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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, 2006. | ||
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 |
Class | Outstanding at February 23, 2007 | |||
Common Stock, par value $0.01 per share | 122,335,466 |
2 | ||||||||
7 | ||||||||
— | Business | 7 | ||||||
— | Risk Factors | 41 | ||||||
— | Unresolved Staff Comments | 54 | ||||||
— | Properties | 54 | ||||||
— | Legal Proceedings | 57 | ||||||
— | Submission of Matters to a Vote of Security Holders | 61 | ||||||
61 | ||||||||
— | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 61 | ||||||
— | Selected Financial Data | 64 | ||||||
— | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 67 | ||||||
— | Quantitative and Qualitative Disclosures about Market Risk | 115 | ||||||
— | Financial Statements and Supplementary Data | 119 | ||||||
— | Changes in and Disagreements with Accountants on Accounting and Financial Disclosures | 119 | ||||||
— | Controls and Procedures | 119 | ||||||
— | Other Information | 120 | ||||||
120 | ||||||||
— | Directors and Executive Officers of the Registrant | 120 | ||||||
— | Executive Compensation | 120 | ||||||
— | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 120 | ||||||
— | Certain Relationships and Related Transactions | 120 | ||||||
— | Principal Accountant Fees and Services | 120 | ||||||
121 | ||||||||
— | Exhibits and Financial Statement Schedules | 121 | ||||||
218 | ||||||||
EX-10.38: NEO 2006 AIP PAYOUT AND 2007 BASE SALARY TABLE | ||||||||
EX-10.39: NRG ENERGY, INC. EXECUTIVE AND KEY MANAGEMENT CHANGE-IN-CONTROL AND GENERAL SEVERANCE PLAN | ||||||||
EX-12.1: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES | ||||||||
EX-12.2: COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDEND REQUIREMENTS | ||||||||
EX-21: SUBSIDIARIES OF NRG ENERGY INC | ||||||||
EX-23.1: CONSENT OF KPMG LLP | ||||||||
EX-31.1: CERTIFICATION | ||||||||
EX-31.2: CERTIFICATION | ||||||||
EX-31.3: CERTIFICATION | ||||||||
EX-32: CERTIFICATION |
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ABWR | Advanced Boiling Water Reactor | |
Acquisition | February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Company’s Texas region | |
Acquisition Agreement | Acquisition Agreement dated September 30, 2005 underlying the February 2, 2006 acquisition of 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 | |
BACT | Best Available Control Technology | |
BART | Best Available Retrofit Technology | |
Baseload capacity | Electric power generation capacity normally expected to serve loads on anaround-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 entered into August 2006 | |
CDWR | California Department of Water Resources | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act | |
CL&P | Connecticut Light & Power | |
CO2 | Carbon dioxide | |
CPUC | California Public Utilities Commission | |
Derate | A derate exists whenever a generating unit is not capable of operating at its tested dependable maximum net capability | |
DNREC | Delaware Department of Natural Resources and Environmental Control | |
EAF | The total available hours a unit is available in a year minus the sum of all partial outage events in a year converted to equivalent hours, expressed as a percent of all hours in the year | |
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 | |
EITF 02-3 | 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 |
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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 | |
FERC | Federal Energy Regulatory Commission | |
FGD | Flue Gas Desulphurization | |
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 | |
Hg | Mercury | |
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 | |
LADEQ | Louisiana Department of Environmental Quality | |
LFRM | Locational Factor Reserve Market | |
LIBOR | London Inter-Bank Offered Rate | |
LNB/OFA | Low NOx Burner with Over Fire Air | |
LSE | Load-Serving Entity | |
MACT | Maximum Achievable Control Technology | |
MADEP | Massachusetts Department of Environmental Protection | |
MDL | Multi-District Litigation | |
Merit Order | A term used for the ranking of power stations in terms of increasing order of fuel costs | |
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 |
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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, 2006 | |
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 | |
PM(2.5) | Fine particulate matter | |
PMI | NRG Power Marketing, Inc., a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manage, 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 | |
RCRA | Resource Conservation and Recovery Act | |
RECLAIM | Regional Clean Air Incentives Market | |
Repowering NRG | 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 | |
RFP | Request for proposal | |
RGGI | Regional Greenhouse Gas Initiative |
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RMR | Reliability Must-Run | |
ROIC | Return on invested capital | |
RTC | RECLAIM Trading Credit | |
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 | |
SCAQMD | South Coast Air Quality Management District | |
Schkopau | Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which NRG has a 41.9% interest | |
SCR | Selective Catalytic Reduction | |
SDG&E | San Diego Gas & Electric | |
SEC | United States Securities and Exchange Commission | |
Sellers | Former holders of Texas Genco LLC shares | |
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” | |
SFAS 123R | SFAS No. 123 (revised 2004),“Share-Based Payment” | |
SFAS 133 | SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities” | |
SFAS 137 | SFAS No. 137,“Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133” | |
SFAS 138 | SFAS No. 138,“Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of FASB Statement No. 133” | |
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 149 | SFAS No. 149,“Amendment of Statement 133 on Derivative Instruments and Hedging Activities” | |
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)” | |
SFAS 159 | SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115” | |
SNCR | Selective non-catalytic reduction | |
SIP | State Implementation Plan | |
SO2 | Sulfur dioxide |
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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” | |
SPP | Southwest Power Pool | |
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 | |
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 | |
Virtual Units | Products sold with scheduling characteristics for energy and ancillary services that are based on an underlying unit physical characteristic | |
VOC | Volatile Organic Carbon | |
WCP | WCP (Generation) Holdings, Inc. |
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Risk | Total | |||||||||||||||||||||||||||||||
Energy | Capacity | Management | Contract | Thermal | Hedge | Other | Operating | |||||||||||||||||||||||||
Region | Revenues | Revenues | Activities | Amortization | Revenues | Reset | Revenues(c) | Revenues | ||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Texas(a) | $ | 1,726 | $ | 849 | $ | (30 | ) | $ | 609 | $ | — | $ | (129 | ) | $ | 63 | $ | 3,088 | ||||||||||||||
Northeast | 966 | 321 | 144 | — | — | — | 112 | 1,543 | ||||||||||||||||||||||||
South Central | 334 | 199 | 13 | 19 | — | — | 5 | 570 | ||||||||||||||||||||||||
West(b) | 75 | 68 | (3 | ) | — | — | — | 6 | 146 | |||||||||||||||||||||||
International | 80 | 79 | — | — | — | — | 14 | 173 | ||||||||||||||||||||||||
Thermal | 12 | — | — | — | 124 | — | 16 | 152 | ||||||||||||||||||||||||
Corporate/Eliminations | — | — | — | — | — | — | (49 | ) | (49 | ) | ||||||||||||||||||||||
Total | $ | 3,193 | $ | 1,516 | $ | 124 | $ | 628 | $ | 124 | $ | (129 | ) | $ | 167 | $ | 5,623 | |||||||||||||||
(a) | For the period February 2, 2006 — December 31, 2006. |
(b) | Includes fully consolidated results of WCP for the period April 1, 2006 — December 31, 2006. |
(c) | Includes operations and maintenance fees, sale of natural gas, sale of emission allowances, and revenues from ancillary services. |
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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(a) | 10,760 | 44,910 | 91.0 | % | 10,300 | 41.0 | % | |||||||||||||
Northeast(b) | 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 | % |
Year Ended December 31, 2005 | ||||||||||||||||||||
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) | ||||||||||||||||||||
Northeast(b) | 7,099 | 16,246 | 87.2 | % | 11,146 | 22.9 | % | |||||||||||||
South Central | 2,395 | 10,009 | 90.9 | 10,518 | 50.6 | |||||||||||||||
West(d) | 1,044 | 1,794 | 86.5 | % | 11,109 | 18.0 | % |
(a) | For the period February 2, 2006 through December 31, 2006. |
(b) | Factor data and heat rate does not include the Keystone and Conemaugh facilities. |
(c) | Includes fully consolidated results of WCP for the period April 1, 2006 — December 31, 2006. |
(d) | Includes 50% of the generation owned through NRG’s WCP partnership. |
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Annual | ||||||||||||||||||||||||||||
Average for | ||||||||||||||||||||||||||||
2007 | 2008 | 2009 | 2010 | 2011 | 2012 | 2007-2012 | ||||||||||||||||||||||
(In millions unless otherwise stated) | ||||||||||||||||||||||||||||
Net Baseload Capacity (MW) | 8,800 | 8,730 | 8,730 | 8,621 | 8,621 | 8,621 | 8,687 | |||||||||||||||||||||
Forecasted Baseload Capacity (MW) | 7,493 | 7,394 | 7,358 | 7,305 | 7,208 | 7,269 | 7,338 | |||||||||||||||||||||
Total Baseload Sales (MW)(a) | 7,263 | 6,105 | 5,370 | 4,334 | 4,679 | 1,767 | 4,920 | |||||||||||||||||||||
Percentage Baseload Capacity Sold Forward(b) | 97 | % | 83 | % | 73 | % | 59 | % | 65 | % | 24 | % | 67 | % | ||||||||||||||
Total Forward Hedged Revenues(c)(d) | $ | 3,582 | $ | 2,803 | $ | 2,524 | $ | 1,931 | $ | 1,934 | $ | 617 | $ | 2,232 | ||||||||||||||
Weighted Average Hedged Price ($ per MWh)(c) | $ | 56 | $ | 52 | $ | 54 | $ | 51 | $ | 47 | $ | 40 | $ | 50 | ||||||||||||||
Weighted Average Hedged Price ($ per MWh) excluding South Central region(d) | $ | 61 | $ | 57 | $ | 59 | $ | 56 | $ | 51 | $ | 49 | $ | 56 |
(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, 2006 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 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 $33/MWh — $35/MWh due to legacy cooperative load contracts entered into at prices significantly below current market levels. | |
(e) | Includes contracted revenues subject to hedge accounting,market-to-market, and normal purchases and normal sales accounting treatment. |
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Closing | Gain/(Loss) | Debt | ||||||||||||||||
Asset | Type | Segment(b) | Date | Proceeds | on Disposition | Reduction | ||||||||||||
(In millions) | ||||||||||||||||||
Rocky Road | Equity investment | Corporate | 03/31/06 | $ | 45 | $ | — | $ | — | |||||||||
Audrain(a) | Discontinued operation | Corporate | 03/29/06 | 115 | 15 | 240 | ||||||||||||
Cadillac | Equity investment | Corporate | 04/13/06 | 11 | 11 | — | ||||||||||||
James River | Equity investment | Corporate | 05/15/06 | 8 | (6 | ) | — | |||||||||||
Latin American Funds | Equity investment | International | 06/30/06 | 23 | 3 | — | ||||||||||||
Flinders | Discontinued operation | International | 08/30/06 | 242 | 60 | 183 | ||||||||||||
Resource Recovery | Discontinued operation | Corporate | 11/08/06 | 22 | 5 | — | ||||||||||||
Total | $ | 466 | $ | 88 | $ | 423 | ||||||||||||
(a) | Of the $115 million in cash proceeds, approximately $20 million was paid to NRG with the balance paid to the lenders of NRG Financial Company I LLC. | |
(b) | Reflects realignment of the Company’s business segments during the fourth quarter 2006. |
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Fuel-type | MW | |||
Gas | 4,050 | |||
Nuclear | 2,700 | |||
Coal Gasification, or IGCC | 1,500 | |||
Solid Fuel | 1,800 | |||
Wind | 300 | |||
Total | 10,350 | |||
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Texas | Northeast | South Central | Other | Total | ||||||||||||||||
(In millions) | ||||||||||||||||||||
2007 | $ | 9 | $ | 118 | $ | 40 | $ | 10 | $ | 177 | ||||||||||
2008 | 16 | 183 | 92 | 10 | 301 | |||||||||||||||
2009 | 19 | 183 | 167 | 5 | 374 | |||||||||||||||
2010 | 26 | 144 | 86 | 4 | 260 | |||||||||||||||
2011 | 19 | 30 | 64 | 1 | 114 | |||||||||||||||
2012 | 13 | 3 | 34 | — | 50 | |||||||||||||||
Total | $ | 102 | $ | 661 | $ | 483 | $ | 30 | $ | 1,276 | ||||||||||
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Net Generation | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In thousands of MWh) | ||||||||||||
Coal | 31,371 | 31,299 | 31,222 | |||||||||
Gas | 7,983 | 6,806 | 7,701 | |||||||||
Nuclear(a) | 9,385 | 6,412 | 6,580 | |||||||||
Total | 48,739 | 44,517 | 45,503 | |||||||||
(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 | ||||||||||
Plant | Location | % Owned | (MW)(c) | Primary Fuel-type | ||||||
Solid Fuel Baseload Units: | ||||||||||
W. A. Parish(a) | Thompsons, TX | 100.0 | 2,480 | Coal | ||||||
Limestone | Jewett, TX | 100.0 | 1,700 | Lignite/Coal | ||||||
South Texas Project(b) | Bay City, TX | 44.0 | 1,100 | Nuclear | ||||||
Total Solid Fuel Baseload | 5,280 | |||||||||
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 (Natural gas)(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 | 10,760 | |||||||||
(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 of 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 2,970 MW of mothballed capacity available for redevelopment. |
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Facility | Fuel-type | Technology | ||
Cedar Bayou | Gas | Simple/Combined Cycle | ||
Limestone — unit 3 | Coal | Pulverized Coal | ||
STP — Units 3&4 | Nuclear | ABWR | ||
Wind Power | Wind | Wind turbines |
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Net Generation | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In thousands of MWh) | ||||||||||||
Coal | 11,042 | 11,363 | 11,694 | |||||||||
Oil | 1,217 | 3,148 | 1,429 | |||||||||
Gas | 1,050 | 1,735 | 1,136 | |||||||||
Total | 13,309 | 16,246 | 14,259 | |||||||||
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Net | ||||||||||
Generation | ||||||||||
Plant | Location | % Owned | Capacity(a) | Primary 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 | 780 | Coal | ||||||
Astoria Gas Turbines | Queens, NY | 100.0 | 550 | Natural Gas | ||||||
Huntley | Tonawanda, NY | 100.0 | 550 | Coal | ||||||
Dunkirk | Dunkirk, NY | 100.0 | 585 | 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 | 60 | Coal | ||||||
Total Northeast Region | 7,240 | |||||||||
(a) | Excludes 365 MW of inactive capacity. |
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Facility | Fuel-type | Technology | ||
Huntley | Coal | IGCC | ||
Indian River | Coal | IGCC | ||
Montville | Gas/Oil | Combined Cycle Gas Turbine | ||
Middletown | Gas/Oil | Gas Peakers | ||
Devon | Gas/Oil | Gas Peakers |
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Net Generation | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In thousands of MWh) | ||||||||||||
Coal | 10,968 | 9,924 | 10,353 | |||||||||
Gas | 68 | 85 | 8 | |||||||||
Total | 11,036 | 10,009 | 10,361 | |||||||||
Net | ||||||||||
Generation | ||||||||||
Capacity | ||||||||||
Plant | Location | % Owned | (MW) | Primary Fuel-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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Facility | Fuel-type | Technology | ||
Big Cajun-II — Unit 4 | Coal | Pulverized Coal (BACT) | ||
Big Cajun-I | Pet coke/Coal | Fluidized Bed Boiler |
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Net | ||||||||||
Generation | ||||||||||
Capacity | ||||||||||
Plant | Location | % Owned | (MW) | Primary Fuel-type | ||||||
Encina | Carlsbad, CA | 100.0 | 965 | Natural Gas | ||||||
El Segundo | El Segundo, CA | 100.0 | 670 | Natural Gas | ||||||
Cabrillo II | San Diego, CA | 100.0 | 190 | Natural Gas | ||||||
Red Bluff(a) | Northern CA | 100.0 | 45 | Natural Gas | ||||||
Chowchilla(a) | Northern CA | 100.0 | 50 | Natural Gas | ||||||
Saguaro | Henderson, NV | 50.0 | 45 | Natural Gas | ||||||
Total West Region | 1,965 | |||||||||
(a) | Sold on January 3, 2007 |
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Facility | Fuel-type | Technology | ||
Long Beach | Gas | Simple Cycle Gas Turbine | ||
Long Beach Repower | Gas | Combined Cycle Gas Turbine | ||
Encina Peakers | Gas | Simple Cycle Gas Turbine | ||
El Segundo 1&2 | Gas | Combined Cycle Gas Turbine | ||
Wind Power — California | Wind | Wind turbines | ||
El Segundo 3&4 | Gas | Combined Cycle Gas Turbine |
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Net | ||||||||||
Generation | ||||||||||
Plant | Location | % Owned | Capacity | Primary Fuel-type | ||||||
Gladstone | Australia | 37.5 | 605 | Coal | ||||||
Schkopau | Germany | 41.9 | 400 | Lignite | ||||||
MIBRAG | Germany | 50.0 | 75 | Lignite | ||||||
ITISA | Brazil | 99.2 | 155 | Hydro | ||||||
Total International | 1,235 | |||||||||
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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; | |
• | work stoppages; | |
• | labor disputes; | |
• | weather interferences; | |
• | unforeseen engineering, environmental and geological problems; | |
• | unanticipated cost overruns; 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 | |
• | 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. |
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• | 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; | |
• | Price mitigation strategies and other market structures employed by independent system operators, or ISO, 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; and | |
• | NRG’s ability to implement itsRepowering NRGstrategy of developing and building new power generation facilities, including new nuclear units and IGCC units. |
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Net | ||||||||
Purchaser/Power | Generation | |||||||
Name and Location of Facility | Market | % Owned | Capacity | Primary Fuel-type | ||||
Texas Region: | ||||||||
W. A. Parish, Thompsons, Texas | ERCOT | 100.0 | 2,480 | Coal | ||||
Limestone, Jewett, Texas | ERCOT | 100.0 | 1,700 | Lignite/Coal | ||||
South Texas Project, Bay City, Texas(a) | ERCOT | 44.0 | 1,100 | 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 | 780 | Coal | ||||
Astoria Gas Turbines, Queens, New York | NYISO | 100.0 | 550 | Natural Gas | ||||
Dunkirk, New York | NYISO | 100.0 | 585 | Coal | ||||
Huntley, Tonawanda, New York | NYISO | 100.0 | 550 | 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 | ||||
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 | 60 | Coal |
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Net | ||||||||
Purchaser/Power | Generation | |||||||
Name and Location of Facility | Market | % Owned | Capacity | Primary Fuel-type | ||||
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 | ||||
Chowchilla, California(c) | Cal ISO | 100.0 | 50 | Natural Gas | ||||
Red Bluff, California(c) | Cal ISO | 100.0 | 45 | Natural Gas | ||||
Saguaro Power Co., Henderson, Nevada | WECC | 50.0 | 45 | 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(d) | ENVIA/MIBRAG Mines | 50.0 | 75 | Lignite | ||||
ITISA, Brazil | COPEL | 99.2 | 155 | Hydro | ||||
Corporate | ||||||||
Power Smith Cogeneration, Oklahoma City, Oklahoma | SPP | 6.25 | 7 | Natural Gas |
(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) | Sold January 2, 2007 | |
(d) | Primarily a coal mining facility |
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% | ||||||
Ownership | ||||||
Name and Location of Facility | Thermal Energy Purchaser | Interest | Generating Capacity(a) | |||
NRG Energy Center Minneapolis, MN | Approx. 100 steam customers and 47 chilled water customers | 100.0 | Steam: 1,203 MMBtu/hr. (353 MWt) Chilled Water: 42,630 tons (150 MWt) | |||
NRG Energy Center San Francisco, CA | Approx. 175 steam customers | 100.0 | Steam: 482 MMBtu/Hr. (141 MWt) | |||
NRG Energy Center Harrisburg, PA | Approx. 250 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, PA | 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, CA | Approx. 20 chilled water customers | 100.0 | Chilled water: 7,425 tons (26 MWt) | |||
NRG Energy Center St. Paul, MN | Rock-Tenn Company | 100.0 | Steam: 430 MMBtu/hr. (126 MWt) | |||
Camas Power Boiler, Camas, WA | Georgia-Pacific Corp. | 100.0 | Steam: 200 MMBtu/hr. (59 MWt) | |||
NRG Energy Center Dover, DE | Kraft Foods Inc. | 100.0 | Steam: 190 MMBtu/hr. (56 MWt) | |||
NRG Energy Center Oak Park Heights, MN | Anderson Corp., MN Correctional Facility | 100.0 | Steam: 200 MMBtu/Hr. (59 MWt) | |||
Paxton Creek Cogeneration, Harrisburg, PA | PJM | 100.0 | 12 MW — Natural Gas | |||
Dover, DE | PJM | 100.0 | 106 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 |
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 | |||||||||||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | |||||||||||||||||||||||||
Common Stock Price | 2006 | 2006 | 2006 | 2006 | 2005 | 2005 | 2005 | 2005 | ||||||||||||||||||||||||
High | $ | 59.48 | $ | 51.15 | $ | 52.61 | $ | 49.46 | $ | 49.44 | $ | 44.45 | $ | 37.61 | $ | 39.10 | ||||||||||||||||
Low | $ | 44.27 | $ | 44.25 | $ | 42.44 | $ | 41.79 | $ | 37.60 | $ | 36.40 | $ | 30.30 | $ | 32.79 | ||||||||||||||||
Closing | $ | 56.01 | $ | 45.30 | $ | 48.18 | $ | 45.22 | $ | 47.12 | $ | 42.60 | $ | 37.60 | $ | 34.15 |
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Total Number | ||||||||||||||||
of Shares | Dollar Value | |||||||||||||||
Purchased as | of Shares That | |||||||||||||||
Total Number | Average Price | Part of Publicly | May be Purchased | |||||||||||||
of Shares | Paid per | Announced Plans | Under the Plans | |||||||||||||
For the Year Ended December 31, 2006 | Purchased | Share | or Programs | or Programs | ||||||||||||
First quarter | — | — | — | — | ||||||||||||
Second quarter | — | — | — | — | ||||||||||||
July 1 – July 31 | — | — | — | — | ||||||||||||
August 1 – August 31 | — | — | — | $ | 500,000,000 | |||||||||||
September 1 – September 30 | 6,113,000 | $ | 48.61 | 6,113,000 | 202,847,070 | |||||||||||
Third quarter total | 6,113,000 | 48.61 | 6,113,000 | — | ||||||||||||
October 1 – October 31 | 4,474,700 | 45.32 | 4,474,700 | 500,053,666 | ||||||||||||
November 1 – November 30 | 4,212,881 | 55.00 | 4,212,881 | 268,345,211 | ||||||||||||
December 1 – December 31 | — | — | — | — | ||||||||||||
Fourth quarter total | 8,687,581 | 50.01 | 8,687,581 | 268,345,211 | ||||||||||||
Total for 2006 | 14,800,581 | $ | 49.43 | 14,800,581 | $ | 268,345,211 | ||||||||||
(a) | (b) | (c) | ||||||||||
Number of Securities | ||||||||||||
Remaining Available | ||||||||||||
Number of Securities | 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 | 3,395,413 | $ | 24.22 | 4,301,489(a | ) | |||||||
Equity compensation plans not approved by security holders | — | N/ | A | — | ||||||||
Total | 3,395,413 | $ | 24.22 | 4,301,489(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 8,000,000 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. |
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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 4,301,489 and 1,355,193 shares of common stock remaining available for grants of awards under NRG’s LTIP as of December 31, 2006 and 2005, respectively. |
![](https://capedge.com/proxy/10-K/0000950123-07-002952/y30985y3098503.gif)
1/04 | 3/04 | 6/04 | 9/04 | 12/04 | 3/05 | 6/05 | 9/05 | 12/05 | 3/06 | 6/06 | 9/06 | 12/06 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
NRG | $ | 100 | $ | 98.89 | $ | 110.47 | $ | 120.00 | $ | 160.58 | $ | 152.12 | $ | 167.48 | $ | 189.76 | $ | 209.89 | $ | 201.43 | $ | 214.61 | $ | 201.78 | $ | 249.49 | |||||||||||||||||||||||||||||||||||||||
S&P 500 | 100 | 101.69 | 103.44 | 101.50 | 110.88 | 108.50 | 109.98 | 113.95 | 116.33 | 121.22 | 119.48 | 126.25 | 134.70 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
UTY | $ | 100 | $ | 105.95 | $ | 104. 20 | $ | 111.74 | $ | 126.23 | $ | 133.97 | $ | 145.94 | $ | 157.53 | $ | 149.50 | $ | 146.70 | $ | 155.86 | $ | 165.24 | $ | 179.67 | |||||||||||||||||||||||||||||||||||||||
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Reorganized NRG | Predecessor Company | ||||||||||||||||||||||||
December 6 - | January 1 - | Year Ended | |||||||||||||||||||||||
Year Ended December 31, | December 31, | December 5, | December 31, | ||||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2003 | 2002 | ||||||||||||||||||||
(In millions except ratio and per share data) | |||||||||||||||||||||||||
Statement of income data: | |||||||||||||||||||||||||
Total operating revenues | $ | 5,623 | $ | 2,430 | $ | 2,104 | $ | 121 | $ | 1,589 | $ | 1,688 | |||||||||||||
Total operating costs and expenses | 4,743 | 2,311 | 1,875 | 110 | (1,603 | ) | 4,544 | ||||||||||||||||||
Income/(loss) from continuing operations, net | 555 | 72 | 155 | 12 | 3,131 | (2,697 | ) | ||||||||||||||||||
Income/(loss) from discontinued operations, net | 66 | 12 | 31 | (1 | ) | (365 | ) | (767 | ) | ||||||||||||||||
Net income/(loss) | 621 | 84 | 186 | 11 | 2,766 | (3,464 | ) | ||||||||||||||||||
Common share data: | |||||||||||||||||||||||||
Basic shares outstanding — average | 129 | 85 | 100 | 100 | |||||||||||||||||||||
Diluted shares outstanding — average | 150 | 85 | 100 | 100 | |||||||||||||||||||||
Shares outstanding — end of year | 122 | 81 | 87 | 100 | |||||||||||||||||||||
Per share data: | |||||||||||||||||||||||||
Income from continuing operations — basic | 3.90 | 0.61 | 1.55 | 0.12 | |||||||||||||||||||||
Income from continuing operations — diluted | 3.63 | 0.61 | 1.54 | 0.12 | |||||||||||||||||||||
Net income — basic | 4.41 | 0.76 | 1.86 | 0.11 | |||||||||||||||||||||
Net income — diluted | 4.07 | 0.75 | 1.85 | 0.11 | |||||||||||||||||||||
Book value | 38.96 | 22.61 | 26.26 | 24.37 |
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Reorganized NRG | Predecessor Company | ||||||||||||||||||||||||
December 6 - | January 1 - | Year Ended | |||||||||||||||||||||||
Year Ended December 31, | December 31, | December 5, | December 31, | ||||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2003 | 2002 | ||||||||||||||||||||
(In millions except ratio and per share data) | |||||||||||||||||||||||||
Business metrics: | |||||||||||||||||||||||||
Cash flow from operations | 408 | 68 | 645 | (589 | ) | 238 | 430 | ||||||||||||||||||
Liquidity position | $ | 2,227 | $ | 758 | $ | 1,600 | $ | 1,545 | N/ | A | N/ | A | |||||||||||||
Ratio of earnings to fixed charges | 2.38 | 1.56 | 1.88 | 1.71 | 11.61 | (5.17 | ) | ||||||||||||||||||
Ratio of earnings to fixed charges and preference dividends | 2.10 | 1.33 | 1.88 | 1.71 | 11.61 | (5.17 | ) | ||||||||||||||||||
Return on equity | 10.98 | 3.77 | 6.91 | N/ | A | N/ | A | N/ | A | ||||||||||||||||
Ratio of debt to total capitalization | 57.48 | 44.82 | 44.99 | 56.09 | N/ | A | N/ | A | |||||||||||||||||
Balance sheet data: | |||||||||||||||||||||||||
Current assets | $ | 3,083 | $ | 2,196 | $ | 2,121 | $ | 2,186 | N/ | A | $ | 1,584 | |||||||||||||
Current liabilities | 2,032 | 1,357 | 1,091 | 2,098 | N/ | A | 9,865 | ||||||||||||||||||
Property, plant and equipment, net | 11,600 | 2,609 | 2,685 | 3,315 | N/ | A | 5,196 | ||||||||||||||||||
Total assets | 19,435 | 7,466 | 7,873 | 9,320 | N/ | A | 10,964 | ||||||||||||||||||
Long-term debt, including current maturities and capitol leases | 8,777 | 2,505 | 3,271 | 3,648 | N/ | A | 7,117 | ||||||||||||||||||
Total stockholders’ equity/(deficit) | $ | 5,658 | $ | 2,231 | $ | 2,692 | $ | 2,437 | N/ | A | $ | (696 | ) | ||||||||||||
Reorganized NRG | Predecessor Company | ||||||||||||||||||||||||
December 6 - | January 1 - | Year Ended | |||||||||||||||||||||||
Year Ended December 31, | December 31, | December 5, | December 31, | ||||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2003 | 2002 | ||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||
Energy | $ | 3,193 | $ | 1,870 | $ | 1,205 | $ | 53 | $ | 788 | $ | 1,028 | |||||||||||||
Capacity | 1,516 | 563 | 612 | 37 | 566 | 553 | |||||||||||||||||||
Risk management activities | 124 | (292 | ) | 61 | — | 19 | 7 | ||||||||||||||||||
Contract amortization | 628 | 9 | (6 | ) | 13 | — | — | ||||||||||||||||||
Thermal | 124 | 124 | 112 | 9 | 24 | 30 | |||||||||||||||||||
Hedge Reset | (129 | ) | — | — | — | — | — | ||||||||||||||||||
Other | 167 | 156 | 120 | 9 | 192 | 70 | |||||||||||||||||||
Total operating revenues | $ | 5,623 | $ | 2,430 | $ | 2,104 | $ | 121 | $ | 1,589 | $ | 1,688 | |||||||||||||
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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 known trends 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; | |
• | Known trends that will affect NRG’s results of operations in the future; 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. Generally, the Company’s targeted net debt to total capital ratio range is 45% to 60%. 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 either through dividends or share repurchases to shareholders. | |
• | Repowering Opportunities — The Company intends to pursue repowering initiatives that enhance and diversify its portfolio and provide a targeted economic return to the Company. |
• | Initiation of a portfolio repowering effort to add approximately 10,350 MW of new multi-fuel, multi-technology generation capacity at NRG’s existing domestic sites to meet growing demand in all of the Company’s core domestic markets. | |
• | Continued share repurchases through the Company’s Capital Allocation Program. | |
• | Increasing the baseload hedge profile to 59% in 2010, 65% in 2011 and 24% in 2012, to provide certainty around the Company’s future cash flows. |
• | Reset legacy Texas region long-termout-of-market power contracts and gas swaps by negotiating to current market price levels resulting in a reduction in operating income of $135 million. |
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• | Total generation increased by 154% primarily due to the addition of the Texas region to the NRG total portfolio. | |
• | Improved operating performance and new tolling agreements contributed to $97 million of higher operating income from the South Central region. | |
• | A mild winter and summer coupled with weak power prices lowered generation demand for the Northeast region’s generation assets by 18%. | |
• | NRG recorded $187 million in refinancing costs and $599 million in interest expense primarily due to new debt facilities associated with the acquisition of NRG Texas. | |
• | Record peak energy demand in each of the market’s served by NRG’s major business segments ranging with increases of 4% to 11% over previous records. | |
• | Recognized $124 million in gains from risk management activities. |
• | On February 2, 2006, NRG acquired Texas Genco LLC. Texas Genco LLC and its affiliates are now wholly-owned subsidiaries of NRG, and is managed and accounted for as a separate business segment referred to as Texas region. | |
• | On August 30, 2006, NRG announced the completion of the sale of its 100% owned Flinders power station and related assets. NRG received approximately $242 million in cash and recognized an after-tax gain on the sale of approximately $60 million. | |
• | On March 31, 2006, NRG acquired Dynegy’s 50% ownership interest in WCP, and became the sole owner of WCP’s 1,825 MW of generation in Southern California. The results of operations of WCP were consolidated as of April 1, 2006, prior to which, NRG’s 50% ownership of WCP was recorded as an equity method investment. | |
• | On November 8, 2006, NRG completed the sale of its Newport and Elk River Resource Recovery facilities, its Becker Ash Disposal facility as well as its ownership in NRG Processing Solutions, LLC, to Resource Recovery Technologies, LLC for approximately $22 million. The Company recognized a gain of approximately $5 million. |
• | On January 31, 2006, NRG finalized a settlement agreement with an equipment manufacturer related to certain turbine purchase agreements. Upon finalization of the settlement, NRG recorded a total of $67 million of other income, of which $35 million was related to the discharge of accounts payable previously recorded and $32 million was related to the receiving and recording of the equipment at fair value. | |
• | Incurred approximately $36 million in development costs primarily related toRepowering NRGprogram. |
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Year Ended December 31, | ||||||||||||
2006 | 2005 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 3,193 | $ | 1,870 | 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 | 5,623 | �� | 2,430 | 131 | ||||||||
Operating Costs and Expenses | ||||||||||||
Cost of operations | 3,276 | 1,838 | 78 | |||||||||
Depreciation and amortization | 593 | 162 | 266 | |||||||||
General, administrative and development | 316 | 181 | 75 | |||||||||
Impairment charges | — | 6 | NA | |||||||||
Corporate relocation charges | — | 6 | NA | |||||||||
Total operating costs and expenses | 4,185 | 2,193 | 91 | |||||||||
Operating Income | 1,438 | 237 | 507 | |||||||||
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 | 160 | 58 | 176 | |||||||||
Refinancing expenses | (187 | ) | (65 | ) | 188 | |||||||
Interest expense | (599 | ) | (184 | ) | 226 | |||||||
Total other expenses | (558 | ) | (118 | ) | 373 | |||||||
Income from Continuing Operations before income tax expense | 880 | 119 | 639 | |||||||||
Income tax expense | 325 | 47 | 591 | |||||||||
Income from Continuing Operations | 555 | 72 | 671 | |||||||||
Income from discontinued operations, net of income tax expense | 66 | 12 | 450 | |||||||||
Net Income | $ | 621 | $ | 84 | 639 | |||||||
Business Metrics | ||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | 6.75 | 8.89 | (24 | )% |
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Year Ended December 31, | ||||||||||||||||||||
2006 | 2005 | |||||||||||||||||||
Total excluding | ||||||||||||||||||||
Consolidated | Texas Region | WCP | Texas Region/WCP | Consolidated | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Energy revenue | $ | 3,193 | $ | 1,726 | $ | 72 | $ | 1,395 | $ | 1,870 | ||||||||||
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 | 5,623 | 3,088 | 141 | 2,394 | 2,430 | |||||||||||||||
Cost of operations | 3,276 | 1,669 | 112 | 1,495 | 1,838 | |||||||||||||||
Depreciation and amortization | 593 | 413 | 2 | 178 | 162 | |||||||||||||||
General, administrative and development | 316 | 125 | 10 | 181 | 181 | |||||||||||||||
Impairment charges | — | — | — | — | 6 | |||||||||||||||
Corporate relocation charges | — | — | — | — | 6 | |||||||||||||||
Total operating costs and expenses | 4,185 | 2,207 | 124 | 1,854 | 2,193 | |||||||||||||||
Operating Income | $ | 1,438 | $ | 881 | $ | 17 | $ | 540 | $ | 237 | ||||||||||
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Year Ended December 31, 2006 | ||||||||||||||||||||
South | ||||||||||||||||||||
Texas | Northeast | Central | Other | Total | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Financial revenues | ||||||||||||||||||||
Net losses on settled positions, or financial revenues | (152 | ) | (10 | ) | (6 | ) | (3 | ) | (171 | ) | ||||||||||
Subtotal 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 | — | 90 | — | — | 90 | |||||||||||||||
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 | ||||||||||||||||
Subtotalmark-to-market results | 122 | 154 | 19 | — | 295 | |||||||||||||||
Total derivative gain/(losses) | $ | (30 | ) | $ | 144 | $ | 13 | $ | (3 | ) | $ | 124 | ||||||||
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Year Ended December 31, | ||||||||
2006 | 2005 | |||||||
(In millions except otherwise stated) | ||||||||
Income from continuing operations before income taxes | $ | 880 | $ | 119 | ||||
Tax at 35% | 308 | 42 | ||||||
State taxes, net of federal benefit | 34 | (1 | ) | |||||
Foreign operations | (23 | ) | (16 | ) | ||||
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 | ) | — | |||||
Permanent differences, reserves, other | 12 | (2 | ) | |||||
Income tax expense | $ | 325 | $ | 47 | ||||
Effective income tax rate | 36.9 | % | 39.5 | % |
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Year Ended December 31, | ||||||||||||
2005 | 2004 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 1,870 | $ | 1,205 | 55 | % | ||||||
Capacity revenue | 563 | 612 | (8 | ) | ||||||||
Thermal revenue | 124 | 112 | 11 | |||||||||
Risk management activities | (292 | ) | 61 | N/A | ||||||||
Contract amortization | 9 | (6 | ) | N/A | ||||||||
Other revenues | 156 | 120 | 30 | |||||||||
Total operating revenues | 2,430 | 2,104 | 15 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of operations | 1,838 | 1,290 | 42 | |||||||||
Depreciation and amortization | 162 | 179 | (9 | ) | ||||||||
General, administrative and development | 181 | 197 | (8 | ) | ||||||||
Impairment charges | 6 | 45 | (87 | ) | ||||||||
Reorganization charges | — | (13 | ) | N/A | ||||||||
Corporate relocation charges | 6 | 16 | (63 | ) | ||||||||
Total operating costs and expenses | 2,193 | 1,714 | 28 | |||||||||
Operating Income | 237 | 390 | (39 | ) | ||||||||
Other Income/(Expense) | ||||||||||||
Equity in earnings of unconsolidated affiliates | 104 | 160 | (35 | ) | ||||||||
Write downs and gains/(losses) on sales of equity method investments | (31 | ) | (16 | ) | 94 | |||||||
Other income, net | 58 | 22 | 164 | |||||||||
Refinancing expenses | (65 | ) | (72 | ) | (10 | ) | ||||||
Interest expense | (184 | ) | (255 | ) | (28 | ) | ||||||
Total other expenses | (118 | ) | (161 | ) | (27 | ) | ||||||
Income from Continuing Operations before income tax expense | 119 | 229 | (48 | ) | ||||||||
Income tax expense | 47 | 74 | (36 | ) | ||||||||
Income from Continuing Operations | 72 | 155 | (54 | ) | ||||||||
Income from discontinued operations, net of income tax expense | 12 | 31 | (61 | ) | ||||||||
Net Income | $ | 84 | $ | 186 | (55 | ) | ||||||
Business Metrics | ||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | 8.89 | 5.89 | 51 | % |
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Year Ended December 31, 2005 | ||||||||||||||||
South | ||||||||||||||||
Northeast | Central | Other | Total | |||||||||||||
(In millions) | ||||||||||||||||
Net losses on settled positions, or financial revenues | $ | (132 | ) | $ | (1 | ) | $ | (5 | ) | $ | (138 | ) | ||||
Mark-to-market results | ||||||||||||||||
Reversal of previously recognized unrealized gains on settled positions | (59 | ) | — | — | (59 | ) | ||||||||||
Net unrealized losses on open positions related to economic hedges | (121 | ) | (1 | ) | — | (122 | ) | |||||||||
Net unrealized gains on open positions related to trading activity | 27 | — | — | 27 | ||||||||||||
Subtotalmark-to-market results | (153 | ) | (1 | ) | — | (154 | ) | |||||||||
Total derivative loss | $ | (285 | ) | $ | (2 | ) | $ | (5 | ) | $ | (292 | ) | ||||
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Period Ended | ||||
December 31, | ||||
2006 (b) | ||||
(In millions except | ||||
otherwise noted) | ||||
Operating Revenues | ||||
Energy revenue | $ | 1,726 | ||
Capacity revenue | 849 | |||
Risk Management Activities | (30 | ) | ||
Contract amortization | 609 | |||
Hedge Reset | (129 | ) | ||
Other revenues | 63 | |||
Total operating revenues | 3,088 | |||
Operating Costs and Expenses | ||||
Cost of energy | 1,276 | |||
Depreciation and amortization | 413 | |||
Other operating expenses | 518 | |||
Operating Income | $ | 881 | ||
MWh sold (in thousands) | 46,361 | |||
MWh generated (in thousands) | 44,910 | |||
Business Metrics | ||||
Average on-peak market power prices ($/MWh) | $ | 60.96 | ||
Cooling Degree Days, or CDDs(a) | 2,891 | |||
CDD’s 30 year rolling average | 2,435 | |||
Heating Degree Days, or HDDs(a) | 1,476 | |||
HDD’s 30 year rolling average | 1,694 |
(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. |
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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 | — | |||||||||
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) | $ | 71.55 | $ | 91.98 | (22 | ) | ||||||
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 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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Year Ended December 31, | ||||||||||||
2005 | 2004 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 1,444 | $ | 853 | 69 | % | ||||||
Capacity revenue | 291 | 265 | 10 | |||||||||
Risk Management Activities | (285 | ) | 58 | NA | ||||||||
Contract amortization | — | (6 | ) | NA | ||||||||
Other revenues | 104 | 81 | 28 | |||||||||
Total operating revenues | 1,554 | 1,251 | 24 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 869 | 521 | 67 | |||||||||
Depreciation and amortization | 74 | 73 | 1 | |||||||||
Other operating expenses | 393 | 339 | 16 | |||||||||
Operating Income | $ | 218 | $ | 318 | (31 | ) | ||||||
MWh sold (in thousands) | 16,246 | 14,259 | 14 | |||||||||
MWh generated (in thousands) | 16,246 | 14,259 | 14 | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 91.98 | $ | 63.53 | 45 | |||||||
Cooling Degree Days, or CDDs(a) | 801 | 516 | 55 | |||||||||
CDD’s 30 year rolling average | 537 | 537 | — | |||||||||
Heating Degree Days, or HDDs(a) | 6,162 | 6,157 | — | |||||||||
HDD’s 30 year rolling average | 6,261 | 6,294 | (1 | )% |
(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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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) | $ | 56.29 | $ | 69.96 | (20 | ) | ||||||
Cooling Degree Days, or CDDs(a) | 2,908 | 2,826 | 3 | |||||||||
CDD’s 30 year rolling average | 2,449 | 2,449 | — | |||||||||
Heating Degree Days, or HDDs(a) | 1,815 | 2,016 | (10 | )% | ||||||||
HDD’s 30 year rolling average | 2,287 | 2,287 | — |
(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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Year Ended December 31, | ||||||||||||
2005 | 2004 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 339 | $ | 221 | 53 | % | ||||||
Capacity revenue | 190 | 211 | (10 | ) | ||||||||
Risk Management Activities | (2 | ) | — | N/A | ||||||||
Contract Amortization | 9 | — | N/A | |||||||||
Other revenues | 24 | 2 | N/A | |||||||||
Total operating revenues | 560 | 434 | 29 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 374 | 224 | 67 | |||||||||
Depreciation and amortization | 67 | 69 | (3 | ) | ||||||||
Other operating expenses | 111 | 80 | 39 | |||||||||
Operating Income | $ | 8 | $ | 61 | (87 | ) | ||||||
MWh sold (in thousands) | 11,771 | 10,613 | 11 | |||||||||
MWh generated (in thousands) | 10,009 | 10,361 | (3 | ) | ||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 69.96 | $ | 45.76 | 53 | |||||||
Cooling Degree Days, or CDDs(a) | 2,826 | 2,550 | 11 | |||||||||
CDD’s 30 year rolling average | 2,449 | 2,449 | — | |||||||||
Heating Degree Days, or HDDs(a) | 2,016 | 2,043 | (1 | )% | ||||||||
HDD’s 30 year rolling average | 2,287 | 2,287 | — |
(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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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 75 | $ | 1 | $ | 10 | ||||||
Capacity revenue | 68 | — | (4 | ) | ||||||||
Risk Management Activities | (3 | ) | — | — | ||||||||
Contract Amortization | — | — | (3 | ) | ||||||||
Other revenues | 6 | 3 | 4 | |||||||||
Total operating revenues | 146 | 4 | 7 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 80 | 1 | 5 | |||||||||
Depreciation and amortization | 3 | 1 | 1 | |||||||||
Other operating expenses | 55 | 8 | 9 | |||||||||
Operating Income/(loss) | $ | 8 | $ | (6 | ) | $ | (8 | ) | ||||
MWh sold (in thousands) | 1,901 | 6 | 77 | |||||||||
MWh generated (in thousands) | 1,901 | 6 | 77 | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 60.12 | $ | 71.06 | $ | 53.16 | ||||||
Cooling Degree Days, or CDDs(a) | 926 | 775 | 887 | |||||||||
CDD’s 30 year rolling average | 704 | 704 | 704 | |||||||||
Heating Degree Days, or HDDs(a) | 3,001 | 2,842 | 2,826 | |||||||||
HDD’s 30 year rolling average | 3,228 | 3,228 | 3,243 |
(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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• | The acquisition of Texas Genco LLC for $6.2 billion, including the assumption of approximately $2.7 billion in debt. | |
• | Proceeds of approximately $357 million and an after-tax gain of approximately $75 million recognized from the sale of Flinders and Audrain. | |
• | Proceeds of approximately $109 million from the sale of non-core assets. | |
• | The purchase of the remaining 50% interest in WCP and sale of NRG’s 50% interest in Rocky Road for a net $160 million. |
• | The issuance of $5.6 billion in a senior credit facility, including a $1 billion revolving credit facility and a $1 billion synthetic letter of credit facility; $3.6 billion in unsecured high yield notes; $500 million of 5.75% Preferred Stock; and $1 billion of common stock related to the acquisition of Texas Genco LLC. | |
• | The extinguishment of $1.1 billion in aggregate principal amount of NRG’s 8% second priority notes. | |
• | The extinguishment of $1.1 billion in aggregate principal amount of Texas Genco LLC and Texas Genco Financing Corp.’s 6.875% senior notes. | |
• | The issuance of $1.1 billion in unsecured high yield notes and an increase by $500 million in the existing synthetic letter of credit facility related to the Hedge Reset transaction in November 2006. | |
• | The institution of a Capital Allocation Program announced on August 1, 2006. |
• | Phase I consisted of the issuance of approximately $249 million of notes and $84 million of preferred interest by unrestricted subsidiaries to partially fund the purchase of $500 million of NRG common stock completed in the fourth quarter 2006. | |
• | Phase II, also a $500 million share buyback, is expected to be completed in the first half of 2007, of which 4.2 million shares of NRG common stock had been repurchased as of December 31, 2006. | |
• | Completed the repayment of $400 million in debt as part of Phase II. |
• | The termination of NRG term loan, funded letter of credit and revolving credit facilities issued on December 24, 2004. | |
• | The return of cash collateral payments of $454 million due to decreases in forward prices for natural gas and power as well as the settlement of trades. |
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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+ | |||||||||
Senior Notes 7.25% | B− | B1 | B+ | |||||||||
Term Loan | BB− | Ba1 | BB |
• | Moody’s reaffirmed their rating but modified NRG’s outlook to negative, reflecting their view of the increased debt level at NRG associated with the program; | |
• | Standard & Poor’s reaffirmed their rating with a stable outlook; and | |
• | Fitch reaffirmed their rating with a stable outlook. |
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South | ||||||||||||||||||||
Texas | Northeast | Central | Other | Total | ||||||||||||||||
(In millions) | ||||||||||||||||||||
2007 | $ | 9 | $ | 118 | $ | 41 | $ | 9 | $ | 177 | ||||||||||
2008 | 16 | 183 | 93 | 10 | 302 | |||||||||||||||
2009 | 19 | 183 | 167 | 5 | 374 | |||||||||||||||
2010 | 26 | 144 | 84 | 4 | 258 | |||||||||||||||
2011 | 19 | 30 | 63 | 1 | 113 | |||||||||||||||
2012 | 13 | 3 | 33 | — | 49 | |||||||||||||||
Total | $ | 102 | $ | 661 | $ | 481 | $ | 29 | $ | 1,273 | ||||||||||
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Equivalent Net Sales secured by Second Lien Structure(a) | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | ||||||||||||||||||
In MW | 3,371 | 3,200 | 3,682 | 3,017 | 3,293 | 591 | ||||||||||||||||||
As a percentage of total forecasted baseload capacity | 57 | % | 54 | % | 63 | % | 52 | % | 57 | % | 13 | % |
(a) | Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region. |
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Subsidiary/Description | 2007 | 2008 | 2009 | 2010 | 2011 | 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 | 36 | 36 | 36 | 36 | 36 | 2,968 | 3,148 | |||||||||||||||||||||
CSF Non-Recourse Obligations | — | 190 | 143 | — | — | — | 333 | |||||||||||||||||||||
ML Note | — | — | — | — | — | 11 | 11 | |||||||||||||||||||||
NRG Energy Center Minneapolis, due 2013 and 2017 | 9 | 10 | 11 | 11 | 12 | 50 | 103 | |||||||||||||||||||||
NRG Peaker Finance Co LLC | 11 | 13 | 15 | 20 | 21 | 210 | 290 | |||||||||||||||||||||
Camas Pwr BLR LP Bank facility | 1 | — | — | — | — | — | 1 | |||||||||||||||||||||
Camas Pwr BLR LP Bonds | 2 | — | — | — | — | — | 2 | |||||||||||||||||||||
ITISA, due January 2012 | 3 | 4 | 4 | 4 | 4 | — | 19 | |||||||||||||||||||||
ITISA, due December 2013 | 4 | 4 | 4 | 4 | 4 | 12 | 32 | |||||||||||||||||||||
Subtotal Debt, Bonds and Notes | 66 | 257 | 213 | 75 | 77 | 7,951 | 8,639 | |||||||||||||||||||||
Capital Lease: | ||||||||||||||||||||||||||||
Saale Energie GmbH, Schkopau | 68 | 30 | 23 | 11 | 5 | 62 | 199 | |||||||||||||||||||||
Other | 2 | 2 | ||||||||||||||||||||||||||
Total Payments and Capital Leases | $ | 136 | $ | 287 | $ | 236 | $ | 86 | $ | 82 | $ | 8,013 | $ | 8,840 | ||||||||||||||
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Year Ended December 31, | ||||||||||||
2006 | 2005 | Change | ||||||||||
(In millions) | ||||||||||||
Net cash provided by operating activities | $ | 408 | $ | 68 | $ | 340 | ||||||
Net cash provided/(used) by investing activities | (4,176 | ) | 158 | (4,334 | ) | |||||||
Net cash provided/(used) by financing activities | 4,053 | (830 | ) | 4,883 |
• | Due to expiration of the underlying contracts and the downward shift of the forward price curves, NRG’s cash collateral deposits in support of derivative contracts decreased by $454 million for the year ended December 31, 2006, compared to an increase of $405 million for the year ended December 31, 2005, a difference of $859 million. As of December 31, 2006, NRG had cash collateral deposits of $27 million; | |
• | Due to the redemption of NRG’s previous senior notes, a premium of $126 million was paid to NRG’s former debt holders; | |
• | NRG’s activity for the year ended December 31, 2006 resulted in an increase of $197 million in working capital compared to a decrease in working capital for the year ended December 31, 2005 of $7 million, a difference of $204 million; | |
• | Due to redemption of NRG’s 8% second priority notes, for the year ended December 31, 2006, NRG wrote off $61 million of deferred financing costs less debt premium of $14 million for a net write-off of $47 million, compared to a write-off of debt premiums of $8 million during the same period in 2005, a difference of $55 million; and | |
• | A gain on the sale of emission allowances adjusted net income by $64 million to reflect the activity as investing. Due to price conditions, it was economically beneficial to sell emissions rather than operate certain plants. |
• | During the first quarter 2006, NRG acquired Texas Genco LLC for approximately $6.2 billion (net of assumed debt), which included the issuance of stock at a value of $1.7 billion and a net cash payment of approximately $4.3 billion (net of cash on hand at Texas region of $238 million); | |
• | NRG acquired Dynegy’s 50% ownership interest in WCP for $25 million (net of cash on hand at WCP of $180 million). Prior to the purchase, NRG had an existing investment in WCP accounted for as an unconsolidated equity method investment; | |
• | During 2006, NRG divested a number of the Company’s equity investments for total proceeds of approximately $86 million; in addition, NRG received approximately $260 million in proceeds from sale of assets classified as discontinued operations; and |
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• | NRG’s capital expenditures were $115 million more for the year ended December 31, 2006 than for the year ended December 31, 2005, with the increase primarily related to capital expenditures at Texas and the Northeast regions. |
• | In conjunction with the purchase of Texas Genco LLC, NRG refinanced the Company’s outstanding debt as well as Texas Genco LLC’s outstanding debt as NRG: |
• | Repaid $446 million in outstanding principal and terminated its term loan under NRG’s Amended Credit Facility; | |
• | Repurchased and retired approximately $1.1 billion of NRG’s 8% Second Priority Notes, pursuant to a tender offer; and | |
• | Repurchased Texas Genco LLC outstanding notes for approximately $1.1 billion and Texas Genco LLC term loan for approximately $500 million. |
• | As part of raising the funds to purchase Texas Genco LLC and to refinance the NRG debt portfolio, the Company: |
• | Issued 20,855,057 shares of common stock on January 31, 2006 at an offering price of $48.75 per share for total net proceeds of approximately $986 million, after deducting expenses; | |
• | Issued 2,000,000 shares of 5.75% Preferred Stock on January 30, 2006 at an offering price of $250 per share for total net proceeds of approximately $486 million, after deducting expenses; | |
• | Entered into a new senior secured credit facility providing for an aggregate amount up to $5.575 billion, consisting of a $3.575 billion Term Loan Facility, a $1.0 billion Revolving Credit Facility, and a $1.0 billion Letter of Credit Facility; and | |
• | Issued (i) $1.2 billion aggregate principal amount of 7.25% Senior Notes, and (ii) $2.4 billion aggregate principal amount of 7.375% Senior Notes. |
• | In accordance with FAS 133, as amended, payments of $296 million for the settlement of derivatives that were acquired with the acquisition of Texas Genco LLC are considered financing activities. These amounts are recorded as a reduction to revenues in the statement of operations. | |
• | In connection with NRG’s Hedge Reset transactions during the fourth quarter 2006, the Company issued approximately $1.1 billion 7.375% Senior Notes, due 2017, which were used to make cash payments to hedge counterparties of approximately $1.35 billion. | |
• | During Phase I of the Company’s Capital Allocation Program, NRG through two wholly-owned unrestricted subsidiaries issued approximately $249 million in notes and $84 million in preferred interests to partially fund the purchase of approximately $500 million of NRG’s common stock for the year ended December 31, 2006. | |
• | Phase II of the Company’s Capital Allocation Program has resulted in the repurchase of an additional $232 million of the Company’s common stock with cash on hand as of December 31, 2006. In addition, the company repaid $400 million in debt. |
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Fuel-type | MW | |||
Gas | 4,050 | |||
Nuclear | 2,700 | |||
Coal Gasification, or IGCC | 1,500 | |||
Solid Fuel | 1,800 | |||
Wind | 300 | |||
Total | 10,350 | |||
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• | The Texas region’s percentage of hedged baseload capacity and the corresponding revenues as of February 2, 2006; | |
• | The revenues expected from those hedges following the Hedge Reset; | |
• | The increase in cash based revenues following the Hedge Reset; and | |
• | The expected increase in net revenues following the Hedge Reset. |
2007 | 2008 | 2009 | 2010 | |||||||||||||
(In millions unless otherwise stated) | ||||||||||||||||
Texas region Net Baseload Capacity (MW) | 5,340 | 5,340 | 5,340 | 5,340 | ||||||||||||
Texas region Baseload Sales (MW)(a) | 4,267 | 4,157 | 3,449 | 1,395 | ||||||||||||
Percentage Baseload Capacity Sold Forward(b) | 80 | % | 78 | % | 65 | % | 26 | % | ||||||||
As of Acquisition: | ||||||||||||||||
Weighted Average Forward Price ($ per MWh)(c)(d) | $ | 39 | �� | $ | 41 | $ | 47 | $ | 51 | |||||||
Total Forward Hedged Revenues(c) | 1,443 | 1,505 | 1,434 | 621 | ||||||||||||
After Hedge Reset(d) | ||||||||||||||||
Weighted Average Forward Price ($ per MWh)(c)(e) | 56 | 54 | 57 | 55 | ||||||||||||
Total Forward Hedged Revenues(c) | 2,103 | 1,963 | $ | 1,707 | $ | 723 | ||||||||||
Increase in energy revenue | 660 | 458 | 273 | 102 | ||||||||||||
Decrease in contract amortization revenue | (563 | ) | (361 | ) | (261 | ) | (75 | ) | ||||||||
Net impact to reported revenue | $ | 97 | $ | 97 | $ | 12 | $ | 27 | ||||||||
(a) | Includes amounts under fixed price power sales contracts and amounts financially hedged under natural gas swap contracts. The forward natural gas swap quantities are reflected in equivalent MWh and are derived by first dividing the quantity of MMBtu of natural gas hedged by the forward market heat rate as of December 30, 2005 to arrive at the equivalent MWh hedged which is then divided by 8,760 (total hours in a year) to arrive at MW hedged. | |
(b) | Percentage hedged is based on total MWh sold as power and gas converted using the method as described in (a) above divided by the net capacity. The net capacity excludes loss in generation from expected forced outages and in generation from forecasted market uncertainties. | |
(c) | Includes amounts under fixed price power sales contracts and financially hedged under natural gas contracts. | |
(d) | Of the Texas region Baseload Sales, 72% of 2007, 58% of 2008, 73% of 2009 and 67% of 2010, had their price negotiated per the Hedge Reset. | |
(e) | Includes power contract prices which are comprised of a fixed demand charge which is exclusive of a fixed energy charge. The forward price related to these contracts is the sum of both charges. |
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By Remaining Maturity at December 31, | ||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||
Under | 2005 | |||||||||||||||||||||||
Contractual Cash Obligations | 1 Year | 1-3 Years | 3-5 Years | Over 5 Years | Total | Total | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Long-term debt (including estimated interest) | $ | 664 | $ | 1,724 | $ | 1,392 | $ | 9,650 | $ | 13,430 | $ | 3,600 | ||||||||||||
Capital lease obligations (including estimated interest) | 87 | 85 | 35 | 196 | 403 | 406 | ||||||||||||||||||
Operating leases | 39 | 70 | 63 | 255 | 427 | 150 | ||||||||||||||||||
Fuel purchase and transportation obligations(a) | 1,614 | 934 | 505 | 593 | 3,646 | 416 | ||||||||||||||||||
Total contractual cash obligations | $ | 2,404 | $ | 2,813 | $ | 1,995 | $ | 10,694 | $ | 17,906 | $ | 4,572 | ||||||||||||
(a) | Includes only those coal transportation and gas commitments for 2007 as no other nominations were made as of December 31, 2006 |
By Remaining Maturity at December 31, | ||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||
Under | 2005 | |||||||||||||||||||||||
Guarantees | 1 Year | 1-3 Years | 3-5 Years | Over 5 Years | Total | Total | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Synthetic letters of credit | $ | 523 | $ | 444 | $ | — | $ | — | $ | 967 | $ | — | ||||||||||||
Funded standby letters of credit | — | — | — | — | — | 312 | ||||||||||||||||||
Unfunded standby letters of credit and surety bonds | 97 | 56 | — | — | 153 | 4 | ||||||||||||||||||
Asset sales guarantee obligations | — | 13 | 110 | 21 | 144 | 123 | ||||||||||||||||||
Commodity sales guarantee obligations | 133 | 51 | — | 420 | 604 | 91 | ||||||||||||||||||
Other guarantees | 1 | — | — | 28 | 29 | 91 | ||||||||||||||||||
Total guarantees | $ | 754 | $ | 564 | $ | 110 | $ | 469 | $ | 1,897 | $ | 621 | ||||||||||||
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(In millions) | ||||
Fair value of contracts at December 31, 2005 | $ | (403 | ) | |
Value of Flinders contracts as at December 31, 2005, reclassified as discontinued operations | 73 | |||
Value of contracts acquired with NRG Texas on February 2, 2006 | (472 | ) | ||
Value of contracts negotiated pursuant to the Hedge Reset transaction | 145 | |||
Contracts realized or otherwise settled during the period | 165 | |||
Changes in fair value | 846 | |||
Fair value of contracts at December 31, 2006 | $ | 354 | ||
Fair Value of Contracts as of December 31, 2006 | ||||||||||||||||||||
Maturity | Maturity | |||||||||||||||||||
Less than | Maturity | Maturity | in Excess | Total Fair | ||||||||||||||||
Sources of Fair Value Gains/(Losses) | 1 Year | 1-3 Years | 4-5 Years | of 5 Years | Value | |||||||||||||||
(In millions) | ||||||||||||||||||||
Prices actively quoted | $ | 80 | $ | — | $ | — | $ | — | $ | 80 | ||||||||||
Prices provided by other external sources | 183 | 72 | 26 | (19 | ) | 262 | ||||||||||||||
Prices provided by models and other valuation methods | 3 | 9 | — | — | 12 | |||||||||||||||
Total | $ | 266 | $ | 81 | $ | 26 | $ | (19 | ) | $ | 354 | |||||||||
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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 | ||
• 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; |
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• | 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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• | 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, 2006 | $ | 18 | ||
Average(a) | 39 | |||
Maximum(a) | 67 | |||
Minimum(a) | 17 | |||
As of December 31, 2005 | $ | 37 | ||
Average | 28 | |||
Maximum | 46 | |||
Minimum | 16 |
(a) | Includes Texas region portfolio beginning the third quarter 2006. |
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Period of swap | Notional Value | Maturity | ||||||
1 — year | $ | 120 million | March 31, 2007 | |||||
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 | ||||||||||||
Credit Exposure | Collateral | Collateral | Net Exposure | |||||||||
(In millions, except ratios) | ||||||||||||
Investment grade | $ | 1,812 | $ | 349 | $ | 1,463 | ||||||
Non-investment grade | 84 | 73 | 11 | |||||||||
Not rated | 146 | 3 | 143 | |||||||||
Total | $ | 2,042 | $ | 425 | $ | 1,617 | ||||||
Investment grade | 89 | % | 82 | % | 90 | % | ||||||
Non-investment grade | 4 | % | 17 | % | 1 | % | ||||||
Not rated | 7 | % | 1 | % | 9 | % |
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Item 10 — | Directors and Executive Officers of the Registrant |
Item 11 — | Executive Compensation |
Item 12 — | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Item 13 — | Certain Relationships and Related Transactions |
Item 14 — | Principal Accountant Fees and Services |
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Item 15 — | Exhibits and Financial Statement Schedules |
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For the Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions except per share amounts) | ||||||||||||
Operating Revenues | ||||||||||||
Total operating revenues | $ | 5,623 | $ | 2,430 | $ | 2,104 | ||||||
Operating Costs and Expenses | ||||||||||||
Cost of operations | 3,276 | 1,838 | 1,290 | |||||||||
Depreciation and amortization | 593 | 162 | 179 | |||||||||
General, administrative and development | 316 | 181 | 197 | |||||||||
Corporate relocation charges | — | 6 | 16 | |||||||||
Reorganization items | — | — | (13 | ) | ||||||||
Impairment charges | — | 6 | 45 | |||||||||
Total operating costs and expenses | 4,185 | 2,193 | 1,714 | |||||||||
Operating Income | 1,438 | 237 | 390 | |||||||||
Other Income/(Expense) | ||||||||||||
Equity in earnings of unconsolidated affiliates | 60 | 104 | 160 | |||||||||
Write downs and gains/(losses) on sales of equity method investments | 8 | (31 | ) | (16 | ) | |||||||
Other income, net | 160 | 58 | 22 | |||||||||
Refinancing expenses | (187 | ) | (65 | ) | (72 | ) | ||||||
Interest expense | (599 | ) | (184 | ) | (255 | ) | ||||||
Total other expenses | (558 | ) | (118 | ) | (161 | ) | ||||||
Income From Continuing Operations Before Income Taxes | 880 | 119 | 229 | |||||||||
Income Tax Expense | 325 | 47 | 74 | |||||||||
Income From Continuing Operations | 555 | 72 | 155 | |||||||||
Income on Discontinued Operations, net of Income Taxes | 66 | 12 | 31 | |||||||||
Net Income | 621 | 84 | 186 | |||||||||
Preference stock dividends | 50 | 20 | — | |||||||||
Income Available for Common Stockholders | $ | 571 | $ | 64 | $ | 186 | ||||||
Weighted Average Number of Common Shares Outstanding — Basic | 129 | 85 | 100 | |||||||||
Income From Continuing Operations per Weighted Average Common Share — Basic | $ | 3.90 | $ | 0.61 | $ | 1.55 | ||||||
Income From Discontinued Operations per Weighted Average Common Share — Basic | 0.51 | 0.15 | 0.31 | |||||||||
Net Income per Weighted Average Common Share — Basic | 4.41 | 0.76 | 1.86 | |||||||||
Weighted Average Number of Common Shares Outstanding — Diluted | 150 | 85 | 100 | |||||||||
Income From Continuing Operations per Weighted Average Common Share — Diluted | 3.63 | 0.61 | 1.54 | |||||||||
Income From Discontinued Operations per Weighted Average Common Share — Diluted | 0.44 | 0.14 | 0.31 | |||||||||
Net Income per Weighted Average Common Share — Diluted | $ | 4.07 | $ | 0.75 | $ | 1.85 |
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As of December 31, | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 795 | $ | 493 | ||||
Restricted cash | 44 | 49 | ||||||
Accounts receivable — trade, less allowance for doubtful accounts of $1 and $2 | 372 | 245 | ||||||
Accounts receivable — affiliate | — | 4 | ||||||
Current portion of capital lease | 27 | 24 | ||||||
Taxes receivable | 63 | 43 | ||||||
Inventory | 421 | 240 | ||||||
Derivative instruments valuation | 1,230 | 387 | ||||||
Collateral on deposits in support of energy risk management activities | 27 | 438 | ||||||
Prepayments and other current assets | 104 | 120 | ||||||
Current assets —held-for-sale | — | 43 | ||||||
Current assets — discontinued operations | — | 110 | ||||||
Total current assets | 3,083 | 2,196 | ||||||
Property, Plant and Equipment | ||||||||
In service | 12,496 | 2,904 | ||||||
Under construction | 88 | 37 | ||||||
Total property, plant and equipment | 12,584 | 2,941 | ||||||
Less accumulated depreciation | (984 | ) | (332 | ) | ||||
Net property, plant and equipment | 11,600 | 2,609 | ||||||
Other Assets | ||||||||
Equity investments in affiliates | 344 | 602 | ||||||
Note receivable, less current portion — affiliates | 114 | 103 | ||||||
Capital lease, less current portion | 365 | 354 | ||||||
Goodwill | 1,789 | — | ||||||
Intangible assets, net of accumulated amortization of $259 and $79 | 981 | 257 | ||||||
Nuclear decommissioning trust fund | 352 | — | ||||||
Derivative instruments valuation | 439 | 18 | ||||||
Funded letter of credit | — | 350 | ||||||
Deferred income taxes | 27 | 26 | ||||||
Other non-current assets | 262 | 124 | ||||||
Intangible assetsheld-for-sale | 79 | — | ||||||
Non-current assets — discontinued operations | — | 827 | ||||||
Total other assets | 4,752 | 2,661 | ||||||
Total Assets | $ | 19,435 | $ | 7,466 | ||||
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As of December 31, | ||||||||
2006 | 2005 | |||||||
(In millions, except share data) | ||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Current portion of long-term debt and capital leases | $ | 130 | $ | 95 | ||||
Accounts payable — trade | 330 | 241 | ||||||
Accounts payable — affiliates | 2 | — | ||||||
Derivative instruments valuation | 964 | 679 | ||||||
Deferred income taxes | 164 | — | ||||||
Accrued expenses | 262 | 76 | ||||||
Other current liabilities | 180 | 96 | ||||||
Current liabilities — discontinued operations | — | 170 | ||||||
Total current liabilities | 2,032 | 1,357 | ||||||
Other Liabilities | ||||||||
Long-term debt and capital leases | 8,647 | 2,410 | ||||||
Nuclear decommissioning reserve | 289 | — | ||||||
Nuclear decommissioning trust liability | 324 | — | ||||||
Postretirement and other benefit obligations | 301 | 103 | ||||||
Deferred income taxes | 554 | 128 | ||||||
Derivative instruments valuation | 351 | 56 | ||||||
Out-of-market contracts | 897 | 298 | ||||||
Other non-current liabilities | 134 | 67 | ||||||
Non-current liabilities — discontinued operations | — | 569 | ||||||
Total non-current liabilities | 11,497 | 3,631 | ||||||
Total Liabilities | 13,529 | 4,988 | ||||||
Minority Interest | 1 | 1 | ||||||
3.625% convertible perpetual preferred stock, $0.01 par value; 250,000 shares issued and outstanding (at liquidation value, net of issuance costs) | 247 | 246 | ||||||
Commitments and Contingencies | ||||||||
Stockholders’ Equity | ||||||||
4% convertible perpetual preferred stock; $0.01 par value; 420,000 shares issued and outstanding at December 31, 2006 and 2005 (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 December 31, 2006 (at liquidation value of $500, net of issuance costs) | 486 | — | ||||||
Common Stock; $.01 par value; 500,000,000 shares authorized; 137,124,132 and 100,048,676 shares issued and 122,323,551 and 80,701,888 outstanding | 1 | 1 | ||||||
Additional paid-in capital | 4,476 | 2,431 | ||||||
Retained earnings | 739 | 261 | ||||||
Less treasury stock, at cost — 14,800,581 and 19,346,788 shares | (732 | ) | (663 | ) | ||||
Accumulated other comprehensive income/(loss) | 282 | (205 | ) | |||||
Total Stockholders’ Equity | 5,658 | 2,231 | ||||||
Total Liabilities and Stockholders’ Equity | $ | 19,435 | $ | 7,466 | ||||
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Accumulated | ||||||||||||||||||||||||||||||||||||
Additional | Other | Total | ||||||||||||||||||||||||||||||||||
Serial Preferred | Common | Paid-In | Retained | Treasury | Comprehensive | Stockholders’ | ||||||||||||||||||||||||||||||
Stock | Shares | Stock | Shares | Capital | Earnings | Equity/ | Income/(Loss) | Equity | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Balances at December 31, 2003 | $ | — | — | $ | 1 | 100 | $ | 2,403 | $ | 11 | $ | — | $ | 22 | $ | 2,437 | ||||||||||||||||||||
Net income | 186 | 186 | ||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | 46 | 46 | ||||||||||||||||||||||||||||||||||
Unrealized gain on derivatives | 8 | 8 | ||||||||||||||||||||||||||||||||||
Comprehensive income for 2004 | 240 | |||||||||||||||||||||||||||||||||||
Equity-based compensation | 14 | 14 | ||||||||||||||||||||||||||||||||||
Issuance of preferred stock | 406 | 0.4 | 406 | |||||||||||||||||||||||||||||||||
Purchase of treasury stock | (13 | ) | (405 | ) | (405 | ) | ||||||||||||||||||||||||||||||
Balances at December 31, 2004 | $ | 406 | 0.4 | $ | 1 | 87 | $ | 2,417 | $ | 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 | (6 | ) | (258 | ) | (258 | ) | ||||||||||||||||||||||||||||||
Balances at December 31, 2005 | $ | 406 | 0.4 | $ | 1 | 81 | $ | 2,431 | $ | 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 ofEITF 04-6 | (93 | ) | (93 | ) | ||||||||||||||||||||||||||||||||
Equity-based compensation | 14 | 14 | ||||||||||||||||||||||||||||||||||
Issuance of common stock to the public | 21 | 986 | 986 | |||||||||||||||||||||||||||||||||
Issuance of preferred stock | 486 | 2.0 | 486 | |||||||||||||||||||||||||||||||||
Issuance of common and treasury stock to the shareholders of Texas Genco LLC | 35 | 1,028 | 663 | 1,691 | ||||||||||||||||||||||||||||||||
Preferred stock dividends | (50 | ) | (50 | ) | ||||||||||||||||||||||||||||||||
Purchase of treasury stock | (15 | ) | (732 | ) | (732 | ) | ||||||||||||||||||||||||||||||
Balances at December 31, 2006 | $ | 892 | 2.4 | $ | 1 | 122 | $ | 4,476 | $ | 739 | $ | (732 | ) | $ | 282 | $ | 5,658 | |||||||||||||||||||
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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
Cash Flows from Operating Activities | ||||||||||||
Net income | $ | 621 | $ | 84 | $ | 186 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||||||
Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | (33 | ) | (8 | ) | (1 | ) | ||||||
Depreciation and amortization of nuclear fuel | 654 | 195 | 215 | |||||||||
Amortization and write-off of deferred financing costs and debt discount/premiums | 79 | 14 | 70 | |||||||||
Amortization of intangibles and out-of-market contracts | (490 | ) | 17 | 52 | ||||||||
Amortization of equity-based compensation | 14 | 12 | 14 | |||||||||
Write down and gains on sale of equity method investments | (8 | ) | 31 | 16 | ||||||||
Loss on sale and disposal of equipment | 10 | 4 | 1 | |||||||||
Impairment charges | — | 6 | 45 | |||||||||
Changes in derivatives | (149 | ) | 143 | (74 | ) | |||||||
Changes in deferred income taxes | 327 | 2 | 57 | |||||||||
Gain on legal settlement | (67 | ) | (14 | ) | — | |||||||
Gain on sale of discontinued operations | (76 | ) | (6 | ) | (23 | ) | ||||||
Gain on sale of emission allowances | (64 | ) | — | — | ||||||||
Change in nuclear decommissioning trust liability | 12 | — | — | |||||||||
Changes in collateral deposits supporting energy risk management activities | 454 | (405 | ) | (7 | ) | |||||||
Settlement ofout-of-market power contracts | (1,073 | ) | — | — | ||||||||
Cash provided by changes in other working capital, net of acquisition and disposition effects | ||||||||||||
Accounts receivable, net | 87 | (8 | ) | (52 | ) | |||||||
Xcel Energy settlement receivable | — | — | 640 | |||||||||
Inventory | (50 | ) | (14 | ) | (56 | ) | ||||||
Prepayments and other current assets | 43 | (35 | ) | 126 | ||||||||
Creditor pool obligation payments | — | — | (540 | ) | ||||||||
Accounts payable | (73 | ) | 57 | 50 | ||||||||
Accrued expenses and other current liabilities | 133 | (16 | ) | (127 | ) | |||||||
Other assets and liabilities | 57 | 9 | 53 | |||||||||
Net Cash Provided by Operating Activities | 408 | 68 | 645 | |||||||||
Cash Flows from Investing Activities | ||||||||||||
Acquisition of Texas Genco LLC, net of cash acquired | (4,302 | ) | (5 | ) | — | |||||||
Acquisition of WCP and Padoma, net of cash acquired | (31 | ) | — | — | ||||||||
Capital expenditures | (221 | ) | (106 | ) | (119 | ) | ||||||
Decrease/(increase) in restricted cash, net | 6 | 45 | (27 | ) | ||||||||
Decrease in notes receivable | 27 | 107 | 25 | |||||||||
Purchases of emission allowances | (135 | ) | — | — | ||||||||
Proceeds from sale of emission allowances | 146 | — | — | |||||||||
Investments in nuclear decommissioning trust fund securities | (227 | ) | — | — | ||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 214 | — | — | |||||||||
Proceeds from sale of investments and equipment | 86 | 79 | 55 | |||||||||
Proceeds from sale of discontinued operations | 260 | 36 | 253 | |||||||||
Return of capital from equity method investments/(Investments in projects) | 1 | 2 | (3 | ) | ||||||||
Net Cash Provided/(Used) by Investing Activities | (4,176 | ) | 158 | 184 | ||||||||
Cash Flows from Financing Activities | ||||||||||||
Payment of dividends to preferred stockholders | (50 | ) | (20 | ) | — | |||||||
Payment of financing element of acquired derivatives | (296 | ) | — | — | ||||||||
Payment for treasury stock | (732 | ) | (250 | ) | (405 | ) | ||||||
Payment of minority interest obligations | — | (4 | ) | — | ||||||||
Funded letter of credit | 350 | — | (100 | ) | ||||||||
Proceeds from issuance of common stock, net of issuance costs | 986 | — | — | |||||||||
Proceeds from issuance of preferred shares, net of issuance costs | 486 | 246 | 406 | |||||||||
Proceeds from issuance of long-term debt | 8,619 | 249 | 1,333 | |||||||||
Payment of deferred debt issuance costs | (199 | ) | (46 | ) | (26 | ) | ||||||
Payments for short and long-term debt | (5,111 | ) | (1,005 | ) | (1,492 | ) | ||||||
Net Cash Provided/(Used) by Financing Activities | 4,053 | (830 | ) | (284 | ) | |||||||
Change in Cash from Discontinued Operations | 13 | 30 | (14 | ) | ||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | 4 | (2 | ) | 3 | ||||||||
Net Increase in Cash and Cash Equivalents | 302 | (576 | ) | 534 | ||||||||
Cash and Cash Equivalents at Beginning of Period | 493 | 1,069 | 535 | |||||||||
Cash and Cash Equivalents at End of Period | $ | 795 | $ | 493 | $ | 1,069 | ||||||
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Note 1 — | Nature of Business |
Note 2 — | Summary of Significant Accounting Policies |
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Year Ended December 31, | ||||||||||
2005 | 2004 | Fair Value Basis | ||||||||
(In millions) | ||||||||||
Turbines | $ | 6 | $ | 15 | Sales price | |||||
Kendall asset group | — | 27 | Realized loss | |||||||
Other | — | 3 | Estimated market price | |||||||
Total impairment charges | $ | 6 | $ | 45 | ||||||
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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. |
• | 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, 2005 | $ | 28 | ||
Additions — acquisitions | 315 | |||
Additions — incurred during the year | 12 | |||
Additions — due to revisions in cash flow | 3 | |||
Accretion | 23 | |||
Balance as of December 31, 2006 | $ | 381 | ||
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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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(In millions) | ||||
Goodwill balance at March 31, 2006 | $ | 2,748 | ||
Increase in fixed assets per revised valuation | (906 | ) | ||
Net decrease in intangibles and other contracts per revised valuation | 215 | |||
Adjustment to deferred tax assets and liabilities | (275 | ) | ||
Change in goodwill due to changes in valuation | (966 | ) | ||
Goodwill balance at December 31, 2006 | $ | 1,782 | ||
• | Change in assumptions and estimates in the price of electricity, coal, gas and emission allowances; | |
• | The tax basis of the assets and liabilities acquired; and | |
• | More precise information with respect to identifiable tangible and intangible assets. |
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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 | $ | 148 | $ | 153 | $ | — | $ | 153 | $ | 301 | ||||||||||
Property, plant and equipment | 24 | 102 | (39 | ) | 63 | 87 | ||||||||||||||
Intangible assets | 2 | 20 | (7 | ) | 13 | 15 | ||||||||||||||
Other non-current assets | — | 8 | — | 8 | 8 | |||||||||||||||
Current liabilities | (12 | ) | (11 | ) | — | (11 | ) | (23 | ) | |||||||||||
Non-current liabilities | (3 | ) | (21 | ) | — | (21 | ) | (24 | ) | |||||||||||
Negative goodwill | — | (46 | ) | 46 | — | — | ||||||||||||||
Total Equity | $ | 159 | $ | 205 | $ | — | $ | 205 | $ | 364 | ||||||||||
Year Ended December 31, | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
Operating revenues | $ | 5,884 | $ | 5,891 | ||||
Net income | 399 | 296 | ||||||
Earnings per share — Basic | 2.59 | 1.74 | ||||||
Earnings per share — Diluted | 2.53 | 1.72 | ||||||
Weighted average number of shares outstanding — Basic | 133.9 | 140.8 | ||||||
Weighted average number of shares outstanding — Diluted | 144 | 152 |
(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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Note 4 — | Discontinued Operations |
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As of December 31, | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
Cash and cash equivalents | $ | — | $ | 13 | ||||
Restricted cash | — | 15 | ||||||
Receivables, net | — | 36 | ||||||
Inventory | — | 20 | ||||||
Other current assets | — | 26 | ||||||
Current assets — discontinued operations | — | 110 | ||||||
Property, plant and equipment, net | — | 545 | ||||||
Notes receivable | — | 241 | ||||||
Other non-current assets | — | 41 | ||||||
Non-current assets — discontinued operations | — | 827 | ||||||
Current portion of long-term debt | — | 6 | ||||||
Accounts payable — trade | — | 27 | ||||||
Other current liabilities | — | 137 | ||||||
Current liabilities — discontinued operations | — | 170 | ||||||
Long-term debt | — | 410 | ||||||
Other non-current liabilities | — | 159 | ||||||
Non-current liabilities — discontinued operations | $ | — | $ | 569 | ||||
Initial Discontinued | ||||||
Operations | ||||||
Project | Segment(a) | Treatment Date | Disposal Date | |||
McClain | Corporate | Third Quarter 2003 | Third Quarter 2004 | |||
PERC | Corporate | First Quarter 2004 | Second Quarter 2004 | |||
Cobee | International | First Quarter 2004 | Second Quarter 2004 | |||
Hsin Yu | International | Second Quarter 2004 | Second Quarter 2004 | |||
LSP Energy (Batesville) | Corporate | Second Quarter 2004 | Third Quarter 2004 | |||
NEO Corporation (NEO, Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha LLC and NEO Tajiguas LLC) | Corporate | Third Quarter 2004 | Third Quarter 2004 | |||
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 |
(a) | Conforms to NRG’s revised segment classification |
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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
Operating revenues | $ | 189 | $ | 292 | $ | 366 | ||||||
Operating costs and other expenses | 201 | 289 | 365 | |||||||||
Pre-tax income/(loss) from operations of discontinued components | (12 | ) | 3 | 1 | ||||||||
Income tax benefit | (2 | ) | (3 | ) | (8 | ) | ||||||
Income from operations of discontinued components | (10 | ) | 6 | 9 | ||||||||
Disposal of discontinued components — pre-tax gain | 80 | 13 | 30 | |||||||||
Income tax expense | 4 | 7 | 8 | |||||||||
Gain on disposal of discontinued components, net | 76 | 6 | 22 | |||||||||
Income on discontinued operations, net of income taxes | $ | 66 | $ | 12 | $ | 31 | ||||||
Year Ended December 31, | ||||||||||||||
2006 | 2005 | 2004 | Segment(a) | |||||||||||
(In millions) | ||||||||||||||
Resource Recovery | $ | 5 | $ | — | $ | — | Corporate | |||||||
Flinders | 60 | — | — | International | ||||||||||
Audrain | 15 | — | — | Corporate | ||||||||||
Northbrook Energy, Northbrook New York | — | 12 | — | Corporate | ||||||||||
McClain | — | 1 | (3 | ) | Corporate | |||||||||
PERC | — | — | 3 | Corporate | ||||||||||
Cobee | — | — | 3 | International | ||||||||||
LSP Energy — Batesville | — | — | 11 | Corporate | ||||||||||
Hsin Yu | — | — | 10 | International | ||||||||||
NEO Corporation | — | — | 6 | Corporate | ||||||||||
Total pre-tax gain on disposal of discontinued operations | $ | 80 | $ | 13 | $ | 30 | ||||||||
(a) | Conforms to NRG’s revised segment classification |
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Note 5 — | Financial Instruments |
Year Ended December 31, | ||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||
2006 | 2005 | 2006 | 2005 | |||||||||||||
(In millions) | ||||||||||||||||
Cash and cash equivalents | $ | 795 | $ | 493 | $ | 795 | $ | 493 | ||||||||
Restricted cash | 44 | 49 | 44 | 49 | ||||||||||||
Trust fund investments | 377 | 20 | 377 | 20 | ||||||||||||
Notes receivable | 114 | 103 | 126 | 173 | ||||||||||||
Long-term debt, including current portion | 8,777 | 2,505 | 8,828 | 2,632 |
Note 6 — | Accounting for Derivative Instruments and Hedging Activities |
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• | Forward contracts, which commit NRG to sell energy commodities or 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 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 2012. | |
• | 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 2010. | |
• | Coal purchase contracts extending through 2015 designated as normal purchases and disclosed as part of NRG’s contractual cash obligations. See Note 21,Commitments and Contingencies, for further discussion. |
• | Load-following forward electric sale contracts extending through 2026. | |
• | Natural gas transportation contracts and storage agreements are not derivatives and are disclosed as part of NRG’s contractual cash obligations. See Note 21,Commitments and Contingencies, for further discussion. |
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Energy-Related | Interest | |||||||||||
Commodities | Rate | Total | ||||||||||
(In millions) | ||||||||||||
Accumulated OCI balance at December 31, 2003 | $ | (2 | ) | $ | 1 | $ | (1 | ) | ||||
Unwound from OCI during period — due to unwinding of previously deferred amounts | 3 | 5 | 8 | |||||||||
Changes in fair value of hedge contracts — gains/(losses) | 4 | (4 | ) | — | ||||||||
Accumulated OCI balance at December 31, 2004 | $ | 5 | $ | 2 | $ | 7 | ||||||
Unwound 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 | ) | ||||
Unwound 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 | ||||||
Gains expected to unwind from OCI during next 12 months, net of $42 tax | $ | 64 | $ | — | $ | 64 |
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Year Ended December 31, 2006 | ||||||||||||
Energy-Related | ||||||||||||
Commodities | Interest Rate | Total | ||||||||||
(In millions) | ||||||||||||
Operating revenues | $ | 295 | $ | — | $ | 295 | ||||||
Cost of operations | — | — | — | |||||||||
Equity in earnings of unconsolidated subsidiaries | — | — | — | |||||||||
Interest expense | — | 3 | 3 | |||||||||
Total Statement of Operations impact before tax | $ | 295 | $ | (3 | ) | $ | 292 | |||||
�� | ||||||||||||
Year Ended December 31, 2005 | ||||||||||||
Energy-Related | ||||||||||||
Commodities | Interest Rate | Total | ||||||||||
(In millions) | ||||||||||||
Operating revenues | $ | (154 | ) | $ | — | $ | (154 | ) | ||||
Cost of operations | 2 | — | 2 | |||||||||
Equity in earnings of unconsolidated subsidiaries | 12 | — | 12 | |||||||||
Interest expense | — | — | — | |||||||||
Total Statement of Operations impact before tax | $ | (140 | ) | $ | — | $ | (140 | ) | ||||
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Year Ended December 31, 2004 | ||||||||||||
Energy-Related | ||||||||||||
Commodities | Interest Rate | Total | ||||||||||
(In millions) | ||||||||||||
Operating revenues | $ | 59 | $ | — | $ | 59 | ||||||
Cost of operations | — | — | — | |||||||||
Equity in earnings of unconsolidated subsidiaries | 24 | — | 24 | |||||||||
Interest expense | — | — | — | |||||||||
Total Statement of Operations impact before tax | $ | 83 | $ | — | $ | 83 | ||||||
(In millions) | ||||
Settlement payment | $ | (1,347 | ) | |
Reduction in derivative liability | 145 | |||
Reduction in out-of-market contracts | 1,073 | |||
Net decrease in revenues | $ | (129 | ) | |
As of December 31, | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
Fuel oil | $ | 162 | $ | 131 | ||||
Coal/Lignite | 118 | 58 | ||||||
Natural gas | 12 | 4 | ||||||
Spare parts | 129 | 44 | ||||||
Other | — | 3 | ||||||
Total Inventory | $ | 421 | $ | 240 | ||||
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As of December 31, | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
Capital Lease Receivable — non-affiliate | ||||||||
VEAG Vereinigte Energiewerke AG, due August 31, 2021, 13.88%(a) | $ | 392 | $ | 378 | ||||
Capital Lease — non-affiliates | 392 | 378 | ||||||
Less current maturities | 27 | 24 | ||||||
Total | 365 | 354 | ||||||
Note Receivable — affiliates | ||||||||
Kraftwerke Schkopau GBR, indefinite maturity date, 4.75%-7.79%(b) | 114 | 103 | ||||||
Notes receivable — affiliates | $ | 114 | $ | 103 | ||||
(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 December 31, | Depreciable | Average Remaining | ||||||||||||||
2006 | 2005 | Lives | Useful Life | |||||||||||||
(In millions) | ||||||||||||||||
Facilities and equipment | $ | 11,696 | $ | 2,769 | 1-40 Years | 21 | ||||||||||
Land and improvements | 561 | 114 | ||||||||||||||
Nuclear fuel | 159 | — | 5 Years | |||||||||||||
Office furnishings and equipment | 80 | 21 | 2-10 Years | 6 | ||||||||||||
Construction in progress | 88 | 37 | ||||||||||||||
Total property, plant and equipment | 12,584 | 2,941 | ||||||||||||||
Accumulated depreciation | (984 | ) | (332 | ) | ||||||||||||
Net property, plant and equipment | $ | 11,600 | $ | 2,609 | ||||||||||||
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Emission | Contracts | |||||||||||||||||||
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 | ||||||||||
Emission | Contracts | |||||||||||||||||||
December 31, 2005 | Allowances | Power | Fuel | Water | Total | |||||||||||||||
(In millions) | ||||||||||||||||||||
January 1, 2005 | $ | 292 | $ | 57 | $ | — | $ | — | $ | 349 | ||||||||||
Sales | (5 | ) | — | — | — | (5 | ) | |||||||||||||
Tax adjustments | (7 | ) | (1 | ) | — | — | (8 | ) | ||||||||||||
Adjusted gross amount | 280 | 56 | — | — | 336 | |||||||||||||||
Less accumulated amortization | (30 | ) | (49 | ) | — | — | (79 | ) | ||||||||||||
Net carrying amount | $ | 250 | $ | 7 | $ | — | $ | — | $ | 257 | ||||||||||
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Amortization | 2006 | 2005 | 2004 | |||||||||
(In millions) | ||||||||||||
Emission allowances | $ | 44 | $ | 12 | $ | 18 | ||||||
Fuel contracts | 65 | — | — | |||||||||
Water contracts | 28 | — | — | |||||||||
Total amortization in cost of operations | $ | 137 | $ | 12 | $ | 18 | ||||||
Power contract amortization recorded as a reduction to operating revenues | $ | 43 | $ | 12 | $ | 32 |
Emission | Contracts | |||||||||||||||
Year Ended December 31, | Allowances | Fuel | Water | Total | ||||||||||||
(In millions) | ||||||||||||||||
2007 | $ | 42 | $ | 41 | $ | 36 | $ | 119 | ||||||||
2008 | 42 | 21 | — | 63 | ||||||||||||
2009 | 42 | 26 | — | 68 | ||||||||||||
2010 | 56 | 6 | — | 62 | ||||||||||||
2011 | 56 | 2 | — | 58 |
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Year Ended December 31, | Coal | Gas Swaps | Power Contracts | Total | ||||||||||||
2007 | $ | 20 | $ | — | $ | 240 | $ | 260 | ||||||||
2008 | 32 | 11 | 279 | 322 | ||||||||||||
2009 | 19 | 34 | 79 | 132 | ||||||||||||
2010 | 8 | 28 | 27 | 63 | ||||||||||||
2011 | 2 | — | 20 | 22 |
As of December 31, | Interest | |||||||||||||||
2006 | 2005 | Rate | ||||||||||||||
(In millions except rates) | ||||||||||||||||
NRG Recourse Debt: | ||||||||||||||||
Senior notes due 2017 | $ | 1,100 | $ | — | 7.375 | |||||||||||
Senior notes due 2016 | 2,400 | — | 7.375 | |||||||||||||
Senior notes due 2014(a) | 1,183 | — | 7.25 | |||||||||||||
ML note payable | 11 | — | L+1.9 | (h) | ||||||||||||
Term loan due 2013 | 3,148 | — | L+2.0 | (h) | ||||||||||||
2nd priority notes redeemed 2006(b) | — | 1,074 | 8.00 | |||||||||||||
Promissory note, Xcel Energy, due 2006(c) | — | 10 | 3.00 | |||||||||||||
Term loan(d) | — | 445 | — | |||||||||||||
Funded letter of credit(d) | — | 350 | — | |||||||||||||
NRG Non-Recourse Debt: | ||||||||||||||||
CSF non-recourse obligations due 2008 and 2009 | 333 | — | 5.45-13.23 | |||||||||||||
NRG Peaker Finance Co. LLC, due June 2019(e) | 240 | 240 | L+1.07 | (h) | ||||||||||||
NRG Energy Center Minneapolis LLC, senior secured notes, | ||||||||||||||||
due 2013 and 2017(f) | 107 | 116 | 7.12-7.31 | |||||||||||||
Camas Power Boiler LP, unsecured term loan, due June 2007 | 1 | 4 | L+0.69 | (h) | ||||||||||||
Camas Power Boiler LP, revenue bonds, due August 2007 | 2 | 3 | 3.38 | |||||||||||||
ITISA, due December 2013 | 32 | 30 | 12.00 | |||||||||||||
ITISA, due January 2012 | 19 | 19 | ||||||||||||||
Capital leases: | ||||||||||||||||
Saale Energie GmbH, Schkopau capital lease, due 2021 | 199 | 214 | ||||||||||||||
Other | 2 | — | — | |||||||||||||
Subtotal | 8,777 | 2,505 | ||||||||||||||
Less current maturities(g) | 130 | 95 | ||||||||||||||
Total | $ | 8,647 | $ | 2,410 | ||||||||||||
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(a) | Includes fair value adjustment as of December 31, 2006 reflects $(17) million 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 $(6) million as of December 31, 2005. 2nd priority notes were retired in 2006. | |
(c) | Promissory note was paid to Xcel Energy in June 2006. | |
(d) | Terminated in 2006. | |
(e) | Includes discount of $(50) million and $(57) million as of December 31, 2006 and 2005 respectively. | |
(f) | Includes premium of $4 million and $5 million as of December 31, 2006 and 2005 respectively. | |
(g) | Includes premium of $6 million. | |
(h) | L+ equals LIBOR plus x% |
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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 | % |
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 | % |
• | return of capital to shareholders; | |
• | grant liens on assets to lenders; and | |
• | incur additional debt. |
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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. |
Period of swap | Notional Value | Maturity | ||||||
1 - year | $ | 120 million | March 31, 2007 | |||||
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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(In millions) | ||||
2007 | $ | 136 | ||
2008 | 287 | |||
2009 | 236 | |||
2010 | 86 | |||
2011 | 82 | |||
Thereafter | 8,013 | |||
Total | $ | 8,840 | ||
(In millions) | ||||
2007 | $ | 87 | ||
2008 | 47 | |||
2009 | 38 | |||
2010 | 22 | |||
2011 | 13 | |||
Thereafter | 196 | |||
Total minimum obligations | 403 | |||
Interest | 202 | |||
Present value of minimum obligations | 201 | |||
Current portion | 70 | |||
Long-term obligations | $ | 131 | ||
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Year Ended December 31, | ||||||||||||
Pension Benefits | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
Service cost benefits earned | $ | 17 | $ | 11 | $ | 11 | ||||||
Interest cost on benefit obligation | 15 | 4 | 3 | |||||||||
Expected return on plan assets | (7 | ) | — | — | ||||||||
Curtailment gain | — | — | (1 | ) | ||||||||
Net periodic benefit cost | $ | 25 | $ | 15 | $ | 13 | ||||||
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Year Ended December 31, | ||||||||||||
Other Postretirement Benefits | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
Service cost benefits earned | $ | 3 | $ | 2 | $ | 1 | ||||||
Interest cost on benefit obligation | 4 | 3 | 3 | |||||||||
Net periodic benefit cost | $ | 7 | $ | 5 | $ | 4 | ||||||
As of December 31, | ||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
2006 | 2005 | 2006 | 2005 | |||||||||||||
(In millions) | ||||||||||||||||
Benefit obligation at January 1 | $ | 318 | $ | 64 | $ | 80 | $ | 51 | ||||||||
Service cost | 17 | 11 | 3 | 2 | ||||||||||||
Interest cost | 15 | 4 | 4 | 3 | ||||||||||||
Plan initiation | — | — | — | — | ||||||||||||
Plan amendments | — | — | — | — | ||||||||||||
Plan curtailment | — | — | — | — | ||||||||||||
Actuarial (gain)/loss | (29 | ) | 5 | (6 | ) | 2 | ||||||||||
Benefit payments | (27 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||
Benefit obligation at December 31 | $ | 294 | $ | 83 | $ | 80 | $ | 57 | ||||||||
Fair value of plan assets at January 1 | 86 | 1 | — | — | ||||||||||||
Actual return on plan assets | 14 | — | — | — | ||||||||||||
Employer contributions | 51 | 13 | 1 | 1 | ||||||||||||
Benefit payments | (28 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||
Fair value of plan assets at December 31 | $ | 123 | $ | 13 | $ | — | $ | — | ||||||||
Funded status at December 31 — excess of obligation over assets | (171 | ) | (70 | ) | (80 | ) | (57 | ) | ||||||||
Unrecognized net (gain) loss | — | 8 | — | 8 | ||||||||||||
Accrued benefit liability recognized on the consolidated balance sheet at December 31 | $ | (171 | ) | $ | (62 | ) | $ | (80 | ) | $ | (49 | ) | ||||
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As of December 31, | ||||||||||||||||
Pension Benefits | Other Post-Employment Benefits | |||||||||||||||
2006 | 2005 | 2006 | 2005 | |||||||||||||
(In millions) | ||||||||||||||||
Assets | $ | — | $ | — | $ | — | $ | — | ||||||||
Current liabilities | — | — | — | — | ||||||||||||
Non-current liabilities | 171 | 62 | 80 | 49 |
As of December 31, | ||||||||||||||||
Pension Benefits | Other Post-Employment Benefits | |||||||||||||||
2006 | 2005 | 2006 | 2005 | |||||||||||||
(In millions) | ||||||||||||||||
Unrecognized gain/(loss) | $ | (26 | ) | $ | — | $ | 1 | $ | — | |||||||
Total | (26 | ) | — | 1 | — | |||||||||||
Pension Benefits | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
Projected benefit obligation | $ | 294 | $ | 83 | ||||
Accumulated benefit obligation | 226 | 35 | ||||||
Fair value of plan assets | 123 | 13 |
Before Application | After Application | |||||||||
of SFAS 158 | Adjustments | of SFAS 158 | ||||||||
(In millions) | ||||||||||
Liability for pension and other post employment benefits | $ | 326 | $ | (25 | ) | $ | 301 | |||
Deferred income tax liabilities | 544 | 10 | 554 | |||||||
Total liabilities | 13,544 | (15 | ) | 13,529 | ||||||
Accumulated other comprehensive income | 267 | 15 | 282 | |||||||
Total stockholders’ equity | $ | 5,634 | $ | 15 | $ | 5,658 |
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As of December 31, | ||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||
Weighted-Average Assumptions | 2006 | 2005 | 2006 | 2005 | ||||||||
Discount rate | 5.92 | % | 5.50 | % | 5.92% | 5.50% | ||||||
Rate of compensation increase | 4.00-4.50 | % | 4.00-4.50 | % | — | — | ||||||
Health care trend rate | — | — | 10.5% grading to 5.5% in 2012 | 11.5% grading to 5.5% in 2012 |
As of December 31, | ||||||||
Pension Benefits | Other Postretirement Benefits | |||||||
Weighted-Average Assumptions | 2006 | 2005 | 2006 | 2005 | ||||
Discount rate | 5.50% | 5.75% | 5.50% | 5.75% | ||||
Expected return on plan assets | 8.00% | 8.00% | — | — | ||||
Rate of compensation increase | 4.00-4.50% | 4.00-4.50% | — | — | ||||
Health care trend rate | — | — | 11.5% grading to 5.5% in 2012 | 9% grading to 5.5% in 2009 |
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As of December 31, | ||||||||
2006 | 2005 | |||||||
US Equity | 55 | % | 56 | % | ||||
International Equity | 17 | % | 15 | % | ||||
US Fixed Income | 28 | % | 29 | % |
Other Postretirement Benefit | ||||||||||||
Pension Benefits | Medicare Prescription | |||||||||||
Benefit Payments | Benefit Payments | Drug Reimbursements | ||||||||||
(In millions) | ||||||||||||
2007 | $ | 22 | $ | 1 | $ | — | ||||||
2008 | 14 | 2 | — | |||||||||
2009 | 16 | 2 | — | |||||||||
2010 | 18 | 3 | — | |||||||||
2011 | 19 | 3 | — | |||||||||
2012-2016 | $ | 124 | $ | 21 | $ | 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 | (6 | ) |
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Authorized | Issued | Treasury | Outstanding | |||||||||||||
Balance as of December 31, 2004 | 500,000,000 | 100,041,935 | (13,000,000 | ) | 87,041,935 | |||||||||||
Shares issued from LTIP during 2005 | — | 6,741 | — | 6,741 | ||||||||||||
Accelerated Share Repurchase Program, August 2005 | — | — | (6,346,788 | ) | (6,346,788 | ) | ||||||||||
Balance as of December 31, 2005 | 500,000,000 | 100,048,676 | (19,346,788 | ) | 80,701,888 | |||||||||||
Shares issued January 2006 | — | 20,855,057 | — | 20,855,057 | ||||||||||||
Acquisition of Texas Genco LLC | — | 16,059,504 | 19,346,788 | 35,406,292 | ||||||||||||
Shares issued from LTIP during 2006 | — | 160,895 | — | 160,895 | ||||||||||||
Capital Allocation Program — Phase I | — | — | (10,587,700 | ) | (10,587,700 | ) | ||||||||||
Capital Allocation Program — Phase II | — | — | (4,212,881 | ) | (4,212,881 | ) | ||||||||||
Balance as of December 31, 2006 | 500,000,000 | 137,124,132 | (14,800,581 | ) | 122,323,551 | |||||||||||
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Applicable Market Value on Conversion Date | Conversion Rate | |||
equal to or greater than $60.45 | 4.1356 | |||
less than $60.45 but greater than $48.75 | 4.1356 to 5.1282 | |||
less than or equal to $48.75 | 5.1282 |
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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 | % |
Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
Summarized Statements of Operations | ||||||||||||
Operating revenues | $ | 910 | $ | 1,300 | $ | 2,428 | ||||||
Costs and expenses | 770 | 1,107 | 1,966 | |||||||||
Net income | 140 | 193 | 462 | |||||||||
Summarized Balance Sheets | ||||||||||||
Current assets | 223 | 592 | ||||||||||
Non-current assets | 1,697 | 2,561 | ||||||||||
Total assets | 1,920 | 3,153 | ||||||||||
Current liabilities | 53 | 133 | ||||||||||
Non-current liabilities | 1,021 | 1,143 | ||||||||||
Equity | 846 | 1,877 | ||||||||||
Total liabilities and equity | 1,920 | 3,153 | ||||||||||
NRG’s share of equity and net income | ||||||||||||
NRG’s share of equity | 344 | 810 | ||||||||||
NRG’s share of net income | $ | 60 | $ | 104 | $ | 160 | ||||||
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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
Operating revenues | $ | 464 | $ | 432 | $ | 427 | ||||||
Operating income | 76 | 72 | 61 | |||||||||
Net income | 59 | 52 | 43 |
As of December 31, | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
Current assets | $ | 90 | $ | 121 | ||||
Other assets | 1,012 | 1,134 | ||||||
Total assets | 1,102 | 1,255 | ||||||
Current liabilities | 23 | 22 | ||||||
Other liabilities | 850 | 885 | ||||||
Equity | 229 | 348 | ||||||
Total liabilities and equity | $ | 1,102 | $ | 1,255 | ||||
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Note 15 — | Write Downs and Gains/(Losses) on Sales of Equity Method Investments |
Year ended December 31, | ||||||||||||||||
2006 | 2005 | 2004 | Segment(a) | |||||||||||||
(In millions) | ||||||||||||||||
Latin American Funds | $ | 3 | $ | — | $ | — | International | |||||||||
James River Power LLC | (6 | ) | — | (7 | ) | Corporate | ||||||||||
Cadillac | 11 | — | — | Corporate | ||||||||||||
Saguaro | — | (27 | ) | — | West | |||||||||||
Rocky Road | — | (20 | ) | — | Corporate | |||||||||||
Kendall | — | 4 | — | Corporate | ||||||||||||
Enfield | — | 12 | — | International | ||||||||||||
Commonwealth Atlantic Limited Partnership | — | — | (5 | ) | Corporate | |||||||||||
NEO Corporation | — | — | (4 | ) | Corporate | |||||||||||
Loy Yang | — | — | (1 | ) | International | |||||||||||
Calpine Cogeneration | — | — | 1 | Corporate | ||||||||||||
Total write downs and gains/(losses) on sales of equity method investments | $ | 8 | $ | (31 | ) | $ | (16 | ) | ||||||||
(a) | Conforms to NRG’s revised segment classification |
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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions, except per share data) | ||||||||||||
Basic earnings per share | ||||||||||||
Numerator: | ||||||||||||
Income from continuing operations | $ | 555 | $ | 72 | $ | 155 | ||||||
Deduct preferred stock dividends | (52 | ) | (20 | ) | (1 | ) | ||||||
Income available to common stockholders from continuing operations | 503 | 52 | 154 | |||||||||
Discontinued operations, net of tax | 66 | 12 | 31 | |||||||||
Net income available to common stockholders | $ | 569 | $ | 64 | $ | 185 | ||||||
Denominator: | ||||||||||||
Weighted average number of common shares outstanding | 129.0 | 84.6 | 99.6 | |||||||||
Basic earnings per share: | ||||||||||||
Income from continuing operations | $ | 3.90 | $ | 0.61 | $ | 1.55 | ||||||
Discontinued operations, net of tax | 0.51 | 0.15 | 0.31 | |||||||||
Net income | $ | 4.41 | $ | 0.76 | $ | 1.86 | ||||||
Diluted earnings per share | ||||||||||||
Numerator: | ||||||||||||
Income available to common stockholders from continuing operations | 503 | 52 | 154 | |||||||||
Add preferred stock dividends for dilutive preferred stock | 43 | — | 1 | |||||||||
Adjusted income from continuing operations | 546 | 52 | 155 | |||||||||
Discontinued operations, net of tax | 66 | 12 | 31 | |||||||||
Net income available to common stockholders | $ | 612 | $ | 64 | $ | 186 |
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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions, except per share data) | ||||||||||||
Denominator: | ||||||||||||
Weighted average number of common shares outstanding | 129.0 | 84.6 | 99.6 | |||||||||
Incremental shares attributable to the issuance of non-qualifying stock options (treasury stock method) | 0.4 | 0.2 | — | |||||||||
Incremental shares attributable to the issuance of non-vested restricted stock units (treasury stock method) | 0.9 | 0.4 | 0.4 | |||||||||
Incremental shares attributable to the assumed conversion of deferred stock units (treasury stock method) | 0.1 | 0.1 | 0.1 | |||||||||
Incremental shares attributable to the assumed conversion of the 4% preferred stock (if converted method) | 10.5 | — | 0.3 | |||||||||
Incremental shares attributable to the assumed conversion of the 5.75% preferred stock (if converted method) | 9.4 | — | — | |||||||||
Total dilutive shares | 150.3 | 85.3 | 100.4 | |||||||||
Diluted earnings per share: | ||||||||||||
Income from continuing operations | $ | 3.63 | $ | 0.61 | $ | 1.54 | ||||||
Discontinued operations, net of tax | 0.44 | 0.14 | 0.31 | |||||||||
Net income | $ | 4.07 | $ | 0.75 | $ | 1.85 | ||||||
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Note 17 — | Segment Reporting |
Year Ended December 31, | 2006 | 2005 | 2004 | |||||||||
Customer A | 10.0 | % | 39.7 | % | 32.0 | % | ||||||
Customer B | — | 16.3 | 10.2 | |||||||||
Total % | 10.0 | % | 56.0 | % | 42.2 | % | ||||||
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Year Ended December 31, 2006 | ||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||
Texas | Northeast | South Central | West | International | Thermal | Corporate | Elimination | Total | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 3,088 | $ | 1,543 | $ | 570 | $ | 146 | $ | 173 | $ | 152 | $ | 12 | $ | (61 | ) | $ | 5,623 | |||||||||||||||||
Operating expenses | 1,794 | 993 | 397 | 135 | 125 | 121 | 30 | (3 | ) | 3,592 | ||||||||||||||||||||||||||
Depreciation and amortization | 413 | 89 | 68 | 3 | 3 | 12 | 5 | — | 593 | |||||||||||||||||||||||||||
Operating income/(loss) | 881 | 461 | 105 | 8 | 45 | 19 | (23 | ) | (58 | ) | 1,438 | |||||||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | — | 1 | 57 | — | 2 | — | 60 | |||||||||||||||||||||||||||
Write downs and losses on sales of equity method investments | — | — | — | — | 3 | — | 5 | — | 8 | |||||||||||||||||||||||||||
Other income, net | 9 | 6 | — | 1 | 11 | 1 | 152 | (20 | ) | 160 | ||||||||||||||||||||||||||
Refinancing expenses | — | — | — | — | — | — | (187 | ) | — | (187 | ) | |||||||||||||||||||||||||
Interest expense | (138 | ) | (63 | ) | (57 | ) | — | (10 | ) | (7 | ) | (344 | ) | 20 | (599 | ) | ||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 752 | 404 | 48 | 10 | 106 | 13 | (395 | ) | (58 | ) | 880 | |||||||||||||||||||||||||
Income tax expense/(benefit) | 23 | — | — | (2 | ) | 26 | — | 278 | — | 325 | ||||||||||||||||||||||||||
Income/(loss) from continuing operations | 729 | 404 | 48 | 12 | 80 | 13 | (673 | ) | (58 | ) | 555 | |||||||||||||||||||||||||
Income on discontinued operations, net of income taxes | — | — | — | — | 49 | — | 17 | — | 66 | |||||||||||||||||||||||||||
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 | $ | 12,611 | $ | (10,488 | ) | $ | 19,435 | |||||||||||||||||
If the Company continued using the full year 2004 allocation method for corporate general and administrative expenses, the effect to the net income of each segment for the year ended December 31, 2006 would have been as follows: | ||||||||||||||||||||||||||||||||||||
Net income/(loss) as reported | $ | 729 | $ | 404 | $ | 48 | $ | 12 | $ | 129 | $ | 13 | $ | (656 | ) | $ | (58 | ) | $ | 621 | ||||||||||||||||
Increase/(decrease) in net income | 50 | 5 | 5 | 3 | 6 | 3 | (72 | ) | — | — | ||||||||||||||||||||||||||
Adjusted net income/(loss) | $ | 779 | $ | 409 | $ | 53 | $ | 15 | $ | 135 | $ | 16 | $ | (728 | ) | $ | (58 | ) | $ | 621 | ||||||||||||||||
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Year Ended December 31, 2005 | ||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||
Northeast | South Central | West | International | Thermal | Corporate | Elimination | Total | |||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Operating revenues | $ | 1,554 | $ | 560 | $ | 4 | $ | 165 | $ | 150 | $ | 6 | $ | (9 | ) | $ | 2,430 | |||||||||||||||
Operating expenses | 1,262 | 485 | 9 | 121 | 118 | 35 | (11 | ) | 2,019 | |||||||||||||||||||||||
Depreciation and amortization | 74 | 67 | 1 | 4 | 11 | 5 | — | 162 | ||||||||||||||||||||||||
Corporate relocation charges | — | — | — | — | — | 6 | — | 6 | ||||||||||||||||||||||||
Impairment charges | — | — | — | — | — | 6 | — | 6 | ||||||||||||||||||||||||
Operating income/(loss) | 218 | 8 | (6 | ) | 40 | 21 | (46 | ) | 2 | 237 | ||||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | 22 | 69 | — | 13 | — | 104 | ||||||||||||||||||||||||
Write downs and losses on sales of equity method investments | — | — | (27 | ) | 12 | — | (16 | ) | — | (31 | ) | |||||||||||||||||||||
Other income, net | 4 | — | 1 | 21 | 2 | 51 | (21 | ) | 58 | |||||||||||||||||||||||
Refinancing expenses | — | — | — | — | — | (65 | ) | — | (65 | ) | ||||||||||||||||||||||
Interest expense | — | (27 | ) | — | (8 | ) | (8 | ) | (162 | ) | 21 | (184 | ) | |||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 222 | (19 | ) | (10 | ) | 134 | 15 | (225 | ) | 2 | 119 | |||||||||||||||||||||
Income tax expense | — | — | — | 26 | 4 | 17 | — | 47 | ||||||||||||||||||||||||
Income/(loss) from continuing operations | 222 | (19 | ) | (10 | ) | 108 | 11 | (242 | ) | 2 | 72 | |||||||||||||||||||||
Income/(loss) on discontinued operations, net of income taxes | — | — | — | (2 | ) | 4 | 10 | — | 12 | |||||||||||||||||||||||
Net income/(loss) | $ | 222 | $ | (19 | ) | $ | (10 | ) | $ | 106 | $ | 15 | $ | (232 | ) | $ | 2 | $ | 84 | |||||||||||||
Balance Sheet | ||||||||||||||||||||||||||||||||
Equity investments in affiliates | 1 | — | 188 | 357 | — | 56 | — | 602 | ||||||||||||||||||||||||
Capital expenditures | 51 | 26 | — | 17 | 6 | 6 | — | 106 | ||||||||||||||||||||||||
Total assets | $ | 1,865 | $ | 1,200 | $ | 203 | $ | 1,548 | $ | 264 | $ | 4,983 | $ | (2,597 | ) | $ | 7,466 | |||||||||||||||
If the Company continued using the full year 2004 allocation method for corporate general and administrative expenses, the effect to the net income of each segment for the year ended December 31, 2005 would have been as follows: | ||||||||||||||||||||||||||||||||
Net income/(loss) as reported | $ | 222 | $ | (19 | ) | $ | (10 | ) | $ | 106 | $ | 15 | $ | (232 | ) | $ | 2 | $ | 84 | |||||||||||||
Increase/(decrease) in net income | 24 | 14 | — | 10 | 5 | (53 | ) | — | — | |||||||||||||||||||||||
Adjusted net income/(loss) | $ | 246 | $ | (5 | ) | $ | (10 | ) | $ | 116 | $ | 20 | $ | (285 | ) | $ | 2 | $ | 84 | |||||||||||||
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Year Ended December 31, 2004 | ||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||
Northeast | South Central | West | International | Thermal | Corporate | Elimination | Total | |||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Operating revenues | $ | 1,251 | $ | 434 | $ | 7 | $ | 159 | $ | 131 | $ | 129 | $ | (7 | ) | $ | 2,104 | |||||||||||||||
Operating expenses | 860 | 300 | 14 | 118 | 108 | 99 | (12 | ) | 1,487 | |||||||||||||||||||||||
Depreciation and amortization | 73 | 69 | 1 | 3 | 11 | 22 | — | 179 | ||||||||||||||||||||||||
Corporate relocation charges | — | — | — | — | — | 16 | — | 16 | ||||||||||||||||||||||||
Reorganization items | — | 1 | — | — | — | (14 | ) | — | (13 | ) | ||||||||||||||||||||||
Impairment charges | — | 3 | — | — | — | 42 | — | 45 | ||||||||||||||||||||||||
Operating income/(loss) | 318 | 61 | (8 | ) | 38 | 12 | (36 | ) | 5 | 390 | ||||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | 74 | 69 | — | 17 | — | 160 | ||||||||||||||||||||||||
Write downs and losses on sales of equity method investments | — | — | — | (1 | ) | (4 | ) | (11 | ) | — | (16 | ) | ||||||||||||||||||||
Other income, net | 4 | 1 | — | 7 | 1 | 30 | (21 | ) | 22 | |||||||||||||||||||||||
Refinancing expenses | — | — | — | — | — | (72 | ) | — | (72 | ) | ||||||||||||||||||||||
Interest expense | (1 | ) | (29 | ) | — | (11 | ) | (9 | ) | (226 | ) | 21 | (255 | ) | ||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 321 | 33 | 66 | 102 | — | (298 | ) | 5 | 229 | |||||||||||||||||||||||
Income tax expense | — | 1 | 2 | 17 | — | 54 | — | 74 | ||||||||||||||||||||||||
Income/(loss) from continuing operations | 321 | 32 | 64 | 85 | — | (352 | ) | 5 | 155 | |||||||||||||||||||||||
Income on discontinued operations, net of income taxes | — | — | — | 9 | 3 | 19 | — | 31 | ||||||||||||||||||||||||
Net income/(loss) | $ | 321 | $ | 32 | $ | 64 | $ | 94 | $ | 3 | $ | (333 | ) | $ | 5 | $ | 186 | |||||||||||||||
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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
Current | ||||||||||||
U.S. | $ | (27 | ) | $ | 19 | $ | — | |||||
Foreign | 21 | 15 | 15 | |||||||||
(6 | ) | 34 | 15 | |||||||||
Deferred | ||||||||||||
U.S. | 326 | 2 | 57 | |||||||||
Foreign | 5 | 11 | 2 | |||||||||
331 | 13 | 59 | ||||||||||
Total income tax | $ | 325 | $ | 47 | $ | 74 | ||||||
Effective tax rate | 36.9 | % | 39.5 | % | 32.3 | % |
Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
U.S. | $ | 767 | $ | (11 | ) | $ | 129 | |||||
Foreign | 113 | 130 | 100 | |||||||||
Total | $ | 880 | $ | 119 | $ | 229 | ||||||
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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions, except percentages) | ||||||||||||
Income from continuing operations before income taxes | $ | 880 | $ | 119 | $ | 229 | ||||||
Tax at 35% | 308 | 42 | 80 | |||||||||
State taxes, net of federal benefit | 34 | (1 | ) | 6 | ||||||||
Foreign operations | (23 | ) | (16 | ) | (13 | ) | ||||||
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 | ) | — | — | ||||||||
Permanent differences, reserves, other | 12 | (2 | ) | 1 | ||||||||
Income tax expense | $ | 325 | $ | 47 | $ | 74 | ||||||
Effective income tax rate | 36.9 | % | 39.5 | % | 32.3 | % |
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As of December 31, | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
Deferred tax liabilities: | ||||||||
Discount/premium on notes | $ | 25 | $ | 23 | ||||
Emissions allowances | 83 | 113 | ||||||
Difference between book and tax basis of property | 1,552 | 191 | ||||||
Derivative asset, net | 216 | — | ||||||
Goodwill | 51 | — | ||||||
Total deferred tax liabilities | 1,927 | 327 | ||||||
Deferred tax assets: | ||||||||
Deferred compensation, pension, accrued vacation and other reserves | 133 | 56 | ||||||
Derivative liability, net | — | 148 | ||||||
Differences between book and tax basis of contracts | 890 | 146 | ||||||
Non-depreciable property | 21 | 197 | ||||||
Intangibles amortization (excluding goodwill) | 145 | 12 | ||||||
Stock options | 16 | 10 | ||||||
Claimants reserve | 8 | 80 | ||||||
U.S. net operating loss carry forwards | 27 | 38 | ||||||
U.S. capital loss carryforwards | 485 | 238 | ||||||
Foreign net operating loss carryforwards | 75 | 70 | ||||||
Investments in projects | 6 | 63 | ||||||
Other | 11 | 3 | ||||||
Total deferred tax assets | 1,817 | 1,061 | ||||||
Valuation allowance | (581 | ) | (836 | ) | ||||
Net deferred tax assets | 1,236 | 225 | ||||||
Net deferred tax liability | $ | 691 | $ | 102 | ||||
As of December 31, | ||||||||
2006 | 2005 | |||||||
(In millions) | ||||||||
Current deferred tax liability | $ | 164 | $ | — | ||||
Non-current deferred tax asset | (27 | ) | (26 | ) | ||||
Non-current deferred tax liability | 554 | 128 | ||||||
Net deferred tax liability | $ | 691 | $ | 102 | ||||
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Weighted | Weighted Average | |||||||||||
Average | Grant-Date Fair | |||||||||||
Shares | Exercise Price | Value Per Share | ||||||||||
(In whole, except weighted average data) | ||||||||||||
Outstanding as of December 31, 2003 | 632,751 | $ | 24.03 | $ | 13.17 | |||||||
Granted | 330,000 | 21.46 | 10.20 | |||||||||
Outstanding as of December 31, 2004 | 962,751 | 23.15 | 12.15 | |||||||||
Outstanding as of December 31, 2004 | 962,751 | 23.15 | 12.15 | |||||||||
Granted | 134,000 | 38.80 | 13.23 | |||||||||
Forfeited | (1,500 | ) | 38.80 | 13.23 | ||||||||
Outstanding as of December 31, 2005 | 1,095,251 | 25.04 | 12.29 | |||||||||
Outstanding as of December 31, 2005 | 1,095,251 | 25.04 | 12.29 | |||||||||
Granted | 814,185 | 48.60 | 14.51 | |||||||||
Forfeited | (154,068 | ) | 38.43 | 12.53 | ||||||||
Exercised | (49,832 | ) | 21.48 | 9.77 | ||||||||
Outstanding at December 31, 2006 | 1,705,536 | 35.18 | 13.40 | |||||||||
Exercisable at December 31, 2006 | 831,911 | $ | 24.22 | $ | 12.64 | |||||||
Year ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Expected Volatility | 27.95%-29.64 | % | 29.75 | % | 51.05 | % | ||||||
Weighted-average volatility | 28.38 | % | 29.75 | % | 51.05 | % | ||||||
Expected dividends | — | — | — | |||||||||
Expected term (in years) | 4-6 | 5 | 5 | |||||||||
Risk free rate | 4.30%-5.05 | % | 4.16 | % | 2.86%-3.83 | % |
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Weighted Average | ||||||||
Grant-Date Fair | ||||||||
Shares | Value per share | |||||||
(In whole except weighted | ||||||||
average data) | ||||||||
Non-vested as of December 31, 2003 | 173,394 | $ | 24.03 | |||||
Granted | 750,100 | 20.94 | ||||||
Forfeited | (40,500 | ) | 20.02 | |||||
Exercised | (2,000 | ) | 19.90 | |||||
Non-vested as of December 31, 2004 | 880,994 | 21.59 | ||||||
Granted | 473,850 | 38.70 | ||||||
Forfeited | (66,250 | ) | 24.05 | |||||
Exercised | (2,650 | ) | 20.97 | |||||
Non-vested as of December 31, 2005 | 1,285,944 | 27.78 | ||||||
Granted | 212,643 | 47.73 | ||||||
Forfeited | (165,950 | ) | 30.69 | |||||
Exercised | (194,044 | ) | 25.55 | |||||
Non-vested at December 31, 2006 | 1,138,593 | $ | 31.48 | |||||
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Weighted Average | ||||||||
Grant-Date Fair | ||||||||
Shares | Value Per Share | |||||||
(In whole, except weighted | ||||||||
average data) | ||||||||
Outstanding as of December 31, 2003 | — | — | ||||||
Granted | 100,961 | $ | 20.36 | |||||
Conversions | (40,680 | ) | 20.49 | |||||
Outstanding as of December 31, 2004 | 60,281 | 20.31 | ||||||
Granted | 68,201 | 37.54 | ||||||
Conversions | (6,298 | ) | 28.20 | |||||
Outstanding as of December 31, 2005 | 122,184 | 29.21 | ||||||
Granted | 25,830 | 49.22 | ||||||
Conversions | (7,594 | ) | 38.75 | |||||
Outstanding at December 31, 2006 | 140,420 | $ | 32.38 | |||||
Outstanding | ||||||||||||||||
Grant Date | Vesting Period | Shares | Target Price | Maximum Price | ||||||||||||
August 1, 2005 | 3 | 36,300 | $ | 54.50 | $ | 63.75 | ||||||||||
January 3, 2006 | 3 | 83,800 | 67.37 | 79.49 | ||||||||||||
February 3, 2006 | 3 | 52,632 | 66.41 | 77.67 | ||||||||||||
May 31, 2006 | 5 | 4,400 | 69.90 | 81.74 | ||||||||||||
May 31, 2006 | 3 | 4,400 | 69.90 | 81.74 | ||||||||||||
August 1, 2006 | 3 | 1,400 | 68.27 | 79.83 | ||||||||||||
November 13, 2006 | 3 | 10,200 | 76.48 | 89.45 | ||||||||||||
December 18, 2006 | 3 | 12,200 | $ | 81.28 | $ | 95.05 |
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Weighted Average | ||||||||
Outstanding | Grant-Date Fair | |||||||
Shares | Value Per Share | |||||||
(In whole, except weighted | ||||||||
average data) | ||||||||
Non-vested as of December 31, 2004 | — | — | ||||||
Granted | 45,900 | $ | 29.87 | |||||
Exercised | — | — | ||||||
Forfeited | (1,000 | ) | 29.87 | |||||
Non-vested as of December 31, 2005 | 44,900 | 29.87 | ||||||
Granted | 202,532 | 35.23 | ||||||
Exercised | — | — | ||||||
Forfeited | (42,100 | ) | 33.12 | |||||
Non-vested at December 31, 2006 | 205,332 | $ | 34.49 | |||||
Year Ended December 31, | ||||||||
2006 | 2005 | |||||||
Expected volatility | 27.95%-29.64 | % | 29.75 | % | ||||
Weighted — average volatility | 28.38 | % | 29.75 | % | ||||
Expected dividends | — | — | ||||||
Expected term (in years) | 3-5 | 3 | ||||||
Risk free rate | 4.30%-5.04 | % | 4.09 | % |
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Total Non-vested | ||||||||||||||||||||
Compensation Cost | Weighted Average | |||||||||||||||||||
Compensation Expense | Not yet Recognized | Life Remaining | ||||||||||||||||||
Year ended December 31 | As of December 31 | |||||||||||||||||||
Award | 2006 | 2005 | 2004 | 2006 | 2006 | |||||||||||||||
(In millions, except weighted average data) | ||||||||||||||||||||
NQSO’s | $ | 5 | $ | 4 | $ | 7 | $ | 8 | 1.1 | |||||||||||
RSU’s | 10 | 8 | 5 | 16 | 1.1 | |||||||||||||||
DSU’s | 1 | 3 | 2 | — | — | |||||||||||||||
PU’s | 2 | — | — | 5 | 2.1 | |||||||||||||||
Total | 18 | 15 | 14 | 29 | ||||||||||||||||
Tax benefit recognized | $ | 7 | $ | 6 | $ | 6 | ||||||||||||||
Note 20 — | Related Party Transactions |
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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
Revenues from Related Parties Included in Operating Revenues | ||||||||||||
WCP(a) | ||||||||||||
O&M fees | $ | 1 | $ | 6 | $ | 4 | ||||||
AMA fees | — | 2 | 3 | |||||||||
Saguaro | ||||||||||||
O&M fees | — | — | — | |||||||||
Gladstone | ||||||||||||
O&M fees | 2 | 3 | 2 | |||||||||
MIBRAG | ||||||||||||
Consulting fees | 4 | 4 | 3 | |||||||||
Total | $ | 7 | $ | 15 | $ | 12 | ||||||
Expenses from Related Parties Included in Cost of Operations | ||||||||||||
MIBRAG | ||||||||||||
Cost of purchased coal | $ | 43 | $ | 41 | $ | 39 |
(a) | For the period January 1, 2006 to March 31, 2006 |
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(In millions) | ||||
2007 | $ | 39 | ||
2008 | 36 | |||
2009 | 34 | |||
2010 | 32 | |||
2011 | 31 | |||
Thereafter | 255 | |||
Total | $ | 427 | ||
(In millions) | ||||
2007 | $ | 1,614 | ||
2008 | 514 | |||
2009 | 420 | |||
2010 | 277 | |||
2011 | 228 | |||
Thereafter | 593 | |||
Total(a) | $ | 3,646 | ||
(a) | Includes only those coal transportation and gas commitments for 2007 as no other nominations were made as of December 31, 2006. |
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Year Ended December 31, | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(In millions) | ||||||||||||
Interest paid, net of amount capitalized | $ | 450 | $ | 257 | $ | 295 | ||||||
Income taxes paid | 18 | 21 | 34 | |||||||||
Non-cash investing and financing activities: | ||||||||||||
Reduction to fixed assets due to liquidated damages | — | — | 15 | |||||||||
Addition to fixed assets due to asset retirement obligations | 15 | 4 | — | |||||||||
Addition to treasury stock for the maximum purchase price adjustment | — | 8 | — |
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By Remaining Maturity at December 31, | ||||||||||||||||||||||||
2006 | ||||||||||||||||||||||||
Under | Over | 2005 | ||||||||||||||||||||||
1 year | 1-3 years | 3-5 years | 5 years | Total | Total | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Guarantees | ||||||||||||||||||||||||
Synthetic letters of credit | $523 | $ | 444 | $ | — | $ | — | $ | 967 | $ | — | |||||||||||||
Funded standby letters of credit | — | — | — | — | — | 312 | ||||||||||||||||||
Unfunded letters of credit and surety bonds | 97 | 56 | — | — | 153 | 4 | ||||||||||||||||||
Asset sales guarantee obligations | — | 13 | 110 | 21 | 144 | 123 | ||||||||||||||||||
Commercial sales arrangements | 133 | 51 | — | 420 | 604 | 91 | ||||||||||||||||||
Other guarantees | 1 | — | — | 28 | 29 | 91 | ||||||||||||||||||
Total guarantees | $754 | $ | 564 | $ | 110 | $ | 469 | $ | 1,897 | $ | 621 | |||||||||||||
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Ownership | Property, Plant & | Accumulated | Construction in | |||||||||||||
As of December 31, 2006 | Interest | Equipment | Depreciation | Progress | ||||||||||||
(In millions unless otherwise stated) | ||||||||||||||||
South Texas Project, Bay City, TX | 44.00 | % | $ | 2,877 | $ | 160 | $ | 10 | ||||||||
Big Cajun II Unit 3, New Roads, LA | 58.00 | 168 | 30 | 6 | ||||||||||||
Keystone, Shelocta, PA | 3.70 | 59 | 9 | 2 | ||||||||||||
Conemaugh, New Florence, PA | 3.72 | 71 | 11 | — |
Quarter Ended | ||||||||||||||||
2006 | ||||||||||||||||
December 31 | September 30 | June 30 | March 31 | |||||||||||||
(In millions, except per share data) | ||||||||||||||||
Operating revenues | $ | 1,144 | $ | 2,000 | $ | 1,404 | $ | 1,075 | ||||||||
Operating income | 100 | 718 | 411 | 209 | ||||||||||||
Income from continuing operations | (33 | ) | 373 | 200 | 15 | |||||||||||
Income on discontinued operations net of income taxes | 3 | 49 | 3 | 11 | ||||||||||||
Net income/(loss) | $ | (30 | ) | $ | 422 | $ | 203 | $ | 26 | |||||||
Weighted average number of common shares outstanding — basic | 125 | 136 | 137 | 117 | ||||||||||||
Income/(loss) from continuing operations per weighted average common share — basic | $ | (0.37 | ) | $ | 2.65 | $ | 1.36 | $ | 0.04 | |||||||
Income from discontinued operations per weighted average common share — basic | 0.02 | 0.35 | 0.02 | 0.09 | ||||||||||||
Net income/(loss) per weighted average common share — basic | $ | (0.35 | ) | $ | 3.00 | $ | 1.38 | $ | 0.13 | |||||||
Weighted average number of common shares outstanding — diluted | 125 | 159 | 159 | 119 | ||||||||||||
Income/(loss) from continuing operations per weighted average common share — diluted | $ | (0.37 | ) | $ | 2.34 | $ | 1.24 | $ | 0.04 | |||||||
Income from discontinued operations per weighted average common share — diluted | 0.02 | 0.31 | 0.02 | 0.09 | ||||||||||||
Net income/(loss) per weighted average common share — diluted | $ | (0.35 | ) | $ | 2.65 | $ | 1.26 | $ | 0.13 |
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Quarter Ended | ||||||||||||||||
2005 | ||||||||||||||||
December 31 | September 30 | June 30 | March 31 | |||||||||||||
(In millions, except per share data) | ||||||||||||||||
Operating revenues | $ | 707 | $ | 687 | $ | 502 | $ | 534 | ||||||||
Operating income | 161 | (8 | ) | 38 | 46 | |||||||||||
Income/(loss) from continuing operations | 76 | (37 | ) | 18 | 15 | |||||||||||
Income/(loss) on discontinued operations net of income taxes | (12 | ) | 10 | 6 | 8 | |||||||||||
Net income/(loss) | $ | 64 | $ | (27 | ) | $ | 24 | $ | 23 | |||||||
Weighted average number of common shares outstanding — basic | 81 | 84 | 87 | 87 | ||||||||||||
Income/(loss) from continuing operations per weighted average common share — basic | $ | 0.87 | $ | (0.51 | ) | $ | 0.16 | $ | 0.13 | |||||||
Income/(loss) from discontinued operations per weighted average common share — basic | (0.15 | ) | 0.12 | 0.07 | 0.08 | |||||||||||
Net income/(loss) per weighted average common share — basic | $ | 0.72 | $ | (0.39 | ) | $ | 0.23 | $ | 0.21 | |||||||
Weighted average number of common shares outstanding — diluted | 92 | 84 | 88 | 88 | ||||||||||||
Income/(loss) from continuing operations per weighted average common share — diluted | $ | 0.81 | $ | (0.51 | ) | $ | 0.15 | $ | 0.13 | |||||||
Income/(loss) from discontinued operations per weighted average common share — diluted | (0.13 | ) | 0.12 | 0.07 | 0.08 | |||||||||||
Net income/(loss) per weighted average common share — diluted | $ | 0.68 | $ | (0.39 | ) | $ | 0.22 | $ | 0.21 |
Arthur Kill Power LLC | NRG California Peaker Operations LLC | |
Astoria Gas Turbine Power LLC | NRG Connecticut Affiliate Services Inc. | |
Berrians I Gas Turbine Power LLC | NRG Devon Operations Inc. | |
Big Cajun II Unit 4 LLC | NRG Dunkirk Operations Inc. | |
Cabrillo Power I LLC | NRG El Segundo Operations Inc. | |
Cabrillo Power II LLC | NRG Generation Holdings, Inc. | |
Chickahominy River Energy Corp. | NRG Huntley Operations Inc. |
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Commonwealth Atlantic Power LLC Conemaugh Power LLC Connecticut Jet Power LLC Devon Power LLC Dunkirk Power LLC Eastern Sierra Energy Company El Segundo Power LLC El Segundo Power II LLC GCP Funding Company, LLC Hanover Energy Company Hoffman Summit Wind Project, LLC Huntley IGCC LLC Huntley Power LLC Indian River IGCC LLC Indian River Operations Inc. Indian River Power LLC James River Power LLC Kaufman Cogen LP Keystone Power LLC Lake Erie Properties Inc. Long Beach Generation LLC Louisiana Generating LLC Middletown Power LLC Montville IGCC LLC Montville Power LLC NEO California Power LLC NEO Chester-Gen LLC NEO Corporation NEO Freehold-Gen LLC NEO Landfill Gas Holdings Inc. NEO Power Services Inc. New Genco GP, LLC New Genco LP, LLC Norwalk Power LLC NRG Affiliate Services Inc. NRG Arthur Kill Operations Inc. NRG Asia-Pacific, Ltd. NRG Astoria Gas Turbine Operations Inc. NRG Bayou Cove LLC NRG Cabrillo Power Operations Inc. NRG Cadillac Operations Inc. | NRG International LLC NRG Kaufman LLC NRG Mesquite LLC NRG MidAtlantic Affiliate Services, Inc. NRG Middletown Operations Inc. NRG Montville Operations Inc. NRG New Jersey Energy Sales LLC NRG New Roads Holdings LLC NRG North Central Operations Inc. NRG Northeast Affiliate Services Inc. NRG Norwalk Harbor Operations Inc. NRG Operating Services, Inc. NRG Oswego Harbor Power Operations Inc. NRG Power Marketing Inc NRG Rocky Road LLC NRG Saguaro Operations Inc. NRG South Central Affiliate Services Inc. NRG South Central Generating LLC NRG South Central Operations Inc. NRG South Texas LP NRG Texas LLC NRG Texas LP NRG West Coast LLC NRG Western Affiliate Services Inc. Oswego Harbor Power LLC Padoma Wind Power, LLC Saguaro Power LLC San Juan Mesa Wind Project II, LLC Somerset Operations Inc. Somerset Power LLC Texas Genco Financing Corp. Texas Genco GP, LLC Texas Genco Holdings, Inc. Texas Genco LP, LLC Texas Genco Operating Services, LLC Texas Genco Services, LP Vienna Operations Inc. Vienna Power LLC WCP (Generation) Holdings LLC West Coast Power LLC |
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Guarantor | Non-Guarantor | Consolidated | ||||||||||||||||||
Subsidiaries | Subsidiaries | NRG Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Total operating revenues | $ | 5,282 | $ | 341 | $ | — | $ | — | $ | 5,623 | ||||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of operations | 3,040 | 234 | 2 | — | 3,276 | |||||||||||||||
Depreciation and amortization | 562 | 26 | 5 | — | 593 | |||||||||||||||
General, administrative and development | 115 | 17 | 184 | — | 316 | |||||||||||||||
Total operating costs and expenses | 3,717 | 277 | 191 | — | 4,185 | |||||||||||||||
Operating Income/(Loss) | 1,565 | 64 | (191 | ) | — | 1,438 | ||||||||||||||
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 losses on sales of equity method investments | (5 | ) | 13 | — | — | 8 | ||||||||||||||
Other income, net | 20 | 119 | 41 | (20 | ) | 160 | ||||||||||||||
Refinancing expenses | — | — | (187 | ) | — | (187 | ) | |||||||||||||
Interest expense | (232 | ) | (65 | ) | (322 | ) | 20 | (599 | ) | |||||||||||
Total other income/(expense) | (81 | ) | 125 | 528 | (1,130 | ) | (558 | ) | ||||||||||||
Income From Continuing Operations Before Income Taxes | 1,484 | 189 | 337 | (1,130 | ) | 880 | ||||||||||||||
Income tax expense | 549 | 45 | (269 | ) | — | 325 | ||||||||||||||
Income From Continuing Operations | 935 | 144 | 606 | (1,130 | ) | 555 | ||||||||||||||
Income from discontinued operations, net of income tax expense/(benefit) | — | 51 | 15 | — | 66 | |||||||||||||||
Net Income | $ | 935 | $ | 195 | $ | 621 | $ | (1,130 | ) | $ | 621 | |||||||||
(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 | $ | 20 | $ | 432 | $ | 343 | $ | — | $ | 795 | ||||||||
Restricted cash | 1 | 43 | — | — | 44 | |||||||||||||
Accounts receivable-trade, net | 332 | 40 | — | — | 372 | |||||||||||||
Inventory | 408 | 13 | — | — | 421 | |||||||||||||
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 | 32 | 736 | (747 | ) | 194 | ||||||||||||
Current assets — discontinued operations | — | — | — | — | — | |||||||||||||
Total current assets | 2,191 | 560 | 1,079 | (747 | ) | 3,083 | ||||||||||||
Net Property, Plant and Equipment | 11,178 | 403 | 19 | — | 11,600 | |||||||||||||
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 assetsheld-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 | |||||||||||||
Total other assets | 5,447 | 852 | 14,864 | (16,411 | ) | 4,752 | ||||||||||||
Total Assets | $ | 18,816 | $ | 1,815 | $ | 15,962 | $ | (17,158 | ) | $ | 19,435 | |||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||
Current Liabilities | ||||||||||||||||||
Current portion of long-term debt and capital leases | $ | 460 | $ | 101 | $ | 37 | $ | (468 | ) | $ | 130 | |||||||
Accounts payable — trade | (682 | ) | 287 | 727 | — | 332 | ||||||||||||
Derivative instruments valuation | 964 | — | — | — | 964 | |||||||||||||
Deferred income taxes | 23 | 7 | 134 | — | 164 | |||||||||||||
Accrued expenses and other current liabilities | 509 | 53 | 160 | (280 | ) | 442 | ||||||||||||
Total current liabilities | 1,274 | 448 | 1,058 | (748 | ) | 2,032 | ||||||||||||
Other Liabilities | ||||||||||||||||||
Long-term debt and capital leases | 5,504 | 869 | 8,791 | (6,517 | ) | 8,647 | ||||||||||||
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-currentout-of-market contracts | 897 | — | — | — | 897 | |||||||||||||
Other non-current liabilities | 385 | 26 | 24 | — | 435 | |||||||||||||
Non-current liabilities — discontinued operations | — | — | — | — | — | |||||||||||||
Total non-current liabilities | 8,218 | 797 | 8,999 | (6,517 | ) | 11,497 | ||||||||||||
Total liabilities | 9,492 | 1,245 | 10,057 | (7,265 | ) | 13,529 | ||||||||||||
Minority interest | — | 1 | — | — | 1 | |||||||||||||
3.625% Preferred Stock | — | — | 247 | — | 247 | |||||||||||||
Stockholders’ Equity | 9,324 | 569 | 5,658 | (9,893 | ) | 5,658 | ||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 18,816 | $ | 1,815 | $ | 15,962 | $ | (17,158 | ) | $ | 19,435 | |||||||
(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) | ||||||||||||||||||||
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 andout-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 | |||||||||||||||
Restructuring and impairment charges | — | — | — | — | — | |||||||||||||||
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/(Increase) in restricted cash, net | 2 | 4 | — | — | 6 | |||||||||||||||
Decrease/(Increase) 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 equipment | — | — | — | — | — | |||||||||||||||
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 | — | 12 | 1 | — | 13 | |||||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | — | 4 | — | — | 4 | |||||||||||||||
Net Increase in Cash and Cash Equivalents | 27 | 354 | (79 | ) | — | 302 | ||||||||||||||
Cash and Cash Equivalents at Beginning of Period | (7 | ) | 78 | 422 | — | 493 | ||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 20 | $ | 432 | $ | 343 | $ | — | $ | 795 | ||||||||||
(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) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Total operating revenues | $ | 2,095 | $ | 340 | $ | — | $ | (5 | ) | $ | 2,430 | |||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of operations | 1,600 | 243 | — | (5 | ) | 1,838 | ||||||||||||||
Depreciation and amortization | 133 | 24 | 5 | — | 162 | |||||||||||||||
General, administrative and development | 39 | 19 | 123 | — | 181 | |||||||||||||||
Impairment charges | 6 | — | — | — | 6 | |||||||||||||||
Corporate relocation charges | — | — | 6 | — | 6 | |||||||||||||||
Total operating costs and expenses | 1,778 | 286 | 134 | (5 | ) | 2,193 | ||||||||||||||
Operating Income/(Loss) | 317 | 54 | (134 | ) | — | 237 | ||||||||||||||
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 | 50 | 13 | (21 | ) | 58 | ||||||||||||||
Refinancing expense | — | 1 | (66 | ) | — | (65 | ) | |||||||||||||
Interest expense | (1 | ) | (63 | ) | (141 | ) | 21 | (184 | ) | |||||||||||
Total other income | 104 | 73 | 80 | (375 | ) | (118 | ) | |||||||||||||
Income/(Loss) From Continuing Operations Before Income Taxes | 421 | 127 | (54 | ) | (375 | ) | 119 | |||||||||||||
Income tax expense/(benefit) | 155 | 22 | (130 | ) | — | 47 | ||||||||||||||
Income From Continuing Operations | 266 | 105 | 76 | (375 | ) | 72 | ||||||||||||||
Income from discontinued operations, net of income tax expense | 5 | (1 | ) | 8 | — | 12 | ||||||||||||||
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 Energy, Inc. | Consolidated | |||||||||||||||||
Subsidiaries | Subsidiaries | (Note Issuer) | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current Assets | ||||||||||||||||||||
Cash and cash equivalents | $ | (7 | ) | $ | 78 | $ | 422 | $ | — | $ | 493 | |||||||||
Restricted cash | 3 | 46 | — | — | 49 | |||||||||||||||
Accounts receivable-trade, net | 214 | 250 | (215 | ) | — | 249 | ||||||||||||||
Inventory | 232 | 8 | — | — | 240 | |||||||||||||||
Deferred income taxes | 6 | (1 | ) | (5 | ) | — | — | |||||||||||||
Derivative instruments valuation | 385 | — | 2 | — | 387 | |||||||||||||||
Collateral on deposit in support of energy risk management activities | 438 | — | — | — | 438 | |||||||||||||||
Prepayments and other current assets | 63 | 41 | 551 | (468 | ) | 187 | ||||||||||||||
Current assets held for sale | 8 | — | 35 | — | 43 | |||||||||||||||
Current assets — discontinued operations | — | 98 | 12 | — | 110 | |||||||||||||||
Total current assets | 1,342 | 520 | 802 | (468 | ) | 2,196 | ||||||||||||||
Net Property, Plant and Equipment | 2,176 | 414 | 19 | — | 2,609 | |||||||||||||||
Other Assets | ||||||||||||||||||||
Investment in subsidiaries | 787 | — | 1,774 | (2,561 | ) | — | ||||||||||||||
Equity investments in affiliates | 243 | 359 | — | — | 602 | |||||||||||||||
Notes receivable, less current portion — affiliate, net | 76 | 457 | 1,397 | (1,473 | ) | 457 | ||||||||||||||
Intangible assets, net | 238 | 19 | — | — | 257 | |||||||||||||||
Derivative instruments valuation | 18 | — | — | — | 18 | |||||||||||||||
Funded letter of credit | — | — | 350 | — | 350 | |||||||||||||||
Deferred income taxes | — | 26 | — | — | 26 | |||||||||||||||
Other non-current assets | 22 | 19 | 83 | — | 124 | |||||||||||||||
Non-current assets — discontinued operations | — | 814 | 13 | — | 827 | |||||||||||||||
Total other assets | 1,384 | 1,694 | 3,617 | (4,034 | ) | 2,661 | ||||||||||||||
Total Assets | $ | 4,902 | $ | 2,628 | $ | 4,438 | $ | (4,502 | ) | $ | 7,466 | |||||||||
LIABILITIES AND STOCK HOLDERS’ EQUITY | ||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||
Current portion of long-term debt and capital leases | $ | 459 | $ | 90 | $ | 14 | $ | (468 | ) | $ | 95 | |||||||||
Accounts payable, trade | 158 | 67 | 16 | — | 241 | |||||||||||||||
Derivative instruments valuation | 678 | 1 | — | — | 679 | |||||||||||||||
Other bankruptcy settlement | — | 3 | — | — | 3 | |||||||||||||||
Other current liabilities | 60 | 41 | 68 | — | 169 | |||||||||||||||
Current liabilities — discontinued operations | — | 164 | 6 | — | 170 | |||||||||||||||
Total current liabilities | 1,355 | 366 | 104 | (468 | ) | 1,357 | ||||||||||||||
Other Liabilities | ||||||||||||||||||||
Long-term debt and capital leases | 1,397 | 620 | 1,866 | (1,473 | ) | 2,410 | ||||||||||||||
Deferred income taxes | 37 | 142 | (51 | ) | — | 128 | ||||||||||||||
Derivative instruments valuation | 25 | 11 | 20 | — | 56 | |||||||||||||||
Non-currentout-of-market contracts | 298 | — | — | — | 298 | |||||||||||||||
Other non-current liabilities | 126 | 23 | 21 | — | 170 | |||||||||||||||
Non-current liabilities — discontinued operations | — | 568 | 1 | — | 569 | |||||||||||||||
Total non-current liabilities | 1,883 | 1,364 | 1,857 | (1,473 | ) | 3,631 | ||||||||||||||
Total liabilities | 3,238 | 1,730 | 1,961 | (1,941 | ) | 4,988 | ||||||||||||||
Minority interest | — | 1 | — | — | 1 | |||||||||||||||
3.625% Preferred Stock | — | — | 246 | — | 246 | |||||||||||||||
Stockholders’ Equity | 1,664 | 897 | 2,231 | (2,561 | ) | 2,231 | ||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 4,902 | $ | 2,628 | $ | 4,438 | $ | (4,502 | ) | $ | 7,466 | |||||||||
(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) | ||||||||||||||||||||
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 andout-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/(increase) in restricted cash, net | 1 | 44 | — | — | 45 | |||||||||||||||
Decrease/(increase) 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 | — | 29 | 1 | — | 30 | |||||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | — | (2 | ) | — | — | (2 | ) | |||||||||||||
Change in Cash and Cash equivalents | (163 | ) | (124 | ) | (289 | ) | — | (576 | ) | |||||||||||
Cash and Cash Equivalents at Beginning of Period | 156 | 202 | 711 | — | 1,069 | |||||||||||||||
Cash and Cash Equivalents at End of Period | $ | (7 | ) | $ | 78 | $ | 422 | $ | — | $ | 493 | |||||||||
(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) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Total operating revenues | $ | 1,722 | $ | 389 | $ | — | $ | (7 | ) | $ | 2,104 | |||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of operations | 1,060 | 237 | — | (7 | ) | 1,290 | ||||||||||||||
Depreciation and amortization | 133 | 38 | 8 | — | 179 | |||||||||||||||
General, administrative and development | 118 | 23 | 56 | — | 197 | |||||||||||||||
Impairment charges | 3 | 27 | 15 | — | 45 | |||||||||||||||
Reorganization charges | 2 | — | (15 | ) | — | (13 | ) | |||||||||||||
Corporate relocation charges | — | — | 16 | — | 16 | |||||||||||||||
Total operating costs and expenses | 1,316 | 325 | 80 | (7 | ) | 1,714 | ||||||||||||||
Operating Income/(Loss) | 406 | 64 | (80 | ) | — | 390 | ||||||||||||||
Other Income (Expense) | ||||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 89 | — | 293 | (382 | ) | — | ||||||||||||||
Equity in earnings of unconsolidated affiliates | 92 | 69 | (1 | ) | — | 160 | ||||||||||||||
Write downs and gains/(losses) on sales of equity method investments | (16 | ) | (1 | ) | 1 | — | (16 | ) | ||||||||||||
Other income, net | 7 | 30 | 5 | (20 | ) | 22 | ||||||||||||||
Refinancing expense | — | — | (72 | ) | — | (72 | ) | |||||||||||||
Interest expense | — | (93 | ) | (182 | ) | 20 | (255 | ) | ||||||||||||
Total other income | 172 | 5 | 44 | (382 | ) | (161 | ) | |||||||||||||
Income/(Loss) From Continuing Operations Before Income Taxes | 578 | 69 | (36 | ) | (382 | ) | 229 | |||||||||||||
Income tax expense/(benefit) | 238 | 53 | (217 | ) | — | 74 | ||||||||||||||
Income From Continuing Operations | 340 | 16 | 181 | (382 | ) | 155 | ||||||||||||||
Income from discontinued operations, net of income tax expense | 3 | 23 | 5 | — | 31 | |||||||||||||||
Net Income | $ | 343 | $ | 39 | $ | 186 | $ | (382 | ) | $ | 186 | |||||||||
(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) | ||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||
Net income | $ | 343 | $ | 39 | $ | 186 | $ | (382 | ) | $ | 186 | |||||||||
Adjustments to reconcile net income to net cash provided (used) by operating activities | ||||||||||||||||||||
Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | (53 | ) | (38 | ) | — | 90 | (1 | ) | ||||||||||||
Depreciation and amortization of nuclear fuel | 133 | 69 | 13 | — | 215 | |||||||||||||||
Amortization and write-of of deferred financing costs and debt discount/premiums | — | 21 | 49 | — | 70 | |||||||||||||||
Amortization of intangibles andout-of-market contracts | 14 | 38 | — | — | 52 | |||||||||||||||
Amortization of unearned equity compensation | 2 | 1 | 11 | — | 14 | |||||||||||||||
Write down and losses/(gains) on sale of equity method investments | 16 | 1 | (1 | ) | — | 16 | ||||||||||||||
Loss on sale of equipment | 1 | — | — | — | 1 | |||||||||||||||
Restructuring and impairment charges | 3 | 27 | 15 | — | 45 | |||||||||||||||
Changes in derivatives | (71 | ) | (9 | ) | 6 | — | (74 | ) | ||||||||||||
Changes in deferred income taxes | 26 | (8 | ) | 118 | (79 | ) | 57 | |||||||||||||
Gain on sale of discontinued operations | (2 | ) | (26 | ) | 5 | — | (23 | ) | ||||||||||||
Changes in collateral deposits supporting energy risk management activities | (7 | ) | — | — | — | (7 | ) | |||||||||||||
Cash provided by changes in other working capital, net of acquisition and disposition affects | (34 | ) | 7 | 126 | (5 | ) | 94 | |||||||||||||
Net Cash Provided by Operating Activities | 371 | 122 | 528 | (376 | ) | 645 | ||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||
Capital expenditures | (82 | ) | (28 | ) | (9 | ) | — | (119 | ) | |||||||||||
Decrease/(increase) in restricted cash, net | 1 | (28 | ) | — | — | (27 | ) | |||||||||||||
Decrease/(increase) in notes receivable | (23 | ) | 16 | 25 | 7 | 25 | ||||||||||||||
Proceeds from sale of investments | 21 | 27 | 3 | — | 51 | |||||||||||||||
Proceeds from sale of equipment | 4 | — | — | — | 4 | |||||||||||||||
Proceeds on sale of discontinued operations | 2 | 251 | — | — | 253 | |||||||||||||||
Distributions/(investments) in subsidiaries | — | — | 82 | (82 | ) | — | ||||||||||||||
Return of capital from equity method investments/investment in projects | 4 | (16 | ) | 9 | — | (3 | ) | |||||||||||||
Net Cash Provided/(Used) by Investing Activities | (73 | ) | 222 | 110 | (75 | ) | 184 | |||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||
Capital contribution from parent | 10 | 33 | — | (43 | ) | — | ||||||||||||||
Payments of dividends | (407 | ) | (10 | ) | — | 417 | — | |||||||||||||
Payment for treasury stock | — | — | (405 | ) | — | (405 | ) | |||||||||||||
Proceeds from issuance of preferred stock, net | — | — | 406 | — | 406 | |||||||||||||||
Proceeds from issuance of long-term debt | — | (7 | ) | 1,304 | 36 | 1,333 | ||||||||||||||
Deferred debt issuance costs | — | — | (26 | ) | — | (26 | ) | |||||||||||||
Funded letter of credit | — | — | (100 | ) | — | (100 | ) | |||||||||||||
Payments for short and long-term debt | (41 | ) | (292 | ) | (1,200 | ) | 41 | (1,492 | ) | |||||||||||
Net Cash Used by Financing Activities | (438 | ) | (276 | ) | (21 | ) | 451 | (284 | ) | |||||||||||
Change in Cash from Discontinued Operations | — | (14 | ) | — | — | (14 | ) | |||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | — | 3 | — | — | 3 | |||||||||||||||
Change in Cash and Cash equivalents | (140 | ) | 57 | 617 | — | 534 | ||||||||||||||
Cash and Cash Equivalents at Beginning of Period | 296 | 144 | 95 | — | 535 | |||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 156 | $ | 201 | $ | 712 | $ | — | $ | 1,069 | ||||||||||
(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, 2006 | $ | 2 | $ | — | $ | — | $ | (1 | ) | $ | 1 | |||||||||
Year ended December 31, 2005 | 1 | 2 | — | (1 | ) | 2 | ||||||||||||||
Year ended December 31, 2004 | — | 1 | — | — | 1 | |||||||||||||||
Income tax valuation allowance, deducted from deferred tax assets | ||||||||||||||||||||
Year ended December 31, 2006 | $ | 836 | $ | (10 | ) | $ | (81 | ) | $ | (164 | ) | $ | 581 | |||||||
Year ended December 31, 2005 | 788 | 22 | 85 | (59 | ) | 836 | ||||||||||||||
Year ended December 31, 2004 | 1,321 | — | (277 | ) | (256 | ) | 788 |
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(Registrant)
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Signature | Title | Date | ||||
/s/ David W. Crane | President, Chief Executive Officer and Director | February 28, 2007 | ||||
/s/ Howard E. Cosgrove | Chairman of the Board | February 28, 2007 | ||||
/s/ John F. Chlebowski | Director | February 28, 2007 | ||||
/s/ Lawrence S. Coben | Director | February 28, 2007 | ||||
/s/ Stephen L. Cropper | Director | February 28, 2007 | ||||
/s/ William E. Hantke | Director | February 28, 2007 | ||||
/s/ Paul W. Hobby | Director | February 28, 2007 | ||||
/s/ Maureen Miskovic | Director | February 28, 2007 | ||||
/s/ Anne C. Schaumburg | Director | February 28, 2007 | ||||
/s/ Herbert H. Tate | Director | February 28, 2007 | ||||
/s/ Thomas H. Weidemeyer | Director | February 28, 2007 | ||||
/s/ Walter R. Young | Director | February 28, 2007 |
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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.(6) | ||
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.(6) | ||
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.(13) | ||
3 | .1 | Amended and Restated Certificate of Incorporation.(18) | ||
3 | .2 | Amended and Restated By-Laws.(7) | ||
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.(9) | ||
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.(19) | ||
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.(21) | ||
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.(29) | ||
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.(29) | ||
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.(15) | ||
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.(8) | ||
4 | .7 | Specimen of Certificate representing common stock of NRG Energy, Inc.(28) | ||
4 | .8 | Indenture, dated February 2, 2006, among NRG Energy, Inc. and Law Debenture Trust Company of New York.(22) | ||
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.(22) | ||
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.(22) | ||
4 | .11 | Form of 7.250% Senior Note due 2014.(22) | ||
4 | .12 | Form of 7.375% Senior Note due 2016.(22) | ||
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.(24) |
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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.(24) | ||
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.(25) | ||
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.(25) | ||
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.(30) | ||
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.(30) | ||
4 | .19 | Ninth Supplemental Indenture, dated November 21, 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.(31) | ||
4 | .20 | Form of 7.375% Senior Note due 2017.(31) | ||
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 | Asset Sales Agreement, dated December 23, 1998, between NRG Energy, Inc., and Niagara Mohawk Power Corporation.(5) | ||
10 | .4 | Amendment to the Asset Sales Agreement, dated June 11, 1999, between NRG Energy, Inc., and Niagara Mohawk Power Corporation.(5) | ||
10 | .5* | Severance Agreement between NRG Energy, Inc. and John P. Brewster dated July 23, 2003.(2) | ||
10 | .6* | Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Officers and Key Management.(17) | ||
10 | .7* | Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Directors.(17) | ||
10 | .8* | Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified Stock Option Agreement.(10) | ||
10 | .9* | Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock Unit Agreement.(10) | ||
10 | .10* | Form of NRG Energy, Inc. Long Term Incentive Plan Performance Unit Agreement.(14) | ||
10 | .11* | Annual Incentive Plan for Designated Corporate Officers.(11) | ||
10 | .12* | Letter Agreement, dated March 5, 2004, between NRG Energy, Inc. and John P. Brewster.(12) | ||
10 | .13* | Letter Agreement, dated March 5, 2004, between NRG Energy, Inc. and Timothy W. O’Brien.(12) | ||
10 | .14* | Letter Agreement, dated February 19, 2004, between NRG Energy, Inc. and Robert C. Flexon.(12) | ||
10 | .15 | Railroad Car Full Service Master Leasing Agreement, dated as of February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(17) | ||
10 | .16 | Commitment Letter, dated February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(17) | ||
10 | .17 | 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.(16) | ||
10 | .18 | 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.(16) | ||
10 | .19* | Letter Agreement, dated June 21, 2005, between NRG Energy, Inc. and Kevin T. Howell.(20) | ||
10 | .20 | Stock Purchase Agreement, dated as of August 10, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(19) |
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10 | .21 | Accelerated Share Repurchase Agreement, dated as of August 11, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(19) | ||
10 | .22 | 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.(23) | ||
10 | .23 | Amended and Restated Master Power Purchase and Sale Agreement, dated February 2, 2006, by and between J. Aron & Company and Texas Genco II, LP (including the cover sheet and confirmation letter thereto) (portions of this document have been omitted pursuant to a request for confidential treatment and filed separately with the SEC).(27) | ||
10 | .24 | 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).(27) | ||
10 | .25* | Employment Agreement, dated March 3, 2006, between NRG Energy, Inc. and David Crane.(27) | ||
10 | .26* | CEO and CFO Compensation Table.(32) | ||
10 | .27* | NRG Energy, Inc. Director Compensation Table.(26) | ||
10 | .28 | Limited Liability Company Agreement of NRG Common Stock Finance I LLC.(29) | ||
10 | .29 | Limited Liability Company Agreement of NRG Common Stock Finance II LLC.(29) | ||
10 | .30 | Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse International and Credit Suisse Securities (USA) LLC.(29) | ||
10 | .31 | 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.(29) | ||
10 | .32 | 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.(29) | ||
10 | .33 | 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.(29) | ||
10 | .34 | Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance I LLC.(29) | ||
10 | .35 | Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance II LLC.(29) | ||
10 | .36 | Credit Agreement, dated February 2, 2006, as amended and restated on November 21, 2006, among NRG Energy, Inc., a Delaware corporation, the Lenders from time to time party thereto, Morgan Stanley Senior Funding, Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as joint lead book runners and joint lead arrangers, Morgan Stanley Senior Funding, Inc., as administrative agent, Morgan Stanley & Co. Incorporated, as collateral agent, and Merrill Lynch Capital Corporation, as syndication agent.(29) | ||
10 | .37* | Amended and Restated Long-Term Incentive Plan, dated December 8, 2006.(32) | ||
10 | .38* | NEO 2006 AIP Payout and 2007 Base Salary Table.(1) | ||
10 | .39* | NRG Energy, Inc. Executive and Key Management Change-in-Control and General Severance Agreement, dated May 24, 2006.(1) | ||
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) | ||
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. |
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(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 quarterly report onForm 10-Q for the quarter ended June 30, 1999. | |
(6) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 19, 2003. | |
(7) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on March 3, 2005. | |
(8) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 27, 2004. | |
(9) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 27, 2004. | |
(10) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended September 30, 2004. | |
(11) | Incorporated herein by reference to NRG Energy, Inc.’s 2004 proxy statement on Schedule 14A filed on July 12, 2004. | |
(12) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended March 31, 2004. | |
(13) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on October 3, 2005. | |
(14) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended June 30, 2005. | |
(15) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on January 4, 2006. | |
(16) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 28, 2005. | |
(17) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 30, 2005. | |
(18) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 24, 2005. | |
(19) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 11, 2005. | |
(20) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 3, 2005. | |
(21) | Incorporated herein by reference to NRG Energy, Inc.’sForm 8-A filed on January 27, 2006. | |
(22) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on February 6, 2006. | |
(23) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on February 8, 2006. | |
(24) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on March 16, 2006. | |
(25) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 3, 2006. | |
(26) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 4, 2006. | |
(27) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 7, 2006. | |
(28) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on August 4, 2006. | |
(29) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 10, 2006. | |
(30) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 14, 2006. | |
(31) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 27, 2006. | |
(32) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 14, 2006. |
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