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þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the Fiscal Year ended December 31, 2007. | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the Transition period from to . |
Delaware | 41-1724239 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
211 Carnegie Center Princeton, New Jersey (Address of principal executive offices) | 08540 (Zip Code) |
Title of Each Class | Name of Exchange on Which Registered | |
Common Stock, par value $0.01 | New York Stock Exchange | |
5.75% Mandatory Convertible Preferred Stock | New York Stock Exchange |
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Class | Outstanding at February 25, 2008 | |
Common Stock, par value $0.01 per share | 236,442,274 |
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Acquisition | February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Company’s Texas region | |
AMA | Administrative Management Agreement between NRG Development Company, Inc. and West Coast Power, LLC | |
APB | Accounting Principles Board | |
APB 18 | APB Opinion No. 18,“The Equity Method of Accounting for Investments in Common Stock” | |
Average gross heat rate | The product of dividing (a) fuel consumed in BTU’s by (b) KWh generated | |
BART | Best Available Retrofit Technology | |
Baseload capacity | Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year | |
BTA | Best Technology Available | |
BTU | British Thermal Unit | |
CAA | Clean Air Act | |
CAIR | Clean Air Interstate Rule | |
CAISO | California Independent System Operator | |
CAMR | Clean Air Mercury Rule | |
Capacity factor | The ratio of the actual net electricity generated to the energy that could have been generated at continuous full-power operation during the year | |
Capital Allocation Program | Share repurchase program announced in August 2006 | |
CDWR | California Department of Water Resources | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act | |
CL&P | Connecticut Light & Power | |
CO2 | Carbon dioxide | |
COLA | Combined Construction and Operating License Application | |
CPUC | California Public Utilities Commission | |
DNREC | Delaware Department of Natural Resources and Environmental Control | |
DPUC | Department of Public Utility Control | |
EAF | Measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account |
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EFOR | Equivalent Forced Outage Rates — considers the equivalent impact that forced de-ratings have in addition to full forced outages | |
EITF | Emerging Issues Task Force | |
EITF02-3 | EITF IssueNo. 02-3,“Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” | |
EPAct of 2005 | Energy Policy Act of 2005 | |
EPC | Engineering, Procurement and Construction | |
ERCOT | Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas | |
ERO | Energy Reliability Organization | |
EWG | Exempt Wholesale Generator | |
Expected annual baseload generation | The net baseload capacity limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages) | |
FASB | Financial Accounting Standards Board, the designated organization for establishing standards for financial accounting and reporting | |
FCM | Forward Capacity Market | |
FERC | Federal Energy Regulatory Commission | |
FIN | FASB Interpretation | |
FIN 45 | FIN No. 45“Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” | |
FIP | Federal Implementation Plan | |
Fresh Start | Reporting requirements as defined bySOP 90-7 | |
GHG | Greenhouse Gases | |
Hedge Reset | Net settlement of long-term power contracts and gas swaps by negotiating prices to current market completed in November 2006 | |
ICT | Independent Coordinator of Transmission | |
IGCC | Integrated Gasification Combined Cycle | |
IRS | Internal Revenue Service | |
ISO | Independent System Operator, also referred to as Regional Transmission Organizations, or RTO | |
ISO-NE | ISO New England, Inc. | |
ITISA | Itiquira Energetica S.A. | |
kW | Kilowatts | |
kWh | Kilowatt-hours | |
LFRM | Locational Forward Reserve Market |
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LIBOR | London Inter-Bank Offer Rate | |
LMP | Locational Marginal Prices | |
MADEP | Massachusetts Department of Environmental Protection | |
Merit Order | A term used for the ranking of power stations in order of ascending marginal cost | |
MIBRAG | Mitteldeutsche Braunkohlengesellschaft mbH | |
Moody’s | Moody’s Investors Services, Inc., a credit rating agency | |
MMBtu | Million British Thermal Units | |
MRTU | Market Redesign and Technology Upgrade | |
MW | Megawatts | |
MWh | Saleable megawatt hours net of internal/parasitic loadmegawatt-hours | |
NAAQS | National Ambient Air Quality Standards | |
Net baseload capacity | Nominal summer net megawatt capacity of power generation adjusted for ownership and parasitic load, and excluding capacity from mothballed units as of December 31, 2007 | |
Net Capacity Factor | Net actual generation divided by net maximum capacity for the period hours | |
Net Generating Capacity | Nominal summer capacity, net of auxiliary power | |
New York Rest of State | New York State excluding New York City | |
NiMo | Niagara Mohawk Power Corporation | |
NOx | Nitrogen oxide | |
NOL | Net Operating Loss | |
NOV | Notice of Violation | |
NRC | United States Nuclear Regulatory Commission | |
NSR | New Source Review | |
NYPA | New York Power Authority | |
NYISO | New York Independent System Operator | |
NYSDEC | New York Department of Environmental Conservation | |
OCI | Other Comprehensive Income | |
OTC | Ozone Transport Commission | |
Phase II 316(b) Rule | A section of the Clean Water Act regulating cooling water intake structures | |
PJM | PJM Interconnection, LLC | |
PJM Market | The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia |
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PMI | NRG Power Marketing, LLC, a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manages all commodity trading and hedging for NRG | |
Powder River Basin, or PRB, Coal | Coal produced in the northeastern Wyoming and southeastern Montana, which has low sulfur content | |
PPA | Power Purchase Agreement | |
PSD | Prevention of Significant Deterioration | |
PUCT | Public Utility Commission of Texas | |
PUHCA | Public Utility Holding Company Act of 2005 | |
PURPA | Public Utility Regulatory Policy Act of 2005 | |
Repowering | Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency | |
RepoweringNRG | NRG’s program designed to develop, finance, construct and operate new, highly efficient, environmentally responsible capacity over the next decade | |
RFP | Request for proposal | |
RGGI | Regional Greenhouse Gas Initiative | |
RMR | Reliability Must-Run | |
ROIC | Return on invested capital | |
RTO | Regional Transmission Organization, also referred to as an ISO | |
S&P | Standard & Poor’s, a credit rating agency | |
SARA | Superfund Amendments and Reauthorization Act of 1986 | |
Sarbanes-Oxley | Sarbanes — Oxley Act of 2002 | |
Schkopau | Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which NRG has a 41.9% interest | |
SCR | Selective Catalytic Reduction | |
SEC | United States Securities and Exchange Commission | |
SERC | Southeastern Electric Reliability Council/Entergy | |
SFAS | Statement of Financial Accounting Standards issued by the FASB | |
SFAS 71 | SFAS No. 71,“Accounting for the Effects of Certain Types of Regulation” | |
SFAS 87 | SFAS No. 87,“Employers’ Accounting for Pensions” | |
SFAS 106 | SFAS No. 106,“Employers’ Accounting for Postretirement Benefits Other Than Pensions” | |
SFAS 109 | SFAS No. 109,“Accounting for Income Taxes” | |
SFAS 123 | SFAS No. 123,“Accounting for Stock-Based Compensation” |
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SFAS 123R | SFAS No. 123 (revised 2004),“Share-Based Payment” | |
SFAS 133 | SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities” as amended | |
SFAS 142 | SFAS No. 142,“Goodwill and Other Intangible Assets” | |
SFAS 143 | SFAS No. 143,“Accounting for Asset Retirement Obligations” | |
SFAS 144 | SFAS No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets” | |
SFAS 157 | SFAS No. 157,“Fair Value Measurement” | |
SFAS 158 | SFAS No. 158,“Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” | |
SO2 | Sulfur dioxide | |
SOP | Statement of Position issued by the American Institute of Certified Public Accountants | |
SOP 90-7 | Statement of Position90-7,“Financial Reporting by Entities in Reorganization Under the Bankruptcy Code” | |
STP | South Texas Project — Nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest | |
STPNOC | South Texas Project Nuclear Operating Company | |
TCEQ | Texas Commission on Environmental Quality | |
Texas Genco | Texas Genco LLC, now referred to as the Company’s Texas region | |
Tonnes | Metric tonnes, which are units of mass or weight in the metric system each equal to 2,205 lbs and are the global measurement for GHG | |
Uprate | A sustainable increase in the electrical rating of a generating facility | |
US | United States of America | |
USEPA | United States Environmental Protection Agency | |
U.S. GAAP | Accounting principles generally accepted in the United States | |
VAR | Value at Risk | |
VOC | Volatile Organic Carbon | |
WCP | WCP (Generation) Holdings, Inc. |
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Item 1 — | Business |
I. | FORNRGis a companywide effort, introduced in 2005, and is designed to increase the return on invested capital, or ROIC, through operational performance improvements to the Company’s asset fleet, along with a range of initiatives at plants and at corporate offices to reduce costs or, in some cases, generate revenue. TheFORNRG earnings accomplishments disclosed in NRG’s SEC filings and press releases include both recurring and one time improvements measured from a 2004 baseline, with the exception of the Texas region where benefits are measured using 2005 as the base year. For plant operations, the program measures cumulative current year benefits using current gross margins times the change in baseline levels of certain key performance indicators. The plant performance benefits include both positive and negative results for plant reliability, capacity, heat rate and station service.FORNRG contributed $39 million to pre-tax earnings in 2005 and $144 million were achieved through the end of 2006. For 2007, the Company attained its previously announced target of $220 million which includes $11 million of one-time benefits. |
lI. | RepoweringNRGis a comprehensive portfolio redevelopment program designed to develop, construct and operate new multi-fuel, multi-technology, highly efficient and environmentally responsible generation capacity over the next decade. Through this initiative, the Company anticipates retiring certain existing units and adding new generation to meet growing demand in the Company’s core markets, with an emphasis on new baseload capacity that is expected to be supported by long-term power purchase agreements, or PPAs, and financed with limited or non-recourse project financing. |
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llI. | econrgrepresents NRG’s commitment to environmentally responsible power generation. econrg seeks to find ways to meet the challenges of climate change, clean air and water, and protecting our natural resources while taking advantage of business opportunities. This initiative builds upon its foundation in environmental compliance and embraces environmental initiatives for the benefit of our communities, employees and shareholders, such as encouraging investment in new environmental technologies, pursuing activities that preserve and protect the environment and encouraging changes in the daily lives of our employees. |
IV. | Future NRGis the Company’s workforce planning and development initiative and represents NRG’s strong commitment to planning for future staffing requirements to meet the on-going needs of the Company’s current operations in addition to the Company’sRepoweringNRG initiatives. Future NRG encompasses analyzing the demographics, skill set and size of the Company’s workforce in addition to the organizational structure with a focus on succession planning requirements, training, development, staffing and recruiting needs. Included under the Future NRG umbrella is NRG University, which develops leadership, managerial, supervisory and technical training programs and includes individual skill development courses. |
V. | NRG Global Giving- Respect for the community is one of NRG’s core values. NRG’s Global Giving Program invests the Company’s resources to strengthen the communities where NRG does business and seeks to make investments in four focus areas: community and economic development, education, environment and human welfare. |
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Risk | Total | |||||||||||||||||||||||||||
Energy | Capacity | Management | Contract | Thermal | Other | Operating | ||||||||||||||||||||||
Region | Revenues | Revenues | Activities | Amortization | Revenues | Revenues | Revenues | |||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||
Texas | $ | 2,698 | $ | 363 | $ | (33 | ) | $ | 219 | $ | — | $ | 40 | $ | 3,287 | |||||||||||||
Northeast | 1,104 | 402 | 27 | — | — | 72 | 1,605 | |||||||||||||||||||||
South Central | 404 | 221 | 10 | 23 | — | — | 658 | |||||||||||||||||||||
West | 4 | 122 | — | — | — | 1 | 127 | |||||||||||||||||||||
International | 42 | 83 | — | — | — | 15 | 140 | |||||||||||||||||||||
Thermal | 13 | 5 | — | — | 125 | 16 | 159 | |||||||||||||||||||||
Corporate/Eliminations | — | — | — | — | — | 13 | 13 | |||||||||||||||||||||
Total | $ | 4,265 | $ | 1,196 | $ | 4 | $ | 242 | $ | 125 | $ | 157 | $ | 5,989 | ||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||||||
Annual | ||||||||||||||||||||
Net | Equivalent | Average Net | ||||||||||||||||||
Net Owned | Generation | Availability | Heat Rate | Net Capacity | ||||||||||||||||
Region | Capacity (MW) | (MWh) | Factor | Btu/kWh | Factor | |||||||||||||||
(In thousands of MWh) | ||||||||||||||||||||
Texas | 10,805 | 47,779 | 87.6 | % | 10,300 | 50.7 | % | |||||||||||||
Northeast(a) | 6,980 | 14,163 | 83.6 | 10,900 | 21.2 | |||||||||||||||
South Central | 2,850 | 10,930 | 89.0 | 10,200 | 46.1 | |||||||||||||||
West | 2,130 | 1,246 | 89.9 | % | 11,200 | 9.3 | % |
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Year Ended December 31, 2006 | ||||||||||||||||||||
Annual | ||||||||||||||||||||
Net | Equivalent | Average Net | ||||||||||||||||||
Net Owned | Generation | Availability | Heat Rate | Net Capacity | ||||||||||||||||
Region | Capacity (MW) | (MWh) | Factor | Btu/kWh | Factor | |||||||||||||||
(In thousands of MWh) | ||||||||||||||||||||
Texas(b) | 10,760 | 44,910 | 91.0 | % | 10,300 | 41.0 | % | |||||||||||||
Northeast(a) | 7,240 | 13,309 | 85.8 | 10,900 | 18.8 | |||||||||||||||
South Central | 2,850 | 11,036 | 94.3 | 10,400 | 47.2 | |||||||||||||||
West(c) | 1,965 | 1,901 | 89.1 | % | 11,400 | 15.1 | % |
(a) | Factor data and heat rate does not include the Keystone and Conemaugh facilities. | |
(b) | For the period February 2, 2006 through December 31, 2006. | |
(c) | Includes fully consolidated results of WCP for the period April 1, 2006 — December 31, 2006. |
(1) | Includes 115 MW as part of NRG’s Thermal assets. For combined scale, approximately 3,450 MW is dual-fuel capable. Reflects only domestic generation capacity as of December 31, 2007. |
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Annual | ||||||||||||||||||||||||||||
Average for | ||||||||||||||||||||||||||||
2008 | 2009 | 2010 | 2011 | 2012 | 2013 | 2008-2013 | ||||||||||||||||||||||
(In millions unless otherwise stated) | ||||||||||||||||||||||||||||
Net Baseload Capacity (MW) | 8,685 | 8,685 | 8,523 | 8,443 | 8,416 | 8,416 | 8,528 | |||||||||||||||||||||
Forecasted Baseload Capacity (MW) | 7,497 | 7,387 | 7,335 | 7,241 | 7,331 | 7,309 | 7,350 | |||||||||||||||||||||
Total Baseload Sales (MW)(a) | 7,390 | 5,416 | 4,066 | 4,206 | 1,543 | 1,005 | 3,938 | |||||||||||||||||||||
Percentage Baseload Capacity Sold Forward(b) | 99 | % | 73 | % | 55 | % | 58 | % | 21 | % | 14 | % | 54 | % | ||||||||||||||
Total Forward Hedged Revenues(c)(d) | $ | 3,701 | $ | 2,735 | $ | 2,000 | $ | 1,959 | $ | 644 | $ | 392 | $ | 1,905 | ||||||||||||||
Weighted Average Hedged Price ($ per MWh)(c) | $ | 57 | $ | 58 | $ | 56 | $ | 53 | $ | 47 | $ | 45 | $ | 53 | ||||||||||||||
Weighted Average Hedged Price ($ per MWh) excluding South Central region(d) | $ | 60 | $ | 61 | $ | 60 | $ | 56 | $ | 54 | $ | — | $ | 58 | ||||||||||||||
Average Equivalent Natural Gas Price ($ per MMBtu)(e) | $ | 7.30 | $ | 7.43 | $ | 7.27 | $ | 6.84 | $ | 6.33 | $ | 6.10 | $ | 6.88 | ||||||||||||||
Average Equivalent Natural Gas Price ($ per MMBtu) excluding South Central region(e) | $ | 7.50 | $ | 7.70 | $ | 7.49 | $ | 7.03 | $ | 6.70 | $ | — | $ | 6.07 |
(a) | Includes amounts under fixed price power sales contracts and amounts financially hedged under natural gas contracts. The forward natural gas quantities are reflected in equivalent MWh and are derived by first dividing the quantity of MMBtu of natural gas hedged by the forward market implied heat rate as of December 31, 2007 to arrive at the equivalent MWh hedged which is then divided by 8,760 hours (total hours in a year) to arrive at MW hedged. | |
(b) | Percentage hedged is based on total MW sold as power and natural gas converted using the method as described in (a) above divided by the forecasted baseload capacity. | |
(c) | Represents all North American baseload sales including power contract prices in the Texas and South Central regions which are comprised of a fixed demand charge exclusive of a fixed energy charge, with the transaction price related to these contracts being the sum of both charges. | |
(d) | The South Central region’s weighted average hedged prices ranges from $40/MWh — $45/MWh due to legacy cooperative load contracts entered into at prices significantly below current market levels. These prices include a fixed capacity charge and an estimated energy charge. | |
(e) | The weighted average hedged price in natural gas equivalents is derived by first multiplying the quantity of MWh of power hedged by the forward market implied heat rate as of December 31, 2007 to arrive at the equivalent MMBtu hedged which is then added with the financially hedged gas quantity. This total quantity in MMBtu is then used to divide the total revenues from all baseload sales to arrive at the weighted average hedged price in natural gas equivalents. |
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Percentage of | ||||
Company’s | ||||
Requirement(1) | ||||
2008 | 99 | % | ||
2009 | 86 | % | ||
2010 | 58 | % | ||
2011 | 52 | % | ||
2012 | 45 | % | ||
2013 | 15 | % |
(1) | The hedge percentages reflect the current plan for the Jewett mine. NRG has the contractual ability to change volumes and may do so in the future. |
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Texas | Northeast | South Central | Total | |||||||||||||
(In millions) | ||||||||||||||||
2008 | $ | 3 | $ | 223 | $ | 133 | $ | 359 | ||||||||
2009 | 5 | 192 | 211 | 408 | ||||||||||||
2010 | 24 | 178 | 117 | 319 | ||||||||||||
2011 | 28 | 112 | 53 | 193 | ||||||||||||
2012 | 11 | 66 | 15 | 92 | ||||||||||||
Total | $ | 71 | $ | 771 | $ | 529 | $ | 1,371 | ||||||||
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Net Generation | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(In thousands of MWh) | ||||||||||||
Coal | 32,648 | 31,371 | 31,299 | |||||||||
Gas | 5,407 | 7,983 | 6,806 | |||||||||
Nuclear(a) | 9,724 | 9,385 | 6,412 | |||||||||
Total | 47,779 | 48,739 | 44,517 | |||||||||
(a) | MWh information reflects the undivided interest in total MWh generated by STP. On May 19, 2005, Texas Genco LLC increased its undivided interest in STP from 30.8% to 44.0%. |
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Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary | |||||||||||
Plant | Location | % Owned | (MW)(c) | Fuel-type | ||||||||
Solid Fuel Baseload Units: | ||||||||||||
W. A. Parish(a) | Thompsons, TX | 100.0 | 2,460 | Coal | ||||||||
Limestone | Jewett, TX | 100.0 | 1,690 | Lignite/Coal | ||||||||
South Texas Project(b) | Bay City, TX | 44.0 | 1,175 | Nuclear | ||||||||
Total Solid Fuel Baseload | 5,325 | |||||||||||
Operating Natural Gas-Fired Units: | ||||||||||||
Cedar Bayou | Baytown, TX | 100.0 | 1,500 | Natural Gas | ||||||||
T. H. Wharton | Houston, TX | 100.0 | 1,025 | Natural Gas | ||||||||
W. A. Parish(a) | Thompsons, TX | 100.0 | 1,190 | Natural Gas | ||||||||
S. R. Bertron | Deer Park, TX | 100.0 | 840 | Natural Gas | ||||||||
Greens Bayou | Houston, TX | 100.0 | 760 | Natural Gas | ||||||||
San Jacinto | LaPorte, TX | 100.0 | 165 | Natural Gas | ||||||||
Total Operating Natural Gas-Fired | 5,480 | |||||||||||
Total Operating Capacity | 10,805 | |||||||||||
(a) | W. A. Parish has nine units, four of which are baseload coal-fired units and five of which are natural gas-fired units. | |
(b) | Generation capacity figure consists of the Company’s 44.0% undivided interest in the two units at STP. | |
(c) | Actual capacity can vary depending on factors including weather conditions, operational conditions and other factors. ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time. Excludes 2,200 MW of mothballed capacity available for redevelopment. |
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Net Generation | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(In thousands of MWh) | ||||||||||||
Coal | 11,527 | 11,042 | 11,363 | |||||||||
Oil | 1,169 | 1,217 | 3,148 | |||||||||
Gas | 1,467 | 1,050 | 1,735 | |||||||||
Total | 14,163 | 13,309 | 16,246 | |||||||||
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Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary | |||||||||||
Plant | Location | % Owned | (MW) | Fuel-type | ||||||||
Oswego | Oswego, NY | 100.0 | 1,635 | Oil | ||||||||
Arthur Kill | Staten Island, NY | 100.0 | 865 | Natural Gas | ||||||||
Middletown | Middletown, CT | 100.0 | 770 | Oil | ||||||||
Indian River | Millsboro, DE | 100.0 | 740 | Coal | ||||||||
Astoria Gas Turbines | Queens, NY | 100.0 | 550 | Natural Gas | ||||||||
Huntley | Tonawanda, NY | 100.0 | 380 | Coal | ||||||||
Dunkirk | Dunkirk, NY | 100.0 | 530 | Coal | ||||||||
Montville | Uncasville, CT | 100.0 | 500 | Oil | ||||||||
Norwalk Harbor | So. Norwalk, CT | 100.0 | 340 | Oil | ||||||||
Devon | Milford, CT | 100.0 | 140 | Natural Gas | ||||||||
Vienna | Vienna, MD | 100.0 | 170 | Oil | ||||||||
Somerset Power | Somerset, MA | 100.0 | 125 | Coal | ||||||||
Connecticut Remote Turbines | Four locations in CT | 100.0 | 105 | Oil | ||||||||
Conemaugh | New Florence, PA | 3.7 | 65 | Coal | ||||||||
Keystone | Shelocta, PA | 3.7 | 65 | Coal | ||||||||
Total Northeast Region | 6,980 | |||||||||||
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Net Generation | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
(In thousands of MWh) | ||||||||||||
Coal | 10,812 | 10,968 | 9,924 | |||||||||
Gas | 118 | 68 | 85 | |||||||||
Total | 10,930 | 11,036 | 10,009 | |||||||||
Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary Fuel | |||||||||||
Plant | Location | % Owned | (MW) | type | ||||||||
Big Cajun II(a) | New Roads, LA | 86.0 | 1,490 | Coal | ||||||||
Bayou Cove | Jennings, LA | 100.0 | 300 | Natural Gas | ||||||||
Big Cajun I — (Peakers) Units 3 & 4 | Jarreau, LA | 100.0 | 210 | Natural Gas | ||||||||
Big Cajun I — Units 1 & 2 | Jarreau, LA | 100.0 | 220 | Natural Gas/Oil | ||||||||
Rockford I | Rockford, IL | 100.0 | 300 | Natural Gas | ||||||||
Rockford II | Rockford, IL | 100.0 | 145 | Natural Gas | ||||||||
Sterlington | Sterlington, LA | 100.0 | 185 | Natural Gas | ||||||||
Total South Central | 2,850 | |||||||||||
(a) | NRG owns 100% of Units 1 & 2; 58% of Unit 3 |
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Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary | |||||||||||
Plant | Location | % Owned | (MW) | Fuel-type | ||||||||
Encina | Carlsbad, CA | 100.0 | 965 | Natural Gas | ||||||||
El Segundo | El Segundo, CA | 100.0 | 670 | Natural Gas | ||||||||
Long Beach | Long Beach, CA | 100.0 | 260 | Natural Gas | ||||||||
Cabrillo II | San Diego, CA | 100.0 | 190 | Natural Gas | ||||||||
Saguaro | Henderson, NV | 50.0 | 45 | Natural Gas | ||||||||
Total West Region | 2,130 | |||||||||||
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Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary | |||||||||||
Plant | Location | % Owned | (MW) | Fuel-type | ||||||||
Gladstone | Australia | 37.5 | 605 | Coal | ||||||||
Schkopau | Germany | 41.9 | 400 | Lignite | ||||||||
MIBRAG | Germany | 50.0 | 75 | Lignite | ||||||||
ITISA(a) | Brazil | 99.2 | 155 | Hydro | ||||||||
Total International | 1,235 | |||||||||||
(a) | NRG entered into an agreement to sell ITISA on December 18, 2007. The sale is subject to regulatory and customary closing conditions. |
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Item 1A — | Risk Factors Related to NRG Energy, Inc. |
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• | increases and decreases in generation capacity in the Company’s markets, including the addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity; | |
• | changes in power transmission or fuel transportation capacity constraints or inefficiencies; | |
• | electric supply disruptions, including plant outages and transmission disruptions; | |
• | heat rate risk; | |
• | weather conditions; | |
• | changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices; | |
• | development of new fuels and new technologies for the production of power; | |
• | regulations and actions of the ISOs; and | |
• | federal and state power market and environmental regulation and legislation. |
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• | weather conditions; | |
• | seasonality; | |
• | demand for energy commodities and general economic conditions; | |
• | disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation; | |
• | additional generating capacity; | |
• | availability and levels of storage and inventory for fuel stocks; | |
• | natural gas, crude oil, refined products and coal production levels; | |
• | changes in market liquidity; | |
• | federal, state and foreign governmental regulation and legislation; and | |
• | the creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with the Company. |
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• | delays in obtaining necessary permits and licenses; | |
• | environmental remediation of soil or groundwater at contaminated sites; | |
• | interruptions to dispatch at the Company’s facilities; | |
• | supply interruptions; |
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• | work stoppages; | |
• | labor disputes; | |
• | weather interferences; | |
• | unforeseen engineering, environmental and geological problems; | |
• | unanticipated cost overruns; | |
• | exchange rate risks; and | |
• | performance risks. |
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• | fluctuations in currency valuation; | |
• | currency inconvertibility; | |
• | expropriation and confiscatory taxation; | |
• | restrictions on the repatriation of capital; and | |
• | approval requirements and governmental policies limiting returns to foreign investors. |
• | increasing NRG’s vulnerability to general economic and industry conditions; | |
• | requiring a substantial portion of NRG’s cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing NRG’s ability to pay dividends to holders of its preferred or common stock or to use its cash flow to fund its operations, capital expenditures and future business opportunities; | |
• | limiting NRG’s ability to enter into long-term power sales or fuel purchases which require credit support; | |
• | exposing NRG to the risk of increased interest rates because certain of its borrowings, including borrowings under its new senior secured credit facility are at variable rates of interest; | |
• | limiting NRG’s ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and |
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• | limiting NRG’s ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to its competitors who have less debt. |
• | general economic and capital market conditions; | |
• | credit availability from banks and other financial institutions; | |
• | investor confidence in NRG, its partners and the regional wholesale power markets; | |
• | NRG’s financial performance and the financial performance of its subsidiaries; | |
• | NRG’s level of indebtedness and compliance with covenants in debt agreements; | |
• | maintenance of acceptable credit ratings; | |
• | cash flow; and | |
• | provisions of tax and securities laws that may impact raising capital. |
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• | General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel; | |
• | Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards; | |
• | The effectiveness of NRG’s risk management policies and procedures, and the ability of NRG’s counterparties to satisfy their financial commitments; | |
• | Counterparties’ collateral demands and other factors affecting NRG’s liquidity position and financial condition; | |
• | NRG’s ability to operate its businesses efficiently, manage capital expenditures and costs tightly (including general and administrative expenses), and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations; | |
• | NRG’s potential inability to enter into contracts to sell power and procure fuel on acceptable terms and prices; | |
• | The liquidity and competitiveness of wholesale markets for energy commodities; | |
• | Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other greenhouse gas emissions; | |
• | Price mitigation strategies and other market structures employed by independent system operators, or ISOs, or regional transmission organizations, or RTOs, that result in a failure to adequately compensate NRG’s generation units for all of its costs; | |
• | NRG’s ability to borrow additional funds and access capital markets, as well as NRG’s substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward; | |
• | Operating and financial restrictions placed on NRG contained in the indentures governing NRG’s outstanding notes in NRG’s senior credit facility and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally; | |
• | NRG’s ability to implement itsRepoweringNRG strategy of developing and building new power generation facilities, including new nuclear units and Integrated Gasification Combined Cycle, or IGCC, units; | |
• | NRG’s ability to implement its econrg strategy of finding ways to meet the challenges of climate change, clean air and protecting our natural resources while taking advantage of business opportunities; and | |
• | NRG’s ability to achieve its strategy of regularly returning capital to shareholders. |
Item 1B — | Unresolved Staff Comments |
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Item 2 — | Properties |
Net | ||||||||||||
Power | Generation | |||||||||||
Name and Location of Facility | Market | % Owned | Capacity(MW) | Primary Fuel-type | ||||||||
Texas Region: | ||||||||||||
W. A. Parish, Thompsons, Texas | ERCOT | 100.0 | 2,460 | Coal | ||||||||
Limestone, Jewett, Texas | ERCOT | 100.0 | 1,690 | Lignite/Coal | ||||||||
South Texas Project, Bay City, Texas(a) | ERCOT | 44.0 | 1,175 | Nuclear | ||||||||
Cedar Bayou, Baytown, Texas | ERCOT | 100.0 | 1,500 | Natural Gas | ||||||||
T. H. Wharton, Houston, Texas | ERCOT | 100.0 | 1,025 | Natural Gas | ||||||||
W. A. Parish, Thompsons, Texas | ERCOT | 100.0 | 1,190 | Natural Gas | ||||||||
S. R. Bertron, Deer Park, Texas | ERCOT | 100.0 | 840 | Natural Gas | ||||||||
Greens Bayou, Houston, Texas | ERCOT | 100.0 | 760 | Natural Gas | ||||||||
San Jacinto, LaPorte, Texas | ERCOT | 100.0 | 165 | Natural Gas | ||||||||
Northeast Region: | ||||||||||||
Oswego, New York | NYISO | 100.0 | 1,635 | Oil | ||||||||
Arthur Kill, Staten Island, New York | NYISO | 100.0 | 865 | Natural Gas | ||||||||
Middletown, Connecticut | ISO-NE | 100.0 | 770 | Oil | ||||||||
Indian River, Millsboro, Delaware | PJM | 100.0 | 740 | Coal | ||||||||
Astoria Gas Turbines, Queens, New York | NYISO | 100.0 | 550 | Natural Gas | ||||||||
Dunkirk, New York | NYISO | 100.0 | 530 | Coal | ||||||||
Huntley, Tonawanda, New York | NYISO | 100.0 | 380 | Coal | ||||||||
Montville, Uncasville, Connecticut | ISO-NE | 100.0 | 500 | Oil | ||||||||
Norwalk Harbor, So. Norwalk, Connecticut | ISO-NE | 100.0 | 340 | Oil | ||||||||
Devon, Milford, Connecticut | ISO-NE | 100.0 | 140 | Natural Gas | ||||||||
Vienna, Maryland | PJM | 100.0 | 170 | Oil | ||||||||
Somerset, Massachusetts | ISO-NE | 100.0 | 125 | Coal |
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Net | ||||||||||||
Power | Generation | |||||||||||
Name and Location of Facility | Market | % Owned | Capacity(MW) | Primary Fuel-type | ||||||||
Connecticut Jet Power, Connecticut (four sites) | ISO-NE | 100.0 | 105 | Oil | ||||||||
Conemaugh, New Florence, Pennsylvania | PJM | 3.7 | 65 | Coal | ||||||||
Keystone, Shelocta, Pennsylvania | PJM | 3.7 | 65 | Coal | ||||||||
South Central Region: | ||||||||||||
Big Cajun II, New Roads, Louisiana(b) | SERC-Entergy | 86.0 | 1,490 | Coal | ||||||||
Bayou Cove, Jennings, Louisiana | SERC-Entergy | 100.0 | 300 | Natural Gas | ||||||||
Big Cajun I, Jarreau, Louisiana | SERC-Entergy | 100.0 | 210 | Natural Gas | ||||||||
Big Cajun I, Jarreau, Louisiana | SERC-Entergy | 100.0 | 220 | Natural Gas/Oil | ||||||||
Rockford I, Illinois | PJM | 100.0 | 300 | Natural Gas | ||||||||
Rockford II, Illinois | PJM | 100.0 | 145 | Natural Gas | ||||||||
Sterlington, Louisiana | SERC-Entergy | 100.0 | 185 | Natural Gas | ||||||||
West Region: | ||||||||||||
Encina, Carlsbad, California | Cal ISO | 100.0 | 965 | Natural Gas | ||||||||
El Segundo Power, California | Cal ISO | 100.0 | 670 | Natural Gas | ||||||||
San Diego Combustion Turbines, California (three sites) | Cal ISO | 100.0 | 190 | Natural Gas | ||||||||
Saguaro Power Co., Henderson, Nevada | WECC | 50.0 | 45 | Natural Gas | ||||||||
Long Beach, California | CAISO | 100.0 | 260 | Natural Gas | ||||||||
International Region: | ||||||||||||
Gladstone Power | Enertrade/Boyne | |||||||||||
Station, Queensland, Australia | Smelters | 37.5 | 605 | Coal | ||||||||
Schkopau Power Station, Germany | Vattenfall Europe | 41.9 | 400 | Lignite | ||||||||
MIBRAG, Germany(c) | Schkopau & Lippendorf/ ENVIA | 50.0 | 75 | Lignite | ||||||||
ITISA, Brazil(d) | COPEL | 99.2 | 155 | Hydro |
(a) | For the nature of NRG’s interest and various limitations on the Company’s interest, please read Item 1 — Business — Texas — Generation Facilities section | |
(b) | Units 1 and 2 owned 100.0%, Unit 3 owned 58.0% | |
(c) | Primarily a coal mining facility | |
(d) | On December 18, 2007, NRG entered into a sale and purchase agreement to sell its interest in ITISA to Brookfield Power, a wholly-owned subsidiary of Brookfield Asset Management Inc., for a purchase price of approximately $288 million, plus the assumption of approximately $60 million in debt, subject to regulatory approvals and other closing conditions. NRG anticipates completion of the sale transactions during the first half 2008 as discussed in Item 15 — Note 3, Discontinued Operations, Business Acquisitions and Dispositions. |
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% | ||||||||
Ownership | ||||||||
Name and Location of Facility | Thermal Energy Purchaser | Interest | Generating Capacity | |||||
NRG Energy Center Minneapolis, Minnesota | Approx. 100 steam customers and 50 chilled water customers | 100.0 | Steam: 1,203 MMBtu/hr. (353 MWt) Chilled Water: 42,630 tons (150 MWt) | |||||
NRG Energy Center San Francisco, California | Approx. 170 steam customers | 100.0 | Steam: 454 MMBtu/Hr. (133 MWt) | |||||
NRG Energy Center Harrisburg, Pennsylvania | Approx. 230 steam customers and 3 chilled water customers | 100.0 | Steam: 440 MMBtu/hr. (129 MWt) Chilled water: 2,400 tons (8 MWt) | |||||
NRG Energy Center Pittsburgh, Pennsylvania | Approx. 25 steam and 25 chilled water customers | 100.0 | Steam: 266 MMBtu/hr. (78 MWt) Chilled water: 12,920 tons (45 MWt) | |||||
NRG Energy Center San Diego, California | Approx. 20 chilled water customers | 100.0 | Chilled water: 7,425 tons (26 MWt) | |||||
Camas Power Boiler Camas, Washington | Georgia-Pacific Corp. | 100.0 | Steam: 200 MMBtu/hr. (59 MWt) | |||||
NRG Energy Center Dover, Delaware | Kraft Foods Inc. | 100.0 | Steam: 190 MMBtu/hr. (56 MWt) | |||||
Paxton Creek Cogeneration, Harrisburg, Pennsylvania | PJM | 100.0 | 12 MW — Natural Gas | |||||
Dover Cogeneration, Delaware | PJM | 100.0 | 104 MW — Natural Gas/Coal |
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Item 3 — | Legal Proceedings |
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Item 4 — | Submission of Matters to a Vote of Security Holders |
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Item 5 — | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Fourth | Third | Second | First | Fourth | Third | Second | First | |||||||||||||||||||||||||
Common Stock | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | ||||||||||||||||||||||||
Price | 2007 | 2007 | 2007 | 2007 | 2006 | 2006 | 2006 | 2006 | ||||||||||||||||||||||||
High | $ | 47.19 | $ | 45.08 | $ | 45.93 | $ | 37.10 | $ | 29.74 | $ | 25.58 | $ | 26.31 | $ | 24.73 | ||||||||||||||||
Low | 38.79 | 34.76 | 35.98 | $ | 27.22 | 22.14 | 22.13 | 21.22 | 20.90 | |||||||||||||||||||||||
Closing | $ | 43.34 | $ | 42.29 | $ | 41.57 | $ | 36.02 | $ | 28.00 | $ | 22.65 | $ | 24.09 | $ | 22.61 |
Total Number | ||||||||||||||||
of Shares | ||||||||||||||||
Purchased as | Dollar Value of | |||||||||||||||
Part of Publicly | Shares that may be | |||||||||||||||
Total Number of | Average Price | Announced Plans | Purchased Under the | |||||||||||||
For the Year Ended December 31, 2007 | Shares Purchased | Paid per Share | or Programs | Plans or Programs | ||||||||||||
First quarter | 3,000,000 | $ | 34.38 | 3,000,000 | $ | 165,160,714 | ||||||||||
Second quarter | 2,669,200 | 42.16 | 2,669,200 | 52,613,935 | ||||||||||||
Third quarter | 1,337,500 | 39.38 | 1,337,500 | — | ||||||||||||
Fourth quarter | 2,037,700 | 41.82 | — | — | ||||||||||||
Total for 2007 | 9,044,400 | $ | 39.09 | 7,006,700 | ||||||||||||
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(c) | ||||||||||||
Number of Securities | ||||||||||||
(a) | Remaining Available | |||||||||||
Number of Securities | (b) | for Future Issuance | ||||||||||
to be Issued Upon | Weighted-Average Exercise | Under Compensation | ||||||||||
Exercise of | Price of Outstanding | Plans (Excluding | ||||||||||
Outstanding Options, | Options, Warrants and | Securities Reflected | ||||||||||
Plan Category | Warrants and Rights | Rights | in Column(a) | |||||||||
Equity compensation plans approved by security holders | 7,180,589 | $ | 19.98 | 7,941,758 | (a) | |||||||
Equity compensation plans not approved by security holders | — | N/A | — | |||||||||
Total | 7,180,589 | $ | 19.98 | 7,941,758 | (a) | |||||||
(a) | NRG Energy, Inc.’s Long-Term Incentive Plan, or the LTIP, became effective upon the Company’s emergence from bankruptcy. The LTIP was subsequently approved by the Company’s stockholders on August 4, 2004 and was amended on April 28, 2006 to increase the number of shares available for issuance to 16,000,000, on a post-split basis, and again on December 8, 2006 to make technical and administrative changes. The LTIP provides for grants of stock options, stock appreciation rights, restricted stock, performance units, deferred stock units and dividend equivalent rights. NRG’s directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the LTIP. The purpose of the LTIP is to promote the Company’s long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company’s success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the LTIP. There were 7,941,758 and 8,602,978 shares of common stock remaining available for grants of awards under NRG’s LTIP as of December 31, 2007 and 2006, respectively. |
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Jan-2004 | Dec-2004 | Dec-2005 | Dec-2006 | Dec-2007 | |||||||||||||||||||||
NRG Energy, Inc. | $ | 100.00 | $ | 160.58 | $ | 209.89 | $ | 249.49 | $ | 386.10 | |||||||||||||||
S&P 500 | 100.00 | 111.22 | 116.68 | 135.11 | 142.53 | ||||||||||||||||||||
UTY | $ | 100.00 | $ | 126.23 | $ | 149.50 | $ | 179.67 | $ | 213.76 | |||||||||||||||
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Item 6 — | Selected Financial Data |
Reorganized NRG | Predecessor Company | |||||||||||||||||||||||
December 6 – | January 1 – | |||||||||||||||||||||||
Year Ended December 31, | December 31, | December 5, | ||||||||||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | 2003 | |||||||||||||||||||
(In millions except ratio and per share data) | ||||||||||||||||||||||||
Statement of income data: | ||||||||||||||||||||||||
Total operating revenues | $ | 5,989 | $ | 5,585 | $ | 2,400 | $ | 2,080 | $ | 120 | $ | 1,570 | ||||||||||||
Total operating costs and expenses | 5,060 | 4,720 | 2,290 | 1,848 | 109 | (1,671 | ) | |||||||||||||||||
Income from continuing operations, net | 569 | 543 | 68 | 157 | 12 | 3,180 | ||||||||||||||||||
Income/(loss) from discontinued operations, net | 17 | 78 | 16 | 29 | (1 | ) | (414 | ) | ||||||||||||||||
Net income | 586 | 621 | 84 | 186 | 11 | 2,766 | ||||||||||||||||||
Common share data: | ||||||||||||||||||||||||
Basic shares outstanding — average | 240 | 258 | 169 | 199 | 200 | |||||||||||||||||||
Diluted shares outstanding — average | 288 | 301 | 171 | 201 | 200 | |||||||||||||||||||
Shares outstanding — end of year | 237 | 245 | 161 | 174 | 200 | |||||||||||||||||||
Per share data: | ||||||||||||||||||||||||
Income from continuing operations — basic | 2.14 | 1.90 | 0.28 | 0.78 | 0.06 | |||||||||||||||||||
Income from continuing operations — diluted | 1.95 | 1.78 | 0.28 | 0.78 | 0.06 | |||||||||||||||||||
Net income — basic | 2.21 | 2.21 | 0.38 | 0.93 | 0.06 | |||||||||||||||||||
Net income — diluted | 2.01 | 2.04 | 0.38 | 0.93 | 0.06 | |||||||||||||||||||
Book value | 19.48 | 19.48 | 11.31 | 13.14 | 12.19 | |||||||||||||||||||
Business metrics: | ||||||||||||||||||||||||
Cash flow from operations | 1,517 | 408 | 68 | 645 | (589 | ) | 238 | |||||||||||||||||
Liquidity position | $ | 2,715 | $ | 2,227 | $ | 758 | $ | 1,600 | $ | 1,545 | N/A | |||||||||||||
Ratio of earnings to fixed charges | 2.28 | 2.38 | 1.48 | 1.93 | 1.76 | 11.92 | ||||||||||||||||||
Ratio of earnings to fixed charges and preference dividends | 2.03 | 2.09 | 1.30 | 1.92 | 1.76 | 11.92 | ||||||||||||||||||
Return on equity | 10.65 | 10.98 | 3.77 | 6.91 | N/A | N/A | ||||||||||||||||||
Ratio of debt to total capitalization | 55.70 | 57.38 | 44.91 | 44.57 | 56.14 | N/A | ||||||||||||||||||
Balance sheet data: | ||||||||||||||||||||||||
Current assets | $ | 3,562 | $ | 3,083 | $ | 2,197 | $ | 2,119 | $ | 2,183 | N/A | |||||||||||||
Current liabilities | 2,277 | 2,032 | 1,357 | 1,090 | 2,096 | N/A | ||||||||||||||||||
Property, plant and equipment, net | 11,320 | 11,546 | 2,559 | 2,639 | 3,271 | N/A | ||||||||||||||||||
Total assets | 19,274 | 19,436 | 7,467 | 7,906 | 9,336 | N/A | ||||||||||||||||||
Long-term debt, including current maturities and capital leases | 8,361 | 8,726 | 2,456 | 3,220 | 3,648 | N/A | ||||||||||||||||||
Total stockholders’ equity | $ | 5,504 | $ | 5,658 | $ | 2,231 | $ | 2,692 | $ | 2,437 | N/A |
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Reorganized NRG | Predecessor Company | |||||||||||||||||||||||
December 6 – | January 1 – | |||||||||||||||||||||||
Year Ended December 31, | December 31, | December 5, | ||||||||||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | 2003 | |||||||||||||||||||
(In millions except ratio and per share data) | ||||||||||||||||||||||||
Energy | $ | 4,265 | $ | 3,155 | $ | 1,840 | $ | 1,181 | $ | 52 | $ | 769 | ||||||||||||
Capacity | 1,196 | 1,516 | 563 | 612 | 37 | 566 | ||||||||||||||||||
Risk management activities | 4 | 124 | (292 | ) | 61 | — | 19 | |||||||||||||||||
Contract amortization | 242 | 628 | 9 | (6 | ) | 13 | — | |||||||||||||||||
Thermal | 125 | 124 | 124 | 112 | 9 | 24 | ||||||||||||||||||
Hedge Reset | — | (129 | ) | — | — | — | — | |||||||||||||||||
Other | 157 | 167 | 156 | 120 | 9 | 192 | ||||||||||||||||||
Total operating revenues | $ | 5,989 | $ | 5,585 | $ | 2,400 | $ | 2,080 | $ | 120 | $ | 1,570 | ||||||||||||
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Item 7 — | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
• | Factors which affect NRG’s business; | |
• | NRG’s earnings and costs in the periods presented; | |
• | Changes in earnings and costs between periods; | |
• | Impact of these factors on NRG’s overall financial condition; | |
• | A discussion of new and ongoing initiatives that may affect NRG’s future results of operations and financial condition; | |
• | Expected future expenditures for capital projects; and | |
• | Expected sources of cash for future operations and capital expenditures. |
• | Business strategy; | |
• | Business environment in which NRG operates including how regulation, weather, and other factors affect the business; | |
• | Significant events that are important to understanding the results of operations and financial condition; | |
• | Results of operations including an overview of the Company’s results, followed by a more detailed review of those results by operating segment; | |
• | Financial condition addressing its credit ratings, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements; and | |
• | Critical accounting policies which are most important to both the portrayal of the Company’s financial condition and results of operations, and which require management’s most difficult, subjective or complex judgment. |
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• | seasonal daily and hourly changes in demand; | |
• | extreme peak demands; | |
• | available supply resources; | |
• | transportation and transmission availability and reliability within and between regions; | |
• | location of NRG’s generating facilities relative to the location of its load-serving opportunities; | |
• | procedures used to maintain the integrity of the physical electricity system during extreme conditions; and | |
• | changes in the nature and extent of federal and state regulations. |
• | weather conditions; | |
• | market liquidity; |
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• | capability and reliability of the physical electricity and gas systems; | |
• | local transportation systems; and | |
• | the nature and extent of electricity deregulation. |
• | Reinvestment in existing assets — Opportunities to invest in the existing business, including maintenance and environmental capital expenditures that improve operational performance, ensure compliance with environmental laws and regulations, and expansion projects. | |
• | Management of debt levels — The Company uses several metrics to measure the efficiency of its capital structure and debt balances, including the Company’s targeted net debt to total capital ratio range of 45% to 60% and certain cash flow and interest coverage ratios. The Company intends in the normal course of business to continue to manage its debt levels towards the lower end of the range and may, from time to time, pay down its debt balances for a variety of reasons. | |
• | Return of capital to shareholders — The Company’s debt instruments include restrictions on the amount of capital that can be returned to shareholders. The Company has in the past returned capital to shareholders while maintaining compliance with existing debt agreements and indentures. The Company expects to regularly return capital to shareholders through opportunistic share repurchases, while exploring other prospects to increase its flexibility under restrictive debt covenants. | |
• | Repowering, econrg and new build opportunities — The Company intends to pursue repowering initiatives that enhance and diversify its portfolio and provide a targeted economic return to the Company. |
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• | Impact of Hedge Reset— in November 2006, the Company reset legacy Texas hedges which resulted in an increase in energy revenue of $449 million as the period’s average contract prices increased by approximately $13 per MWh as compared to the 2006 average contract prices. | |
• | Development costs— NRG incurred $101 million in net development costs primarily due to required engineering studies to obtain the Combined Construction and Operating License Application, or COLA, as well as development costs for otherRepoweringNRG projects. On September 24, 2007, NRG filed a COLA with the NRC to build and operate two new nuclear units at the STP site. Effective October 29, 2007, the City of San Antonio agreed to partner with NRG in the development and ownership of these new units, to reimburse NRG for a pro rata share of certain project costs NRG had incurred, and to pay a pro rata share of future development costs. NRG was reimbursed $42 million for costs incurred to develop STP 3 and 4 through October 31, 2007; $39 million of the total $42 million was recorded as a reduction to development costs. | |
• | Acquisition of Texas and WCP— the inclusion of a full year of activity for the Texas region and WCP in 2007, contributed to an increase in operating income of approximately $76 million, compared to 2006. | |
• | New capacity markets— the introduction of the Locational Forward Reserve Market, or LFRM, the Reliability Pricing Model market, or RPM, and transition capacity payment markets, increased capacity revenues in the Northeast region by $78 million. | |
• | Refinancing expense— the Company recognized a $35 million write-off of previously deferred financing cost due to the refinancing of the Company’s Senior Credit Facility. | |
• | Interest expense — the increase in debt due to the acquisition of Texas Genco LLC, Hedge Reset transaction and the Capital Allocation Program increased interest expense by approximately $99 million. | |
• | Sale of ITISA — on December 18, 2007, NRG entered into a sale and purchase agreement to sell its 100% interest in Tosli, which holds all of NRG’s interest in ITISA, to Brookfield Asset Management Inc. for the purchase price of $288 million, plus the assumption of approximately $60 million in debt. NRG anticipates the completion of the sale transaction during the first half of 2008. As discussed in Note 3 —Discontinued Operations, Business Acquisitions and Dispositions the activities of Tosli and ITISA have been classified in discontinued operations. |
• | STP Repowerings — The NRC docketed the Company’s COLA on November 30, 2007, signaling the beginning of their comprehensive and detailed review process. The Company expects to achieve commercial operation for Unit 3 approximately 48 months after issuance of the COLA, and commercial operation for Unit 4 approximately 12 months thereafter. | |
• | Cedar Bayou Generating Station — on August 1, 2007, NRG and a partner entered into definitive agreements pursuant to which the two parties will jointly develop, construct, operate and own, on a50/50 undivided interest basis, a new 550 MW combined cycle natural gas turbine generating plant at NRG’s Cedar Bayou Generating Station in Chambers County, Texas. In exchange for a 50% undivided interest in certain tangible and intangible assets and rights to use facilities owned by NRG, the partner agreed to pay NRG $45 million during a24-month period. | |
• | Long Beach — on August 1, 2007, the Company successfully completed and commissioned the repowering of 260 MW of new gas-fired generating capacity at its Long Beach Generating Station. This project is supported by a10-year PPA. |
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Year Ended December 31, | ||||||||||||
2007 | 2006 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 4,265 | $ | 3,155 | 35 | % | ||||||
Capacity revenue | 1,196 | 1,516 | (21 | ) | ||||||||
Risk management activities | 4 | 124 | N/A | |||||||||
Contract amortization | 242 | 628 | (61 | ) | ||||||||
Thermal revenue | 125 | 124 | 1 | |||||||||
Hedge Reset | — | (129 | ) | N/A | ||||||||
Other revenues | 157 | 167 | (6 | ) | ||||||||
Total operating revenues | 5,989 | 5,585 | 7 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of operations | 3,378 | 3,265 | 3 | |||||||||
Depreciation and amortization | 658 | 590 | 12 | |||||||||
General and administrative | 309 | 276 | 12 | |||||||||
Development costs | 101 | 36 | 181 | |||||||||
Total operating costs and expenses | 4,446 | 4,167 | 7 | |||||||||
Gain on sale of assets | 17 | — | N/A | |||||||||
Operating Income | 1,560 | 1,418 | 10 | |||||||||
Other Income/(Expense) | ||||||||||||
Equity in earnings of unconsolidated affiliates | 54 | 60 | (10 | ) | ||||||||
Gains on sales of equity method investments | 1 | 8 | (88 | ) | ||||||||
Other income, net | 55 | 156 | (65 | ) | ||||||||
Refinancing expenses | (35 | ) | (187 | ) | (81 | ) | ||||||
Interest expense | (689 | ) | (590 | ) | 17 | |||||||
Total other expenses | (614 | ) | (553 | ) | 11 | |||||||
Income from Continuing Operations before income tax expense | 946 | 865 | 9 | |||||||||
Income tax expense | 377 | 322 | 17 | |||||||||
Income from Continuing Operations | 569 | 543 | 5 | |||||||||
Income from discontinued operations, net of income tax expense | 17 | 78 | (78 | ) | ||||||||
Net Income | $ | 586 | $ | 621 | (6 | ) | ||||||
Business Metrics | ||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | 7.12 | 6.99 | 2 | % |
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• | Energy revenues — energy revenues increased by $1.1 billion for the year ended December 31, 2007, compared to 2006: |
• | Texas — energy revenues increased by $972 million of which $217 million was due to the inclusion of twelve months activity in 2007 compared to eleven months in 2006. Of the remaining $755 million increase, $449 million was due to the Hedge Reset transaction which resulted in higher 2007 average contracted prices of approximately $13 per MWh. In addition, revenues from 8.8 million MWh of generation moved from capacity revenue to energy revenue. Prior to the Acquisition, PUCT regulations required that Texas sell 15% of its capacity by auction at reduced rates. In March 2006, the PUCT accepted NRG’s request to no longer participate in these auctions and that capacity is now being sold in the merchant market. These favorable results were partially offset by lower sales from the region’s natural gas-fired units due to a cooler summer which resulted in lower generation of approximately 2.7 million MWh. | |
• | Northeast — energy revenues increased by approximately $138 million, of which $61 million was due to a 6% increase in generation, primarily driven by increases at the region’s Arthur Kill, Oswego and Indian River plants. The Arthur Kill plant increased generation by 448 thousand MWh due to transmission constraints around New York City, the Oswego plants’ generation increased by 127 thousand MWh due to a colder winter during 2007 compared to 2006, and the Indian River plants’ generation increased by 418 thousand MWh due to stronger pricing and fewer outages in the second half of 2007 compared to the second half of 2006. | |
• | South Central — energy revenues increased by approximately $70 million, due to a new contract which increased contract sales volume by approximately 1.3 million MWh and energy revenues by $69 million. Following a contractual fuel adjustment charge, energy revenues increased by $11 million from the region’s cooperative customers. This was offset by a $12 million decrease in merchant energy revenue. | |
• | West — energy revenues decreased by approximately $72 million, excluding the first quarter 2007, due to the tolling agreement at the Encina plant that has resulted in the receipt of fixed monthly capacity payment in return for the right to schedule and dispatch from the plant. The Encina tolling agreement replaced an RMR agreement under which the plant was called upon to generate and earn energy revenues for such dispatch. |
• | Capacity revenues — capacity revenues decreased by $320 million for the year ended December 31, 2007, compared to 2006, due to a decrease in Texas capacity revenues that were partially offset by increases in capacity revenues in the Northeast, South Central and West regions: |
• | Texas — capacity revenues decreased by $486 million due to a reduction of capacity auction sales mandated by the PUCT in prior years as previously discussed. | |
• | Northeast — capacity revenues increased by $81 million of which $39 million of the increase was from the region’s NEPOOL assets and $36 million was from the region’s PJM assets. The NEPOOL assets benefited from the new LFRM market and transition capacity market, both introduced in the fourth quarter 2006. Capacity revenues increased by $24 million from the LFRM market and $18 million from transition capacity payments, which was offset by a $3 million reduction in capacity payments due to the expiration of the Devon plant’s RMR agreement on December 31, 2006. On June 1, 2007, the new RPM capacity market became effective in PJM increasing capacity revenues by $36 million as compared to 2006. | |
• | South Central — capacity revenues increased by approximately $22 million. Of this increase, $15 million was due to higher billing rates as a result of the region’s market setting new summer peaks hit in 2006 and 2007, $6 million was due to higher contractual transmission pass-though costs to the region’s cooperative customers and $3 million was due to improved market conditions at the region’s Rockford plants. In |
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• | West — capacity revenues increased by approximately $54 million, of which $26 million was related to the inclusion of the first quarter 2007 compared to 2006. New tolling agreements at the region’s Encina and Long Beach plants accounted for the remaining difference, with the Encina facility contributing approximately $15 million and the newly-repowered Long Beach facility contributing approximately $13 million. |
• | Contract amortization — revenues from contract amortization decreased by $386 million for the year ended December 31, 2007, compared to 2006, as a result of the November 2006 Hedge Reset transaction, which resulted in a write-off of a large portion of the Company’s out-of-market power contracts during the fourth quarter 2006. | |
• | Other revenues —other revenues decreased by $10 million for the year ended December 31, 2007, compared to 2006 due to: |
• | Sale of emission allowances — net sales of SO2 emission allowances decreased by approximately $33 million. In 2006, we sold emissions in lieu of generation due to an unseasonably warm first quarter. Since that time the average market price for SO2 allowances decreased by 28%. | |
• | Physical gas sales — decreased by $7 million due to the lower sales of excess natural gas. | |
• | Ancillary revenues — ancillary services revenue increased by approximately $27 million due to a change in strategy to actively provide ancillary services in the Texas region which increased revenues by $33 million. This was partially offset by a $4 million reduction in ancillary services in the Northeast region due to higher transmission costs following transmission constraints in the New York City area. |
• | Risk management activities —gains/losses from risk management activities include all derivative activity that do not qualify for hedge accounting as well as the ineffective portion associated with hedged transactions. Such gains were $4 million for the year ended December 31, 2007. The breakdown of changes by region are as follows: |
Year Ended December 31, 2007 | ||||||||||||||||
Texas | Northeast | South Central | Total | |||||||||||||
(In millions) | ||||||||||||||||
Net gains on settled positions, or financial revenues | $ | 33 | $ | 43 | $ | 5 | $ | 81 | ||||||||
Mark-to-market results | ||||||||||||||||
Reversal of previously recognized unrealized gains on settled positions related to economic hedges | (83 | ) | (45 | ) | — | (128 | ) | |||||||||
Reversal of previously recognized unrealized gains on settled positions related to trading activity | (1 | ) | (12 | ) | (19 | ) | (32 | ) | ||||||||
Net unrealized gains on open positions related to economic hedges | 19 | 15 | — | 34 | ||||||||||||
Net unrealized gains/(losses) on open positions related to trading activity | (1 | ) | 26 | 24 | 49 | |||||||||||
Subtotal mark-to-market results | (66 | ) | (16 | ) | 5 | (77 | ) | |||||||||
Total derivative gains/(losses) | $ | (33 | ) | $ | 27 | $ | 10 | $ | 4 | |||||||
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• | Cost of energy —cost of energy decreased by approximately $24 million, to $2,428 million, for the year ended December 31, 2007, compared to 2006, and as a percentage of revenue it decreased from 44% for the year ended December 31, 2006, to 41% for the year ended December 31, 2007. This decrease was due to: |
• | Texas —decreased by $95 million for the year ended December 31, 2007, compared to 2006. This included an additional month’s expense of $96 million in 2007, without which cost of energy would have decreased by $191 million. This decrease was due to a reduction in natural gas expense and fuel contract amortization, partially offset by increased ancillary service expense. |
— | Fuel expense and purchased power expense — Natural gas expense decreased by $170 million, which excludes January 2007 natural gas expense of $27 million. This was due to a decrease of 2.7 million MWh in gas-fired generation as a result of cooler summer weather, coupled with greater economic purchases from ERCOT and increased baseload generation. Despite higher coal-fired generation at the region’s W.A. Parish and Limestone plants, the region’s coal expenses, excluding January 2007, decreased by $13 million due to a 9% reduction in average contracted coal prices. | |
— | Fuel contract amortization — decreased by approximately $43 million, excluding January 2007, due to declining forward fuel price curves below the contracted prices used at Acquisition. | |
— | Purchased ancillary service expense — increased by approximately $34 million due to favorable market prices in purchasing this service in the market compared to providing the service from internal resources. |
• | Northeast — cost of energy increased by $26 million primarily due to $30 million in higher natural gas costs related to increased generation at the region’s Arthur Kill plant due to its locational advantage to New York City following transmission constraints during the last three quarters of 2007. | |
• | South Central — Cost of energy increased by $104 million due to increases in purchased energy, coal costs and transmission costs. |
— | Purchased energy — increased by approximately $69 million due to increased market purchases following increased cooperative load requirements and planned maintenance at the region’s Big Cajun II facility. | |
— | Coal costs — increased by approximately $17 million, of which $11 million was related to a 9% increase in coal prices and $7 million due to higher coal transportation costs. | |
— | Transmission costs — increased by approximately $16 million of which $6 million was due to contractual increases related to network transmission service. Point-to-point transmission costs also increased by $10 million reflecting more off-system sales. |
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• | West — Cost of energy decreased by approximately $76 million, excluding the first quarter 2007, due to new tolling agreement entered into at the Encina plant in 2007, which requires the counterparty to supply their own fuel. Under the previous arrangement in 2006, the plant supplied the fuel. |
• | Other operating costs —Other operating costs which includes operations and maintenance expenses, or O&M, increased by $137 million, to $950 million, for the year ended December 31, 2007, compared to 2006. This increase was due to: |
• | Texas — other operating costs increased by $75 million, after excluding January 2007 expense of $39 million, other operating costs increased by $36 million. This $36 million increase was due to $25 million in higher O&M expense as a result of increased maintenance associated with planned outages and fuel handling at the W.A. Parish facility and $10 million in higher property tax expenses following an increased valuation after the Acquisition. | |
• | Northeast — other operating costs increased by $18 million due to increased staffing costs and higher maintenance costs. | |
• | South Central — other operating costs increased by approximately $28 million, $19 million of which was due to increased maintenance expense primarily related to planned outages. Additionally, the region disposed of $4 million in assets in conjunction with the outage. | |
• | Acquisition of WCP — these results include $15 million of WCP expenses that were not included in the Company’s results in 2006. |
• | Texas acquisition — the inclusion of Texas results for twelve months in 2007 compared to eleven months in 2006 resulted in an increase of approximately $38 million. | |
• | Impact of new environmental legislation —due to new and more restrictive environmental legislation, the useful life of certain pollution control equipment has been reduced. The Company accelerated depreciation on certain equipment in its Northeast region to reflect the remaining useful life, resulting in increased depreciation of approximately $13 million. |
• | Texas and WCP acquisitions — the inclusion of Texas results for twelve months in 2007 compared to eleven months in 2006 and the consolidation of WCP for the last three quarters of 2006 resulted in an increase of approximately $9 million. | |
• | Wage and benefit costs — due to the expansion of the Company, includingRepoweringNRG initiatives, wages and related benefits costs resulted in a $28 million increase in G&A. Additionally, information technology and other office services to support this expansion increased by $8 million. | |
• | Franchise tax — the Company’s Louisiana state franchise tax increased by approximately $6 million. This was because the state’s franchise tax is assessed based on the Company’s total debt and equity that increased significantly following the acquisition of Texas Genco LLC. | |
• | Non-recurring expenses during 2006 — for the year ended December 31, 2006, G&A included non-recurring fees of $20 million of which $6 million were related to the unsolicited takeover attempt by Mirant Corporation and $14 million associated with the Texas integration efforts. |
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• | Texas —on September 24, 2007, NRG filed a COLA with the NRC to build and operate two new nuclear units at the STP site. During the period, NRG incurred $91 million in development costs related to STP units 3 and 4 project in 2007. These development costs were reduced by a $39 million reimbursement related to a partnership agreement signed during the fourth quarter 2007. | |
• | Wind projects —approximately $13 million in development costs related to wind projects primarily in Texas. | |
• | Other project —approximately $4 million in development costs related to otherRepoweringNRG projects in the West region. |
• | Refinancing for the acquisition of Texas Genco LLC in February 2006 — the Company significantly increased its corporate debt facilities from approximately $2 billion as of December 31, 2005, to approximately $7 billion as of February 2, 2006. This increased interest expense by approximately $12 million compared to 2006. | |
• | Increase of $1.1 billion in debt for Hedge Reset — the Company issued $1.1 billion in Senior Notes due 2017 in November 2006 related to the Hedge Reset, which increased interest expense by approximately $72 million. |
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• | Capital Allocation Program — the Company issued a total of $330 million of debt to fund Phase I of the Capital Allocation Program during the second half of 2006. This increased interest expense by $20 million compared to 2006. |
Year Ended December 31, | ||||||||
2007 | 2006 | |||||||
(In millions | ||||||||
except otherwise stated) | ||||||||
Income from continuing operations before income taxes | $ | 946 | $ | 865 | ||||
Tax at 35% | 331 | 303 | ||||||
State taxes, net of federal benefit | 46 | 34 | ||||||
Foreign operations | (13 | ) | (21 | ) | ||||
Subpart F taxable income | — | 11 | ||||||
Valuation allowance, including change in state effective rate | 6 | (10 | ) | |||||
Change in state effective tax rate | — | 21 | ||||||
Claimant reserve settlements | — | (28 | ) | |||||
Change in local German effective tax rates | (29 | ) | — | |||||
Foreign dividends | 26 | 1 | ||||||
Non-deductible interest | 10 | 3 | ||||||
Permanent differences, reserves, other | — | 8 | ||||||
Income tax expense | $ | 377 | $ | 322 | ||||
Effective income tax rate | 39.9 | % | 37.2 | % |
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• | Increase in profits — income before tax increased by $81 million, with a corresponding increase of approximately $32 million in income tax expense. | |
• | Permanent differences — the Company’s effective tax rate differs from the US statutory rate of 35% due to: |
• | Change in German tax rate— due to a reduction in the German statutory and resulting effective tax rate, income tax expense benefited by $29 million for the year-ended 2007. | |
• | Taxable dividends from foreign subsidiaries— in January 2007, the Company transferred the proceeds from the sale of its Flinders assets to the U.S. creating additional income tax expense of approximately $25 million. | |
• | Lower tax rates in foreign jurisdictions— lower income tax rates at the Company’s foreign locations resulted in additional income tax expense during 2007 compared to 2006 of $8 million. | |
• | Non-deductible interest— interest expense from the stock buybacks from Phase I of the Company’s Capital Allocation Program were non-deductible for income tax purposes, thus increasing income tax expense by approximately $7 million. | |
• | Change in state effective tax rate— the state effective tax rate remains unchanged for 2007. This resulted in a net decrease in income tax expense of approximately $5 million as compared to 2006, after taking into account the movement in valuation allowance as a result of the change in rate from 2005 to 2006. | |
• | Subpart F taxable income— a dividend was declared and paid in 2007 by NRGenerating International B.V. As result of this dividend, there was no Subpart F income compared to 2006. This resulted in a decrease to income tax expense of approximately $11 million. | |
• | Disputed claims reserve— During 2007 as compared to 2006, the Company made no distribution from its disputed claims reserve, this increased income tax expense by approximately $28 million. |
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Year Ended December 31 | ||||||||||||
2006 | 2005 | Change % | ||||||||||
(In millions | ||||||||||||
except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 3,155 | $ | 1,840 | 71 | % | ||||||
Capacity revenue | 1,516 | 563 | 169 | |||||||||
Risk management activities | 124 | (292 | ) | NA | ||||||||
Contract amortization | 628 | 9 | NA | |||||||||
Thermal revenue | 124 | 124 | — | |||||||||
Hedge Reset | (129 | ) | — | NA | ||||||||
Other revenues | 167 | 156 | 7 | |||||||||
Total operating revenues | 5,585 | 2,400 | 133 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of operations | 3,265 | 1,829 | 79 | |||||||||
Depreciation and amortization | 590 | 158 | 273 | |||||||||
General and administrative | 276 | 176 | 57 | |||||||||
Development costs | 36 | — | NA | |||||||||
Other charges | — | 12 | NA | |||||||||
Total operating costs and expenses | 4,167 | 2,175 | 92 | |||||||||
Operating Income | 1,418 | 225 | 530 | |||||||||
Other Income/(Expense) | ||||||||||||
Equity in earnings of unconsolidated affiliates | 60 | 104 | (42 | ) | ||||||||
Write downs and gains/(losses) on sales of equity method investments | 8 | (31 | ) | NA | ||||||||
Other income, net | 156 | 54 | 189 | |||||||||
Refinancing expenses | (187 | ) | (65 | ) | 188 | |||||||
Interest expense | (590 | ) | (177 | ) | 233 | |||||||
Total other expenses | (553 | ) | (115 | ) | 381 | |||||||
Income from Continuing Operations before income tax expense | 865 | 110 | 686 | |||||||||
Income tax expense | 322 | 42 | 667 | |||||||||
Income from Continuing Operations | 543 | 68 | 699 | |||||||||
Income from discontinued operations, net of income tax expense | 78 | 16 | 388 | |||||||||
Net Income | $ | 621 | $ | 84 | 639 | |||||||
Business Metrics | ||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | 6.99 | 8.89 | (21 | )% | ||||||||
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Year Ended December 31, | ||||||||||||||||||||
2006 | ||||||||||||||||||||
Total excluding | 2005 | |||||||||||||||||||
Consolidated | Texas Region | WCP | Texas Region/WCP | Consolidated | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Energy revenue | $ | 3,155 | $ | 1,726 | $ | 72 | $ | 1,357 | $ | 1,840 | ||||||||||
Capacity revenue | 1,516 | 849 | 64 | 603 | 563 | |||||||||||||||
Risk management activities | 124 | (30 | ) | — | 154 | (292 | ) | |||||||||||||
Contract amortization | 628 | 609 | — | 19 | 9 | |||||||||||||||
Thermal revenue | 124 | — | — | 124 | 124 | |||||||||||||||
Hedge Reset | (129 | ) | (129 | ) | — | — | — | |||||||||||||
Other revenues | 167 | 63 | 5 | 99 | 156 | |||||||||||||||
Total Operating revenues | 5,585 | 3,088 | 141 | 2,356 | 2,400 | |||||||||||||||
Cost of operations | 3,265 | 1,669 | 112 | 1,484 | 1,829 | |||||||||||||||
Depreciation and amortization | 590 | 413 | 2 | 175 | 158 | |||||||||||||||
General and administrative | 276 | 111 | 6 | 159 | 176 | |||||||||||||||
Development costs | 36 | 14 | 4 | 18 | — | |||||||||||||||
Other charges | — | — | — | — | 12 | |||||||||||||||
Total operating costs and expenses | 4,167 | 2,207 | 124 | 1,836 | 2,175 | |||||||||||||||
Operating Income | $ | 1,418 | $ | 881 | $ | 17 | $ | 520 | $ | 225 | ||||||||||
• | Energy revenues — energy revenues increased by $1,315 million for the year ended December 31, 2006, compared to 2005 with 50% contracted in 2006 compared to 13% in 2005. Excluding the Texas region and WCP, energy revenues decreased by approximately $483 million or 26%. |
• | Texas —The acquisitions of Texas Genco LLC now referred to as the Company’s Texas region, contributed $3,088 million to operating revenues including $1,726 million of energy revenues. | |
• | West —The acquisition of Dynegy’s 50% interest in WCP contributed $72 million to total energy revenues. | |
• | Northeast —generation demand for the Northeast region’s intermediate and peaking plants declined by 54%, accompanied by a 19% to 23% year over year decline in power prices in the Northeast region’s three major markets. |
• | Capacity revenues— capacity revenues were $1,516 million for the year ended December 31, 2006 compared to $563 million for the year ended December 31, 2005, an increase of $953 million. This was due to: |
• | Texas —the acquisitions of Texas Genco LLC now referred to as the Company’s Texas region, contributed $3,088 million to operating revenues including $849 million of capacity revenues. | |
• | West —The acquisition of Dynegy’s 50% interest in WCP contributed $64 million to total capacity revenues. | |
• | Northeast —Higher capacity prices for the New York Rest of State market, led to a $30 million increase in the Northeast region’s 2006 capacity revenues. |
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• | South Central —The region’s capacity revenues also grew by $9 million as pricing increased due to increased peak demand. |
Year Ended December 31, 2006 | ||||||||||||||||||||
South | ||||||||||||||||||||
Texas | Northeast | Central | Other | Total | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Net losses on settled positions, or financial revenues | $ | (152 | ) | $ | (10 | ) | $ | (6 | ) | $ | (3 | ) | $ | (171 | ) | |||||
Mark-to-market results | ||||||||||||||||||||
Reversal of previously recognized unrealized losses on settled positions related to economic hedges | — | 115 | 1 | — | 116 | |||||||||||||||
Reversal of previously recognized unrealized gains on settled positions related to trading activity | — | (25 | ) | (1 | ) | — | (26 | ) | ||||||||||||
Net unrealized gains on open positions related to economic hedges | 122 | 50 | — | — | 172 | |||||||||||||||
Net unrealized gains on open positions related to trading activity | — | 14 | 19 | — | 33 | |||||||||||||||
Subtotal mark-to-market results | 122 | 154 | 19 | — | 295 | |||||||||||||||
Total derivative gains/(losses) | $ | (30 | ) | $ | 144 | $ | 13 | $ | (3 | ) | $ | 124 | ||||||||
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• | Texas — The acquisitions of Texas Genco LLC now referred to as the Company’s Texas region, increased cost of energy by approximately $1,276 million. | |
• | West — The acquisition of Dynegy’s 50% interest in WCP increased cost of energy by approximately $79 million. |
• | Northeast— cost of energy decreased by $254 million, due to $143 million lower oil costs and $101 million in lower gas fuel costs as a result of lower generation from oil- and gas-fired assets of approximately 70% and 45%, respectively. | |
• | South Central — cost of energy decreased by $66 million in 2006, as higher coal plant availability and increased utilization of the region’s tolling agreements reduced the need to purchase energy to support contract load requirements. |
• | NRG’s G&A costs for 2006 were $276 million compared to $176 million in the previous year. Corporate costs represented $143 million, or 3% of 2006 total operating revenues and $112 million, or 5% of the Company’s 2005 total operating revenues. Excluding WCP and the Company’s Texas region G&A was lower by $17 million, despite having been adversely impacted by $6 million of costs associated with the unsolicited acquisition offer by Mirant Corporation and approximately $14 million of NRG Texas integration costs. |
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• | Purchase of remaining 50% interest in WCP — NRG’s purchase of the remaining 50% interest in WCP accounted for $21 million of the decline, as the results of WCP were fully consolidated as of March 31, 2006. As part of that transaction, NRG sold its 50% interest in the Rocky Road investment, which accounted for $7 million of the decline in total equity earnings. | |
• | Sale of Non-Core Assets — NRG’s Enfield investment, which was sold on April 1, 2005, earned $16 million during 2005. Sales of other equity investments in 2006 included James River, Cadillac and certain Latin American power funds. |
• | Refinancing for the acquisition of Texas Genco LLC — NRG partially financed the acquisition of Texas Genco LLC through borrowings under new debt facilities and repaid and terminated previous debt facilities. As a result of this financing, the Company incurred $178 million of refinancing expenses: $127 million was related to the premium paid to NRG’s previous debt holders, $34 million for the amortization of the remaining balance of a bridge loan commitment entered into on September 30, 2005, and $31 million related to write-offs of deferred financing costs associated with NRG’s previous debt, and a credit of $14 million related to a debt premium write-off. | |
• | Redemption of Second Priority Notes — In 2005, NRG redeemed and purchased a total of approximately $645 million of the Company’s second priority notes. As a result of the redemption and purchases, NRG |
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• | Financing for the acquisition of Texas Genco LLC — interest on new debt issued to finance the acquisition of Texas Genco LLC. See Item 15 — Note 3,Discontinued Operations,Business Acquisitions and Dispositions, and Note 11,Debt and Capital Leases, to the consolidated financial statements for a further discussion of the acquisition and the related financing. As part of the refinancing, NRG replaced its previous senior secured term loan with a new $3.575 billion senior secured term loan. In addition, NRG retired $1.1 billion of its 8% second priority notes and issued $3.6 billion in senior unsecured notes with a weighted average interest rate of 7.33%. |
Year Ended December 31, | ||||||||
2006 | 2005 | |||||||
(In millions except otherwise stated) | ||||||||
Income from continuing operations before income taxes | $ | 865 | $ | 110 | ||||
Tax at 35% | 303 | 39 | ||||||
State taxes, net of federal benefit | 34 | (1 | ) | |||||
Foreign operations | (21 | ) | (18 | ) | ||||
2005 Section 965 taxable dividend | — | 5 | ||||||
Subpart F taxable income | 11 | 19 | ||||||
Valuation allowance, including change in state effective rate | (10 | ) | 22 | |||||
Change in state effective tax rate | 21 | (22 | ) | |||||
Claimant reserve settlements | (28 | ) | — | |||||
Foreign dividends | 1 | — | ||||||
Non-deductible interest | 3 | — | ||||||
Permanent differences, reserves, other | 8 | (2 | ) | |||||
Income tax expense | $ | 322 | $ | 42 | ||||
Effective income tax rate | 37.2 | % | 38.2 | % |
• | Increase in profits — income before tax increased by $755 million, with a corresponding increase of approximately $299 million in tax expense. |
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• | Permanent differences — the Company’s effective tax rate differs from the US statutory rate of 35% due to: |
• | Change in state effective tax rate— the state effective tax rate was changed which resulted in a net increase to income tax expense of approximately $11 million, as compared to 2005, inclusive of the movement in valuation allowance resulting from the change in state effective tax rate. | |
• | Disputed claims reserve— during 2006, the Company made distributions from its disputed claims reserve decreasing 2006 income tax expense by approximately $28 million. |
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Year Ended December 31, | ||||||||||||
2007 | 2006(b) | Change % | ||||||||||
(In millions except | ||||||||||||
otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 2,698 | $ | 1,726 | 56 | % | ||||||
Capacity revenue | 363 | 849 | (57 | ) | ||||||||
Risk management activities | (33 | ) | (30 | ) | 10 | |||||||
Contract amortization | 219 | 609 | (64 | ) | ||||||||
Hedge Reset | — | (129 | ) | N/A | ||||||||
Other revenues | 40 | 63 | (37 | ) | ||||||||
Total operating revenues | 3,287 | 3,088 | 6 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 1,181 | 1,276 | (7 | ) | ||||||||
Depreciation and amortization | 469 | 413 | 14 | |||||||||
Other operating expenses | 668 | 518 | 29 | |||||||||
Operating Income | $ | 969 | $ | 881 | 10 | |||||||
MWh sold (in thousands) | 49,220 | 46,361 | 6 | |||||||||
MWh generated (in thousands) | 47,779 | 44,910 | 6 | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 62.00 | $ | 63.07 | (2 | ) | ||||||
Cooling Degree Days, or CDDs(a) | 2,707 | 3,108 | (13 | ) | ||||||||
CDD’s 30 year rolling average | 2,647 | 2,647 | — | |||||||||
Heating Degree Days, or HDDs(a) | 1,949 | 1,533 | 27 | % | ||||||||
HDD’s 30 year rolling average | 1,997 | 1,997 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. | |
(b) | For the period February 2, 2006 to December 31, 2006 only. |
• | Energy Revenues — for eleven months of 2007 compared to the same period in 2006 were up by $755 million, $449 million of which was due to the Hedge Reset transaction, as the average price of the underlying power contracts increased by $13 per MWh compared to average contract prices prior to the hedge reset. The balance of the increase in energy revenues was due to the sale of additional output as energy rather than under PUCT mandated capacity auctions. |
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• | Capacity Revenues — reduction in capacity auction sales reduced capacity revenues by approximately $517 million, excluding January 2007. | |
• | Contract Amortization — the Hedge Reset transaction decreased contract amortization by approximately $498 million, excluding January 2007. | |
• | Gas-fired Generation —lower natural gas-fired generation of approximately 2.7 million MWh, for the comparable eleven month period in 2007, was a result of cooler summer weather coupled with increased economic purchases of energy and ancillary services from ERCOT. Lower sales revenue for the eleven months was offset by natural lower natural gas fuel costs of $170 million and cash flow economic hedge improvements. | |
• | Development Costs — increased by $44 million in 2007 compared to 2006 largely due to the development of STP nuclear units 3 and 4 project, including $2 million of expenses in January 2007. The $44 million increase also includes $39 million in reimbursements from a partnership agreement signed in the fourth quarter 2007. |
• | Energy revenues — energy revenues increased by $972 million of which $217 million was due to the inclusion of twelve months activity in 2007 compared to eleven months in 2006. Of the remaining $755 million increase, $449 million was due to the Hedge Reset transaction which resulted in higher 2007 average contracted prices of approximately $13 per MWh. In addition, revenues from 8.8 million MWh of generation moved from capacity revenue to energy revenue. Prior to the Acquisition, PUCT regulations required that NRG Texas sell 15% of its capacity by auction at reduced rates. In March 2006, the PUCT accepted NRG’s request to no longer participate in these auctions and that capacity is now being sold in the merchant market. These favorable results were partially offset by lower sales from natural gas-fired units due to a cooler summer which resulted in lower natural gas-fired generation of approximately 2.7 million MWh. | |
• | Other revenues — the region’s other revenues decreased by $27 million for the eleven months of 2007 compared to 2006. This was due to a decrease in intercompany emission allowance sales of $40 million and a $19 million decrease in physical gas sales. This $59 million decrease was offset by a $33 million increase in ancillary services revenue due to a change in strategy to more actively provide ancillary services in the Texas region. | |
• | Capacity revenues — capacity revenues decreased by $517 million, excluding $31 million incurred in January 2007. This decrease was due to the reduction of capacity auction sales mandated by the PUCT in prior years as described above. | |
• | Contract amortization — revenues from contract amortization excluding January 2007 decreased by $405 million primarily due to the write-off of out-of-market power contracts during the fourth quarter 2006 related to the Hedge Reset transaction. |
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• | Fuel expense— natural gas expense decreased by $170 million, excluding the January 2007 expense of $27 million, due to a decrease of 2.7 million MWh in natural gas-fired generation as a result of cooler summer weather, coupled with greater economic purchases of energy and ancillary services from ERCOT and increased baseload generation. Coal expenses, excluding January 2007, decreased by $13 million due to an 9% reduction in average contracted coal prices in 2007, despite a 1.1 million MWh increase in coal-fired generation at the region’s W.A. Parish and Limestone plants. | |
• | Purchased ancillary service— increased by approximately $34 million due to the favorable market prices in purchasing this service in the market compared to providing the service from internal resources causing an associated decrease in natural gas expense. | |
• | Fuel contract Amortization— decreased by approximately $43 million, excluding January 2007, due to declining forward fuel price curves below the contracted prices used at acquisition in February 2006. |
• | Development costs— on September 24, 2007, NRG filed a COLA with the NRC. The Company incurred $91 million in development costs related to STP nuclear unit 3 and 4 project in 2007, including $2 million in January 2007, compared to development costs of $14 million in 2006. Of the $91 million incurred this year, $39 million was reimbursed through a partnership agreement in the fourth quarter 2007. Fossil development costs was $6 million in 2007. | |
• | Plant O&M expense— increased by $25 million, excluding January 2007, due to increased maintenance associated with planned outages and fuel handling at W.A. Parish, increased maintenance related to higher utilization in 2006 of the region’s natural gas fleet, and retirement of older assets. | |
• | Corporate allocations— were higher by approximately $16 million. | |
• | Property tax expense— increased by approximately $10 million related to the Texas acquisition. |
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Year Ended December 31, | ||||||||||||
2007 | 2006 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 1,104 | $ | 966 | 14 | % | ||||||
Capacity revenue | 402 | 321 | 25 | |||||||||
Risk management activities | 27 | 144 | (81 | ) | ||||||||
Other revenues | 72 | 112 | (36 | ) | ||||||||
Total operating revenues | 1,605 | 1,543 | 4 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 641 | 615 | 4 | |||||||||
Depreciation and amortization | 102 | 89 | 15 | |||||||||
Other operating expenses | 404 | 378 | 7 | |||||||||
Operating Income | $ | 458 | $ | 461 | (1 | ) | ||||||
MWh sold (in thousands) | 14,163 | 13,309 | 6 | |||||||||
MWh generated (in thousands) | 14,163 | 13,309 | 6 | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 76.37 | $ | 67.73 | 13 | |||||||
Cooling Degree Days, or CDDs(a) | 702 | 653 | 8 | |||||||||
CDD’s 30 year rolling average | 537 | 537 | — | |||||||||
Heating Degree Days, or HDDs(a) | 6,074 | 5,417 | 12 | % | ||||||||
HDD’s 30 year rolling average | 6,261 | 6,261 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Cost of energy — increased by approximately $26 million due to a 6% increase in generation at the region’s coal and natural gas-fired plants. | |
• | Other operating expenses — increased by $26 million primarily due to increased maintenance and staffing costs combined with higher property tax. | |
• | Depreciation — increased by $13 million reflecting the additional depreciation expense following the reduction in estimated useful lives of certain components of the region’s power plants as a result of new environmental regulation. | |
• | Offset by higher operating revenues — of approximately $62 million due to increased generation, favorable pricing and the favorable impact from new capacity markets. This was partially offset by lower gains in the region’s risk management activities and lower sales of emission allowances due to a 28% reduction in market prices. |
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• | Energy revenues —increased by approximately $138 million, of which $61 million was due to increased generation, and $88 million due to a 9% increase in average realized market prices partially offset by an $11 million reduction in contracted bilateral energy revenues. |
• | Generation — increased by 6%, primarily driven by increases at the region’s Arthur Kill, Oswego and Indian River plants. The Arthur Kill plant increased generation by 448 thousand MWh due to transmission constraints around New York City, the Oswego plants’ generation increased by 127 thousand MWh due to a colder winter during 2007 compared to 2006, and Indian River plants’ generation increased by 418 thousand MWh due to stronger pricing and fewer outages. | |
• | Price — on average, realized prices in the Northeast increased by 9% due to a mix of higher priced New York City generation coupled with improved economic energy hedge trading resulting in a $37 million increase in energy revenues. |
• | Capacity revenues — increased by $81 million, of which $39 million was from the region’s NEPOOL assets, $36 million from the region’s PJM assets and $6 million from the region’s New York Rest of State assets. |
• | NEPOOL — The region’s NEPOOL assets benefited from the new LFRM market and transition capacity market, both of which were introduced in the fourth quarter 2006. Capacity revenues increased by $24 million from the LFRM market and $18 million from transition capacity payments, which were partially offset by a $3 million reduction due to the expiration of an RMR agreement for the region’s Devon plant on December 31, 2006 and by RMR payments from the region’s Norwalk plant which began in the third quarter 2007. | |
• | PJM — On June 1, 2007, the new RPM capacity market became effective in PJM increasing capacity revenues by approximately $36 million. | |
• | NYISO — New York Rest of State capacity prices increased by 75% as load requirement growth increased demand for capacity. This was coupled with the impact from the new capacity markets in NEPOOL which reduced exported supply into the New York market that further improved the supply/demand dynamics. |
• | Risk management activities— The Northeast region recorded $27 million in derivative gain for the year ended December 31, 2007 compared to a $144 million gain for the year ended December 31, 2006. The region’s 2007 derivative gain was comprised of $16 million of mark-to-market losses and $43 million in settled gains, or financial revenue. Of the $16 million of mark-to-market losses, $45 million represents the reversal of mark-to-market gains previously recognized on economic hedges and $12 million from the reversal of mark-to-market gains previously recognized on trading activity. Both of these losses ultimately settled as financial revenues during 2007. The region also recognized a $15 million unrealized gain from economic hedge positions which was comprised primarily of a $13 million increase in the value of forward sales of electricity and fuel due to favorable power and gas prices. The region also recognized a $26 million unrealized gain associated with the Company’s trading activity. The $144 million derivative gain for the year ended December 31, 2006 was comprised of a $154 million unrealized mark-to-market gain and $10 million in settled losses. Most of these unrealized gains reversed out in 2007. | |
• | Other revenues— decreased by $40 million, of which approximately $48 million was due to reduced activity in the trading of emission allowances following both an increase in generation and a 28% decrease in market prices. This decrease was partially offset by an $11 million increase in physical gas sales to third parties due to favorable trading opportunities in the market. |
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• | Cost of energy increased by $26 million for the year ended December 31, 2007, compared to 2006, primarily due to $30 million in higher natural gas costs related to increased generation at the region’s Arthur Kill plant due to its locational advantage to New York City following transmission constraints during the last three quarters of 2007. |
• | Plant O&M spending — of $15 million due to increased plant staffing costs of $7 million, increased maintenance costs of $6 million and increased environmental remediation costs of $2 million. | |
• | Property tax — increased by approximately $3 million due to a favorable tax decision in 2006 related to NYC assets of $10 million partially offset by a tax law change the same year that resulted in a reduction of property tax receivable of $5 million in 2006 and a $2 million reduction in property taxes at the New England plants in 2007. | |
• | Regional G&A expenditures — Regional staffing and benefits increased by $3 million primarily related to the region’sRepoweringNRG development efforts while corporate allocations increased by $5 million. |
Year Ended December 31, | ||||||||||||
2006 | 2005 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 966 | $ | 1,444 | (33 | )% | ||||||
Capacity revenue | 321 | 291 | 10 | |||||||||
Risk management activities | 144 | (285 | ) | N/A | ||||||||
Other revenues | 112 | 104 | 8 | |||||||||
Total operating revenues | 1,543 | 1,554 | (1 | ) | ||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 615 | 869 | (29 | ) | ||||||||
Depreciation and amortization | 89 | 74 | 20 | |||||||||
Other operating expenses | $ | 378 | $ | 393 | (4 | ) | ||||||
Operating Income | 461 | 218 | 111 | |||||||||
MWh sold (in thousands) | 13,309 | 16,246 | (18 | ) | ||||||||
MWh generated (in thousands) | 13,309 | 16,246 | (18 | ) | ||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 67.73 | $ | 91.98 | (26 | ) | ||||||
Cooling Degree Days, or CDDs(a) | 653 | 801 | (18 | ) | ||||||||
CDD’s 30 year rolling average | 537 | 537 | — | |||||||||
Heating Degree Days, or HDDs(a) | 5,417 | 6,162 | (12 | )% | ||||||||
HDD’s 30 year rolling average | 6,261 | 6,261 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean |
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temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Risk management activities — of $144 million in mark-to-market gains from risk management activities, compared to a $285 million loss for the year ended December 31, 2005. The favorable gain from risk management activities was largely due to weak forward power prices, which resulted in substantial unrealized gains in the region’s forward positions for the year ended December 31, 2006. In 2005, forward mark-to-market losses and settlement of positions at losses was related to therun-up in natural gas prices which occurred in the wake of hurricanes Katrina and Rita. | |
• | Natural gas costs — mild weather reduced demand for natural gas, with average prices falling as much as 22% year over year. Falling natural gas prices reduced annual average power prices in the New York, NEPOOL and PJM markets by 23%, 20% and 19%, respectively. |
• | Generation — mild weather also led to an 18% decline in power generation for the Company’s Northeast region to 13.3 million MWh in 2006, compared to 16.2 million MWh in 2005. Generation from the region’s oil-fired assets declined by nearly 2 million MWh, representing 66% of the overall Northeast region’s generation decrease. Half of this decline was attributable to the region’s Western New York plants, which had more run time in 2005 due to that year’s cold January winter. |
• | Energy revenues — decreased by $478 million to $966 million due to lower generation from the region’s Oswego plant and lower realized price from generation from the region’s baseload coal plants which reduced energy revenues by $318 million. In addition, the region had $23 million of adjustments in 2005 relating to prior year NYISO settlements and a $6 million reversal of a reserve due to a favorable court decision regarding spinning reserve payments. | |
• | Capacity revenues — increased to $321 million, compared to $291 million for the same period in 2005. Of this increase, $28 million was due to higher capacity revenues in the New York State market. New York capacity revenues outside of New York City drove the increase in 2006, as increased demand for capacity, coupled with a decline in imports of capacity into the market, pushed clearing prices higher. Capacity prices were also favorably impacted in the region’s New England market by $16 million due to the new LFRM market and the new transition capacity market. The Northeast region also earned $9 million more in RMR payments in 2006 with the approval of new RMR agreements. These were partially offset by $23 million of reserve reversals in 2005 following the settlement of prior year RMR agreements. | |
• | Other revenues — which include emission allowance sales, natural gas sales, and expense recovery revenues, totaled $112 million for the year ended December 31, 2006, compared to $104 million in the same period in 2005, an increase of $8 million. This increase was primarily related to $17 million in higher emission allowance sales as the Company sold emission allowances in lieu of generation during the first quarter 2006. Higher emission allowance revenues were partially offset by lower gas sales of $2 million, lower ancillary revenues of $3 million and lack of cost recovery revenues of $5 million related to the 2005 RMR agreements. | |
• | Risk management activity — The total derivative gain for the year was $144 million, comprised of $10 million in financial revenue losses and $154 million of unrealized mark-to-market gains. The $10 million loss of financial revenues represents the settled value for the year of all financial instruments, |
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• | Cost of energy — decreased by $254 million to $615 million for the year ended December 31, 2006 due to 18% lower generation from the region’s generation assets which resulted in a $143 million decrease in oil fuel costs, as lower oil-fired generation accounted for 66% of the total decline in generation volume. Gas fuel costs for the Northeast region decreased by $101 million. Coal costs increased by $11 million, despite slightly lower generation, primarily due to higher rail transportation costs. Emission allowance amortization costs declined in 2006 by $18 million, primarily due to lower generation, which resulted in lower consumption of emission allowances. |
• | Plant utilities — decreased by $20 million. This was primarily due to a favorable court decision in the second quarter 2006 that allowed the Northeast region to reverse into earnings $18 million of previously accrued station power expense. | |
• | Insurance costs — decreased by $8 million due to favorable renewals. | |
• | Corporate allocations — decreased by $14 million due to the inclusion of the Texas region in our allocation methodology. |
• | Maintenance expense — increased by $15 million in 2006 primarily due to more extensive boiler tube work at the region’s Dunkirk and Arthur Kill plants to reduce forced outage hours, additional turbine maintenance and oil tank repair costs at the region’s Oswego facility. | |
• | Development costs — increased by $8 million to advance the region’sRepoweringNRG efforts. |
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Year Ended December 31, | ||||||||||||
2007 | 2006 | Change % | ||||||||||
(In millions except | ||||||||||||
otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 404 | $ | 334 | 21 | % | ||||||
Capacity revenue | 221 | 199 | 11 | |||||||||
Risk management activities | 10 | 13 | (23 | ) | ||||||||
Contract amortization | 23 | 19 | 21 | |||||||||
Other revenues | — | 5 | N/A | |||||||||
Total operating revenues | 658 | 570 | 15 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 412 | 308 | 34 | |||||||||
Depreciation and amortization | 68 | 68 | — | |||||||||
Other operating expenses | 121 | 89 | 36 | |||||||||
Operating Income | $ | 57 | $ | 105 | (46 | ) | ||||||
MWh sold (in thousands) | 12,452 | 11,845 | 5 | |||||||||
MWh generated (in thousands) | 10,930 | 11,036 | (1 | ) | ||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 59.62 | $ | 56.18 | 6 | |||||||
Cooling Degree Days, or CDDs(a) | 1,963 | 1,797 | 9 | |||||||||
CDD’s 30 year rolling average | 1,547 | 1,547 | — | |||||||||
Heating Degree Days, or HDDs(a) | 3,236 | 3,169 | 2 | % | ||||||||
HDD’s 30 year rolling average | 3,604 | 3,604 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Energy revenues — increased by approximately $70 million due to a new contract which contributed $69 million in contract energy revenues, increasing contract sales volume by approximately 1.3 million MWh. A contractual change in the fuel adjustment charge for the region’s cooperative customers increased energy revenues by an additional $11 million. This was offset by a $12 million decrease in merchant energy revenue as a result of satisfying increasing load requirement from the new contract. |
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• | Capacity revenues — increased by approximately $22 million, of which $15 million was due to higher rates as a result of the region setting new summer peaks in 2006 and 2007; the new system peak of 2,123 MW set in August 2007 will continue to impact capacity revenue in the first half of 2008. Higher network transmission costs, which are passed through to the region’s cooperative customers, also increased capacity revenues by $6 million. Improved market conditions in PJM resulted in an increase of $3 million in merchant capacity revenue from the Rockford plants. |
• | Purchased energy — increased by approximately $69 million as planned and maintenance outage hours at the region’s Big Cajun II facility increased by 1,209 hours, primarily due to the planned turbine/generator outage at the Big Cajun II Unit 3 facility in the fourth quarter 2007. These increases were offset by a drop of $2.53/MWh in realized purchased power prices. | |
• | Coal costs — increased by approximately $17 million, of which approximately $11 million was due to a 9% increase in coal prices and $7 million due to higher coal transportation costs. | |
• | Transmission costs — increased by approximately $16 million. Network transmission costs, which are passed-through to the region’s cooperative customers, increased by $6 million due to load growth and increased utilization of the Entergy transmission system. Point-to-point transmission costs to support off-system sales increased by $10 million. |
• | Maintenance expense — increased by approximately $19 million as the scope of work on planned outages were more extensive in 2007. The Big Cajun II Unit 3 facility incurred a major planned outage in the fourth quarter 2007, during which the generator was rewound, turbine controls were replaced with a modern digital control system, and the turbine steam path was replaced with a high-efficiency design. Asset disposals in conjunction with the outage added $4 million. | |
• | Franchise tax — Louisiana state franchise tax increased by approximately $6 million due to an increased assessment based on the Company’s total debt and equity. The Company’s total debt and equity increased significantly following the acquisition of Texas Genco LLC. |
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Year Ended December 31, | ||||||||||||
2006 | 2005 | Change % | ||||||||||
(In millions except | ||||||||||||
otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 334 | $ | 339 | (1 | )% | ||||||
Capacity revenue | 199 | 190 | 5 | |||||||||
Risk management activities | 13 | (2 | ) | N/A | ||||||||
Contract amortization | 19 | 9 | 111 | |||||||||
Other revenues | 5 | 24 | (79 | ) | ||||||||
Total operating revenues | 570 | 560 | 2 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 308 | 374 | (18 | ) | ||||||||
Depreciation and amortization | 68 | 67 | 1 | |||||||||
Other operating expenses | 89 | 111 | (20 | ) | ||||||||
Operating Income | $ | 105 | $ | 8 | N/A | |||||||
MWh sold (in thousands) | 11,845 | 11,771 | 1 | |||||||||
MWh generated (in thousands) | 11,036 | 10,009 | 10 | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 56.18 | $ | 69.96 | (20 | ) | ||||||
Cooling Degree Days, or CDDs(a) | 1,797 | 1,811 | (1 | ) | ||||||||
CDD’s 30 year rolling average | 1,547 | 1,547 | — | |||||||||
Heating Degree Days, or HDDs(a) | 3,169 | 3,366 | (6 | )% | ||||||||
HDD’s 30 year rolling average | 3,604 | 3,604 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Better plant availability — due to lower planned and forced outages in 2006, which resulted in 11% higher coal generation in 2006 than 2005. The Big Cajun II facility achieved an EFOR of 3.13% in 2006 compared to 6.56% in 2005, resulting in 907 fewer forced outage hours in 2006. | |
• | Lower outages — In addition, the Big Cajun II coal units experienced 826 less planned outage hours in 2006 than in 2005. The forced outages in 2005 occurred primarily during the peak summer months when contract load is highest, requiring increased energy purchases than in 2006. These fewer planned outages in 2006 also resulted in $12 million of lower major maintenance expense, which benefited operating income. | |
• | Favorable price spreads — allowed for resale of power received from the region’s tolling agreements, providing additional margins. |
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• | Energy revenues — increased sales to the region’s contract customers were offset by lower sales in the merchant market. | |
• | Capacity revenues — were $9 million higher for the year ended December 31, 2006 than in the same period for 2005, as the peak of 2011 MW set by the region’s cooperative customers in August 2006 impacted capacity revenue in the latter half of 2006. | |
• | Risk management activities — The region recognized $13 million from risk management activities in 2006. | |
• | Contract amortization — increased by $10 million due to increased megawatt hour sales to contract customers and the expiration of the Rockford contract in 2005. | |
• | Other revenues — decreased by $19 million from 2005 levels, primarily due to $23 million in lower gas sales relating to the region’s tolling agreements. |
• | Lower purchased power — the cost of purchased power, including the costs of the region’s tolling agreements, was $74 million in 2006, a decrease of $71 million from 2005. This decrease was primarily due to fewer forced outages at the region’s baseload coal plants in 2006 and the impact of netting energy purchases and resale. A drop in average purchased power prices by $9/MWh from 2005 to 2006 also contributed to the reduction in purchased power costs. As a result of improved plant availability, energy purchased by the South Central region to support load contracts dropped 16%. The South Central region increased its use of generation from tolled facilities in 2006; tolled combined cycle plants contributed 1,451,758 MWh to the region’s energy resources in 2006 compared to 474,386 MWh in 2005. The tolling agreements further contributed to the region’s results as the spread between gas costs and energy costs widened in the summer of 2006. |
• | Transmission costs — increased by $7 million due to a combination of contractual increases in network transmission rates and higher peaks in 2006. | |
• | Coal costs — increased by $25 million, reflecting contractual increases in coal commodity costs and higher plant availability in 2006. |
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Year Ended December 31, | ||||||||||||
2007 | 2006 | Change % | ||||||||||
(In millions except | ||||||||||||
otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 4 | $ | 75 | (95 | )% | ||||||
Capacity revenue | 122 | 68 | 79 | |||||||||
Risk management activities | — | (3 | ) | N/A | ||||||||
Other revenues | 1 | 6 | (83 | ) | ||||||||
Total operating revenues | 127 | 146 | (13 | ) | ||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 5 | 80 | (94 | ) | ||||||||
Depreciation and amortization | 3 | 3 | — | |||||||||
Other operating expenses | 80 | 55 | 45 | |||||||||
Operating Income | $ | 39 | $ | 8 | 388 | |||||||
MWh sold (in thousands) | 1,246 | 1,901 | (34 | ) | ||||||||
MWh generated (in thousands) | 1,246 | 1,901 | (34 | ) | ||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 66.52 | $ | 61.54 | 8 | |||||||
Cooling Degree Days, or CDDs(a) | 785 | 926 | (15 | ) | ||||||||
CDD’s 30 year rolling average | 704 | 704 | — | |||||||||
Heating Degree Days, or HDDs(a) | 3,048 | 3,001 | 2 | % | ||||||||
HDD’s 30 year rolling average | 3,228 | 3,228 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Capacity revenues —increased by approximately $28 million, excluding the first quarter 2007, due to new tolling agreements at the region’s Encina and Long Beach plants: |
• | Encina — In January 2007, NRG signed a new tolling agreement for the region’s Encina plant which contributed $15 million in capacity revenues for the year ended December 31, 2007. | |
• | Long Beach — On August 1, 2007, NRG successfully completed the repowering of a 260 MW natural gas-fueled generating plant at its Long Beach generating facility, which contributed approximately $13 million in capacity revenues for the year ended December 31, 2007. |
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• | Cost of energy —decreased by $76 million, excluding the first quarter 2007, due to the new tolling agreement entered into at the Encina plant in 2007, which required the counterparty to supply their own fuel. Under the previous arrangement in 2006, the plant supplied the fuel. |
• | Energy revenues — decreased by approximately $72 million, excluding the first quarter 2007, primarily due to the tolling agreement at the Encina plant that has resulted in the receipt of fixed monthly capacity payment in return for the right to schedule and dispatch from the plant. The Encina tolling agreement replaced the RMR agreement under which the plant was called upon to generate revenues for such dispatch. | |
• | O&M expense— increased by approximately $6 million, excluding the first quarter 2007, primarily due to increases in labor costs, major maintenance and auxiliary power. | |
• | Development expenses — increased by $4 million, reflectingRepoweringNRG initiatives at the region’s El Segundo and Encina sites. | |
• | Other revenues — decreased ancillary service revenue of $3 million at the Encina plant due to the new tolling agreement that consigns ancillary service revenue to the counterparty in exchange for a fixed monthly capacity payment. |
Year Ended December 31, | ||||||||||||
2006 | 2005 | Change % | ||||||||||
(In millions except | ||||||||||||
otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 75 | $ | 1 | N/A | |||||||
Capacity revenue | 68 | — | N/A | |||||||||
Risk management activities | (3 | ) | — | N/A | ||||||||
Other revenues | 6 | 3 | 100 | |||||||||
Total operating revenues | 146 | 4 | N/A | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 80 | 1 | N/A | |||||||||
Depreciation and amortization | 3 | 1 | 200 | |||||||||
Other operating expenses | 55 | 8 | 588 | |||||||||
Operating Income/(loss) | $ | 8 | $ | (6 | ) | N/A | ||||||
MWh sold (in thousands) | 1,901 | 6 | N/A | |||||||||
MWh generated (in thousands) | 1,901 | 6 | N/A | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 61.54 | $ | 71.06 | (13 | ) | ||||||
Cooling Degree Days, or CDDs(a) | 926 | 775 | 19 | |||||||||
CDD’s 30 year rolling average | 704 | 704 | — | |||||||||
Heating Degree Days, or HDDs(a) | 3,001 | 2,842 | 6 | % | ||||||||
HDD’s 30 year rolling average | 3,228 | 3,228 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
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As of December 31, | 2007 | 2006 | ||||||
(In millions) | ||||||||
Cash and cash equivalents | $ | 1,132 | $ | 795 | ||||
Restricted cash | 29 | 44 | ||||||
Total cash | 1,161 | 839 | ||||||
Synthetic letter of credit availability | 557 | 533 | ||||||
Revolver credit facility availability | 997 | 855 | ||||||
Total liquidity | $ | 2,715 | $ | 2,227 | ||||
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S&P | Moody’s | Fitch | ||||||||||
NRG Energy, Inc. | B+ | Ba3 | B | |||||||||
7.375% Senior Notes, due 2016, 2017 | B | B1 | B+ | |||||||||
7.25% Senior Notes due 2014 | B | B1 | B+ | |||||||||
Term Loan | BB | Ba1 | BB |
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Equivalent Net Sales Secured by First and Second Lien Structure(a) | 2008 | 2009 | 2010 | 2011 | 2012 | |||||||||||||||
In MW(b) | 3,283 | 3,811 | 3,050 | 3,264 | 572 | |||||||||||||||
As a percentage of total forecasted baseload capacity | 57 | % | 55 | % | 45 | % | 48 | % | 9 | % |
(a) | Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region. | |
(b) | 2008 MW value consists of March through December positions only. |
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Maintenance | Environmental | Repowering | Total | |||||||||
(In millions) | ||||||||||||
Northeast | $ | 28 | $ | 71 | $ | 7 | $ | 106 | ||||
Texas | 143 | 2 | 45 | 190 | ||||||||
South Central | 29 | 1 | — | 30 | ||||||||
West | 4 | — | 76 | 80 | ||||||||
Wind | — | — | 69 | 69 | ||||||||
Other | 6 | — | — | 6 | ||||||||
Total | $ | 210 | $ | 74 | $ | 197 | $ | 481 | ||||
Estimated capital expenditures for 2008 | $ | 234 | $ | 359 | $ | 603 | $ | 1,196 | ||||
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Texas | Northeast | South Central | Total | |||||||||
(In millions) | ||||||||||||
2008 | $ | 3 | $ | 223 | $ | 133 | $ | 359 | ||||
2009 | 5 | 192 | 211 | 408 | ||||||||
2010 | 24 | 178 | 117 | 319 | ||||||||
2011 | 28 | 112 | 53 | 193 | ||||||||
2012 | 11 | 66 | 15 | 92 | ||||||||
Total | $ | 71 | $ | 771 | $ | 529 | $ | 1,371 | ||||
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Subsidiary/Description | 2008 | 2009 | 2010 | 2011 | 2012 | Thereafter | Total | ||||||||||||||
(In millions) | |||||||||||||||||||||
Debt: | |||||||||||||||||||||
7.375% Notes due 2017 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 1,100 | $ | 1,100 | |||||||
7.25% Notes due 2014 | — | — | — | — | — | 1,200 | 1,200 | ||||||||||||||
7.375% Notes due 2016 | — | — | — | — | — | 2,400 | 2,400 | ||||||||||||||
Term Loan, due 2013 | 184 | 31 | 32 | 31 | 31 | 2,506 | 2,815 | ||||||||||||||
CSF Non-Recourse Obligations | 190 | 143 | — | — | — | — | 333 | ||||||||||||||
NRG Energy Center Minneapolis, due 2013 and 2017 | 10 | 11 | 11 | 12 | 13 | 37 | 94 | ||||||||||||||
NRG Peaker Finance Co LLC | 13 | 15 | 20 | 21 | 22 | 188 | 279 | ||||||||||||||
Subtotal Debt, Bonds and Notes | 397 | 200 | 63 | 64 | 66 | 7,431 | 8,221 | ||||||||||||||
Capital Lease: | |||||||||||||||||||||
Saale Energie GmbH, Schkopau | 75 | 26 | 12 | 6 | 5 | 57 | 181 | ||||||||||||||
Total Payments and Capital Leases | $ | 472 | $ | 226 | $ | 75 | $ | 70 | $ | 71 | $ | 7,488 | $ | 8,402 | |||||||
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Year Ended December 31, | 2007 | 2006 | Change | |||||||||
(In millions) | ||||||||||||
Net cash provided by operating activities | $ | 1,517 | $ | 408 | $ | 1,109 | ||||||
Net cash provided/(used) by investing activities | (327 | ) | (4,176 | ) | 3,849 | |||||||
Net cash provided/(used) by financing activities | (814 | ) | 4,053 | (4,867 | ) |
• | Hedge Reset and derivative activity — this increase was primarily due to the write off of power contracts of $1.1 billion in the fourth quarter of 2006 and a corresponding $339 million reduction in contract amortization during 2007 compared to 2006 as a result of the Hedge Reset transaction. In addition, net income increased $226 million as a result of adjustments for derivative activity. | |
• | Collateral deposits — following an upward shift of the forward price curves, NRG’s net collateral deposits in support of derivative contracts increased by $125 million for the year ended December 31, 2007, compared to a decrease of $454 million during the same period in 2006, a difference of $579 million. As of December 31, 2007, NRG had net cash collateral deposit of $85 million. |
• | Texas acquisition — that occurred during the first quarter 2006. NRG acquired Texas Genco LLC for approximately $6.2 billion that included the issuance of common stock at a value of $1.7 billion and a net cash payment of approximately $4.3 billion; | |
• | Capital expenditures — NRG’s capital expenditures increased by $260 million due to expenditures of approximately $197 million forRepoweringNRG projects, primarily related to $76 million for the Long Beach plant and $67 million in deposits for wind turbines. In addition, the Company initiated a baghouse project at the Huntley and Dunkirk plants which also increased capital expenditures by approximately $71 million. | |
• | Discontinued Operations and Asset Sales — In 2006 NRG received proceeds of $261 million from the sale of Flinders, Audrain, and Resource Recovery. The sale of the Company’s Red Bluff and Chowchilla plants and equipment resulted in increased proceeds from asset sales by approximately $57 million for 2007. |
• | During the first quarter 2006, NRG acquired Texas Genco LLC. As part of the acquisition, NRG refinanced the Company’s outstanding debt as well as Texas Genco LLC’s outstanding debt, and also issued new debt, preferred stock and common stock to fund the acquisition: |
• | Total debt repayments were $4.6 billion — $1.9 billion of NRG debt and $2.7 billion of Texas Genco LLC debt. | |
• | Total proceeds from debt issued were $7.2 billion — $3.6 billion from unsecured notes and $3.6 billion from a senior secured facility, including a $1.0 billion Revolving Credit Facility, and a $1.5 billion Synthetic Letter of Credit Facility. |
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• | Total proceeds from stock issued of approximately $1.5 billion - net proceeds of $986 million from issuing approximately 21 million shares of common stock and net proceeds of $486 million from issuing 2 million shares of the Company’s 5.75% Preferred Stock. |
• | For the year ended December 31, 2007, NRG repurchased 9,049,400 shares of the Company’s common stock for approximately $353 million. For the year ended December 31, 2006, NRG repurchased 29,601,162 shares for $732 million. The Company also used cash on hand to repay, without penalty, $300 million of its Term B loan under the Senior Credit Facility. |
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By Remaining Maturity at December 31, | ||||||||||||||||||
2007 | ||||||||||||||||||
Under | Over | 2006 | ||||||||||||||||
Contractual Cash Obligations | 1 Year | 1-3 Years | 3-5 Years | 5 Years | Total | Total | ||||||||||||
(In millions) | ||||||||||||||||||
Long-term debt (including estimated interest) | $ | 1,010 | $ | 1,407 | $ | 1,263 | $ | 8,621 | $ | 12,301 | $ | 13,348 | ||||||
Capital lease obligations (including estimated interest) | 93 | 66 | 28 | 203 | 390 | 403 | ||||||||||||
Operating leases | 40 | 73 | 64 | 243 | 420 | 427 | ||||||||||||
Fuel purchase and transportation obligations(a) | 1,614 | 1,059 | 299 | 231 | 3,203 | 3,646 | ||||||||||||
Total contractual cash obligations | $ | 2,757 | $ | 2,605 | $ | 1,654 | $ | 9,298 | $ | 16,314 | $ | 17,824 | ||||||
(a) | Includes only those coal transportation commitments for 2008 as no other nominations were made as of December 31, 2007. |
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By Remaining Maturity at December 31, | ||||||||||||||||||
2007 | ||||||||||||||||||
Under | Over | 2006 | ||||||||||||||||
Guarantees | 1 Year | 1-3 Years | 3-5 Years | 5 Years | Total | Total | ||||||||||||
(In millions) | ||||||||||||||||||
Synthetic letters of credit | $ | 475 | $ | 268 | $ | — | $ | — | $ | 743 | $ | 967 | ||||||
Unfunded standby letters of credit and surety bonds | 8 | — | — | — | 8 | 153 | ||||||||||||
Asset sales guarantee obligations | 13 | — | 113 | 22 | 148 | 144 | ||||||||||||
Commodity sales guarantee obligations | 93 | 134 | — | 564 | 791 | 604 | ||||||||||||
Other guarantees | — | — | — | 32 | 32 | 29 | ||||||||||||
Total guarantees | $ | 589 | $ | 402 | $ | 113 | $ | 618 | $ | 1,722 | $ | 1,897 | ||||||
Derivative Activity Gains/(Losses) | (In millions) | |||
Fair value of contracts as of December 31, 2006 | $ | 354 | ||
Contracts realized or otherwise settled during the period | (292 | ) | ||
Changes in fair value | (554 | ) | ||
Fair value of contracts as of December 31, 2007 | $ | (492 | ) | |
Fair Value of Contracts as of December 31, 2007 | |||||||||||||||||||
Maturity | Maturity | ||||||||||||||||||
Less Than | Maturity | Maturity | in Excess | Total Fair | |||||||||||||||
Sources of Fair Value Gains/(Losses) | 1 Year | 1-3 Years | 4-5 Years | 4-5 Years | Value | ||||||||||||||
(In millions) | |||||||||||||||||||
Prices actively quoted | $ | 4 | $ | 2 | $ | — | $ | — | $ | 6 | |||||||||
Prices provided by other external sources | 89 | (198 | ) | (394 | ) | (22 | ) | (525 | ) | ||||||||||
Prices provided by models and other valuation methods | 23 | 2 | 2 | — | 27 | ||||||||||||||
Total | $ | 116 | $ | (194 | ) | $ | (392 | ) | $ | (22 | ) | $ | (492 | ) | |||||
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Accounting Policy | Judgments/Uncertainties Affecting Application | |||
Derivative Financial Instruments | • | Assumptions used in valuation techniques | ||
• | Assumptions used in forecasting generation | |||
• | Market maturity and economic conditions | |||
• | Contract interpretation | |||
• | Market conditions in the energy industry, especially the effects of price volatility on contractual commitments | |||
• | Regulatory and political environments and requirements | |||
Income Taxes and Valuation Allowance for Deferred Tax Assets | • | Ability of tax authority decisions to withstand legal challenges or appeals | ||
• | Anticipated future decisions of tax authorities | |||
• | Application of tax statutes and regulations to transactions | |||
• | Ability to utilize tax benefits through carrybacks to prior periods and carryforwards to future periods | |||
Impairment of Long Lived Assets | • | Recoverability of investment through future operations | ||
• | Regulatory and political environments and requirements | |||
• | Estimated useful lives of assets | |||
• | Environmental obligations and operational limitations |
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Accounting Policy | Judgments/Uncertainties Affecting Application | |||
• | Estimates of future cash flows | |||
• | Estimates of fair value (fresh start) | |||
• | Judgment about triggering events | |||
Goodwill and Other Intangible Assets | • | Estimated useful lives for finite-lived intangible assets | ||
• | Judgment about impairment triggering events | |||
• | Estimates of reporting unit’s fair value | |||
• | Fair value estimate of certain power sales and fuel contracts using forward pricing curves as of the closing date over the life of each contract | |||
Contingencies | • | Estimated financial impact of event(s) | ||
• | Judgment about likelihood of event(s) occurring |
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• | Significant decrease in the market price of a long-lived asset; | |
• | Significant adverse change in the manner an asset is being used or its physical condition; | |
• | Adverse business climate; | |
• | Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset, | |
• | Current-period loss combined with a history of losses or the projection of future losses; and | |
• | Change in the Company’s intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life. |
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Item 7A — | Quantitative and Qualitative Disclosures about Market Risk |
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• | Manage and hedge fixed-price purchase and sales commitments; | |
• | Manage and hedge exposure to variable rate debt obligations; | |
• | Reduce exposure to the volatility of cash market prices; and | |
• | Hedge fuel requirements for the Company’s generating facilities. |
• | Seasonal, daily and hourly changes in demand; | |
• | Extreme peak demands due to weather conditions; | |
• | Available supply resources; | |
• | Transportation availability and reliability within and between regions; and | |
• | Changes in the nature and extent of federal and state regulations. |
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VAR | In millions | |||
As of December 31, 2007(b) | $ | 64 | ||
Average | 28 | |||
Maximum | 64 | |||
Minimum | 14 | |||
As of December 31, 2006 | $ | 18 | ||
Average(a) | 39 | |||
Maximum(a) | 67 | |||
Minimum(a) | 17 |
(a) | Includes Texas region portfolio beginning the third quarter 2006. | |
(b) | Prior to December 4, 2007, NRG’s VAR measurement was based on a rolling24-month forward looking period |
Period of Swap | Notional Value | Maturity | ||||||
2 - year | $ | 140 million | March 31, 2008 | |||||
3 - year | $ | 150 million | March 31, 2009 | |||||
4 - year | $ | 190 million | March 31, 2010 | |||||
5 - year | $ | 1.55 billion | March 31, 2011 |
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Exposure | ||||||||||||
Before | Net | |||||||||||
Credit Exposure | Collateral | Collateral | Exposure | |||||||||
(In millions, except ratios) | ||||||||||||
Investment grade | $ | 1,446 | $ | 464 | $ | 982 | ||||||
Non-investment grade | 39 | 9 | 30 | |||||||||
Not rated | 171 | 11 | 160 | |||||||||
Total | $ | 1,656 | $ | 484 | $ | 1,172 | ||||||
Investment grade | 87 | % | 96 | % | 84 | % | ||||||
Non-investment grade | 2 | % | 2 | % | 3 | % | ||||||
Not rated | 10 | % | 2 | % | 14 | % |
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Item 8 — | Financial Statements and Supplementary Data |
Item 9A — | Controls and Procedures |
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1. | Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; | |
2. | Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and | |
3. | Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements. |
Item 9B — | Other Information |
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Item 10 — | Directors, Executive Officers and Corporate Governance |
athttp://www.nrgenergy.com/investor/corpgov/.htm.NRG Energy, Inc. also elects to disclose the information required byForm 8-K, Item 5.05, “Amendments to the registrant’s code of ethics, or waiver of a provision of the code of ethics,” through the Company’s website, and such information will remain available on this website for at least a12-month period. A copy of the “NRG Energy, Inc. Code of Conduct” is available in print to any shareholder who requests it.
Item 11 — | Executive Compensation |
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Item 12 — | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Item 13 — | Certain Relationships and Related Transactions, and Director Independence |
Item 14 — | Principal Accountant Fees and Services |
(b) | Exhibits |
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For the | For the | For the | ||||||||||
Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions except per share amounts) | ||||||||||||
Operating Revenues | ||||||||||||
Total operating revenues | $ | 5,989 | $ | 5,585 | $ | 2,400 | ||||||
Operating Costs and Expenses | ||||||||||||
Cost of operations | 3,378 | 3,265 | 1,829 | |||||||||
Depreciation and amortization | 658 | 590 | 158 | |||||||||
General and administrative | 309 | 276 | 176 | |||||||||
Development costs | 101 | 36 | — | |||||||||
Other charges | — | — | 12 | |||||||||
Total operating costs and expenses | 4,446 | 4,167 | 2,175 | |||||||||
Gain on sale of assets | 17 | — | — | |||||||||
Operating Income | 1,560 | 1,418 | 225 | |||||||||
Other Income/(Expense) | ||||||||||||
Equity in earnings of unconsolidated affiliates | 54 | 60 | 104 | |||||||||
Write downs and gains/(losses) on sales of equity method investments | 1 | 8 | (31 | ) | ||||||||
Other income, net | 55 | 156 | 54 | |||||||||
Refinancing expenses | (35 | ) | (187 | ) | (65 | ) | ||||||
Interest expense | (689 | ) | (590 | ) | (177 | ) | ||||||
Total other expenses | (614 | ) | (553 | ) | (115 | ) | ||||||
Income From Continuing Operations Before Income Taxes | 946 | 865 | 110 | |||||||||
Income tax expense | 377 | 322 | 42 | |||||||||
Income From Continuing Operations | 569 | 543 | 68 | |||||||||
Income from discontinued operations, net of income taxes | 17 | 78 | 16 | |||||||||
Net Income | 586 | 621 | 84 | |||||||||
Preference stock dividends | 55 | 50 | 20 | |||||||||
Income Available for Common Stockholders | $ | 531 | $ | 571 | $ | 64 | ||||||
Weighted average number of common shares outstanding — basic | 240 | 258 | 169 | |||||||||
Income from continuing operations per weighted average common share — basic | $ | 2.14 | $ | 1.90 | $ | 0.28 | ||||||
Income from discontinued operations per weighted average common share — basic | 0.07 | 0.31 | 0.10 | |||||||||
Net Income per Weighted Average Common Share — Basic | $ | 2.21 | $ | 2.21 | $ | 0.38 | ||||||
Weighted average number of common shares outstanding — diluted | 288 | 301 | 171 | |||||||||
Income from continuing operations per weighted average common share — diluted | $ | 1.95 | $ | 1.78 | $ | 0.28 | ||||||
Income from discontinued operations per weighted average common share — diluted | 0.06 | 0.26 | 0.10 | |||||||||
Net Income per Weighted Average Common Share — Diluted | $ | 2.01 | $ | 2.04 | $ | 0.38 | ||||||
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As of | As of | |||||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(In millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 1,132 | $ | 777 | ||||
Restricted cash | 29 | 41 | ||||||
Accounts receivable — trade, less allowance for doubtful accounts of $1 and $1 | 482 | 369 | ||||||
Current portion of capital lease | 30 | 27 | ||||||
Taxes receivable | 58 | 63 | ||||||
Inventory | 451 | 420 | ||||||
Derivative instruments valuation | 1,034 | 1,230 | ||||||
Deferred income taxes | 124 | �� | — | |||||
Collateral on deposits in support of energy risk management activities | 85 | 27 | ||||||
Prepayments and other current assets | 86 | 105 | ||||||
Current assets — discontinued operations | 51 | 24 | ||||||
Total current assets | 3,562 | 3,083 | ||||||
Property, Plant and Equipment | ||||||||
In service | 12,678 | 12,433 | ||||||
Under construction | 337 | 87 | ||||||
Total property, plant and equipment | 13,015 | 12,520 | ||||||
Less accumulated depreciation | (1,695 | ) | (974 | ) | ||||
Net property, plant and equipment | 11,320 | 11,546 | ||||||
Other Assets | ||||||||
Equity investments in affiliates | 425 | 344 | ||||||
Note receivable — affiliates | 126 | 114 | ||||||
Capital lease, less current portion | 365 | 365 | ||||||
Goodwill | 1,786 | 1,789 | ||||||
Intangible assets, net of accumulated amortization of $372 and $259 | 873 | 981 | ||||||
Nuclear decommissioning trust fund | 384 | 352 | ||||||
Derivative instruments valuation | 150 | 439 | ||||||
Other non-current assets | 176 | 262 | ||||||
Intangible assets held-for-sale | 14 | 79 | ||||||
Non-current assets — discontinued operations | 93 | 82 | ||||||
Total other assets | 4,392 | 4,807 | ||||||
Total Assets | $ | 19,274 | $ | 19,436 | ||||
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As of | As of | |||||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(In millions, except share data) | ||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Current portion of long-term debt and capital leases | $ | 466 | $ | 123 | ||||
Accounts payable — trade | 381 | 327 | ||||||
Accounts payable — affiliates | 3 | 2 | ||||||
Derivative instruments valuation | 917 | 964 | ||||||
Deferred income taxes | — | 164 | ||||||
Accrued interest expense | 185 | 131 | ||||||
Other accrued expenses | 189 | 130 | ||||||
Other current liabilities | 99 | 163 | ||||||
Current liabilities — discontinued operations | 37 | 28 | ||||||
Total current liabilities | 2,277 | 2,032 | ||||||
Other Liabilities | ||||||||
Long-term debt and capital leases | 7,895 | 8,603 | ||||||
Nuclear decommissioning reserve | 307 | 289 | ||||||
Nuclear decommissioning trust liability | 326 | 324 | ||||||
Postretirement and other benefit obligations | 263 | 301 | ||||||
Deferred income taxes | 843 | 554 | ||||||
Derivative instruments valuation | 759 | 351 | ||||||
Out-of-market contracts | 628 | 897 | ||||||
Other non-current liabilities | 149 | 116 | ||||||
Non-current liabilities — discontinued operations | 76 | 64 | ||||||
Total non-current liabilities | 11,246 | 11,499 | ||||||
Total Liabilities | 13,523 | 13,531 | ||||||
3.625% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs) | 247 | 247 | ||||||
Commitments and Contingencies | ||||||||
Stockholders’ Equity | �� | |||||||
4% convertible perpetual preferred stock; $0.01 par value; 420,000 shares issued and outstanding (at liquidation value of $420, net of issuance costs) | 406 | 406 | ||||||
5.75% convertible perpetual preferred stock; $0.01 par value, 2,000,000 shares issued and outstanding (at liquidation value of $500, net of issuance costs) | 486 | 486 | ||||||
Common Stock; $0.01 par value; 500,000,000 shares authorized; 261,285,529 and 274,248,264 shares issued and 236,734,929 and 244,647,102 outstanding at December 31, 2007 and 2006 | 3 | 3 | ||||||
Additional paid-in-capital | 4,092 | 4,474 | ||||||
Retained earnings | 1,270 | 739 | ||||||
Less treasury stock, at cost — 24,550,600 and 29,601,162 shares at December 31, 2007 and 2006 | (638 | ) | (732 | ) | ||||
Accumulated other comprehensive (loss)/income | (115 | ) | 282 | |||||
Total Stockholders’ Equity | 5,504 | 5,658 | ||||||
Total Liabilities and Stockholders’ Equity | $ | 19,274 | $ | 19,436 | ||||
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Accumulated | ||||||||||||||||||||||||||||||||||||
Additional | Other | Total | ||||||||||||||||||||||||||||||||||
Serial Preferred | Common | Paid-In | Retained | Treasury | Comprehensive | Stockholders’ | ||||||||||||||||||||||||||||||
Stock | Shares | Stock | Shares | Capital | Earnings | Stock | Income/(Loss) | Equity | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Balances at December 31, 2004 | $ | 406 | 0.4 | $ | 3 | 174 | $ | 2,415 | $ | 197 | $ | (405 | ) | $ | 76 | $ | 2,692 | |||||||||||||||||||
Net income | 84 | 84 | ||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | (72 | ) | (72 | ) | ||||||||||||||||||||||||||||||||
Unrealized loss on derivatives | (203 | ) | (203 | ) | ||||||||||||||||||||||||||||||||
Minimum pension liability, net of $3 tax | (6 | ) | (6 | ) | ||||||||||||||||||||||||||||||||
Comprehensive loss for 2005 | (197 | ) | ||||||||||||||||||||||||||||||||||
Equity-based compensation | 14 | 14 | ||||||||||||||||||||||||||||||||||
Preferred stock dividends | (20 | ) | (20 | ) | ||||||||||||||||||||||||||||||||
Purchase of treasury stock | (13 | ) | (258 | ) | (258 | ) | ||||||||||||||||||||||||||||||
Balances at December 31, 2005 | $ | 406 | 0.4 | $ | 3 | 161 | $ | 2,429 | $ | 261 | $ | (663 | ) | $ | (205 | ) | $ | 2,231 | ||||||||||||||||||
Net income | 621 | 621 | ||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | 60 | 60 | ||||||||||||||||||||||||||||||||||
Unrealized gain on derivatives, net of $135 tax | 405 | 405 | ||||||||||||||||||||||||||||||||||
Minimum pension liability, net of $3 tax | 7 | 7 | ||||||||||||||||||||||||||||||||||
Comprehensive income for 2006 | 1,093 | |||||||||||||||||||||||||||||||||||
Impact upon adoption of SFAS 158, net of $10 tax | 15 | 15 | ||||||||||||||||||||||||||||||||||
Reduction to tax valuation allowance | 17 | 17 | ||||||||||||||||||||||||||||||||||
Impact upon adoption of EITF 04-6 | (93 | ) | (93 | ) | ||||||||||||||||||||||||||||||||
Equity-based compensation | 14 | 14 | ||||||||||||||||||||||||||||||||||
Issuance of common stock to the public | 42 | 986 | 986 | |||||||||||||||||||||||||||||||||
Issuance of preferred stock | 486 | 2.0 | 486 | |||||||||||||||||||||||||||||||||
Issuance of common and treasury stock to the shareholders of Texas Genco LLC | 71 | 1,028 | 663 | 1,691 | ||||||||||||||||||||||||||||||||
Preferred stock dividends | (50 | ) | (50 | ) | ||||||||||||||||||||||||||||||||
Purchase of treasury stock | (29 | ) | (732 | ) | (732 | ) | ||||||||||||||||||||||||||||||
Balances at December 31, 2006 | $ | 892 | 2.4 | $ | 3 | 245 | $ | 4,474 | $ | 739 | $ | (732 | ) | $ | 282 | $ | 5,658 | |||||||||||||||||||
Net income | 586 | 586 | ||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | 73 | 73 | ||||||||||||||||||||||||||||||||||
Unrealized loss on derivatives, net of $310 tax benefit | (474 | ) | (474 | ) | ||||||||||||||||||||||||||||||||
Available-for-sale securities, net of $1 tax | 2 | 2 | ||||||||||||||||||||||||||||||||||
Defined benefit plan — prior service cost of $4 and net loss of $(2), net of $2 tax | 2 | 2 | ||||||||||||||||||||||||||||||||||
Comprehensive income for 2007 | 189 | |||||||||||||||||||||||||||||||||||
Equity-based compensation | 1 | 9 | 9 | |||||||||||||||||||||||||||||||||
Reduction to tax valuation allowance | 56 | 56 | ||||||||||||||||||||||||||||||||||
Preferred stock dividends | (55 | ) | (55 | ) | ||||||||||||||||||||||||||||||||
Purchase of treasury stock | (9 | ) | (353 | ) | (353 | ) | ||||||||||||||||||||||||||||||
Retirement of treasury stock | (447 | ) | 447 | — | ||||||||||||||||||||||||||||||||
Balances at December 31, 2007 | $ | 892 | 2.4 | $ | 3 | 237 | $ | 4,092 | $ | 1,270 | $ | (638 | ) | $ | (115 | ) | $ | 5,504 | ||||||||||||||||||
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Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Cash Flows from Operating Activities | ||||||||||||
Net income | $ | 586 | $ | 621 | $ | 84 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||||||
Distributions less than equity in earnings of unconsolidated affiliates | (33 | ) | (33 | ) | (8 | ) | ||||||
Depreciation and amortization of nuclear fuel | 719 | 654 | 195 | |||||||||
Amortization and write-off of deferred financing costs and debt discount/premiums | 66 | 79 | 14 | |||||||||
Amortization of intangibles and out-of-market contracts | (156 | ) | (490 | ) | 17 | |||||||
Amortization of equity-based compensation | 19 | 14 | 12 | |||||||||
Write down and (gains)/losses on sale of equity method investments | (1 | ) | (8 | ) | 31 | |||||||
(Gain)/loss on sale and disposal of equipment | (17 | ) | 10 | 4 | ||||||||
Impairment charges and asset write downs | 20 | — | 6 | |||||||||
Changes in derivatives | 77 | (149 | ) | 143 | ||||||||
Changes in deferred income taxes | 352 | 327 | 2 | |||||||||
Gain on legal settlement | — | (67 | ) | (14 | ) | |||||||
Gain on sale of discontinued operations | — | (76 | ) | (6 | ) | |||||||
Gain on sale of emission allowances | (31 | ) | (64 | ) | — | |||||||
Change in nuclear decommissioning trust liability | 32 | 12 | — | |||||||||
Changes in collateral deposits supporting energy risk management activities | (125 | ) | 454 | (405 | ) | |||||||
Settlement of out-of-market power contracts | — | (1,073 | ) | — | ||||||||
Cash provided by changes in other working capital, net of acquisition and disposition effects | ||||||||||||
Accounts receivable, net | (102 | ) | 87 | (8 | ) | |||||||
Inventory | (38 | ) | (50 | ) | (14 | ) | ||||||
Prepayments and other current assets | 22 | 43 | (35 | ) | ||||||||
Accounts payable | 49 | (73 | ) | 57 | ||||||||
Accrued expenses and other current liabilities | 106 | 133 | (16 | ) | ||||||||
Other assets and liabilities | (28 | ) | 57 | 9 | ||||||||
Net Cash Provided by Operating Activities | 1,517 | 408 | 68 | |||||||||
Cash Flows from Investing Activities | ||||||||||||
Acquisition of Texas Genco LLC, WCP and Padoma , net of cash acquired | — | (4,333 | ) | (5 | ) | |||||||
Capital expenditures | (481 | ) | (221 | ) | (106 | ) | ||||||
Decrease in restricted cash, net | 12 | 6 | 45 | |||||||||
Decrease in notes receivable | 34 | 27 | 107 | |||||||||
Decrease in trust fund balances | 19 | — | — | |||||||||
Purchases of emission allowances | (161 | ) | (135 | ) | — | |||||||
Proceeds from sale of emission allowances | 272 | 146 | — | |||||||||
Investments in nuclear decommissioning trust fund securities | (265 | ) | (227 | ) | — | |||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 233 | 214 | — | |||||||||
Proceeds from sale of investments and equipment | 2 | 86 | 79 | |||||||||
Purchases of securities | (49 | ) | — | — | ||||||||
Proceeds from sale of discontinued operations and assets | 57 | 260 | 36 | |||||||||
Return of capital from equity method investments | — | 1 | 2 | |||||||||
Net Cash Provided/(Used) by Investing Activities | (327 | ) | (4,176 | ) | 158 | |||||||
Cash Flows from Financing Activities | ||||||||||||
Payment of dividends to preferred stockholders | (55 | ) | (50 | ) | (20 | ) | ||||||
Payment of financing element of acquired derivatives | — | (296 | ) | — | ||||||||
Payment for treasury stock | (353 | ) | (732 | ) | (250 | ) | ||||||
Payment of minority interest obligations | — | — | (4 | ) | ||||||||
Funded letter of credit | — | 350 | — | |||||||||
Proceeds from issuance of common stock, net of issuance costs | 7 | 986 | — | |||||||||
Proceeds from issuance of preferred shares, net of issuance costs | — | 486 | 246 | |||||||||
Proceeds from issuance of long-term debt | 1,411 | 8,619 | 249 | |||||||||
Payment of deferred debt issuance costs | (5 | ) | (199 | ) | (46 | ) | ||||||
Payments for short and long-term debt | (1,819 | ) | (5,111 | ) | (1,005 | ) | ||||||
Net Cash Provided/(Used) by Financing Activities | (814 | ) | 4,053 | (830 | ) | |||||||
Change in cash from discontinued operations | (25 | ) | 2 | 37 | ||||||||
Effect of exchange rate changes on cash and cash equivalents | 4 | 4 | (2 | ) | ||||||||
Net Increase/(Decrease) in Cash and Cash Equivalents | 355 | 291 | (569 | ) | ||||||||
Cash and Cash Equivalents at Beginning of Period | 777 | 486 | 1,055 | |||||||||
Cash and Cash Equivalents at End of Period | $ | 1,132 | $ | 777 | $ | 486 | ||||||
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Step one — | Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two. | |
Step two — | Compare the implied fair value of the reporting unit’s goodwill to the book value of the reporting unit goodwill. If the book value of goodwill exceeds fair value, an impairment charge is recognized for the sum of such excess. |
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• | Current income tax expense or benefit consists solely of regular tax less applicable tax credits, and | |
• | Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income. |
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• | Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or | |
• | Deferred and recorded as a component of accumulated other comprehensive income, or OCI, until the hedged transactions occur and are recognized in earnings for forecasted transactions. |
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Total | ||||
(In millions) | ||||
Balance as of December 31, 2006 | $ | 381 | ||
Additions | 4 | |||
Reduction | (1 | ) | ||
Accretion — Expense | 7 | |||
Accretion — Other | 18 | |||
Balance as of December 31, 2007 | $ | 409 | ||
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Initial Discontinued | ||||||
Operations | ||||||
Project | Segment | Treatment Date | Disposal Date | |||
Northbrook New York and Northbrook Energy | Corporate | Third Quarter 2005 | Third Quarter 2005 | |||
Audrain | Corporate | Fourth Quarter 2005 | Second Quarter 2006 | |||
Flinders | International | Second Quarter 2006 | Third Quarter 2006 | |||
Resource Recovery | Corporate | Third Quarter 2006 | Fourth Quarter 2006 | |||
ITISA | International | Fourth Quarter 2007 | First Half 2008(a) |
(a) | Estimated sale date. |
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As of | As of | |||||
December 31, | December 31, | |||||
2007 | 2006 | |||||
(In millions) | ||||||
Cash and cash equivalents | $ | 43 | $ | 18 | ||
Restricted cash | 4 | 3 | ||||
Receivables, net | 4 | 3 | ||||
Current assets — discontinued operations | 51 | 24 | ||||
Property, plant and equipment, net | 61 | 54 | ||||
Other non-current assets | 32 | 28 | ||||
Non-current assets — discontinued operations | 93 | 82 | ||||
Current portion of long-term debt | 10 | 8 | ||||
Accounts payable — trade | 4 | 3 | ||||
Other current liabilities | 23 | 17 | ||||
Current liabilities — discontinued operations | 37 | 28 | ||||
Long-term debt | 51 | 44 | ||||
Minority interest | 1 | 1 | ||||
Other non-current liabilities | 24 | 19 | ||||
Non-current liabilities — discontinued operations | $ | 76 | $ | 64 | ||
Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Operating revenues | $ | 50 | $ | 227 | $ | 323 | ||||||
Operating costs and other expenses | 27 | 224 | 311 | |||||||||
Pre-tax income from operations of discontinued components | 23 | 3 | 12 | |||||||||
Income tax expense | 6 | 1 | 2 | |||||||||
Income from operations of discontinued components | 17 | 2 | 10 | |||||||||
Disposal of discontinued components — pre-tax gain | — | 80 | 13 | |||||||||
Income tax expense | — | 4 | 7 | |||||||||
Gain on disposal of discontinued components, net of income taxes | — | 76 | 6 | |||||||||
Income from discontinued operations, net of income taxes | $ | 17 | $ | 78 | $ | 16 | ||||||
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Year Ended | Year Ended | |||||||||
December 31, | December 31, | |||||||||
2006 | 2005 | Segment | ||||||||
(In millions) | ||||||||||
Resource Recovery | $ | 5 | $ | — | Corporate | |||||
Flinders | 60 | — | International | |||||||
Audrain | 15 | — | Corporate | |||||||
Northbrook New York and Northbrook Energy | — | 12 | Corporate | |||||||
Other | — | 1 | Corporate | |||||||
Total pre-tax gain on disposal of discontinued operations | $ | 80 | $ | 13 | ||||||
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February 2, | ||||
2006 | ||||
(In millions) | ||||
ASSETS | ||||
Current and non-current assets | $ | 832 | ||
Coal inventory | 33 | |||
In-market contracts: | ||||
Power contracts | 39 | |||
Water contracts | 64 | |||
Fuel contracts | 171 | |||
Emission allowances | 880 | |||
Property, plant and equipment | 9,336 | |||
Deferred tax asset | 2,868 | |||
Goodwill | 1,782 | |||
Total assets acquired | 16,005 | |||
LIABILITIES | ||||
Current and non-current liabilities | 935 | |||
Pension and post-retirement liability | 222 | |||
Out-of-market contracts: | ||||
Coal | 93 | |||
Gas swaps | 472 | |||
Power contracts | 2,100 | |||
Deferred tax liability | 3,217 | |||
Long term debt | 2,735 | |||
Total liabilities assumed | 9,774 | |||
Net assets acquired | $ | 6,231 | ||
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New Investment | ||||||||||||||||||||
Fair Value Before | Fair Value after | |||||||||||||||||||
Original | Negative Goodwill | Allocation of | Negative Goodwill | Purchase Price | ||||||||||||||||
Investment | Allocation | Negative Goodwill | Allocation | Allocation | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Current assets | $ | 149 | $ | 153 | $ | — | $ | 153 | $ | 302 | ||||||||||
Property, plant and equipment | 24 | 103 | (38 | ) | 65 | 89 | ||||||||||||||
Intangible assets | 2 | 26 | (10 | ) | 16 | 18 | ||||||||||||||
Other non-current assets | — | 9 | — | 9 | 9 | |||||||||||||||
Current liabilities | (13 | ) | (18 | ) | — | (18 | ) | (31 | ) | |||||||||||
Non-current liabilities | (3 | ) | (19 | ) | — | (19 | ) | (22 | ) | |||||||||||
Negative goodwill | — | (48 | ) | 48 | — | — | ||||||||||||||
Total Equity | $ | 159 | $ | 206 | $ | — | $ | 206 | $ | 365 | ||||||||||
Year Ended December 31, | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
Operating revenues | $ | 5,884 | $ | 5,891 | ||||
Net income | 399 | 296 | ||||||
Earnings per share — Basic | 1.30 | 0.87 | ||||||
Earnings per share — Diluted | 1.27 | 0.86 | ||||||
Weighted average number of shares outstanding — Basic | 267.8 | 281.6 | ||||||
Weighted average number of shares outstanding — Diluted | 288 | 304 |
(In millions) | ||||
Equity compensation costs incurred due to immediate vesting of equity compensation awards under change of control provisions | $ | 271 | ||
Professional fees and other acquisition-related costs | 61 | |||
Total | $ | 332 | ||
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Carrying Amount | Fair Value | |||||||||||||||
Year Ended | Year Ended | Year Ended | Year Ended | |||||||||||||
December 31, | December 31, | December 31, | December 31, | |||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
(In millions) | ||||||||||||||||
Cash and cash equivalents | $ | 1,132 | $ | 777 | $ | 1,132 | $ | 777 | ||||||||
Restricted cash | 29 | 41 | 29 | 41 | ||||||||||||
Investment in available-for-sale securities (classified within other non-current assets): | ||||||||||||||||
Debt securities | 32 | — | 32 | — | ||||||||||||
Marketable equity securities | 7 | — | 7 | — | ||||||||||||
Trust fund investments | 390 | 377 | 390 | 377 | ||||||||||||
Notes receivable | 126 | 114 | 138 | 126 | ||||||||||||
Long-term debt, including current portion | 8,180 | 8,525 | 8,164 | 8,628 |
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• | Forward contracts, which commit NRG to sell energy commodities or purchase fuels in the future. | |
• | Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument. | |
• | Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity. | |
• | Option contracts, which convey the right or obligation to buy or sell a commodity. |
• | Fixing the price for a portion of anticipated future electricity sales through the use of various derivative instruments including gas collars and swaps at a level that provides an acceptable return on the Company’s electric generation operations. | |
• | Fixing the price of a portion of anticipated fuel purchases for the operation of NRG’s power plants. | |
• | Fixing the price of a portion of anticipated energy purchases to supply NRG’s load-serving customers. |
• | Forward and financial contracts for the sale of electricity and related products economically hedging NRG’s generation assets’ forecasted output through 2014. | |
• | Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG’s generation assets into 2017. |
• | Power sales and capacity contracts extending to 2025. | |
• | Coal purchase contracts extending through 2012 designated as normal purchases and disclosed as part of NRG’s contractual cash obligations. See Note 21,Commitments and Contingencies, for further discussion. |
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• | Load-following forward electric sale contracts extending through 2026. | |
• | Power Tolling contracts through 2017. | |
• | Lignite purchase contract through 2018. | |
• | Power transmission contracts through 2009. | |
• | Natural gas transportation contracts and storage agreements through 2018. | |
• | Coal transportation contracts through 2015. |
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Energy-Related | ||||||||||||
Commodities | Interest Rate | Total | ||||||||||
(In millions) | ||||||||||||
Accumulated OCI balance at December 31, 2004 | $ | 5 | $ | 2 | $ | 7 | ||||||
Realized from OCI during period — due to unwinding of previously deferred amounts | 132 | (2 | ) | 130 | ||||||||
Changes in fair value of hedge contracts — gains/(losses) | (341 | ) | 8 | (333 | ) | |||||||
Accumulated OCI balance at December 31, 2005 | $ | (204 | ) | $ | 8 | $ | (196 | ) | ||||
Realized from OCI during period: — due to unwinding of previously deferred amounts | 6 | (2 | ) | 4 | ||||||||
Changes in fair value of hedge contracts — gains | 391 | 10 | 401 | |||||||||
Accumulated OCI balance at December 31, 2006 | $ | 193 | $ | 16 | $ | 209 | ||||||
Realized from OCI during period — due to unwinding of previously deferred amounts | (50 | ) | (2 | ) | (52 | ) | ||||||
Changes in fair value of hedge contracts — losses | (377 | ) | (45 | ) | (422 | ) | ||||||
Accumulated OCI balance at December 31, 2007 | $ | (234 | ) | $ | ’ (31 | ) | $ | (265 | ) | |||
Gains expected to unwind from OCI during next 12 months, net of $26 tax | $ | 41 | $ | — | $ | 41 | ||||||
For the | For the | For the | ||||||||||
Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Revenue from operations — energy commodities | $ | (77 | ) | $ | 295 | $ | (154 | ) | ||||
Cost of operations | — | — | 2 | |||||||||
Equity in earnings of unconsolidated subsidiaries | — | — | 12 | |||||||||
Interest expense — interest rate swaps | — | (3 | ) | — | ||||||||
Total impact to statement of operations | $ | (77 | ) | $ | 292 | $ | (140 | ) | ||||
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(In millions) | ||||
Settlement payment | $ | (1,347 | ) | |
Reduction in derivative liability | 145 | |||
Reduction in out-of-market contracts | 1,073 | |||
Net decrease in revenues | $ | (129 | ) | |
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As of | As of | |||||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(In millions) | ||||||||
Cash and cash equivalents | $ | 4 | $ | 7 | ||||
U.S. government and federal agency obligations | 21 | 29 | ||||||
Federal agency mortgage-backed securities | 59 | 41 | ||||||
Commercial mortgage-backed securities | 22 | 16 | ||||||
Corporate debt securities | 44 | 43 | ||||||
Marketable equity securities | 234 | 216 | ||||||
Total | $ | 384 | $ | 352 | ||||
As of | As of | |||||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(In millions) | ||||||||
Fuel oil | $ | 140 | $ | 162 | ||||
Coal/Lignite | 174 | 118 | ||||||
Natural gas | 16 | 12 | ||||||
Spare parts | 121 | 128 | ||||||
Total Inventory | $ | 451 | $ | 420 | ||||
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As of | As of | |||||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(In millions) | ||||||||
Capital Lease Receivable — non-affiliate | ||||||||
VEAG Vereinigte Energiewerke AG, due August 31, 2021, 11.00%(a) | $ | 395 | $ | 392 | ||||
Capital Lease — non-affiliates | 395 | 392 | ||||||
Less current maturities | 30 | 27 | ||||||
Total | 365 | 365 | ||||||
Note Receivable — affiliates | ||||||||
Kraftwerke Schkopau GBR, indefinite maturity date, 5.89%-7.00%(b) | 126 | 114 | ||||||
Notes receivable — affiliates | $ | 126 | $ | 114 | ||||
(a) | Saale Energie GmbH, or SEG, has sold 100% of its share of capacity from the Schkopau power plant to VEAG Vereinigte Energiewerke AG under a25-year contract, which is more than 83% of the useful life of the plant. This direct financing lease receivable amount was calculated based on the present value of the income to be received over the life of the contract. | |
(b) | SEG entered into a note receivable with Kraftwerke Schkopau GBR, a partnership between Saale and E.On Kraftwerke GmbH. The note was used to fund SEG’s initial capital contribution to the partnership and to cover project liquidity shortfalls during construction of the Schkopau power plant. The note is subject to repayment upon the disposition of the Schkopau plant. |
As of | As of | |||||||||||
December 31, | December 31, | Depreciable | ||||||||||
2007 | 2006 | Lives | ||||||||||
(In millions) | ||||||||||||
Facilities and equipment | $ | 11,829 | $ | 11,636 | 5-40 Years | |||||||
Land and improvements | 584 | 559 | ||||||||||
Nuclear fuel | 181 | 159 | 5 Years | |||||||||
Office furnishings and equipment | 84 | 79 | 3-10 Years | |||||||||
Construction in progress | 337 | 87 | ||||||||||
Total property, plant and equipment | 13,015 | 12,520 | ||||||||||
Accumulated depreciation | (1,695 | ) | (974 | ) | ||||||||
Net property, plant and equipment | $ | 11,320 | $ | 11,546 | ||||||||
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Emission | Contracts | |||||||||||||||||||||||
As of December 31, 2007 | Allowances | Power | Fuel | Water | Other | Total | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
January 1, 2007 | $ | 913 | $ | 92 | $ | 171 | $ | 64 | $ | — | $ | 1,240 | ||||||||||||
Acquisitions | 5 | — | — | — | 2 | 7 | ||||||||||||||||||
Sales | (1 | ) | — | — | — | — | (1 | ) | ||||||||||||||||
Transfer to held for sale | (1 | ) | — | — | — | — | (1 | ) | ||||||||||||||||
Adjusted gross amount | 916 | 92 | 171 | 64 | 2 | 1,245 | ||||||||||||||||||
Less accumulated amortization | (114 | ) | (92 | ) | (102 | ) | (64 | ) | — | (372 | ) | |||||||||||||
Net carrying amount | $ | 802 | $ | — | $ | 69 | $ | — | $ | 2 | $ | 873 | ||||||||||||
Emission | Contracts | |||||||||||||||||||
As of December 31, 2006 | Allowances | Power | Fuel | Water | Total | |||||||||||||||
(In millions) | ||||||||||||||||||||
January 1, 2006 | $ | 280 | $ | 56 | $ | — | $ | — | $ | 336 | ||||||||||
Acquisitions | 894 | 39 | 171 | 64 | 1,168 | |||||||||||||||
Transfer to held for sale | (23 | ) | — | — | — | (23 | ) | |||||||||||||
Tax adjustments | (238 | ) | (3 | ) | — | — | (241 | ) | ||||||||||||
Adjusted gross amount | 913 | 92 | 171 | 64 | 1,240 | |||||||||||||||
Less accumulated amortization | (74 | ) | (92 | ) | (65 | ) | (28 | ) | (259 | ) | ||||||||||
Net carrying amount | $ | 839 | $ | — | $ | 106 | $ | 36 | $ | 981 | ||||||||||
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Amortization | 2007 | 2006 | 2005 | |||||||||
(In millions) | ||||||||||||
Emission allowances | $ | 40 | $ | 44 | $ | 12 | ||||||
Fuel contracts | 37 | 65 | — | |||||||||
Water contracts | 36 | 28 | — | |||||||||
Total amortization in cost of operations | $ | 113 | $ | 137 | $ | 12 | ||||||
Power contract amortization recorded as a reduction to operating revenues | $ | — | $ | 43 | $ | 12 | ||||||
Emission | ||||||||||||
Year Ended December 31, | Allowances | Fuel | Total | |||||||||
(In millions) | ||||||||||||
2008 | $ | 41 | $ | 21 | $ | 62 | ||||||
2009 | 41 | 26 | 67 | |||||||||
2010 | 55 | 6 | 61 | |||||||||
2011 | 54 | 2 | 56 | |||||||||
2012 | 45 | 2 | 47 |
Year Ended December 31, | Coal | Gas Swaps | Power Contracts | Total | ||||||||||||
2008 | $ | 33 | $ | 11 | $ | 279 | $ | 323 | ||||||||
2009 | 19 | 34 | 82 | 135 | ||||||||||||
2010 | 6 | 28 | 32 | 66 | ||||||||||||
2011 | — | — | 22 | 22 | ||||||||||||
2012 | — | — | 22 | 22 |
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Interest | ||||||||||||
As of December 31, | 2007 | 2006 | Rate | |||||||||
(In millions except rates) | ||||||||||||
NRG Recourse Debt: | ||||||||||||
Senior notes due 2017 | $ | 1,100 | $ | 1,100 | 7.375 | |||||||
Senior notes due 2016 | 2,400 | 2,400 | 7.375 | |||||||||
Senior notes due 2014(a) | 1,199 | 1,183 | 7.25 | |||||||||
ML note payable | — | 11 | L+1.9 | (e) | ||||||||
Term loan B due 2013 | 2,816 | 3,148 | L+1.75/L+2.0 | (e) | ||||||||
NRG Non-Recourse Debt: | ||||||||||||
CSF non-recourse obligations due 2008 and 2009 | 333 | 333 | 5.45-13.23 | |||||||||
NRG Peaker Finance Co. LLC, due June 2019(b) | 235 | 240 | L+1.07 | (e) | ||||||||
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013 and 2017(c) | 97 | 107 | 7.12-7.31 | |||||||||
Camas Power Boiler LP, unsecured term loan, due June 2007 | — | 1 | L+0.69 | (e) | ||||||||
Camas Power Boiler LP, revenue bonds, due August 2007 | — | 2 | 3.38 | |||||||||
Subtotal long term debt | 8,180 | 8,525 | ||||||||||
Capital leases: | ||||||||||||
Saale Energie GmbH, Schkopau capital lease, due 2021 | 181 | 199 | ||||||||||
Other | — | 2 | ||||||||||
Subtotal | 8,361 | 8,726 | ||||||||||
Less current maturities(d) | 466 | 123 | ||||||||||
Total | $ | 7,895 | $ | 8,603 | ||||||||
(a) | Includes fair value adjustment as of December 31 2007 and 2006, reflects $(1) million and $(17) million, respectively, reduction for an interest rate swap. The swap was re-designated from the retired 2nd priority note to this note as part of the financing related to the Texas Genco LLC acquisition. |
(b) | Includes discount of $(43) million and $(50) million as of December 31, 2007 and 2006, respectively. |
(c) | Includes premium of $3 million and $4 million as of December 31, 2007 and 2006, respectively. |
(d) | Includes premium of $7 million on the NRG Peaker Finance debt and a discount of $1 million on NRG Energy Center Minneapolis debt as of December 31, 2007 and 2006. |
(e) | L+ equals LIBOR plus x% |
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• | return capital to shareholders; | |
• | grant liens on assets to lenders; and | |
• | incur additional debt. |
Premium as | ||||
Redemption Period | Defined Above | |||
February 1, 2010 to February 1, 2011 | 103.625 | % | ||
February 1, 2011 to February 1, 2012 | 101.813 | % | ||
February 1, 2012 and thereafter | 100.000 | % |
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Premium as | ||||
Redemption Period | Defined Above | |||
February 1, 2011 to February 1, 2012 | 103.688 | % | ||
February 1, 2012 to February 1, 2013 | 102.458 | % | ||
February 1, 2013 to February 1, 2014 | 101.229 | % | ||
February 1, 2014 and thereafter | 100.000 | % |
Premium as | ||||
Redemption Period | Defined Above | |||
February 1, 2012 to February 1, 2013 | 103.688 | % | ||
February 1, 2013 to February 1, 2014 | 102.458 | % | ||
February 1, 2014 to February 1, 2015 | 101.229 | % | ||
February 1, 2015 and thereafter | 100.000 | % |
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• | incur indebtedness and liens and enter into sale and lease-back transactions; | |
• | make investments, loans and advances; and | |
• | return capital to shareholders. |
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Maturity | Notional Value | |||
March 31, 2008 | $ | 140 million | ||
March 31, 2009 | $ | 150 million | ||
March 31, 2010 | $ | 190 million | ||
March 31, 2011 | $ | 1.55 billion |
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(In millions) | ||||
2008 | $ | 472 | ||
2009 | 226 | |||
2010 | 75 | |||
2011 | 70 | |||
2012 | 71 | |||
Thereafter | 7,488 | |||
Total | $ | 8,402 | ||
(In millions) | ||||
2008 | $ | 93 | ||
2009 | 42 | |||
2010 | 24 | |||
2011 | 15 | |||
2012 | 13 | |||
Thereafter | 203 | |||
Total minimum obligations | 390 | |||
Interest | 209 | |||
Present value of minimum obligations | 181 | |||
Current portion | 75 | |||
Long-term obligations | $ | 106 | ||
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Pension Benefits | ||||||||||||
Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Service cost benefits earned | $ | 15 | $ | 17 | $ | 11 | ||||||
Interest cost on benefit obligation | 17 | 15 | 4 | |||||||||
Expected return on plan assets | (11 | ) | (7 | ) | — | |||||||
Net periodic benefit cost | $ | 21 | $ | 25 | $ | 15 | ||||||
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Other Postretirement Benefits | ||||||||||||
Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Service cost benefits earned | $ | 2 | $ | 3 | $ | 2 | ||||||
Interest cost on benefit obligation | 5 | 4 | 3 | |||||||||
Net periodic benefit cost | $ | 7 | $ | 7 | $ | 5 | ||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
As of | As of | As of | As of | |||||||||||||
December 31, | December 31, | December 31, | December 31, | |||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
(In millions) | ||||||||||||||||
Benefit obligation at January 1 | $ | 294 | $ | 318 | $ | 80 | $ | 80 | ||||||||
Service cost | 15 | 17 | 2 | 3 | ||||||||||||
Interest cost | 17 | 15 | 5 | 4 | ||||||||||||
Plan amendments | (4 | ) | — | — | — | |||||||||||
Actuarial (gain)/loss | (13 | ) | (29 | ) | (2 | ) | (6 | ) | ||||||||
Benefit payments | (19 | ) | (27 | ) | (2 | ) | (1 | ) | ||||||||
Benefit obligation at December 31 | $ | 290 | $ | 294 | $ | 83 | $ | 80 | ||||||||
Fair value of plan assets at January 1 | 123 | 86 | — | — | ||||||||||||
Actual return on plan assets | 7 | 14 | — | — | ||||||||||||
Employer contributions | 58 | 51 | 1 | 1 | ||||||||||||
Benefit payments | (20 | ) | (28 | ) | (1 | ) | (1 | ) | ||||||||
Fair value of plan assets at December 31 | $ | 168 | $ | 123 | $ | — | $ | — | ||||||||
Funded status at December 31 — excess of obligation over assets | $ | (122 | ) | $ | (171 | ) | $ | (83 | ) | $ | (80 | ) | ||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
As of | As of | As of | As of | |||||||||||||
December 31, | December 31, | December 31, | December 31, | |||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
(In millions) | ||||||||||||||||
Assets | $ | — | $ | — | $ | — | $ | — | ||||||||
Current liabilities | — | — | — | — | ||||||||||||
Non-current liabilities | 122 | 171 | 83 | 80 |
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Pension Benefits | Other Postretirement Benefits | |||||||||||||||
As of | As of | As of | As of | |||||||||||||
December 31, | December 31, | December 31, | December 31, | |||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
(In millions) | ||||||||||||||||
Unrecognized (gain)/loss | $ | (36 | ) | $ | (27 | ) | $ | 1 | $ | 1 | ||||||
Prior service credit | $ | (3 | ) | $ | — | $ | — | $ | — |
Other | ||||||||
Pension | Postretirement | |||||||
Benefits | Benefits | |||||||
As of December 31, | 2007 | |||||||
(In millions) | ||||||||
Net gain | $ | (8 | ) | $ | (2 | ) | ||
Prior service credit | $ | (4 | ) | $ | — | |||
Total recognized in other comprehensive income | $ | (12 | ) | $ | (2 | ) | ||
Total recognized in net periodic pension cost and other comprehensive income | $ | 9 | $ | 5 |
Pension Benefits | ||||||||
As of | As of | |||||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(In millions) | ||||||||
Projected benefit obligation | $ | 290 | $ | 294 | ||||
Accumulated benefit obligation | 236 | 226 | ||||||
Fair value of plan assets | 168 | 123 |
As of December 31, | ||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Weighted-Average Assumptions | 2007 | 2006 | 2007 | 2006 | ||||||||||||
Discount rate | 6.56% | 5.92% | 6.56% | 5.92% | ||||||||||||
Rate of compensation increase | 4.00-4.50% | 4.00-4.50% | ||||||||||||||
Health care trend rate | — | — | 9.5% grading to 5.5% in 2016 | 10.5% grading to 5.5% in 2012 |
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As of December 31, | ||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
Weighted-Average Assumptions | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | ||||||||||||||||||
Discount rate | 5.92 | % | 5.50 | % | 5.75 | % | 5.92% | 5.50% | 5.75% | |||||||||||||||
Expected return on plan assets | 8.00 | % | 8.00 | % | 8.00 | % | — | — | — | |||||||||||||||
Rate of compensation increase | 4.00-4.50 | % | 4.00-4.50 | % | 4.00-4.50 | % | — | — | — | |||||||||||||||
Health care trend rate | — | — | — | 10.5% grading | 11.5% grading | 9% grading | ||||||||||||||||||
to 5.5% in 2012 | to 5.5% in 2012 | to 5.5% in 2012 |
As of | As of | |||||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
US Equity | 50-55 | % | 55 | % | ||||
International Equity | 15 | % | 17 | % | ||||
US Fixed Income | 30-35 | % | 28 | % |
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Other Postretirement Benefit | ||||||||||||
Pension | Medicare Prescription | |||||||||||
Benefit Payments | Benefit Payments | Drug Reimbursements | ||||||||||
(In millions) | ||||||||||||
2008 | $ | 13 | $ | 2 | $ | — | ||||||
2009 | 14 | 2 | — | |||||||||
2010 | 16 | 3 | — | |||||||||
2011 | 17 | 3 | — | |||||||||
2012 | 19 | 4 | — | |||||||||
2013-2017 | $ | 126 | $ | 25 | $ | 1 |
1-Percentage- | 1-Percentage- | |||||||
Point Increase | Point Decrease | |||||||
(In millions) | ||||||||
Effect on total service and interest cost components | $ | 1 | $ | (1 | ) | |||
Effect on postretirement benefit obligation | 7 | (5 | ) |
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
As of | As of | As of | As of | |||||||||||||
December 31, | December 31, | December 31, | December 31, | |||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||
(In millions) | ||||||||||||||||
Funded status — STPNOC benefit plans | $ | (20 | ) | $ | (27 | ) | $ | (22 | ) | $ | (16 | ) | ||||
Net periodic pension costs | 4 | 5 | 3 | 3 | ||||||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive income | $ | 4 | $ | 1 | $ | 4 | $ | — |
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Authorized | Issued | Treasury | Outstanding | |||||||||||||
Balance as of December 31, 2005 | 500,000,000 | 200,097,352 | (38,693,576 | ) | 161,403,776 | |||||||||||
Shares issued January 2006 | — | 41,710,114 | — | 41,710,114 | ||||||||||||
Acquisition of Texas Genco LLC | — | 32,119,008 | 38,693,576 | 70,812,584 | ||||||||||||
Capital Allocation Program — Phase I and II during 2006 | — | — | (29,601,162 | ) | (29,601,162 | ) | ||||||||||
Shares issued from LTIP through December 31, 2006 | — | 321,790 | — | 321,790 | ||||||||||||
Balance as of December 31, 2006 | 500,000,000 | 274,248,264 | (29,601,162 | ) | 244,647,102 | |||||||||||
Capital Allocation Program — Phase II during 2007 | — | — | (7,006,700 | ) | (7,006,700 | ) | ||||||||||
Additional Share Repurchases — December 2007 | — | — | (2,037,700 | ) | (2,037,700 | ) | ||||||||||
Shares issued from LTIP through December 31, 2007 | — | 1,132,227 | — | 1,132,227 | ||||||||||||
Retirement of shares through December 31, 2007 | — | (14,094,962 | ) | 14,094,962 | — | |||||||||||
Balance as of December 31, 2007 | 500,000,000 | 261,285,529 | (24,550,600 | ) | 236,734,929 | |||||||||||
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Common Stock | ||||
Equity Instrument | Reserve Balance | |||
4% Convertible perpetual preferred | 26,151,972 | |||
3.625% Redeemable perpetual preferred | 16,000,000 | |||
5.75% Mandatory convertible preferred | 20,520,000 | |||
Long term incentive plan | 14,565,741 | |||
Total | 77,237,713 | |||
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Applicable Market Value on Conversion Date | Conversion Rate | |||
equal to or greater than $30.23 | 8.2712 | |||
less than $30.23 but greater than $24.38 | 8.2712 to 10.2564 | |||
less than or equal to $24.38 | 10.2564 |
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Economic | ||||||||
Name | Geographic Area | Interest | ||||||
MIBRAG | Germany | 50.0 | % | |||||
Saguaro Power Company, or Saguaro | USA | 50.0 | % | |||||
Gladstone Power Station, or Gladstone | Australia | 37.5 | % |
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Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Summarized Statements of Operations | ||||||||||||
Operating revenues | $ | 871 | $ | 910 | $ | 1,300 | ||||||
Costs and expenses | 748 | 770 | 1,107 | |||||||||
Net income | 123 | 140 | 193 | |||||||||
Summarized Balance Sheets | ||||||||||||
Current assets | 268 | 223 | ||||||||||
Non-current assets | 1,808 | 1,697 | ||||||||||
Total assets | 2,076 | 1,920 | ||||||||||
Current liabilities | 88 | 53 | ||||||||||
Non-current liabilities | 950 | 1,021 | ||||||||||
Equity | 1,038 | 846 | ||||||||||
Total liabilities and equity | 2,076 | 1,920 | ||||||||||
NRG’s share of equity and net income | ||||||||||||
NRG’s share of equity | 425 | 344 | ||||||||||
NRG’s share of net income | $ | 54 | $ | 60 | $ | 104 | ||||||
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Year Ended | Year Ended | Year Ended | ||||||||||||||
December 31, | December 31, | December 31, | ||||||||||||||
2007 | 2006 | 2005 | Segment | |||||||||||||
(In millions) | ||||||||||||||||
Powersmith Cogeneration | $ | 1 | $ | — | $ | — | Corporate | |||||||||
Latin American Funds | — | 3 | — | International | ||||||||||||
James River Power LLC | — | (6 | ) | — | Corporate | |||||||||||
Cadillac | — | 11 | — | Corporate | ||||||||||||
Saguaro | — | — | (27 | ) | West | |||||||||||
Rocky Road | — | — | (20 | ) | Corporate | |||||||||||
Kendall | — | — | 4 | Corporate | ||||||||||||
Enfield | — | — | 12 | International | ||||||||||||
Total write downs and gains/(losses) on sales of equity method investments | $ | 1 | $ | 8 | $ | (31 | ) | |||||||||
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Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Basic earnings per share | ||||||||||||
Numerator: | ||||||||||||
Income from continuing operations | $ | 569 | $ | 543 | $ | 68 | ||||||
Deduct preferred stock dividends | (55 | ) | (52 | ) | (20 | ) | ||||||
Income available to common stockholders from continuing operations | 514 | 491 | 48 | |||||||||
Discontinued operations, net of tax | 17 | 78 | 16 | |||||||||
Net income available to common stockholders | $ | 531 | $ | 569 | $ | 64 | ||||||
Denominator: | ||||||||||||
Weighted average number of common shares outstanding | 240.2 | 258.0 | 169.2 | |||||||||
Basic earnings per share: | ||||||||||||
Income from continuing operations | $ | 2.14 | $ | 1.90 | $ | 0.28 | ||||||
Discontinued operations, net of tax | 0.07 | 0.31 | 0.10 | |||||||||
Net income | $ | 2.21 | $ | 2.21 | $ | 0.38 | ||||||
Diluted earnings per share | ||||||||||||
Numerator: | ||||||||||||
Income available to common stockholders from continuing operations | 514 | 491 | 48 | |||||||||
Add preferred stock dividends for dilutive preferred stock | 46 | 43 | — | |||||||||
Adjusted income from continuing operations | 560 | 534 | 48 | |||||||||
Discontinued operations, net of tax | 17 | 78 | 16 | |||||||||
Net income available to common stockholders | $ | 577 | $ | 612 | $ | 64 | ||||||
Denominator: | ||||||||||||
Weighted average number of common shares outstanding | 240.2 | 258.0 | 169.2 | |||||||||
Incremental shares attributable to the issuance of stock-based compensation (treasury stock method) | 3.8 | 2.8 | 1.4 | |||||||||
Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method) | 6.0 | — | — | |||||||||
Incremental shares attributable to the assumed conversion features of outstanding preferred stock (if-converted method) | 37.5 | 39.8 | — | |||||||||
Total dilutive shares | 287.5 | 300.6 | 170.6 | |||||||||
Diluted earnings per share: | ||||||||||||
Income from continuing operations | $ | 1.95 | $ | 1.78 | $ | 0.28 | ||||||
Discontinued operations, net of tax | 0.06 | 0.26 | 0.10 | |||||||||
Net income | $ | 2.01 | $ | 2.04 | $ | 0.38 | ||||||
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Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions of shares) | ||||||||||||
Equity compensation — NQSO’s and PU’s | 0.1 | 0.7 | 0.4 | |||||||||
Convertible preferred stock | — | — | 21.0 | |||||||||
Embedded derivative of 3.625% redeemable perpetual preferred stock | 12.2 | 16.0 | 16.0 | |||||||||
Embedded derivative of preferred interests and notes issued by CSF I and CSF II | 16.1 | 18.3 | — | |||||||||
Total | 28.4 | 35.0 | 37.4 | |||||||||
Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
Customer A — Northeast region | — | % | 10 | % | 40 | % | ||||||
Customer B — Northeast region | — | — | 17 | |||||||||
Customer C — Texas region | 27 | — | — | |||||||||
Total | 27 | % | 10 | % | 57 | % | ||||||
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Year Ended December 31, 2007 | ||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||
South | ||||||||||||||||||||||||||||||||||||
Texas | Northeast | Central | West | International | Thermal | Corporate | Elimination | Total | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 3,287 | $ | 1,605 | $ | 658 | $ | 127 | $ | 140 | $ | 159 | $ | 30 | $ | (17 | ) | $ | 5,989 | |||||||||||||||||
Operating expenses | 1,849 | 1,045 | 533 | 85 | 112 | 125 | 47 | (8 | ) | 3,788 | ||||||||||||||||||||||||||
Depreciation and amortization | 469 | 102 | 68 | 3 | — | 11 | 5 | — | 658 | |||||||||||||||||||||||||||
Gain/(loss) on sale of assets | — | — | — | — | — | 18 | (1 | ) | — | 17 | ||||||||||||||||||||||||||
Operating income/(loss) | 969 | 458 | 57 | 39 | 28 | 41 | (23 | ) | (9 | ) | 1,560 | |||||||||||||||||||||||||
Equity in earnings/(loss) of unconsolidated affiliates | — | — | — | (3 | ) | 57 | — | — | — | 54 | ||||||||||||||||||||||||||
Write downs and gain on sales of equity method investments | — | — | — | — | — | — | 1 | — | 1 | |||||||||||||||||||||||||||
Other income, net | 7 | — | — | — | 8 | 1 | 58 | (19 | ) | 55 | ||||||||||||||||||||||||||
Refinancing expenses | — | — | — | — | — | — | (35 | ) | — | (35 | ) | |||||||||||||||||||||||||
Interest expense | (164 | ) | (57 | ) | (53 | ) | — | (5 | ) | (6 | ) | (423 | ) | 19 | (689 | ) | ||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 812 | 401 | 4 | 36 | 88 | 36 | (422 | ) | (9 | ) | 946 | |||||||||||||||||||||||||
Income tax expense/(benefit) | 327 | — | — | — | (12 | ) | — | 62 | — | 377 | ||||||||||||||||||||||||||
Income/(loss) from continuing operations | 485 | 401 | 4 | 36 | 100 | 36 | (484 | ) | (9 | ) | 569 | |||||||||||||||||||||||||
Income on discontinued operations, net of income taxes | — | — | — | — | 17 | — | — | — | 17 | |||||||||||||||||||||||||||
Net income/(loss) | $ | 485 | $ | 401 | $ | 4 | $ | 36 | $ | 117 | $ | 36 | $ | (484 | ) | $ | (9 | ) | $ | 586 | ||||||||||||||||
Balance sheet | ||||||||||||||||||||||||||||||||||||
Equity investments in affiliates | — | 1 | — | 27 | 397 | — | — | — | 425 | |||||||||||||||||||||||||||
Capital expenditures | 190 | 106 | 30 | 80 | — | 6 | 69 | — | 481 | |||||||||||||||||||||||||||
Goodwill | 1,781 | — | — | — | — | — | 5 | — | 1,786 | |||||||||||||||||||||||||||
Total assets | $ | 12,165 | $ | 1,572 | $ | 995 | $ | 246 | $ | 1,169 | $ | 211 | $ | 12,847 | $ | (9,931 | ) | $ | 19,274 | |||||||||||||||||
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Year Ended December 31, 2006 | ||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||
South | ||||||||||||||||||||||||||||||||||||
Texas | Northeast | Central | West | International | Thermal | Corporate | Elimination | Total | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 3,088 | $ | 1,543 | $ | 570 | $ | 146 | $ | 135 | $ | 152 | $ | 12 | $ | (61 | ) | $ | 5,585 | |||||||||||||||||
Operating expenses | 1,794 | 993 | 397 | 135 | 110 | 121 | 30 | (3 | ) | 3,577 | ||||||||||||||||||||||||||
Depreciation and amortization | 413 | 89 | 68 | 3 | — | 12 | 5 | — | 590 | |||||||||||||||||||||||||||
Operating income/(loss) | 881 | 461 | 105 | 8 | 25 | 19 | (23 | ) | (58 | ) | 1,418 | |||||||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | — | 1 | 57 | — | 2 | — | 60 | |||||||||||||||||||||||||||
Write downs and gain on sales of equity method investments | — | — | — | — | 3 | — | 5 | — | 8 | |||||||||||||||||||||||||||
Other income, net | 9 | 6 | — | 1 | 7 | 1 | 152 | (20 | ) | 156 | ||||||||||||||||||||||||||
Refinancing expenses | — | — | — | — | — | — | (187 | ) | — | (187 | ) | |||||||||||||||||||||||||
Interest expense | (138 | ) | (63 | ) | (57 | ) | — | (1 | ) | (7 | ) | (344 | ) | 20 | (590 | ) | ||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 752 | 404 | 48 | 10 | 91 | 13 | (395 | ) | (58 | ) | 865 | |||||||||||||||||||||||||
Income tax expense/(benefit) | 23 | — | — | (2 | ) | 23 | — | 278 | — | 322 | ||||||||||||||||||||||||||
Income/(loss) from continuing operations | 729 | 404 | 48 | 12 | 68 | 13 | (673 | ) | (58 | ) | 543 | |||||||||||||||||||||||||
Income on discontinued operations, net of income taxes | — | — | — | — | 61 | — | 17 | — | 78 | |||||||||||||||||||||||||||
Net income/(loss) | $ | 729 | $ | 404 | $ | 48 | $ | 12 | $ | 129 | $ | 13 | $ | (656 | ) | $ | (58 | ) | $ | 621 | ||||||||||||||||
Balance sheet | ||||||||||||||||||||||||||||||||||||
Equity investments in affiliates | — | 1 | — | 29 | 312 | — | 2 | — | 344 | |||||||||||||||||||||||||||
Capital expenditures | 125 | 49 | 11 | 7 | 5 | 12 | 12 | — | 221 | |||||||||||||||||||||||||||
Goodwill | 1,782 | — | — | — | — | — | 7 | — | 1,789 | |||||||||||||||||||||||||||
Total assets | $ | 12,980 | $ | 1,583 | $ | 1,029 | $ | 176 | $ | 1,293 | $ | 251 | $ | 12,608 | $ | (10,484 | ) | $ | 19,436 | |||||||||||||||||
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Year Ended December 31, 2005 | ||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||
South | ||||||||||||||||||||||||||||||||
Northeast | Central | West | International | Thermal | Corporate | Elimination | Total | |||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Operating revenues | $ | 1,554 | $ | 560 | $ | 4 | $ | 135 | $ | 150 | $ | 6 | $ | (9 | ) | $ | 2,400 | |||||||||||||||
Operating expenses | 1,262 | 485 | 9 | 107 | 118 | 35 | (11 | ) | 2,005 | |||||||||||||||||||||||
Depreciation and amortization | 74 | 67 | 1 | — | 11 | 5 | — | 158 | ||||||||||||||||||||||||
Corporate relocation charges | — | — | — | — | — | 6 | — | 6 | ||||||||||||||||||||||||
Restructuring and impairment charges | — | — | — | — | — | 6 | — | 6 | ||||||||||||||||||||||||
Operating income/(loss) | 218 | 8 | (6 | ) | 28 | 21 | (46 | ) | 2 | 225 | ||||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | 22 | 69 | — | 13 | — | 104 | ||||||||||||||||||||||||
Write downs and gain/(loss) on sales of equity method investments | — | — | (27 | ) | 12 | — | (16 | ) | — | (31 | ) | |||||||||||||||||||||
Other income, net | 4 | — | 1 | 17 | 2 | 51 | (21 | ) | 54 | |||||||||||||||||||||||
Refinancing expenses | — | — | — | — | — | (65 | ) | — | (65 | ) | ||||||||||||||||||||||
Interest expense | — | (27 | ) | — | (1 | ) | (8 | ) | (162 | ) | 21 | (177 | ) | |||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 222 | (19 | ) | (10 | ) | 125 | 15 | (225 | ) | 2 | 110 | |||||||||||||||||||||
Income tax expense | — | — | — | 21 | 4 | 17 | — | 42 | ||||||||||||||||||||||||
Income/(loss) from continuing operations | 222 | (19 | ) | (10 | ) | 104 | 11 | (242 | ) | 2 | 68 | |||||||||||||||||||||
Income on discontinued operations, net of income taxes | — | — | — | 2 | 4 | 10 | — | 16 | ||||||||||||||||||||||||
Net income/(loss) | $ | 222 | $ | (19 | ) | $ | (10 | ) | $ | 106 | $ | 15 | $ | (232 | ) | $ | 2 | $ | 84 | |||||||||||||
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Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Current | ||||||||||||
U.S | $ | (7 | ) | $ | (27 | ) | $ | 19 | ||||
Foreign | 20 | 19 | 15 | |||||||||
13 | (8 | ) | 34 | |||||||||
Deferred | ||||||||||||
U.S | 394 | 326 | 2 | |||||||||
Foreign | (30 | ) | 4 | 6 | ||||||||
364 | 330 | 8 | ||||||||||
Total income tax | $ | 377 | $ | 322 | $ | 42 | ||||||
Effective tax rate | 39.9 | % | 37.2 | % | 38.2 | % | ||||||
Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
U.S. | $ | 860 | $ | 767 | $ | (11 | ) | |||||
Foreign | 86 | 98 | 121 | |||||||||
Total | $ | 946 | $ | 865 | $ | 110 | ||||||
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Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions, except percentages) | ||||||||||||
Income from continuing operations before income taxes | $ | 946 | $ | 865 | $ | 110 | ||||||
Tax at 35% | 331 | 303 | 39 | |||||||||
State taxes, net of federal benefit | 46 | 34 | (1 | ) | ||||||||
Foreign operations | (13 | ) | (21 | ) | (18 | ) | ||||||
2005 Section 965 taxable dividend | — | — | 5 | |||||||||
Subpart F taxable income | — | 11 | 19 | |||||||||
Valuation allowance, including change in state effective rate | 6 | (10 | ) | 22 | ||||||||
Change in state effective tax rate | — | 21 | (22 | ) | ||||||||
Claimant reserve settlements | — | (28 | ) | — | ||||||||
Change in local German effective tax rates | (29 | ) | — | — | ||||||||
Foreign dividends | 26 | 1 | — | |||||||||
Non-deductible interest | 10 | 3 | — | |||||||||
Permanent differences, reserves, other | — | 8 | (2 | ) | ||||||||
Income tax expense | $ | 377 | $ | 322 | $ | 42 | ||||||
Effective income tax rate | 39.9 | % | 37.2 | % | 38.2 | % | ||||||
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As of | As of | |||||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(In millions) | ||||||||
Deferred tax liabilities: | ||||||||
Discount/premium on notes | $ | 23 | $ | 25 | ||||
Emissions allowances | 109 | 83 | ||||||
Difference between book and tax basis of property | 1,568 | 1,579 | ||||||
Derivative asset, net | — | 216 | ||||||
Goodwill | 45 | 51 | ||||||
Investment in projects | 6 | — | ||||||
Total deferred tax liabilities | 1,751 | 1,954 | ||||||
Deferred tax assets: | ||||||||
Deferred compensation, pension, accrued vacation and other reserves | 129 | 133 | ||||||
Derivative liability, net | 125 | — | ||||||
Differences between book and tax basis of contracts | 577 | 890 | ||||||
Non-depreciable property | 19 | 21 | ||||||
Intangibles amortization (excluding goodwill) | 152 | 145 | ||||||
Equity compensation | 15 | 16 | ||||||
Claimants reserve | 7 | 8 | ||||||
U.S. net operating loss carry forwards | — | 27 | ||||||
U.S. capital loss carryforwards | 439 | 485 | ||||||
Foreign net operating loss carryforwards | 80 | 74 | ||||||
Foreign capital loss carryforwards | 1 | — | ||||||
Investments in projects | — | 6 | ||||||
Deferred financing costs | 12 | — | ||||||
Other | 15 | 12 | ||||||
Total deferred tax assets | 1,571 | 1,817 | ||||||
Valuation allowance | (539 | ) | (581 | ) | ||||
Net deferred tax assets | 1,032 | 1,236 | ||||||
Net deferred tax liability | $ | 719 | $ | 718 | ||||
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As of | As of | |||||||
December 31, | December 31, | |||||||
2007 | 2006 | |||||||
(In millions) | ||||||||
Current deferred tax asset | $ | 124 | $ | — | ||||
Current deferred tax liability | — | 164 | ||||||
Non-current deferred tax liability | 843 | 554 | ||||||
Net deferred tax liability | $ | 719 | $ | 718 | ||||
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As of | ||||
December 31, | ||||
2007 | ||||
(In millions) | ||||
Balance as of January 1 | $ | 712 | ||
Increase due to current year positions | 76 | |||
Decrease due to current year positions | (105 | ) | ||
Increase due to prior year positions | — | |||
Decrease due to prior year positions | — | |||
Decrease due to settlements and payments | — | |||
Decrease due to statute expirations | — | |||
Unrecognized tax benefits as of December 31 | $ | 683 | ||
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Weighted | ||||||||||||||||
Average | ||||||||||||||||
Weighted | Remaining | Aggregate | ||||||||||||||
Average | Contractual Term | Intrinsic Value | ||||||||||||||
Shares | Exercise Price | (in years) | (In millions) | |||||||||||||
(In whole, except weighted average data) | ||||||||||||||||
Outstanding at December 31, 2006 | 3,411,072 | $ | 17.59 | |||||||||||||
Granted | 784,350 | 28.63 | ||||||||||||||
Forfeited | (180,673 | ) | 24.29 | |||||||||||||
Exercised | (434,974 | ) | 15.09 | |||||||||||||
Outstanding at December 31, 2007 | 3,579,775 | $ | 19.98 | 5 | $ | 84 | ||||||||||
Exercisable at December 31, 2007 | 1,917,722 | $ | 14.57 | 6 | $ | 55 | ||||||||||
2007 | 2006 | 2005 | ||||||||||
Expected volatility | 25.88%-27.28% | 27.95%-29.64% | 29.75% | |||||||||
Expected dividend yield | — | — | — | |||||||||
Expected term (in years) | 4 | 4-6 | 5 | |||||||||
Risk free rate | 4.58%-4.68% | 4.30%-5.05% | 4.16% |
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Weighted Average | ||||||||
Grant-Date Fair | ||||||||
Units | Value per Unit | |||||||
(In whole except weighted average data) | ||||||||
Non-vested at December 31, 2006 | 2,277,186 | $ | 15.74 | |||||
Granted | 568,580 | 38.61 | ||||||
Forfeited | (115,150 | ) | 23.29 | |||||
Vested | (1,142,300 | ) | 10.74 | |||||
Non-vested at December 31, 2007 | 1,588,316 | $ | 26.99 | |||||
Weighted Average | ||||||||
Grant-Date Fair | ||||||||
Units | Value per Unit | |||||||
(In whole except weighted average data) | ||||||||
Outstanding at December 31, 2006 | 280,840 | $ | 16.19 | |||||
Granted | 22,289 | 44.43 | ||||||
Conversions | (34,135 | ) | 19.86 | |||||
Outstanding at December 31, 2007 | 268,994 | $ | 18.06 | |||||
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Weighted Average | ||||||||
Outstanding | Grant-Date Fair | |||||||
Units | Value per Unit | |||||||
(In whole except weighted average data) | ||||||||
Non-vested at December 31, 2006 | 410,664 | $ | 18.86 | |||||
Granted | 189,300 | 22.43 | ||||||
Forfeited | (63,200 | ) | 18.35 | |||||
Non-vested at December 31, 2007 | 536,764 | $ | 20.18 | |||||
2007 | 2006 | 2005 | ||||||||||
Expected volatility | 25.91%-27.28% | 27.95%-29.64% | 29.75% | |||||||||
Expected dividend payment (in dollars) | — | — | — | |||||||||
Expected term (in years) | 3 | 3-5 | 3 | |||||||||
Risk free rate | 4.54%-4.69% | 4.30%-5.04% | 4.09% |
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Total Non-Vested | Weighted Average | |||||||||||||||||||
Compensation Cost | Life Remaining | |||||||||||||||||||
Compensation Expense | Not Yet Recognized | (In years) | ||||||||||||||||||
Year Ended December 31 | As of December 31 | |||||||||||||||||||
Award | 2007 | 2006 | 2005 | 2007 | 2007 | |||||||||||||||
(In millions, except weighted average data) | ||||||||||||||||||||
NQSO’s | $ | 5 | $ | 5 | $ | 4 | $ | 8 | 0.9 | |||||||||||
RSU’s | 10 | 10 | 8 | 27 | 1.4 | |||||||||||||||
DSU’s | 1 | 1 | 3 | — | — | |||||||||||||||
PU’s | 3 | 2 | — | 5 | 1.4 | |||||||||||||||
Total | $ | 19 | $ | 18 | $ | 15 | $ | 40 | ||||||||||||
Tax benefit recognized | $ | 8 | $ | 7 | $ | 6 | ||||||||||||||
Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Revenues from Related Parties Included in Operating Revenues | ||||||||||||
WCP(a) | ||||||||||||
O&M fees | $ | — | $ | 1 | $ | 6 | ||||||
AMA fees | — | — | 2 | |||||||||
Gladstone | ||||||||||||
O&M fees | 1 | 2 | 3 | |||||||||
MIBRAG | ||||||||||||
Consulting fees | 4 | 4 | 4 | |||||||||
Total | $ | 5 | $ | 7 | $ | 15 | ||||||
Expenses from Related Parties Included in Cost of Operations | ||||||||||||
MIBRAG | ||||||||||||
Cost of purchased coal | $ | 43 | $ | 43 | $ | 41 | ||||||
(a) | For the period January 1, 2006 to March 31, 2006 |
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Period | (In millions) | |||
2008 | $ | 40 | ||
2009 | 38 | |||
2010 | 35 | |||
2011 | 33 | |||
2012 | 31 | |||
Thereafter | 243 | |||
Total | $ | 420 | ||
Period | (In millions) | |||
2008 | $ | 1,614 | ||
2009 | 795 | |||
2010 | 264 | |||
2011 | 150 | |||
2012 | 149 | |||
Thereafter | 231 | |||
Total(a) | $ | 3,203 | ||
(a) | Includes only those coal transportation commitments for 2008 as no other nominations were made as of December 31, 2007. |
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Year Ended | Year Ended | Year Ended | ||||||||||
December 31, | December 31, | December 31, | ||||||||||
2007 | 2006 | 2005 | ||||||||||
(In millions) | ||||||||||||
Interest paid, net of amount capitalized | $ | 598 | $ | 450 | $ | 257 | ||||||
Income taxes paid(a) | 22 | 18 | 21 | |||||||||
Non-cash investing and financing activities: | ||||||||||||
Addition to fixed assets due to asset retirement obligations | 7 | 15 | 4 | |||||||||
Addition to treasury stock for the maximum purchase price adjustment | — | — | 8 |
(a) | 2007 income taxes paid is net of $6 million federal tax refund received. |
By Remaining Maturity at December 31, | ||||||||||||||||||||||||
2007 | ||||||||||||||||||||||||
Under | Over | 2006 | ||||||||||||||||||||||
Guarantees | 1 Year | 1-3 Years | 3-5 Years | 5 Years | Total | Total | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Synthetic letters of credit | $ | 475 | $ | 268 | $ | — | $ | — | $ | 743 | $ | 967 | ||||||||||||
Unfunded letters of credit and surety bonds | 8 | — | — | — | 8 | 153 | ||||||||||||||||||
Asset sales guarantee obligations | 13 | — | 113 | 22 | 148 | 144 | ||||||||||||||||||
Commercial sales arrangements | 93 | 134 | — | 564 | 791 | 604 | ||||||||||||||||||
Other guarantees | — | — | — | 32 | 32 | 29 | ||||||||||||||||||
Total guarantees | $ | 589 | $ | 402 | $ | 113 | $ | 618 | $ | 1,722 | $ | 1,897 | ||||||||||||
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Ownership | Property, Plant & | Accumulated | Construction in | |||||||||||||
As of December 31, 2007 | Interest | Equipment | Depreciation | Progress | ||||||||||||
(In millions unless otherwise stated) | ||||||||||||||||
South Texas Project Units 1 and 2, Bay City, TX | 44.00 | % | $ | 2,914 | $ | (345 | ) | $ | 19 | |||||||
Big Cajun II Unit 3, New Roads, LA | 58.00 | 173 | (39 | ) | 10 | |||||||||||
Cedar Bayou Unit 4, Baytown, TX | 50.00 | — | — | 71 | ||||||||||||
Keystone, Shelocta, PA | 3.70 | 61 | (12 | ) | 6 | |||||||||||
Conemaugh, New Florence, PA | 3.72 | 72 | (15 | ) | 1 |
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Quarter Ended 2007 | ||||||||||||||||
December 31 | September 30 | June 30 | March 31 | |||||||||||||
(In millions, except per share data) | ||||||||||||||||
Operating revenues | $ | 1,382 | $ | 1,772 | $ | 1,536 | $ | 1,299 | ||||||||
Operating income | 320 | 546 | 427 | 267 | ||||||||||||
Income from continuing operations, net of income taxes | 100 | 265 | 143 | 61 | ||||||||||||
Income from discontinued operations, net of income taxes | 4 | 3 | 6 | 4 | ||||||||||||
Net income | $ | 104 | $ | 268 | $ | 149 | $ | 65 | ||||||||
Weighted average number of common shares outstanding — basic | 239 | 239 | 240 | 244 | ||||||||||||
Income from continuing operations per weighted average common share — basic | $ | 0.36 | $ | 1.06 | $ | 0.54 | $ | 0.19 | ||||||||
Income from discontinued operations per weighted average common share — basic | $ | 0.02 | $ | 0.01 | $ | 0.02 | $ | 0.02 | ||||||||
Net income per weighted average common share — basic | $ | 0.38 | $ | 1.07 | $ | 0.56 | $ | 0.21 | ||||||||
Weighted average number of common shares outstanding — diluted | 270 | 285 | 288 | 271 | ||||||||||||
Income from continuing operations per weighted average common share — diluted | $ | 0.34 | $ | 0.92 | $ | 0.49 | $ | 0.19 | ||||||||
Income from discontinued operations per weighted average common share — diluted | 0.01 | 0.01 | 0.02 | 0.01 | ||||||||||||
Net income per weighted average common share — diluted | $ | 0.35 | $ | 0.93 | $ | 0.51 | $ | 0.20 |
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Quarter Ended 2006 | ||||||||||||||||
December 31 | September 30 | June 30 | March 31 | |||||||||||||
(In millions, except per share data) | ||||||||||||||||
Operating revenues | $ | 1,135 | $ | 1,932 | $ | 1,492 | $ | 1,026 | ||||||||
Operating income | 96 | 713 | 404 | 205 | ||||||||||||
Income/(loss) from continuing operations, net of income taxes | (35 | ) | 367 | 198 | 13 | |||||||||||
Income from discontinued operations, net of income taxes | 5 | 55 | 5 | 13 | ||||||||||||
Net income/(loss) | $ | (30 | ) | $ | 422 | $ | 203 | $ | 26 | |||||||
Weighted average number of common shares outstanding — basic | 250 | 272 | 274 | 235 | ||||||||||||
Income/(loss) from continuing operations per weighted average common share — basic | $ | (0.19 | ) | $ | 1.30 | $ | 0.67 | $ | 0.01 | |||||||
Income/(loss) from discontinued operations per weighted average common share — basic | 0.02 | 0.20 | 0.02 | 0.05 | ||||||||||||
Net income/(loss) per weighted average common share — basic | $ | (0.17 | ) | $ | 1.50 | $ | 0.69 | $ | 0.06 | |||||||
Weighted average number of common shares outstanding — diluted | 250 | 317 | 319 | 238 | ||||||||||||
Income/(loss) from continuing operations per weighted average common share — diluted | $ | (0.19 | ) | $ | 1.15 | $ | 0.61 | $ | 0.01 | |||||||
Income from discontinued operations per weighted average common share — diluted | 0.02 | 0.17 | 0.02 | 0.05 | ||||||||||||
Net income/(loss) per weighted average common share — diluted | $ | (0.17 | ) | $ | 1.32 | $ | 0.63 | $ | 0.06 |
Arthur Kill Power LLC | NRG Construction LLC | |
Astoria Gas Turbine Power LLC | NRG Devon Operations Inc. | |
Berrians I Gas Turbine Power LLC | NRG Dunkirk Operations Inc. | |
Big Cajun II Unit 4 LLC | NRG El Segundo Operations Inc. | |
Cabrillo Power I LLC | NRG Generation Holdings, Inc. | |
Cabrillo Power II LLC | NRG Huntley Operations Inc. | |
Chickahominy River Energy Corp. | NRG International LLC | |
Commonwealth Atlantic Power LLC | NRG Kaufman LLC | |
Conemaugh Power LLC | NRG Mesquite LLC | |
Connecticut Jet Power LLC | NRG MidAtlantic Affiliate Services Inc. | |
Devon Power LLC | NRG Middletown Operations Inc. | |
Dunkirk Power LLC | NRG Montville Operations Inc. | |
Eastern Sierra Energy Company | NRG New Jersey Energy Sales LLC |
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El Segundo Power, LLC | NRG New Roads Holdings LLC | |
El Segundo Power II LLC | NRG North Central Operations Inc. | |
GCP Funding Company, LLC | NRG Northeast Affiliate Services Inc. | |
Hanover Energy Company | NRG Norwalk Harbor Operations Inc. | |
Hoffman Summit Wind Project, LLC | NRG Operating Services, Inc. | |
Huntley IGCC LLC | NRG Oswego Harbor Power Operations Inc. | |
Huntley Power LLC | NRG Power Marketing LLC | |
Indian River IGCC LLC | NRG Rocky Road LLC | |
Indian River Operations Inc. | NRG Saguaro Operations Inc. | |
Indian River Power LLC | NRG South Central Affiliate Services Inc. | |
James River Power LLC | NRG South Central Generating LLC | |
Kaufman Cogen LP | NRG South Central Operations Inc. | |
Keystone Power LLC | NRG South Texas LP | |
Lake Erie Properties Inc. | NRG Texas LLC | |
Louisiana Generating LLC | NRG Texas Power LLC | |
Middletown Power LLC | NRG West Coast LLC | |
Montville IGCC LLC | NRG Western Affiliate Services Inc. | |
Montville Power LLC | Oswego Harbor Power LLC | |
NEO Chester-Gen LLC | Padoma Wind Power, LLC | |
NEO Corporation | Saguaro Power LLC | |
NEO Freehold-Gen LLC | San Juan Mesa Wind Project II, LLC | |
NEO Power Services Inc. | Somerset Operations Inc. | |
New Genco GP, LLC | Somerset Power LLC | |
Norwalk Power LLC | Texas Genco Financing Corp. | |
NRG Affiliate Services Inc. | Texas Genco GP, LLC | |
NRG Arthur Kill Operations Inc. | Texas Genco Holdings, Inc. | |
NRG Asia-Pacific, Ltd. | Texas Genco LP, LLC | |
NRG Astoria Gas Turbine Operations Inc. | Texas Genco Operating Services, LLC | |
NRG Bayou Cove LLC | Texas Genco Services, LP | |
NRG Cabrillo Power Operations Inc. | Vienna Operations Inc. | |
NRG Cadillac Operations Inc. | Vienna Power LLC | |
NRG California Peaker Operations LLC | WCP (Generation) Holdings LLC | |
NRG Cedar Bayou Development Company, LLC | West Coast Power LLC | |
NRG Connecticut Affiliate Services Inc |
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Guarantor | Non-Guarantor | Consolidated | ||||||||||||||||||
Subsidiaries | Subsidiaries | NRG Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Total operating revenues | $ | 5,614 | $ | 375 | $ | — | $ | — | $ | 5,989 | ||||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of operations | 3,131 | 247 | — | — | 3,378 | |||||||||||||||
Depreciation and amortization | 630 | 24 | 4 | — | 658 | |||||||||||||||
General and administrative | 101 | 19 | 189 | — | 309 | |||||||||||||||
Development costs | 66 | 2 | 33 | — | 101 | |||||||||||||||
Total operating costs and expenses | 3,928 | 292 | 226 | — | 4,446 | |||||||||||||||
Gain/(loss) on sale of assets | 18 | — | (1 | ) | — | 17 | ||||||||||||||
Operating Income/(Loss) | 1,704 | 83 | (227 | ) | — | 1,560 | ||||||||||||||
Other Income/(Expense) | ||||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 204 | — | 986 | (1,190 | ) | — | ||||||||||||||
Equity in earnings of unconsolidated affiliates | (3 | ) | 57 | — | — | 54 | ||||||||||||||
Gain on sale of equity method investments | — | 1 | — | — | 1 | |||||||||||||||
Other income, net | 9 | 13 | 33 | — | 55 | |||||||||||||||
Refinancing expenses | — | — | (35 | ) | — | (35 | ) | |||||||||||||
Interest expense | (250 | ) | (64 | ) | (375 | ) | — | (689 | ) | |||||||||||
Total other income/(expense) | (40 | ) | 7 | 609 | (1,190 | ) | (614 | ) | ||||||||||||
Income From Continuing Operations Before Income Taxes | 1,664 | 90 | 382 | (1,190 | ) | 946 | ||||||||||||||
Income tax expense/(benefit) | 576 | 5 | (204 | ) | — | 377 | ||||||||||||||
Income From Continuing Operations | 1,088 | 85 | 586 | (1,190 | ) | 569 | ||||||||||||||
Income from discontinued operations, net of income taxes | — | 17 | — | — | 17 | |||||||||||||||
Net Income | $ | 1,088 | $ | 102 | $ | 586 | $ | (1,190 | ) | $ | 586 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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Guarantor | Non-Guarantor | Consolidated | ||||||||||||||||
Subsidiaries | Subsidiaries | NRG Energy Inc. | Eliminations(a) | Balance | ||||||||||||||
(In millions) | ||||||||||||||||||
ASSETS | ||||||||||||||||||
Current Assets | ||||||||||||||||||
Cash and cash equivalents | $ | (4 | ) | $ | 124 | $ | 1,012 | $ | — | $ | 1,132 | |||||||
Restricted cash | 1 | 28 | — | — | 29 | |||||||||||||
Accounts receivable-trade, net | 445 | 37 | — | — | 482 | |||||||||||||
Inventory | 439 | 12 | — | — | 451 | |||||||||||||
Deferred income taxes | 139 | (18 | ) | 3 | — | 124 | ||||||||||||
Derivative instruments valuation | 1,034 | — | — | — | 1,034 | |||||||||||||
Collateral on deposit in support of energy risk management activities | 85 | — | — | — | 85 | |||||||||||||
Prepayments and other current assets | 96 | 35 | 195 | (152 | ) | 174 | ||||||||||||
Current assets — discontinued operations | — | 51 | — | — | 51 | |||||||||||||
Total current assets | 2,235 | 269 | 1,210 | (152 | ) | 3,562 | ||||||||||||
Net Property, Plant and Equipment | 10,828 | 470 | 22 | — | 11,320 | |||||||||||||
Other Assets | ||||||||||||||||||
Investment in subsidiaries | 610 | — | 9,787 | (10,397 | ) | — | ||||||||||||
Equity investments in affiliates | 28 | 397 | — | — | 425 | |||||||||||||
Notes receivable | 360 | 126 | 3,779 | (4,139 | ) | 126 | ||||||||||||
Capital lease, less current portion | — | 365 | — | — | 365 | |||||||||||||
Goodwill | 1,786 | — | — | — | 1,786 | |||||||||||||
Intangible assets, net | 859 | 14 | — | — | 873 | |||||||||||||
Intangible assets held-for-sale | 14 | — | — | — | 14 | |||||||||||||
Nuclear decommissioning trust fund | 384 | — | — | — | 384 | |||||||||||||
Derivative instruments valuation | 150 | — | — | — | 150 | |||||||||||||
Other non-current assets | 11 | 1 | 164 | — | 176 | |||||||||||||
Non-current assets — discontinued operations | — | 93 | — | — | 93 | |||||||||||||
Total other assets | 4,202 | 996 | 13,730 | (14,536 | ) | 4,392 | ||||||||||||
Total Assets | $ | 17,265 | $ | 1,735 | $ | 14,962 | $ | (14,688 | ) | $ | 19,274 | |||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||
Current Liabilities | ||||||||||||||||||
Current portion of long-term debt and capital leases | $ | 83 | $ | 282 | $ | 184 | $ | (83 | ) | $ | 466 | |||||||
Accounts payable — trade | (699 | ) | 352 | 731 | — | 384 | ||||||||||||
Derivative instruments valuation | 916 | 1 | — | — | 917 | |||||||||||||
Accrued expenses and other current liabilities | 335 | 62 | 145 | (69 | ) | 473 | ||||||||||||
Current liabilities — discontinued operations | — | 37 | — | — | 37 | |||||||||||||
Total current liabilities | 635 | 734 | 1,060 | (152 | ) | 2,277 | ||||||||||||
Other Liabilities | ||||||||||||||||||
Long-term debt and capital leases | 3,773 | 571 | 7,690 | (4,139 | ) | 7,895 | ||||||||||||
Nuclear decommissioning reserve | 307 | — | — | — | 307 | |||||||||||||
Nuclear decommissioning trust liability | 326 | — | — | — | 326 | |||||||||||||
Deferred income taxes | 598 | (138 | ) | 383 | — | 843 | ||||||||||||
Derivative instruments valuation | 690 | 16 | 53 | — | 759 | |||||||||||||
Non-current out-of-market contracts | 628 | — | — | — | 628 | |||||||||||||
Other non-current liabilities | 377 | 10 | 25 | — | 412 | |||||||||||||
Non-current liabilities — discontinued operations | — | 76 | — | — | 76 | |||||||||||||
Total non-current liabilities | 6,699 | 535 | 8,151 | (4,139 | ) | 11,246 | ||||||||||||
Total liabilities | 7,334 | 1,269 | 9,211 | (4,291 | ) | 13,523 | ||||||||||||
3.625% Preferred Stock | — | — | 247 | — | 247 | |||||||||||||
Stockholders’ Equity | 9,931 | 466 | 5,504 | (10,397 | ) | 5,504 | ||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 17,265 | $ | 1,735 | $ | 14,962 | $ | (14,688 | ) | $ | 19,274 | |||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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Non- | ||||||||||||||||||||
Guarantor | Guarantor | NRG Energy, | Consolidated | |||||||||||||||||
Subsidiaries | Subsidiaries | Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||
Net income | $ | 1,088 | $ | 102 | $ | 586 | $ | (1,190 | ) | $ | 586 | |||||||||
Adjustments to reconcile net income to net cash provided/(used) by operating activities | ||||||||||||||||||||
Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | 101 | (36 | ) | (684 | ) | 586 | (33 | ) | ||||||||||||
Depreciation and amortization of nuclear fuel | 688 | 27 | 4 | — | 719 | |||||||||||||||
Amortization and write-of of deferred financing costs and debt discount/premiums | — | 6 | 60 | — | 66 | |||||||||||||||
Amortization of intangibles and out-of-market contracts | (160 | ) | 4 | — | — | (156 | ) | |||||||||||||
Amortization of unearned equity compensation | — | — | 19 | — | 19 | |||||||||||||||
Gains on sale of equity method investments | — | (1 | ) | — | — | (1 | ) | |||||||||||||
(Gain)/loss on sale assets | (18 | ) | — | �� | 1 | — | (17 | ) | ||||||||||||
Impairment charges and asset write downs | 9 | — | 11 | — | 20 | |||||||||||||||
Changes in derivatives | 77 | — | — | — | 77 | |||||||||||||||
Changes in deferred income taxes | 112 | (31 | ) | 271 | — | 352 | ||||||||||||||
Gain on sale of emission allowances | (30 | ) | (1 | ) | — | — | (31 | ) | ||||||||||||
Change in nuclear decommissioning trust liability | 32 | — | — | — | 32 | |||||||||||||||
Changes in collateral deposits supporting energy risk management activities | (125 | ) | — | — | — | (125 | ) | |||||||||||||
Cash provided/(used) by changes in other working capital, net of disposition affects | 214 | 100 | (305 | ) | — | 9 | ||||||||||||||
Net Cash Provided by Operating Activities | 1,988 | 170 | (37 | ) | (604 | ) | 1,517 | |||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||
Intercompany loans to subsidiaries | 655 | — | 2,109 | (2,764 | ) | — | ||||||||||||||
Capital expenditures | (389 | ) | (84 | ) | (8 | ) | — | (481 | ) | |||||||||||
Decrease in restricted cash, net | — | 12 | — | — | 12 | |||||||||||||||
Decrease in notes receivable | — | 34 | — | — | 34 | |||||||||||||||
Decrease in trust fund balances | 19 | — | — | — | 19 | |||||||||||||||
Purchases of emission allowances | (161 | ) | — | — | — | (161 | ) | |||||||||||||
Proceeds from sale of emission allowances | 271 | 1 | — | — | 272 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | (265 | ) | — | — | — | (265 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 233 | — | — | — | 233 | |||||||||||||||
Proceeds from sale of investment and equipment | — | 2 | — | — | 2 | |||||||||||||||
Purchase of securities | — | — | (49 | ) | — | (49 | ) | |||||||||||||
Proceeds from sale of discontinued operations and assets | 29 | — | 28 | — | 57 | |||||||||||||||
Net Cash Provided/(Used) by Investing Activities | 392 | (35 | ) | 2,080 | (2,764 | ) | (327 | ) | ||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||
Payment of dividends to preferred stockholders | — | — | (55 | ) | — | (55 | ) | |||||||||||||
Payment for treasury stock | — | — | (353 | ) | — | (353 | ) | |||||||||||||
Payments from intercompany loans | (2,101 | ) | (38 | ) | (625 | ) | 2,764 | — | ||||||||||||
Payments from intercompany dividends | (302 | ) | (302 | ) | — | 604 | — | |||||||||||||
Proceeds from issuance of common stock | — | — | 7 | — | 7 | |||||||||||||||
Proceeds from issuance of long-term debt | — | — | 1,411 | — | 1,411 | |||||||||||||||
Payment of deferred debt issuance costs | — | — | (5 | ) | — | (5 | ) | |||||||||||||
Payments of short and long-term debt | (1 | ) | (64 | ) | (1,754 | ) | — | (1,819 | ) | |||||||||||
Net Cash Provided/(Used) by Financing Activities | (2,404 | ) | (404 | ) | (1,374 | ) | 3,368 | (814 | ) | |||||||||||
Change in cash from discontinued operations | — | (25 | ) | — | — | (25 | ) | |||||||||||||
Effect of exchange rate changes on cash and cash equivalents | — | 4 | — | — | 4 | |||||||||||||||
Net Increase/(decrease) in Cash and Cash Equivalents | (24 | ) | (290 | ) | 669 | — | 355 | |||||||||||||
Cash and Cash Equivalents at Beginning of Period | 20 | 414 | 343 | — | 777 | |||||||||||||||
Cash and Cash Equivalents at End of Period | $ | (4 | ) | $ | 124 | $ | 1,012 | $ | — | $ | 1,132 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2006
Guarantor | Non-Guarantor | NRG | Consolidated | |||||||||||||||||
Subsidiaries | Subsidiaries | Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Total operating revenues | $ | 5,282 | $ | 303 | $ | — | $ | — | $ | 5,585 | ||||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of operations | 3,040 | 223 | 2 | — | 3,265 | |||||||||||||||
Depreciation and amortization | 562 | 23 | 5 | — | 590 | |||||||||||||||
General and administrative | 83 | 13 | 180 | — | 276 | |||||||||||||||
Development costs | 32 | — | 4 | — | 36 | |||||||||||||||
Total operating costs and expenses | 3,717 | 259 | 191 | — | 4,167 | |||||||||||||||
Operating Income/(Loss) | 1,565 | 44 | (191 | ) | — | 1,418 | ||||||||||||||
Other Income/(Expense) | ||||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 134 | — | 996 | (1,130 | ) | — | ||||||||||||||
Equity in earnings of unconsolidated affiliates | 2 | 58 | — | — | 60 | |||||||||||||||
Write downs and gains/(losses) on sales of equity method investments | (5 | ) | 13 | — | — | 8 | ||||||||||||||
Other income, net | 20 | 115 | 41 | (20 | ) | 156 | ||||||||||||||
Refinancing expenses | — | — | (187 | ) | — | (187 | ) | |||||||||||||
Interest expense | (232 | ) | (56 | ) | (322 | ) | 20 | (590 | ) | |||||||||||
Total other income/(expense) | (81 | ) | 130 | 528 | (1,130 | ) | (553 | ) | ||||||||||||
Income From Continuing Operations Before Income Taxes | 1,484 | 174 | 337 | (1,130 | ) | 865 | ||||||||||||||
Income tax expense | 549 | 42 | (269 | ) | — | 322 | ||||||||||||||
Income From Continuing Operations | 935 | 132 | 606 | (1,130 | ) | 543 | ||||||||||||||
Income from discontinued operations, net of income taxes | — | 63 | 15 | — | 78 | |||||||||||||||
Net Income | $ | 935 | $ | 195 | $ | 621 | $ | (1,130 | ) | $ | 621 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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CONSOLIDATING BALANCE SHEETS
December 31, 2006
Guarantor | Non-Guarantor | NRG Energy | Consolidated | |||||||||||||||||
Subsidiaries | Subsidiaries | Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current Assets | ||||||||||||||||||||
Cash and cash equivalents | $ | 20 | $ | 414 | $ | 343 | $ | — | $ | 777 | ||||||||||
Restricted cash | 1 | 40 | — | — | 41 | |||||||||||||||
Accounts receivable-trade, net | 332 | 37 | — | — | 369 | |||||||||||||||
Inventory | 408 | 12 | — | — | 420 | |||||||||||||||
Deferred income taxes | — | — | — | — | — | |||||||||||||||
Derivative instruments valuation | 1,230 | — | — | — | 1,230 | |||||||||||||||
Collateral on deposit in support of energy risk management activities | 27 | — | — | — | 27 | |||||||||||||||
Prepayments and other current assets | 173 | 33 | 736 | (747 | ) | 195 | ||||||||||||||
Current assets — discontinued operations | — | 24 | — | — | 24 | |||||||||||||||
Total current assets | 2,191 | 560 | 1,079 | (747 | ) | 3,083 | ||||||||||||||
Net Property, Plant and Equipment | 11,178 | 349 | 19 | — | 11,546 | |||||||||||||||
Other Assets | ||||||||||||||||||||
Investment in subsidiaries | 730 | — | 9,163 | (9,893 | ) | — | ||||||||||||||
Equity investments in affiliates | 31 | 313 | — | — | 344 | |||||||||||||||
Notes receivable, less current portion | 1,015 | 114 | 5,503 | (6,518 | ) | 114 | ||||||||||||||
Capital lease, less current portion, net | — | 365 | — | — | 365 | |||||||||||||||
Goodwill | 1,789 | — | — | — | 1,789 | |||||||||||||||
Intangible assets, net | 977 | 4 | — | — | 981 | |||||||||||||||
Intangible assets held-for-sale | 78 | — | 1 | — | 79 | |||||||||||||||
Nuclear decommissioning trust fund | 352 | — | — | — | 352 | |||||||||||||||
Derivative instruments valuation | 424 | — | 15 | — | 439 | |||||||||||||||
Deferred income taxes | 27 | (27 | ) | — | — | — | ||||||||||||||
Other non-current assets | 24 | 56 | 182 | — | 262 | |||||||||||||||
Non-current assets — discontinued operations | — | 82 | — | — | 82 | |||||||||||||||
Total other assets | 5,447 | 907 | 14,864 | (16,411 | ) | 4,807 | ||||||||||||||
Total Assets | $ | 18,816 | $ | 1,816 | $ | 15,962 | $ | (17,158 | ) | $ | 19,436 | |||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||
Current portion of long-term debt and capital leases | $ | 460 | $ | 94 | $ | 37 | $ | (468 | ) | $ | 123 | |||||||||
Accounts payable — trade | (682 | ) | 284 | 727 | — | 329 | ||||||||||||||
Derivative instruments valuation | 964 | — | — | — | 964 | |||||||||||||||
Deferred income taxes | 23 | 7 | 134 | — | 164 | |||||||||||||||
Accrued expenses and other current liabilities | 509 | 35 | 160 | (280 | ) | 424 | ||||||||||||||
Current liabilities — discontinued operations | — | 28 | — | — | 28 | |||||||||||||||
Total current liabilities | 1,274 | 448 | 1,058 | (748 | ) | 2,032 | ||||||||||||||
Other Liabilities | ||||||||||||||||||||
Long-term debt and capital leases | 5,504 | 825 | 8,791 | (6,517 | ) | 8,603 | ||||||||||||||
Nuclear decommissioning reserve | 289 | — | — | — | 289 | |||||||||||||||
Nuclear decommissioning trust liability | 324 | — | — | — | 324 | |||||||||||||||
Deferred income taxes | 494 | (104 | ) | 164 | — | 554 | ||||||||||||||
Derivative instruments valuation | 325 | 6 | 20 | — | 351 | |||||||||||||||
Non-current out-of-market contracts | 897 | — | — | — | 897 | |||||||||||||||
Other non-current liabilities | 385 | 8 | 24 | — | 417 | |||||||||||||||
Non-current liabilities — discontinued operations | — | 64 | — | — | 64 | |||||||||||||||
Total non-current liabilities | 8,218 | 799 | 8,999 | (6,517 | ) | 11,499 | ||||||||||||||
Total liabilities | 9,492 | 1,247 | 10,057 | (7,265 | ) | 13,531 | ||||||||||||||
Minority Interest | — | — | — | — | — | |||||||||||||||
3.625% Preferred Stock | — | — | 247 | — | 247 | |||||||||||||||
Stockholders’ Equity | 9,324 | 569 | 5,658 | (9,893 | ) | 5,658 | ||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 18,816 | $ | 1,816 | $ | 15,962 | $ | (17,158 | ) | $ | 19,436 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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Guarantor | Non-Guarantor | NRG | Consolidated | |||||||||||||||||
Subsidiaries | Subsidiaries | Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||
Net income | $ | 935 | $ | 195 | $ | 621 | $ | (1,130 | ) | $ | 621 | |||||||||
Adjustments to reconcile net income to net cash provided/(used) by operating activities Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | (136 | ) | (31 | ) | (996 | ) | 1,130 | (33 | ) | |||||||||||
Depreciation and amortization of nuclear fuel | 609 | 35 | 10 | — | 654 | |||||||||||||||
Amortization and write-of of deferred financing costs and debt discount/premiums | — | 6 | 73 | — | 79 | |||||||||||||||
Amortization of intangibles and out-of-market contracts | (487 | ) | (3 | ) | — | — | (490 | ) | ||||||||||||
Amortization of unearned equity compensation | — | — | 14 | — | 14 | |||||||||||||||
Write down and gains on sale of equity method investments | 5 | (13 | ) | — | — | (8 | ) | |||||||||||||
Loss on sale of equipment | 10 | — | — | — | 10 | |||||||||||||||
Changes in derivatives | (151 | ) | 2 | — | — | (149 | ) | |||||||||||||
Changes in deferred income taxes | 474 | 19 | (166 | ) | — | 327 | ||||||||||||||
Gain on legal settlement | — | (67 | ) | — | — | (67 | ) | |||||||||||||
Gain on sale of discontinued operations | — | (71 | ) | (5 | ) | — | (76 | ) | ||||||||||||
Gain on sale of emission allowances | (64 | ) | — | — | — | (64 | ) | |||||||||||||
Change in nuclear decommissioning trust liability | 12 | — | — | — | 12 | |||||||||||||||
Changes in collateral deposits supporting energy risk management activities | 454 | — | — | — | 454 | |||||||||||||||
Settlement of out-of-market power contracts | (1,073 | ) | — | — | — | (1,073 | ) | |||||||||||||
Cash provided by changes in other working capital, net of acquisition and disposition affects | (554 | ) | 213 | 538 | — | 197 | ||||||||||||||
Net Cash Provided by Operating Activities | 34 | 285 | 89 | — | 408 | |||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||
I/C loans to subsidiaries | (939 | ) | — | (4,106 | ) | 5,045 | — | |||||||||||||
Acquisition of Texas Genco LLC, WCP and Padoma, net of cash acquired | — | — | (4,333 | ) | — | (4,333 | ) | |||||||||||||
Capital expenditures | (195 | ) | (21 | ) | (5 | ) | — | (221 | ) | |||||||||||
Decrease in restricted cash, net | 2 | 4 | — | — | 6 | |||||||||||||||
Decrease in notes receivable | — | 27 | — | — | 27 | |||||||||||||||
Purchases of emission allowances | (135 | ) | — | — | — | (135 | ) | |||||||||||||
Proceeds from sale of emission allowances | 146 | — | — | — | 146 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | (227 | ) | — | — | — | (227 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 214 | — | — | — | 214 | |||||||||||||||
Proceeds from sale of investments | 53 | 33 | — | — | 86 | |||||||||||||||
Proceeds from sale of discontinued operations | — | 239 | 22 | — | 261 | |||||||||||||||
Net Cash Provided/(Used) by Investing Activities | (1,081 | ) | 282 | (8,422 | ) | 5,045 | (4,176 | ) | ||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||
Payment of dividends to preferred stockholders | — | — | (50 | ) | — | (50 | ) | |||||||||||||
Payment of financing element of acquired derivatives | (296 | ) | — | — | — | (296 | ) | |||||||||||||
Payment for treasury stock | — | (500 | ) | (232 | ) | — | (732 | ) | ||||||||||||
Funded letter of credit | — | — | 350 | — | 350 | |||||||||||||||
Proceeds from Intercompany loans | 4,106 | — | 939 | (5,045 | ) | — | ||||||||||||||
Proceeds from issuance of common stock, net | — | — | 986 | — | 986 | |||||||||||||||
Proceeds from issuance of preferred shares, net | — | — | 486 | — | 486 | |||||||||||||||
Proceeds from issuance of long-term debt | — | 333 | 8,286 | — | 8,619 | |||||||||||||||
Payment of deferred debt issuance costs | — | — | (199 | ) | — | (199 | ) | |||||||||||||
Payments of short and long-term debt | (2,736 | ) | (62 | ) | (2,313 | ) | — | (5,111 | ) | |||||||||||
Net Cash Provided/(Used) by Financing Activities | 1,074 | (229 | ) | 8,253 | (5,045 | ) | 4,053 | |||||||||||||
Change in cash from discontinued operations | — | 1 | 1 | — | 2 | |||||||||||||||
Effect of exchange rate changes on cash and cash equivalents | — | 4 | — | — | 4 | |||||||||||||||
Net Increase/(decrease) in Cash and Cash Equivalents | 27 | 343 | (79 | ) | — | 291 | ||||||||||||||
Cash and Cash Equivalents at Beginning of Period | (7 | ) | 71 | 422 | — | 486 | ||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 20 | $ | 414 | $ | 343 | $ | — | $ | 777 | ||||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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CONSOLIDATING STATEMENTS OF OPERATIONS
Year Ended December 31, 2005
Guarantor | Non-Guarantor | NRG | Consolidated | |||||||||||||||||
Subsidiaries | Subsidiaries | Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Total operating revenues | $ | 2,095 | $ | 310 | $ | — | $ | (5 | ) | $ | 2,400 | |||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of operations | 1,600 | 234 | — | (5 | ) | 1,829 | ||||||||||||||
Depreciation and amortization | 133 | 20 | 5 | — | 158 | |||||||||||||||
General and administrative | 39 | 14 | 123 | — | 176 | |||||||||||||||
Other charges | 6 | — | 6 | — | 12 | |||||||||||||||
Total operating costs and expenses | 1,778 | 268 | 134 | (5 | ) | 2,175 | ||||||||||||||
Operating Income/(Loss) | 317 | 42 | (134 | ) | — | 225 | ||||||||||||||
Other Income (Expense) | ||||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 101 | — | 274 | (375 | ) | — | ||||||||||||||
Equity in earnings of unconsolidated affiliates | 35 | 69 | — | — | 104 | |||||||||||||||
Write downs and gains/(losses) on sales of equity method investments | (47 | ) | 16 | — | — | (31 | ) | |||||||||||||
Other income, net | 16 | 46 | 13 | (21 | ) | 54 | ||||||||||||||
Refinancing expense | — | 1 | (66 | ) | — | (65 | ) | |||||||||||||
Interest expense | (1 | ) | (56 | ) | (141 | ) | 21 | (177 | ) | |||||||||||
Total other income | 104 | 76 | 80 | (375 | ) | (115 | ) | |||||||||||||
Income/(Loss) From Continuing Operations Before Income Taxes | 421 | 118 | (54 | ) | (375 | ) | 110 | |||||||||||||
Income tax expense/(benefit) | 155 | 17 | (130 | ) | — | 42 | ||||||||||||||
Income From Continuing Operations | 266 | 101 | 76 | (375 | ) | 68 | ||||||||||||||
Income from discontinued operations, net of income taxes | 5 | 3 | 8 | — | 16 | |||||||||||||||
Net Income | $ | 271 | $ | 104 | $ | 84 | $ | (375 | ) | $ | 84 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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Guarantor | Non-Guarantor | NRG | Consolidated | |||||||||||||||||
Subsidiaries | Subsidiaries | Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||
Net income | $ | 271 | $ | 104 | $ | 84 | $ | (375 | ) | $ | 84 | |||||||||
Adjustments to reconcile net income to net cash provided/ (used) by operating activities Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | (64 | ) | (45 | ) | 453 | (352 | ) | (8 | ) | |||||||||||
Depreciation and amortization of nuclear fuel | 133 | 52 | 10 | — | 195 | |||||||||||||||
Amortization and write-of of deferred financing costs and debt discount/premiums | — | (4 | ) | 18 | — | 14 | ||||||||||||||
Amortization of intangibles and out-of-market contracts | (2 | ) | 19 | — | — | 17 | ||||||||||||||
Amortization of unearned equity compensation | 3 | 1 | 8 | — | 12 | |||||||||||||||
Write down and (gains)/losses on sale of equity method investments | 47 | (16 | ) | — | — | 31 | ||||||||||||||
Loss on sale of equipment | 4 | — | — | — | 4 | |||||||||||||||
Impairment charges | 6 | — | — | — | 6 | |||||||||||||||
Changes in derivatives | 150 | (10 | ) | 3 | — | 143 | ||||||||||||||
Changes in deferred income taxes | 71 | 13 | (82 | ) | — | 2 | ||||||||||||||
Gain on legal settlement | — | (14 | ) | — | — | (14 | ) | |||||||||||||
Gain on sale of discontinued operations | (6 | ) | — | — | — | (6 | ) | |||||||||||||
Changes in collateral deposits supporting energy risk management activities | (405 | ) | — | — | — | (405 | ) | |||||||||||||
Cash provided by changes in other working capital, net of acquisition and disposition affects | (421 | ) | 10 | 404 | — | (7 | ) | |||||||||||||
Net Cash Provided/(Used) by Operating Activities | (213 | ) | 110 | 898 | (727 | ) | 68 | |||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||
Return of capital from subsidiaries | — | — | 1,398 | (1,398 | ) | — | ||||||||||||||
Intercompany loans to subsidiaries | — | — | (2,181 | ) | 2,181 | — | ||||||||||||||
Proceeds from intercompany loans with parents and subsidiaries | 327 | — | 325 | (652 | ) | — | ||||||||||||||
Capital expenditures | (78 | ) | (22 | ) | (6 | ) | — | (106 | ) | |||||||||||
Decrease in restricted cash, net | 1 | 44 | — | — | 45 | |||||||||||||||
Decrease in notes receivable | 5 | 102 | — | — | 107 | |||||||||||||||
Deferred acquisition costs | — | — | (5 | ) | — | (5 | ) | |||||||||||||
Proceeds from sale of investments | 9 | 70 | — | — | 79 | |||||||||||||||
Proceeds on sale of discontinued operations | 36 | — | — | — | 36 | |||||||||||||||
Return of capital from equity method investments and projects | — | 2 | — | — | 2 | |||||||||||||||
Net Cash Provided/(Used) by Investing Activities | 300 | 196 | (469 | ) | 131 | 158 | ||||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||
Return of capital payments to parent | (1,398 | ) | — | — | 1,398 | — | ||||||||||||||
Proceeds from parent intercompany loans | 2,181 | — | — | (2,181 | ) | — | ||||||||||||||
Payments for parent intercompany loans | (325 | ) | (327 | ) | — | 652 | — | |||||||||||||
Payments of dividends to preferred stockholders | (704 | ) | (23 | ) | (20 | ) | 727 | (20 | ) | |||||||||||
Payment for treasury stock | — | — | (250 | ) | — | (250 | ) | |||||||||||||
Repayment of minority interest obligations | — | (4 | ) | — | — | (4 | ) | |||||||||||||
Proceeds from issuance of preferred stock | — | — | 246 | — | 246 | |||||||||||||||
Proceeds from issuance of long-term debt | — | 249 | — | — | 249 | |||||||||||||||
Deferred debt issuance costs | — | — | (46 | ) | — | (46 | ) | |||||||||||||
Payments for short and long-term debt | (4 | ) | (352 | ) | (649 | ) | — | (1,005 | ) | |||||||||||
Net Cash Used by Financing Activities | (250 | ) | (457 | ) | (719 | ) | 596 | (830 | ) | |||||||||||
Change in cash from discontinued operations | — | 36 | 1 | — | 37 | |||||||||||||||
Effect of exchange rate changes on cash and cash equivalents | — | (2 | ) | — | — | (2 | ) | |||||||||||||
Change in Cash and Cash equivalents | (163 | ) | (117 | ) | (289 | ) | — | (569 | ) | |||||||||||
Cash and Cash Equivalents at Beginning of Period | 156 | 188 | 711 | — | 1,055 | |||||||||||||||
Cash and Cash Equivalents at End of Period | $ | (7 | ) | $ | 71 | $ | 422 | $ | — | $ | 486 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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Additions | ||||||||||||||||||
Balance at | Charged to | Charged to | ||||||||||||||||
Beginning of | Costs and | Other | Balance at | |||||||||||||||
Period | Expenses | Accounts | Deductions | End of Period | ||||||||||||||
(In millions) | ||||||||||||||||||
Allowance for doubtful accounts, deducted from accounts receivable | ||||||||||||||||||
Year ended December 31, 2007 | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||
Year ended December 31, 2006 | 2 | — | — | (1 | ) | 1 | ||||||||||||
Year ended December 31, 2005 | 1 | 2 | — | (1 | ) | 2 | ||||||||||||
Income tax valuation allowance, deducted from deferred tax assets | ||||||||||||||||||
Year ended December 31, 2007 | $ | 581 | $ | 6 | $ | 8 | $ | (56 | ) | $ | 539 | |||||||
Year ended December 31, 2006 | 836 | (10 | ) | (81 | ) | (164 | ) | 581 | ||||||||||
Year ended December 31, 2005 | 788 | 22 | 85 | (59 | ) | 836 |
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Signature | Title | Date | ||||
/s/ David W. Crane David W. Crane | President, Chief Executive Officer and Director | February 28, 2008 | ||||
/s/ Howard E. Cosgrove Howard E. Cosgrove | Chairman of the Board | February 28, 2008 | ||||
/s/ John F. Chlebowski John F. Chlebowski | Director | February 28, 2008 | ||||
/s/ Lawrence S. Coben Lawrence S. Coben | Director | February 28, 2008 | ||||
/s/ Stephen L. Cropper Stephen L. Cropper | Director | February 28, 2008 | ||||
/s/ William E. Hantke William E. Hantke | Director | February 28, 2008 | ||||
/s/ Paul W. Hobby Paul W. Hobby | Director | February 28, 2008 | ||||
/s/ Maureen Miskovic Maureen Miskovic | Director | February 28, 2008 | ||||
/s/ Anne C. Schaumburg Anne C. Schaumburg | Director | February 28, 2008 | ||||
/s/ Herbert H. Tate Herbert H. Tate | Director | February 28, 2008 | ||||
/s/ Thomas H. Weidemeyer Thomas H. Weidemeyer | Director | February 28, 2008 | ||||
/s/ Walter R. Young Walter R. Young | Director | February 28, 2008 |
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2 | .1 | Third Amended Joint Plan of Reorganization of NRG Energy, Inc., NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance Company I LLC, and NRGenerating Holdings (No. 23) B.V.(5) | ||
2 | .2 | First Amended Joint Plan of Reorganization of NRG Northeast Generating LLC (and certain of its subsidiaries), NRG South Central Generating (and certain of its subsidiaries) and Berrians I Gas Turbine Power LLC.(5) | ||
2 | .3 | Acquisition Agreement, dated as of September 30, 2005, by and among NRG Energy, Inc., Texas Genco LLC and the Direct and Indirect Owners of Texas Genco LLC.(11) | ||
3 | .1 | Amended and Restated Certificate of Incorporation.(16) | ||
3 | .2 | Amended and Restated By-Laws.(1) | ||
3 | .3 | Certificate of Designation of 4.0% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on December 20, 2004.(7) | ||
3 | .4 | Certificate of Designations of 3.625% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on August 11, 2005.(17) | ||
3 | .5 | Certificate of Designations of 5.75% Mandatory Convertible Preferred Stock, as filed with the Secretary of State of the State of Delaware on January 27, 2006.(19) | ||
3 | .6 | Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 14, 2006.(27) | ||
3 | .7 | Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance II LLC, as filed with the Secretary of State of Delaware on August 14, 2006.(27) | ||
4 | .1 | Supplemental Indenture dated as of December 30, 2005, among NRG Energy, Inc., the subsidiary guarantors named on Schedule A thereto and Law Debenture Trust Company of New York, as trustee.(13) | ||
4 | .2 | Amended and Restated Common Agreement among XL Capital Assurance Inc., Goldman Sachs Mitsui Marine Derivative Products, L.P., Law Debenture Trust Company of New York, as Trustee, The Bank of New York, as Collateral Agent, NRG Peaker Finance Company LLC and each Project Company Party thereto dated as of January 6, 2004, together with Annex A to the Common Agreement.(2) | ||
4 | .3 | Amended and Restated Security Deposit Agreement among NRG Peaker Finance Company, LLC and each Project Company party thereto, and the Bank of New York, as Collateral Agent and Depositary Agent, dated as of January 6, 2004.(2) | ||
4 | .4 | NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of New York, as Collateral Agent, dated as of January 6, 2004.(2) | ||
4 | .5 | Indenture dated June 18, 2002, between NRG Peaker Finance Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC and Sterlington Power LLC, as Guarantors, XL Capital Assurance Inc., as Insurer, and Law Debenture Trust Company, as Successor Trustee to the Bank of New York.(3) | ||
4 | .6 | Registration Rights Agreement, dated December 21, 2004, by and among NRG Energy, Inc., Citigroup Global Markets Inc. and Deutsche Bank Securities Inc.(6) | ||
4 | .7 | Specimen of Certificate representing common stock of NRG Energy, Inc.(26) | ||
4 | .8 | Indenture, dated February 2, 2006, among NRG Energy, Inc. and Law Debenture Trust Company of New York.(19) | ||
4 | .9 | First Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(20) | ||
4 | .10 | Second Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(20) | ||
4 | .11 | Form of 7.250% Senior Note due 2014.(20) | ||
4 | .12 | Form of 7.375% Senior Note due 2016.(20) |
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4 | .13 | Third Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(22) | ||
4 | .14 | Fourth Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(22) | ||
4 | .15 | Fifth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(23) | ||
4 | .16 | Sixth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(23) | ||
4 | .17 | Seventh Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(28) | ||
4 | .18 | Eighth Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(28) | ||
4 | .19 | Ninth Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(29) | ||
4 | .20 | Tenth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(33) | ||
4 | .21 | Eleventh Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(33) | ||
4 | .22 | Twelfth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(33) | ||
4 | .23 | Thirteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(34) | ||
4 | .24 | Fourteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(34) | ||
4 | .25 | Fifteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(34) | ||
4 | .26 | Form of 7.375% Senior Note due 2017.(29) | ||
10 | .1 | Note Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc. and each of the purchasers named therein.(4) | ||
10 | .2 | Master Shelf and Revolving Credit Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate, which becomes party thereto.(4) | ||
10 | .3* | Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Officers and Key Management.(15) | ||
10 | .4* | Form of NRG Energy, Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Directors.(15) | ||
10 | .5* | Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified Stock Option Agreement.(8) | ||
10 | .6* | Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock Unit Agreement.(8) | ||
10 | .7* | Form of NRG Energy, Inc. Long Term Incentive Plan Performance Unit Agreement.(15) |
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10 | .8* | Annual Incentive Plan for Designated Corporate Officers.(9) | ||
10 | .9* | Letter Agreement, dated February 19, 2004, between NRG Energy, Inc. and Robert C. Flexon.(8) | ||
10 | .10 | Railroad Car Full Service Master Leasing Agreement, dated as of February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(15) | ||
11 | .11 | Commitment Letter, dated February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(15) | ||
10 | .12 | Purchase Agreement (West Coast Power) dated as of December 27, 2005, by and among NRG Energy, Inc., NRG West Coast LLC (Buyer), DPC II Inc. (Seller) and Dynegy, Inc.(14) | ||
10 | .13 | Purchase Agreement (Rocky Road Power), dated as of December 27, 2005, by and among Termo Santander Holding, L.L.C.(Buyer), Dynegy, Inc., NRG Rocky Road LLC (Seller) and NRG Energy, Inc.(14) | ||
10 | .14* | Letter Agreement, dated June 21, 2005, between NRG Energy, Inc. and Kevin T. Howell.(18) | ||
10 | .15 | Stock Purchase Agreement, dated as of August 10, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(17) | ||
10 | .16 | Accelerated Share Repurchase Agreement, dated as of August 11, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(17) | ||
10 | .17 | Investor Rights Agreement, dated as of February 2, 2006, by and among NRG Energy, Inc. and Certain Stockholders of NRG Energy, Inc. set forth therein.(21) | ||
10 | .18 | Terms and Conditions of Sale, dated as of October 5, 2005, between Texas Genco II LP and Freight Car America, Inc., (including the Proposal Letter and Amendment thereto) (portions of this document have been omitted pursuant to a request for confidential treatment and filed separately with the SEC).(25) | ||
10 | .19* | Employment Agreement, dated March 3, 2006, between NRG Energy, Inc. and David Crane.(25) | ||
10 | .20* | CEO and CFO Compensation Table.(30) | ||
10 | .21* | NRG Energy, Inc. Director Compensation Table.(24) | ||
10 | .22 | Limited Liability Company Agreement of NRG Common Stock Finance I LLC.(27) | ||
10 | .23 | Limited Liability Company Agreement of NRG Common Stock Finance II LLC.(27) | ||
10 | .24 | Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse International and Credit Suisse Securities (USA) LLC.(27) | ||
10 | .25 | Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit Suisse International and Credit Suisse Securities (USA) LLC, as agent.(27) | ||
10 | .26 | Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(27) | ||
10 | .27 | Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(27) | ||
10 | .28 | Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance I LLC.(27) | ||
10 | .29 | Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance II LLC.(27) | ||
10 | .30 | Second Amended and Restated Credit Agreement, dated June 8, 2007, by and among NRG Energy, Inc., the lenders party thereto, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Citicorp North America Inc. and Credit Suisse.(32) | ||
10 | .31 | Credit Agreement dated June 8, 2007 by and among NRG Holdings, Inc., the lenders party thereto, Credit Suisse Securities (USA) LLC, Credit Suisse and Citigroup Global Markets Inc.(32) | ||
10 | .32* | Amended and Restated Long-Term Incentive Plan, dated December 8, 2006.(31) | ||
10 | .33* | Named Executive Officer Compensation.(1) | ||
10 | .34* | NRG Energy, Inc. Executive and Key ManagementChange-in-Control and General Severance Agreement, dated May 24, 2006.(31) | ||
12 | .1 | NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges.(1) | ||
12 | .2 | NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements.(1) |
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21 | Subsidiaries of NRG Energy. Inc.(1) | |||
23 | .1 | Consent of KPMG LLP.(1) | ||
31 | .1 | Rule 13a-14(a)/15d-14(a) certification of David W. Crane.(1) | ||
31 | .2 | Rule 13a-14(a)/15d-14(a) certification of Robert C. Flexon.(1) | ||
31 | .3 | Rule 13a-14(a)/15d-14(a) certification of Carolyn J. Burke.(1) | ||
32 | Section 1350 Certification.(1) |
* | Exhibit relates to compensation arrangements. | |
(1) | Filed herewith. | |
(2) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 16, 2004. | |
(3) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 31, 2003. | |
(4) | Incorporated herein by reference to NRG Energy Inc.’s Registration Statement onForm S-1, as amended, RegistrationNo. 333-33397. | |
(5) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 19, 2003. | |
(6) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 27, 2004. | |
(7) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 27, 2004. | |
(8) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended September 30, 2004. | |
(9) | Incorporated herein by reference to NRG Energy, Inc.’s 2004 proxy statement on Schedule 14A filed on July 12, 2004. | |
(10) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended March 31, 2004. | |
(11) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on October 3, 2005. | |
(12) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended June 30, 2005. | |
(13) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on January 4, 2006. | |
(14) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 28, 2005. | |
(15) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 30, 2005. | |
(16) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 24, 2005. | |
(17) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 11, 2005. | |
(18) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 3, 2005. | |
(19) | Incorporated herein by reference to NRG Energy, Inc.’sForm 8-A filed on January 27, 2006. | |
(20) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on February 6, 2006. | |
(21) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on February 8, 2006. | |
(22) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on March 16, 2006. | |
(23) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 3, 2006. | |
(24) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 4, 2006. | |
(25) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 7, 2006. | |
(26) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on August 4, 2006. | |
(27) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 10, 2006. | |
(28) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 14, 2006. |
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(29) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 27, 2006. | |
(30) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 26, 2007. | |
(31) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on May 2, 2007. | |
(32) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on June 13, 2007. | |
(33) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on July 20, 2007. | |
(34) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on September 4, 2007. |
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