation Adjustment | |
DB London | Deutsche Bank AG London | |
Deer Park | Deer Park Energy Center Limited Partnership | |
DIG | Derivatives Implementation Group | |
DIP | Debtor-in-possession |
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Abbreviation | Definition | |
DIP Facility | The Revolving Credit, Term Loan and Guarantee Agreement, dated as of December 22, 2005, as amended on January 26, 2006, and as amended and restated by that certain Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2005, among Calpine Corporation, as borrower, the Guarantors party thereto, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as joint syndication agents, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, General Electric Capital Corporation, as Sub-Agent for the Revolving Lenders, Credit Suisse, as administrative agent for the Second Priority Term Lenders, Landesbank Hessen Thuringen Girozentrale, New York Branch, General Electric Capital Corporation and HSH Nordbank AG, New York Branch, as joint documentation agents for the first priority Lenders and Bayerische Landesbank, General Electric Capital Corporation and Union Bank of California, N.A., as joint documentation agents for the second priority Lenders, as amended | |
E&S | Electricity and steam | |
Eastman | Eastman Chemical Company | |
EIA | Energy Information Administration of the Department of Energy | |
EITF | Emerging Issues Task Force | |
Enron | Enron Corp. | |
Enron Canada | Enron Canada Corp. | |
Entergy | Entergy Services, Inc. | |
EOB | California Electricity Oversight Board | |
EPA | United States Environmental Protection Agency | |
EPAct (1992)(2005) | Energy Policy Act of 1992 — or — Energy Policy Act of 2005 | |
EPS | Earnings per share | |
ERC(s) | Emission reduction credit(s) | |
ERCOT | Electric Reliability Council of Texas | |
ERISA | Employee Retirement Income Security Act | |
ESA | Energy Services Agreement | |
ESPP | 2000 Employee Stock Purchase Plan | |
EWG(s) | Exempt wholesale generator(s) | |
Exchange Act | United States Securities Exchange Act of 1934, as amended | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
FFIC | Fireman’s Fund Insurance Company | |
FIN | FASB Interpretation Number | |
FIN 46-R | FIN 46, as revised | |
First Priority Notes | 95/8% First Priority Senior Secured Notes Due 2014 | |
FPA | Federal Power Act | |
Freeport | Freeport Energy Center, LP | |
FSP | FASB staff positions | |
FUCO(s) | Foreign Utility Company(ies) | |
GAAP | Generally accepted accounting principles |
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Abbreviation | Definition | |
GE | General Electric International, Inc. | |
GEC | Gilroy Energy Center, LLC | |
GECF | GE Commercial Finance Energy Financial Services | |
General Electric | General Electric Company | |
Gilroy | Calpine Gilroy Cogen, L.P. | |
Gilroy 1 | Calpine Gilroy 1, Inc. | |
Goose Haven | Goose Haven Energy Center, LLC | |
GPC | Geysers Power Company, LLC | |
Greenfield LP | Greenfield Energy Centre LP | |
Heat rate | A measure of the amount of fuel required to produce a unit of electricity | |
HIGH TIDES I | 53/4% Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities | |
HIGH TIDES II | 51/2% Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities | |
HIGH TIDES III | 5% Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities | |
HRSG | Heat recovery steam generator | |
HTM | Heat Thermal Medium Heater System | |
IP | International Paper Company | |
IPP(s) | Independent power producer(s) | |
IRS | United States Internal Revenue Service | |
ISO | Independent System Operator | |
King City Cogen | Calpine King City Cogen, LLC | |
KWh | Kilowatt hour(s) | |
LCRA | Lower Colorado River Authority | |
LDC(s) | Local distribution company(ies) | |
LIBOR | London Inter-Bank Offered Rate | |
LNG | Liquid natural gas | |
LSTC | Liabilities Subject to Compromise | |
LTSA | Long Term Service Agreement | |
Mankato | Mankato Energy Center, LLC | |
Metcalf | Metcalf Energy Center, LLC | |
Mitsui | Mitsui & Co., Ltd. | |
MLCI | Merrill Lynch Commodities, Inc. | |
MMBtu | Million Btu | |
MMcfe | Million net cubic feet equivalent | |
Morris | Morris Energy Center | |
MW | Megawatt(s) | |
MWh | Megawatt hour(s) | |
NERC | North American Electric Reliability Council | |
NESCO | National Energy Systems Company | |
NGA | Natural Gas Act | |
NGPA | Natural Gas Policy Act |
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Abbreviation | Definition | |
NOL | Net operating loss | |
Non-Debtor(s) | The subsidiaries and affiliates of Calpine Corporation that are not Calpine Debtors | |
NOPR | Notice of Proposed Rulemaking | |
NOR | Notice of Rejection | |
NPC | Nevada Power Company | |
NYSE | New York Stock Exchange | |
O&M | Operations and maintenance | |
OCI | Other Comprehensive Income | |
Oneta | Oneta Energy Center | |
Ontelaunee | Ontelaunee Energy Center | |
OPA | Ontario Power Authority | |
OTC | Over-the-counter | |
Panda | Panda Energy International, Inc., and related party PLC II, LLC | |
PCF | Power Contract Financing, L.L.C. | |
PCF III | Power Contract Financing III, LLC | |
Petition Date | December 20, 2005 | |
PG&E | Pacific Gas and Electric | |
Pink Sheets | Pink Sheets Electronic Quotation Service maintained by Pink Sheets LLC for the National Quotation Bureau, Inc. | |
PJM | Pennsylvania-New Jersey-Maryland | |
PLC | PLC II, LLC | |
POX | Plant operating expense | |
PPA(s) | Power purchase agreement(s) | |
PSM | Power Systems Mfg., LLC | |
PUC(s) | Public Utility Commission(s) | |
PUHCA 1935 | Public Utility Holding Company Act of 1935 | |
PUHCA 2005 | Public Utility Holding Company Act of 2005 | |
PURPA | Public Utility Regulatory Policies Act of 1978 | |
QF(s) | Qualifying facility(ies) | |
RCRA | Resource Conservation and Recovery Act | |
RMR Contracts | Reliability Must Run contracts | |
Rosetta | Rosetta Resources Inc. | |
SAB | Staff Accounting Bulletin | |
Saltend | Saltend Energy Centre | |
SDG&E | San Diego Gas & Electric Company | |
SDNY Court | United States District Court for the Southern District of New York | |
SEC | Securities and Exchange Commission | |
Second Priority Notes | Calpine Corporation’s Second Priority Senior Secured Floating Rate Notes due 2007, 8.500% Second Priority Senior Secured Notes due 2010, 8.750% Second Priority Senior Secured Notes due 2013 and 9.875% Second Priority Senior Secured Notes due 2011 |
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Abbreviation | Definition | |
Second Priority Secured Debt Instruments | The Indentures between the Company and Wilmington Trust Company, as Trustee, relating to the Company’s Second Priority Senior Secured Floating Rate Notes due 2007, 8.500% Second Priority Senior Secured Notes due 2010, 8.750% Second Priority Senior Secured Notes due 2013, 9.875% Second Priority Senior Secured Notes due 2011 and the Credit Agreement among the Company, as Borrower, Goldman Sachs Credit Partners L.P., as Administrative Agent, Sole Lead Arranger and Sole Book Runner, 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 Agent, relating to the Company’s Senior Secured Term Loans Due 2007, in each case as such instruments may be amended from time to time | |
Securities Act | United States Securities Act of 1933, as amended | |
SFAS | Statement of Financial Accounting Standards | |
SFAS No. 123-R | SFAS No. 123, as revised | |
SFAS No. 128-R | SFAS No. 128, as revised | |
Siemens-Westinghouse | Siemens-Westinghouse Power Corporation (changed to Siemens Power Generation, Inc. on August 1, 2005) | |
SIP | 1996 Stock Incentive Plan | |
SkyGen | SkyGen Energy LLC, now called Calpine Northbrook Energy, LLC | |
SOP | Statement of Position | |
SPE | Special-Purpose Entities | |
SPP | Southwest Power Pool | |
SPPC | Sierra Pacific Power Company | |
Trust I | Calpine Capital Trust | |
Trust II | Calpine Capital Trust II | |
Trust III | Calpine Capital Trust III | |
TSA(s) | Transmission service agreement(s) | |
TTS | Thomassen Turbine Systems, B.V. | |
ULC I | Calpine Canada Energy Finance ULC | |
ULC II | Calpine Canada Energy Finance II ULC | |
U.S | United States of America | |
U.S. Bankruptcy Court | United States Bankruptcy Court for the Southern District of New York | |
U.S. Debtor(s) | Calpine Corporation and each of its subsidiaries and affiliates that have filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, which matters are being jointly administered in the U.S. Bankruptcy Court under the captionIn re Calpine Corporation, et al., Case No. 95-60200 (BRL) | |
Valladolid | Valladolid III Energy Center | |
VIE(s) | Variable interest entity(ies) | |
Whitby | Whitby Cogeneration Limited Partnership |
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Item 1. | Business |
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Our Business |
Bankruptcy Cases |
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• | Business Development: We are limiting our new business development activities and are focusing our ongoing efforts on maximizing the value of our advanced development opportunities, including projects with long-term power contracts or in advanced contract negotiations. We will review for possible sale certain development projects and will continue to evaluate existing petroleum coke gasification development in Texas. | |
• | Construction: We are completing construction projects with long-term power sales commitments and are significantly scaling back construction management activities. We are continuing to evaluate options for those projects without long-term PPAs, some of which have been identified for potential sale. | |
• | Power Services: We are discontinuing all new business activity for Calpine Power Services, Inc. CPSI will continue to perform its service obligations under existing construction management and O&M contracts. | |
• | Marketing and Sales: We are evaluating our future participation in certain power markets to determine the right balance between short-term, long-term and tolling contracts for the sale of our electrical generation. Until then, we are curtailing new retail power sales efforts and, while administering existing contracts, we are limiting our efforts to put long-term power contracts in place for existing generation plants. | |
• | TTS: In keeping with our focus on the North American power generation sector, we have determined that TTS is not a core business for us and we are exploring the possible sale of this company. |
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• | Reduce negative cash flow and create a profitable, competitive and sustainable business with stable positive earnings |
• | Achieve positive operating cash flow in 2007 | |
• | Optimize our asset portfolio through selective asset sales and contract rejections | |
• | Reduce operating cost and achieve greater operational efficiencies | |
• | Reduce interest cost |
• | Simplify our business structure |
• | Define core businesses and functions | |
• | Focus on new asset base and business functions | |
• | Streamline management reporting processes and prioritize information reported | |
• | Reduce management reporting overhead costs |
• | Simplify our project financing and overall corporate capital structure | |
• | Improve access to working capital |
• | Align with new business model |
• | Motivate key employees to execute the goals of the business plan | |
• | Formulate and implement a plan of reorganization |
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Air Pollutant Emission Rates — Pounds of Pollutant Emitted | |||||||||||||||||||||
per MWh of Electricity Generated | |||||||||||||||||||||
Average | Calpine Power Plants | ||||||||||||||||||||
US 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 | 3.10 | 0.21 | 93.2% Less | 0.00074 | 99.9% Less | ||||||||||||||||
Sulphur Dioxide, SO(2) | |||||||||||||||||||||
Acid rain and fine particulate formation | 8.09 | 0.005 | 99.9% Less | 0.00015 | 99.9% Less | ||||||||||||||||
Mercury, Hg | |||||||||||||||||||||
Neurotoxin | 0.000036 | 0 | 100% Less | 0.000008 | 77.8% Less | ||||||||||||||||
Carbon Dioxide, CO(2) | |||||||||||||||||||||
Principal greenhouse gas — contributor to climate change | 1,919 | 882 | 54.0% Less | 80.8 | 95.86% Less | ||||||||||||||||
Particulate Matter, PM | |||||||||||||||||||||
Respiratory health effects | 0.5 | 0.037 | 92.6% Less | 0.014 | 97.2% Less |
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(1) | The U.S. fossil fuel fleet’s emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2004. Emission rates are based on 2004 emissions and net generation. |
(2) | Calpine’s combined-cycle power plant emission rates are based on 2005 data. |
(3) | Calpine’s geothermal power plant emission rates are based on 2004 data and include expected results from the mercury abatement program currently in process. |
• | 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. | |
• | 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 joined the EPA’s Climate Leaders Program, which is intended to encourage climate change strategies, help establish future greenhouse gas emission reduction goals, and increase energy efficiency among participants. As part of Climate Leaders, Calpine has submitted data on greenhouse gas emissions annually since 2003, from all its natural gas-fired power plants, The Geysers and its natural gas production facilities located throughout the United States. | |
• | Calpine became the first IPP to earn the distinction ofClimate Action Leadertm, and has certified its 2003 and 2004 CO2 emissions inventory with the California Climate Action Registry. Calpine continues to publicly and voluntarily report its CO2 emissions from generation of electricity in California under this rigorous registry program. | |
• | Calpine was awarded a 2005 Flex Your Power Honorable Mention for our outstanding achievements in energy efficiency in the Innovative Products and Services category for our Performance Optimization Program and Santa Rosa Geysers Recharge Project. | |
• | Calpine is one of several Silicon Valley firms pledging to reduce area CO2 emissions to 20% below 1990 levels by 2010 as a participant in the Sustainable Silicon Valley Project, a multi-stakeholder collaborative initiative to produce significant environmental improvement and resource conservation in Silicon Valley through the development and implementation of a regional environmental management system. |
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![](https://capedge.com/proxy/10-K/0000891618-06-000236/f17394f1739401.gif)
Market Share | |||||||||||||
NERC Region/ Country | Projects | Megawatts | (NERC/UK) | ||||||||||
WECC | 49 | 8,361 | 5% | ||||||||||
ERCOT | 12 | 7,666 | 9% | ||||||||||
SERC | 9 | 5,030 | 3% | ||||||||||
MAIN | 4 | * | 2,136 | 3% | |||||||||
SPP | 3 | 1,674 | 4% | ||||||||||
NEPOOL | 5 | 1,272 | 4% | ||||||||||
FRCC | 3 | 875 | 2% | ||||||||||
MAAC | 3 | 193 | 1% | ||||||||||
MAPP | 1 | 375 | 1% | ||||||||||
NYPOOL | 5 | 334 | 1% | ||||||||||
NPCC | 2 | 510 | 1% | ||||||||||
TOTAL NERC | 96 | 28,426 | 3% | ||||||||||
Mexico | 1 | 236 | 1% | ||||||||||
TOTAL | 97 | 28,662 | 3% | ||||||||||
* | Includes Phase II of Fox Energy Center, which was under construction as of December 31, 2005. |
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Megawatts | ||||||||||||||||||||||
With | Calpine Net | Calpine Net | ||||||||||||||||||||
Number of | Baseload | Peaking | Interest | Interest with | ||||||||||||||||||
Plants | Capacity | Capacity | Baseload | Peaking | ||||||||||||||||||
In operation | ||||||||||||||||||||||
Geothermal power plants | 19 | 750 | 750 | 750 | 750 | |||||||||||||||||
Gas-fired power plants | 73 | 21,660 | 26,935 | 20,543 | 25,709 | |||||||||||||||||
Under construction | ||||||||||||||||||||||
New facilities | 5 | 2,312 | 2,734 | 1,636 | 1,943 | |||||||||||||||||
Expansion/ Phase II | — | 245 | 260 | 245 | 260 | |||||||||||||||||
Total | 97 | 24,967 | 30,679 | 23,174 | 28,662 | |||||||||||||||||
Operating Power Plants |
Country, | Calpine Net | ||||||||||||||||||||||||||||
US | With | Calpine Net | Interest | ||||||||||||||||||||||||||
State or | Baseload | Peaking | Calpine | Interest | with | Total 2005 | |||||||||||||||||||||||
Can. | Capacity | Capacity | Interest | Baseload | Peaking | Generation | |||||||||||||||||||||||
Power Plant | Province | (MW) | (MW) | Percentage | (MW) | (MW) | MWh(1) | ||||||||||||||||||||||
Geothermal Power Plants | |||||||||||||||||||||||||||||
Total Geothermal Power Plants(19) | 750.0 | 750.0 | 750.0 | 750.0 | 6,704,751 | ||||||||||||||||||||||||
Gas-Fired Power Plants | |||||||||||||||||||||||||||||
Freestone Energy Center | TX | 1,022.0 | 1,022.0 | 100.0 | % | 1,022.0 | 1,022.0 | 4,187,391 | |||||||||||||||||||||
Deer Park Energy Center | TX | 792.0 | 1,019.0 | 100.0 | % | 792.0 | 1,019.0 | 5,691,076 | |||||||||||||||||||||
Oneta Energy Center | OK | 994.0 | 994.0 | 100.0 | % | 994.0 | 994.0 | 683,307 | |||||||||||||||||||||
Delta Energy Center | CA | 799.0 | 882.0 | 100.0 | % | 799.0 | 882.0 | 5,509,506 | |||||||||||||||||||||
Morgan Energy Center | AL | 722.0 | 852.0 | 100.0 | % | 722.0 | 852.0 | 1,208,479 | |||||||||||||||||||||
Decatur Energy Center | AL | 793.0 | 852.0 | 100.0 | % | 793.0 | 852.0 | 690,875 | |||||||||||||||||||||
Broad River Energy Center | SC | — | 847.0 | 100.0 | % | — | 847.0 | 662,103 | |||||||||||||||||||||
Baytown Energy Center | TX | 742.0 | 830.0 | 100.0 | % | 742.0 | 830.0 | 4,299,914 | |||||||||||||||||||||
Pasadena Power Plant | TX | 776.0 | 777.0 | 100.0 | % | 776.0 | 777.0 | 3,094,913 | |||||||||||||||||||||
Magic Valley Generating Station | TX | 700.0 | 751.0 | 100.0 | % | 700.0 | 751.0 | 3,082,194 | |||||||||||||||||||||
Pastoria Energy Facility | CA | 750.0 | 750.0 | 100.0 | % | 750.0 | 750.0 | 2,582,487 | |||||||||||||||||||||
Hermiston Power Project | OR | 546.0 | 642.0 | 100.0 | % | 546.0 | 642.0 | 3,650,823 | |||||||||||||||||||||
Columbia Energy Center | SC | 464.0 | 641.0 | 100.0 | % | 464.0 | 641.0 | 391,087 | |||||||||||||||||||||
Rocky Mountain Energy Center | CO | 479.0 | 621.0 | 100.0 | % | 479.0 | 621.0 | 3,249,691 | |||||||||||||||||||||
Osprey Energy Center | FL | 530.0 | 609.0 | 100.0 | % | 530.0 | 609.0 | 1,780,739 | |||||||||||||||||||||
Acadia Energy Center | LA | 1,092.0 | 1,210.0 | 50.0 | % | 546.0 | 605.0 | 2,738,118 | |||||||||||||||||||||
Riverside Energy Center | WI | 518.0 | 603.0 | 100.0 | % | 518.0 | 603.0 | 1,769,523 | |||||||||||||||||||||
Metcalf Energy Center | CA | 554.0 | 600.0 | 100.0 | % | 554.0 | 600.0 | 1,974,610 | |||||||||||||||||||||
Brazos Valley Power Plant | TX | 508.0 | 594.0 | 100.0 | % | 508.0 | 594.0 | 3,368,606 | |||||||||||||||||||||
Aries Power Project | MO | 523.0 | 590.0 | 100.0 | % | 523.0 | 590.0 | 285,452 | |||||||||||||||||||||
Channel Energy Center | TX | 527.0 | 574.0 | 100.0 | % | 527.0 | 574.0 | 2,800,139 | |||||||||||||||||||||
Los Medanos Energy Center | CA | 497.0 | 566.0 | 100.0 | % | 497.0 | 566.0 | 3,705,762 | |||||||||||||||||||||
Sutter Energy Center | CA | 535.0 | 543.0 | 100.0 | % | 535.0 | 543.0 | 2,472,080 |
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Country, | Calpine Net | |||||||||||||||||||||||||||
US | With | Calpine Net | Interest | |||||||||||||||||||||||||
State or | Baseload | Peaking | Calpine | Interest | with | Total 2005 | ||||||||||||||||||||||
Can. | Capacity | Capacity | Interest | Baseload | Peaking | Generation | ||||||||||||||||||||||
Power Plant | Province | (MW) | (MW) | Percentage | (MW) | (MW) | MWh(1) | |||||||||||||||||||||
Corpus Christi Energy Center | TX | 414.0 | 537.0 | 100.0 | % | 414.0 | 537.0 | 2,315,678 | ||||||||||||||||||||
Texas City Power Plant | TX | 457.0 | 534.0 | 100.0 | % | 457.0 | 534.0 | 1,860,795 | ||||||||||||||||||||
Carville Energy Center | LA | 455.0 | 531.0 | 100.0 | % | 455.0 | 531.0 | 2,062,451 | ||||||||||||||||||||
South Point Energy Center | AZ | 520.0 | 530.0 | 100.0 | % | 520.0 | 530.0 | 1,523,763 | ||||||||||||||||||||
Westbrook Energy Center | ME | 528.0 | 528.0 | 100.0 | % | 528.0 | 528.0 | 3,492,152 | ||||||||||||||||||||
Zion Energy Center | IL | — | 513.0 | 100.0 | % | — | 513.0 | 35,058 | ||||||||||||||||||||
RockGen Energy Center | WI | — | 460.0 | 100.0 | % | — | 460.0 | 332,447 | ||||||||||||||||||||
Clear Lake Power Plant | TX | 344.0 | 400.0 | 100.0 | % | 344.0 | 400.0 | 1,063,972 | ||||||||||||||||||||
Hidalgo Energy Center | TX | 499.0 | 499.0 | 78.5 | % | 392.0 | 392.0 | 1,790,681 | ||||||||||||||||||||
Fox Energy Center(2) | WI | 245.0 | 300.0 | 100.0 | % | 245.0 | 300.0 | 443,536 | ||||||||||||||||||||
Blue Spruce Energy Center | CO | — | 285.0 | 100.0 | % | — | 285.0 | 252,702 | ||||||||||||||||||||
Goldendale Energy Center | WA | 237.0 | 271.0 | 100.0 | % | 237.0 | 271.0 | 1,025,566 | ||||||||||||||||||||
Tiverton Power Plant(3) | RI | 267.0 | 267.0 | 100.0 | % | 267.0 | 267.0 | 1,822,302 | ||||||||||||||||||||
Rumford Power Plant(3) | ME | 263.0 | 263.0 | 100.0 | % | 263.0 | 263.0 | 1,022,754 | ||||||||||||||||||||
Santa Rosa Energy Center | FL | 250.0 | 250.0 | 100.0 | % | 250.0 | 250.0 | 1,150 | ||||||||||||||||||||
Hog Bayou Energy Center | AL | 235.0 | 237.0 | 100.0 | % | 235.0 | 237.0 | 20,432 | ||||||||||||||||||||
Pine Bluff Energy Center | AR | 184.0 | 215.0 | 100.0 | % | 184.0 | 215.0 | 1,228,979 | ||||||||||||||||||||
Los Esteros Critical Energy Facility | CA | — | 188.0 | 100.0 | % | — | 188.0 | 276,974 | ||||||||||||||||||||
Dighton Power Plant | MA | 170.0 | 170.0 | 100.0 | % | 170.0 | 170.0 | 517,445 | ||||||||||||||||||||
Auburndale Power Plant | FL | 150.0 | 150.0 | 100.0 | % | 150.0 | 150.0 | 628,849 | ||||||||||||||||||||
Gilroy Energy Center | CA | — | 135.0 | 100.0 | % | — | 135.0 | 52,968 | ||||||||||||||||||||
Gilroy Cogeneration Plant | CA | 117.0 | 128.0 | 100.0 | % | 117.0 | 128.0 | 111,608 | ||||||||||||||||||||
King City Cogeneration Plant | CA | 120.0 | 120.0 | 100.0 | % | 120.0 | 120.0 | 815,948 | ||||||||||||||||||||
Parlin Power Plant | NJ | 98.0 | 118.0 | 100.0 | % | 98.0 | 118.0 | 78,593 | ||||||||||||||||||||
Auburndale Peaking Energy Center | FL | — | 116.0 | 100.0 | % | — | 116.0 | 7,332 | ||||||||||||||||||||
Kennedy International Airport Power Plant (“KIAC”) | NY | 99.0 | 105.0 | 100.0 | % | 99.0 | 105.0 | 736,749 | ||||||||||||||||||||
Pryor Power Plant | OK | 38.0 | 90.0 | 100.0 | % | 38.0 | 90.0 | 315,955 | ||||||||||||||||||||
Calgary Energy Centre(4) | AB | 252.0 | 286.0 | 30.0 | % | 75.6 | 85.8 | 327,617 | ||||||||||||||||||||
Bethpage Energy Center 3 | NY | 79.9 | 79.9 | 100.0 | % | 79.9 | 79.9 | 199,395 | ||||||||||||||||||||
Island Cogeneration(4) | BC | 219.0 | 250.0 | 30.0 | % | 65.7 | 75.0 | 2,051,155 | ||||||||||||||||||||
Pittsburg Power Plant | CA | 64.0 | 64.0 | 100.0 | % | 64.0 | 64.0 | 194,235 | ||||||||||||||||||||
Bethpage Power Plant | NY | 55.0 | 56.0 | 100.0 | % | 55.0 | 56.0 | 109,930 | ||||||||||||||||||||
Newark Power Plant | NJ | 50.0 | 56.0 | 100.0 | % | 50.0 | 56.0 | 46,061 | ||||||||||||||||||||
Greenleaf 1 Power Plant | CA | 49.5 | 49.5 | 100.0 | % | 49.5 | 49.5 | 280,203 | ||||||||||||||||||||
Greenleaf 2 Power Plant | CA | 49.5 | 49.5 | 100.0 | % | 49.5 | 49.5 | 254,054 | ||||||||||||||||||||
Wolfskill Energy Center | CA | — | 48.0 | 100.0 | % | — | 48.0 | 16,475 | ||||||||||||||||||||
Yuba City Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 36,188 | ||||||||||||||||||||
Feather River Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 13,346 | ||||||||||||||||||||
Creed Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 9,657 | ||||||||||||||||||||
Lambie Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 15,899 |
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Country, | Calpine Net | ||||||||||||||||||||||||||||
US | With | Calpine Net | Interest | ||||||||||||||||||||||||||
State or | Baseload | Peaking | Calpine | Interest | with | Total 2005 | |||||||||||||||||||||||
Can. | Capacity | Capacity | Interest | Baseload | Peaking | Generation | |||||||||||||||||||||||
Power Plant | Province | (MW) | (MW) | Percentage | (MW) | (MW) | MWh(1) | ||||||||||||||||||||||
Goose Haven Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 11,036 | |||||||||||||||||||||
Riverview Energy Center | CA | — | 47.0 | 100.0 | % | — | 47.0 | 21,032 | |||||||||||||||||||||
Stony Brook Power Plant | NY | 45.0 | 47.0 | 100.0 | % | 45.0 | 47.0 | 299,722 | |||||||||||||||||||||
Bethpage Peaker | NY | — | 46.0 | 100.0 | % | — | 46.0 | 120,983 | |||||||||||||||||||||
King City Peaking Energy Center | CA | — | 45.0 | 100.0 | % | — | 45.0 | 16,261 | |||||||||||||||||||||
Androscoggin Energy Center(5) | ME | 136.0 | 136.0 | 32.3 | % | 44.0 | 44.0 | 1,552 | |||||||||||||||||||||
Watsonville (Monterey) Cogeneration Plant | CA | 29.0 | 30.0 | 100.0 | % | 29.0 | 30.0 | 164,929 | |||||||||||||||||||||
Agnews Power Plant | CA | 28.0 | 28.0 | 100.0 | % | 28.0 | 28.0 | 162,623 | |||||||||||||||||||||
Philadelphia Water Project | PA | — | 23.0 | 83.0 | % | — | 19.1 | — | |||||||||||||||||||||
Whitby Cogeneration(4) | ON | 50.0 | 50.0 | 15.0 | % | 7.5 | 7.5 | 337,281 | |||||||||||||||||||||
Total Gas-Fired Power Plants (73) | 21,659.9 | 26,934.9 | 20,542.7 | 25,709.3 | 88,405,348 | ||||||||||||||||||||||||
Total Operating Power Plants (92) | 22,409.9 | 27,684.9 | 21,292.7 | 26,459.3 | 95,110,099 | ||||||||||||||||||||||||
Consolidated Projects including plants with operating leases | 21,752.9 | 26,962.9 | 21,099.9 | 26,247.0 | |||||||||||||||||||||||||
Equity (Unconsolidated) Projects | 657.0 | 722.0 | 192.8 | 212.3 |
(1) | Generation MWh is shown here as 100% of each plant’s gross generation in MWh. |
(2) | Subsequent to December 31, 2005, Phase II of the Fox Energy Center entered commercial operation, resulting in a total net operating peaking capacity of the facility of 560 MW. |
(3) | On February 6, 2006, we filed a Notice of Rejection with the Bankruptcy Court to terminate the underlying operating lease of this facility. See Note 3 of the Notes to Consolidated Financial Statements. |
(4) | These power plants were deconsolidated as of December 31, 2005. See Note 10 of the Notes to Consolidated Financial Statements. |
(5) | See Note 10 of the Notes to Consolidated Financial Statements for the status of this project. |
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Projects Under Active Construction (All Gas-Fired) |
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 Active Construction(1) | ||||||||||||||||||||||||||
Otay Mesa Energy Center | CA | 510.0 | 593.0 | 100.0 | % | 510.0 | 593.0 | |||||||||||||||||||
Mankato Power Plant | MN | 292.0 | 375.0 | 100.0 | % | 292.0 | 375.0 | |||||||||||||||||||
Fox Energy Center II | WI | 245.0 | 260.0 | 100.0 | % | 245.0 | 260.0 | |||||||||||||||||||
Freeport Energy Center | TX | 210.0 | 236.0 | 100.0 | % | 210.0 | 236.0 | |||||||||||||||||||
Greenfield Energy Centre | Canada | 775.0 | 1,005.0 | 50.0 | % | 387.5 | 502.5 | |||||||||||||||||||
Valladolid III Power Plant | Mexico | 525.0 | 525.0 | 45.0 | % | 236.3 | 236.3 | |||||||||||||||||||
Total Projects Under Active Construction | 2,557.0 | 2,994.0 | 1,880.8 | 2,202.8 | ||||||||||||||||||||||
(1) | See “Projects Under Active Construction at December 31, 2005” below for current status of these projects. |
Projects Under Active Construction at December 31, 2005 |
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Federal Regulation of Electricity |
Federal Power Act |
Market Based Rate Authorization |
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FERC Regulation of Transfers of Jurisdictional Facilities |
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FERC Regulation Of Open Access Electric Transmission |
Public Utility Holding Company Act of 1935 |
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Public Utility Regulatory Policies Act of 1978 |
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Additional Provisions of EPAct 2005 |
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Western Energy Markets |
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FERC Regulation of Natural Gas Transportation |
FERC Regulation Over Natural Gas Transportation |
FERC Regulation of Sales of Natural Gas at Negotiated Rates |
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State Energy Regulation |
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Environmental Regulations |
Clean Air Act |
Clean Water Act |
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Safe Drinking Water Act |
Resource Conservation and Recovery Act |
Comprehensive Environmental Response, Compensation and Liability Act |
Canadian Environmental, Health and Safety Regulations |
Regulation of Canadian Gas |
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Summary of Key Activities |
Finance — New Issuances and Amendments: |
Date | Amount | Description | ||||
1/28/05 | $ | 100.0 million | Complete a non-recourse construction credit facility for Metcalf (repaid on June 20, 2005, in connection with the Metcalf preferred share and senior term loan financing described below) | |||
1/31/05 | $ | 260.0 million | Calpine Jersey II completes issuance of redeemable preferred shares due July 30, 2005 (repurchased on July 28, 2005, in connection with the sale of the Saltend facility described below) | |||
3/1/05 | $ | 503.0 million | Close a non-recourse project finance facility that provides $466.5 million to complete construction of Mankato and Freeport as well as a $36.5 million collateral letter of credit facility | |||
6/20/05 | $ | 255.0 million | Metcalf closes on a $155.0 million 5.5-year redeemable preferred shares offering and a five-year $100.0 million senior term loan; (repaid $100 million non-recourse credit facility completed on January 28, 2005, described above) | |||
6/23/05 | $ | 650.0 million | Receive funding on offering of 2015 Convertible Notes | |||
6/30/05 | $ | 123.1 million | Close non-recourse project finance facility for Bethpage Energy Center 3 | |||
8/12/05 | $ | 150.0 million | CCFCP completes a $150.0 million private placement of Class A Redeemable Preferred Shares due 2006 (repurchased in full on October 14, 2005) | |||
10/14/05 | $ | 300.0 million | CCFCP issues $300.0 million of 6-Year Redeemable Preferred Shares due 2011 | |||
12/22/05 | $ | 2.0 billion | Receive approval of first day motions from the U.S. Bankruptcy Court, including permission to continue to perform under power trading contracts, authorization to continue paying employee wages, salaries and benefits as well as interim approval to immediately use $500 million of its $2 billion DIP Facility, arranged by Deutsche Bank Securities Inc. and Credit Suisse |
Finance — Repurchases and Extinguishments: |
Date | Amount | Description | ||||
7/13/05 | $ | 517.5 million | Repay the convertible debentures payable to Trust III, the issuer of the HIGH TIDES III preferred securities, the proceeds of which are applied by Trust III to redeem the HIGH TIDES III preferred securities in full | |||
10/14/05 | $ | 150.0 million | Repurchase $150.0 million in CCFCP Class A Redeemable Preferred Shares due 2006 | |||
6/28/05 | $ | 94.3 million | Issue approximately 27.5 million shares of Calpine common stock in exchange for $94.3 million in aggregate principal amount at maturity of 2014 Convertible Notes pursuant to Section 3(a)(9) under the Securities Act | |||
1/1/05 — 12/31/05 | $ | 917.1 million | Repurchase Senior Notes in open market transactions totaling $917.1 million in principal for cash of $685.5 million plus accrued interest |
Finance — Other: |
Date | Description | |
3/31/05 | Deer Park Energy Center Limited Partnership enters into agreements with Merrill Lynch Commodities, Inc. to sell power and buy gas from April 1, 2005, to December 31, 2010, for a cash payment of $195.8 million, net of transaction costs, plus additional cash payments as additional transactions are executed |
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Asset Sales: |
Date | Description | |
7/7/05 | Complete the sale of substantially all of our remaining oil and gas assets for $1.05 billion, less approximately $60 million of estimated transaction fees and expenses | |
7/8/05 | Complete the sale of our 50% interest in the 175-MW Grays Ferry Power Plant for gross proceeds of $37.4 million | |
7/28/05 | Complete the sale of the 1,200-MW Saltend Energy Centre for approximately $862.9 million | |
7/29/05 | Complete the sale of Inland Empire Energy Center development project to GE for approximately $30.9 million | |
8/2/05 | Complete the sale of the 156-MW Morris Energy Center for $84.5 million | |
10/6/05 | Complete the sale of the 561-MW Ontelaunee Energy Center for $212.3 million |
Other: |
Date | Description | |
2/22/05 | Announce the selection of Inland Energy Center as site for North American launch of General Electric’s most advanced gas turbine technology, the “H Systemtm” | |
2/23/05 | NewSouth Energy, a newly formed subsidiary, launches an energy venture to better focus on wholesale power customers and energy markets in the South | |
3/28/05 | Announce the receipt of a contract to provide 75 MW of Transmission Must Run Services to Alberta Electric System Operator with contract terms of March 17, 2005 to June 30, 2006, with options to extend until June 2008 | |
4/12/05 | Enter into a 20-year Clean Energy Supply Contract with the OPA to make clean energy available from Calpine’s new 1,005-MW Greenfield Energy Centre, a partnership between Calpine and Mitsui, once commercial operation is achieved | |
6/1/05 | Expand and extend power contract with Safeway, Inc. for up to 141 MW during on peak and 122 MW during off peak through mid-2008 | |
6/2/05 | Carville Energy Center, LLC, CES, and Entergy enter into a one-year agreement to supply up to 485 MW of capacity and energy to Entergy | |
7/5/05 | Sign an agreement with Siemens-Westinghouse to restructure the long-term relationship, which is expected to provide additional flexibility to self-perform maintenance work in the future | |
7/7/05 | Announce a 15-year Master Products and Services Agreement with GE to supplement operations with a variety of services and to lower operating costs | |
7/11/05 | Major merchant power generator selects PSM to install LEC-III® and eliminate 90% of the power plant’s nitrogen oxide emissions | |
8/26/05 | CES announces new service agreements with Project Orange Associates LLC and the Greater Toronto Airports Authority to provide them with marketing, scheduling, and other energy managements services | |
8/29/05 | CES announces five year long-term power supply agreement for 170 MW of electricity with Tampa Electric Company | |
9/7/05 | Agree to form an energy marketing and trading venture with Bear Stearns to develop a third-party customer business focused on physical natural gas and power trading and related structured transactions | |
9/14/05 | Jeffrey E. Garten resigns from the Company’s Board of Directors | |
9/19/05 | William J. Keese and Walter L. Revell elected as independent directors | |
11/4/05 | John O. Wilson retires from the Company’s Board of Directors | |
11/10/05 | Announce resignation of Susan C. Schwab from the Company’s Board of Directors due to her confirmation by the U.S. Senate as a Deputy U.S. Trade Representative |
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Date | Description | |
11/29/05 | Announce change in executive management with the departures of Peter Cartwright, Chairman, President and Chief Executive Officer, and Robert D. Kelly, Executive Vice President and Chief Financial Officer | |
11/29/05 | Announce appointments of Kenneth T. Derr as Chairman of the Board and Acting Chief Executive Officer of Calpine and Eric N. Pryor as Interim Chief Financial Officer | |
12/5/05 | Gerald Greenwald resigns from the Company’s Board of Directors | |
12/6/05 | NYSE suspends trading of Calpine common stock prior to the opening of the market | |
12/12/05 | Robert P. May appointed as new Chief Executive Officer and member of the Company’s Board of Directors | |
12/20/05 | Peter Cartwright resigns from the Board of Directors | |
12/20/05 | The Company and certain of its United States subsidiaries file voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court, and certain of the Company’s Canadian subsidiaries file petitions for relief under the CCAA in Canada; in conjunction with the U.S. filings the Company receives commitments for up to $2 billion of secured DIP Financing |
Power Plant Development and Construction: |
Date | Project | Description | ||||
5/4/05 | Pastoria Energy Center | Commercial Operation | ||||
5/27/05 | Metcalf Energy Center | Commercial Operation | ||||
6/1/05 | Fox Energy Center (Phase 1) | Commercial Operation | ||||
7/1/05 | Bethpage Energy Center 3 | Commercial Operation | ||||
7/5/05 | Pastoria Energy Center (Phase II) | Commercial Operation |
Item 1A. | Risk Factors |
Risks Relating to Bankruptcy |
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• | the actions and decisions of our creditors and other third parties with interests in our bankruptcy cases, including official and unofficial committees of creditors and equity holders, which may be inconsistent with our plans; | |
• | objections to or limitations on our ability to obtain Bankruptcy Court approval with respect to motions in the bankruptcy cases that we may seek from time to time or potentially adverse decisions by the Bankruptcy Courts with respect to such motions; | |
• | objections to or limitations on our ability to avoid or reject contracts or leases that are burdensome or uneconomical; | |
• | the expiration of the exclusivity period for us to propose and confirm a plan of reorganization or delays, limitations or other impediments to our ability to develop, propose, confirm and consummate a plan of reorganization; | |
• | the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization; | |
• | our ability to obtain and maintain normal terms with customers, vendors and service providers; and | |
• | our ability to maintain contracts and leases that are critical to our operations. |
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• | how long payments under our secured debt could be delayed as a result of the bankruptcy cases; | |
• | whether or when secured creditors (or their applicable agents) could repossess or dispose of collateral; | |
• | the value of the collateral; or | |
• | whether or to what extent secured creditors would be compensated for any delay in payment or loss of value of the collateral through the requirement of “adequate protection.” |
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Capital Resources; Liquidity |
• | incur additional indebtedness and issue stock; | |
• | make prepayments on or purchase indebtedness in whole or in part; |
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• | pay dividends and other distributions with respect to our capital stock or repurchase our capital stock or make other restricted payments; | |
• | use DIP Loans for non-US Debtors or make inter-company loans to non-US Debtors; | |
• | make certain investments; | |
• | enter into transactions with affiliates on other than arms-length terms; | |
• | 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; | |
• | incur dividend or other payment restrictions affecting certain subsidiaries; | |
• | make capital expenditures beyond specified limits; | |
• | engage in certain business activities; and | |
• | acquire facilities or other businesses. |
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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. |
• | 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 reliable operation of our current power generation facilities; and | |
• | provisions of tax and securities laws that are conducive to raising capital. |
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Operations |
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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. |
• | start-up problems; | |
• | the breakdown or failure of equipment or processes; and | |
• | performance below expected levels of output or efficiency. |
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• | 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 PPA or to establish, maintain, restore, extend the term of, or increase the posted security if required by the PPA; | |
• | 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 PPA; | |
• | 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. |
• | the heat content of the extractable steam or fluids; | |
• | the geology of the reservoir; |
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• | 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. |
• | seasonal variations in energy prices; | |
• | variations in levels of production; | |
• | the timing and size of acquisitions; and | |
• | the completion of development and construction projects. |
Market |
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California Power Market |
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Government Regulation |
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Item 1B. | Unresolved Staff Comments |
Item 2. | Properties |
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Item 3. | Legal Proceedings |
Item 4. | Submission of Matters to a Vote of Security Holders |
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
High | Low | Market | ||||||||
2004 | ||||||||||
First Quarter | $ | 6.42 | $ | 4.35 | NYSE | |||||
Second Quarter | 4.98 | 3.04 | NYSE | |||||||
Third Quarter | 4.46 | 2.87 | NYSE | |||||||
Fourth Quarter | 4.08 | 2.24 | NYSE | |||||||
2005 | ||||||||||
First Quarter | $ | 3.80 | $ | 2.64 | NYSE | |||||
Second Quarter | 3.60 | 1.45 | NYSE | |||||||
Third Quarter | 3.88 | 2.26 | NYSE | |||||||
Fourth Quarter | 3.05 | 0.20 | NYSE (high) | |||||||
Pink Sheets (low) |
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Item 6. | Selected Financial Data |
Selected Consolidated Financial Data |
Years Ended December 31, | |||||||||||||||||||||
2005 | 2004 | 2003 | 2002 | 2001 | |||||||||||||||||
(In thousands, except earnings per share) | |||||||||||||||||||||
Statement of Operations data: | |||||||||||||||||||||
Total revenue | $ | 10,112,658 | $ | 8,648,382 | $ | 8,421,170 | $ | 7,069,198 | $ | 6,338,305 | |||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (9,880,954 | ) | $ | (419,683 | ) | $ | (13,272 | ) | $ | 1,463 | $ | 470,557 | ||||||||
Discontinued operations, net of tax | (58,254 | ) | 177,222 | 114,351 | 117,155 | 151,899 | |||||||||||||||
Cumulative effect of a change in accounting principle(1) | — | — | 180,943 | — | 1,036 | ||||||||||||||||
Net income (loss) | $ | (9,939,208 | ) | $ | (242,461 | ) | $ | 282,022 | $ | 118,618 | $ | 623,492 | |||||||||
Basic earnings (loss) per common share: | |||||||||||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (21.32 | ) | $ | (0.97 | ) | $ | (0.03 | ) | $ | — | $ | 1.55 | ||||||||
Discontinued operations, net of tax | (0.12 | ) | 0.41 | 0.29 | 0.33 | 0.50 | |||||||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | — | 0.46 | — | — | ||||||||||||||||
Net income (loss) | $ | (21.44 | ) | $ | (0.56 | ) | $ | 0.72 | $ | 0.33 | $ | 2.05 | |||||||||
Diluted earnings (loss) per common share: | |||||||||||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (21.32 | ) | $ | (0.97 | ) | $ | (0.03 | ) | $ | — | $ | 1.32 | ||||||||
Discontinued operations, net of tax provision | (0.12 | ) | 0.41 | 0.29 | 0.33 | 0.48 | |||||||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | — | 0.45 | — | — | ||||||||||||||||
Net income (loss) | $ | (21.44 | ) | $ | (0.56 | ) | $ | 0.71 | $ | 0.33 | $ | 1.80 | |||||||||
Balance Sheet data: | |||||||||||||||||||||
Total assets | $ | 20,544,797 | $ | 27,216,088 | $ | 27,303,932 | $ | 23,226,992 | $ | 21,937,227 | |||||||||||
Short-term debt and capital lease obligations | 5,413,937 | 1,029,257 | 346,994 | 1,651,448 | 25,307 | ||||||||||||||||
Long-term debt and capital lease obligations | 2,462,462 | 16,940,809 | 17,324,284 | 12,456,259 | 12,490,175 | ||||||||||||||||
Liabilities subject to compromise(2) | 14,610,064 | — | — | — | — | ||||||||||||||||
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts(3) | $ | — | $ | — | $ | — | $ | 1,123,969 | $ | 1,122,924 |
(1) | The 2003 gain from the cumulative effect of a change in accounting principle included three items: (1) a gain of $181.9 million, net of tax effect, from the adoption of DIG Issue No. C20; (2) a loss of $1.5 million associated with the adoption of FIN 46, as revised and the deconsolidation of the Trusts which issued the HIGH TIDES and (3) a gain of $0.5 million, net of tax effect, from the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations.” |
(2) | LSTC include unsecured and undersecured liabilities incurred prior to the Petition Date and exclude liabilities that are fully secured or liabilities of our subsidiaries or affiliates that have not made bankruptcy filings and other approved payments such as taxes and payroll. See Note 24 of the Notes to Consolidated Financial Statements for more information. |
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(3) | Included in long-term debt as of December 31, 2004 and 2003. See Note 14 of the Notes to Consolidated Financial Statements for more information. |
Selected Operating Information |
Years Ended December 31, | ||||||||||||||||||||||
2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||||
(Dollars in thousands, except pricing data) | ||||||||||||||||||||||
Power Plants(1): | ||||||||||||||||||||||
Electricity and steam revenues: | ||||||||||||||||||||||
Energy | $ | 4,676,631 | $ | 3,782,205 | $ | 3,023,327 | $ | 2,072,257 | $ | 1,593,452 | ||||||||||||
Capacity | 1,103,118 | 1,002,939 | 965,728 | 757,562 | 507,542 | |||||||||||||||||
Thermal and other | 499,091 | 380,203 | 302,119 | 164,132 | 138,845 | |||||||||||||||||
Total electricity and steam revenues | $ | 6,278,840 | $ | 5,165,347 | $ | 4,291,174 | $ | 2,993,951 | $ | 2,239,839 | ||||||||||||
MWh produced | 87,431 | 83,412 | 70,856 | 63,172 | 38,445 | |||||||||||||||||
Average electric price per MWh generated(2) | $ | 71.81 | $ | 61.93 | $ | 60.56 | $ | 47.39 | $ | 58.26 |
(1) | From continuing operations only. Discontinued operations are excluded. |
(2) | Excluding the effects of hedging, balancing and optimization activities related to our generating assets. |
Years Ended December 31, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Total revenue | $ | 10,112,658 | $ | 8,648,382 | $ | 8,421,170 | ||||||
Sales of purchased power and gas for hedging and optimization(1) | 3,667,992 | 3,376,293 | 4,033,193 | |||||||||
As a percentage of total revenue | 36.27 | % | 39.04 | % | 47.89 | % | ||||||
Total cost of revenue | 12,057,581 | 8,268,433 | 7,814,343 | |||||||||
Purchased power and gas expense for hedging and optimization(1) | 3,417,153 | 3,198,690 | 3,962,613 | |||||||||
As a percentage of total cost of revenue | 28.34 | % | 38.69 | % | 50.71 | % |
(1) | On October 1, 2003, we adopted on a prospective basis EITF Issue No.03-11 and netted certain 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. |
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Nine Months | |||||
Ended | |||||
September 30, | |||||
2003 | |||||
(In thousands) | |||||
Sales to NEPOOL from power we generated | $ | 258,945 | |||
Sales to NEPOOL from hedging and other activity | 117,345 | ||||
Total sales to NEPOOL | $ | 376,290 | |||
Total purchases from NEPOOL | $ | 310,025 |
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Overview |
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• | developing and executing our new business plan, including enhancing the value of our core assets and businesses during the pendency of our bankruptcy cases; |
• | preserving and enhancing our liquidity while spark spreads (the differential between power revenues and fuel costs) are depressed; | |
• | lowering our costs of production and overhead through various efficiency programs; |
• | developing, proposing, confirming and implementing our plan of reorganization; and | |
• | emerging from bankruptcy as a stronger, more competitive company. |
Bankruptcy Considerations |
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• | Stabilization — During this initial phase, we are focused on stabilizing our business operations and adjusting to the changes caused by bankruptcy. Our activities during this period include securing the DIP Facility, establishing working relationships with our various creditor committees and their advisors and performing a comprehensive lease and executory contract review process. We have made significant progress in this phase and will continue our stabilization efforts during 2006, particularly with regard to the lease and executory contract review process. | |
• | Plan Design — In this phase, we assess the business and prepare a business plan, evaluate claims made against the Calpine Debtors and prepare a plan of reorganization that is intended to maximize the value of the bankruptcy estate. We are in the early stages of this phase now and will likely be in this phase throughout 2006. The period during which we have the exclusive right to propose a plan or plans of reorganization has been extended by the U.S. Bankruptcy Court to December 31, 2006, and we have the exclusive right to solicit acceptances of any such plans until March 31, 2007. | |
• | Implementation — In this phase, we will continue to negotiate our plan of reorganization with creditor committees with the expectation that an agreed plan of reorganization, supported by our official and ad hoc creditor committees, will be proposed and filed with the U.S. Bankruptcy Court, and an agreed plan, which may contemplate liquidation of the Canadian Debtors, filed with the Canadian Court. In addition, during this phase we will determine how the claims of various creditors and interests of equity holders, if any, will be satisfied. This is the final phase and we expect that it will result in our emergence from bankruptcy. However, we cannot be sure at this time when or if we will emerge from bankruptcy. It is possible that some or all of the assets of any one or more of the Calpine Debtors may be sold. |
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Results of Operations |
Year Ended December 31, 2005, Compared to Year Ended December 31, 2004 |
Revenue |
2005 | 2004 | $ Change | % Change | |||||||||||||
Total revenue | $ | 10,112.7 | $ | 8,648.4 | $ | 1,464.3 | 16.9% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Electricity and steam revenue | $ | 6,278.8 | $ | 5,165.3 | $ | 1,113.5 | 21.6% |
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2005 | 2004 | $ Change | % Change | |||||||||||||
Transmission sales revenue | $ | 11.5 | $ | 20.0 | $ | (8.5 | ) | (42.5)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Sales of purchased power and gas for hedging and optimization | $ | 3,668.0 | $ | 3,376.3 | $ | 291.7 | 8.6 | % |
2005 | 2004 | $ Change | % Change | ||||||||||||||
Realized gain on power and gas mark-to-market transactions, net | $ | 106.5 | $ | 48.1 | $ | 58.4 | 121.4 | % | |||||||||
Unrealized (loss) on power and gas mark-to-market transactions, net | (95.1 | ) | (34.7 | ) | (60.4 | ) | 174.1 | % | |||||||||
Mark-to-market activities, net | $ | 11.4 | $ | 13.4 | $ | (2.0 | ) | (14.9 | )% | ||||||||
2005 | 2004 | $ Change | % Change | |||||||||||||
Other revenue | $ | 143.0 | $ | 73.3 | $ | 69.7 | 95.1% |
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Cost of Revenue |
2005 | 2004 | $ Change | % Change | |||||||||||||
Cost of revenue | $ | 12,057.6 | $ | 8,268.4 | $ | (3,789.2 | ) | (45.8)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Plant operating expense | $ | 717.4 | $ | 727.9 | $ | 10.5 | 1.4% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Royalty expense | $ | 36.9 | $ | 28.4 | $ | (8.5 | ) | (29.9)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Transmission purchase expense | $ | 87.6 | $ | 74.8 | $ | (12.8 | ) | (17.1)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Purchased power and gas expense for hedging and optimization | $ | 3,417.2 | $ | 3,198.7 | $ | (218.5 | ) | (6.8)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Fuel expense | $ | 4,623.3 | $ | 3,587.4 | $ | (1,035.9 | ) | (28.9)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Depreciation and amortization expense | $ | 506.4 | $ | 446.0 | $ | (60.4 | ) | (13.5)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Operating Plant Impairments | $ | 2,412.6 | $ | — | $ | (2,412.6 | ) | — % |
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2005 | 2004 | $ Change | % Change | |||||||||||||
Operating lease expense | $ | 104.7 | $ | 105.9 | $ | 1.2 | 1.1% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Other cost of revenue | $ | 151.5 | $ | 99.3 | $ | (52.2 | ) | (52.6)% |
(Income)/ Expense |
2005 | 2004 | $ Change | % Change | |||||||||||||
(Income) loss from unconsolidated investments in power projects and oil and gas properties | $ | (12.1 | ) | $ | 14.1 | $ | 26.2 | 185.8% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Equipment, development project and other impairments | $ | 2,117.7 | $ | 46.9 | $ | (2,070.8 | ) | (4,415.4)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Long-term service agreement cancellation charge | $ | 34.1 | $ | 7.7 | $ | (26.4 | ) | (342.9)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Project development expense | $ | 27.6 | $ | 19.9 | $ | (7.7 | ) | (38.7)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Research and development expense | $ | 19.2 | $ | 18.4 | $ | (0.8 | ) | (4.3)% |
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2005 | 2004 | $ Change | % Change | |||||||||||||
Sales, general and administrative expense | $ | 239.9 | $ | 220.6 | $ | (19.3 | ) | (8.7)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Interest expense | $ | 1,397.3 | $ | 1,095.4 | $ | (301.9 | ) | (27.6)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Interest (income) | $ | (84.2 | ) | $ | (54.8 | ) | $ | 29.4 | 53.6% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Minority interest expense | $ | 42.5 | $ | 34.7 | $ | (7.8 | ) | (22.5)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
(Income) from the repurchase of various issuances of debt | $ | (203.3 | ) | $ | (246.9 | ) | $ | (43.6 | ) | (17.7)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Other (income)/expense, net | $ | 72.4 | $ | (121.1 | ) | $ | (193.5 | ) | (159.8)% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Reorganization items | $ | 5,026.5 | $ | — | $ | (5,026.5 | ) | — % |
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December 31, 2005 | |||||
Provision for allowable claims | $ | 3,791.5 | |||
Impairment of investment in Canadian subsidiaries | 879.1 | ||||
Write-off of unamortized deferred financing costs and debt discounts | 148.1 | ||||
Loss on terminated contracts, net | 139.4 | ||||
Professional fees | �� | 36.4 | |||
Other reorganization items | 32.0 | ||||
Total reorganization items | $ | 5,026.5 | |||
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2005 | 2004 | $ Change | % Change | |||||||||||||
Provision (benefit) for income taxes | $ | (741.4 | ) | $ | (235.3 | ) | $ | 506.1 | 215.1% |
2005 | 2004 | $ Change | % Change | |||||||||||||
Discontinued operations, net of tax | $ | (58.2 | ) | $ | 177.2 | $ | (235.4 | ) | (132.8 | )% |
Net Income (Loss) |
2005 | 2004 | $ Change | % Change | |||||||||||||
Net income (loss) | $ | (9,939.2 | ) | $ | (242.5 | ) | $ | (9,696.7 | ) | (3,998.6)% |
Results of Operations |
Year Ended December 31, 2004, Compared to Year Ended December 31, 2003 |
Revenue |
2004 | 2003 | $ Change | % Change | |||||||||||||
Total revenue | $ | 8,648.4 | $ | 8,421.2 | $ | 227.2 | 2.7% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Electricity and steam revenue | $ | 5,165.3 | $ | 4,291.2 | $ | 874.1 | 20.4% |
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2004 | 2003 | $ Change | % Change | |||||||||||||
Transmission sales revenue | $ | 20.0 | $ | 15.3 | $ | 4.7 | 30.7% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Sales of purchased power and gas for hedging and optimization | $ | 3,376.3 | $ | 4,033.2 | $ | (656.9 | ) | (16.3)% |
2004 | 2003 | $ Change | % Change | ||||||||||||||
Realized gain on power and gas mark-to-market transactions, net | $ | 48.1 | $ | 24.3 | $ | 23.8 | 97.9 | % | |||||||||
Unrealized (loss) on power and gas mark-to-market transactions, net | (34.7 | ) | (50.7 | ) | 16.0 | 31.6 | % | ||||||||||
Mark-to-market activities, net | $ | 13.4 | $ | (26.4 | ) | $ | 39.8 | 150.8 | % | ||||||||
2004 | 2003 | $ Change | % Change | |||||||||||||
Other revenue | $ | 73.3 | $ | 107.9 | $ | (34.6 | ) | (32.1)% |
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Cost of Revenue |
2004 | 2003 | $ Change | % Change | |||||||||||||
Cost of revenue | $ | 8,268.4 | $ | 7,814.3 | $ | (454.1 | ) | (5.8)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Plant operating expense | $ | 727.9 | $ | 599.3 | $ | (128.6 | ) | (21.5)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Royalty expense | $ | 28.4 | $ | 24.6 | $ | (3.8 | ) | (15.4)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Transmission purchase expense | $ | 74.8 | $ | 34.7 | $ | (40.1 | ) | (115.6)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Purchased power and gas expense for hedging and optimization | $ | 3,198.7 | $ | 3,962.6 | $ | 763.9 | 19.3% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Fuel expense | $ | 3,587.4 | $ | 2,636.7 | $ | (950.7 | ) | (36.1)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Depreciation and amortization expense | $ | 446.0 | $ | 382.0 | $ | (64.0 | ) | (16.8)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Operating lease expense | $ | 105.9 | $ | 112.1 | $ | 6.2 | 5.5% |
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2004 | 2003 | $ Change | % Change | |||||||||||||
Other cost of revenue | $ | 99.3 | $ | 62.3 | $ | (37.0 | ) | (59.4)% |
(Income)/ Expense |
2004 | 2003 | $ Change | % Change | |||||||||||||
(Income) loss from unconsolidated investments in power projects and oil and gas properties | $ | 14.1 | $ | (75.7 | ) | $ | (89.8 | ) | (118.6)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Equipment, development projects and other impairment cost | $ | 46.9 | $ | 68.0 | $ | 21.1 | 31.0% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Long-term service agreement cancellation charge | $ | 7.7 | $ | 16.3 | $ | 8.6 | 52.8% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Project development expense | $ | 19.9 | $ | 18.2 | $ | (1.7 | ) | (9.3)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Research and development expense | $ | 18.4 | $ | 10.6 | $ | (7.8 | ) | (73.6)% |
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2004 | 2003 | $ Change | % Change | |||||||||||||
Sales, general and administrative expense | $ | 220.6 | $ | 204.1 | $ | (16.5 | ) | (8.1)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Interest expense | $ | 1,095.4 | $ | 695.5 | $ | (399.9 | ) | (57.5)% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Distributions on trust preferred securities | $ | — | $ | 46.6 | $ | 46.6 | 100.0% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Interest (income) | $ | (54.8 | ) | $ | (39.2 | ) | $ | 15.6 | 39.8% |
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)% |
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2004 | 2003 | $ Change | % Change | |||||||||||||
Other (income), net | $ | (121.1 | ) | $ | (46.6 | ) | $ | 74.5 | 159.9% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Provision (benefit) for income taxes | $ | (235.3 | ) | $ | (26.4 | ) | $ | 208.9 | 791.3% |
2004 | 2003 | $ Change | % Change | |||||||||||||
Discontinued operations, net of tax | $ | 177.2 | $ | 114.4 | $ | 62.8 | 54.9% |
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)% |
Liquidity and Capital Resources |
Bankruptcy Proceedings and Financing Activities |
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Years Ended December 31, | |||||||||||||||
2005 | 2004 | 2003 | |||||||||||||
(In thousands) | |||||||||||||||
Beginning cash and cash equivalents | $ | 718,023 | $ | 954,828 | $ | 567,371 | |||||||||
Net cash provided by: | |||||||||||||||
Operating activities | $ | (708,361 | ) | $ | 9,895 | $ | 290,559 | ||||||||
Investing activities | 917,457 | (401,426 | ) | (2,515,365 | ) | ||||||||||
Financing activities | (159,929 | ) | 167,052 | 2,623,986 | |||||||||||
Effect of exchange rates changes on cash and cash equivalents, including discontinued operations cash | (181 | ) | 16,101 | 13,140 | |||||||||||
Net increase (decrease) in cash and cash equivalents including discontinued operations cash | $ | 48,986 | $ | (208,378 | ) | $ | 412,320 | ||||||||
Change in discontinued operations cash classified as current assets held for sale | 18,628 | (28,427 | ) | (24,863 | ) | ||||||||||
Net increase (decrease) in cash and cash equivalents | $ | 67,614 | $ | (236,805 | ) | $ | 387,457 | ||||||||
Ending cash and cash equivalents | $ | 785,637 | $ | 718,023 | $ | 954,828 | |||||||||
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Date | Description | |
7/7/05 | Completed the sale of substantially all of our remaining oil and gas assets for $1.05 billion, less approximately $60 million of estimated transaction fees and expenses | |
7/8/05 | Completed the sale of our 50% interest in the 175-MW Grays Ferry Power Plant for gross proceeds of $37.4 million | |
7/28/05 | Completed the sale of our 1,200-MW Saltend Energy Centre for approximately $862.9 million | |
7/29/05 | Completed the sale of our Inland Empire development project for approximately $30.9 million | |
8/2/05 | Completed the sale of our 156-MW Morris Energy Center for $84.5 million | |
10/06/05 | Complete the sale of the 561-MW Ontelaunee Energy Center for $212.3 million |
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Amounts of Commitment Expiration per Period | |||||||||||||||||||||||||||||
Total | |||||||||||||||||||||||||||||
Amounts | |||||||||||||||||||||||||||||
Commercial Commitments | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Committed | ||||||||||||||||||||||
Guarantee of subsidiary debt | $ | 24,425 | $ | 198,859 | $ | 1,592,342 | $ | 22,131 | $ | 11,040 | $ | 590,287 | $ | 2,439,084 | |||||||||||||||
Standby letters of credit | 361,104 | 8,298 | 898 | — | — | — | 370,300 | ||||||||||||||||||||||
Surety bonds | — | — | — | — | — | 11,395 | 11,395 | ||||||||||||||||||||||
Guarantee of subsidiary operating lease payments | 81,772 | 82,487 | 115,604 | 113,977 | 263,041 | 900,742 | 1,557,623 | ||||||||||||||||||||||
Total | $ | 467,301 | $ | 289,644 | $ | 1,708,844 | $ | 136,108 | $ | 274,081 | $ | 1,502,424 | $ | 4,378,402 | |||||||||||||||
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2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | |||||||||||||||||||||||||
Other contractual obligations | $ | 31,846 | $ | 7,148 | $ | 8,148 | $ | 5,880 | $ | 5,837 | $ | 45,652 | $ | 104,511 | |||||||||||||||||
Total operating lease obligations(1) | $ | 198,967 | $ | 184,284 | $ | 180,015 | $ | 174,696 | $ | 318,751 | $ | 1,122,140 | $ | 2,178,853 | |||||||||||||||||
Debt: | |||||||||||||||||||||||||||||||
Notes payable and other borrowings(3)(4) | 179,597 | 134,447 | 97,901 | 104,003 | 111,464 | 1,443 | 628,855 | ||||||||||||||||||||||||
Preferred interests(3) | 9,479 | 8,990 | 12,236 | 16,228 | 175,144 | 370,819 | 592,896 | ||||||||||||||||||||||||
Capital lease obligations(3) | 8,133 | 7,940 | 9,875 | 10,952 | 16,057 | 233,800 | 286,757 | ||||||||||||||||||||||||
CCFC (3) | 3,208 | 3,208 | 3,209 | 365,349 | — | 409,539 | 784,513 | ||||||||||||||||||||||||
CALGEN(3) | — | 44,974 | 12,050 | 829,875 | 721,083 | 830,000 | 2,437,982 | ||||||||||||||||||||||||
Construction/project financing(3)(5) | 79,594 | 100,069 | 95,502 | 99,518 | 190,630 | 1,795,712 | 2,361,025 | ||||||||||||||||||||||||
DIP Facility | — | 25,000 | — | — | — | — | 25,000 | ||||||||||||||||||||||||
Senior Notes and term loans(2) | — | — | — | — | — | 641,652 | 641,652 | ||||||||||||||||||||||||
Total debt not subject to compromise | 280,011 | 324,628 | 230,773 | 1,425,925 | 1,214,378 | 4,282,965 | 7,758,680 | ||||||||||||||||||||||||
Liabilities subject to compromise(8): | |||||||||||||||||||||||||||||||
Construction/project financing(3)(5) | — | — | — | — | — | 166,506 | 166,506 | ||||||||||||||||||||||||
Contingent Convertible Senior Notes Due 2006, 2014, 2015 and 2023(2) | — | — | — | — | — | 1,823,460 | 1,823,460 | ||||||||||||||||||||||||
Second priority senior secured Notes(2) | — | — | — | — | — | 3,671,875 | 3,671,875 | ||||||||||||||||||||||||
Unsecured senior notes(2) | — | — | — | — | — | 1,879,989 | 1,879,989 | ||||||||||||||||||||||||
Notes payable and other liabilities — related party | — | — | — | — | — | 1,078,045 | 1,078,045 | ||||||||||||||||||||||||
Provision for claims under parent guarantees | — | — | — | — | — | 5,132,349 | 5,132,349 | ||||||||||||||||||||||||
Other | — | — | — | — | — | 857,840 | 857,840 | ||||||||||||||||||||||||
Total liabilities subject to compromise | — | — | — | — | — | 14,610,064 | 14,610,064 | ||||||||||||||||||||||||
Total debt and liabilities subject to compromise(4)(8) | $ | 280,011 | $ | 324,628 | $ | 230,773 | $ | 1,425,925 | $ | 1,214,378 | $ | 18,893,029 | $ | 22,368,744 | |||||||||||||||||
Interest payments on debt not subject to compromise(8) | $ | 911,607 | $ | 737,843 | $ | 730,605 | $ | 679,207 | $ | 548,177 | $ | 1,588,891 | $ | 5,196,330 | |||||||||||||||||
Interest rate swap agreement payments | $ | 1,153 | $ | 795 | $ | 907 | $ | 677 | $ | 1,197 | $ | 1,327 | $ | 6,056 | |||||||||||||||||
Purchase obligations: | |||||||||||||||||||||||||||||||
Turbine commitments | 17,578 | 4,432 | 2,699 | — | — | — | 24,709 | ||||||||||||||||||||||||
Commodity purchase obligations(6) | 965,934 | 476,431 | 455,114 | 446,363 | 440,038 | 1,821,912 | 4,605,792 | ||||||||||||||||||||||||
Land leases | 4,394 | 4,585 | 5,122 | 5,616 | 5,744 | 361,700 | 387,161 | ||||||||||||||||||||||||
Long-term service agreements | 35,036 | 53,420 | 36,637 | 39,649 | 34,692 | 204,711 | 404,145 | ||||||||||||||||||||||||
Costs to complete construction projects | 215,213 | — | — | — | — | — | 215,213 | ||||||||||||||||||||||||
Other purchase obligations(9) | 54,624 | 32,886 | 27,190 | 26,945 | 27,559 | 446,677 | 615,881 | ||||||||||||||||||||||||
Total purchase obligations(7) | $ | 1,292,779 | $ | 571,754 | $ | 526,762 | $ | 518,573 | $ | 508,033 | $ | 2,835,000 | $ | 6,252,901 | |||||||||||||||||
(1) | Included in the total are future minimum payments for power plant operating leases, and office and equipment leases. See Note 31 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) | 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. | |
(4) | A note payable totaling $117.7 million associated with the sale of the PG&E note receivable to a third party is excluded from notes payable and other borrowings for this purpose as it is a noncash liability. If the $117.7 million is summed with the $628.9 million (total notes payable and other) from the table above, the total notes payable and other would be $746.6 million, which agrees to the sum of the current and long-term notes payable and other borrowings balances on the Consolidated Balance Sheet. See Note 14 of the Notes to Consolidated Financial Statements for more information concerning this note. Total debt not subject to compromise of $7,758.7 million from the table above summed with the $117.7 million totals $7,876.4 million, which agrees to the total debt not subject to compromise amount in Note 14 of the Notes to Consolidated Financial Statements. | |
(5) | Included in the total are guaranteed amounts of $275.1 million and $72.4 million, respectively, of project financing for the Broad River Energy Center and Pasadena Power Plant. | |
(6) | 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. | |
(7) | 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. | |
(8) | In accordance with SOP 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” and as a result of the automatic stay provisions of Chapter 11 and the uncertainty of the amount approved by the court as allowed claims, we are unable to determine the maturity date of the LSTC. Accordingly, only the total contractual amounts due related to these instruments is noted above. Also, we ceased accruing and recognizing interest expense on debt that is considered to be subject to compromise, except that being paid pursuant to the Cash Collateral Order. Consequently, interest payable does not include contractual interest due on LSTC. |
(9) | The amounts include obligations under employment agreements. They do not include success fees which are contingent on the employment status if and when a plan of reorganization is confirmed by the bankruptcy court. Also, any claim by Mr. Cartwright for severance benefits is not included in the table above and would be a pre-petition claim and processed accordingly in the Chapter 11 cases. See Item 11. “Executive Compensation — Employment Agreements, Termination of Employment and Change in Control Arrangements” for a discussion of Messrs. May, Davido and Cartwright’s employment contracts. |
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2005 | 2004 | |||||||||||||||
Principal | Amount | Principal | Amount | |||||||||||||
Debt Security and HIGH TIDES | Amount | Paid | Amount | Paid | ||||||||||||
2006 Convertible Notes | $ | — | $ | — | $ | 658.7 | $ | 657.7 | ||||||||
2023 Convertible Notes | — | — | 266.2 | 177.0 | ||||||||||||
First Priority Notes | 138.9 | 138.9 | — | — | ||||||||||||
81/4% Senior Notes Due 2005 | 4.0 | 4.0 | 38.9 | 34.9 | ||||||||||||
101/2% Senior Notes Due 2006 | 13.5 | 12.4 | 13.9 | 12.4 | ||||||||||||
75/8% Senior Notes Due 2006 | 9.4 | 8.7 | 103.1 | 96.5 | ||||||||||||
83/4% Senior Notes Due 2007 | 5.0 | 3.2 | 30.8 | 24.4 | ||||||||||||
77/8% Senior Notes Due 2008 | 53.5 | 39.6 | 78.4 | 56.5 | ||||||||||||
81/2% Senior Notes Due 2008 | 159.8 | 102.6 | 344.3 | 249.4 | ||||||||||||
83/8% Senior Notes Due 2008 | — | — | 6.1 | 4.0 | ||||||||||||
73/4% Senior Notes Due 2009 | 41.0 | 24.8 | 11.0 | 8.1 | ||||||||||||
85/8% Senior Notes Due 2010 | 86.2 | 59.1 | — | — | ||||||||||||
81/2% Senior Notes Due 2011 | 405.8 | 292.2 | 116.9 | 73.1 | ||||||||||||
$ | 917.1 | $ | 685.5 | $ | 1,668.3 | $ | 1,394.0 | |||||||||
• | During 2004 we exchanged 24.3 million shares of Calpine common stock in privately negotiated transactions for a total of approximately $115.0 million par value of HIGH TIDES I and HIGH TIDES II. | |
• | On October 20, 2004, we repaid $636 million of convertible debentures held by Trust I and Trust II, respectively, which then used those proceeds to redeem the outstanding HIGH TIDES I and II. The redemption included the $115.0 million par value HIGH TIDES I and II previously purchased and held by us and resulted in a net loss of $7.8 million, comprised of a gain of $6.1 million against a write-off of $13.9 million of unamortized deferred financing costs. | |
• | On June 28, 2005, we exchanged 27.5 million shares of Calpine common stock in privately negotiated transactions for $94.3 million in aggregate principal amount at maturity of our 2014 Convertible Notes. This resulted in a pre-tax loss of $8.3 million, comprised of a gain of $8.9 million, net of write-offs of $2.8 million unamortized deferred financing costs and $14.4 unamortized discount and legal costs. |
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• | On July 13, 2005, we repaid $517.5 million of convertible debentures held by Trust III, which then used those proceeds to redeem the outstanding HIGH TIDES III. The redemption included the $115 million of HIGH TIDES III previously purchased and held by us and resulted in a net loss of $8.5 million, comprised of a gain of $4.4 million against a write-off of $12.9 million of unamortized deferred financing costs. |
2005 | 2004 | |||||||||||||||
Common | Common | |||||||||||||||
Principal | Stock | Principal | Stock | |||||||||||||
Debt Securities and HIGH TIDES | Amount | Issued | Amount | Issued | ||||||||||||
2014 Convertible Notes | $ | 94.3 | 27.5 | $ | — | — | ||||||||||
HIGH TIDES I | — | — | 40.0 | 8.5 | ||||||||||||
HIGH TIDES II | — | — | 75.0 | 15.8 | ||||||||||||
$ | 94.3 | 27.5 | $ | 115.0 | 24.3 | |||||||||||
Calpine | |||||||||||||||||
Corporation | |||||||||||||||||
and Restricted | Unrestricted | ||||||||||||||||
Subsidiaries | Subsidiaries | Eliminations | Total | ||||||||||||||
Assets | $ | 20,184,479 | $ | 360,318 | $ | — | $ | 20,544,797 | |||||||||
Liabilities not subject to compromise | $ | 10,962,473 | $ | 204,961 | $ | — | $ | 11,167,434 | |||||||||
Liabilities subject to compromise | $ | 14,581,425 | $ | 28,639 | $ | — | $ | 14,610,064 | |||||||||
Total revenue | $ | 10,108,178 | $ | 12,822 | $ | (8,342 | ) | $ | 10,112,658 | ||||||||
Total (cost) of revenue | (12,050,108 | ) | (20,341 | ) | 12,868 | (12,057,581 | ) | ||||||||||
Equipment, development project and other impairments | (2,117,665 | ) | — | — | (2,117,665 | ) | |||||||||||
Interest income | 74,334 | 16,681 | (6,789 | ) | 84,226 | ||||||||||||
Interest (expense) | (1,384,345 | ) | (12,943 | ) | — | (1,397,288 | ) | ||||||||||
Reorganization items | (5,026,510 | ) | — | — | (5,026,510 | ) | |||||||||||
Other | 517,896 | (54,944 | ) | — | 462,952 | ||||||||||||
Net income (loss) | $ | (9,878,220 | ) | $ | (58,725 | ) | $ | (2,263 | ) | $ | (9,939,208 | ) | |||||
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2005 | ||||
Assets | $ | 21,985 | ||
Liabilities not subject to compromise | $ | 37,275 | ||
Total revenue(1) | $ | 22,575 | ||
Total cost of revenue | $ | — | ||
Interest expense | $ | 4,679 | ||
Net income (loss) | $ | 17,817 |
(1) | CNEM’s contracts are derivatives and are recorded on a netmark-to-market basis on our financial statements under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” notwithstanding that economically they are fully hedged. |
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2005 | ||||
Assets | $ | 469,305 | ||
Liabilities | $ | 581,616 | ||
Total revenue | $ | 512,405 | ||
Total cost of revenue | $ | 435,018 | ||
Interest expense | $ | 54,654 | ||
Net income (loss) | $ | 26,490 |
2005 | ||||
Assets | $ | 601,681 | ||
Liabilities | $ | 255,906 | ||
Total revenue | $ | 96,816 | ||
Total cost of revenue | $ | 35,688 | ||
Interest expense | $ | 17,735 | ||
Net income | $ | 45,614 |
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2005 | ||||
Assets | $ | 362,761 | ||
Liabilities | $ | 118,701 | ||
Liabilities subject to compromise | $ | 2,514 |
2005 | ||||
Assets | $ | 1,576 | ||
Liabilities | $ | 57,117 |
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Rocky Mountain | Riverside Energy | Calpine Riverside | ||||||||||
Energy Center, LLC | Center, LLC | Holdings, LLC | ||||||||||
2005 | 2005 | 2005 | ||||||||||
Assets | $ | 431,408 | $ | 690,554 | $ | 284,782 | ||||||
Liabilities | $ | 279,521 | $ | 421,820 | $ | — |
Calpine Fox, LLC and | ||||
Calpine Fox Holdings, LLC | ||||
2005 | ||||
Assets | $ | 429,412 | ||
Liabilities | $ | 365,985 |
2005 | ||||
Assets | $ | 560,805 | ||
Liabilities | $ | 366,032 |
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2005 | ||||
Assets | $ | 2,111,301 | ||
Liabilities | $ | 1,158,751 |
2005 | ||||
Assets | $ | 652,985 | ||
Liabilities | $ | 275,762 |
Capital Spending — Development and Construction |
Performance Metrics |
• | MWh generated. We generate power that we sell to third parties. These sales are recorded as E&S revenue. The volume in MWh is a key indicator of our level of activity. | |
• | 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 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 Btus of fuel consumed per KWh generated. We calculate the average heat rate for our gas-fired power plants (excluding peakers) by dividing (a) fuel consumed in Btu 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 down by the equivalent heat content in steam or other |
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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 E&S revenue, which includes capacity revenues, energy revenues, thermal revenues, the spread on sales of purchased electricity for hedging, balancing, and optimization activity and generating revenue recorded inmark-to-market activities, net, by (b) total generated MWh in the period. | |
• | Average cost of natural gas expressed in dollars per MMBtu 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 MMBtu 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 gas pipeline costs, which is eliminated in consolidation), the spread on sales of purchased gas for hedging, balancing, and optimization activity, and fuel expense related to generation recorded inmark-to-market activities, net by (b) the heat content in millions of Btu 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 MWh. To assess trends in electric power plant operating expense (“POX”) per MWh, we divide POX by actual MWh. |
Years Ended December 31, | ||||||||||||||
2005 | 2004 | 2003 | ||||||||||||
(In thousands) | ||||||||||||||
Operating Performance Metrics; | ||||||||||||||
MWh generated | 87,431 | 83,412 | 70,856 | |||||||||||
Average availability | 91.5 | % | 92.6 | % | 91.1 | % | ||||||||
Average baseload capacity factor: | ||||||||||||||
Average total MW in operation | 25,207 | 22,198 | 18,283 | |||||||||||
Less: Average MW of pure peakers | 2,965 | 2,951 | 2,672 | |||||||||||
Average baseload MW in operation | 22,242 | 19,247 | 15,611 | |||||||||||
Hours in the period | 8,760 | 8,784 | 8,760 | |||||||||||
Potential baseload generation (MWh) | 194,840 | 169,066 | 136,752 | |||||||||||
Actual total generation (MWh) | 87,431 | 83,412 | 70,856 | |||||||||||
Less: Actual pure peakers’ generation (MWh) | 1,893 | 1,453 | 1,290 | |||||||||||
Actual baseload generation (MWh) | 85,538 | 81,959 | 69,566 | |||||||||||
Average baseload capacity factor | 43.9 | % | 48.5 | % | 50.9 | % | ||||||||
Average heat rate for gas-fired power plants (excluding peakers)(Btu’s/ KWh): | ||||||||||||||
Not steam adjusted | 8,369 | 8,303 | 8,081 | |||||||||||
Steam adjusted | 7,187 | 7,172 | 7,335 |
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Years Ended December 31, | |||||||||||||
2005 | 2004 | 2003 | |||||||||||
(In thousands) | |||||||||||||
Average all-in realized electric price: | |||||||||||||
Electricity and steam revenue | $ | 6,278,840 | $ | 5,165,347 | $ | 4,291,173 | |||||||
Spread on sales of purchased power for hedging and optimization | 307,759 | 166,016 | 29,246 | ||||||||||
Revenue related to power generation in mark-to-market activity, net | 243,405 | — | — | ||||||||||
Adjusted electricity and steam revenue | $ | 6,830,004 | $ | 5,331,363 | $ | 4,320,419 | |||||||
MWh generated | 87,431 | 83,412 | 70,856 | ||||||||||
Average all-in realized electric price per MWh | $ | 78.12 | $ | 63.92 | $ | 60.97 | |||||||
Average cost of natural gas: | |||||||||||||
Fuel expense | $ | 4,623,286 | $ | 3,587,417 | $ | 2,636,744 | |||||||
Fuel cost elimination | 8,395 | 18,028 | 61,423 | ||||||||||
Spread on sales of purchased gas for hedging and optimization | 56,921 | (11,587 | ) | (41,334 | ) | ||||||||
Fuel expense related to power generation in mark-to-market activity, net | 189,770 | — | — | ||||||||||
Adjusted fuel expense | $ | 4,878,372 | $ | 3,593,858 | $ | 2,656,833 | |||||||
MMBtu of fuel consumed by generating plants | 592,962 | 571,869 | 484,050 | ||||||||||
Average cost of natural gas per MMBtu | $ | 8.23 | $ | 6.28 | $ | 5.49 | |||||||
MWh generated | 87,431 | 83,412 | 70,856 | ||||||||||
Average cost of adjusted fuel expense per MWh | $ | 55.80 | $ | 43.09 | $ | 37.50 | |||||||
Average spark spread: | |||||||||||||
Adjusted electricity and steam revenue | $ | 6,830,004 | $ | 5,331,363 | $ | 4,320,419 | |||||||
Less: Adjusted fuel expense | 4,878,372 | 3,593,858 | 2,656,833 | ||||||||||
Spark spread | $ | 1,951,632 | $ | 1,737,505 | $ | 1,663,586 | |||||||
MWh generated | 87,431 | 83,412 | 70,856 | ||||||||||
Average spark spread per MWh | $ | 22.32 | $ | 20.83 | $ | 23.48 | |||||||
Average plant operating expense (POX) per actual MWh: | |||||||||||||
Plant operating expense (POX) | $ | 717,393 | $ | 727,911 | $ | 599,325 | |||||||
POX per actual MWh | $ | 8.21 | $ | 8.73 | $ | 8.46 |
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Years Ended December 31, | ||||||||||||||||
2005 | 2004 | 2003 | ||||||||||||||
(In thousands) | ||||||||||||||||
Realized: | ||||||||||||||||
Power activity | ||||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | 297,893 | $ | 52,262 | $ | 52,559 | ||||||||||
Other mark-to-market activity(1) | (13,372 | ) | (12,158 | ) | (26,059 | ) | ||||||||||
Total realized power activity | $ | 284,521 | $ | 40,104 | $ | 26,500 | ||||||||||
Gas activity | ||||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | (177,752 | ) | $ | 8,025 | $ | (2,166 | ) | ||||||||
Other mark-to-market activity(1) | (286 | ) | — | — | ||||||||||||
Total realized gas activity | $ | (178,038 | ) | $ | 8,025 | $ | (2,166 | ) | ||||||||
Total realized activity: | ||||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | 120,141 | $ | 60,287 | $ | 50,393 | ||||||||||
Other mark-to-market activity(1) | (13,658 | ) | (12,158 | ) | (26,059 | ) | ||||||||||
Total realized activity | $ | 106,483 | $ | 48,129 | $ | 24,334 | ||||||||||
Unrealized: | ||||||||||||||||
Power activity | ||||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | (85,860 | ) | $ | (18,075 | ) | $ | (55,450 | ) | |||||||
Ineffectiveness related to cash flow hedges | (4,638 | ) | 1,814 | (5,001 | ) | |||||||||||
Other mark-to-market activity(1) | 6,393 | (13,591 | ) | (1,243 | ) | |||||||||||
Total unrealized power activity | $ | (84,105 | ) | $ | (29,852 | ) | $ | (61,694 | ) | |||||||
Gas activity | ||||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | (9,042 | ) | $ | (10,700 | ) | $ | 7,768 | ||||||||
Ineffectiveness related to cash flow hedges | (1,951 | ) | 5,827 | 3,153 | ||||||||||||
Other mark-to-market activity(1) | — | — | — | |||||||||||||
Total unrealized gas activity | $ | (10,993 | ) | $ | (4,873 | ) | $ | 10,921 | ||||||||
Total unrealized activity: | ||||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | (94,902 | ) | $ | (28,775 | ) | $ | (47,682 | ) | |||||||
Ineffectiveness related to cash flow hedges | (6,589 | ) | 7,641 | (1,848 | ) | |||||||||||
Other mark-to-market activity(1) | 6,393 | (13,591 | ) | (1,243 | ) | |||||||||||
Total unrealized activity | $ | (95,098 | ) | $ | (34,725 | ) | $ | (50,773 | ) | |||||||
Total mark-to-market activity: | ||||||||||||||||
“Trading Activity” as defined in EITF Issue No. 02-03 | $ | 25,239 | $ | 31,512 | $ | 2,711 | ||||||||||
Ineffectiveness related to cash flow hedges | (6,589 | ) | 7,641 | (1,848 | ) | |||||||||||
Other mark-to-market activity(1) | (7,265 | ) | (25,749 | ) | (27,302 | ) | ||||||||||
Total mark-to-market activity | $ | 11,385 | $ | 13,404 | $ | (26,439 | ) | |||||||||
(1) | Activity related to our assets but does not qualify for hedge accounting. |
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Strategy |
Financial Market Risks |
Fair value of contracts outstanding at January 1, 2005 | $ | 37,863 | ||
Cash losses recognized or otherwise settled during the period(1) | 79,265 | |||
Non-cash gains recognized or otherwise settled during the period(2) | 44,979 | |||
Changes in fair value attributable to new contracts(3) | (344,520 | ) | ||
Changes in fair value attributable to price movements | (267,112 | ) | ||
Terminated derivatives | 9,711 | |||
Fair value of contracts outstanding at December 31, 2005(4) | $ | (439,814 | ) | |
Realized cash flow from fair value hedges(5) | $ | 346,733 | ||
(1) | Realized losses from cash flow hedges andmark-to-market activity are reflected in the tables below (in millions): |
Realized value of commodity cash flow hedges reclassified from OCI(a) | $ | (384.4 | ) | ||
Net of: | |||||
Terminated and monetized derivatives | (29.2 | ) | |||
Equity method hedges | — | ||||
Hedges reclassified to discontinued operations | (199.4 | ) | |||
Cash losses realized from cash flow hedges | (155.8 | ) | |||
Realized value of mark-to-market activity(b) | 106.5 | ||||
Net of: | |||||
Non-cash realized mark-to-market activity | 30.0 | ||||
Cash gains realized on mark-to-market activity | 76.5 | ||||
Cash losses recognized or otherwise settled during the period | $ | (79.3 | ) | ||
(a) | Realized value as disclosed in Note 29 of the Notes to Consolidated Condensed Financial Statements. | |
(b) | Realized value as reported in Management’s discussion and analysis of operating performance metrics. |
(2) | This represents the non-cash amortization of deferred items embedded in our derivative assets and liabilities. |
(3) | The change attributable to new contracts includes the $284.2 million derivative liability associated with a transaction by our Deer Park facility as discussed in Note 29 of the Notes to Consolidated Condensed Financial Statements. |
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(4) | Net commodity derivative liabilities reported in Note 29 of the Notes to Consolidated Condensed Financial Statements. |
(5) | 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. |
Fair Value Source | 2006 | 2007-2008 | 2009-2010 | After 2010 | Total | ||||||||||||||||
Prices actively quoted | $ | (31,275 | ) | $ | 1,483 | $ | — | $ | — | $ | (29,792 | ) | |||||||||
Prices provided by other external sources | (206,744 | ) | (90,747 | ) | (34,418 | ) | — | (331,909 | ) | ||||||||||||
Prices based on models and other valuation methods | — | (30,707 | ) | (47,383 | ) | (23 | ) | (78,113 | ) | ||||||||||||
Total fair value | $ | (238,019 | ) | $ | (119,971 | ) | $ | (81,801 | ) | $ | (23 | ) | $ | (439,814 | ) | ||||||
Credit Quality | |||||||||||||||||||||
(Based on Standard & Poor’s Ratings as of | |||||||||||||||||||||
December 31, 2005) | 2006 | 2007-2008 | 2009-2010 | After 2010 | Total | ||||||||||||||||
Investment grade | $ | (217,717 | ) | $ | (115,588 | ) | $ | (80,475 | ) | $ | (23 | ) | $ | (413,803 | ) | ||||||
Non-investment grade | (18,324 | ) | (2,715 | ) | (1,326 | ) | — | (22,365 | ) | ||||||||||||
No external ratings | (1,978 | ) | (1,668 | ) | — | — | (3,646 | ) | |||||||||||||
Total fair value | $ | (238,019 | ) | $ | (119,971 | ) | $ | (81,801 | ) | $ | (23 | ) | $ | (439,814 | ) | ||||||
Fair Value After | ||||||||||
10% Adverse | ||||||||||
Fair Value | Price Change | |||||||||
At December 31, 2005: | ||||||||||
Electricity | $ | (628,386 | ) | $ | (760,216 | ) | ||||
Natural gas | 188,572 | 163,509 | ||||||||
Total | $ | (439,814 | ) | $ | (596,707 | ) | ||||
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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 | |||||||||||||
2007 | $ | 56,757 | 4.5 | % | 3-month US$LIBOR | $ | 451 | ||||||||||
2007 | 284,768 | 4.5 | % | 3-month US$LIBOR | 2,289 | ||||||||||||
2009 | 38,454 | 4.4 | % | 3-month US$LIBOR | 420 | ||||||||||||
2009 | 192,937 | 4.4 | % | 3-month US$LIBOR | 2,105 | ||||||||||||
2009 | 50,000 | 4.8 | % | 3-month US$LIBOR | (60 | ) | |||||||||||
2011 | 37,563 | 4.9 | % | 3-month US$LIBOR | (155 | ) | |||||||||||
2011 | 24,695 | 4.8 | % | 3-month US$LIBOR | (72 | ) | |||||||||||
2011 | 18,802 | 4.8 | % | 3-month US$LIBOR | (36 | ) | |||||||||||
2011 | 18,782 | 4.9 | % | 3-month US$LIBOR | (77 | ) | |||||||||||
2011 | 18,782 | 4.9 | % | 3-month US$LIBOR | (77 | ) | |||||||||||
2011 | 18,802 | 4.8 | % | 3-month US$LIBOR | (36 | ) | |||||||||||
2011 | 18,782 | 4.9 | % | 3-month US$LIBOR | (77 | ) | |||||||||||
2011 | 18,802 | 4.8 | % | 3-month US$LIBOR | (36 | ) | |||||||||||
2012 | 100,926 | 6.5 | % | 3-month US$LIBOR | (6,486 | ) | |||||||||||
2016 | 20,100 | 7.3 | % | 3-month US$LIBOR | (2,592 | ) | |||||||||||
Total | $ | 918,952 | 4.8 | % | $ | (4,439 | ) | ||||||||||
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Fair Value After a 1.0% | ||||
(100 Basis Points) Adverse | ||||
Net Fair Value as of December 31, 2005 | Interest Rate Change | |||
$(4,439) | $ | (38,848 | ) |
Fair Value | ||||||||||||||||||||||||||
2010 and | December 31, | |||||||||||||||||||||||||
2006 | 2007 | 2008 | 2009 | Thereafter | 2005 | |||||||||||||||||||||
3-month US $LIBOR weighted average interest rate basis(3) | ||||||||||||||||||||||||||
Riverside Energy Center project financing | $ | 3,685 | $ | 3,685 | $ | 3,685 | $ | 3,685 | $ | 340,553 | $ | 355,293 | ||||||||||||||
Rocky Mountain Energy Center project financing | 2,649 | 2,649 | 2,649 | 2,649 | 235,276 | 245,872 | ||||||||||||||||||||
Total of 3-month US $LIBOR rate debt | 6,334 | 6,334 | 6,334 | 6,334 | 575,829 | 601,165 | ||||||||||||||||||||
1-month US $LIBOR interest rate basis(3) | ||||||||||||||||||||||||||
Freeport Energy Center, LP project financing | — | 2,528 | 2,323 | 2,054 | 156,698 | 163,603 | ||||||||||||||||||||
Mankato Energy Center, LLC project financing | — | 2,222 | 2,292 | 1,969 | 144,747 | 151,230 | ||||||||||||||||||||
Total of 1-month US $LIBOR interest rate | — | 4,750 | 4,615 | 4,023 | 301,445 | 314,833 |
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Fair Value | |||||||||||||||||||||||||||
2010 and | December 31, | ||||||||||||||||||||||||||
2006 | 2007 | 2008 | 2009 | Thereafter | 2005 | ||||||||||||||||||||||
(1)(3) | |||||||||||||||||||||||||||
Metcalf Energy Center, LLC preferred interest | — | — | — | — | 155,000 | 155,000 | |||||||||||||||||||||
Third Priority Secured Floating Rate Notes Due 2011 (CalGen) | — | — | — | — | 680,000 | 680,000 | |||||||||||||||||||||
Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC) | — | — | — | — | 409,539 | 409,539 | |||||||||||||||||||||
CCFC Preferred Holdings, LLC preferred interest | — | — | — | — | 300,000 | 300,000 | |||||||||||||||||||||
Total of variable rate debt as defined at(1) below | — | — | — | — | 1,544,539 | 1,544,539 | |||||||||||||||||||||
(2)(3) | |||||||||||||||||||||||||||
Blue Spruce Energy Center project financing | 3,750 | 3,750 | 3,750 | 3,750 | 81,395 | 96,395 | |||||||||||||||||||||
Total of variable rate debt as defined at(2) below | 3,750 | 3,750 | 3,750 | 3,750 | 81,395 | 96,395 | |||||||||||||||||||||
(4)(3) | |||||||||||||||||||||||||||
First Priority Secured Floating Rate Notes Due 2009 (CalGen) | — | 1,175 | 2,350 | 231,475 | — | 235,000 | |||||||||||||||||||||
First Priority Secured Institutional Term Loans Due 2009 (CalGen) | — | 3,000 | 6,000 | 591,000 | — | 600,000 | |||||||||||||||||||||
First Priority Senior Secured Institutional Term Loan Due 2009 (CCFC) | 3,208 | 3,208 | 3,208 | 365,350 | — | 374,974 | |||||||||||||||||||||
DIP Facility | — | 25,000 | — | — | — | 25,000 | |||||||||||||||||||||
Second Priority Secured Institutional Floating Rate Notes Due 2010 (CalGen) | — | — | 3,200 | 6,400 | 623,639 | 633,239 | |||||||||||||||||||||
Second Priority Secured Term Loans Due 2010 (CalGen) | — | — | 500 | 1,000 | 97,444 | 98,944 | |||||||||||||||||||||
Metcalf Energy Center, LLC project financing | — | — | — | — | 100,000 | 100,000 | |||||||||||||||||||||
Total of variable rate debt as defined at (4) below | 3,208 | 32,383 | 15,258 | 1,195,225 | 821,083 | 2,067,157 | |||||||||||||||||||||
(5)(4) | |||||||||||||||||||||||||||
Contra Costa | 171 | 179 | 187 | 196 | 1,381 | 2,114 | |||||||||||||||||||||
Total of variable rate debt as defined at (5) below | 171 | 179 | 187 | 196 | 1,381 | 2,114 | |||||||||||||||||||||
Grand total variable-rate debt instruments | $ | 13,463 | $ | 47,396 | $ | 30,144 | $ | 1,209,528 | $ | 3,325,672 | $ | 4,626,203 | |||||||||||||||
(1) | British Bankers Association LIBOR Rate for deposit in US dollars for a period of six months. |
(2) | British Bankers Association LIBOR Rate for deposit in US dollars for a period of three months. |
(3) | Actual interest rates include a spread over the basis amount. |
(4) | Choice of1-month US $LIBOR,2-month US $LIBOR,3-month US $LIBOR,6-month US $LIBOR,12-month US $LIBOR or a base rate. |
(5) | Bankers Acceptance Rate. |
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Application of Critical Accounting Policies |
Financial Reporting Under Bankruptcy |
• | Reclassification of unsecured or under-secured pre-petition liabilities to a separate line item in the balance sheet which we have called Liabilities Subject to Compromise or LSTC; | |
• | Non-accrual of interest expense for financial reporting purposes, to the extent not paid during bankruptcy and not expected to be an allowed claim. However, unpaid contractual interest is calculated for disclosure purposes. | |
• | Adjust any unamortized deferred financing costs and discounts/premiums associated with debt classified as LSTC to reflect the expected amount of the probable allowed claim. As a result of applying this guidance, we have written off approximately $148.1 million for the year ended December 31, 2005, as a charge to reorganization items related to certain debt instruments deemed subject to compromise, in order to reflect this debt at the amount of the probable allowed claim; | |
• | Segregation of reorganization items (direct and incremental costs, such as professional fees, of being in bankruptcy) as a separate line item in the statement of operations outside of income from continuing operations; | |
• | Evaluation of actual or potential bankruptcy claims, which are not already reflected as a liability on the balance sheet, under SFAS No. 5, “Accounting for Contingencies.” Due to the close proximity of our bankruptcy filing date to our fiscal year-end date, we have been presented with only a limited number of significant claims meeting the SFAS No. 5 criteria (probable and can be reasonably estimated) to be accrued at December 31, 2005, the most significant of which we expect could total approximately $3.8 billion related to U.S. parent guarantees of our deconsolidated Canadian subsidiary debt. If valid unrecorded claims, including parent guarantees of subsidiary debt, meeting the SFAS No. 5 criteria are presented to us in future periods, we would accrue for these amounts, also at the expected amount of the allowed claim rather than at the expected settlement amount. | |
• | Disclosure of condensed combined debtor entity financial information, if the consolidated financial statements include material subsidiaries that did not file for bankruptcy protection. | |
• | Upon confirmation by the Bankruptcy Court of our plan of reorganization, and our emergence from Chapter 11 reorganization, “fresh-start reporting” must be adopted if the reorganization value of our assets immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. Essentially, the reorganization value of the entity, as mutually agreed to by thedebtor-in-possession and its creditors, would be allocated to the entity’s assets in conformity with the procedures specified by SFAS No. 141, “Business Combinations”. |
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Fair Value of Energy Marketing and Risk Management Contracts and Derivatives |
Credit Reserves |
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Liquidity Reserves |
Accounting for Commodity Contracts |
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Normal Purchases and Sales |
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), | |
• | transactions executed with the intent to profit from short-term price movements, | |
• | 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, and | |
• | 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 and Investments |
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Turbine Impairment Charges |
Capitalized Interest |
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Accounting for Income and Other Taxes |
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Variable Interest Entities and Primary Beneficiary |
Joint Venture Investments |
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Significant Long-Term Power Sales and Tolling Agreements |
Preferred Interests Issued from Wholly Owned Subsidiaries |
Operating Leases with Fixed Price Options |
Investments in Special-Purpose Entities |
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Stock-Based Compensation |
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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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• | Enhanced various tax provision processes such as effective tax rate schedules and review procedures. | |
• | Completed reviews of significant transactions for tax ramifications. | |
• | Engaged third party tax consultants to supplement our staff and to review the details of income tax calculations. |
• | Improve the processes around the underlying accounting data used for tax accounting purposes. | |
• | Integrate and centralize the fixed assets system to include both accounting and tax basis. | |
• | Add additional internal resources in the accounting department and provide additional tax accounting training for key personnel; and | |
• | Timely perform book-tax basis reconciliations on newly acquired property, plant and equipment. |
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Item 9B. | Other Information |
Item 10. | Directors and Executive Officers of the Registrant |
Name | Age | Principal Occupation | ||||
Kenneth T. Derr* | 69 | Chairman of the Board, Calpine Corporation | ||||
Robert P. May | 57 | Chief Executive Officer, Calpine Corporation | ||||
David C. Merritt* | 51 | Managing Director, Salem Partners LLC | ||||
William J. Keese* | 67 | Consultant, North American Insulation Manufacturers Association | ||||
Walter L. Revell* | 71 | Chairman and Chief Executive Officer, Revell Investments International, Inc. | ||||
George J. Stathakis | 76 | Chief Executive Officer, George J. Stathakis & Associates | ||||
Susan Wang* | 55 | Retired, Former Executive Vice President and Chief Financial Officer of Solectron Corporation |
* | Independent director as independence is defined by the listing standards of the NYSE. |
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Name | Age | Principal Occupation | ||||
Charles B. Clark, Jr. | 58 | Senior Vice President, Chief Accounting Officer and Corporate Controller | ||||
Scott J. Davido | 44 | Executive Vice President, Chief Financial Officer and Chief Restructuring Officer | ||||
Robert E. Fishman | 54 | Executive Vice President — Power Operations | ||||
Eric N. Pryor | 41 | Senior Vice President, Finance and Corporate Risk Officer |
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Director Independence |
Family Relationships — None |
Certain Legal Proceedings |
Audit Committee and Designated Audit Committee Financial Experts |
Section 16(a) Beneficial Ownership Reporting Compliance |
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Code of Ethics for Senior Financial Officers |
Stockholder Nominees to Board of Directors |
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Item 11. | Executive Compensation |
Long-Term Compensation | |||||||||||||||||||||||||
Annual Compensation(5) | Restricted | Securities | |||||||||||||||||||||||
Stock | Underlying | All Other | |||||||||||||||||||||||
Name and Principal Position | Year | Salary(6) | Bonus(7) | Awards(8) | Options(6) | Compensation(9) | |||||||||||||||||||
Robert P. May | 2005 | $ | 57,692 | $ | 2,000,000 | $ | — | — | $ | — | |||||||||||||||
Chief Executive Officer | |||||||||||||||||||||||||
Kenneth T. Derr | 2005 | 80,000 | — | — | 25,000 | — | |||||||||||||||||||
Director and Chairman of the | 2004 | 24,000 | — | — | 16,176 | — | |||||||||||||||||||
Board, and former Acting | 2003 | 29,000 | — | — | 20,922 | — | |||||||||||||||||||
Chief Executive Officer(1) | |||||||||||||||||||||||||
Peter Cartwright | 2005 | 1,595,865 | — | 1,350,002 | 1,600,500 | 137,186 | |||||||||||||||||||
Former Chairman of the Board, | 2004 | 1,000,000 | — | — | 915,090 | 119,865 | |||||||||||||||||||
President and Chief | 2003 | 1,000,000 | 2,250,000 | — | 1,018,939 | 83,782 | |||||||||||||||||||
Executive Officer(2) | |||||||||||||||||||||||||
Ann B. Curtis | 2005 | 550,000 | — | 412,500 | 350,000 | 11,298 | |||||||||||||||||||
Former Executive Vice President, | 2004 | 547,222 | 2,000 | — | 255,018 | 14,276 | |||||||||||||||||||
Vice Chairman of the Board | 2003 | 475,000 | 660,000 | — | 350,000 | 14,180 | |||||||||||||||||||
and Corporate Secretary(3) | |||||||||||||||||||||||||
Robert D. Kelly | 2005 | 682,934 | — | 1,000,001 | 500,000 | 19,083 | |||||||||||||||||||
Executive Vice President, and | 2004 | 548,162 | — | — | 288,000 | 20,045 | |||||||||||||||||||
Chief Financial Officer, | 2003 | 470,000 | 1,000,000 | — | 368,939 | 20,270 | |||||||||||||||||||
Calpine Corporation, and President, Calpine Finance Company(2) | |||||||||||||||||||||||||
E. James Macias | 2005 | 538,462 | 148 | 375,001 | 225,000 | 11,298 | |||||||||||||||||||
Senior Vice President | 2004 | 490,741 | — | — | 183,622 | 11,006 | |||||||||||||||||||
2003 | 467,308 | 560,000 | — | 250,000 | 9,905 | ||||||||||||||||||||
Thomas R. Mason | 2005 | 538,462 | — | 375,001 | 200,000 | 16,716 | |||||||||||||||||||
Executive Vice President, | 2004 | 499,074 | — | — | 144,000 | 28,044 | |||||||||||||||||||
Calpine Corporation, and | 2003 | 475,000 | 560,000 | — | 150,000 | 28,030 | |||||||||||||||||||
President, Calpine Power Company | |||||||||||||||||||||||||
Paul Posoli | 2005 | 410,141 | — | — | 200,000 | 9,537 | |||||||||||||||||||
Executive Vice President, | 2004 | 398,524 | 750,500 | — | 38,500 | 9,343 | |||||||||||||||||||
Calpine Corporation, and | 2003 | 381,231 | 800,500 | — | 38,000 | 8,983 | |||||||||||||||||||
President, Calpine Merchant Services Company, and Calpine Energy Services, L.P.(4) |
(1) | Mr. Derr served as the Company’s Interim Chief Executive Officer from November 28, 2005 — December 12, 2005. Mr. Derr was not compensated for his service as Interim Chief Executive Officer and all compensation that is disclosed was received in his role as a non-employee director. |
(2) | Mr. Cartwright’s and Mr. Kelly’s employment with the Company terminated effective November 28, 2005 and Mr. Cartwright resigned from the Board of Directors on December 20, 2005. |
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(3) | Ms. Curtis’ employment with the Company terminated and she resigned from the Board of Directors, effective January 27, 2006. |
(4) | Mr. Posoli’s employment with the Company terminated effective March 22, 2006. |
(5) | The Company does not provide any perquisites to its named executive officers. |
(6) | Salary figures for years prior to 2005 include the amount of salary deferral reflected in the following stock option grants under the Salary Investment Option Grant Program of the 1996 Stock Incentive Plan, which was frozen in December 2004 to comply with Section 409A of the Internal Revenue Code: |
Name | Year | Option Grant | Salary Deferral | |||||||||
Peter Cartwright | 2004 | 15,090 | $ | 50,000 | ||||||||
2003 | 18,939 | 50,000 | ||||||||||
Ann B. Curtis | 2004 | 3,018 | 10,000 | |||||||||
Robert D. Kelly | 2003 | 18,939 | 50,000 | |||||||||
E. James Macias | 2004 | 3,622 | 12,000 |
These stock option grants are also included in the amounts listed as Securities Underlying Options. |
(7) | In December 2005, Mr. May was paid a one-time cash signing bonus of $2,000,000 under his Employment Agreement. Bonuses for 2003 and, in the case of Mr. Posoli, 2004, were made under the Company’s Management Incentive Plan. Such annual incentives bonuses are tied to the Company’s performance as well as the performance of each executive and his or her business unit. In addition, an Employee Service Recognition bonus was paid to Ann B. Curtis in 2004 in recognition of her 20th year of service with the Company. A non-cash Employee Service Recognition bonus was paid to E. James Macias in 2005 in recognition of his 5th year of service with the Company. All Company employees are eligible to participate in the Employee Service Recognition bonus program. |
(8) | Indicates the following restricted stock grants made by the Company on March 8, 2005 under the Direct Issuance Program of the 1996 Stock Incentive Plan. The fair market value of such grants on the date of grant was $3.32 per share and such restricted stock grants were issued in consideration for past services. Such restricted stock grants have the following performance-based vesting: 50% of such restricted stock shall vest at such time as the Company’s stock price is equal to or greater than $5.00 per share for four consecutive trading days and the remaining 50% of the restricted stock shall vest at such time as the Company’s stock price is equal to or greater than $10.00 per share for four consecutive trading days. |
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(9) | For the named executive officers, this column includes the following payments by the Company. |
Term Life | |||||||||||||
Insurance | |||||||||||||
Name | Year | 401(k) | Payment | ||||||||||
Peter Cartwright | 2005 | $ | 8,400 | $ | 128,786 | ||||||||
2004 | 8,200 | 111,665 | |||||||||||
2003 | 8,000 | 75,782 | |||||||||||
Ann B. Curtis | 2005 | 8,400 | 2,898 | ||||||||||
2004 | 8,200 | 6,076 | |||||||||||
2003 | 8,000 | 6,180 | |||||||||||
Robert D. Kelly | 2005 | 8,400 | 10,683 | ||||||||||
2004 | 8,200 | 11,845 | |||||||||||
2003 | 8,000 | 12,180 | |||||||||||
E. James Macias | 2005 | 8,400 | 2,898 | ||||||||||
2004 | 8,200 | 2,806 | |||||||||||
2003 | 8,000 | 1,905 | |||||||||||
Thomas R. Mason | 2005 | 8,400 | 8,316 | ||||||||||
2004 | 8,200 | 19,844 | |||||||||||
2003 | 8,000 | 20,030 | |||||||||||
Paul Posoli | 2005 | 8,400 | 1,137 | ||||||||||
2004 | 8,200 | 1,143 | |||||||||||
2003 | 8,000 | 983 |
Stock Options |
Individual Grants(5) | ||||||||||||||||||||||||
Potential Realizable Value | ||||||||||||||||||||||||
Percentage of | at Assumed Annual Rates | |||||||||||||||||||||||
Total Options | of Stock Price Appreciation | |||||||||||||||||||||||
Options | Granted to | Exercise | for Option Term(7) | |||||||||||||||||||||
Granted | Employees in | Price per | Expiration | |||||||||||||||||||||
Name | (No. of Shares) | Fiscal Year(6) | Share | Date | 5% | 10% | ||||||||||||||||||
Robert P. May | — | — | $ | — | $ | — | $ | — | ||||||||||||||||
Peter Cartwright(1) | 350,500 | 4.39 | % | 3.32 | 3/8/2012 | 473,726 | 1,103,984 | |||||||||||||||||
Peter Cartwright(1) | 1,250,000 | (8) | 15.64 | 3.80 | 3/9/2011 | 895,153 | 2,712,701 | |||||||||||||||||
Ann B. Curtis(2) | 350,000 | 4.38 | 3.32 | 3/8/2012 | 473,051 | 1,102,409 | ||||||||||||||||||
Robert D. Kelly(1)(4) | 500,000 | 6.26 | 3.32 | 3/8/2012 | 675,787 | 1,574,870 | ||||||||||||||||||
E. James Macias | 225,000 | 2.82 | 3.32 | 3/8/2012 | 304,104 | 708,692 | ||||||||||||||||||
Thomas R. Mason | 200,000 | 2.50 | 3.32 | 3/8/2012 | 270,315 | 629,948 | ||||||||||||||||||
Paul Posoli(3) | 200,000 | 2.50 | 3.32 | 3/8/2012 | 270,315 | 629,948 |
(1) | Mr. Cartwright’s and Mr. Kelly’s employment with the Company terminated effective November 28, 2005, and Mr. Cartwright resigned from the Board of Directors on December 20, 2005. |
(2) | Ms. Curtis’ employment with the Company terminated and she resigned from the Board of Directors, effective January 27, 2006. |
(3) | Mr. Posoli’s employment with the Company terminated effective March 22, 2006. |
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(4) | Mr. Kelly’s options have terminated. |
(5) | Unless otherwise noted herein, the following applies to each option set forth in the table. Each option has a term of seven (7) years, subject to earlier termination upon the executive officer’s termination of service with the Company. Each option has an exercise price equal to the fair market value of the Common Stock on the date of grant. Each option will become exercisable for 25% of the option shares upon the officer’s completion of each additional one year of service measured from the grant date. Each option will immediately become exercisable for all of the option shares (i) upon an acquisition of the Company by merger or asset sale unless the options are assumed by the successor corporation, or (ii) upon retirement of the executive officer at least 12 months after the option grant date, if the executive officer is at least 55 years of age at retirement and if the sum of the executive officer’s age and years of service at retirement is at least 70. |
(6) | The Company granted options to purchase 7,992,710 shares of Common Stock during the fiscal year ended December 31, 2005 to employees. |
(7) | The 5% and 10% assumed annual rates of compound stock price appreciation from the exercise date are mandated by the rules of the Securities and Exchange Commission and do not represent the Company’s estimate or a projection by the Company of future stock prices. |
(8) | These options were granted pursuant to Mr. Cartwright’s employment agreement under the Discretionary Option Grant Program of the 1996 Stock Incentive Plan. The options will fully vest upon the earlier to occur of (a) the price of the Company’s common stock closing at or above $10.00 per share for four consecutive trading days or (b) December 31, 2009. The options expire on March 9, 2011. As provided by Mr. Cartwright’s employment agreement, if Mr. Cartwright is entitled to receive a severance under such agreement, all stock options shall vest and remain exercisable through their initial terms. |
Stock Option Exercises and Holdings |
Options at | Value of Unexercised | |||||||||||||||||||||||
December 31, 2005 | In-the-Money Options | |||||||||||||||||||||||
(No. of Shares) | at December 31, 2005(3) | |||||||||||||||||||||||
Shares Acquired | Value | |||||||||||||||||||||||
Name | on Exercise | Realized(2) | Exercisable | Unexercisable | Exercisable | Unexercisable | ||||||||||||||||||
Robert P. May | — | $ | — | — | — | $ | — | $ | — | |||||||||||||||
Peter Cartwright(1) | 1,289,320 | 2,810,718 | 9,435,117 | — | — | — | ||||||||||||||||||
Ann B. Curtis | — | — | 1,034,812 | 722,820 | — | — | ||||||||||||||||||
Robert D. Kelly | — | — | 1,019,072 | — | — | — | ||||||||||||||||||
E. James Macias | — | — | 241,897 | 489,828 | — | — | ||||||||||||||||||
Thomas R. Mason | — | — | 510,543 | 391,820 | — | — | ||||||||||||||||||
Paul Posoli | — | — | 131,102 | 252,875 | — | — |
(1) | Includes options to purchase 2,050,000 shares, which might be subject to accelerated vesting pursuant to Mr. Cartwright’s employment agreement, if Mr. Cartwright is entitled to severance benefits under his employment agreement. |
(2) | Based upon the market price of the purchased shares on the exercise date less the option exercise price paid for the shares. |
(3) | Based upon the closing selling price on the last trading day in the calendar year 2005 of $0.208 per share of the Common Stock on December 30, 2005, less the option exercise price payable per share. |
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Director Compensation |
Employment Agreements, Termination of Employment and Change in Control Arrangements |
Employment Contracts |
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Change in Control Arrangements |
Key Employee Program/ Severance Program/2006 Management Incentive Plan |
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Compensation Committee Interlocks and Insider Participation — None |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Total | Shares Individuals | |||||||||||||||
Number of Shares | Common Shares | Restricted Shares | Have the Right to | |||||||||||||
Beneficially | Beneficially | Subject to | Acquire Within | |||||||||||||
Name | Owned(5) | Owned(6) | Vesting(7) | 60 days(8) | ||||||||||||
Robert P. May | — | — | — | — | ||||||||||||
Peter Cartwright(1) | 12,265,901 | 2,424,157 | 406,627 | 9,435,117 | ||||||||||||
Ann B. Curtis(2) | 1,383,555 | 65,176 | 124,247 | 1,194,132 | ||||||||||||
Kenneth T. Derr | 52,393 | 5,000 | — | 47,393 | ||||||||||||
William J. Keese | — | — | — | — | ||||||||||||
Robert D. Kelly(1) | 1,019,072 | — | — | 1,019,072 | ||||||||||||
E. James Macias | 499,541 | 32,364 | 112,952 | 354,225 | ||||||||||||
Thomas R. Mason | 778,477 | 72,662 | 112,952 | 592,863 | ||||||||||||
David C. Merritt(3) | — | — | — | — | ||||||||||||
George J. Stathakis | 325,040 | 24,000 | — | 301,040 | ||||||||||||
Paul Posoli(4) | 199,065 | 44,088 | — | 154,977 | ||||||||||||
Walter L. Revell | — | — | — | — | ||||||||||||
Susan Wang | 13,500 | — | — | 13,500 | ||||||||||||
All executive officers and directors as a group (16 persons) | 17,746,100 | 2,726,539 | 946,222 | 14,073,339 |
(1) | Mr. Cartwright’s and Mr. Kelly’s employment with the Company terminated effective November 28, 2005, and Mr. Cartwright resigned from the Board of Directors on December 20, 2005. Includes options to purchase 2,050,500 shares, which might be subject to accelerated vesting pursuant to Mr. Cartwright’s employment agreement, if Mr. Cartwright is entitled to severance benefits under his employment agreement. |
(2) | Ms. Curtis’ employment with the Company terminated and she resigned from the Board of Directors effective January 27, 2006. |
(3) | Mr. Merritt joined the Board of Directors effective February 8, 2006. |
(4) | Mr. Posoli’s employment with the Company terminated effective March 22, 2006. |
(5) | Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and consists of either or both voting or investment power with respect to securities. Shares of Common Stock issuable upon the exercise of options or warrants or upon the conversion of convertible securities that are immediately exercisable or convertible or that will become exercisable or convertible within the next 60 days are deemed beneficially owned by the beneficial owner of such options, warrants or convertible securities and are deemed outstanding for the purpose of computing the percentage of |
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shares beneficially owned by the person holding such instruments, but are not deemed outstanding for the purpose of computing the percentage of any other person. Except as otherwise indicated by footnote, and subject to community property laws where applicable, the persons named in the table have reported that they have sole voting and sole investment power with respect to all shares of Common Stock shown as beneficially owned by them. The number of shares of Common Stock outstanding as of December 31, 2005 was 569,081,863. | |
(6) | Indicates shares of Calpine common stock beneficially owned. Shares indicated are included in the Total Number of Shares Beneficially Owned column. |
(7) | Indicates restricted stock grants made by the Company on March 8, 2005 under the Direct Issuance Program of the 1996 Stock Incentive Plan. The fair market value of such grants on the date of grant was $3.32 per share and such restricted stock grants were issued in consideration for past services. Such restricted stock grants have the following performance-based vesting: 50% of such restricted stock shall vest at such time as the Company’s stock price is equal to or greater than $5.00 per share for four consecutive trading days and the remaining 50% of the restricted stock shall vest at such time as the Company’s stock price is equal to or greater than $10.00 per share for four consecutive trading days. Shares indicated are included in the Total Number of Shares Beneficially Owned column. |
(8) | Indicates shares of Calpine common stock that certain directors and executive officers have the right to acquire within 60 days by exercising stock options. The numbers and values of exercisable stock options as of December 31, 2005 are shown in Item 11 above. Shares indicated are included in the Total Number of Shares Beneficially Owned column. |
Securities Authorized for Issuance Under Equity Compensation Plans |
Number of Securities | |||||||||||||
Remaining Available for | |||||||||||||
Future Issuance Under | |||||||||||||
Equity Compensation | |||||||||||||
Number of Securities | Plans (Excluding | ||||||||||||
to be Issued Upon | Weighted Average | Securities to be Issued | |||||||||||
Exercise of | Exercise Price of | Upon Exercise of | |||||||||||
Outstanding Options, | Outstanding Options, | Outstanding Options, | |||||||||||
Plan Category | Warrants and Rights | Warrants and Rights | Warrants and Rights)(1) | ||||||||||
Equity compensation plans approved by security holders | 37,090,268 | 7.62 | 30,293,714 | ||||||||||
Equity compensation plans not approved by security holders | — | — | — | ||||||||||
Total | 37,090,268 | 7.62 | 30,293,714 |
(1) | Includes 13,451,324 shares subject to issuance under the Calpine Corporation 2000 Employee Stock Purchase Plan. |
Item 13. | Certain Relationships and Related Transactions |
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Item 14. | Principal Accounting Fees and Services |
Audit Fees |
Audit-Related Fees |
Tax Fees |
All Other Fees |
Item 15. | Exhibits, Financial Statement Schedules |
Report of Independent Registered Public Accounting Firm | |
Consolidated Balance Sheets December 31, 2005 and 2004 | |
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004, and 2003 | |
Consolidated Statements of Comprehensive Income and Stockholders’ Equity (Deficit) for the Years Ended December 31, 2005, 2004, and 2003 | |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003 | |
Notes to Consolidated Financial Statements for the Years Ended December 31, 2005, 2004, and 2003 |
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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) | ||
2 | .4 | Share Sale and Purchase Agreement, made as of May 28, 2005, among the Company, Calpine UK Holdings Limited, Quintana Canada Holdings, LLC, International Power PLC, Mitsui & Co., Ltd. and Normantrail (UK CO 3) Limited. Approximately four pages of this Exhibit 2.4 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(b) | ||
2 | .5 | Purchase and Sale Agreement dated July 7, 2005, by and among Calpine Gas Holdings LLC, Calpine Fuels Corporation, the Company, Rosetta Resources Inc., and the other Subject Companies identified therein.(c) | ||
2 | .6 | Agreement dated as of December 20, 2005, by and among Steam Heat LLC, Thermal Power Company and, for certain limited purposes, Geysers Power Company, LLC.(*) | ||
3 | .1.1 | Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004.(d) | ||
3 | .1.2 | Amendment to Amended and Restated Certificate of Incorporation of the Company, dated June 20, 2005.(e) | ||
3 | .2 | Amended and Restated By-laws of the Company.(f) | ||
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.(g) | ||
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.(h) | ||
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.(i) | ||
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.(j) | ||
4 | .2.2 | Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(k) | ||
4 | .2.3 | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h) | ||
4 | .2.4 | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i) | ||
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.(l) | ||
4 | .3.2 | Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(l) | ||
4 | .3.3 | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h) | ||
4 | .3.4 | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i) | ||
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.(m) |
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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.(h) | ||
4 | .4.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i) | ||
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.(m) | ||
4 | .5.2 | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h) | ||
4 | .5.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i) | ||
4 | .6.1 | Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(n) | ||
4 | .6.2 | First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(h) | ||
4 | .6.3 | Second Supplemental Indenture dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee.(o) | ||
4 | .6.3 | Third Supplemental Indenture dated as of June 23, 2005, between the Company and Wilmington Trust Company, as Trustee.(b) | ||
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.(p) | ||
4 | .7.2 | Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(q) | ||
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.(p) | ||
4 | .8.1 | Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(p) | ||
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.(p) | ||
4 | .8.3 | Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(p) | ||
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.(p) | ||
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.(r) | ||
4 | .10 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r) | ||
4 | .11 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r) | ||
4 | .12 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r) | ||
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 FSB, as Trustee, including form of Notes.(s) | ||
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 FSB, as Trustee.(s) |
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Exhibit | ||||
Number | Description | |||
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 FSB, as Trustee.(t) | ||
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 FSB, as Trustee.(t) | ||
4 | .13.5 | Fourth Supplemental Indenture, dated as of March 15, 2006, 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 FSB, as Trustee.(*) | ||
4 | .13.6 | Waiver Agreement, dated as of March 15, 2006, 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 FSB, as Trustee.(*) | ||
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.(s) | ||
4 | .15 | Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(t) | ||
4 | .16 | Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(t) | ||
4 | .17.1 | First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t) | ||
4 | .17.2 | Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t) | ||
4 | .17.3 | Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t) | ||
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.(d) | ||
4 | .19 | Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(u) | ||
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.(v) | ||
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.(o) | ||
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.(w) | ||
4 | .21.1 | Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 14, 2005, containing terms of its 6-Year Redeemable Preferred Shares Due 2011.(*) | ||
4 | .21.2 | Consent, Acknowledgment and Amendment, dated as of March 15, 2006, among Calpine CCFC Holdings, Inc. and the Redeemable Preferred Members party thereto.(*) | ||
4 | .22 | Third Amended and Restated Limited Liability Company Operating Agreement of Metcalf Energy Center, LLC, dated as of June 20, 2005, containing terms of its 5.5-year redeemable preferred shares.(*) | ||
4 | .23 | Pass Through Certificates (Tiverton and Rumford) | ||
4 | .23.1 | 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.(h) |
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Exhibit | ||||
Number | Description | |||
4 | .23.2 | 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.(h) | ||
4 | .23.3 | Appendix A — Definitions and Rules of Interpretation.(h) | ||
4 | .23.4 | 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.(h) | ||
4 | .23.5 | 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.(h) | ||
4 | .23.6 | 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.(h) | ||
4 | .24 | Pass Through Certificates (South Point, Broad River and RockGen) | ||
4 | .24.1 | 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.(f) | ||
4 | .24.2 | 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.(f) | ||
4 | .24.3 | 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.(f) | ||
4 | .24.4 | 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.(f) | ||
4 | .24.5 | 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.(f) | ||
4 | .24.6 | 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.(f) |
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Exhibit | ||||
Number | Description | |||
4 | .24.7 | 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.(f) | ||
4 | .24.8 | 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.(f) | ||
4 | .24.9 | 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.(f) | ||
4 | .24.10 | 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.(f) | ||
4 | .24.11 | 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.(f) | ||
4 | .24.12 | 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.(f) | ||
4 | .24.13 | 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.(f) | ||
4 | .24.14 | 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.(f) | ||
4 | .24.15 | 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.(f) |
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Exhibit | ||||
Number | Description | |||
4 | .24.16 | 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.(f) | ||
4 | .24.17 | 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.(f) | ||
4 | .24.18 | 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.(f) | ||
4 | .24.19 | 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.(f) | ||
4 | .24.20 | 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.(f) | ||
4 | .24.21 | 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.(f) | ||
4 | .24.22 | 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.(f) | ||
4 | .24.23 | 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.(f) | ||
4 | .24.24 | 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.(f) | ||
4 | .24.25 | 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.(f) | ||
4 | .24.26 | 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.(f) | ||
4 | .24.27 | 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.(f) | ||
4 | .24.28 | 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.(f) |
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Exhibit | ||||
Number | Description | |||
4 | .24.29 | 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.(f) | ||
4 | .24.30 | 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.(f) | ||
4 | .24.31 | 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.(f) | ||
4 | .24.32 | 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.(f) | ||
4 | .24.33 | 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.(f) | ||
4 | .24.34 | 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.(f) | ||
4 | .24.35 | 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.(f) | ||
4 | .24.36 | 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.(f) | ||
4 | .24.37 | 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.(f) | ||
4 | .24.38 | 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.(f) | ||
10 | .1 | DIP Financing Agreements | ||
10 | .1.1.1 | $2,000,000,000 Amended & Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among the Company, as borrower, the Subsidiaries of the Company named therein, as guarantors, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Trust Company Americas, as Joint Syndication Agents, Deutsche Bank Securities Inc. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners, and Credit Suisse and Deutsche Bank Trust Company Americas, as Joint Administrative Agents.(*) |
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Exhibit | ||||
Number | Description | |||
10 | .1.1.2 | First Consent, Waiver and Amendment, dated as of May 3, 2006, to and under the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders.(*) | ||
10 | .1.2 | Amended and Restated Security and Pledge Agreement, dated as of February 23, 2006, among the Company, the Subsidiaries of the Company signatory thereto and Deutsche Bank Trust Company Americas, as collateral agent.(*) | ||
10 | .2 | Financing and Term Loan Agreements | ||
10 | .2.1 | 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.(o) | ||
10 | .2.2 | 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.(t) | ||
10 | .2.3.1 | 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.(r) | ||
10 | .2.3.2 | Amendment to Letter of Credit Agreement, dated as of September 30, 2004, between the Company and The Bank of Nova Scotia, as Administrative Agent.(y) | ||
10 | .2.4 | 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.(y) | ||
10 | .2.5 | 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.(r) | ||
10 | .2.6.1 | 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.(s) | ||
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.(s) | ||
10 | .2.6.3 | 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.(t) | ||
10 | .2.6.4 | 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.(t) | ||
10 | .2.6.5 | Amendment No. 4 to the Credit and Guarantee Agreement, dated as of March 15, 2006, 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.(*) |
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Exhibit | ||||
Number | Description | |||
10 | .2.6.6 | Waiver Agreement, dated as of March 15, 2006 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.(*) | ||
10 | .2.7 | 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.(t) | ||
10 | .2.8 | 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.(t) | ||
10 | .2.9 | 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.(z) | ||
10 | .2.10 | 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.(z) | ||
10 | .2.11 | 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.(z) | ||
10 | .3 | Security Agreements | ||
10 | .3.1 | 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.(r) | ||
10 | .3.2 | 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.(r) | ||
10 | .3.3 | 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.(r) | ||
10 | .3.4.1 | 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.(r) | ||
10 | .3.4.2 | 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.(t) | ||
10 | .3.5.1 | 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.(r) | ||
10 | .3.5.2 | 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.(t) | ||
10 | .3.6 | 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.(r) |
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Exhibit | ||||
Number | Description | |||
10 | .3.7.1 | 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.(r) | ||
10 | .3.7.2 | 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.(t) | ||
10 | .3.8 | 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.(r) | ||
10 | .3.9 | 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.(r) | ||
10 | .3.10 | 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.(r) | ||
10 | .3.11 | 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.(r) | ||
10 | .3.12 | 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.(r) | ||
10 | .3.13 | 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.(r) | ||
10 | .3.14 | 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.(r) | ||
10 | .3.15 | 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.(r) | ||
10 | .3.16 | 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.(r) | ||
10 | .3.17 | 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.(r) | ||
10 | .3.18 | 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.(r) | ||
10 | .3.19 | 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.(r) | ||
10 | .3.20 | 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.(r) |
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Exhibit | ||||
Number | Description | |||
10 | .3.21 | 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.(r) | ||
10 | .3.22 | 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.(t) | ||
10 | .4 | Power Purchase and Other Agreements. | ||
10 | .4.1 | Master Transaction Agreement, dated September 7, 2005, among the Company, Calpine Energy Services, L.P., The Bear Stearns Companies Inc., and such other parties as may become party thereto from time to time. Approximately two pages of this Exhibit 10.3.1 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(aa) | ||
10 | .4.2 | Power Purchase and Sale Agreements with the State of California Department of Water Resources comprising Amended and Restated Cover Sheet and Master Power Purchase and Sale Agreement, dated as of April 22, 2002 and effective as of May 1, 2004, between Calpine Energy Services, L.P. and the State of California Department of Water Resources together with Amended and Restated Confirmation (“Calpine 1”), Amended and Restated Confirmation (“Calpine 2”), Amended and Restated Confirmation (“Calpine 3”) and Amended and Restated Confirmation (“Calpine 4”), each dated as of April 22, 2002, and effective as of May 1, 2002, between Calpine Energy Services, L.P., and the State of California Department of Water Resources.(bb) | ||
10 | .5 | Management Contracts or Compensatory Plans or Arrangements. | ||
10 | .5.1 | Employment Agreement, effective as of January 1, 2005, between the Company and Mr. Peter Cartwright.(cc)(dd) | ||
10 | .5.2 | Employment Agreement, effective as of December 12, 2005, between the Company and Mr. Robert P. May.(*)(dd) | ||
10 | .5.3 | Employment Agreement, effective as of January 30, 2006, between the Company and Mr. Scott J. Davido.(*)(dd) | ||
10 | .5.5 | Consulting Contract, dated as of January 1, 2005, between the Company and Mr. George J. Stathakis.(hh)(dd) | ||
10 | .5.6 | Form of Indemnification Agreement for directors and officers.(gg)(dd) | ||
10 | .5.7 | Form of Indemnification Agreement for directors and officers.(f)(dd) | ||
10 | .5.8.1 | Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(t)(dd) | ||
10 | .5.8.2 | Amendment to Calpine Corporation 1996 Stock Incentive Plan.(z)(dd) | ||
10 | .5.9 | Calpine Corporation U.S. Severance Program.(*)(dd) | ||
10 | .5.10 | Base Salary, Bonus, Stock Option Grant and Restricted Stock Summary Sheet.(cc)(dd) | ||
10 | .511 | Form of Stock Option Agreement.(cc)(dd) | ||
10 | .5.12 | Form of Restricted Stock Agreement.(cc)(dd) | ||
10 | .5.13 | Calpine Corporation 2003 Management Incentive Plan.(hh)(dd) | ||
10 | .5.14 | 2000 Employee Stock Purchase Plan.(ii)(dd) | ||
12 | .1 | Statement on Computation of Ratio of Earnings to Fixed Charges.(*) | ||
21 | .1 | Subsidiaries of the Company.(*) | ||
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.(*) |
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Exhibit | ||||
Number | Description | |||
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, July 31, 2005 and December 31, 2004 and 2003.(*) |
(*) | 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 Current Report on Form 8-K filed with the SEC on June 23, 2005. |
(c) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on July 13, 2005. |
(d) | 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. |
(e) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2005, filed with the SEC on August 9, 2005. |
(f) | 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. |
(g) | 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. |
(h) | 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. |
(i) | 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. |
(j) | 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. |
(k) | 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. |
(l) | 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. |
(m) | 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. |
(n) | 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. |
(o) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 30, 2004. |
(p) | 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. |
(q) | 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. |
(r) | 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. |
(s) | 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. |
(t) | 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. |
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(u) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on October 6, 2004. |
(v) | 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. |
(w) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 23, 2005. |
(x) | 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. |
(y) | 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. |
(z) | Description of such Amendment is incorporated by reference to Item 1.01 of Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 20, 2005. |
(aa) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2005, filed with the SEC on November 9, 2005. |
(bb) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K/ A dated December 31, 2003, filed with the SEC on September 13, 2004 |
(cc) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 17, 2005. |
(dd) | Management contract or compensatory plan or arrangement. |
(ee) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on December 27, 2005. |
(ff) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on February 3, 2006. |
(gg) | 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. |
(hh) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 31, 2005. |
(ii) | 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. |
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CALPINE CORPORATION |
By: | /s/ SCOTT J. DAVIDO |
Scott J. Davido | ||
Executive Vice President, | ||
Chief Financial Officer and | ||
Chief Restructuring Officer |
Signature | Title | Date | ||||
/s/ROBERT P. MAY | Chief Executive Officer and Director (Principal Executive Officer) | May 19, 2006 | ||||
/s/SCOTT J. DAVIDO | Executive Vice President, Chief Financial Officer and Chief Restructuring Officer (Principal Financial Officer) | May 19, 2006 | ||||
/s/CHARLES B. CLARK, JR. | Senior Vice President and Corporate Controller (Principal Accounting Officer) | May 19, 2006 |
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Signature | Title | Date | ||||
/s/KENNETH T. DERR | Director | May 19, 2006 | ||||
/s/WILLIAM J. KEESE | Director | May 19, 2006 | ||||
/s/DAVID C. MERRITT | Director | May 19, 2006 | ||||
/s/WALTER L. REVELL | Director | May 19, 2006 | ||||
/s/GEORGE J. STATHAKIS | Director | May 19, 2006 | ||||
/s/SUSAN WANG | Director | May 19, 2006 |
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2005 | 2004 | |||||||||
(In thousands, except | ||||||||||
share and per share amounts) | ||||||||||
ASSETS | ||||||||||
Current assets: | ||||||||||
Cash and cash equivalents | $ | 785,637 | $ | 718,023 | ||||||
Accounts receivable, net of allowance of $12,686 and $7,317 | 1,025,886 | 1,043,061 | ||||||||
Margin deposits and other prepaid expense | 434,363 | 439,698 | ||||||||
Inventories | 150,444 | 171,639 | ||||||||
Restricted cash | 457,510 | 593,304 | ||||||||
Current derivative assets | 489,499 | 324,206 | ||||||||
Current assets held for sale | 39,542 | 142,096 | ||||||||
Other current assets | 45,156 | 131,538 | ||||||||
Total current assets | 3,428,037 | 3,563,565 | ||||||||
Restricted cash, net of current portion | 613,440 | 157,868 | ||||||||
Notes receivable, net of current portion | 165,124 | 203,680 | ||||||||
Project development costs | 24,232 | 150,179 | ||||||||
Investments | 83,620 | 373,108 | ||||||||
Deferred financing costs | 210,809 | 406,844 | ||||||||
Prepaid lease, net of current portion | 515,828 | 424,586 | ||||||||
Property, plant and equipment, net | 14,119,215 | 18,397,743 | ||||||||
Goodwill | 45,160 | 45,160 | ||||||||
Other intangible assets, net | 54,143 | 68,423 | ||||||||
Long-term derivative assets | 714,226 | 506,050 | ||||||||
Long-term assets held for sale | — | 2,260,401 | ||||||||
Other assets | 570,963 | 658,481 | ||||||||
Total assets | $ | 20,544,797 | $ | 27,216,088 | ||||||
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2005 | 2004 | |||||||||
(In thousands, except | ||||||||||
share and per share amounts) | ||||||||||
LIABILITIES & STOCKHOLDERS’ EQUITY (DEFICIT) | ||||||||||
Current liabilities: | ||||||||||
Accounts payable | $ | 399,450 | $ | 980,280 | ||||||
Accrued payroll and related expense | 29,483 | 87,659 | ||||||||
Accrued interest payable | 195,980 | 385,794 | ||||||||
Income taxes payable | 99,073 | 57,234 | ||||||||
Notes payable and other borrowings, current portion | 188,221 | 200,076 | ||||||||
Preferred interests, current portion | 9,479 | 8,641 | ||||||||
Capital lease obligations, current portion | 191,497 | 5,490 | ||||||||
CCFC financing, current portion | 784,513 | 3,208 | ||||||||
CalGen financing, current portion | 2,437,982 | — | ||||||||
Construction/project financing, current portion | 1,160,593 | 93,393 | ||||||||
Senior notes and term loans, current portion | 641,652 | 718,449 | ||||||||
Current derivative liabilities | 728,894 | 356,030 | ||||||||
Current liabilities held for sale | — | 86,458 | ||||||||
Other current liabilities | 275,595 | 302,680 | ||||||||
Total current liabilities | 7,142,412 | 3,285,392 | ||||||||
Notes payable and other borrowings, net of current portion | 558,353 | 769,490 | ||||||||
Notes payable to Calpine Capital Trusts | — | 517,500 | ||||||||
Preferred interests, net of current portion | 583,417 | 497,896 | ||||||||
Capital lease obligations, net of current portion | 95,260 | 283,429 | ||||||||
CCFC financing, net of current portion | — | 783,542 | ||||||||
CalGen financing | — | 2,395,332 | ||||||||
Construction/project financing, net of current portion | 1,200,432 | 1,905,658 | ||||||||
Convertible Senior Notes | — | 1,255,298 | ||||||||
DIP Facility | 25,000 | — | ||||||||
Senior notes, net of current portion | — | 8,532,664 | ||||||||
Deferred income taxes, net of current portion | 353,386 | 885,754 | ||||||||
Deferred revenue | 138,653 | 114,202 | ||||||||
Long-term derivative liabilities | 919,084 | 516,230 | ||||||||
Long-term liabilities held for sale | — | 176,298 | ||||||||
Other liabilities | 151,437 | 316,285 | ||||||||
Total liabilities not subject to compromise | 11,167,434 | 22,234,970 | ||||||||
Liabilities subject to compromise | 14,610,064 | — | ||||||||
Commitments and contingencies (see Note 31) | ||||||||||
Minority interests | 275,384 | 393,445 | ||||||||
Stockholders’ equity (deficit): | ||||||||||
Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and outstanding in 2005 and 2004 | — | — | ||||||||
Common stock, $.001 par value per share; authorized 2,000,000,000 shares; issued and outstanding 569,081,863 shares in 2005 and 536,509,231 shares in 2004 | 569 | 537 | ||||||||
Additional paid-in capital | 3,265,458 | 3,151,577 | ||||||||
Additional paid-in capital, loaned shares | 258,100 | 258,100 | ||||||||
Additional paid-in capital, returnable shares | (258,100 | ) | (258,100 | ) | ||||||
Retained earnings (accumulated deficit) | (8,613,160 | ) | 1,326,048 | |||||||
Accumulated other comprehensive income (loss) | (160,952 | ) | 109,511 | |||||||
Total stockholders’ equity (deficit) | (5,508,085 | ) | 4,587,673 | |||||||
Total liabilities and stockholders’ equity (deficit) | $ | 20,544,797 | $ | 27,216,088 | ||||||
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For the Years Ended December 31, | ||||||||||||||
2005 | 2004 | 2003 | ||||||||||||
(In thousands, except per share | ||||||||||||||
amounts) | ||||||||||||||
Revenue: | ||||||||||||||
Electricity and steam revenue | $ | 6,278,840 | $ | 5,165,347 | $ | 4,291,174 | ||||||||
Transmission sales revenue | 11,479 | 20,003 | 15,347 | |||||||||||
Sales of purchased power and gas for hedging and optimization | 3,667,992 | 3,376,293 | 4,033,193 | |||||||||||
Mark-to-market activities, net | 11,385 | 13,404 | (26,439 | ) | ||||||||||
Other revenue | 142,962 | 73,335 | 107,895 | |||||||||||
Total revenue | 10,112,658 | 8,648,382 | 8,421,170 | |||||||||||
Cost of revenue: | ||||||||||||||
Plant operating expense | 717,393 | 727,911 | 599,324 | |||||||||||
Royalty expense | 36,948 | 28,370 | 24,634 | |||||||||||
Transmission purchase expense | 87,598 | 74,818 | 34,690 | |||||||||||
Purchased power and gas expense for hedging and optimization | 3,417,153 | 3,198,690 | 3,962,613 | |||||||||||
Fuel expense | 4,623,286 | 3,587,416 | 2,636,744 | |||||||||||
Depreciation and amortization expense | 506,441 | 446,018 | 381,980 | |||||||||||
Operating plant impairments | 2,412,586 | — | — | |||||||||||
Operating lease expense | 104,709 | 105,886 | 112,070 | |||||||||||
Other cost of revenue | 151,467 | 99,324 | 62,288 | |||||||||||
Total cost of revenue | 12,057,581 | 8,268,433 | 7,814,343 | |||||||||||
Gross profit (loss) | (1,944,923 | ) | 379,949 | 606,827 | ||||||||||
(Income) loss from unconsolidated investments | (12,119 | ) | 14,088 | (75,724 | ) | |||||||||
Equipment, development project and other impairments | 2,117,665 | 46,894 | 67,979 | |||||||||||
Long-term service agreement cancellation charge | 34,095 | 7,735 | 16,255 | |||||||||||
Project development expense | 27,623 | 19,889 | 18,208 | |||||||||||
Research and development expense | 19,235 | 18,396 | 10,630 | |||||||||||
Sales, general and administrative expense | 239,857 | 220,567 | 204,106 | |||||||||||
Income (loss) from operations | (4,371,279 | ) | 52,380 | 365,373 | ||||||||||
Interest expense | 1,397,288 | 1,095,419 | 695,504 | |||||||||||
Distributions on trust preferred securities | — | — | 46,610 | |||||||||||
Interest (income) | (84,226 | ) | (54,766 | ) | (39,190 | ) | ||||||||
Minority interest expense | 42,454 | 34,735 | 27,330 | |||||||||||
(Income) from repurchase of various issuances of debt | (203,341 | ) | (246,949 | ) | (278,612 | ) | ||||||||
Other (income) expense, net | 72,388 | (121,062 | ) | (46,564 | ) | |||||||||
Income (loss) before reorganization items, provision (benefit) for income taxes, discontinued operations and cumulative effect of a change in accounting principle | (5,595,842 | ) | (654,997 | ) | (39,705 | ) | ||||||||
Reorganization items | 5,026,510 | — | — | |||||||||||
Income (loss) before provisions (benefit) for income taxes, discontinued operations and cumulative effect of a change in accounting principle | (10,622,352 | ) | (654,997 | ) | (39,705 | ) | ||||||||
Benefit for income taxes | (741,398 | ) | (235,314 | ) | (26,433 | ) | ||||||||
Loss before discontinued operations and cumulative effect of a change in accounting principle | (9,880,954 | ) | (419,683 | ) | (13,272 | ) | ||||||||
Discontinued operations, net of tax provision of $131,746, $8,860 and $20,513 | (58,254 | ) | 177,222 | 114,351 | ||||||||||
Cumulative effect of a change in accounting principle, net of tax provision of $ — , $ — , and $110,913 | — | — | 180,943 | |||||||||||
Net income (loss) | $ | (9,939,208 | ) | $ | (242,461 | ) | $ | 282,022 | ||||||
Basic earnings per common share: | ||||||||||||||
Weighted average shares of common stock outstanding | 463,567 | 430,775 | 390,772 | |||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (21.32 | ) | $ | (0.97 | ) | $ | (0.03 | ) | |||||
Discontinued operations, net of tax | (0.12 | ) | 0.41 | 0.29 | ||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | — | 0.46 | |||||||||||
Net income (loss) | $ | (21.44 | ) | $ | (0.56 | ) | $ | 0.72 | ||||||
Diluted earnings per common share: | ||||||||||||||
Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities | 463,567 | 430,775 | 396,219 | |||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (21.32 | ) | $ | (0.97 | ) | $ | (0.03 | ) | |||||
Discontinued operations, net of tax | (0.12 | ) | 0.41 | 0.29 | ||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | — | 0.45 | |||||||||||
Net income (loss) | $ | (21.44 | ) | $ | (0.56 | ) | $ | 0.71 | ||||||
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Accumulated Other Comprehensive | ||||||||||||||||||||||||||||||
Income (Loss) | ||||||||||||||||||||||||||||||
Net Unrealized Gain (Loss) from | ||||||||||||||||||||||||||||||
(in thousands except per share amounts) | Retained | Total | ||||||||||||||||||||||||||||
Additional | Earnings | Available- | Foreign | Stockholders’ | ||||||||||||||||||||||||||
Common | Paid-In | (Accumulated | Cash Flow | For-Sale | Currency | Equity | ||||||||||||||||||||||||
Stock | Capital | Deficit) | Hedges(1) | Investments | Translation | (Deficit) | ||||||||||||||||||||||||
Balance, January 1, 2003 | $ | 381 | $ | 2,802,503 | $ | 1,286,487 | $ | (224,414 | ) | $ | — | $ | (13,043 | ) | $ | 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 | |||||||||||||||||||||||
Total stockholders’ equity (deficit) before comprehensive income items | 4,045,180 | |||||||||||||||||||||||||||||
Net income | — | — | 282,022 | — | — | — | 282,022 | |||||||||||||||||||||||
Comprehensive pre-tax gain before reclassification adjustment | — | — | — | 112,481 | — | — | 112,481 | |||||||||||||||||||||||
Reclassification adjustment for loss included in net loss | — | — | — | 55,620 | — | — | 55,620 | |||||||||||||||||||||||
Income tax provision | — | — | — | (74,106 | ) | — | — | (74,106 | ) | |||||||||||||||||||||
Foreign currency translation gain | — | — | — | — | — | 200,056 | 200,056 | |||||||||||||||||||||||
Total comprehensive income | 576,073 | |||||||||||||||||||||||||||||
Balance, December 31, 2003 | $ | 415 | $ | 2,995,735 | $ | 1,568,509 | $ | (130,419 | ) | $ | — | $ | 187,013 | $ | 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 | ||||||||||||||||||||||||||||
Total stockholders’ equity (deficit) before comprehensive income items | 155,964 | |||||||||||||||||||||||||||||
Net loss | — | — | (242,461 | ) | — | — | — | (242,461 | ) | |||||||||||||||||||||
Comprehensive pre-tax gain (loss) before reclassification adjustment | — | — | — | (106,071 | ) | 19,239 | — | (86,832 | ) | |||||||||||||||||||||
Reclassification adjustment for (gain) loss included in net loss | — | — | — | 89,888 | (18,281 | ) | — | 71,607 | ||||||||||||||||||||||
Income tax benefit (provision) | — | — | — | 6,451 | (376 | ) | — | 6,075 | ||||||||||||||||||||||
Foreign currency translation gain | — | — | — | — | — | 62,067 | 62,067 | |||||||||||||||||||||||
Total comprehensive income | (189,544 | ) | ||||||||||||||||||||||||||||
Balance, December 31, 2004 | $ | 537 | $ | 3,151,577 | $ | 1,326,048 | $ | (140,151 | ) | $ | 582 | $ | 249,080 | $ | 4,587,673 | |||||||||||||||
Issuance of 32,572,632 shares of common stock, net of issuance costs | 32 | 97,608 | — | — | — | — | 97,640 | |||||||||||||||||||||||
Stock compensation expense | — | 16,273 | — | — | — | — | 16,273 | |||||||||||||||||||||||
Total stockholders’ equity (deficit) before comprehensive income items | 113,913 | |||||||||||||||||||||||||||||
Net loss | — | — | (9,939,208 | ) | — | — | — | (9,939,208 | ) | |||||||||||||||||||||
Comprehensive pre-tax gain (loss) before reclassification adjustment | — | — | — | (435,583 | ) | (958 | ) | — | (436,541 | ) | ||||||||||||||||||||
Reclassification adjustment for (gain) loss included in net loss | — | — | — | 405,524 | — | — | 405,524 | |||||||||||||||||||||||
Income tax benefit (provision) | — | — | — | 11,483 | 376 | — | 11,859 | |||||||||||||||||||||||
Foreign currency translation loss | — | — | — | — | — | (251,305 | ) | (251,305 | ) | |||||||||||||||||||||
Total comprehensive income | (10,209,671 | ) | ||||||||||||||||||||||||||||
Balance, December 31, 2005 | $ | 569 | $ | 3,265,458 | $ | (8,613,160 | ) | $ | (158,727 | ) | $ | — | $ | (2,225 | ) | $ | (5,508,085 | ) | ||||||||||||
(1) | Includes AOCI from cash flow hedges held by unconsolidated investees. At December 31, 2005, 2004 and 2003, these amounts were $0, $1,698 and $6,911, respectively. |
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2005 | 2004 | 2003 | ||||||||||||
(In thousands) | ||||||||||||||
Cash flows from operating activities: | ||||||||||||||
Net income (loss) | $ | (9,939,208 | ) | $ | (242,461 | ) | $ | 282,022 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||
Depreciation and amortization(1) | 760,023 | 833,375 | 732,410 | |||||||||||
Oil and gas impairments | — | 202,120 | 2,931 | |||||||||||
Operating plant impairments | 2,412,586 | — | — | |||||||||||
Equipment, development project and other impairments | 2,361,435 | 42,374 | 56,458 | |||||||||||
Deferred income taxes, net | (609,652 | ) | (226,454 | ) | 150,323 | |||||||||
Gain on sale of assets | (326,176 | ) | (349,611 | ) | (65,351 | ) | ||||||||
Foreign currency transaction loss (gain) | 53,586 | 25,122 | 33,346 | |||||||||||
Cumulative change in accounting principle | — | — | (180,943 | ) | ||||||||||
Income from repurchase of various issuances of debt | (203,341 | ) | (246,949 | ) | (278,612 | ) | ||||||||
Minority interest expense | 42,454 | 34,735 | 27,330 | |||||||||||
Change in net derivative liability | 25,035 | 14,743 | 59,490 | |||||||||||
(Income) loss from unconsolidated investments in power projects | (12,280 | ) | 9,717 | (76,704 | ) | |||||||||
Distributions from unconsolidated investments in power projects | 24,962 | 29,869 | 141,627 | |||||||||||
Stock compensation expense | 19,283 | 20,929 | 16,072 | |||||||||||
Other | 2,146 | — | — | |||||||||||
Reorganization items | 5,012,765 | — | — | |||||||||||
Change in operating assets and liabilities, net of effects of acquisitions: | ||||||||||||||
Accounts receivable | (42,437 | ) | (99,447 | ) | (221,243 | ) | ||||||||
Other current assets | (23,266 | ) | (118,790 | ) | (160,672 | ) | ||||||||
Other assets | (95,722 | ) | (95,699 | ) | (143,654 | ) | ||||||||
Accounts payable and accrued expense | (111,282 | ) | 231,827 | (111,901 | ) | |||||||||
Other liabilities | (59,272 | ) | (55,505 | ) | 27,630 | |||||||||
Net cash provided by (used in) operating activities | (708,361 | ) | 9,895 | 290,559 | ||||||||||
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2005 | 2004 | 2003 | ||||||||||||
(In thousands) | ||||||||||||||
Cash flows from investing activities: | ||||||||||||||
Purchases of property, plant and equipment | (773,988 | ) | (1,545,480 | ) | (1,886,013 | ) | ||||||||
Disposals of property, plant and equipment | 2,066,242 | 1,066,481 | 206,804 | |||||||||||
Disposal of subsidiary | — | 85,412 | — | |||||||||||
Disposal of investment | 36,900 | — | — | |||||||||||
Acquisitions, net of cash acquired | — | (187,786 | ) | (6,818 | ) | |||||||||
Advances to joint ventures | — | (8,788 | ) | (54,024 | ) | |||||||||
Sale of collateral securities | — | 93,963 | — | |||||||||||
Project development costs | (14,880 | ) | (29,308 | ) | (35,778 | ) | ||||||||
Purchases of HIGH TIDES securities | — | (110,592 | ) | — | ||||||||||
Disposal of HIGH TIDES securities | 132,500 | — | — | |||||||||||
Cash flows from derivatives not designated as hedges | 102,698 | 16,499 | 42,342 | |||||||||||
(Increase) decrease in restricted cash | (535,621 | ) | 210,762 | (766,841 | ) | |||||||||
(Increase) decrease in notes receivable | 837 | 10,235 | (21,135 | ) | ||||||||||
Cash effect of deconsolidation of Canadian Operations | (90,897 | ) | — | — | ||||||||||
Other | (6,334 | ) | (2,824 | ) | 6,098 | |||||||||
Net cash provided by (used in) investing activities | 917,457 | (401,426 | ) | (2,515,365 | ) | |||||||||
Cash flows from financing activities: | ||||||||||||||
Borrowings from notes payable and lines of credit | 6,289 | 101,781 | 1,672,871 | |||||||||||
Repayments of notes payable and lines of credit | (204,074 | ) | (256,141 | ) | (1,768,704 | ) | ||||||||
Borrowings from project financing | 750,484 | 3,743,930 | 1,548,601 | |||||||||||
Repayments of project financing | (185,775 | ) | (3,006,374 | ) | (1,638,519 | ) | ||||||||
Proceeds from issuance of Convertible Notes | 650,000 | 867,504 | 650,000 | |||||||||||
Repurchases of Convertible Senior Notes | (15 | ) | (834,765 | ) | (455,447 | ) | ||||||||
DIP facility borrowings | 25,000 | — | — | |||||||||||
Repayments and repurchases of senior notes | (880,063 | ) | (871,309 | ) | (1,139,812 | ) | ||||||||
Proceeds from issuance of senior notes | — | 878,814 | 3,892,040 | |||||||||||
Proceeds from issuance of preferred interests(2) | 865,000 | 360,000 | — | |||||||||||
Redemptions of preferred interests | (778,641 | ) | (97,095 | ) | (368 | ) | ||||||||
Repayment of Calpine Capital Trust convertible debentures | (517,500 | ) | (483,500 | ) | — | |||||||||
Proceeds from Deer Park prepaid commodity contract | 263,623 | — | — | |||||||||||
Costs of Deer Park prepaid commodity contract | (20,315 | ) | — | — | ||||||||||
Proceeds from issuance of common stock | 4 | 98 | 15,951 | |||||||||||
Proceeds from income trust offerings | — | — | 159,727 | |||||||||||
Financing costs | (96,966 | ) | (204,139 | ) | (323,167 | ) | ||||||||
Other | (36,980 | ) | (31,752 | ) | 10,813 | |||||||||
Net cash provided by (used in) financing activities | (159,929 | ) | 167,052 | 2,623,986 | ||||||||||
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2005 | 2004 | 2003 | |||||||||||
(In thousands) | |||||||||||||
Effect of exchange rate changes on cash and cash equivalents | (181 | ) | 16,101 | 13,140 | |||||||||
Net increase (decrease) in cash and cash equivalents including discontinued operations cash | 48,986 | (208,378 | ) | 412,320 | |||||||||
Change in discontinued operations cash classified as current assets held for sale | 18,628 | (28,427 | ) | (24,863 | ) | ||||||||
Net increase (decrease) in cash and cash equivalents | 67,614 | (236,805 | ) | 387,457 | |||||||||
Cash and cash equivalents, beginning of period | 718,023 | 954,828 | 567,371 | ||||||||||
Cash and cash equivalents, end of period | $ | 785,637 | $ | 718,023 | $ | 954,828 | |||||||
Cash paid during the period for: | |||||||||||||
Interest, net of amounts capitalized | $ | 1,315,538 | $ | 939,243 | $ | 462,714 | |||||||
Income taxes | $ | 26,104 | $ | 22,877 | $ | 18,415 | |||||||
Reorganization items included in operating activities | $ | 13,744 | $ | — | $ | — |
(1) | Includes depreciation and amortization that is also recorded in sales, general and administrative expense and interest expense. |
(2) | 2005 amount relates to the $260.0 million Calpine Jersey II, $155.0 million Metcalf, $150.0 million CCFC, and $300.0 million CCFC offerings of redeemable preferred securities. See Note 17 of the accompanying notes. |
• | 2005 contribution of turbines to Greenfield joint venture investment resulting in a non-cash decrease in property, plant and equipment of $62.1 million, and non-cash increases in Investments of $40.7 million and in other assets of $21.4 million. | |
• | 2005 Consolidation of our Acadia joint venture investment resulting in non-cash increases in property, plant and equipment of $478.4 million and minority interest of $275.4 million and a non-cash decrease in Investments of $203.0 million. | |
• | 2005 issuance of 27.5 million shares of Calpine common stock in exchange for $94.3 million in principal amount at maturity of 2014 Convertible Notes. | |
• | 2004 issuance of 24.3 million shares of Calpine 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 27 for more information. | |
• | 2004 acquisition of the remaining 50% interest in the Aries Power Plant for net amounts of $3.7 million cash and $220.0 million of assumed liabilities, including debt of $173.2 million. | |
• | 2003 issuance of 30 million shares of Calpine common stock in exchange for $182.5 million of debt, convertible debt and preferred securities. |
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1. | Organization and Operations of the Company |
2. | Summary of Significant Accounting Policies |
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• | Reclassification of unsecured or under-secured pre-petition liabilities to a separate line item in the balance sheet which we have called Liabilities Subject to Compromise; | |
• | Non-accrual of interest expense for financial reporting purposes, to the extent not paid during bankruptcy and not expected to be an allowable claim. However, unpaid contractual interest is calculated for disclosure purposes. | |
• | Adjust any unamortized deferred financing costs and discounts/premiums associated with debt classified as LSTC to reflect the expected amount of the probable allowed claim. As a result of applying this guidance, we have written off approximately $148.1 million for the year ended December 31, 2005, as a charge to reorganization items related to certain debt instruments deemed subject to compromise, in order to reflect this debt at the amount of the probable allowed claim; | |
• | Segregation of reorganization items (direct and incremental costs, such as professional fees, of being in bankruptcy) as a separate line item in the statement of operations outside of income from continuing operations; | |
• | Evaluation of actual or potential bankruptcy claims, which are not already reflected as a liability on the balance sheet, under SFAS No. 5, “Accounting for Contingencies.” Due to the close proximity of our bankruptcy filing date to our fiscal year-end date, we have been presented with only a limited number of significant claims meeting the SFAS No. 5 criteria (probable and can be reasonably estimated) to be accrued at December 31, 2005, the most significant of which we expect could total approximately $3.8 billion related to U.S. parent guarantees of our deconsolidated Canadian subsidiary debt. If valid unrecorded claims, including parent guarantees of subsidiary debt, meeting the SFAS No. 5 criteria are presented to us in future periods, we would accrue for these amounts, also at the expected amount of the allowed claim rather than at the expected settlement amount. | |
• | Disclosure of condensed combined debtor entity financial information, if our consolidated financial statements include material subsidiaries that did not file for bankruptcy protection. | |
• | Upon confirmation of our plan of reorganization, and our emergence from Chapter 11 reorganization, “fresh-start reporting” must be adopted if the reorganization value of our assets immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity. Essentially, the reorganization value of the entity, as mutually agreed to by thedebtor-in-possession and its creditors, would be allocated to the entity’s assets in conformity with the procedures specified by SFAS No. 141, “Business Combinations.” |
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2005 | 2004 | ||||||||||||||||||||||||
Current | Non-Current | Total | Current | Non-Current | Total | ||||||||||||||||||||
Debt service | $ | 152,512 | $ | 118,000 | $ | 270,512 | $ | 160,655 | $ | 120,106 | $ | 280,761 | |||||||||||||
Rent reserve | 50,020 | — | 50,020 | 51,632 | — | 51,632 | |||||||||||||||||||
Construction/major maintenance | 77,448 | 36,732 | 114,180 | 20,252 | 7,195 | 27,447 | |||||||||||||||||||
Proceeds from assets sales | — | 406,905 | 406,905 | — | — | — | |||||||||||||||||||
Collateralized letters of credit and other credit support | 148,959 | 9,327 | 158,286 | 329,280 | 9,140 | 338,420 | |||||||||||||||||||
Other | 28,571 | 42,476 | 71,047 | 31,485 | 21,427 | 52,912 | |||||||||||||||||||
Total | $ | 457,510 | $ | 613,440 | $ | 1,070,950 | $ | 593,304 | $ | 157,868 | $ | 751,172 | |||||||||||||
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2005 | 2004 | |||||||
PCF | $ | 178.1 | $ | 175.6 | ||||
Gilroy Energy Center, LLC | 57.0 | 53.5 | ||||||
Riverside Energy Center, LLC | 29.5 | 7.1 | ||||||
Rocky Mountain Energy Center, LLC | 25.7 | 18.1 | ||||||
Calpine Northbrook Energy Marketing, LLC | 7.3 | 6.0 | ||||||
Calpine King City Cogen, LLC | 4.8 | 6.7 | ||||||
Calpine Fox LLC | 1.0 | — | ||||||
PCF III | 0.5 | 1.5 | ||||||
Calpine Energy Management, L.P. | — | 6.9 | ||||||
Creed Energy Center, LLC | — | 0.3 | ||||||
Goose Haven Energy Center, LLC | — | 0.3 | ||||||
$ | 303.9 | $ | 276.0 | |||||
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Accounting for Commodity Contracts |
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Year Ended December 31, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Sales of purchased power for hedging and optimization | $ | 1,129,773 | $ | 1,676,003 | $ | 256,573 | ||||||
Purchased power expense for hedging and optimization | $ | 1,129,773 | $ | 1,676,003 | $ | 256,573 | ||||||
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2005 | 2004 | 2003 | ||||||||||||
Net income (loss) | ||||||||||||||
As reported | $ | (9,939,208 | ) | $ | (242,461 | ) | $ | 282,022 | ||||||
Pro Forma | (9,940,776 | ) | (247,316 | ) | 270,418 | |||||||||
Earnings (loss) per share data: | ||||||||||||||
Basic earnings (loss) per share | ||||||||||||||
As reported | $ | (21.44 | ) | $ | (0.56 | ) | $ | 0.72 | ||||||
Pro Forma | (21.44 | ) | (0.57 | ) | 0.69 | |||||||||
Diluted earnings per share | ||||||||||||||
As reported | $ | (21.44 | ) | $ | (0.56 | ) | $ | 0.71 | ||||||
Pro Forma | (21.44 | ) | (0.57 | ) | 0.68 | |||||||||
Stock-based compensation cost included in net income (loss), as reported | $ | 16,273 | $ | 12,734 | $ | 9,724 | ||||||||
Stock-based compensation cost included in net income (loss), pro forma | 17,841 | 17,589 | 21,328 |
New Accounting Pronouncements |
SFAS No. 123-R and Related FSPs |
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• | If settlement of an award creates a tax deduction that exceeds compensation cost, the additional tax benefit would be recorded as a contribution topaid-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. |
SFAS No. 128-R |
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• | normal conversion assuming a combination of cash and variable number of shares; and | |
• | conversion during events of default other than bankruptcy assuming 100% shares at the fixed conversion rate, or, in the case of 2023 Convertible Notes, meeting a put entirely with shares of stock. |
SFAS No. 151 |
SFAS No. 153 |
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SFAS No. 154 |
EITF Issue No. 03-13 |
EITF Issue No. 04-13 |
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FIN 47 |
SFAS No. 155 |
SFAS No. 156 |
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3. | Bankruptcy Proceedings |
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• | On December 21, 2005, we filed a motion with the U.S. Bankruptcy Court to reject eight PPAs and to enjoin FERC from asserting jurisdiction over the rejections. The U.S. Bankruptcy Court issued a temporary restraining order against FERC and set the matter for a hearing on January 5, 2006. Under most of the PPAs sought to be rejected, we are obligated to sell power at prices that are significantly lower than currently-prevailing market prices. At the time of filing the motion, we forecasted that it would cost us in excess of $1.2 billion if we were required to continue to perform under these PPAs rather than to sell the contracted energy at current market prices. On December 29, 2005, certain counterparties to the various PPAs filed an action in the SDNY Court arguing that the U.S. Bankruptcy Court did not have jurisdiction over the dispute. On January 5, 2006, the SDNY Court entered an order that had the effect of transferring our motion seeking to reject the eight PPAs and our related request for an injunction against FERC to the SDNY Court from the U.S. Bankruptcy Court. Earlier, however, on December 19, 2005, CDWR, a counterparty to one of the eight PPAs, had filed a complaint with FERC seeking to obtain injunctive relief to prevent us from rejecting our PPA with CDWR and contending that FERC had exclusive jurisdiction over the matter. On January 3, |
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2006, FERC determined that it did not have exclusive jurisdiction, and that the matter could be heard by the U.S. Bankruptcy Court. However, despite the FERC ruling, on January 27, 2006, the SDNY Court determined that FERC had jurisdiction over whether the contracts could be rejected. We appealed the SDNY Court’s decision to the United States Court of Appeals for the Second Circuit. The appeal was heard on April 10, 2006 and we have not yet received a decision. We can not determine at this time whether the SDNY Court, the U.S. Bankruptcy Court or FERC will ultimately determine whether we may reject any or all of the eight PPAs, or when such determination will be made. In the meantime, three of the PPAs have been terminated by the applicable counterparties, and we continue to perform under those PPAs that remain in effect. | ||
• | On February 6, 2006, we filed a notice of rejection of our leasehold interests in the Rumford power plant and the Tiverton power plant with the U.S. Bankruptcy Court, and noticed the surrender of the two plants to their owner-lessor. The owner-lessor has declined to take possession and control of the plants, which are not currently being dispatched but are being maintained in operating condition. The deadline for filing objections to the notice of rejection, which pursuant to a U.S. Bankruptcy Court order regarding expedited lease rejection procedures was originally set for February 16, 2006, was consensually extended to April 14, 2006. Both the indenture trustee related to the leaseholds and the owner-lessor filed objections to the rejection notice on that date. Additionally, the indenture trustee filed a motion to withdraw the reference of the rejection notice to the SDNY Court, arguing that the U.S. Bankruptcy Court does not have jurisdiction over the lease rejection dispute. The ISO New England, Inc. has separately filed a motion to withdraw the reference of the rejection notice to the SDNY Court on similar grounds. A hearing is currently scheduled for May 24, 2006 before the U.S. Bankruptcy Court to determine whether or not to approve the rejection and any other matters raised by the objections. However, such hearing date is subject to change. The Rumford and Tiverton power plants represent a combined 530 MW of installed capacity with the output sold into the New England wholesale market. | |
• | In February 2006, we filed notices of rejection with the U.S. Bankruptcy Court relating to our office leases in Portland, Oregon and in Deer Park, Texas. In March 2006, we filed notices of rejection relating to our office leases in Denver and Fort Collins, Colorado and in Tampa, Florida. In April 2006, we filed a notice of rejection relating to our office lease in Atlanta, Georgia. The rejection of each of the foregoing leases has been approved by the U.S. Bankruptcy Court. We anticipate that it is more likely than not that we will file further notices of rejection with respect to additional office leases; in particular, we announced in April 2006 that we intend to close our Dublin, California and Boston, Massachusetts offices. |
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4. | Calpine Debtors Condensed Combined Financial Statements |
Debtors | ||||||
(In billions) | ||||||
Assets: | ||||||
Current assets | $ | 5.5 | ||||
Restricted cash, net of current portion | .5 | |||||
Investments | 2.1 | |||||
Property, plant and equipment, net | 7.7 | |||||
Other assets | 1.6 | |||||
Total assets | $ | 17.4 | ||||
Liabilities not subject to compromise: | ||||||
Current liabilities | $ | 4.9 | ||||
Long-term debt | .2 | |||||
Long-term derivative liabilities | .7 | |||||
Other liabilities | .2 | |||||
Liabilities subject to compromise | 16.7 | |||||
Minority interest | .3 | |||||
Stockholders’ equity (deficit) | (5.6 | ) | ||||
Total liabilities and stockholders’ equity (deficit) | $ | 17.4 | ||||
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Debtors | ||||||
(In billions) | ||||||
Total revenue | $ | 11.6 | ||||
Total cost of revenue | 14.3 | |||||
Operating expenses | 2.2 | |||||
Loss from operations | (4.9 | ) | ||||
Interest expense | 1.0 | |||||
Other (income) expense, net | (.1 | ) | ||||
Reorganization items, net | 5.0 | |||||
Benefit for income taxes | .8 | |||||
Income (loss) from continuing operations before discontinued operations | (10.0 | ) | ||||
Income from discontinued operations, net of tax | .1 | |||||
Net income (loss) | $ | (9.9 | ) | |||
U.S. | |||||
Debtors | |||||
(In millions) | |||||
Net cash provided by (used in): | |||||
Operating | $ | (1,520.3 | ) | ||
Investing activities | 2,113.1 | ||||
Financing activities | (630.7 | ) | |||
Effect of exchange rate changes on cash and cash equivalents | (.1 | ) | |||
Net (decrease) increase in cash and cash equivalents | (38.0 | ) | |||
Cash and cash equivalents, beginning of year | 481.9 | ||||
Cash and cash equivalents, end of year | $ | 443.9 | |||
Cash paid for reorganization items included in operating activities | $ | 13.8 | |||
Basis of Presentation |
Interest Expense |
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Reorganization Items |
December 31, 2005 | |||||
Provision for allowable claims | $ | 3,791.5 | |||
Impairment of investment in Canadian subsidiaries | 879.1 | ||||
Write-off of unamortized deferred financing costs and debt discounts | 148.1 | ||||
Loss on terminated contracts, net | 139.4 | ||||
Professional fees | 36.4 | ||||
Other reorganization items | 32.0 | ||||
Total reorganization items | $ | 5,026.5 | |||
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5. | Available-for-Sale Debt Securities |
HIGH TIDES |
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6. | Impairments |
• | Restrictions on us and our subsidiaries that arise from our December 20, 2005, bankruptcy filings, including the need to obtain support or approvals from the Bankruptcy Courts, creditors’ committees and DIP Facility lenders to execute certain of our key business decisions; | |
• | Our current status as a Chapter 11 debtor, current credit constraints and focus on reorganizing and emerging from bankruptcy have made us less likely to commit to expending additional capital in the foreseeable future for certain of our development and construction projects; | |
• | Near-term action to sell or abandon operating plants that currently have significant negative cash flow is more likely as part of our reorganization and restructuring process; | |
• | Debt covenant restrictions, including under the DIP Facility, and recent court rulings restrict or prevent the use of proceeds from the sale of assets, or use of cash from operations, for development and construction projects; | |
• | Among other things, our bankruptcy filings and related credit constraints make it much more difficult to secure long-term PPAs with electrical utilities or other customers that would have made it possible to finance the construction of projects or allow merchant power plants with current negative cash flow (until spot market prices and spark spreads recover) to become profitable. For example, because credit support is required by prospective long-term PPA customers due to our financial condition and bankruptcy filings, it has become increasingly difficult for us to enter into PPAs; | |
• | Our access to capital on attractive terms for development projects has been reduced; and | |
• | Historically high and very volatile natural gas prices in recent times have made many customers hesitant to commit to long-term base load PPAs for gas-fired electrical generation. |
Book Value | |||||||||||||
before | Impairment | New Cost | |||||||||||
Project Description | Impairment | Charge | Basis | ||||||||||
Operating plants | $ | 3,182,392 | $ | (2,412,586 | ) | $ | 769,806 | ||||||
Development and construction projects and assets | $ | 3,314,418 | $ | (1,957,498 | ) | $ | 1,356,920 | ||||||
Joint venture investments | 238,297 | (134,469 | ) | 103,828 | |||||||||
Notes receivable | 38,644 | (25,698 | ) | 12,946 | |||||||||
Total non-operating project impairment charges | 3,591,359 | (2,117,665 | ) | 1,473,694 | |||||||||
Total | $ | 6,773,751 | $ | (4,530,251 | ) | $ | 2,243,500 | ||||||
Operating Plants |
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Development and Construction Projects and Assets |
Joint Venture Investments |
Carrying Value | Carrying Value | ||||||||||||
before | after | ||||||||||||
Project Description | Impairment | Impairments | Impairment | ||||||||||
Greenfield LP(1) | $ | 154,060 | $ | (93,132 | ) | $ | 60,928 | ||||||
Valladolid | 84,237 | (41,337 | ) | 42,900 | |||||||||
Total joint venture investments | $ | 238,297 | $ | (134,469 | ) | $ | 103,828 | ||||||
(1) | At December 31, 2005, our investment in Greenfield LP was approximately $40.7 million, representing the fair value of the turbines of approximately $60.9 million less a receivable from the joint venture of |
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approximately $20.2 million which we treated as a return of capital. See Note 10 for a discussion of this investment. |
Notes receivable impairments |
7. | Property, Plant and Equipment, Net, and Capitalized Interest |
2005 | 2004 | |||||||
Buildings, machinery, and equipment | $ | 14,023,358 | $ | 14,615,907 | ||||
Oil and gas pipelines | 106,752 | 90,625 | ||||||
Geothermal properties | 480,149 | 474,869 | ||||||
Other | 178,145 | 206,049 | ||||||
14,788,404 | 15,387,450 | |||||||
Less: Accumulated depreciation | (1,872,989 | ) | (1,416,586 | ) | ||||
12,915,415 | 13,970,864 | |||||||
Land | 92,595 | 104,972 | ||||||
Construction in progress | 1,111,205 | 4,321,907 | ||||||
Property, plant and equipment, net | $ | 14,119,215 | $ | 18,397,743 | ||||
Buildings, Machinery and Equipment |
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Oil and Gas Pipelines |
Geothermal Properties |
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Other |
Construction in Progress |
Capital Spending — Development and Construction |
Equipment | Project | |||||||||||||||||||
# of | Included in | Development | Unassigned | |||||||||||||||||
Projects | CIP | CIP | Costs | Equipment | ||||||||||||||||
Projects in active construction(1) | 4 | $ | 662,952 | $ | 247,916 | $ | — | $ | — | |||||||||||
Projects in suspended construction | 3 | 265,416 | 167,447 | — | — | |||||||||||||||
Projects in suspended development | 6 | 167,859 | 167,800 | 24,232 | — | |||||||||||||||
Other capital projects | NA | 14,978 | — | — | — | |||||||||||||||
Unassigned equipment | NA | — | — | — | 137,760 | |||||||||||||||
Total construction and development costs | $ | 1,111,205 | $ | 583,163 | $ | 24,232 | $ | 137,760 | ||||||||||||
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(1) | There were a total of four consolidated projects in active construction at December 31, 2005. Additionally, we had two projects in active construction that are recorded in unconsolidated investments and are not included in the table above. |
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Asset Retirement Obligations |
Total | |||||
Asset retirement obligation at January 1, 2004 | $ | 23,551 | |||
Liabilities incurred | 3,492 | ||||
Liabilities settled | (324 | ) | |||
Accretion expense | 5,174 | ||||
Revisions in the estimated cash flows | — | ||||
Other (primarily foreign currency translation) | (1,897 | ) | |||
Asset retirement obligation at December 31, 2004 | $ | 29,996 | |||
Liabilities incurred | 156 | ||||
Liabilities settled | — | ||||
Accretion expense | 3,634 | ||||
Revisions in the estimated cash flows | (129 | ) | |||
Other (primarily Canadian and other foreign subsidiaries deconsolidation) | (846 | ) | |||
Asset retirement obligation at December 31, 2005 | $ | 32,811 | |||
8. | Goodwill and Other Intangible Assets |
Weighted | As of December 31, 2005 | As of December 31, 2004 | |||||||||||||||||||
Average | |||||||||||||||||||||
Useful Life/ | Carrying | Accumulated | Carrying | Accumulated | |||||||||||||||||
Contract Life | Amount(1) | Amortization(1) | Amount(1) | Amortization(1) | |||||||||||||||||
Patents | 5 | $ | — | $ | — | $ | 485 | $ | (417 | ) | |||||||||||
Power purchase agreements | 23 | 85,099 | (46,237 | ) | 85,099 | (43,115 | ) | ||||||||||||||
Fuel supply and fuel management contracts | 23 | 5,000 | (2,039 | ) | 5,000 | (1,826 | ) | ||||||||||||||
Geothermal lease rights(2) | 20 | 8,108 | (650 | ) | 19,518 | (550 | ) | ||||||||||||||
Other | 15 | 5,887 | (1,025 | ) | 4,755 | (526 | ) | ||||||||||||||
Total | $ | 104,094 | $ | (49,951 | ) | $ | 114,857 | $ | (46,434 | ) | |||||||||||
(1) | Fully amortized intangible assets are not included. |
(2) | Geothermal lease rights relate to undeveloped properties at The Geysers. Certain of these properties were no longer probable of development, and we recorded an impairment charge of approximately $11.4 mil- |
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lion in the period ended December 31, 2005. This charge is reflected in the “Equipment, development project and other impairments” line item of the Consolidated Statements of Operations. See Note 6 for more information regarding the impairment of our development projects. |
9. | Acquisitions |
2004 Acquisitions |
Calpine Cogeneration Company Transaction |
Aries Transaction |
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Debit/ (Credit) | ||||
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 |
2003 Acquisitions |
Thomassen Turbine Systems Transaction |
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2004 | 2003 | |||||||
(in thousands, except per | ||||||||
share amounts) | ||||||||
Total revenue | $ | 8,938,746 | $ | 8,714,609 | ||||
Income (loss) before discontinued operations and cumulative effect of accounting changes | $ | (485,746 | ) | $ | (62,163 | ) | ||
Net income (loss) | $ | (250,176 | ) | $ | 266,743 | |||
Net income (loss) per basic share | $ | (0.58 | ) | $ | 0.68 | |||
Net income (loss) per diluted share | $ | (0.58 | ) | $ | 0.67 |
10. | Investments |
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Ownership | Investment Balance at | ||||||||||||
Interest as of | December 31, | ||||||||||||
December 31, | |||||||||||||
2005 | 2005 | 2004 | |||||||||||
Valladolid III Energy Center(1) | 45.0 | % | $ | 42,900 | $ | 77,401 | |||||||
Greenfield Energy Centre(2) | 50.0 | % | 40,698 | — | |||||||||
Androscoggin Energy Center(3) | 32.3 | % | — | — | |||||||||
Whitby Cogeneration(3) | 50.0 | % | — | 32,528 | |||||||||
Other Canadian and other foreign subsidiaries(3) | 100.0 | % | — | — | |||||||||
Grays Ferry Power Plant(4) | 50.0 | % | — | 48,558 | |||||||||
Acadia Energy Center(5) | 50.0 | % | — | 214,501 | |||||||||
Other | — | 22 | 120 | ||||||||||
Total investments in power projects | $ | 83,620 | $ | 373,108 | |||||||||
(1) | Subsequent to December 31, 2005, we sold our 45% interest in Valladolid to Mitsui and Chubu. See Notes 6 and 34 for more information. |
(2) | In addition to our investment in Greenfield LP, as of December 31, 2005 we had a receivable from Mitsui of approximately $20.2 million. |
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(3) | These investments were fully impaired at December 31, 2005. Also, the investment in Androscoggin Energy Center excludes certain Notes Receivable. See Note 10 for more information on such notes receivable. |
(4) | On July 8, 2005, we completed the sale of the Grays Ferry Power Plant, in which we held a 50% interest, for gross proceeds of $37.4 million. In June 2005, we recorded to the “Other expense (income), net” line of the Consolidated Condensed Statement of Operations an $18.5 million impairment charge. This transaction did not qualify as a discontinued operation under the guidance of SFAS No. 144, which specifically excludes equity method investments from its scope, unless the investment is part of a larger disposal group. |
(5) | As discussed above, this investment is consolidated into our financial statements as of December 31, 2005. |
Income (Loss) from Unconsolidated | |||||||||||||||||||||||||
Investments in Power Projects | Distributions | ||||||||||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||||||||||
2005 | 2004 | 2003 | 2005 | 2004 | 2003 | ||||||||||||||||||||
Valladolid III Energy Center | $ | (213 | ) | $ | 76 | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Androscoggin Energy Center | — | (23,566 | ) | (7,478 | ) | — | — | — | |||||||||||||||||
Whitby Cogeneration | 2,234 | 1,433 | 303 | 4,533 | 1,499 | — | |||||||||||||||||||
Grays Ferry Power Plant | (739 | ) | (2,761 | ) | (1,380 | ) | — | — | — | ||||||||||||||||
Acadia Energy Center | 10,872 | 14,142 | 75,272 | 20,231 | 21,394 | 136,977 | |||||||||||||||||||
Aries Power Plant(1) | — | (4,264 | ) | (3,442 | ) | — | — | — | |||||||||||||||||
Calpine Natural Gas Trust(2) | — | — | — | — | 6,127 | 1,959 | |||||||||||||||||||
Gordonsville Power Plant(3) | — | — | 11,985 | — | — | 2,672 | |||||||||||||||||||
Other | (35 | ) | 12 | (1 | ) | 198 | 849 | 19 | |||||||||||||||||
Total | $ | 12,119 | $ | (14,928 | ) | $ | 75,259 | $ | 24,962 | $ | 29,869 | $ | 141,627 | ||||||||||||
Interest income on loans to power projects(4) | $ | — | $ | 840 | $ | 465 | |||||||||||||||||||
Total | $ | 12,119 | $ | (14,088 | ) | $ | 75,724 | ||||||||||||||||||
(1) | On March 26, 2004, we acquired the remaining 50% interest in the Aries Power Plant. See Note 9 for a discussion of the acquisition. |
(2) | On September 2, 2004, we completed the sale of our equity investment in CNGT. See Note 13 for more information on the 2004 sale of the Canadian natural gas reserves and petroleum assets. |
(3) | On November 26, 2003, we completed the sale of our 50% interest in the Gordonsville Power Plant. Under the terms of the transaction, we received $36.2 million in cash for our $25.4 million investment and recorded a pre-tax gain of $7.1 million. |
(4) | At December 31, 2005 and 2004, loans to power projects represented an outstanding loan to our 32.3% owned investment, AELLC, in the amount of $4.0, million after impairment charges and reserves. |
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December 31, | ||||||||||||||
2005 | 2004 | 2003 | ||||||||||||
Condensed statements of operations: | ||||||||||||||
Revenue | $ | 171,065 | $ | 237,983 | $ | 416,506 | ||||||||
Gross profit(1) | 112,551 | 45,994 | 147,247 | |||||||||||
Income (loss) from continuing operations before extraordinary items and cumulative effect of a change in accounting principle | (30,930 | ) | (9,230 | ) | 174,730 | |||||||||
Net income (loss) | (30,930 | ) | (9,230 | ) | 174,730 | |||||||||
Condensed balance sheets: | ||||||||||||||
Current assets | $ | 101,538 | $ | 67,022 | ||||||||||
Non-current assets | 456,201 | 897,574 | ||||||||||||
Total assets | $ | 557,739 | $ | 964,596 | ||||||||||
Current liabilities | $ | 199,468 | $ | 150,716 | ||||||||||
Non-current liabilities | 226,680 | 114,597 | ||||||||||||
Total liabilities | $ | 426,148 | $ | 265,313 | ||||||||||
(1) | The 2005 gross profit primarily consists of revenue AELLC received from the April 2005 sale of fixed price gas contracts as explained above. |
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December 31, | ||||||
2005 | ||||||
Condensed statements of operations: | ||||||
Revenue | $ | 12,453 | ||||
Gross profit | (1,355 | ) | ||||
Loss from continuing operations before extraordinary items and cumulative effect of a change in accounting principle | (55,898 | ) | ||||
Net loss | (55,898 | ) | ||||
Condensed balance sheets: | ||||||
Current assets | $ | 250,969 | ||||
Non-current assets | 571,288 | |||||
Total assets | $ | 822,257 | ||||
Current liabilities | $ | 122,962 | ||||
Non-current liabilities | 41,587 | |||||
Total liabilities not subject to compromise | $ | 164,549 | ||||
Liabilities subject to compromise | $ | 2,171,893 | ||||
Related-Party Transactions with Unconsolidated Investments |
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As of December 31, | 2005 | 2004 | ||||||
Accounts receivable | $ | 5,073 | $ | 765 | ||||
Note receivable | 4,037 | 4,037 | ||||||
Other receivables | 641 | — | ||||||
Accounts payable | 352 | 9,489 | ||||||
Other current liabilities | 24,645 | — | ||||||
Liabilities subject to compromise | 6,193,798 | — |
For the Years Ended December 31, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Revenue | $ | 4,814 | $ | 1,241 | $ | 3,493 | ||||||
Cost of revenue | 79,248 | 115,008 | 82,205 | |||||||||
Interest expense | 58 | — | — | |||||||||
Interest income | — | 840 | 1,117 | |||||||||
Gain on sale of assets | — | 6,240 | 62,176 | |||||||||
Reorganization items | 4,654,202 | — | — |
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11. | Notes Receivable and Other Receivables |
2005 | 2004 | |||||||||
PG&E (Gilroy) note | $ | 135,045 | $ | 145,853 | ||||||
Panda note | 12,946 | 38,644 | ||||||||
Eastman note | 19,413 | 19,748 | ||||||||
Androscoggin note | 4,037 | 4,037 | ||||||||
Other | 6,419 | 7,168 | ||||||||
Total notes receivable | 177,860 | 215,450 | ||||||||
Less: Notes receivable, current portion included in other current assets | (12,736 | ) | (11,770 | ) | ||||||
Notes receivable, net of current portion | $ | 165,124 | $ | 203,680 | ||||||
Gilroy Note |
Panda Note |
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Eastman Note |
Androscoggin Note |
12. | Canadian Power and Gas Trusts |
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13. | Discontinued Operations |
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Oil and Gas Production and Marketing |
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Net Proved Reserve Summary — Unaudited |
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Unaudited | ||||||
(Bcfe)(1) equivalents(4): | ||||||
Net proved reserves at December 31, 2002 | 978 | |||||
Net proved reserves at December 31, 2003 | 821 | |||||
Net proved reserves at December 31, 2004 | 389 | |||||
Net proved developed reserves: | ||||||
Natural gas (Bcf)(1) | ||||||
December 31, 2002 | 640 | |||||
December 31, 2003 | 545 | |||||
December 31, 2004 | 256 | |||||
Natural gas liquids and crude oil (MBbl)(2)(3) | ||||||
December 31, 2002 | 14,132 | |||||
December 31, 2003 | 8,690 | |||||
December 31, 2004 | 1,402 | |||||
Bcf(1) equivalents(4) | ||||||
December 31, 2002 | 725 | |||||
December 31, 2003 | 596 | |||||
December 31, 2004 | 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 — Unaudited |
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Unaudited | |||||
(in millions) | |||||
December 31, 2004: | |||||
Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves | $ | 653 | |||
December 31, 2003: | |||||
Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves | $ | 1,341 | |||
December 31, 2002: | |||||
Standardized measure of discounted future net cash flows relating to proved gas, natural gas liquids and crude oil reserves | $ | 1,259 |
Electric Generation and Marketing |
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Other |
Summary |
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December 31, 2004 | ||||||||||||||
Electric | Oil and Gas | |||||||||||||
Generation | Production | |||||||||||||
and Marketing | and Marketing | Total | ||||||||||||
Assets | ||||||||||||||
Cash and cash equivalents | $ | 65,405 | $ | — | $ | 65,405 | ||||||||
Accounts receivable, net | 54,095 | — | 54,095 | |||||||||||
Inventories | 7,756 | — | 7,756 | |||||||||||
Prepaid expenses | 14,840 | — | 14,840 | |||||||||||
Total current assets held for sale | 142,096 | — | 142,096 | |||||||||||
Property, plant and equipment | 1,632,131 | 606,520 | 2,238,651 | |||||||||||
Other assets | 20,826 | 924 | 21,750 | |||||||||||
Total long-term assets held for sale | $ | 1,652,957 | $ | 607,444 | $ | 2,260,401 | ||||||||
Liabilities | ||||||||||||||
Accounts payable | $ | 34,070 | $ | — | $ | 34,070 | ||||||||
Current derivative liabilities | 8,935 | — | 8,935 | |||||||||||
Other current liabilities | 42,187 | 1,266 | 43,453 | |||||||||||
Total current liabilities held for sale | 85,192 | 1,266 | 86,458 | |||||||||||
Deferred income taxes, net of current portion | 135,985 | — | 135,985 | |||||||||||
Long-term derivative liabilities | 10,367 | — | 10,367 | |||||||||||
Other liabilities | 21,562 | 8,384 | 29,946 | |||||||||||
Total long-term liabilities held for sale | $ | 167,914 | $ | 8,384 | $ | 176,298 | ||||||||
2005 | ||||||||||||||||
Electric | Oil and Gas | |||||||||||||||
Generation | Production | |||||||||||||||
and Marketing | and Marketing | Other | Total | |||||||||||||
Total revenue | $ | 369,796 | $ | 25,129 | $ | — | $ | 394,925 | ||||||||
Gain on disposal before taxes | $ | 21,537 | $ | 336,894 | $ | — | $ | 358,431 | ||||||||
Operating income (loss) from discontinued operations before taxes | (318,499 | ) | 33,560 | — | (284,939 | ) | ||||||||||
Income from discontinued operations before taxes | $ | (296,962 | ) | $ | 370,454 | $ | $ | 73,492 | ||||||||
Income tax provision (benefit) | $ | (9,027 | ) | $ | 140,773 | $ | $ | 131,746 | ||||||||
(Loss) from discontinued operations, net of tax | $ | (287,935 | ) | $ | 229,681 | $ | $ | (58,254 | ) | |||||||
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2004 | ||||||||||||||||
Electric | Oil and Gas | |||||||||||||||
Generation | Production | |||||||||||||||
and Marketing | and Marketing | Other | Total | |||||||||||||
Total revenue | $ | 525,177 | $ | 91,421 | $ | $ | 616,598 | |||||||||
Gain on disposal before taxes | $ | 35,327 | $ | 208,172 | $ | $ | 243,499 | |||||||||
Operating income (loss) from discontinued operations before taxes | 41,607 | (99,024 | ) | (57,417 | ) | |||||||||||
Income from discontinued operations before taxes | $ | 76,934 | $ | 109,148 | $ | $ | 186,082 | |||||||||
Income tax provision (benefit) | $ | 14,066 | $ | (5,206 | ) | $ | $ | 8,860 | ||||||||
Income from discontinued operations, net of tax | $ | 62,868 | $ | 114,354 | $ | $ | 177,222 | |||||||||
2003 | ||||||||||||||||
Electric | Oil and Gas | |||||||||||||||
Generation | Production | |||||||||||||||
and Marketing | and Marketing | Other | Total | |||||||||||||
Total revenue | $ | 466,074 | $ | 106,412 | $ | 3,748 | $ | 576,234 | ||||||||
Loss on disposal before taxes | $ | — | $ | (235 | ) | $ | (11,571 | ) | $ | (11,806 | ) | |||||
Operating income (loss) from discontinued operations before taxes | (16,738 | ) | 170,326 | (6,918 | ) | 146,670 | ||||||||||
Income (loss) from discontinued operations before taxes | $ | (16,738 | ) | $ | 170,091 | $ | (18,489 | ) | $ | 134,864 | ||||||
Income tax provision (benefit) | 1,038 | 26,501 | (7,026 | ) | 20,513 | |||||||||||
Income from discontinued operations, net of tax | $ | (17,776 | ) | $ | 143,590 | $ | (11,463 | ) | $ | 114,351 | ||||||
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(in thousands) | ||||||||||||||
Interest Expense Allocation | 2005 | 2004 | 2003 | |||||||||||
Electric generation and marketing | ||||||||||||||
Saltend Energy Centre | $ | 45,080 | $ | 14,613 | $ | 7,203 | ||||||||
Ontelaunee Energy Center | 12,264 | 13,304 | 11,724 | |||||||||||
Morris Energy Center and Lost Pines | 3,662 | 7,295 | 8,563 | |||||||||||
Total | $ | 61,006 | $ | 35,212 | $ | 27,490 | ||||||||
Oil and gas production and marketing | ||||||||||||||
Canadian and Rockies | $ | — | $ | 17,893 | $ | 19,797 | ||||||||
Remaining oil and gas assets | 10,295 | 8,518 | 3,426 | |||||||||||
Total | $ | 10,295 | $ | 26,411 | $ | 23,223 | ||||||||
14. | Debt |
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(in thousands) | ||||||||||||
December 31, 2005 | ||||||||||||
Current | Long-Term | Total | ||||||||||
Notes payable and other borrowings | $ | 188,221 | $ | 558,353 | $ | 746,574 | ||||||
Preferred interests | 9,479 | 583,417 | 592,896 | |||||||||
Capital lease obligations | 191,497 | 95,260 | 286,757 | |||||||||
CCFC financing | 784,513 | — | 784,513 | |||||||||
CalGen financing | 2,437,982 | — | 2,437,982 | |||||||||
Construction/project financing | 1,160,593 | 1,200,432 | 2,361,025 | |||||||||
DIP Facility | — | 25,000 | 25,000 | |||||||||
Senior notes and term loans | 641,652 | — | 641,652 | |||||||||
$ | 5,413,937 | $ | 2,462,462 | $ | 7,876,399 | |||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
December 31, 2005 | December 31, 2004 | |||||||||||||||||||||||
Current | Long-Term | Total | Current | Long-Term | Total | |||||||||||||||||||
Notes payable and other borrowings | $ | 188,221 | $ | 558,353 | $ | 746,574 | $ | 200,076 | $ | 769,490 | $ | 969,566 | ||||||||||||
Notes payable to Calpine Capital Trusts | — | — | — | — | 517,500 | 517,500 | ||||||||||||||||||
Preferred interests | 9,479 | 583,417 | 592,896 | 8,641 | 497,896 | 506,537 | ||||||||||||||||||
Capital lease obligations | 8,133 | 278,624 | 286,757 | 5,490 | 283,429 | 288,919 | ||||||||||||||||||
CCFC financing | 3,208 | 781,305 | 784,513 | 3,208 | 783,542 | 786,750 | ||||||||||||||||||
CalGen financing | — | 2,437,982 | 2,437,982 | — | 2,395,332 | 2,395,332 | ||||||||||||||||||
Construction/project financing | 79,594 | 2,281,431 | 2,361,025 | 93,393 | 1,905,658 | 1,999,051 | ||||||||||||||||||
DIP Facility | — | 25,000 | 25,000 | — | — | — | ||||||||||||||||||
Senior notes and term loans | — | 641,652 | 641,652 | 718,449 | 8,532,664 | 9,251,113 | ||||||||||||||||||
Convertible Senior Notes | — | — | — | — | 1,255,298 | 1,255,298 | ||||||||||||||||||
$ | 288,635 | $ | 7,587,764 | $ | 7,876,399 | $ | 1,029,257 | $ | 16,940,809 | $ | 17,970,066 | |||||||||||||
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2006 | $ | 288,635 | ||||
2007 | 335,037 | |||||
2008 | 242,242 | |||||
2009 | 1,438,381 | |||||
2010 | 1,264,277 | |||||
Thereafter | 4,365,852 | |||||
Total debt | 7,934,424 | |||||
(Discount)/ Premium | (58,025 | ) | ||||
Total | $ | 7,876,399 | ||||
(in millions) | ||||||||||||||||
2005 | 2004 | |||||||||||||||
Principal | Amount | Principal | Amount | |||||||||||||
Debt Security | Amount | Paid | Amount | Paid | ||||||||||||
2006 Convertible Notes | $ | — | $ | — | $ | 658.7 | $ | 657.7 | ||||||||
2023 Convertible Notes | — | — | 266.2 | 177.0 | ||||||||||||
95/8% First Priority Senior Notes Due 2014 | 138.9 | 138.9 | — | — | ||||||||||||
81/4% Senior Notes Due 2005 | 4.0 | 4.0 | 38.9 | 34.9 | ||||||||||||
101/2% Senior Notes Due 2006 | 13.5 | 12.4 | 13.9 | 12.4 | ||||||||||||
75/8% Senior Notes Due 2006 | 9.4 | 8.7 | 103.1 | 96.5 | ||||||||||||
83/4% Senior Notes Due 2007 | 5.0 | 3.2 | 30.8 | 24.4 | ||||||||||||
77/8% Senior Notes Due 2008 | 53.5 | 39.6 | 78.4 | 56.5 | ||||||||||||
81/2% Senior Notes Due 2008 | 159.8 | 102.6 | 344.3 | 249.4 | ||||||||||||
83/8% Senior Notes Due 2008 | — | — | 6.1 | 4.0 | ||||||||||||
73/4% Senior Notes Due 2009 | 41.0 | 24.8 | 11.0 | 8.1 | ||||||||||||
85/8% Senior Notes Due 2010 | 86.2 | 59.1 | — | — | ||||||||||||
81/2% Senior Notes Due 2011 | 405.8 | 292.2 | 116.9 | 73.1 | ||||||||||||
$ | 917.1 | $ | 685.5 | $ | 1,668.3 | $ | 1,394.0 | |||||||||
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• | We were required to use the proceeds of certain asset sales and issuances of preferred stock completed in 2005 to make capital expenditures, to acquire permitted assets or capital stock, or to repurchase or repay indebtedness in the first three quarters of 2006. However, as a result of the bankruptcy filings, we have not been, and do not expect to be, able to do so. | |
• | We sold our remaining oil and gas assets on July 7, 2005. The gas component of such sale constituted a sale of “designated assets” under certain of our indentures, which restrict the use of the proceeds of sales of designated assets. In accordance with the indentures, we used $138.9 million of the net proceeds of $902.8 million from the sale to repurchase First Priority Notes from holders pursuant to an offer to purchase. We used approximately $308.2 million, plus accrued interest, of the net proceeds to purchase natural gas assets in storage, and the remaining $406.9 million remains in a restricted designated asset sale proceeds account pursuant to the indentures governing the First and Second Priority Notes. As further described in Note 31, the Delaware Chancery Court found in November 2005 that our use of the approximately $308.2 million of proceeds to make purchases of gas assets in storage was in violation of such indentures and ordered that amount to be returned to a designated asset sale proceeds account. The Delaware Supreme Court affirmed the Delaware Chancery Court’s decision in December 2005. To date, we have not been able to refund the proceeds that were used to purchase gas assets to such account. |
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Non-Debtor Entities |
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15. | Notes Payable and Other Borrowings |
Borrowings Outstanding | Letters of Credit Issued | ||||||||||||||||
December 31, | December 31, | ||||||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||||||
Corporate Cash Collateralized Letter of Credit Facility | $ | — | $ | — | $ | 140,270 | $ | 233,271 | |||||||||
Calpine Northbrook Energy Marketing, LLC note | 29,442 | 52,294 | — | — | |||||||||||||
Calpine Commercial Trust | — | 34,255 | — | — | |||||||||||||
Power Contract Financing III, LLC | 56,316 | 51,592 | — | — | |||||||||||||
Power Contract Financing, L.L.C. | 540,269 | 688,366 | — | — | |||||||||||||
Gilroy note payable(1) | 117,719 | 125,478 | — | — | |||||||||||||
Other | 2,828 | 17,581 | 4,591 | 6,158 | |||||||||||||
Total notes payable and other borrowings | $ | 746,574 | $ | 969,566 | $ | 144,861 | $ | 239,429 | |||||||||
Less: notes payable and other borrowings, current portion | 188,221 | 200,076 | — | — | |||||||||||||
Notes payable and other borrowings, net of current portion | $ | 558,353 | $ | 769,490 | $ | 144,861 | $ | 239,429 | |||||||||
(1) | See Note 11 for information regarding the Gilroy note payable. |
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Notes Payable and Other Borrowings |
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16. | Notes Payable to Calpine Capital Trusts |
Conversion | ||||||||||||||||||||||||||||
Ratio — | ||||||||||||||||||||||||||||
Number of | ||||||||||||||||||||||||||||
Stated | Common | First | Initial | |||||||||||||||||||||||||
Interest | Offering | Shares per | Redemption | Redemption | ||||||||||||||||||||||||
Issue Date | Shares | Rate | Amount | 1 High Tide | Date | Price | ||||||||||||||||||||||
HIGH TIDES I | October 1999 | 5,520,000 | 5.75 | % | $ | 276,000 | 3.4620 | November 5, 2002 | 101.440 | % | ||||||||||||||||||
HIGH TIDES II | January and February 2000 | 7,200,000 | 5.50 | % | 360,000 | 1.9524 | February 5, 2003 | 101.375 | % | |||||||||||||||||||
HIGH TIDES III | August 2000 | 10,350,000 | 5.00 | % | 517,500 | 1.1510 | August 5, 2003 | 101.250 | % | |||||||||||||||||||
23,070,000 | $ | 1,153,500 | ||||||||||||||||||||||||||
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17. | Preferred Interests |
Borrowings Outstanding | |||||||||
December 31, | |||||||||
2005 | 2004 | ||||||||
Preferred interest in Auburndale Power Plant | $ | 78,076 | $ | 79,135 | |||||
Preferred interest in Gilroy Energy Center, LLC | 59,820 | 67,402 | |||||||
Preferred interest in Calpine Jersey I and II | — | 360,000 | |||||||
Preferred interest in Metcalf Energy Center, LLC | 155,000 | — | |||||||
Preferred interest in CCFC Preferred Holdings, LLC | 300,000 | — | |||||||
Total preferred interests | $ | 592,896 | $ | 506,537 | |||||
Less: preferred interests, current portion | 9,479 | 8,641 | |||||||
Preferred interests, net of current portion, and term loan | $ | 583,417 | $ | 497,896 | |||||
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18. | Capital Lease Obligations |
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King City | ||||||||||||||
Capital Lease | Other | |||||||||||||
with Related | Capital | |||||||||||||
Party | Leases | Total | ||||||||||||
Years Ending December 31: | ||||||||||||||
2006 | $ | 33,158 | $ | 20,298 | $ | 53,456 | ||||||||
2007 | 16,552 | 20,460 | 37,012 | |||||||||||
2008 | 16,199 | 21,855 | 38,054 | |||||||||||
2009 | 16,592 | 21,600 | 38,192 | |||||||||||
2010 | 19,526 | 22,447 | 41,973 | |||||||||||
Thereafter | 157,047 | 245,864 | 402,911 | |||||||||||
Total minimum lease payments | 259,074 | 352,524 | 611,598 | |||||||||||
Less: Amount representing interest(1) | 162,095 | 162,746 | 324,841 | |||||||||||
Present value of net minimum lease payments | 96,979 | 189,778 | 286,757 | |||||||||||
Less: Capital lease obligations, current portion | 2,360 | 189,137 | 191,497 | |||||||||||
Capital lease obligations, net of current portion | $ | 94,619 | $ | 641 | $ | 95,260 | ||||||||
(1) | Amount necessary to reduce net minimum lease payments to present value calculated at the incremental borrowing rate at the time of acquisition. |
19. | CCFC Financing |
Outstanding at | |||||||||
December 31, | |||||||||
2005(1) | 2004 | ||||||||
Second Priority Senior Secured Floating Rate Notes Due 2011 | $ | 409,539 | $ | 408,568 | |||||
First Priority Senior Secured Institutional Term Loans Due 2009 | 374,974 | 378,182 | |||||||
Total CCFC financing | 784,513 | 786,750 | |||||||
Less: Current portion | 784,513 | 3,208 | |||||||
CCFC financing, net of current portion | $ | — | $ | 783,542 | |||||
(1) | Due to technical default under the indenture, all amounts are recorded as current liabilities as of December 31, 2005. |
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20. | CalGen Financing |
Letters of Credit | |||||||||||||||||
Outstanding at | Outstanding at | ||||||||||||||||
December 31, | December 31, | ||||||||||||||||
2005 | 2004 | 2005 | 2004 | ||||||||||||||
First Priority Secured Floating Rate Notes Due 2009 | $ | 235,000 | $ | 235,000 | $ | — | $ | — | |||||||||
Second Priority Secured Floating Rate Notes Due 2010 | 633,239 | 631,639 | — | — | |||||||||||||
Third Priority Secured Floating Rate Notes Due 2011 | 680,000 | 680,000 | — | — | |||||||||||||
Third Priority Secured Fixed Rate Notes Due 2011 | 150,000 | 150,000 | — | — | |||||||||||||
First Priority Secured Term Loans Due 2009 | 600,000 | 600,000 | — | — | |||||||||||||
Second Priority Secured Term Loans Due 2010 | 98,944 | 98,693 | — | — | |||||||||||||
First Priority Secured Revolving Loans | 40,799 | — | 158,335 | 189,958 | |||||||||||||
Total CalGen financing(1) | $ | 2,437,982 | $ | 2,395,332 | $ | 158,335 | $ | 189,958 | |||||||||
(1) | Due to the defaults occurring as a result of the Chapter 11 filings of Calgen and its subsidiaries, including CalGen Finance Corp., under the CalGen Secured Note indentures and the CalGen Term Loan agreements, all amounts are recorded as current liabilities. |
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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 Fixed Rate 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) | |
First Priority Secured Revolving Loans | LIBOR plus 350 basis points(3) |
(1) | We may also elect a Base Rate plus 275 basis points. |
(2) | We may also elect a Base Rate plus 475 basis points. |
(3) | We may also elect a Base Rate plus 250 basis points. |
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2005 Effective Interest | 2004 Effective Interest | |||||||
Rate after Amortization of | Rate after Amortization of | |||||||
Deferred Financing Costs | Deferred Financing Costs | |||||||
First Priority Secured Floating Rate Notes Due 2009 | 7.5 | % | 5.8 | % | ||||
Second Priority Secured Floating Rate Notes Due 2010 | 9.7 | % | 8.1 | % | ||||
Third Priority Secured Floating Rate Notes Due 2011 | 12.6 | % | 10.9 | % | ||||
Third Priority Secured Fixed Rate Notes Due 2011 | 11.8 | % | 11.8 | % | ||||
First Priority Secured Term Loans Due 2009 | 7.6 | % | 5.8 | % | ||||
Second Priority Secured Term Loans Due 2010 | 9.8 | % | 8.0 | % | ||||
First Priority Secured Revolving Loans | 14.6 | % | 17.5 | % |
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21. | Other Construction/ Project Financing |
Letters of Credit | |||||||||||||||||
Outstanding at | Outstanding at | ||||||||||||||||
December 31, | December 31, | ||||||||||||||||
Projects | 2005 | 2004 | 2005 | 2004 | |||||||||||||
Pasadena Cogeneration, L.P. | $ | 282,222 | $ | 282,896 | $ | — | $ | — | |||||||||
Broad River Energy LLC | 265,217 | 275,112 | — | — | |||||||||||||
Otay Mesa Energy Center, LLC — Ground Lease | 7,000 | 7,000 | — | — | |||||||||||||
Gilroy Energy Center, LLC | 223,218 | 261,382 | — | — | |||||||||||||
Blue Spruce Energy Center, LLC | 96,395 | 98,272 | — | — | |||||||||||||
Riverside Energy Center, LLC | 355,293 | 368,500 | — | — | |||||||||||||
Rocky Mountain Energy Center, LLC | 245,872 | 264,900 | — | — | |||||||||||||
Calpine Fox LLC | 347,828 | 266,075 | 10,000 | 75,000 | |||||||||||||
Metcalf Energy Center, LLC | 100,000 | — | — | — | |||||||||||||
Mankato Energy Center, LLC | 151,230 | — | 25,000 | — | |||||||||||||
Freeport Energy Center, LP | 163,603 | — | 25,000 | — | |||||||||||||
MEP Pleasant Hill, LLC(1) | — | 174,914 | — | — | |||||||||||||
Bethpage Energy Center 3, LLC | 123,147 | — | — | — | |||||||||||||
Total | 2,361,025 | 1,999,051 | $ | 60,000 | $ | 75,000 | |||||||||||
Less: Current portion | 1,160,593 | 93,393 | |||||||||||||||
Long-term construction/project financing | $ | 1,200,432 | $ | 1,905,658 | |||||||||||||
(1) | Classified as liability subject to compromise as of December 21, 2005, due to our bankruptcy filings on December 20, 2005. |
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22. | DIP Facility |
December 22, 2005 | |||||
(In thousands) | |||||
First Priority Facility Commitments | |||||
Revolving Credit Facility(1)(2) | $ | 1,000,000 | |||
First Priority Term Loan(2) | 400,000 | ||||
Second Priority Facility Commitments | |||||
Second Priority Term Loan(2) | $ | 600,000 |
(1) | Commitments for letters of credit ($300 million) and swingline loans ($10 million) can be drawn against the revolving credit facility. The DIP Facility will remain in place until the earlier of an effective plan of reorganization on December 20, 2007. |
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(2) | Pursuant to the interim order issued by the US Bankruptcy Court on December 22, 2005, the US Debtors were only authorized to borrow an aggregate amount up to $500,000,000 under the Revolving Credit Facility and nothing under either term facility until the final order was issued by the US Bankruptcy Court on January 26, 2006. |
Margin | ||||
December 22, 2005 | ||||
Revolving Loans and Swingline Loans | 2.25 | % | ||
First Priority Term Loan | 2.25 | % | ||
Second Priority Term Loan | 4.00 | % |
• | 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; | |
• | incur dividend or other payment restrictions affecting certain subsidiaries; | |
• | make capital expenditures; | |
• | engage in certain business activities; and | |
• | acquire facilities or other businesses. |
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23. | Senior Notes |
First Priority Senior Secured Notes Due 2014 |
Amount Outstanding as | Fair Value as of | |||||||||||||||
First | of December 31, | December 31, | ||||||||||||||
Interest | Call | |||||||||||||||
Rates | Date | 2005 | 2004 | 2005 | 2004 | |||||||||||
First Priority Senior Secured Notes Due 2014 | 95/8% | (12 | ) | $641,652 | $778,971 | $660,902 | $801,367 |
24. | Liabilities Subject to Compromise |
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Accounts payable and accrued liabilities | $ | 724.2 | |||
Derivative liabilities | 133.6 | ||||
Project financing | 166.5 | ||||
Convertible notes | 1,823.5 | ||||
Second priority senior secured notes | 3,671.9 | ||||
Unsecured senior notes | 1,880.0 | ||||
Notes payable and other liabilities — related party | 1,078.0 | ||||
Provision for allowable claims | 5,132.4 | ||||
Total liabilities subject to compromise | $ | 14,610.1 | |||
Project Financing |
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Convertible Notes |
Fair Value as of | ||||||||||||||||||||||
December 31, | December 31, | |||||||||||||||||||||
Interest | ||||||||||||||||||||||
Rates | 2005 | 2004 | 2005 | 2004 | ||||||||||||||||||
Convertible Notes | ||||||||||||||||||||||
2006 Convertible Notes | 4 | % | $ | 1,311 | $ | 1,326 | $ | 1,311 | $ | 1,326 | ||||||||||||
2023 Convertible Notes | 43/4 | % | 633,775 | 633,775 | 160,424 | 633,775 | ||||||||||||||||
2014 Convertible Notes | 6 | %(1) | 538,374 | 620,197 | 108,011 | 716,055 | ||||||||||||||||
2015 Convertible Notes | 73/4 | % | 650,000 | — | 327,275 | — | ||||||||||||||||
Total Convertible Notes | $ | 1,823,460 | $ | 1,255,298 | $ | 597,021 | $ | 1,351,156 | ||||||||||||||
(1) | The 2014 Convertible Notes pay interest each March 30 and September 30 at the rate of 6% per annum, except that no interest is paid on or accrues for the March 30 and September 30, 2007, 2008 and 2009 interest payment dates. Instead, beginning on September 30, 2006, the original principal amount of $839 per note increases by $0.1469 daily to $1,000 principal amount per note at September 30, 2009. Thereafter, the principal amount of the notes does not increase, and the notes resume paying interest on each March 30 and September 30 at the rate of 6% per annum. |
4% Convertible Senior Notes Due 2006 |
43/4% Contingent Convertible Senior Notes Due 2023 |
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Contingent Convertible Notes Due 2014 |
237
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73/4% Contingent Convertible Notes Due 2015 |
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Second Priority Senior Secured Notes and Term Loans |
Fair Value as of | ||||||||||||||||||||||||||||
First | December 31, | December 31, (3) | ||||||||||||||||||||||||||
Interest | Call | |||||||||||||||||||||||||||
Rates | Date | 2005 | 2004 | 2005 | 2004 | |||||||||||||||||||||||
Second Priority Senior Secured Notes and Term Loans | ||||||||||||||||||||||||||||
Second Priority Senior Secured Term Loan B Due 2007 | (4) | (5 | ) | $ | 733,125 | $ | 740,625 | $ | 687,305 | $ | 677,672 | |||||||||||||||||
Second Priority Senior Secured Floating Rate Notes Due 2007 | (6) | (2 | ) | 488,750 | 493,750 | 453,316 | 449,313 | |||||||||||||||||||||
Second Priority Senior Secured Notes Due 2010 | 81/2 | % | (2 | ) | 1,150,000 | 1,150,000 | 922,875 | 987,563 | ||||||||||||||||||||
Second Priority Senior Secured Notes Due 2011 | 97/8 | % | (1 | ) | 400,000 | 393,150 | 312,000 | 344,006 | ||||||||||||||||||||
Second Priority Senior Secured Notes Due 2013 | 83/4 | % | (2 | ) | 900,000 | 900,000 | 724,500 | 740,250 | ||||||||||||||||||||
Total Second Priority Senior Secured Notes and Term Loans | 3,671,875 | 3,677,525 | 3,099,996 | 3,198,804 | ||||||||||||||||||||||||
Less: Second Priority Senior Secured Notes and Term Loans, current portion | — | 12,500 | — | 12,500 | ||||||||||||||||||||||||
Second Priority Senior Secured Notes and Term Loans, net of current portion | $ | 3,671,875 | $ | 3,665,025 | $ | 3,099,996 | $ | 3,186,304 | ||||||||||||||||||||
(1) | Not redeemable prior to maturity. |
(2) | 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, we 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) we pay 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 we redeem, plus accrued interest; (2) we 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. |
(3) | Represents the market value of the notes at the respective dates. |
(4) | U.S. Prime Rate in combination with the Federal Funds Effective Rate, plus a spread. |
(5) | We may not voluntarily prepay these notes prior to July 15, 2005, except that we may on any one or more occasions make such prepayment with the proceeds of one or more public equity offerings. |
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(6) | British Bankers Association LIBOR Rate for deposits in U.S. dollars for a period of three months, plus a spread. |
Second Priority Senior Secured Term Loan B Due 2007 |
Second Priority Senior Secured Floating Rate Notes Due 2007 |
81/2% Second Priority Senior Secured Notes Due 2010 |
97/8% Second Priority Senior Secured Notes Due 2011 |
83/4% Second Priority Senior Secured Notes Due 2013 |
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Unsecured Senior Notes |
Fair Value as of | |||||||||||||||||||||||||
First | December 31, | December 31, (3) | |||||||||||||||||||||||
Interest | Call | ||||||||||||||||||||||||
Rates | Date | 2005 | 2004 | 2005 | 2004 | ||||||||||||||||||||
Unsecured Senior Notes | |||||||||||||||||||||||||
Senior Notes Due 2005 | 81/4 | % | (2) | $ | — | $ | 185,949 | $ | — | $ | 188,424 | ||||||||||||||
Senior Notes Due 2006 | 101/2 | % | 2001 | 139,205 | 152,695 | 57,625 | 151,359 | ||||||||||||||||||
Senior Notes Due 2006 | 75/8 | % | (1) | 102,194 | 111,563 | 42,921 | 109,332 | ||||||||||||||||||
Senior Notes Due 2007 | 83/4 | % | 2002 | 190,299 | 195,305 | 79,926 | 177,728 | ||||||||||||||||||
* Senior Notes Due 2007(4) | 83/4 | % | (2) | — | 165,572 | — | 150,671 | ||||||||||||||||||
Senior Notes Due 2008 | 77/8 | % | (1) | 173,761 | 227,071 | 67,332 | 191,875 | ||||||||||||||||||
* Senior Notes Due 2008 | 81/2 | % | (2) | — | 1,581,539 | — | 1,347,472 | ||||||||||||||||||
* Senior Notes Due 2008(5) | 83/8 | % | (2) | — | 160,050 | — | 121,638 | ||||||||||||||||||
Senior Notes Due 2009 | 73/4 | % | (1) | 180,602 | 221,539 | 75,853 | 177,231 | ||||||||||||||||||
Senior Notes Due 2010 | 85/8 | % | (2) | 411,137 | 496,973 | 131,564 | 402,548 | ||||||||||||||||||
Senior Notes Due 2011 | 81/2 | % | (2) | 682,791 | 1,063,850 | 211,665 | 792,568 | ||||||||||||||||||
* Senior Notes Due 2011(6) | 87/8 | % | (2) | — | 232,511 | — | 167,989 | ||||||||||||||||||
Total Unsecured Senior Notes | $ | 1,879,989 | $ | 4,794,617 | $ | 666,886 | $ | 3,978,835 | |||||||||||||||||
* | Due to Canadian Bankruptcy filing, these Senior Notes have been deconsolidated as of December 20, 2005, and appear for 2004 for historical purposes only. At December 31, 2005, the outstanding balances were: $170.9 million for the 83/4% Senior Notes Due 2007; $1,422.7 million for the 81/2% Senior Notes Due 2008; $139.3 million for the 83/8% Senior Notes Due 2008; and $210.0 million for the 87/8% Senior Notes Due 2011. |
(1) | Not redeemable prior to maturity. |
(2) | Redeemable by us at any time prior to maturity. |
(3) | Represents the market values of the Senior Notes at the respective dates. |
(4) | Issued and payable in Canadian dollars. |
(5) | Issued and payable in Euros. |
(6) | Issued and payable in Sterling. |
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Unsecured Senior Notes Due 2005 |
Unsecured Senior Notes Due 2006 |
Unsecured Senior Notes Due 2007 |
Unsecured Senior Notes Due 2008 |
243
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Unsecured Senior Notes Due 2009 |
Unsecured Senior Notes Due 2010 |
Unsecured Senior Notes Due 2011 |
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Notes Payable and Other Liabilities — Related Party |
Provision for Allowable Claims |
25. | Provision for Income Taxes |
2005 | 2004 | 2003 | ||||||||||
U.S. | $ | (9,971,966 | ) | $ | (406,577 | ) | $ | (92,335 | ) | |||
International | (650,386 | ) | (248,420 | ) | 52,630 | |||||||
�� | ||||||||||||
Income (loss) before provision for income taxes | $ | (10,622,352 | ) | $ | (654,997 | ) | $ | (39,705 | ) | |||
2005 | 2004 | 2003 | |||||||||||||
Current: | |||||||||||||||
Federal | $ | 51,913 | $ | — | $ | 350 | |||||||||
State | 5,410 | 1,198 | — | ||||||||||||
Foreign | 78,431 | 1,296 | — | ||||||||||||
Total Current | 135,754 | 2,494 | 350 | ||||||||||||
Deferred: | |||||||||||||||
Federal | (779,490 | ) | (140,726 | ) | (44,661 | ) | |||||||||
State | (67,573 | ) | 24,184 | (1,893 | ) | ||||||||||
Foreign | (30,089 | ) | (121,266 | ) | 19,771 | ||||||||||
Total Deferred | (877,152 | ) | (237,808 | ) | (26,783 | ) | |||||||||
Total provision (benefit) | $ | (741,398 | ) | $ | (235,314 | ) | $ | (26,433 | ) | ||||||
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2005 | 2004 | 2003 | ||||||||||
Expected tax (benefit) rate at United States statutory tax rate | (35.00 | )% | (35.00 | )% | (35.00 | )% | ||||||
State income tax (benefit), net of federal benefit | (0.58 | )% | 2.39 | % | (2.03 | )% | ||||||
Depletion and other permanent items | (0.02 | )% | 0.50 | % | 1.41 | % | ||||||
Valuation allowances against future tax benefits | 13.14 | % | 4.54 | % | — | |||||||
Tax credits | (0.01 | )% | (0.21 | )% | (4.10 | )% | ||||||
Foreign tax at rates other than U.S. statutory rate | 1.55 | % | (8.12 | )% | (12.95 | )% | ||||||
Non-deductible reorganization items | 13.27 | % | — | — | ||||||||
Other, net (including U.S. tax on Foreign Income) | 0.65 | % | — | (13.93 | )% | |||||||
Effective income tax (benefit) rate | (7.00 | )% | (35.90 | )% | (66.60 | )% | ||||||
2005 | 2004 | ||||||||||
Deferred tax assets: | |||||||||||
Net operating loss and credit carryforwards | $ | 1,174,980 | $ | 1,095,688 | |||||||
Taxes related to risk management activities and SFAS No. 133 | 89,122 | 71,226 | |||||||||
Reorganization and impairments | 837,762 | — | |||||||||
Other differences(1) | — | 324,040 | |||||||||
Deferred tax assets before valuation allowance | 2,101,864 | 1,490,954 | |||||||||
Valuation allowance | (1,639,222 | ) | (62,822 | ) | |||||||
Total Deferred tax assets | 462,642 | 1,428,132 | |||||||||
Deferred tax liabilities: | |||||||||||
Property differences | (706,661 | ) | (2,238,278 | ) | |||||||
Other differences(1) | (122,317 | ) | — | ||||||||
Total Deferred tax liabilities | (828,978 | ) | (2,238,278 | ) | |||||||
Net deferred tax liability | (366,336 | ) | (810,146 | ) | |||||||
Less: Current portion: asset/(liability)(1) | (12,950 | ) | 75,608 | ||||||||
Deferred income taxes, net of current portion | $ | (353,386 | ) | $ | (885,754 | ) | |||||
(1) | Current portion of net deferred income taxes are classified within other current liabilities in 2005 and other current assets in 2004 on the Consolidated Balance Sheets. |
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26. | Employee Benefit Plans |
Retirement Savings Plans |
2000 Employee Stock Purchase Plan |
1996 Stock Incentive Plan |
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Weighted | |||||||||||||
Available for | Outstanding | Average | |||||||||||
Option or | Number of | Exercise | |||||||||||
Award | Options | Price | |||||||||||
Outstanding January 1, 2003 | 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 | ) | — | — | |||||||||
Share awards | — | (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 | ) | — | — | |||||||||
Share awards | — | (1,980 | ) | 4.33 | |||||||||
Outstanding December 31, 2004 | 22,205,905 | 34,777,857 | 8.42 | ||||||||||
Granted | (8,242,710 | ) | 8,242,710 | 3.38 | |||||||||
Exercised | — | (1,679,650 | ) | 1.25 | |||||||||
Canceled | 4,250,649 | (4,250,649 | ) | 8.58 | |||||||||
Canceled options(1) | (425,232 | ) | — | — | |||||||||
Restricted award shares | (1,247,427 | ) | — | 3.32 | |||||||||
Canceled restricted award shares | 301,205 | — | — | ||||||||||
Outstanding December 31, 2005 | 16,842,390 | 37,090,268 | $ | 7.62 | |||||||||
Options exercisable: | |||||||||||||
December 31, 2003 | 22,953,781 | 8.02 | |||||||||||
December 31, 2004 | 22,949,497 | 9.30 | |||||||||||
December 31, 2005 | 27,185,497 | 8.78 |
(1) | Represents cessation of options awarded under the Encal and the Calpine 1992 stock option plans. |
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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 - $ 2.640 | 3,916,638 | 2.42 | $ | 2.144 | 3,831,638 | $ | 2.134 | |||||||||||||
$ 2.650 - $ 3.320 | 6,222,204 | 6.16 | 3.317 | 1,656,864 | 3.315 | |||||||||||||||
$ 3.440 - $ 3.860 | 4,502,400 | 3.75 | 3.841 | 4,490,900 | 3.842 | |||||||||||||||
$ 3.910 - $ 3.980 | 4,735,074 | 7.03 | 3.980 | 3,147,397 | 3.980 | |||||||||||||||
$ 4.010 - $ 5.240 | 2,670,284 | 6.32 | 5.146 | 2,127,788 | 5.123 | |||||||||||||||
$ 5.330 - $ 5.560 | 4,626,019 | 8.15 | 5.560 | 2,084,052 | 5.559 | |||||||||||||||
$ 5.565 - $ 9.955 | 5,972,331 | 4.84 | 8.715 | 5,542,057 | 8.800 | |||||||||||||||
$10.000 - $48.150 | 4,313,821 | 4.45 | 27.656 | 4,174,274 | 28.084 | |||||||||||||||
$48.188 - $56.920 | 129,647 | 5.24 | 51.333 | 128,677 | 51.320 | |||||||||||||||
$56.990 - $56.990 | 1,850 | 5.33 | 56.990 | 1,850 | 56.990 | |||||||||||||||
37,090,268 | 5.43 | 7.623 | 27,185,497 | 8.778 | ||||||||||||||||
27. | Stockholders’ Equity (Deficit) |
Common Stock |
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Preferred Stock and Preferred Share Purchase Rights |
28. | Customers |
Significant Customer |
Counterparty Exposure |
California Department of Water Resources |
251
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Lease Income |
2006 | $ | 175,349 | |||
2007 | 213,431 | ||||
2008 | 285,386 | ||||
2009 | 288,516 | ||||
2010 | 291,693 | ||||
Thereafter | 2,553,024 | ||||
Total | $ | 3,807,399 | |||
Credit Evaluations |
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29. | Derivative Instruments |
Commodity Derivative Instruments |
Interest Rate and Currency Derivative Instruments |
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Summary of Derivative Values |
Commodity | ||||||||||||||
Interest Rate | Derivative | Total | ||||||||||||
Derivative | Instruments | Derivative | ||||||||||||
Instruments | Net | Instruments | ||||||||||||
Current derivative assets | $ | 1,089 | $ | 488,410 | $ | 489,499 | ||||||||
Long-term derivative assets | 4,176 | 710,050 | 714,226 | |||||||||||
Total assets | $ | 5,265 | $ | 1,198,460 | $ | 1,203,725 | ||||||||
Current derivative liabilities | $ | 2,334 | $ | 726,560 | $ | 728,894 | ||||||||
Long-term derivative liabilities | 7,370 | 911,714 | 919,084 | |||||||||||
Total liabilities | $ | 9,704 | $ | 1,638,274 | $ | 1,647,978 | ||||||||
Net derivative assets (liabilities) | $ | (4,439 | ) | $ | (439,814 | ) | $ | (444,253 | ) | |||||
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Relationship of Net Derivative Assets or Liabilities to AOCI |
• | 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. |
Net derivative liabilities | $ | (444,253 | ) | ||
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness | 549,696 | ||||
Cash flow hedges terminated prior to maturity | (353,293 | ) | |||
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges | 89,123 | ||||
Accumulated other comprehensive loss from derivative instruments, net of tax(1) | $ | (158,727 | ) | ||
(1) | Amount represents one portion of our total AOCI balance. |
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December 31, 2005 | ||||||||||
Gross | Net | |||||||||
Current derivative assets | $ | 2,612,436 | $ | 488,410 | ||||||
Long-term derivative assets | 1,300,990 | 710,050 | ||||||||
Total derivative assets | $ | 3,913,426 | $ | 1,198,460 | ||||||
Current derivative liabilities | $ | 2,850,587 | $ | 726,560 | ||||||
Long-term derivative liabilities | 1,502,653 | 911,714 | ||||||||
Total derivative liabilities | $ | 4,353,240 | $ | 1,638,274 | ||||||
Net commodity derivative (liabilities) | $ | (439,814 | ) | $ | (439,814 | ) | ||||
2005 | |||||||||||||
Hedge | Undesignated | ||||||||||||
Ineffectiveness | Derivatives | Total | |||||||||||
Natural gas derivatives(1) | $ | (1,951 | ) | $ | (9,042 | ) | $ | (10,993 | ) | ||||
Power derivatives(1) | (4,638 | ) | (79,467 | ) | (84,105 | ) | |||||||
Interest rate derivatives(2) | 161 | (2,527 | ) | (2,366 | ) | ||||||||
Currency derivatives | — | — | — | ||||||||||
Total | $ | (6,428 | ) | $ | (91,036 | ) | $ | (97,464 | ) | ||||
2004 | |||||||||||||
Hedge | Undesignated | ||||||||||||
Ineffectiveness | Derivatives | Total | |||||||||||
Natural gas derivatives(1) | $ | 5,827 | $ | (10,700 | ) | $ | (4,873 | ) | |||||
Power derivatives(1) | 1,814 | (31,666 | ) | (29,852 | ) | ||||||||
Interest rate derivatives(2) | 1,492 | 6,035 | 7,527 | ||||||||||
Currency derivatives | — | (12,897 | ) | (12,897 | ) | ||||||||
Total | $ | 9,133 | $ | (49,228 | ) | $ | (40,095 | ) | |||||
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2003 | |||||||||||||
Hedge | Undesignated | ||||||||||||
Ineffectiveness | Derivatives | Total | |||||||||||
Natural gas derivatives(1) | $ | 3,153 | $ | 7,768 | $ | 10,921 | |||||||
Power derivatives(1) | (5,001 | ) | (56,693 | ) | (61,694 | ) | |||||||
Interest rate derivatives(2) | (974 | ) | — | (974 | ) | ||||||||
Currency derivatives | — | — | — | ||||||||||
Total | $ | (2,822 | ) | $ | (48,925 | ) | $ | (51,747 | ) | ||||
(1) | Represents the unrealized portion ofmark-to-market activity on gas and power transactions. The unrealized portion ofmark-to-market activity is combined with the realized portions ofmark-to-market activity and presented in the Consolidated Statements of Operations asmark-to-market activities, net. |
(2) | Recorded within Other Income. |
2005 | 2004 | 2003 | |||||||||||
Natural gas and crude oil derivatives | $ | 136,767 | $ | 58,308 | $ | 40,752 | |||||||
Power derivatives | (521,119 | ) | (128,556 | ) | (79,233 | ) | |||||||
Interest rate derivatives | (16,984 | ) | (17,625 | ) | (27,727 | ) | |||||||
Foreign currency derivatives | (4,188 | ) | (2,015 | ) | 10,588 | ||||||||
Total derivatives | $ | (405,524 | ) | $ | (89,888 | ) | $ | (55,620 | ) | ||||
2011 & | |||||||||||||||||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | After | Total | |||||||||||||||||||||||
Gas OCI | $ | 305,259 | $ | 11,800 | $ | — | $ | — | $ | — | $ | — | $ | 317,059 | |||||||||||||||
Power OCI | (484,439 | ) | (33,757 | ) | (5,956 | ) | (4,336 | ) | (3,037 | ) | — | (531,525 | ) | ||||||||||||||||
Interest rate OCI | (5,798 | ) | (5,267 | ) | (4,516 | ) | (3,989 | ) | (2,265 | ) | (11,550 | ) | (33,385 | ) | |||||||||||||||
Foreign currency OCI | — | — | — | — | — | — | — | ||||||||||||||||||||||
Total pre-tax OCI | $ | (184,978 | ) | $ | (27,224 | ) | $ | (10,472 | ) | $ | (8,325 | ) | $ | (5,302 | ) | $ | (11,550 | ) | $ | (247,851 | ) | ||||||||
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30. | Earnings (Loss) per Share |
For the Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||
2005 | 2004 | 2003 | ||||||||||||||||||||||||||||||||||||
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 | $ | (9,880,954 | ) | 463,567 | $ | (21.32 | ) | $ | (419,683 | ) | 430,775 | $ | (0.97 | ) | $ | (13,272 | ) | 390,772 | $ | (0.03 | ) | |||||||||||||||||
Discontinued operations, net of tax | (58,254 | ) | — | (0.12 | ) | 177,222 | — | 0.41 | 114,351 | — | 0.29 | |||||||||||||||||||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | — | — | — | — | — | 180,943 | — | 0.46 | |||||||||||||||||||||||||||||
Net income (loss) | $ | (9,939,208 | ) | 463,567 | $ | (21.44 | ) | $ | (242,461 | ) | 430,775 | $ | (0.56 | ) | $ | 282,022 | 390,772 | $ | 0.72 | |||||||||||||||||||
Diluted earnings (loss) per common share: | ||||||||||||||||||||||||||||||||||||||
Common shares issuable upon exercise of stock options using treasury stock method | — | — | 5,447 | |||||||||||||||||||||||||||||||||||
Income (loss) before discontinued operations and cumulative effect of a change in accounting principle | $ | (9,880,954 | ) | 463,567 | $ | (21.32 | ) | $ | (419,683 | ) | 430,775 | $ | (0.97 | ) | $ | (13,272 | ) | 396,219 | $ | (0.03 | ) | |||||||||||||||||
Discontinued operations, net of tax | (58,254 | ) | — | (0.12 | ) | 177,222 | — | 0.41 | 114,351 | — | 0.29 | |||||||||||||||||||||||||||
Cumulative effect of a change in accounting principle, net of tax | — | — | — | — | — | — | 180,943 | — | 0.45 | |||||||||||||||||||||||||||||
Net income (loss) | $ | (9,939,208 | ) | 463,567 | $ | (21.44 | ) | $ | (242,461 | ) | 430,775 | $ | (0.56 | ) | $ | 282,022 | 396,219 | $ | 0.71 | |||||||||||||||||||
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• | 2023 Convertible Notes — If our closing stock price is above the instrument’s conversion price of $6.50, a maximum of approximately 97.5 million shares would be included (if dilutive) in the diluted EPS calculation; | |
• | 2015 Convertible Notes — If our closing stock price is above the instrument’s conversion price of $4.00, a maximum of approximately 163.0 million shares would be included (if dilutive) in the diluted EPS calculation; | |
• | 2014 Convertible Notes — If our closing stock price is above the instrument’s conversion price of $3.85, a maximum of approximately 139.8 million shares would be included (if dilutive) in the diluted EPS calculation; |
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Year | Total | ||||
(In thousands) | |||||
2006 | $ | 17,578 | |||
2007 | 4,432 | ||||
2008 | 2,699 | ||||
Total | $ | 24,709 | |||
Turbine | |||||
Restructuring | |||||
Accrual | |||||
As of January 1, 2003 | $ | 24,824 | |||
Payments | (15,805 | ) | |||
Adjustments to accrual | (473 | ) | |||
As of December 31, 2003 | $ | 8,546 | |||
Payments | (4,498 | ) | |||
As of December 31, 2004 | $ | 4,048 | |||
Payments | — | ||||
As of December 31, 2005 | $ | 4,048 | |||
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Total | |||||||||||||
Accrued Rent- | Accrued Rent- | Accrued Rent | |||||||||||
Short-Term | Long-Term | Liability | |||||||||||
As of January 1, 2003 | $ | 4,009 | $ | 2,370 | $ | 6,379 | |||||||
Additions | 2,062 | 8,341 | 10,403 | ||||||||||
Reclass from long-term | 825 | (825 | ) | — | |||||||||
Amortization | (3,718 | ) | (162 | ) | (3,880 | ) | |||||||
Adjustments to accrual | (166 | ) | 195 | 29 | |||||||||
As of December 31, 2003 | $ | 3,012 | $ | 9,919 | $ | 12,931 | |||||||
Additions | 1,313 | 354 | 1,667 | ||||||||||
Reclass from long-term | 2,512 | (2,512 | ) | — | |||||||||
Amortization | (2,585 | ) | — | (2,585 | ) | ||||||||
Accretion | — | 1,325 | 1,325 | ||||||||||
Adjustments to accrual | 12 | 54 | 66 | ||||||||||
As of December 31, 2004 | $ | 4,264 | $ | 9,140 | $ | 13,404 | |||||||
Additions | 281 | 1,373 | 1,654 | ||||||||||
Reclass from long-term | 3,300 | (3,300 | ) | — | |||||||||
Amortization | (4,156 | ) | — | (4,156 | ) | ||||||||
Accretion | — | 982 | 982 | ||||||||||
Adjustments to accrual (primarily Canadian and other foreign subsidiaries deconsolidation) | (837 | ) | (1,121 | ) | (1,958 | ) | |||||||
As of December 31, 2005 | $ | 2,852 | $ | 7,074 | $ | 9,926 | |||||||
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Severance | ||||
Liability | ||||
January 1, 2003 | $ | 1,556 | ||
Additions | 3,914 | |||
Payments | (5,191 | ) | ||
Adjustments | 414 | |||
As of December 31, 2003 | $ | 693 | ||
Additions | 6,154 | |||
Payments | (5,292 | ) | ||
Adjustments | (1,555 | ) | ||
As of December 31, 2004 | $ | — | ||
Additions | 6,241 | |||
Payments | (598 | ) | ||
Adjustments | — | |||
As of December 31, 2005 | $ | 5,643 | ||
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Initial | |||||||||||||||||||||||||||||||||
Year | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | ||||||||||||||||||||||||||
Watsonville | 1995 | $ | 2,905 | $ | 2,905 | $ | 2,905 | $ | 4,065 | $ | — | $ | — | $ | 12,780 | ||||||||||||||||||
Greenleaf | 1998 | 6,604 | 6,999 | 6,290 | 7,697 | 6,440 | 22,931 | 56,961 | |||||||||||||||||||||||||
Geysers | 1999 | 61,965 | 47,150 | 42,886 | 34,566 | 22,899 | 83,118 | 292,584 | |||||||||||||||||||||||||
KIAC | 2000 | 23,875 | 23,845 | 24,473 | 24,537 | 24,548 | 215,535 | 336,813 | |||||||||||||||||||||||||
Rumford/ Tiverton | 2000 | 45,000 | 45,000 | 45,000 | 45,000 | 205,924 | 321,038 | 706,962 | |||||||||||||||||||||||||
South Point | 2001 | 9,620 | 9,620 | 9,620 | 9,620 | 9,620 | 297,570 | 345,670 | |||||||||||||||||||||||||
RockGen | 2001 | 26,088 | 27,478 | 28,732 | 29,360 | 29,250 | 140,003 | 280,911 | |||||||||||||||||||||||||
Total | $ | 176,057 | $ | 162,997 | $ | 159,906 | $ | 154,845 | $ | 298,681 | $ | 1,080,195 | $ | 2,032,681 | |||||||||||||||||||
2006 | $ | 22,910 | |||
2007 | 21,287 | ||||
2008 | 20,109 | ||||
2009 | 19,851 | ||||
2010 | 20,070 | ||||
Thereafter | 41,945 | ||||
Total | $ | 146,172 | |||
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Commitments Expiring | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | Total | ||||||||||||||||||||||
Guarantee of subsidiary debt(5) | $ | 24,425 | $ | 198,859 | $ | 1,592,342 | $ | 22,131 | $ | 11,040 | $ | 590,287 | $ | 2,439,084 | |||||||||||||||
Standby letters of credit(1)(3) | 361,104 | 8,298 | 898 | — | — | — | 370,300 | ||||||||||||||||||||||
Surety bonds(2)(3)(4) | — | — | — | — | — | 11,395 | 11,395 | ||||||||||||||||||||||
Guarantee of subsidiary operating lease payments(3) | 81,772 | 82,487 | 115,604 | 113,977 | 263,041 | 900,742 | 1,557,623 | ||||||||||||||||||||||
Total | $ | 467,301 | $ | 289,644 | $ | 1,708,844 | $ | 136,108 | $ | 274,081 | $ | 1,502,424 | $ | 4,378,402 | |||||||||||||||
(1) | The standby letters of credit disclosed above include those disclosed in Notes 15 and 20. |
(2) | The surety bonds do not have expiration or cancellation dates. |
(3) | These are off balance sheet obligations. |
(4) | As of December 31, 2005, $7,061 of cash collateral is outstanding related to these bonds. |
(5) | Includes the guarantee of our ULCI and ULCII subsidiary debt which was deconsolidated along with most of our Canadian and other foreign subsidiaries on December 20, 2005. |
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Balance at | ||||
December 31, 2005 | ||||
Guarantee of subsidiary debt | $ | 2,439,084 | ||
Standby letters of credit | 370,300 | |||
Surety bonds | 11,395 | |||
$ | 2,820,779 | |||
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Electric | ||||||||||||||||
Generation | Corporate and | |||||||||||||||
and Marketing | �� | Other | Eliminations | Total | ||||||||||||
2005 | ||||||||||||||||
Revenue from external customers | $ | 10,011,789 | $ | 239,700 | $ | (138,831 | ) | $ | 10,112,658 | |||||||
Depreciation and amortization expense included in cost of revenue | 503,992 | 3,661 | (1,212 | ) | 506,441 | |||||||||||
Operating plant impairments | 2,412,586 | — | — | 2,412,586 | ||||||||||||
(Income) loss from unconsolidated investments | (12,119 | ) | — | — | (12,119 | ) | ||||||||||
Equipment, development project and other impairments | 2,091,967 | — | 25,698 | 2,117,665 | ||||||||||||
Interest expense | 1,318,121 | 21,213 | 57,954 | 1,397,288 | ||||||||||||
Interest (income) | (79,454 | ) | (1,279 | ) | (3,493 | ) | (84,226 | ) | ||||||||
(Income) from repurchase of various issuances of debt | — | — | (203,341 | ) | (203,341 | ) | ||||||||||
Other (income) expense, net | 53,713 | 2,617 | 16,058 | 72,388 | ||||||||||||
Income (loss) before reorganization items, provision (benefit) for income taxes, and discontinued operations | (5,535,921 | ) | (72,142 | ) | 12,221 | (5,595,842 | ) | |||||||||
Reorganization items | 296,187 | (145,757 | ) | 4,876,080 | 5,026,510 | |||||||||||
Provision (benefit) for income taxes | (769,399 | ) | 28,001 | — | (741,398 | ) | ||||||||||
Total assets | 19,380,779 | 311,902 | 852,116 | 20,544,797 | ||||||||||||
Investment in power projects and oil and gas properties | 83,620 | — | — | 83,620 | ||||||||||||
Property additions | 784,562 | 6,156 | 31,589 | 822,307 | ||||||||||||
2004 | ||||||||||||||||
Revenue from external customers | $ | 8,580,461 | $ | 117,797 | $ | (49,876 | ) | $ | 8,648,382 | |||||||
Depreciation and amortization expense included in cost of revenue | 441,215 | 3,637 | 1,166 | 446,018 | ||||||||||||
(Income) loss from unconsolidated investments | 14,088 | — | — | 14,088 | ||||||||||||
Equipment, development project and other impairments | 46,371 | 523 | — | 46,894 | ||||||||||||
Interest expense | 1,010,937 | 49,243 | 35,239 | 1,095,419 | ||||||||||||
Interest (income) | (50,542 | ) | (2,462 | ) | (1,762 | ) | (54,766 | ) | ||||||||
(Income) from repurchase of various issuances of debt | — | — | (246,949 | ) | (246,949 | ) | ||||||||||
Other (income) expense, net | (197,760 | ) | 7,243 | 69,455 | (121,062 | ) | ||||||||||
Income (loss) before reorganization items, provision (benefit) for income taxes, and discontinued operations | (563,659 | ) | (129,667 | ) | 38,329 | (654,997 | ) | |||||||||
Provision (benefit) for income taxes | (200,606 | ) | (49,273 | ) | 14,565 | (235,314 | ) | |||||||||
Total assets | 25,117,106 | 1,223,454 | 875,528 | 27,216,088 | ||||||||||||
Investments in power projects and oil and gas properties | 373,108 | — | — | 373,108 | ||||||||||||
Property additions | 1,457,819 | 5,343 | 18,417 | 1,481,579 | ||||||||||||
2003 | ||||||||||||||||
Revenue from external customers | $ | 8,380,469 | $ | 51,439 | $ | (10,738 | ) | $ | 8,421,170 | |||||||
Depreciation and amortization expense included in cost of revenue | 359,005 | 20,967 | 2,008 | 381,980 | ||||||||||||
(Income) loss from unconsolidated investments | (75,724 | ) | — | — | (75,724 | ) | ||||||||||
Equipment, development project and other impairments | 67,979 | — | — | 67,979 | ||||||||||||
Interest expense | 611,048 | 48,554 | 35,902 | 695,504 | ||||||||||||
Interest (income) | (34,431 | ) | (2,736 | ) | (2,023 | ) | (39,190 | ) | ||||||||
(Income) from repurchase of various issuances of debt | — | — | (278,612 | ) | (278,612 | ) | ||||||||||
Other (income) expense, net | (46,461 | ) | (46,581 | ) | 46,478 | (46,564 | ) | |||||||||
Income (loss) before reorganization items, provision (benefit) for income taxes, and discontinued operations | (57,970 | ) | (20,164 | ) | 38,429 | (39,705 | ) | |||||||||
Provision (benefit) for income taxes | (33,374 | ) | (7,662 | ) | 14,603 | (26,433 | ) | |||||||||
Cumulative effect of a change in accounting principle, net of tax | 183,270 | (1,443 | ) | (884 | ) | 180,943 |
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Geographic Area Information |
United States | Canada | Europe | Total | |||||||||||||
(In thousands) | ||||||||||||||||
2005 | ||||||||||||||||
Total Revenue | $ | 9,955,907 | $ | 105,497 | $ | 51,254 | $ | 10,112,658 | ||||||||
Property, plant and equipment, net | 14,118,795 | — | 420 | 14,119,215 | ||||||||||||
2004 | ||||||||||||||||
Total Revenue | $ | 8,512,769 | $ | 93,071 | $ | 42,542 | $ | 8,648,382 | ||||||||
Property, plant and equipment, net | 17,893,678 | 498,136 | 5,929 | 18,397,743 | ||||||||||||
2003 | ||||||||||||||||
Total Revenue | $ | 8,276,392 | $ | 121,218 | $ | 23,560 | $ | 8,421,170 |
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Quarter Ended | |||||||||||||||||
December 31, | September 30, | June 30, | March 31, | ||||||||||||||
(In thousands, except per share amounts) | |||||||||||||||||
2005 Common stock price per share: | |||||||||||||||||
High | $ | 3.05 | $ | 3.88 | $ | 3.60 | $ | 3.80 | |||||||||
Low | 0.20 | 2.26 | 1.45 | 2.64 | |||||||||||||
2005 | |||||||||||||||||
Total revenue | $ | 2,586,430 | $ | 3,281,590 | $ | 2,198,907 | $ | 2,045,731 | |||||||||
(Income) from repurchase of various issuances of debt | (36,885 | ) | (15,530 | ) | (129,154 | ) | (21,772 | ) | |||||||||
Operating plant impairments | 2,412,586 | — | — | — | |||||||||||||
Gross profit (loss) | (2,346,247 | ) | 239,127 | 78,458 | 83,739 | ||||||||||||
Equipment, development project and other impairments | 2,117,665 | — | — | — | |||||||||||||
Income (loss) from operations | (4,488,655 | ) | 175,164 | (78,632 | ) | 20,844 | |||||||||||
Reorganization items | 5,026,510 | — | — | — | |||||||||||||
Income (loss) before discontinued operations | (9,259,478 | ) | (242,435 | ) | (208,182 | ) | (170,859 | ) | |||||||||
Discontinued operations, net of tax | 4,150 | 25,744 | (90,276 | ) | 2,128 | ||||||||||||
Net income (loss) | $ | (9,255,329 | ) | $ | (216,690 | ) | $ | (298,458 | ) | $ | (168,731 | ) | |||||
Basic earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations | $ | (19.33 | ) | $ | (0.51 | ) | $ | (0.46 | ) | $ | (0.38 | ) | |||||
Discontinued operations, net of tax | 0.01 | 0.06 | (0.20 | ) | — | ||||||||||||
Net income (loss) | (19.32 | ) | (0.45 | ) | (0.66 | ) | (0.38 | ) | |||||||||
Diluted earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations | $ | (19.33 | ) | $ | (0.51 | ) | $ | (0.46 | ) | $ | (0.38 | ) | |||||
Discontinued operations, net of tax | 0.01 | 0.06 | (0.20 | ) | — | ||||||||||||
Net income (loss) | (19.32 | ) | (0.45 | ) | (0.66 | ) | (0.38 | ) | |||||||||
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 | |||||||||||||||||
Total revenue | $ | 2,182,050 | $ | 2,411,732 | $ | 2,189,128 | $ | 1,865,472 | |||||||||
(Income) from repurchase of various issuances of debt | (76,401 | ) | (167,154 | ) | (2,559 | ) | (835 | ) | |||||||||
Gross profit | 71,458 | 226,445 | 33,144 | 48,902 | |||||||||||||
Income (loss) from operations | (45,725 | ) | 142,323 | (32,062 | ) | (12,156 | ) | ||||||||||
Income (loss) before discontinued operations | (225,208 | ) | 28,878 | (69,887 | ) | (153,466 | ) | ||||||||||
Discontinued operations, net of tax | (58,488 | ) | 112,247 | 41,189 | 82,274 | ||||||||||||
Net income (loss) | (283,696 | ) | 141,125 | (28,698 | ) | (71,192 | ) | ||||||||||
Basic earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations | $ | (0.51 | ) | $ | 0.07 | $ | (0.17 | ) | $ | (0.37 | ) | ||||||
Discontinued operations, net of tax | (0.13 | ) | 0.25 | 0.10 | 0.20 | ||||||||||||
Net income (loss) | $ | (0.64 | ) | $ | 0.32 | $ | (0.07 | ) | $ | (0.17 | ) | ||||||
Diluted earnings per common share: | |||||||||||||||||
Income (loss) before discontinued operations | (0.51 | ) | 0.07 | (0.17 | ) | (0.37 | ) | ||||||||||
Discontinued operations, net of tax | (0.13 | ) | 0.25 | 0.10 | 0.20 | ||||||||||||
Net income (loss) | $ | (0.64 | ) | $ | 0.32 | $ | (0.07 | ) | $ | (0.17 | ) |
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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, 2005 | |||||||||||||||||||||||||
Allowance for doubtful accounts | $ | 7,317 | $ | 11,645 | $ | — | $ | (3,267 | ) | $ | (3,009 | ) | $ | 12,686 | |||||||||||
Allowance for doubtful accounts with related party Canadian and other foreign subsidiaries | — | 54,830 | — | — | — | 54,830 | |||||||||||||||||||
Reserve for notes receivable | 2,910 | 28,936 | — | — | — | 31,846 | |||||||||||||||||||
Reserve for interest and notes receivable with related party Canadian and other foreign subsidiaries | — | 228,014 | — | — | — | 228,014 | |||||||||||||||||||
Gross reserve for California Refund Liability | 12,905 | 90 | — | — | — | 12,995 | |||||||||||||||||||
Reserve for investment in Androscoggin Energy Center | 5,000 | — | — | — | — | 5,000 | |||||||||||||||||||
Reserve for derivative assets | 3,268 | 4,077 | 3 | (3,862 | ) | — | 3,486 | ||||||||||||||||||
Deferred tax asset valuation allowance | 62,822 | 1,576,400 | — | — | — | 1,639,222 | |||||||||||||||||||
Year ended December 31, 2004 | |||||||||||||||||||||||||
Allowance for doubtful accounts | $ | 7,282 | $ | 6,119 | $ | — | $ | (6,486 | ) | $ | 402 | $ | 7,317 | ||||||||||||
Reserve for notes receivable | 273 | 2,637 | — | — | — | 2,910 | |||||||||||||||||||
Gross reserve for California Refund Liability | 12,905 | — | — | — | — | 12,905 | |||||||||||||||||||
Reserve for 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 | $ | 5,057 | $ | 2,190 | $ | — | $ | (383 | ) | $ | 418 | $ | 7,282 | ||||||||||||
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 |
(1) | Represents write-offs of accounts considered to be uncollectible and recoveries of amounts previously written off or reserved. |
(2) | Primarily relates to amounts recorded on our deconsolidated Canadian and other foreign subsidiaries for the year ended December 31, 2005, and to foreign currency translation adjustments for the years ended December 31, 2004 and 2003. |
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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) | ||
2 | .4 | Share Sale and Purchase Agreement, made as of May 28, 2005, among the Company, Calpine UK Holdings Limited, Quintana Canada Holdings, LLC, International Power PLC, Mitsui & Co., Ltd. and Normantrail (UK CO 3) Limited. Approximately four pages of this Exhibit 2.4 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(b) | ||
2 | .5 | Purchase and Sale Agreement dated July 7, 2005, by and among Calpine Gas Holdings LLC, Calpine Fuels Corporation, the Company, Rosetta Resources Inc., and the other Subject Companies identified therein.(c) | ||
2 | .6 | Agreement dated as of December 20, 2005, by and among Steam Heat LLC, Thermal Power Company and, for certain limited purposes, Geysers Power Company, LLC.(*) | ||
3 | .1.1 | Amended and Restated Certificate of Incorporation of the Company, as amended through June 2, 2004.(d) | ||
3 | .1.2 | Amendment to Amended and Restated Certificate of Incorporation of the Company, dated June 20, 2005.(e) | ||
3 | .2 | Amended and Restated By-laws of the Company.(f) | ||
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.(g) | ||
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.(h) | ||
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.(i) | ||
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.(j) | ||
4 | .2.2 | Supplemental Indenture dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(k) | ||
4 | .2.3 | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h) | ||
4 | .2.4 | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i) | ||
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.(l) | ||
4 | .3.2 | Supplemental Indenture dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(l) | ||
4 | .3.3 | Second Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h) | ||
4 | .3.4 | Third Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i) | ||
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.(m) | ||
4 | .4.2 | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h) |
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Exhibit | ||||
Number | Description | |||
4 | .4.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i) | ||
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.(m) | ||
4 | .5.2 | First Supplemental Indenture dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(h) | ||
4 | .5.3 | Second Supplemental Indenture dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(i) | ||
4 | .6.1 | Indenture dated as of August 10, 2000, between the Company and Wilmington Trust Company, as Trustee.(n) | ||
4 | .6.2 | First Supplemental Indenture dated as of September 28, 2000, between the Company and Wilmington Trust Company, as Trustee.(h) | ||
4 | .6.3 | Second Supplemental Indenture dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee.(o) | ||
4 | .6.3 | Third Supplemental Indenture dated as of June 23, 2005, between the Company and Wilmington Trust Company, as Trustee.(b) | ||
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.(p) | ||
4 | .7.2 | Guarantee Agreement dated as of April 25, 2001, between the Company and Wilmington Trust Company, as Trustee.(q) | ||
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.(p) | ||
4 | .8.1 | Indenture dated as of October 18, 2001, between Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee.(p) | ||
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.(p) | ||
4 | .8.3 | Guarantee Agreement dated as of October 18, 2001, between the Company and Wilmington Trust Company, as Trustee.(p) | ||
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.(p) | ||
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.(r) | ||
4 | .10 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r) | ||
4 | .11 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r) | ||
4 | .12 | Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(r) | ||
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 FSB, as Trustee, including form of Notes.(s) | ||
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 FSB, as Trustee.(s) | ||
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 FSB, as Trustee.(t) |
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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 FSB, as Trustee.(t) | ||
4 | .13.5 | Fourth Supplemental Indenture, dated as of March 15, 2006, 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 FSB, as Trustee.(*) | ||
4 | .13.6 | Waiver Agreement, dated as of March 15, 2006, 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 FSB, as Trustee.(*) | ||
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.(s) | ||
4 | .15 | Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(t) | ||
4 | .16 | Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(t) | ||
4 | .17.1 | First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t) | ||
4 | .17.2 | Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t) | ||
4 | .17.3 | Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust Company, as Trustee, including form of Notes.(t) | ||
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.(d) | ||
4 | .19 | Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, including form of Notes.(u) | ||
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.(v) | ||
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.(o) | ||
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.(w) | ||
4 | .21.1 | Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 14, 2005, containing terms of its 6-Year Redeemable Preferred Shares Due 2011.(*) | ||
4 | .21.2 | Consent, Acknowledgment and Amendment, dated as of March 15, 2006, among Calpine CCFC Holdings, Inc. and the Redeemable Preferred Members party thereto.(*) | ||
4 | .22 | Third Amended and Restated Limited Liability Company Operating Agreement of Metcalf Energy Center, LLC, dated as of June 20, 2005, containing terms of its 5.5-year redeemable preferred shares.(*) | ||
4 | .23 | Pass Through Certificates (Tiverton and Rumford) | ||
4 | .23.1 | 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.(h) |
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Number | Description | |||
4 | .23.2 | 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.(h) | ||
4 | .23.3 | Appendix A — Definitions and Rules of Interpretation.(h) | ||
4 | .23.4 | 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.(h) | ||
4 | .23.5 | 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.(h) | ||
4 | .23.6 | 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.(h) | ||
4 | .24 | Pass Through Certificates (South Point, Broad River and RockGen) | ||
4 | .24.1 | 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.(f) | ||
4 | .24.2 | 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.(f) | ||
4 | .24.3 | 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.(f) | ||
4 | .24.4 | 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.(f) | ||
4 | .24.5 | 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.(f) | ||
4 | .24.6 | 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.(f) |
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Number | Description | |||
4 | .24.7 | 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.(f) | ||
4 | .24.8 | 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.(f) | ||
4 | .24.9 | 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.(f) | ||
4 | .24.10 | 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.(f) | ||
4 | .24.11 | 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.(f) | ||
4 | .24.12 | 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.(f) | ||
4 | .24.13 | 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.(f) | ||
4 | .24.14 | 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.(f) | ||
4 | .24.15 | 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.(f) |
291
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Exhibit | ||||
Number | Description | |||
4 | .24.16 | 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.(f) | ||
4 | .24.17 | 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.(f) | ||
4 | .24.18 | 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.(f) | ||
4 | .24.19 | 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.(f) | ||
4 | .24.20 | 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.(f) | ||
4 | .24.21 | 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.(f) | ||
4 | .24.22 | 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.(f) | ||
4 | .24.23 | 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.(f) | ||
4 | .24.24 | 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.(f) | ||
4 | .24.25 | 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.(f) | ||
4 | .24.26 | 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.(f) | ||
4 | .24.27 | 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.(f) | ||
4 | .24.28 | 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.(f) |
292
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Exhibit | ||||
Number | Description | |||
4 | .24.29 | 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.(f) | ||
4 | .24.30 | 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.(f) | ||
4 | .24.31 | 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.(f) | ||
4 | .24.32 | 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.(f) | ||
4 | .24.33 | 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.(f) | ||
4 | .24.34 | 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.(f) | ||
4 | .24.35 | 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.(f) | ||
4 | .24.36 | 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.(f) | ||
4 | .24.37 | 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.(f) | ||
4 | .24.38 | 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.(f) | ||
10 | .1 | DIP Financing Agreements | ||
10 | .1.1.1 | $2,000,000,000 Amended & Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among the Company, as borrower, the Subsidiaries of the Company named therein, as guarantors, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Trust Company Americas, as Joint Syndication Agents, Deutsche Bank Securities Inc. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners, and Credit Suisse and Deutsche Bank Trust Company Americas, as Joint Administrative Agents.(*) |
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Number | Description | |||
10 | .1.1.2 | First Consent, Waiver and Amendment, dated as of May 3, 2006, to and under the Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, its subsidiaries named therein, as guarantors, the Lenders party thereto, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, Credit Suisse, Cayman Islands Branch, as administrative agent for the Second Priority Term Lenders.(*) | ||
10 | .1.2 | Amended and Restated Security and Pledge Agreement, dated as of February 23, 2006, among the Company, the Subsidiaries of the Company signatory thereto and Deutsche Bank Trust Company Americas, as collateral agent.(*) | ||
10 | .2 | Financing and Term Loan Agreements | ||
10 | .2.1 | 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.(o) | ||
10 | .2.2 | 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.(t) | ||
10 | .2.3.1 | 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.(r) | ||
10 | .2.3.2 | Amendment to Letter of Credit Agreement, dated as of September 30, 2004, between the Company and The Bank of Nova Scotia, as Administrative Agent.(y) | ||
10 | .2.4 | 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.(y) | ||
10 | .2.5 | 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.(r) | ||
10 | .2.6.1 | 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.(s) | ||
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.(s) | ||
10 | .2.6.3 | 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.(t) | ||
10 | .2.6.4 | 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.(t) |
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Number | Description | |||
10 | .2.6.5 | Amendment No. 4 to the Credit and Guarantee Agreement, dated as of March 15, 2006, 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.(*) | ||
10 | .2.6.6 | Waiver Agreement, dated as of March 15, 2006 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.(*) | ||
10 | .2.7 | 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.(t) | ||
10 | .2.8 | 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.(t) | ||
10 | .2.9 | 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.(z) | ||
10 | .2.10 | 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.(z) | ||
10 | .2.11 | 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.(z) | ||
10 | .3 | Security Agreements | ||
10 | .3.1 | 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.(r) | ||
10 | .3.2 | 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.(r) | ||
10 | .3.3 | 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.(r) | ||
10 | .3.4.1 | 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.(r) | ||
10 | .3.4.2 | 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.(t) | ||
10 | .3.5.1 | 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.(r) | ||
10 | .3.5.2 | 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.(t) |
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Exhibit | ||||
Number | Description | |||
10 | .3.6 | 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.(r) | ||
10 | .3.7.1 | 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.(r) | ||
10 | .3.7.2 | 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.(t) | ||
10 | .3.8 | 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.(r) | ||
10 | .3.9 | 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.(r) | ||
10 | .3.10 | 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.(r) | ||
10 | .3.11 | 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.(r) | ||
10 | .3.12 | 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.(r) | ||
10 | .3.13 | 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.(r) | ||
10 | .3.14 | 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.(r) | ||
10 | .3.15 | 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.(r) | ||
10 | .3.16 | 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.(r) | ||
10 | .3.17 | 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.(r) | ||
10 | .3.18 | 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.(r) | ||
10 | .3.19 | 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.(r) |
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Exhibit | ||||
Number | Description | |||
10 | .3.20 | 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.(r) | ||
10 | .3.21 | 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.(r) | ||
10 | .3.22 | 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.(t) | ||
10 | .4 | Power Purchase and Other Agreements. | ||
10 | .4.1 | Master Transaction Agreement, dated September 7, 2005, among the Company, Calpine Energy Services, L.P., The Bear Stearns Companies Inc., and such other parties as may become party thereto from time to time. Approximately two pages of this Exhibit 10.3.1 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(aa) | ||
10 | .4.2 | Power Purchase and Sale Agreements with the State of California Department of Water Resources comprising Amended and Restated Cover Sheet and Master Power Purchase and Sale Agreement, dated as of April 22, 2002 and effective as of May 1, 2004, between Calpine Energy Services, L.P. and the State of California Department of Water Resources together with Amended and Restated Confirmation (“Calpine 1”), Amended and Restated Confirmation (“Calpine 2”), Amended and Restated Confirmation (“Calpine 3”) and Amended and Restated Confirmation (“Calpine 4”), each dated as of April 22, 2002, and effective as of May 1, 2002, between Calpine Energy Services, L.P., and the State of California Department of Water Resources.(bb) | ||
10 | .5 | Management Contracts or Compensatory Plans or Arrangements. | ||
10 | .5.1 | Employment Agreement, effective as of January 1, 2005, between the Company and Mr. Peter Cartwright.(cc)(dd) | ||
10 | .5.2 | Employment Agreement, effective as of December 12, 2005, between the Company and Mr. Robert P. May.(*)(dd) | ||
10 | .5.3 | Employment Agreement, effective as of January 30, 2006, between the Company and Mr. Scott J. Davido.(*)(dd) | ||
10 | .5.5 | Consulting Contract, effective as of January 1, 2005, between the Company and Mr. George J. Stathakis.(hh)(dd) | ||
10 | .5.6 | Form of Indemnification Agreement for directors and officers.(gg)(dd) | ||
10 | .5.7 | Form of Indemnification Agreement for directors and officers.(f)(dd) | ||
10 | .5.8.1 | Calpine Corporation 1996 Stock Incentive Plan and forms of agreements there under.(t)(dd) | ||
10 | .5.8.2 | Amendment to Calpine Corporation 1996 Stock Incentive Plan.(z)(dd) | ||
10 | .5.9 | Calpine Corporation U.S. Severance Program.(*)(dd) | ||
10 | .5.10 | Base Salary, Bonus, Stock Option Grant and Restricted Stock Summary Sheet.(cc)(dd) | ||
10 | .5.11 | Form of Stock Option Agreement.(cc)(dd) | ||
10 | .5.12 | Form of Restricted Stock Agreement.(cc)(dd) | ||
10 | .5.13 | Calpine Corporation 2003 Management Incentive Plan.(hh)(dd) | ||
10 | .5.14 | 2000 Employee Stock Purchase Plan.(ii)(dd) | ||
12 | .1 | Statement on Computation of Ratio of Earnings to Fixed Charges.(*) | ||
21 | .1 | Subsidiaries of the Company.(*) | ||
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.(*) |
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Exhibit | ||||
Number | Description | |||
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, July 31, 2005 and December 31, 2004 and 2003.(*) |
(*) | 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 Current Report on Form 8-K filed with the SEC on June 23, 2005. |
(c) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on July 13, 2005. |
(d) | 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. |
(e) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2005, filed with the SEC on August 9, 2005. |
(f) | 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. |
(g) | 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. |
(h) | 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. |
(i) | 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. |
(j) | 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. |
(k) | 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. |
(l) | 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. |
(m) | 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. |
(n) | 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. |
(o) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 30, 2004. |
(p) | 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. |
(q) | 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. |
(r) | 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. |
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(s) | 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. |
(t) | 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. |
(u) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on October 6, 2004. |
(v) | 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. |
(w) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 23, 2005. |
(x) | 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. |
(y) | 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. |
(z) | Description of such Amendment is incorporated by reference to Item 1.01 of Calpine Corporation’s Current Report on Form 8-K filed with the SEC on September 20, 2005. |
(aa) | Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2005, filed with the SEC on November 9, 2005. |
(bb) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K/ A dated December 31, 2003, filed with the SEC on September 13, 2004 |
(cc) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on March 17, 2005. |
(dd) | Management contract or compensatory plan or arrangement. |
(ee) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on December 27, 2005. |
(ff) | Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K filed with the SEC on February 3, 2006. |
(gg) | 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. |
(hh) | Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 31, 2005. |
(ii) | 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. |
299