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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, 2005. | ||
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 | 08540 | |
(Address of principal executive offices) | (Zip Code) |
Title of Each Class | Name of Exchange on Which Registered | |
5.75% Mandatorily Convertible Preferred Stock | New York Stock Exchange |
Class | Outstanding at March 3, 2006 | |
Common Stock, par value $0.01 per share | 136,975,275 |
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APB | Accounting Principles Board | |
APB 18 | APB Opinion No. 18,“The Equity Method of Accounting for Investments in Common Stock.” | |
Average gross heat rate | The product of dividing(a) fuel consumed in BTU’s by(b) KWh generated. | |
BART | Best Available Retrofit Technology | |
Baseload capacity | Electric power generation capacity normally expected to serve loads on an around-=the-clock basis throughout the calendar year. | |
BTA | Best Technology Available | |
BTU | British Thermal Unit | |
CAA | Clean Air Act | |
CAIR | Clean Air Interstate Rule | |
Cal ISO | 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. | |
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, | |
CTDEP | Connecticut Department of Environmental Protection | |
CWA | Clean Water Act | |
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 91-6 | EITF No. 91-6,“Revenue Recognition of Long-Term Power Sales Contracts.” | |
EITF 02-3 | EITF Issue No. 02-3,“Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” | |
EITF 03-11 | EITF Issue No. 03-11,“Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in EITF Issue No. 02-03.” | |
EPA | Environmental Protection Agency |
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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 | |
ERISA | Employee Retirement Income Security Act | |
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 | |
FF-ACI | Fabric Filter with Activated Carbon Injection | |
FGD | Flue Gas Desulphurization | |
FIN | Financial Accounting Standards Board Interpretation | |
FIN 45 | FIN No. 45“Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” | |
FIN 46R | FIN No. 46 (Revised 2003),“Consolidation of Variable Interest Entities” | |
FIP | Federal Implementation Plan | |
Fresh Start | Reporting requirements as defined by SOP 90-7 | |
FSP | FASB Staff Position (interpretations of standards issued by the staff of the FASB) | |
FSP 106-1 | FSP 106-1,“Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” | |
FSP 106-2 | FSP 106-2,“Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” | |
GHG | Greenhouse Gases | |
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. | |
KWh | kilowatt-hours | |
LADEQ | Louisiana Department of Environmental Quality | |
LIBOR | London Inter-Bank Offered Rate | |
LNB/OFA | Low NOxBurner with Over Fire Air | |
MACT | Maximum Achievable Control Technology | |
MADEP | Massachusetts Department of Environmental Protection | |
Moody’s | Moody’s Investors Services, Inc. | |
MISO | Midwest Independent Transmission System Operator | |
MW | Megawatts | |
MWh | Saleable megawatt hours net of internal/parasitic load megawatt-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, 2005 |
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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 | |
NiMo | Niagara Mohawk Power Corporation | |
NOx | Nitrogen oxides | |
NOL | Net operating loss | |
NRC | United States Nuclear Regulatory Commission | |
NSR | New Source Review | |
NYISO | New York Independent System Operator. | |
NYSDEC | New York Department of Environmental Conservation | |
OCI | Other Comprehensive Income | |
OTC | Ozone Transport Commission | |
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. | |
PM2.5 | Fine particulate matter | |
PSD | Prevention of Significant Deterioration | |
PUCT | Public Utility Commission of Texas | |
Powder River Basin, or PRB Coal | Coal produced in the northeastern Wyoming and southeastern Montana, which coal has low sulfur content | |
RCRA | Resource Conservation and Recovery Act | |
RECLAIM | Regional Clean Air Incentives Market | |
RGGI | Regional Greenhouse Gas Initiative | |
RMR | Reliability must-run | |
RTC | RECLAIM Trading Credit | |
RTO | Regional transmission organization | |
S&P | Standard & Poor’s, a division of the McGraw Hill Companies | |
SARA | Superfund Amendments and Reauthorization Act of 1986 | |
Sarbanes-Oxley | Sarbanes — Oxley Act of 2002 | |
SCAQMD | South Coast Air Quality Management District | |
SCR | Selective Catalytic Reduction | |
SDG&E | San Diego Gas & Electric | |
SEC | United States Securities and Exchange Commission | |
SERC | Southeastern Electric Reliability Council/ Entergy | |
SFAS | Statement of Financial Accounting Standards issued by the FASB | |
SFAS 71 | SFAS No. 71“Accounting for the Effects of Certain Types of Regulation” | |
SFAS 87 | SFAS No. 87,“Employers’ Accounting for Pensions” | |
SFAS 106 | SFAS No. 106,“Employers’ Accounting for Postretirement Benefits Other Than Pensions” | |
SFAS 109 | SFAS No. 109,“Accounting for Income Taxes” | |
SFAS 123 | SFAS No. 123,“Accounting for Stock-Based Compensation” | |
SFAS 123R | SFAS No. 123 (revised 2004),“Share-Based Payment” | |
SFAS 133 | SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities” |
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SFAS 140 | SFAS No. 140,“Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, a replacement of FASB Statement 125” | |
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” | |
SIP | State Implementation Plan | |
SO2 | Sulfur dioxide | |
SOP | Statement of Position issued by the American Institute of Certified Public Accountants | |
SOP 90-7 | Statement of Position 90-7“Financial Reporting by Entities in Reorganization Under the Bankruptcy Code” | |
SPP | Southwest Power Pool | |
STP | South Texas Project — Texas Genco’s nuclear generating facility located in Bay City, TX of which we own a 44% interest | |
TCEQ | Texas Commission on Environmental Quality | |
Texas Genco | Texas Genco LLC | |
US | United States of America | |
USEPA | US Environmental Protection Agency | |
US GAAP | Accounting principles generally accepted in the US | |
WCP | WCP (Generation) Holdings, Inc. |
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(1) | Reflects only domestic generation capacity; 19 MW of wood-fired generation capacity not shown. |
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Alternative | ||||||||||||||||||||||||
Energy | Capacity | Energy | Other | Total | ||||||||||||||||||||
Region | Revenues | Revenues | Revenues | O&M Fees | Revenues*** | Revenues | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Northeast | $ | 1,444 | $ | 291 | $ | — | $ | — | $ | (181 | ) | $ | 1,554 | |||||||||||
South Central | 330 | 186 | — | — | 36 | 552 | ||||||||||||||||||
Western* | 1 | — | — | — | — | 1 | ||||||||||||||||||
Other | 11 | 5 | 2 | — | (3 | ) | 15 | |||||||||||||||||
Total North America Power Generation** | $ | 1,786 | $ | 482 | $ | 2 | $ | — | $ | (148 | ) | $ | 2,122 | |||||||||||
* | Consists of our wholly-owned subsidiary, NEO California LLC. Does not include revenues which were produced by assets in which we have a 50% equity interest, primarily West Coast Power, and are reported under the equity method of accounting. |
** | For additional information — see Item 15 — Note 21 of the Consolidated Financial Statements for our consolidated revenues by segment disclosures. |
*** | Includes miscellaneous revenues from the sale of natural gas, recovery of incurred costs under reliability must-run agreements, revenues received under leasing arrangements, revenues from maintenance, revenues from the sale of ancillary services and revenues from entering into certain financial transactions, offset by contract amortization. |
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 | |||||||||||||||
Northeast* | 7,099 | 15,251,449 | 87.2% | 11,146 | 22.9% | |||||||||||||||
South Central | 2,395 | 10,116,622 | 90.9% | 10,518 | 50.6% | |||||||||||||||
Western** | 1,044 | 1,588,962 | 86.5% | 11,109 | 18.0% | |||||||||||||||
Other North America | 1,467 | 247,721 | 90.6% | 14,297 | 3.4% |
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Year Ended December 31, 2004 | ||||||||||||||||||||
Annual | ||||||||||||||||||||
Net | Equivalent | Average Net | ||||||||||||||||||
Net Owned | Generation | Availability | Heat Rate | Net Capacity | ||||||||||||||||
Region | Capacity (MW) | (MWh) | Factor | Btu/KWh | Factor | |||||||||||||||
Northeast* | 7,099 | 13,205,040 | 85.6% | 10,823 | 19.8% | |||||||||||||||
South Central | 2,395 | 10,470,786 | 92.1% | 10,494 | 52.9% | |||||||||||||||
Western** | 1,044 | 2,291,844 | 88.4% | 10,624 | 25.6% | |||||||||||||||
Other North America*** | 1,467 | 147,376 | 97.3% | N/A | 2.4% |
* | Net Generation and the other metrics do not include Keystone and Conemaugh. |
** | Includes 50% of the generation owned through our West Coast Power partnership. |
*** | Excludes operations for Kendall, McClain and Batesville which were sold during 2004. |
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 | |||||||||||||||
Flinders Northern Power Station | 480 | 3,990,642 | 95.8% | 10,900 | 94.9% | |||||||||||||||
Flinders Playford Power Station | 220 | 458,180 | 57.9% | 15,900 | 23.8% | |||||||||||||||
Gladstone* | 605 | 2,808,335 | 93.3% | 10,300 | 53.0% |
Year Ended December 31, 2004 | ||||||||||||||||||||
Annual | ||||||||||||||||||||
Net | Equivalent | Average Net | ||||||||||||||||||
Net Owned | Generation | Availability | Heat Rate | Net Capacity | ||||||||||||||||
Region | Capacity (MW) | (MWh) | Factor | Btu/KWh | Factor | |||||||||||||||
Flinders Northern Power Station | 480 | 3,924,196 | 93.2% | 11,400 | 93.1% | |||||||||||||||
Flinders Playford Power Station | 220 | 365,642 | 46.0% | 16,300 | 18.9% | |||||||||||||||
Gladstone* | 605 | 2,879,236 | 83.2% | 10,200 | 54.2% |
* | Includes 37.5% of the generation owned through our Gladstone Unincorporated Joint Venture. |
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Annual | Annual | |||||||||||||||||||||||||||
Average for | Average for | |||||||||||||||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | 2006-2007 | 2006-2010 | ||||||||||||||||||||||
Net Baseload Capacity (MW) | 5,294 | 5,340 | 5,340 | 5,340 | 5,340 | 5,317 | 5,331 | |||||||||||||||||||||
Total Baseload Sales (MW)(1) | 4,375 | 4,267 | 4,157 | 3,449 | 1,395 | 4,321 | 3,529 | |||||||||||||||||||||
Percentage Baseload Capacity Sold Forward | 83 | % | 80 | % | 78 | % | 65 | % | 26 | % | 81 | % | 66 | % | ||||||||||||||
Weighted Average Forward Price ($ per MWh)(2) | $ | 44 | $ | 39 | $ | 41 | $ | 47 | $ | 51 | $ | 41 | $ | 43 | ||||||||||||||
Total Revenues Sold Forward ($ in millions)(2) | $ | 1,690 | $ | 1,443 | $ | 1,505 | $ | 1,434 | $ | 621 | $ | 1,566 | $ | 1,338 |
(1) | Includes amounts under fixed price firm and non-firm power sales contracts and amounts financially hedged under natural gas swap contracts. The forward natural gas swap quantities are reflected in equivalent MW and are derived by first dividing the quantity of MMBtu of natural gas hedged by the forward market heat rate (in MMBtu/ MWh, mid-point of the bid and offer as quoted by |
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brokers in the market of the relevant Electric Reliability Council of Texas zones as of December 30, 2005) to arrive at the equivalent MWh hedged which is then divided by 8,760 to arrive at MW hedged. |
(2) | Includes amounts under fixed price power sales contracts and amounts financially hedged under natural gas swap contracts. |
Northeast |
Annual | ||||||||||||||||||||||||
Average for | ||||||||||||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | 2006-2007 | |||||||||||||||||||
Net Baseload Capacity (MW) | 1,876 | 1,876 | 1,876 | 1,876 | 1,876 | 1,876 | ||||||||||||||||||
Total Baseload Sales (MW) | 1,410 | 608 | — | — | — | 1,009 | ||||||||||||||||||
Percentage Baseload Capacity Sold Forward | 75 | % | 32 | % | — | % | — | % | — | % | 54 | % | ||||||||||||
Weighted Average Forward Price ($ per MWh) | $ | 72 | $ | 76 | $ | — | $ | — | $ | — | $ | 74 | ||||||||||||
Total Revenues Sold Forward ($ in millions) | $ | 885 | $ | 406 | $ | — | $ | — | $ | — | $ | 645 |
South Central |
Annual | Annual | |||||||||||||||||||||||||||
Average for | Average for | |||||||||||||||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | 2006-2007 | 2006-2010 | ||||||||||||||||||||||
Net Baseload Capacity (MW) | 1,489 | 1,489 | 1,489 | 1,489 | 1,489 | 1,489 | 1,489 | |||||||||||||||||||||
Total Baseload Sales (MW)(1) | 1,150 | 1,097 | 1,088 | 1,015 | 1,008 | 1,124 | 1,072 | |||||||||||||||||||||
Percentage Baseload Capacity Sold Forward | 77 | % | 74 | % | 73 | % | 68 | % | 68 | % | 75 | % | 72 | % | ||||||||||||||
Weighted Average Forward Price ($ per MWh) | $ | 33 | $ | 32 | $ | 33 | $ | 34 | $ | 36 | $ | 33 | $ | 34 | ||||||||||||||
Total Revenues Sold Forward ($ in millions) | $ | 307 | $ | 308 | $ | 314 | $ | 303 | $ | 316 | $ | 307 | $ | 310 |
(1) | Total Baseload Sales volumes for South Central are estimated volumes using historical load information. |
Western |
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Australia |
Other |
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12 Months Starting | |||||||||||||||||||||
Jan 1, | Jan 1, | Jan 1, | Jan 1, | Jan 1, | |||||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | |||||||||||||||||
Equivalent Net Sales secured by Second Lien Structure(1) | |||||||||||||||||||||
In MWh | 2,081 | 3,067 | 2,513 | 2,999 | 1,395 | ||||||||||||||||
As a percentage of net baseload capacity in collateral pool as of February 2, 2006 | 30 | % | 44 | % | 36 | % | 43 | % | 20 | % |
(1) | Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region. |
Letters of | Collateral | |||||||||||
Credit Rating | Credit | Cash | Posted | |||||||||
(In millions) | ||||||||||||
A– and above | $ | 616 | $ | 392 | $ | 1,008 | ||||||
BBB– through BBB+ | 99 | 39 | 138 | |||||||||
Below BBB- | 7 | 4 | 11 | |||||||||
Not Rated(1) | 38 | 3 | 41 | |||||||||
Total | $ | 760 | $ | 438 | $ | 1,198 | ||||||
(1) | Not Rated indicates that no rating has been issued, or that an external rating agency (for example, Standard & Poor’s or Moody’s) does not rate a particular obligation as a matter of policy. The Not Rated row above consists of collateral posted to 17 counterparties, mainly gas producers. |
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Process | Supplier(s) | Procurement Status | ||||
Step 1 | Yellow cake U(3)O(8). Conversion to uranium hexafluoride (UF(6)) | Contracts with Cameco (Canada) and Cogema/Arriba (France) combine these steps. | 100% covered through mid-2011 and then 25% covered through 2021. | |||
Step 2 | Enrichment of U235 content | Urenco (Germany), Cogema/ Arriba (France), Louisiana Enrichment Services, or LES(1)(joint venture between Westinghouse & Urenco). | Urenco and Cogema contracts cover through mid-2008. Contract with Urenco/LES through 2027/2028. | |||
Step 3 | Fabrication of fuel rods | Westinghouse. | Contract covers life of operating license. |
(1) | Enrichment by LES assumes successful completion of LES licensing and construction of facility in New Mexico. |
Closing | Gain/(Loss) | Debt | |||||||||||||||||||||||
Asset (Location) | Type | Segment | Date | Proceeds | on Disposition | Reduction | |||||||||||||||||||
(In millions) | |||||||||||||||||||||||||
Enfield, England | Equity investment | Other International | 4/1/2005 | $ | 65 | $ | 12 | $ | — | ||||||||||||||||
Kendall, IL | Equity investment | Other North America | 8/8/2005 | 5 | 4 | — | |||||||||||||||||||
Northbrook New York, NY and Northbrook Energy (Multi- state) | Discontinued operation | Other North America | 8/11/2005 | 36 | 12 | 44 | |||||||||||||||||||
Bourbonnais, IL | Land sale | Other North America | 8/31/2005 | 2 | — | — | |||||||||||||||||||
Kaufman, TX | Land sale | Other North America | 12/22/2005 | 5 | 4 | — | |||||||||||||||||||
Total | $ | 113 | $ | 32 | $ | 44 | |||||||||||||||||||
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Reorganized NRG (excluding Texas Genco) |
Predecessor Company |
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SO2 | NOx | Hg | Particulate | |||||||||||||||||||||||||||||
Control | Install | Control | Install | Control | Install | Control | Install | |||||||||||||||||||||||||
Units | Equipment | Date | Equipment | Date | Equipment | Date | Equipment | Date | ||||||||||||||||||||||||
Huntley 67 | Wet FGD(1) | 2013 | SNCR | 2010 | FF-ACI(2) | 2011 | ESP | 1973 | ||||||||||||||||||||||||
Huntley 68 | Wet FGD(1) | 2013 | SNCR | 2011 | FF-ACI(2) | 2009 | ESP | 1973 | ||||||||||||||||||||||||
Dunkirk 1 | None | — | SNCR | 2010 | FF-ACI(2) | 2010 | ESP | 1974 | ||||||||||||||||||||||||
Dunkirk 2 | None | — | SNCR | 2011 | FF-ACI(2) | 2011 | ESP | 1974 | ||||||||||||||||||||||||
Dunkirk 3 | None | — | SNCR | 2010 | FF-ACI(2) | 2011 | ESP | 1975 | ||||||||||||||||||||||||
Dunkirk 4 | None | — | SNCR | 2011 | FF-ACI(2) | 2010 | ESP | 1976 | ||||||||||||||||||||||||
Indian River 1 | In-Duct Scrubber | 2012 | SNCR & LNB(3) | 2008 | Co-Benefit of Scrubbers | 2012 | ESP (IR1-3) | 1976 | ||||||||||||||||||||||||
Indian River 2 | In-Duct Scrubber | 2013 | SNCR & LNB(3) | 2008 | Co-Benefit of Scrubbers | 2013 | ESP (IR1-3) | 1976 | ||||||||||||||||||||||||
Indian River 3 | In-Duct Scrubber | 2012 | LNB(3) & SNCR | 2008 | Co-Benefit of Scrubbers | 2012 | ESP (IR1-3) | 1980 | ||||||||||||||||||||||||
upgrade | ||||||||||||||||||||||||||||||||
Indian River 4 | Dry Scrubber | 2011 | LNB(3) & SNCR | 2008 | Co-Benefit of Scrubbers | 2011 | ESP (IR1-3) | 1980 | ||||||||||||||||||||||||
upgrade | ||||||||||||||||||||||||||||||||
Big Cajun II 1 | Dry Scrubber | 2011 | None | ACI(2) | 2012 | ESP | 1981 | |||||||||||||||||||||||||
Big Cajun II 2 | Dry Scrubber | 2010 | SCR(4) | 2010 | ACI(2) | 2011 | ESP | 1981 | ||||||||||||||||||||||||
Big Cajun II 3 | Dry Scrubber | 2013 | SCR(4) | 2013 | ACI(2) | 2014 | ESP | 1983 | ||||||||||||||||||||||||
Limestone | FGD | 1986-87 | LNB/OFA(3) | 2000-01 | Co-Benefit of Scrubbers | — | ESP | 1986-87 | ||||||||||||||||||||||||
WA Parish 5,6,7 | None | NA | SCR & LNB/OFA(3) | 2000-04 | None | — | FF | 1988 | ||||||||||||||||||||||||
WA Parish 8 | FGD | 1982 | SCR & LNB/OFA(3) | 2000-04 | Co-Benefit of Scrubber | — | FF | 1988 |
(1) | FGD stands for Flue Gas Desulfurization |
(2) | FF-ACI stands for Fabric Filter with Activated Carbon Injection |
(3) | LNB/ OFA stands for Low NOx Burner with Over Fire Air |
(4) | SCR stands for Selective Catalytic Reduction |
TEXAS (ERCOT) |
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Net Generation (MWh) | |||||||||||||
2005 | 2004 | 2003 | |||||||||||
(In thousands) | |||||||||||||
Coal | 31,299 | 31,222 | 29,754 | ||||||||||
Gas | 6,806 | 7,701 | 10,701 | ||||||||||
Nuclear | 6,412 | 6,580 | 4,843 | ||||||||||
Total | 44,517 | 45,503 | 45,298 | ||||||||||
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Net Generation | ||||||||||||||||
Capacity | ||||||||||||||||
Generation Sites | Location | % Owned | (MW)(1) | Primary Fuel Type(2) | ||||||||||||
Solid Fuel Baseload Units: | ||||||||||||||||
W. A. Parish(3) | Thompsons, TX | 100 | % | 2,463 | Low Sulfur Coal Lignite/Low Sulfur | |||||||||||
Limestone | Jewett, TX | 100 | % | 1,614 | Coal | |||||||||||
South Texas Project(4) | Bay City, TX | 44 | % | 1,101 | Nuclear | |||||||||||
Total Solid Fuel Baseload | 5,178 | |||||||||||||||
Operating Natural Gas-Fired Units: | ||||||||||||||||
Cedar Bayou | Chambers County, TX | 100 | % | 1,498 | Natural Gas | |||||||||||
T. H. Wharton | Houston, TX | 100 | % | 1,025 | Natural Gas | |||||||||||
W. A. Parish (Natural gas)(3) | Thompsons, TX | 100 | % | 1,191 | Natural Gas | |||||||||||
S. R. Bertron | Deer Park, TX | 100 | % | 844 | Natural Gas | |||||||||||
Greens Bayou | Houston, TX | 100 | % | 760 | Natural Gas | |||||||||||
San Jacinto | LaPorte, TX | 100 | % | 162 | Natural Gas | |||||||||||
Total Operating Natural Gas-Fired | 5,480 | |||||||||||||||
Total Texas (ERCOT) Region | 10,658 | |||||||||||||||
(1) | 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 3,378 MW of inactive capacity available for redevelopment of which 174 MW of available capacity was sold on November 14, 2005. An additional 461 MW was moved to inactive status as of December 31, 2005. |
(2) | Low sulfur coal is coal mined from the Powder River Basin, a coal-producing area in northeastern Wyoming and southeastern Montana, which coal has low sulfur content relative to most coal from the eastern United States. |
(3) | W. A. Parish has nine units, four of which are baseload coal-fired units and five of which are natural gas-fired units. |
(4) | Generation capacity figure consists of our 44.0% undivided interest in the two units of STP. |
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NORTHEAST REGION |
Net Generation (MWh) | |||||||||||||
2005 | 2004 | 2003 | |||||||||||
(In thousands) | |||||||||||||
Coal | 10,369 | 10,664 | 9,783 | ||||||||||
Oil | 3,158 | 1,381 | 1,471 | ||||||||||
Gas | 1,724 | 1,160 | 1,172 | ||||||||||
Total | 15,251 | 13,205 | 12,426 | ||||||||||
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Net | ||||||||||||||||
Generation | ||||||||||||||||
Capacity | ||||||||||||||||
Plant | Location | % Owned | (MW)* | Primary Fuel Type | ||||||||||||
Oswego | Oswego, NY | 100.0 | % | 1,634 | Oil | |||||||||||
Arthur Kill | Staten Island, NY | 100.0 | % | 841 | Natural Gas | |||||||||||
Middletown | Middletown, CT | 100.0 | % | 770 | Oil | |||||||||||
Indian River | Millsboro, DE | 100.0 | % | 737 | Coal | |||||||||||
Astoria Gas Turbines | Queens, NY | 100.0 | % | 553 | Natural Gas | |||||||||||
Dunkirk | Dunkirk, NY | 100.0 | % | 522 | Coal | |||||||||||
Huntley | Tonawanda, NY | 100.0 | % | 552 | Coal | |||||||||||
Montville | Uncasville, CT | 100.0 | % | 497 | Oil | |||||||||||
Norwalk Harbor | So. Norwalk, CT | 100.0 | % | 342 | Oil | |||||||||||
Devon | Milford, CT | 100.0 | % | 124 | Natural Gas | |||||||||||
Vienna | Vienna, MD | 100.0 | % | 170 | Oil | |||||||||||
Somerset Power | Somerset, MA | 100.0 | % | 127 | Coal | |||||||||||
Connecticut Remote Turbines | Various locations in CT | 100.0 | % | 104 | Oil | |||||||||||
Conemaugh | New Florence, PA | 3.7 | % | 64 | Coal | |||||||||||
Keystone | Shelocta, PA | 3.7 | % | 63 | Coal | |||||||||||
Total Northeast Region | 7,099 | |||||||||||||||
* | Excludes 382 MW of inactive capacity. |
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SOUTH CENTRAL REGION |
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Net Generation (MWh) | |||||||||||||
2005 | 2004 | 2003 | |||||||||||
(In thousands) | |||||||||||||
Coal | 10,103 | 10,469 | 10,318 | ||||||||||
Gas | 14 | 2 | 27 | ||||||||||
Total | 10,117 | 10,471 | 10,345 | ||||||||||
Net | ||||||||||||||
Generating | ||||||||||||||
Capacity | Primary Fuel | |||||||||||||
Plant | Location | % Owned | (MW) | Type | ||||||||||
Big Cajun II(1) | New Roads, LA | 86.0 | % | 1,489 | Coal | |||||||||
Bayou Cove | Jennings, LA | 100.0 | % | 300 | Natural Gas | |||||||||
Big Cajun I — (Peakers) Units 3 & 4 | New Roads, LA | 100.0 | % | 210 | Natural Gas | |||||||||
Big Cajun I — Units 1 & 2 | New Roads, LA | 100.0 | % | 220 | Natural Gas/Oil | |||||||||
Sterlington | Sterlington, LA | 100.0 | % | 176 | Natural Gas | |||||||||
Total South Central | 2,395 | |||||||||||||
(1) | NRG owns 100% of Units 1 & 2; 58% of Unit 3 |
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Estimated | ||||||||||||
Expiration | Contract Load | Customers | ||||||||||
Form A | March 2025 | 42 | % | 6 | ||||||||
Form B | March 2025 | 3 | % | 1 | ||||||||
Form C | March 2009-2014 | 42 | % | 4 |
WESTERN REGION |
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Net | |||||||||||||||||
Generation | |||||||||||||||||
Capacity | Primary Fuel | ||||||||||||||||
Plant | Location | % Owned | (MW) | Type | |||||||||||||
WCP(1) | |||||||||||||||||
Encina | Carlsbad, CA | 50.0% | 483 | Natural Gas | |||||||||||||
El Segundo | El Segundo, CA | 50.0% | 335 | Natural Gas | |||||||||||||
Cabrillo II | San Diego, CA | 50.0% | 86 | Natural Gas | |||||||||||||
Total WCP | 904 | ||||||||||||||||
Other Western Region Assets | |||||||||||||||||
Saguaro | Henderson, NV | 50.0% | 46 | Natural Gas | |||||||||||||
Chowchilla | Northern CA | 100.0% | 49 | Natural Gas | |||||||||||||
Red Bluff | Northern CA | 100.0% | 45 | Natural Gas | |||||||||||||
140 | |||||||||||||||||
Total Western Region | 1,044 | ||||||||||||||||
(1) | On December 27, 2005, NRG entered into a purchase and sale agreement to acquire Dynegy’s 50% ownership interest in WCP Holdings to become the sole owner of power plants totaling approximately 1,800 MW of generation capacity in the Western region. The transaction is expected to close in the first quarter of 2006. |
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OTHER |
Other North American Assets |
Net | |||||||||||||
Generating | |||||||||||||
Capacity | |||||||||||||
Plant | Location | % Owned | MW | Primary Fuel Type | |||||||||
Audrain* | Vandalia, MO | 100.0% | 577 | Natural Gas | |||||||||
Rockford I (Peaker) | Rockford, IL | 100.0% | 310 | Natural Gas | |||||||||
Rocky Road Partnership* | East Dundee, IL | 50.0% | 165 | Natural Gas | |||||||||
Rockford II (Peaker) | Rockford, IL | 100.0% | 160 | Natural Gas | |||||||||
Dover | Dover, DE | 100.0% | 104 | Natural Gas/Coal | |||||||||
Power Smith Cogeneration | Oklahoma City, OK | 6.25% | 7 | Natural Gas | |||||||||
Ilion Cogeneration* | New York | 100.0% | 58 | Natural Gas | |||||||||
James River | Virginia | 50.0% | 55 | Coal | |||||||||
Cadillac* | Cadillac, MI | 50.0% | 19 | Wood | |||||||||
Paxton Creek | Harrisburg, PA | 100.0% | 12 | Natural Gas | |||||||||
Other North American Assets | 1,467 | ||||||||||||
* | Certain of the above projects are in transition. The Audrain project is under contract for sale. Closing is expected in 2006. NRG is in advanced discussions regarding the sale of the Cadillac project. NRG is currently performing under an agreement whereby the Ilion project will be disconnected and terminated. On December 27, 2005, NRG entered into a purchase and sale agreement with Dynegy through which NRG will sell to Dynegy its 50% ownership interest in the jointly held entity that owns the Rocky Road power plant. The transaction is conditioned upon NRG’s acquisition of Dynegy’s 50% interest in WCP Holdings and is expected to close in the first quarter of 2006. |
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Net | ||||||||||||||||
Generating | ||||||||||||||||
Capacity | Primary | |||||||||||||||
Plant | Location | % Owned | MW | Fuel Type | ||||||||||||
Operating Assets | ||||||||||||||||
Flinders | Australia | 100.0 | % | 700 | Coal | |||||||||||
Gladstone | Australia | 37.5 | % | 605 | Coal | |||||||||||
Schkopau | Germany | 41.9 | % | 400 | Coal | |||||||||||
MIBRAG(1) | Germany | 50.0 | % | 55 | Coal | |||||||||||
Itiquira | Brazil | 99.2 | % | 156 | Hydro | |||||||||||
Total International Assets | 1,916 | |||||||||||||||
(1) | Primarily a coal mining facility. Approximately 90% of MIBRAG’s revenues represent coal sales and 8% represent electricity sales. MIBRAG owns 110 MW of net exportable generation. Approximately two-thirds of that amount is sold to third parties and one-third is used to power mining and other MIBRAG operations. NRG equity in net exportable electricity is 55 MW. |
Australia |
Germany |
Asset Management Strategy |
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Thermal and Chilled Water Businesses |
Resource Recovery Facilities |
Federal Energy Regulatory Commission |
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Nuclear Regulatory Commission |
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Public Utility Commission of Texas |
Regional Businesses — Market Developments |
Texas (ERCOT) Region |
Texas Nodal Protocols |
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U.S. Federal Environmental Initiatives |
Air |
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Water |
Nuclear Waste |
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Regional U.S. Environmental Regulatory Initiatives |
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Domestic Site Remediation Matters |
International Environmental Matters |
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General |
Nuclear |
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Many of our power generation facilities operate, wholly or partially, without long-term power sale agreements. |
Our financial performance may be impacted by future decreases in oil and natural gas prices, significant and unpredictable price fluctuations in the wholesale power markets and other market factors that are beyond our control. |
• | increases and decreases in generation capacity in our 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; | |
• | 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; | |
• | availability of competitively priced alternative power sources; | |
• | development of new fuels and new technologies for the production of power; | |
• | natural disasters, wars, embargoes, terrorist attacks and other catastrophic events; |
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• | regulations and actions of the ISOs; and | |
• | federal and state power market and environmental regulation and legislation. |
Our costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of our fuel supplies. |
• | weather conditions; | |
• | seasonality; | |
• | demand for energy commodities and general economic conditions; | |
• | disruption of electricity, gas or coal transmission or transportation, infrastructure or other constraints or inefficiencies; | |
• | additional generating capacity; | |
• | availability of competitively priced alternative energy sources; | |
• | availability and levels of storage and inventory for fuel stocks; | |
• | natural gas, crude oil, refined products and coal production levels; | |
• | the creditworthiness or bankruptcy or other financial distress of market participants; | |
• | changes in market liquidity; | |
• | natural disasters, wars, embargoes, acts of terrorism and other catastrophic events; | |
• | federal, state and foreign governmental regulation and legislation; and | |
• | our creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with us. |
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There may be periods when we will not be able to meet our commitments under our forward sales obligations at a reasonable cost or at all. |
Our trading operations and the use of hedging agreements could result in financial losses that negatively impact our results of operations. |
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We may not have sufficient liquidity to hedge market risks effectively. |
The accounting for our hedging activities may increase the volatility in our quarterly and annual financial results. |
• | electricity sales from our generation assets; | |
• | fuel utilized by those assets; and | |
• | emission allowances. |
Competition in wholesale power markets may have a material adverse effect on our results of operations, cash flows and the market value of our assets. |
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Operation of power generation facilities involves significant risks that could have a material adverse effect on our revenues and results of operations. |
Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on our revenues and results of operations. |
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• | delays in obtaining necessary permits and licenses; | |
• | environmental remediation of soil or groundwater at contaminated sites; | |
• | interruptions to dispatch at our facilities; | |
• | supply interruptions; | |
• | work stoppages; | |
• | labor disputes; | |
• | weather interferences; | |
• | unforeseen engineering, environmental and geological problems; and | |
• | unanticipated cost overruns. |
Supplier and/or customer concentration at certain of our facilities may expose us to significant financial credit or performance risks. |
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We rely on power transmission facilities that we do not own or control and are subject to transmission constraints within a number of our core regions. If these facilities fail to provide us with adequate transmission capacity, we may be restricted in our ability to deliver wholesale electric power to our customers and we may either incur additional costs or forego revenues. Conversely, improvements to certain transmission systems could also reduce revenues. |
Because we own less than a majority of some of our project investments, we cannot exercise complete control over their operations. |
Future acquisition activities may have adverse effects. |
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Our operations are subject to hazards customary to the power generation industry. We may not have adequate insurance to cover all of these hazards. |
Our business is subject to substantial governmental regulation and may be adversely affected by liability under, or any future inability to comply with, existing or future regulations or requirements. |
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Our ownership interest in a nuclear power facility subjects us to regulations, costs and liabilities uniquely associated with these types of facilities. |
We are subject to environmental laws and regulations that impose extensive and increasingly stringent requirements on our ongoing operations, as well as potentially substantial liabilities arising out of environmental contamination. These environmental requirements and liabilities could adversely impact our results of operations, financial condition and cash flows. |
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The value of our assets is subject to the nature and extent of decommissioning and remediation obligations applicable to us. |
Our business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by our unionized employees. |
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Changes in technology may impair the value of our power plants. |
Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows. |
Our international investments are subject to additional risks that our U.S. investments do not have. |
• | 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. |
Our plants are the subject of a number of lawsuits filed by individuals who claim injury due to exposure to asbestos while working at certain of our facilities. |
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Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry. |
• | increasing our vulnerability to general economic and industry conditions; | |
• | requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our preferred or common stock or to use our cash flow to fund our operations, capital expenditures and future business opportunities; | |
• | limiting our ability to enter into long-term power sales or fuel purchases which require credit support; | |
• | exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under our new senior secured credit facility are at variable rates of interest; | |
• | making it more difficult for us to satisfy our obligations with respect to our notes; | |
• | placing us at a competitive disadvantage compared to our competitors that have less debt; | |
• | limiting our 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 our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who have less debt. |
• | general economic and capital market conditions; | |
• | credit availability from banks and other financial institutions; | |
• | investor confidence in us, our partners and the regional wholesale power markets; | |
• | our financial performance and the financial performance of our subsidiaries; | |
• | our levels 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. |
We may not be able to realize the anticipated benefits from the Texas Genco Acquisition. |
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Because the historical financial information may not be representative of our results as a combined company or capital structure after the Acquisition, and NRG’s and Texas Genco’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate us, NRG and Texas Genco. |
Goodwill and/or other intangible assets that we will record in connection with the Acquisition are subject to mandatory annual impairment evaluations and as a result, the combined company could be required to write off some or all of this goodwill and other intangibles, which may adversely affect its financial condition and results of operations. |
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• | General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel or other raw materials; | |
• | 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 fossil 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 we 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; | |
• | Our ability to operate its businesses efficiently, manage capital expenditures and costs tightly (including general and administrative expenses), and generate earnings and cash flow from its asset-based businesses in relation to its debt and other obligations; and | |
• | Our potential inability to enter into contracts to sell power and procure fuel on terms and prices acceptable to us; | |
• | The liquidity and competitiveness of wholesale markets for energy commodities; | |
• | Changes in government regulation, including but not limited to the pending changes of market rules, market structures and design, rates, tariffs, environmental laws and regulations and regulatory compliance requirements; | |
• | Price mitigation strategies and other market structures employed by independent system operators, or ISOs, or regional transmission organizations, that result in a failure to adequately compensate our generation units for all of their costs; | |
• | Our ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness going forward; | |
• | The success of the business following the acquisition of Texas Genco LLC; | |
• | Operating and financial restrictions placed on us contained in the indentures governing our 7.25% and 7.375% unsecured senior notes due 2014 and 2016, respectively, our new senior secured credit facility and in debt and other agreements of certain of our subsidiaries and project affiliates generally; and | |
• | Lack of comparable financial data due to adoption of Fresh Start reporting. |
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Net | ||||||||||||
Generation | ||||||||||||
Purchaser/Power | Capacity | |||||||||||
Name and Location of Facility | Market | % Owned | (MW) | Primary Fuel Type | ||||||||
Texas Region: | ||||||||||||
W. A. Parish, Thompsons, TX | ERCOT | 100.00 | % | 2,463 | Low Sulfur Coal | |||||||
Limestone, Jewett, TX | ERCOT | 100.00 | % | 1,614 | Lignite/Low Sulfur Coal | |||||||
South Texas Project, Bay City, TX(1) | ERCOT | 44.00 | % | 1,101 | Nuclear | |||||||
Cedar Bayou, TX | ERCOT | 100.00 | % | 1,498 | Natural Gas | |||||||
T. H. Wharton, Houston, TX | ERCOT | 100.00 | % | 1,025 | Natural Gas | |||||||
W. A. Parish (Natural gas), Thompsons, TX | ERCOT | 100.00 | % | 1,191 | Natural Gas | |||||||
S. R. Bertron, Deer Park, TX | ERCOT | 100.00 | % | 844 | Natural Gas | |||||||
Greens Bayou, Houston, TX | ERCOT | 100.00 | % | 760 | Natural Gas | |||||||
San Jacinto, LaPorte, TX | ERCOT | 100.00 | % | 162 | Natural Gas | |||||||
Northeast Region: | ||||||||||||
Oswego, New York | NYISO | 100.00 | % | 1,634 | Oil | |||||||
Arthur Kill, New York | NYISO | 100.00 | % | 841 | Natural Gas | |||||||
Middletown, Connecticut | ISO-NE | 100.00 | % | 770 | Oil | |||||||
Indian River, Delaware | PJM | 100.00 | % | 737 | Coal | |||||||
Astoria Gas Turbines, New York | NYISO | 100.00 | % | 553 | Natural Gas | |||||||
Dunkirk, New York | NYISO | 100.00 | % | 522 | Coal | |||||||
Huntley, New York | NYISO | 100.00 | % | 552 | Coal | |||||||
Montville, Connecticut | ISO-NE | 100.00 | % | 497 | Oil | |||||||
Norwalk Harbor, Connecticut | ISO-NE | 100.00 | % | 342 | Oil | |||||||
Devon, Connecticut | ISO-NE | 100.00 | % | 124 | Natural Gas | |||||||
Vienna, Maryland | PJM | 100.00 | % | 170 | Oil | |||||||
Somerset, Massachusetts | ISO-NE | 100.00 | % | 127 | Coal | |||||||
Connecticut Jet Power, Connecticut | ISO-NE | 100.00 | % | 104 | Oil | |||||||
Conemaugh, Pennsylvania | PJM | 3.72 | % | 64 | Coal | |||||||
Keystone, Pennsylvania | PJM | 3.72 | % | 63 | Coal |
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Net | ||||||||||||
Generation | ||||||||||||
Purchaser/Power | Capacity | |||||||||||
Name and Location of Facility | Market | % Owned | (MW) | Primary Fuel Type | ||||||||
South Central Region: | ||||||||||||
Big Cajun II, Louisiana(2) | SERC-Entergy | 86.00 | % | 1,489 | Coal | |||||||
Bayou Cove, Louisiana | SERC-Entergy | 100.00 | % | 300 | Natural Gas | |||||||
Big Cajun I, Louisiana | SERC-Entergy | 100.00 | % | 210 | Natural Gas | |||||||
Big Cajun I, Louisiana | SERC-Entergy | 100.00 | % | 220 | Natural Gas/Oil | |||||||
Sterlington, Louisiana | SERC-Entergy | 100.00 | % | 176 | Natural Gas | |||||||
Western Region: | ||||||||||||
Encina, California | Cal ISO | 50.00 | % | 483 | Natural Gas | |||||||
El Segundo Power, California | Cal ISO | 50.00 | % | 335 | Natural Gas | |||||||
San Diego Combustion Turbines, California | Cal ISO | 50.00 | % | 86 | Natural Gas | |||||||
Saguaro Power Co., Nevada | WECC | 50.00 | % | 46 | Natural Gas | |||||||
Chowchilla, California | Cal ISO | 100.00 | % | 49 | Natural Gas | |||||||
Red Bluff, California | Cal ISO | 100.00 | % | 45 | Natural Gas | |||||||
Other North America Region: | ||||||||||||
Audrain(3) | MISO | 100.00 | % | 577 | Natural Gas | |||||||
Rockford I, Illinois | PJM | 100.00 | % | 310 | Natural Gas | |||||||
Rocky Road Power, Illinois(3) | PJM | 50.00 | % | 165 | Natural Gas | |||||||
Rockford II, Illinois | PJM | 100.00 | % | 160 | Natural Gas | |||||||
Dover, Delaware | PJM | 100.00 | % | 104 | Natural Gas/Coal | |||||||
Power Smith Cogeneration, Oklahoma | SPP | 6.25 | % | 7 | Natural Gas | |||||||
Ilion, New York(3) | NYISO | 100.00 | % | 58 | Natural Gas | |||||||
James River, Virginia | SERC — TVA | 50.00 | % | 55 | Coal | |||||||
Cadillac, Michigan(3) | MISO | 50.00 | % | 19 | Wood | |||||||
Paxton Creek Cogeneration, Pennsylvania | PJM | 100.00 | % | 12 | Natural Gas | |||||||
Australia Region: | ||||||||||||
Flinders, South Australia | South Australian Pool | 100.00 | % | 700 | Coal | |||||||
Gladstone Power Station, Queensland | Enertrade/Boyne Smelters | 37.50 | % | 605 | Coal | |||||||
Other International Region: | ||||||||||||
Schkopau Power Station, Germany | Vattenfall Europe | 41.90 | % | 400 | Coal | |||||||
MIBRAG mbH, Germany(4) | ENVIA/MIBRAG Mines | 50.00 | % | 55 | Coal | |||||||
Itiquira Energetica, Brazil | COPEL | 99.20 | % | 156 | Hydro |
(1) | For the nature of our interest and various limitations on our interest, please read Item 1 — Business — Texas — Facilities section. |
(2) | Units 1 and 2 owned 100%, Unit 3 owned 58% |
(3) | Committed to sell or may sell or dispose of in 2006 |
(4) | Primarily a coal mining facility |
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% | ||||||||||||
Name and Location of | Year of | Ownership | Thermal Energy | |||||||||
Facility | Acquisition | Generating Capacity(1) | Interest | Purchaser/MSW Supplier | ||||||||
NRG Energy Center Minneapolis, MN | 1993 | Steam: 1,203 mmBtu/hr., (353 MWt) Chilled Water: 41,630 tons (146 MWt) | 100% | Approx. 100 steam customers and 47 chilled water customers | ||||||||
NRG Energy Center San Francisco, CA | 1999 | Steam: 482 mmBtu/Hr. (141 MWt) | 100% | Approx. 165 steam customers | ||||||||
NRG Energy Center Harrisburg, PA | 2000 | Steam: 440 mmBtu/hr. (129 MWt) Chilled water: 2,400 tons (8 MWt) | 100% | Approx. 265 steam customers and 3 chilled water customers | ||||||||
NRG Energy Center | 1999 | Steam: 266 mmBtu/hr. (78 MWt) Chilled water: 12,580 tons (44 MWt) | 100% | Approx. 25 steam and 25 chilled water customers | ||||||||
NRG Energy Center San Diego, CA | 1997 | Chilled water: 7,425 tons (26 MWt) | 100% | Approx. 20 chilled water customers | ||||||||
NRG Energy Center St. Paul, MN | 1992 | Steam: 430 mmBtu/hr. (126 MWt) | 100% | Rock-Tenn Company | ||||||||
Camas Power Boiler, Washington | 1997 | Steam: 200 mm Btu/hr. (59 MWt) | 100% | Georgia-Pacific Corp. | ||||||||
NRG Energy Center Dover, DE | 2000 | Steam: 190 mmBtu/hr. (56 MWt) | 100% | Kraft Foods Inc. | ||||||||
NRG Energy Center Oak Park Heights, MN | 1992 | Steam: 200 mmBtu/Hr. (59 MWt) | 100% | Andersen Corp., MN Correctional Facility |
(1) | Thermal production and transmission capacity is based on 1,000 Btus per pound of steam production or transmission capacity. The unit mmBtu is equal to one million Btus. |
% | ||||||||||||||
Date of | Ownership | |||||||||||||
Name and Location of Facility | Acquisition | Processing Capacity(1) | Interest | MSW Supplier | ||||||||||
Newport, MN(1) | 1993 | MSW: 1,500 tons/day | 100 | % | Ramsey and Washington Counties | |||||||||
Elk River, MN(2) | 2001 | MSW: 1,500 tons/day | 85 | % | Anoka, Hennepin and Sherburne Counties; Tri- County Solid Waste Management Commissioner |
(1) | The Newport facilities are strictly related to garbage-sorting facilities. |
(2) | For the Elk River facility, NRG’s 85% interest is related strictly to garbage-sorting facilities. |
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Pamela R Gordon, on Behalf of Herself and All Others Similarly Situated v Reliant Energy, Inc. et al.,Case No. 758487, Superior Court of the State of California, County of San Diego(filed on November 27, 2000).Ruth Hendricks, On Behalf of Herself and All Others Similarly Situated and On Behalf of the General Public v. Dynegy Power Marketing, Inc. et al.,Case No. 758565, Superior Court of the State of California, County of San Diego(filed November 29, 2000).The People of the State of California, by and through San Francisco City Attorney Louise H. Renne v. Dynegy Power Marketing, Inc. et al.,Case No. 318189, Superior Court of California, San Francisco County(filed January 18, 2001).Pier 23 Restaurant, A California Partnership, On Behalf of Itself and All Others Similarly Situated v PG&E Energy Trading et al.,Case No. 318343, Superior Court of California, San Francisco County(filed January 24, 2001).Sweetwater Authority, et al. v. Dynegy, Inc. et al.,Case No. 760743, Superior Court of California, County of San Diego(filed January 16, 2001).Cruz M Bustamante, individually, and Barbara Matthews, individually, and on behalf of the general public and as a representative taxpayer suit, v. Dynegy Inc. et al., inclusive.Case No. BC249705, Superior Court of California, Los Angeles County(filed May 2, 2001). |
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California Electricity and Related Litigation Indemnification |
NRG Bankruptcy Cap on California Claims |
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FERC Proceedings |
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Additional Litigation |
Item 4 — | Submission of Matters to a Vote of Security Holders |
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Item 5 — | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Fourth | Third | Second | First | Fourth | Third | Second | First | |||||||||||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | |||||||||||||||||||||||||
Common Stock Price | 2005 | 2005 | 2005 | 2005 | 2004 | 2004 | 2004 | 2004 | ||||||||||||||||||||||||
High | $ | 49.44 | $ | 44.45 | $ | 37.61 | $ | 39.10 | $ | 36.18 | $ | 28.43 | $ | 24.80 | $ | 22.50 | ||||||||||||||||
Low | $ | 37.60 | $ | 36.40 | $ | 30.30 | $ | 32.79 | $ | 26.00 | $ | 24.10 | $ | 19.17 | $ | 18.10 | ||||||||||||||||
Closing | $ | 47.12 | $ | 42.60 | $ | 30.70 | $ | 34.15 | $ | 36.05 | $ | 26.94 | $ | 24.80 | $ | 22.20 |
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Total Number | Maximum Number | |||||||||||||||
of Shares | of Shares That | |||||||||||||||
Total Number | Average Price | Purchased as | May Yet be | |||||||||||||
of Shares | Paid per | Part of Publicly | Purchased Under | |||||||||||||
Period | Purchased | Share | Announced Plans | the Plans | ||||||||||||
August 11, 2005 | 6,346,788* | $ | 39.90 | none | N/A |
* | 6,346,788 shares were purchased as part of the Accelerated Share Repurchase Agreement with CSFB as described above. |
Date of | ||||
Redemption | ||||
or Repurchase | Amount | Source | ||
January 2005 | $25 million face value repurchased | Existing cash | ||
February 2005 | $375 million redeemed | Proceeds from the sale of the 4% Preferred Stock in December 2004 | ||
March 2005 | $15.8 million face value repurchased | Existing Cash | ||
September 2005 | $229 million redeemed | Proceeds from the sale of the 3.625% Preferred Stock in August 2005 |
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(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 | 2,593,179 | $ | 25.04 | 1,355,193* | |||||||||
Equity compensation plans not approved by security holders | — | n/a | — | ||||||||||
Total | 2,593,179 | $ | 25.04 | 1,355,193* | |||||||||
* | The NRG Energy, Inc. Long-Term Incentive Plan became effective upon our emergence from bankruptcy. The Long-Term Incentive Plan, which was adopted in connection with the NRG plan of reorganization, was approved by our stockholders on August 4, 2004. The Long-Term Incentive Plan provides for grants of stock options, stock appreciation rights, restricted stock, performance awards, deferred stock units and dividend equivalent rights. Our directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by us, are eligible to receive grants under the Long-Term Incentive Plan. A total of 4,000,000 shares of our common stock are available for issuance under the Long-Term Incentive Plan. The purpose of the Long-Term Incentive Plan is to promote our long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to our success and to enable us to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of our Board of Directors administers the Long-Term Incentive Plan. There were 1,355,193 and 2,053,294 shares of common stock remaining available for grants of stock options under our Long-Term Incentive Plan as of December 31, 2005 and 2004, respectively. |
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Item 6 — | Selected Financial Data |
Reorganized NRG | Predecessor Company | ||||||||||||||||||||||||
Year Ended | |||||||||||||||||||||||||
Year Ended December 31, | December 6 - | January 1 - | December 31, | ||||||||||||||||||||||
December 31, | December 5, | ||||||||||||||||||||||||
2005 | 2004 | 2003 | 2003 | 2002 | 2001 | ||||||||||||||||||||
(In millions, except per share amounts) | |||||||||||||||||||||||||
Revenues from majority-owned operations | $ | 2,708 | $ | 2,348 | $ | 137 | $ | 1,798 | $ | 1,926 | $ | 2,085 | |||||||||||||
Corporate relocation charges | 6 | 16 | — | — | — | — | |||||||||||||||||||
Reorganization, restructuring and impairment charges | 6 | 32 | 2 | 435 | 2,497 | — | |||||||||||||||||||
Fresh start reporting adjustments | — | — | — | (4,220 | ) | — | — | ||||||||||||||||||
Legal settlement | — | — | — | 463 | — | — | |||||||||||||||||||
Total operating costs and expenses | 2,470 | 1,955 | 122 | (1,587 | ) | 4,231 | 1,704 | ||||||||||||||||||
Write downs and losses on equity method investments | (31 | ) | (16 | ) | — | (147 | ) | (200 | ) | — | |||||||||||||||
Income/(loss) from continuing operations | 77 | 161 | 11 | 3,082 | (2,693 | ) | 211 | ||||||||||||||||||
Income/(loss) from discontinued operations, net | 7 | 25 | — | (316 | ) | (771 | ) | 55 | |||||||||||||||||
Net income/(loss) | 84 | 186 | 11 | 2,766 | (3,464 | ) | 265 | ||||||||||||||||||
Income/(loss) from continuing operations per weighted average share — basic | $ | 0.67 | $ | 1.61 | $ | 0.11 | |||||||||||||||||||
Income/(loss) from continuing operations per weighted average share — diluted | $ | 0.66 | $ | 1.60 | $ | 0.11 | |||||||||||||||||||
Total assets | 7,431 | 7,864 | 9,315 | N/A | 10,897 | 12,915 | |||||||||||||||||||
Long-term debt, including current maturities | $ | 2,682 | $ | 3,484 | $ | 3,846 | N/A | $ | 7,217 | $ | 6,291 |
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Reorganized NRG | Predecessor Company | ||||||||||||||||||||||||
Year Ended | Year Ended | ||||||||||||||||||||||||
December 31, | December 6 - | January 1 - | December 31, | ||||||||||||||||||||||
December 31, | December 5, | ||||||||||||||||||||||||
2005 | 2004 | 2003 | 2003 | 2002 | 2001 | ||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||
Energy | $ | 2,014 | $ | 1,364 | $ | 64 | $ | 910 | $ | 1,172 | $ | 1,376 | |||||||||||||
Capacity | 563 | 612 | 37 | 566 | 553 | 490 | |||||||||||||||||||
Hedging and risk management activities | (248 | ) | 76 | 2 | 19 | 7 | — | ||||||||||||||||||
Alternative energy | 191 | 176 | 12 | 82 | 98 | 162 | |||||||||||||||||||
O&M fees | 20 | 21 | 1 | 13 | 14 | 16 | |||||||||||||||||||
Other | 168 | 99 | 21 | 208 | 82 | 41 | |||||||||||||||||||
Total revenues from majority-owned operations | $ | 2,708 | $ | 2,348 | $ | 137 | $ | 1,798 | $ | 1,926 | $ | 2,085 | |||||||||||||
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Item 7 — | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
• | Factors which affect our business, | |
• | Our earnings and costs in the periods presented, | |
• | Changes in earnings and costs between periods, | |
• | Sources of earnings, | |
• | Impact of these factors on our overall financial condition, | |
• | A discussion of known trends, including the expected impact of the Texas Genco Acquisition, that will affect our future results of operations and financial condition, | |
• | Expected future expenditures for capital projects, and | |
• | Expected sources of cash for future operations and capital expenditures. |
• | First, we discuss our strategy. | |
• | We then describe the business environment in which we operate including how regulation, weather, and other factors affect our business. | |
• | We highlight significant events that are important to understanding our results of operations and financial condition. | |
• | We then review our results of operations discussing: |
• | An overview of our total company results, followed by a more detailed review of those results by operating segment. | |
• | Known trends that will affect our results of operations in the future. |
• | We review our financial condition addressing: |
• | Our sources and uses of cash, credit ratings, capital resources and requirements, commitments, and off-balance sheet arrangements. | |
• | Known trends that will affect our financial condition in the future. |
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• | Next, we discuss our critical accounting policies. These are the accounting policies that are most important to both the portrayal of our financial condition and results of operations and require management’s most difficult, subjective or complex judgment. |
Increase value from our existing assets. We have a highly diversified portfolio of power generation assets in terms of region, fuel type and dispatch levels. We will continue to focus on extracting value from our portfolio by improving plant performance, reducing costs and harnessing our advantages of scale in the procurement of fuels: a strategy that we have branded“FORNRG,”or Focus on ROIC@NRG. | |
Pursue intrinsic growth opportunities at existing sites in our core regions. We are favorably positioned to pursue growth opportunities through expansion of our existing generating capacity. We intend to invest in our existing assets through plant improvements, repowering and brownfield development to meet anticipated regional requirements for new capacity. We expect that these efforts will provide more efficient energy, lower our delivered cost, expand our electricity production capability and improve our ability to dispatch economically across all sections of the merit order, including baseload, intermediate and peaking generation. | |
Maintain financial strength and flexibility. We remain focused on increasing cash flow and maintaining liquidity and balance sheet strength in order to ensure continued access to capital for growth; enhancing risk-adjusted returns; and providing flexibility in executing our business strategy. We will continue our focus on maintaining operational and financial controls designed to ensure that our financial position remains strong. | |
Reduce the volatility of our cash flows through asset-based commodity hedging activities. We will continue to execute asset-based risk management, hedging, marketing and trading strategies within well-defined risk and liquidity guidelines in order to manage the value of our physical and contractual assets. Our marketing and hedging philosophy is centered on generating stable returns from our portfolio of power generation assets while preserving the ability to capitalize on strong spot market conditions and to capture the extrinsic value of our portfolio. We believe that we can successfully execute this strategy by taking advantage of our expertise in marketing power and ancillary services, our knowledge of markets, our flexible financial structure and our diverse portfolio of power generation assets. | |
Participate in continued industry consolidation. We will continue to pursue selective acquisitions, joint ventures and divestitures to enhance our asset mix and competitive position in our core regions to meet the fuel and dispatch requirements in these regions. We intend to concentrate on acquisition and joint venture opportunities that present attractive risk-adjusted returns. We will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures during the consolidation of the power generation industry in the United States. |
• | Hurricanes Katrina and Rita exacerbated an already tight national natural gas production and delivery system during record summer demand. This led to significant price spikes and volatility across all fuel sources, which in turn spurred regulatory concerns over excessive burdens on retail consumers and |
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renewed interest by incumbent utilities in securing long-term power supplies that are not tied to the price of natural gas. | ||
• | The Energy Policy Act of 2005, or EPAct, the most comprehensive energy legislation in more than a decade, was enacted in August 2005. EPAct reinforces FERC oversight and monitoring responsibilities and encourages the development of regulatory framework that provide the appropriate market signals for increased infrastructure investment including generation. | |
• | While financial and strategic buyers continue to participate in energy sector asset sales and acquisitions, there has been renewed interest within the power sector for scope and scale and renewed merger and acquisitions activities by existing owners of power generation. This year has also seen regulated utilities seeking to participate in the competitive markets through outright combinations with deregulated entities. | |
• | The EPA released its CAIR and CAMR guidelines in March. While there continues to be uncertainty as to the implementation standards by certain states, these environmental requirements coupled with potential improved scrubber technologies provide additional clarity with respect to longer term compliance strategies that will drive higher capital expenditure programs towards the end of the decade for many energy providers. | |
• | There has been contentious but continued progress towards capacity markets evolution in order to meet increasing demand and encourage new investment in transmission and generation in load pockets around the country, including New England and California. |
• | seasonal daily and hourly changes in demand, | |
• | extreme peak demands, | |
• | available supply resources, | |
• | transportation and transmission availability and reliability within and between regions, |
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• | location of our generating facilities relative to the location of our 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, | |
• | capability and reliability of the physical electricity and gas systems, | |
• | local transportation systems, and | |
• | the nature and extent of electricity deregulation. |
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Reorganized NRG | |||||||||||||||||||||||||||||
For the Year Ended December 31, 2005 | |||||||||||||||||||||||||||||
South | Other North | ||||||||||||||||||||||||||||
Northeast | Central | Western | America | Australia | All Other | Total | |||||||||||||||||||||||
(In millions, except MWh, CDD and HDD data) | |||||||||||||||||||||||||||||
Energy revenue | $ | 1,444 | $ | 330 | $ | 1 | $ | 11 | $ | 144 | $ | 84 | $ | 2,014 | |||||||||||||||
Capacity revenue | 291 | 186 | — | 5 | — | 81 | 563 | ||||||||||||||||||||||
Hedging & risk management activity | (285 | ) | (1 | ) | — | — | 43 | (5 | ) | (248 | ) | ||||||||||||||||||
Alternative revenue | — | — | — | 2 | — | 189 | 191 | ||||||||||||||||||||||
O&M fees | — | — | — | — | — | 20 | 20 | ||||||||||||||||||||||
Other revenue | 104 | 37 | (3 | ) | 25 | 5 | 168 | ||||||||||||||||||||||
Operating revenues | 1,554 | 552 | 1 | 15 | 212 | 374 | 2,708 | ||||||||||||||||||||||
Cost of energy | 871 | 368 | 1 | 14 | 93 | 182 | 1,529 | ||||||||||||||||||||||
Derivative cost of energy | (2 | ) | — | — | — | — | — | (2 | ) | ||||||||||||||||||||
Other operating expenses(1) | 393 | 104 | 5 | 16 | 99 | 121 | 738 | ||||||||||||||||||||||
Depreciation and amortization | 74 | 61 | 1 | 7 | 27 | 24 | 194 | ||||||||||||||||||||||
Operating income/ (loss) | 218 | 20 | (6 | ) | (28 | ) | (7 | ) | 41 | 238 | |||||||||||||||||||
MWh sold(2)(in thousands) | 16,128 | 11,710 | 6 | 77 | 5,495 | ||||||||||||||||||||||||
Market indicators: | |||||||||||||||||||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | $ | 8.89 | |||||||||||||||||||||||||||
Average on-peak market power prices ($/MWh) | $ | 91.98 | $ | 69.96 | $ | 71.06 | $ | 63.76 | |||||||||||||||||||||
Cooling Degree Days, or CDDs(3) | 1,604 | 2,825 | 776 | 970 | |||||||||||||||||||||||||
CDD’s 30 year rolling average | 1,073 | 2,449 | 704 | 708 | |||||||||||||||||||||||||
Heating Degree Days, or HDDs(3) | 10,449 | 1,638 | 2,563 | 5,095 | |||||||||||||||||||||||||
HDD’s 30 year rolling average | 10,479 | 1,888 | 2,790 | 5,436 |
(1) | Other operating expenses include “Cost of majority-owned operations” and “General, administrative and development” expenses, excluding cost of energy. |
(2) | Includes MWhs sold for wholly owned subsidiaries only. |
(3) | 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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Reorganized NRG | |||||||||||||||||||||||||||||
For the Year Ended December 31, 2004 | |||||||||||||||||||||||||||||
South | Other North | ||||||||||||||||||||||||||||
Northeast | Central | Western | America | Australia | All Other | Total | |||||||||||||||||||||||
(In millions, except MWh, CDD and HDD data) | |||||||||||||||||||||||||||||
Energy revenue | $ | 853 | $ | 219 | $ | 10 | $ | 15 | $ | 159 | $ | 109 | $ | 1,365 | |||||||||||||||
Capacity revenue | 265 | 183 | (4 | ) | 84 | — | 84 | 612 | |||||||||||||||||||||
Hedging & risk management activity | 58 | — | — | 1 | 15 | 2 | 76 | ||||||||||||||||||||||
Alternative revenue | — | — | — | 2 | — | 174 | 176 | ||||||||||||||||||||||
O&M fees | — | — | — | — | — | 21 | 21 | ||||||||||||||||||||||
Other revenue | 75 | 16 | (3 | ) | (8 | ) | 7 | 11 | 98 | ||||||||||||||||||||
Operating revenues | 1,251 | 418 | 3 | 94 | 181 | 401 | 2,348 | ||||||||||||||||||||||
Cost of energy | 521 | 223 | 5 | 10 | 79 | 168 | 1,006 | ||||||||||||||||||||||
Derivative cost of energy | — | — | — | — | — | — | — | ||||||||||||||||||||||
Other operating expenses(1) | 338 | 71 | 5 | 42 | 83 | 154 | 693 | ||||||||||||||||||||||
Depreciation and amortization | 73 | 62 | 1 | 21 | 24 | 27 | 208 | ||||||||||||||||||||||
Operating income/(loss) | 318 | 58 | (9 | ) | (5 | ) | (5 | ) | 36 | 393 | |||||||||||||||||||
MWh sold(2)(in thousands) | 14,259 | 10,569 | 77 | 5 | 5,189 | ||||||||||||||||||||||||
Market indicators: | |||||||||||||||||||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | $ | 5.89 | |||||||||||||||||||||||||||
Average on-peak market power prices ($/MWh) | $ | 63.53 | $ | 45.76 | $ | 53.16 | $ | 43.31 | |||||||||||||||||||||
Cooling Degree Days, or CDDs(3) | 1,031 | 2,547 | 888 | 590 | |||||||||||||||||||||||||
CDD’s 30 year rolling average | 1,073 | 2,449 | 704 | 708 | |||||||||||||||||||||||||
Heating Degree Days, or HDDs(3) | 10,256 | 1,557 | 2,347 | 4,987 | |||||||||||||||||||||||||
HDD’s 30 year rolling average | 10,479 | 1,888 | 2,790 | 5,436 |
(1) | Other operating expenses include “Cost of majority-owned operations” and “General, administrative and development” expenses, excluding cost of energy. |
(2) | Includes MWhs sold for wholly owned subsidiaries only. |
(3) | 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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Reorganized NRG | |||||||||||||||||||||||||||||
For the Period from December 6, 2003 through December 31, 2003 | |||||||||||||||||||||||||||||
South | Other North | ||||||||||||||||||||||||||||
Northeast | Central | Western | America | Australia | All Other | Total | |||||||||||||||||||||||
(In millions, except MWh, CDD and HDD data) | |||||||||||||||||||||||||||||
Energy revenue | $ | 49 | $ | 15 | $ | — | $ | — | $ | 10 | $ | (10 | ) | $ | 64 | ||||||||||||||
Capacity revenue | 14 | 11 | — | 5 | — | 7 | 37 | ||||||||||||||||||||||
Hedging & risk management activity | — | — | — | — | 2 | — | 2 | ||||||||||||||||||||||
Alternative revenue | — | — | — | 12 | 12 | ||||||||||||||||||||||||
O&M fees | — | — | — | — | — | 1 | 1 | ||||||||||||||||||||||
Other revenue | 6 | 1 | — | (1 | ) | — | 15 | 21 | |||||||||||||||||||||
Operating revenues | 69 | 27 | 4 | 12 | 25 | 137 | |||||||||||||||||||||||
Cost of energy | 28 | 15 | 6 | 14 | 63 | ||||||||||||||||||||||||
Derivative cost of energy | — | — | — | — | — | — | — | ||||||||||||||||||||||
Other operating expenses(1) | 25 | 4 | — | 3 | 4 | 9 | 45 | ||||||||||||||||||||||
Depreciation and amortization | 5 | 3 | — | 2 | 1 | 1 | 12 | ||||||||||||||||||||||
Operating income/(loss) | 11 | 4 | — | — | — | — | 15 | ||||||||||||||||||||||
Market indicators: | |||||||||||||||||||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | $ | 6.28 | |||||||||||||||||||||||||||
Average on-peak market power prices ($/MWh) | $ | 60.75 | $ | 39.98 | $ | 49.08 | $ | 33.09 | |||||||||||||||||||||
Cooling Degree Days, or CDDs(3) | — | — | — | — | |||||||||||||||||||||||||
CDD’s 30 year rolling average | 1,073 | 2,449 | 704 | 708 | |||||||||||||||||||||||||
Heating Degree Days, or HDDs(3) | 1,494 | 377 | 427 | 803 | |||||||||||||||||||||||||
HDD’s 30 year rolling average | 10,479 | 1,888 | 2,790 | 5,436 |
(1) | Other operating expenses include “Cost of majority-owned operations” and “General, administrative and development” expenses, excluding cost of energy. |
(2) | Includes MWhs sold for wholly owned subsidiaries only. |
(3) | 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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Predecessor NRG | |||||||||||||||||||||||||||||
For the Period from January 1, 2003 through December 5, 2003 | |||||||||||||||||||||||||||||
South | Other North | ||||||||||||||||||||||||||||
Northeast | Central | Western | America | Australia | All Other | Total | |||||||||||||||||||||||
(in millions, except MWh, CDD and HDD data) | |||||||||||||||||||||||||||||
Energy revenue | $ | 554 | $ | 196 | $ | 5 | $ | 9 | $ | 122 | $ | 24 | $ | 910 | |||||||||||||||
Capacity revenue | 235 | 160 | 19 | 74 | — | 78 | 566 | ||||||||||||||||||||||
Hedging & risk management activity | 19 | — | — | — | — | — | 19 | ||||||||||||||||||||||
Alternative revenue | — | — | — | 2 | — | 80 | 82 | ||||||||||||||||||||||
O&M fees | — | — | — | 2 | — | 11 | 13 | ||||||||||||||||||||||
Other revenue | 53 | 1 | — | (1 | ) | 29 | 126 | 208 | |||||||||||||||||||||
Operating revenues | 861 | 357 | 24 | 86 | 151 | 319 | 1,798 | ||||||||||||||||||||||
Cost of energy | 470 | 188 | 4 | 7 | 72 | 104 | 845 | ||||||||||||||||||||||
Derivative cost of energy | 4 | — | — | — | (9 | ) | — | (5 | ) | ||||||||||||||||||||
Other operating expenses(1) | 326 | 59 | 4 | 39 | 61 | 195 | 684 | ||||||||||||||||||||||
Depreciation and amortization | 90 | 34 | 11 | 30 | 17 | 29 | 211 | ||||||||||||||||||||||
Operating income/ (loss) | (1,331 | ) | (384 | ) | (101 | ) | (465 | ) | (68 | ) | 5,734 | 3,385 | |||||||||||||||||
Market indicators: | |||||||||||||||||||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | $ | 5.43 | |||||||||||||||||||||||||||
Average on-peak market power prices ($/MWh) | $ | 61.78 | $ | 41.53 | $ | 48.64 | $ | 37.83 | |||||||||||||||||||||
Cooling Degree Days, or CDDs(3) | 1,164 | 2,583 | 900 | 633 | |||||||||||||||||||||||||
CDD’s 30 year rolling average | 1,073 | 2,449 | 704 | 708 | |||||||||||||||||||||||||
Heating Degree Days, or HDDs(3) | 11,404 | 1,836 | 2,455 | 5,586 | |||||||||||||||||||||||||
HDD’s 30 year rolling average | 10,479 | 1,888 | 2,790 | 5,436 |
(1) | Other operating expenses include “Cost of majority-owned operations” and “General, administrative and development” expenses, excluding cost of energy. |
(2) | Includes MWhs sold for wholly owned subsidiaries only. |
(3) | 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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For year ended December 31, 2005 compared to the year ended December 31, 2004 |
Significant Events Reflected in our Results of Operations During 2005 |
• | Extreme weather conditions, including Hurricanes Katrina and Rita, contributed to the increase in the sale price of power. This increase in power prices drove the netmark-to-market losses of $119 million primarily associated with forward financial electric sales in support of our Northeast assets. | |
• | As compared to the year ended December 31, 2004, on-peak electricity prices increased between 43% to 53% in the various markets we operate, whereas our total domestic coal costs, which are largely contracted, increased only 17% increasing our dark spreads. Gas and oil prices increased 50% and 49%, respectively, resulting in higher spark spreads, but compressed oil margins as compared to the same period last year(1) | |
• | Total generation increased for the year ended December 31, 2005 compared to 2004 by 5%. | |
• | We began selling excess emission allowances, and have recognized a net gain of $31 million during 2005. | |
• | Forced outages at our Huntley, Dunkirk, Indian River and Big Cajun II plants during 2005 negatively impacted our generation by 2.4 million MWh. | |
• | We repurchased $645 million in aggregate principal amount of our Second Priority Notes, resulting in $45 million of refinancing charges. | |
• | We sold a number of non-core assets including, Enfield, our Northbrook assets and our remaining Kendall interest for a total of $106 million in proceeds and a net gain of approximately $32 million. | |
• | We announced the signing of a sale agreement for Rocky Road resulting in an impairment charge of $20 million. | |
• | We wrote-down our interest in the Saguaro Power Company by $27 million. |
Consolidated Discussion: |
Revenues from Majority-Owned Operations |
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Average | |||||||||||||
Tons | Sales Price | Revenue | |||||||||||
Balance of NRG SO2Emissions Credits Allowances, as of December 31, 2004 | 897,653 | n/a | n/a | ||||||||||
Sales during 2005 | 35,052 | $ | 889 | $ | 31 million | ||||||||
Consumed | (115,810 | ) | |||||||||||
Balance of NRG SO2Emissions Credits Allowances, as of December 31, 2005 | 746,791 | n/a | n/a | ||||||||||
Completed Sales between January 1 and February 28, 2006 | 46,077 | $ | 1,180 | $ | 54 million | ||||||||
Balance of NRG SO2Emissions Credits Allowances, as of February 28, 2006 | 700,714 | n/a | n/a |
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Hedging and Risk Management Activity |
For the Year Ended December 31, 2005 | |||||||||||||||||||||||||||||
South | Other North | ||||||||||||||||||||||||||||
Northeast | Central | Western | America | Australia | All Other | Total | |||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||||
Net gains/ (losses) on settled positions, or financial revenues | $ | (132 | ) | $ | (1 | ) | $ | — | $ | — | $ | 35 | $ | (5 | ) | $ | (103 | ) | |||||||||||
Mark-to-market results | |||||||||||||||||||||||||||||
Reversal of previously recognized unrealized (gains)/losses on settled positions | (59 | ) | — | — | — | 1 | — | (58 | ) | ||||||||||||||||||||
Net unrealized gains/ (losses) on open positions related to economic hedges | (119 | ) | 7 | (112 | ) | ||||||||||||||||||||||||
Net unrealized gains/ (losses) on open positions related to trading activity | 27 | — | — | — | — | — | 27 | ||||||||||||||||||||||
Subtotal mark-to-market results | (151 | ) | — | — | — | 8 | — | (143 | ) | ||||||||||||||||||||
Total derivative gain/ (loss) | $ | (283 | ) | $ | (1 | ) | $ | — | $ | — | $ | 43 | $ | (5 | ) | $ | (246 | ) | |||||||||||
Cost of Majority-Owned Operations |
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Depreciation and Amortization |
General, Administrative and Development |
Corporate Relocation Charges |
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Equity in Earnings of Unconsolidated Affiliates |
Write Downs and Gains/(Losses) on Sales of Equity Method Investments |
Other Income, net |
88
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Refinancing expense |
Interest expense |
Income Tax Expense |
Income from Discontinued Operations, net of Income Taxes |
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Regional Discussion |
Northeast Region Results |
Operating Income |
Revenues |
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Cost of energy |
Other Operating Expenses |
91
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South Central Region Results |
Operating Income |
Revenues |
Cost of Energy |
Other Operating Expenses |
Western Region Results |
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Other North America Region Results |
Australia Region Results |
Operating Income |
Revenues |
Cost of Energy |
Other Operating Expenses |
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For the Year Ended December 31, 2004 Compared to the Year Ended December 31, 2003 |
Net Income |
Reorganized NRG |
Predecessor Company |
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Revenues from Majority-Owned Operations |
Reorganized NRG |
95
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Predecessor Company |
Cost of Majority-Owned Operations |
Cost of Energy |
Operating Expenses |
Reorganized NRG |
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Predecessor Company |
Depreciation and Amortization |
Reorganized NRG |
Predecessor Company |
General, Administrative and Development |
Reorganized NRG |
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Predecessor Company |
Other Charges (Credits) |
Reorganized NRG |
Predecessor Company |
Reorganized NRG | Predecessor Company | |||||||||||||
For the Period | For the Period | |||||||||||||
Year Ended | December 6 - | January 1 - | ||||||||||||
December 31, | December 31, | December 5, | ||||||||||||
2004 | 2003 | 2003 | ||||||||||||
(In millions) | ||||||||||||||
Corporate relocation charges | $ | 16 | $ | — | $ | — | ||||||||
Reorganization items | (13 | ) | 2 | 198 | ||||||||||
Impairment charges | 45 | — | 229 | |||||||||||
Restructuring charges | — | — | 8 | |||||||||||
Fresh Start adjustments | — | — | (4,220 | ) | ||||||||||
Legal settlement | — | — | 463 | |||||||||||
Total | $ | 48 | $ | 2 | $ | (3,322 | ) | |||||||
Corporate Relocation Charges |
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Reorganization Items |
Impairment Charges |
Restructuring Charges |
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Fresh Start Adjustments |
(In millions) | |||||
Discharge of corporate level debt | $ | 5,162 | |||
Discharge of other liabilities | 811 | ||||
Establishment of creditor pool | (1,040 | ) | |||
Receivable from Xcel | 640 | ||||
Revaluation of fixed assets | (1,392 | ) | |||
Revaluation of equity investments | (207 | ) | |||
Valuation of SO2emission credits | 374 | ||||
Valuation of out of market contracts, net | (400 | ) | |||
Fair market valuation of debt | 108 | ||||
Valuation of pension liabilities | (61 | ) | |||
Other valuation adjustments | (100 | ) | |||
Total Fresh Start adjustments | 3,895 | ||||
Less discontinued operations | (325 | ) | |||
Total Fresh Start adjustments — continuing operations | $ | 4,220 | |||
Legal Settlement Charges |
Other Income (Expense) |
Reorganized NRG |
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Predecessor Company |
Equity in Earnings of Unconsolidated Affiliates |
Reorganized NRG |
Predecessor Company |
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Predecessor | ||||||||||||||
Reorganized NRG | Company | |||||||||||||
Year Ended | December 6, 2003 | January 1, 2003 | ||||||||||||
December 31, | Through | Through | ||||||||||||
2004 | December 31, 2003 | December 5, 2003 | ||||||||||||
(In millions) | ||||||||||||||
WCP | $ | 69 | $ | 9 | $ | 99 | ||||||||
MIBRAG | 21 | — | 22 | |||||||||||
Enfield | 28 | 1 | 6 | |||||||||||
Gladstone | 17 | 1 | 12 | |||||||||||
Rocky Road | 7 | — | 7 | |||||||||||
James River | 8 | 1 | (2 | ) | ||||||||||
NRG Saguaro | 5 | 1 | 4 | |||||||||||
Scudder LA Trust | 2 | — | 3 | |||||||||||
NRG National | 1 | — | 2 | |||||||||||
Loy Yang | — | — | 18 | |||||||||||
Other | 2 | 1 | — | |||||||||||
Total Equity in Earnings of Unconsolidated Affiliates | $ | 160 | $ | 14 | $ | 171 | ||||||||
Write Downs and Losses on Sales of Equity Method Investments |
Other Income, net |
Reorganized NRG |
Predecessor Company |
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Interest Expense |
Reorganized NRG |
Predecessor Company |
Refinancing Expense |
Income Tax Expense |
Reorganized NRG |
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Predecessor Company |
Income From Discontinued Operations, net of Income Taxes |
Reorganized NRG |
Predecessor Company |
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Reorganization and Emergence from Bankruptcy |
Financial Reporting by Entities in Reorganization under the Bankruptcy Code and Fresh Start |
“Predecessor Company” | The Company, pre-emergence from bankruptcy The Company’s operations prior to December 6, 2003 | |
“Reorganized NRG” | The Company, post-emergence from bankruptcy The Company’s operations from December 6, 2003- December 31, 2004 |
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Company | Debt Discharge | NRG | ||||||||||||||||||
December 5, | and Exchange | Fresh Start | December 6, | |||||||||||||||||
2003 | of Stock | Adjustments | Consolidation | 2003 | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Current Assets | $ | 1,718 | $ | 614 | $ | 4 | $ | 6 | $ | 2,342 | ||||||||||
Non-current Assets | 8,172 | (155 | ) | (1,233 | ) | 41 | 6,825 | |||||||||||||
Total Assets | $ | 9,890 | $ | 459 | $ | (1,229 | ) | $ | 47 | $ | 9,167 | |||||||||
Current Liabilities | 2,190 | 999 | 1,187 | 1 | 4,377 | |||||||||||||||
Non-current Liabilities | 9,458 | (6,270 | ) | (848 | ) | 46 | 2,386 | |||||||||||||
Total Liabilities | 11,648 | (5,271 | ) | 339 | 47 | 6,763 | ||||||||||||||
Stockholders Equity | (1,758 | ) | 2,404 | 1,758 | — | 2,404 | ||||||||||||||
Total Liabilities and Stockholders Equity | $ | 9,890 | $ | (2,867 | ) | $ | 2,097 | $ | 47 | $ | 9,167 | |||||||||
Known trends that will affect our results in the future: |
Acquisition of Texas Genco and Financing Transactions |
Debt instruments: |
• | $3.575 billion Term Loan Facility | |
• | $1.0 billion Revolving Credit Facility | |
• | $1.0 billion Letter of Credit Facility | |
• | $1.2 billion in aggregate principal amount of 7.25% Senior Notes | |
• | $2.4 billion in aggregate principal amount of 7.375% Senior Notes |
Equity instruments: |
• | $485 million from the issuance of 2 million shares of 5.75% Preferred Stock, net of issuance costs | |
• | $985 million from the issuance of 20,855,057 shares of our common stock, net of issuance costs |
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Acquisition of Remaining 50% Equity Interest in WCP |
Significant Events during 2005 |
• | The repurchase of $645 million in aggregate principal amount of our Second Priority Notes, resulting in $54 million of refinancing charges | |
• | The issuance of $250 million of 3.625% Preferred Stock | |
• | The execution of the Accelerated Share Repurchase Agreement whereby we repurchased $250 million of common stock | |
• | Repatriation of $298 million of foreign funds utilizing the tax benefits of the American Jobs Creation Act of 2004 | |
• | Cash collateral payments of $405 million supporting our hedging activities | |
• | Collection of $71 million in an arbitration award related to TermoRio | |
• | Execution of the Texas Genco Acquisition Agreement and related financing commitments | |
• | Sale of non-core assets resulting in $106 million in proceeds | |
• | The announced signing of sales and purchase agreements for the sale of Audrain resulting in its reclassification as a discontinued operation |
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Balance | 2005 activity and | 2006 activity and | |||||||||||||||||||
Outstanding at | Outstanding at | Outstanding at | |||||||||||||||||||
Date of | Original | December 31, | December 31, | February 25, | |||||||||||||||||
Transaction | Amount | 2004 | 2005 | 2006 | |||||||||||||||||
(In millions) | |||||||||||||||||||||
Xcel Promissory Note | Dec. 6, 2003 | $ | 10 | $ | 10 | $ | 10 | $ | 10 | ||||||||||||
NRG 8% Second Priority Notes | Dec. 23, 2003- Jan. 28, 2004 | 1,725 | 1,725 | ||||||||||||||||||
Repurchase of Notes | Jan-Mar, 2005 | (41 | ) | ||||||||||||||||||
Early redemption | Feb-Sep, 2005 | (604 | ) | ||||||||||||||||||
Ending balance Dec. 31, 2005 | 1,080 | ||||||||||||||||||||
Repurchase of Notes | Feb. 2, 2006 | (1,080 | ) | ||||||||||||||||||
Ending balance Feb. 25, 2006 | $ | — | |||||||||||||||||||
NRG Credit Facility Term loan | Dec. 23, 2003 | 950 | 450 | ||||||||||||||||||
Repayments of Term Loans | Throughout 2005 | (4 | ) | ||||||||||||||||||
Ending balance Dec. 31, 2005 | 446 | ||||||||||||||||||||
Prepayment of Term Loan | Jan 2006 | (446 | ) | ||||||||||||||||||
Ending balance Feb. 25, 2006 | $ | — | |||||||||||||||||||
Letter of Credit facility | Dec. 23, 2003 | 250 | 350 | 350 | |||||||||||||||||
Terminating Letter of Credit facility | Feb. 2, 2006 | (350 | ) | ||||||||||||||||||
Ending balance Feb. 25, 2006 | $ | — | |||||||||||||||||||
Corporate Revolver* | Dec. 23, 2003 | 250 | 150 | 150 | |||||||||||||||||
Terminating Corporate Revolver* | Feb. 2, 2006 | (150 | ) | ||||||||||||||||||
Ending balance Feb. 25, 2006* | $ | — | |||||||||||||||||||
New Sr. Secured Term loan | Feb. 2, 2006 | 3,575 | |||||||||||||||||||
New Funded LC Facility | Feb. 2, 2006 | 1,000 | |||||||||||||||||||
New Corporate Revolver* | Feb. 2, 2006 | 1,000 | |||||||||||||||||||
Ending balance Feb. 25, 2006 | $ | 5,575 | |||||||||||||||||||
7.25% Senior Notes due 2014 | Feb. 2, 2006 | 1,200 | |||||||||||||||||||
7.375% Senior Notes due 2016 | Feb. 2, 2006 | 2,400 | |||||||||||||||||||
Ending balance Feb. 25, 2006 | $ | 3,600 | |||||||||||||||||||
Total Corporate Level Debt* | $ | 2,535 | $ | 1,886 | $ | 7,185 | |||||||||||||||
* | Amount indicates capacity to borrow under NRG’s revolver facilities only. Un-borrowed capacity is not included in total corporate level debt. |
Sources of Funds |
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Uses of Funds |
(i) Commercial Operations |
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(ii) Capital Expenditures |
(iii) Corporate Financial Restructuring |
(iv) Project Finance Requirements |
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Subsidiary/Description | Total | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | |||||||||||||||||||||||
Xcel Energy Note | $ | 10 | $ | 10 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Amended Credit Facility due | ||||||||||||||||||||||||||||||
Dec. 2011 | 796 | 796 | — | — | — | — | — | |||||||||||||||||||||||
8% Second Priority Notes | 1,080 | 1,080 | — | — | — | — | — | |||||||||||||||||||||||
NRG Energy Center Minneapolis, due 2013 and 2017 | 111 | 8 | 9 | 10 | 11 | 11 | 62 | |||||||||||||||||||||||
NRG Peaker Finance Co LLC | 297 | 7 | 11 | 13 | 15 | 20 | 231 | |||||||||||||||||||||||
Flinders Power Finance Pty | 177 | 6 | 14 | 4 | 8 | 18 | 127 | |||||||||||||||||||||||
Camas Pwr BLR LP Bank facility | 4 | 3 | 1 | — | — | — | — | |||||||||||||||||||||||
Camas Pwr BLR LP Bonds | 3 | 1 | 2 | — | — | — | — | |||||||||||||||||||||||
Itiquira Energetica S.A., due January 2012 | 19 | 3 | 3 | 3 | 3 | 3 | 4 | |||||||||||||||||||||||
Itiquira Energetica S.A., due December 2013 | 30 | 4 | 4 | 4 | 4 | 4 | 10 | |||||||||||||||||||||||
Subtotal Debt, Bonds and Notes | 2,527 | 1,918 | 44 | 34 | 41 | 56 | 434 | |||||||||||||||||||||||
Saale Energie GmbH, Schkopau (capital lease) | 214 | 61 | 34 | 28 | 21 | 10 | 60 | |||||||||||||||||||||||
Conemaugh Fuels LLC (capital lease) | — | — | — | — | — | — | — | |||||||||||||||||||||||
Subtotal Capital Leases | 214 | 61 | 34 | 28 | 21 | 10 | 60 | |||||||||||||||||||||||
Total Debt | $ | 2,741 | $ | 1,979 | $ | 78 | $ | 62 | $ | 62 | $ | 66 | $ | 494 | ||||||||||||||||
Description | Total | 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | ||||||||||||||||||||||
New Credit Facility due Feb 2013 | $ | 3,575 | $ | 26 | $ | 36 | $ | 36 | $ | 36 | $ | 36 | $ | 3,405 | |||||||||||||||
7.25% Notes due 2014 | 1,200 | — | — | — | — | — | 1,200 | ||||||||||||||||||||||
7.375% Notes due 2016 | 2,400 | — | — | — | — | — | 2,400 | ||||||||||||||||||||||
Total Debt | $ | 7,175 | $ | 26 | $ | 36 | $ | 36 | $ | 36 | $ | 36 | $ | 7,005 | |||||||||||||||
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Historical Cash Flows |
Predecessor | ||||||||||||||||
Reorganized NRG | Company | |||||||||||||||
For the Period | For the Period | |||||||||||||||
Year Ended | Year Ended | December 6- | January 1- | |||||||||||||
December 31, | December 31, | December 31, | December 5, | |||||||||||||
2005 | 2004 | 2003 | 2003 | |||||||||||||
(In millions) | ||||||||||||||||
Net cash provided (used) by operating activities | $ | 68 | $ | 645 | $ | (589 | ) | $ | 238 | |||||||
Net cash (used) provided by investing activities | 158 | 184 | 363 | (186 | ) | |||||||||||
Net cash provided (used) by financing activities | (830 | ) | (284 | ) | 393 | (30 | ) |
Net Cash Provided (Used) By Operating Activities |
• | Net income decreased by $102 million for the year ended December 31, 2005 compared to the year ended December 31, 2004. | |
• | Due to the sharp increase in the sale price per MWh, our derivative contract terms required collateral deposits of $405 million during 2005, compared to $7 million during 2004, a difference of $398 million. As of December 31, 2005 we had collateral deposits of $438 million and we expect $405 of this amount to be refunded during 2006 as the underlying contracts expire. | |
• | A decrease of $60 million in distributions from our equity investments during 2005 compared to 2004. The majority of this decrease is from our WCP investment. Since the expiration of the CDWR contract on December 31, 2004, WCP’s profit has been significantly reduced and has subsequently distributed $59 million less dividends during 2005 compared to 2004. | |
• | Receipt of $100 million in 2004 related to the settlement with Xcel Energy. |
Net Cash Provided (Used) By Investing Activities |
• | During 2004, we sold interests in non-core assets for proceeds totaling $304 million. As most of the non-core assets were sold during 2004 and management began focusing on different areas of operation, during 2005 proceeds from the sale of non-core assets fell by $198 million. | |
• | Our capital expenditures were $13 million less during 2005 compared to 2004 due to lower PRB conversion expenditures. | |
• | During 2005, proceeds from payments on our notes receivable increased by $82 million, primarily due to the payment from TermoRio of approximately $71 million as the dispute related to this note was settled. |
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• | In comparison to an increase of $27 million during 2004, restricted cash balances decreased by $46 million, a difference of $72 million. This amount is explained by the release of approximately $38 million of restricted cash at our Flinders facility as a result of our refinancing of Flinders’ debt, as well as the release of accounts from restrictions during post bankruptcy operations. |
Net Cash Provided (Used) By Financing Activities |
• | The redemption and repurchase of $645 million of our Second Priority Secured Notes. In order to redeem our Second Priority Notes, we issued $420 million of the 4% Preferred Stock in December 2004, and subsequently, $250 million of the 3.625% Preferred Stock in August of 2005. The timing difference between the receipt of cash from our 4% Preferred Stock in December 2004 and the redemption of debt in 2005 is the primary reason for the increase in cash used for financing activities in 2005 in comparison to 2004. | |
• | Our accelerated share repurchase payment of $250 million. | |
• | Payment of $46 million for financing costs to refinance our Flinders’ debt. | |
• | Payment of $20 million of dividends to holders of our preferred stock. |
Other Liquidity Matters — NOLs and Deferred Tax Assets |
Conclusion on Future Liquidity |
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Known Trends and Other Factors Affecting our Liquidity |
New Senior Credit Facility |
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• | incur indebtedness and liens and enter into sale and lease-back transactions; | |
• | make investments, loans and advances; | |
• | engage in mergers, acquisitions, consolidations and asset sales; | |
• | pay dividends and make other restricted payments; | |
• | enter into transactions with affiliates; | |
• | make capital expenditures; | |
• | make debt payments; and | |
• | make certain changes to the terms of material indebtedness. |
Senior Notes |
• | make restricted payments; | |
• | restrict dividends or other payments of subsidiaries; | |
• | incur additional debt; | |
• | engage in transactions with affiliates; | |
• | create liens on assets; |
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• | engage in sale and leaseback transactions; and | |
• | consolidate, merge or transfer all or substantially all of its assets and the assets of its subsidiaries. |
Second Lien Structure |
Mandatory Convertible Preferred Stock |
Common Stock |
Sale of Audrain |
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Brownfield Developments |
Obligations Under Certain Guarantee Contracts |
Retained or Contingent Interests |
Derivative Instrument obligations |
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity |
Variable interest in Equity investments |
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New Synthetic Letter of Credit Facility and Revolver Facility |
Contractual Obligations and Commercial Commitments |
Payments Due by Period as of December 31, 2005 | |||||||||||||||||||||
After | |||||||||||||||||||||
Contractual Cash Obligations | Total | Short-term | 2-3 Years | 4-5 Years | 5 Years | ||||||||||||||||
(In millions) | |||||||||||||||||||||
Long-term debt (including estimated interest) | $ | 3,600 | $ | 201 | $ | 391 | $ | 408 | $ | 2,600 | |||||||||||
Capital lease obligations (including estimated interest) | 406 | 77 | 90 | 52 | 187 | ||||||||||||||||
Operating leases | 150 | 25 | 37 | 27 | 61 | ||||||||||||||||
Coal purchase and transportation obligations | 416 | 192 | 154 | 52 | 18 | ||||||||||||||||
Total contractual cash obligations | $ | 4,572 | $ | 495 | $ | 672 | $ | 539 | $ | 2,866 | |||||||||||
Amount of Guarantee Liabilities Expiration per Period as of | |||||||||||||||||||||
December 31, 2005 | |||||||||||||||||||||
Total | |||||||||||||||||||||
Amounts | After | ||||||||||||||||||||
Guarantee Type | Committed | Short-term | 2-3 Years | 4-5 Years | 5 Years | ||||||||||||||||
(In millions) | |||||||||||||||||||||
Funded standby letters of credit | $ | 312 | $ | 312 | $ | — | $ | — | $ | — | |||||||||||
Unfunded standby letters of credit | 9 | 9 | — | — | — | ||||||||||||||||
Surety bonds | 4 | 4 | — | — | — | ||||||||||||||||
Asset sales guarantee obligations | 123 | — | 13 | — | 110 | ||||||||||||||||
Commodity sales guarantee obligations | 91 | 62 | 12 | 14 | 3 | ||||||||||||||||
Other guarantees | 91 | — | 1 | — | 90 | ||||||||||||||||
Total guarantees | $ | 630 | $ | 387 | $ | 26 | $ | 14 | $ | 203 | |||||||||||
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Derivative Activity Gains/(Losses) |
(In millions) | ||||
Fair value of contracts at December 31, 2004 | $ | (43 | ) | |
Contracts realized or otherwise settled during the period | 129 | |||
Changes in fair value | (490 | ) | ||
Fair value of contracts at December 31, 2005 | $ | (404 | ) | |
Sources of Fair Value Gains/(Losses) |
Fair Value of Contracts as of December 31, 2005 | ||||||||||||||||||||
Maturity | Maturity | |||||||||||||||||||
Less Than | Maturity | Maturity | in Excess | Total Fair | ||||||||||||||||
1 Year | 1-3 Years | 4-5 Years | of 5 Years | Value | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Prices actively quoted | $ | (243 | ) | $ | (12 | ) | $ | — | $ | — | $ | (255 | ) | |||||||
Prices based on models and other valuation methods | 2 | (22 | ) | (10 | ) | (38 | ) | (68 | ) | |||||||||||
Prices provided by other external sources | (53 | ) | (1 | ) | 6 | (33 | ) | (81 | ) | |||||||||||
Total | $ | (294 | ) | $ | (35 | ) | $ | (4 | ) | $ | (71 | ) | $ | (404 | ) | |||||
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Accounting Policy | Judgments/Uncertainties Affecting Application | |
Revenue Recognition and Derivative Activity | • Assumptions used in valuation models | |
• Market maturity and economic conditions | ||
• Contract interpretation | ||
• Market conditions in the energy industry, especially the effects of price volatility on contractual commitments | ||
• Documentation requirements | ||
• Market conditions in foreign countries | ||
• 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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Revenue Recognition and Derivative Instruments |
Income Taxes and Valuation Allowance for Deferred Tax Assets |
Evaluation of Assets for Impairment and Other Than Temporary Decline in Value |
• | Significant decrease in the market price of a long-lived asset; |
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• | Significant adverse change in the manner an asset is being used or its physical condition; | |
• | Adverse business climate; | |
• | Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset, | |
• | Current-period loss combined with a history of losses or the projection of future losses; | |
• | Change in our 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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Goodwill and Other Intangible Assets |
Contingencies |
Recent Accounting Developments |
• | Manage and hedge our fixed-price purchase and sales commitments; | |
• | Manage and hedge our exposure to variable rate debt obligations, | |
• | Reduce our exposure to the volatility of cash market prices; and | |
• | Hedge our fuel requirements for our generating facilities. |
• | Seasonal daily and hourly changes in demand | |
• | Extreme peak demands due to weather conditions |
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• | Available supply resources | |
• | Transportation availability and reliability within and between regions | |
• | Changes in the nature and extent of federal and state regulations |
(In millions) | |||||
Year end December 31, 2005 | $ | 36.9 | |||
Average | 27.6 | ||||
High | 45.9 | ||||
Low | 16.0 | ||||
Year end December 31, 2004 | 26.7 | ||||
Average | 40.3 | ||||
High | 53.4 | ||||
Low | 26.7 |
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Interest Rate Risk |
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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Liquidity Risk |
Credit Risk |
Exposure | |||||||||||||
Before | Net | ||||||||||||
Collateral | Collateral | Exposure | |||||||||||
(In millions) | |||||||||||||
Investment grade | $ | 518 | $ | 96 | $ | 422 | |||||||
Non-investment grade | 24 | 5 | 19 | ||||||||||
Not rated | 164 | 25 | 139 | ||||||||||
Total | $ | 706 | $ | 126 | $ | 580 | |||||||
Investment grade | 73 | % | 76 | % | 73 | % | |||||||
Non-investment grade | 3 | % | 4 | % | 3 | % | |||||||
Not rated | 24 | % | 20 | % | 24 | % |
Currency Exchange Risk |
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128
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Item 12 — | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
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Consolidated Statement of Operations — Year ended December 31, 2005 and the Year ended December 31, 2004 (Reorganized NRG) | |
Consolidated Balance Sheet — December 31, 2005 and December 31, 2004 (Reorganized NRG) | |
Consolidated Statement of Cash Flows — Year ended December 31, 2005 and the Year ended December 31, 2004 (Reorganized NRG) | |
Consolidated Statement of Stockholders’ Equity/(Deficit) and Comprehensive Income/(Loss) — Year ended December 31, 2005 and the Year ended December 31, 2004 (Reorganized NRG) | |
Notes to Consolidated Financial Statements |
Consolidated Statements of Operations — The period December 6, 2003 to December 31, 2003 (Reorganized NRG) and the period January 1, 2003 to December 5, 2003 (Predecessor Company) | |
Consolidated Statements of Cash Flows — The period December 6, 2003 to December 31, 2003 (Reorganized NRG) and the period January 1, 2003 to December 5, 2003 (Predecessor Company) | |
Consolidated Statements of Stockholders’ Equity/(Deficit) and Comprehensive Income/(Loss) — The period December 6, 2003 to December 31, 2003 (Reorganized NRG) and the period January 1, 2003 to December 5, 2003 (Predecessor Company) | |
Notes to Consolidated Financial Statements |
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/s/ KPMG LLP | |
KPMG LLP |
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/s/ KPMG LLP | |
KPMG LLP |
133
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/s/PricewaterhouseCoopers LLP | |
PricewaterhouseCoopers LLP |
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/s/PricewaterhouseCoopers LLP | |
PricewaterhouseCoopers LLP |
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Predecessor | ||||||||||||||||||||
Reorganized NRG | Company | |||||||||||||||||||
December 6, | January 1, | |||||||||||||||||||
2003 | 2003 | |||||||||||||||||||
Year Ended | Year Ended | Through | Through | |||||||||||||||||
December 31, | December 31, | December 31, | December 5, | |||||||||||||||||
2005 | 2004 | 2003 | 2003 | |||||||||||||||||
(In millions, except per share amounts) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Revenues from majority-owned operations | $ | 2,708 | $ | 2,348 | $ | 137 | $ | 1,798 | ||||||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of majority-owned operations | 2,067 | 1,489 | 95 | 1,354 | ||||||||||||||||
Depreciation and amortization | 194 | 208 | 12 | 211 | ||||||||||||||||
General, administrative and development | 197 | 210 | 13 | 170 | ||||||||||||||||
Other charges (credits) | ||||||||||||||||||||
Corporate relocation charges | 6 | 16 | — | — | ||||||||||||||||
Reorganization items | — | (13 | ) | 2 | 198 | |||||||||||||||
Restructuring and impairment charges | 6 | 45 | — | 237 | ||||||||||||||||
Fresh start reporting adjustments | — | — | — | (4,220 | ) | |||||||||||||||
Legal settlement | — | — | — | 463 | ||||||||||||||||
Total operating costs and expenses | 2,470 | 1,955 | 122 | (1,587 | ) | |||||||||||||||
Operating Income | 238 | 393 | 15 | 3,385 | ||||||||||||||||
Other Income/(Expense) | ||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | 104 | 160 | 14 | 171 | ||||||||||||||||
Write downs and losses on sales of equity method investments | (31 | ) | (16 | ) | — | (147 | ) | |||||||||||||
Other income, net | 62 | 27 | — | 19 | ||||||||||||||||
Refinancing expenses | (56 | ) | (72 | ) | — | — | ||||||||||||||
Interest expense | (197 | ) | (266 | ) | (19 | ) | (308 | ) | ||||||||||||
Total other expense | (118 | ) | (167 | ) | (5 | ) | (265 | ) | ||||||||||||
Income From Continuing Operations Before Income Taxes | 120 | 226 | 10 | 3,120 | ||||||||||||||||
Income Tax Expense/(Benefit) | 43 | 65 | (1 | ) | 38 | |||||||||||||||
Income From Continuing Operations | 77 | 161 | 11 | 3,082 | ||||||||||||||||
Income/(Loss) on Discontinued Operations, net of Income Taxes | 7 | 25 | — | (316 | ) | |||||||||||||||
Net Income | 84 | 186 | 11 | 2,766 | ||||||||||||||||
Preference stock dividends | 20 | — | — | — | ||||||||||||||||
Income Available for Common Stockholders | $ | 64 | $ | 186 | $ | 11 | $ | 2,766 | ||||||||||||
Weighted Average Number of Common Shares Outstanding — Basic | 85 | 100 | 100 | — | ||||||||||||||||
Income From Continuing Operations per Weighted Average Common Share — Basic | $ | 0.67 | $ | 1.61 | $ | 0.11 | — | |||||||||||||
Income From Discontinued Operations per Weighted Average Common Share — Basic | 0.09 | 0.25 | — | — | ||||||||||||||||
Net Income per Weighted Average Common Share — Basic | $ | 0.76 | $ | 1.86 | $ | 0.11 | — | |||||||||||||
Weighted Average Number of Common Shares Outstanding — Diluted | 85 | 100 | 100 | — | ||||||||||||||||
Income From Continuing Operations per Weighted Average Common Share — Diluted | $ | 0.66 | $ | 1.60 | $ | 0.11 | — | |||||||||||||
Income From Discontinued Operations per Weighted Average Common Share — Diluted | 0.09 | 0.25 | — | — | ||||||||||||||||
Net Income per Weighted Average Common Shares — Diluted | $ | 0.75 | $ | 1.85 | $ | 0.11 | — |
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Reorganized NRG | |||||||||||
December 31, | December 31, | ||||||||||
2005 | 2004 | ||||||||||
(In millions, except shares | |||||||||||
and par value) | |||||||||||
ASSETS | |||||||||||
Current Assets | |||||||||||
Cash and cash equivalents | $ | 506 | $ | 1,104 | |||||||
Restricted cash | 64 | 110 | |||||||||
Accounts receivable-trade, less allowance for doubtful accounts of $2 and $1 | 280 | 270 | |||||||||
Accounts receivable-affiliate | 4 | — | |||||||||
Current portion of notes receivable and capital lease | 25 | 85 | |||||||||
Property taxes receivable | 43 | 37 | |||||||||
Inventory | 260 | 247 | |||||||||
Derivative instruments valuation | 404 | 80 | |||||||||
Collateral on deposit in support of energy risk management activities | 438 | 33 | |||||||||
Deferred income taxes | 4 | — | |||||||||
Prepayments and other current assets | 125 | 136 | |||||||||
Current assets — held for sale | 43 | — | |||||||||
Current assets — discontinued operations | 1 | 17 | |||||||||
Total current assets | 2,197 | 2,119 | |||||||||
Property, Plant and Equipment, net | 3,039 | 3,158 | |||||||||
Other Assets | |||||||||||
Equity investments in affiliates | 603 | 735 | |||||||||
Notes receivable, less current portion — affiliates, net | 103 | 124 | |||||||||
Notes receivable and capital lease, less current portion, net | 355 | 440 | |||||||||
Intangible assets, net of accumulated amortization of $79 and $55 | 257 | 294 | |||||||||
Derivative instruments valuation | 22 | 42 | |||||||||
Funded letter of credit | 350 | 350 | |||||||||
Deferred income tax | 26 | 34 | |||||||||
Other assets | 125 | 111 | |||||||||
Non-current assets — discontinued operations | 354 | 457 | |||||||||
Total other assets | 2,195 | 2,587 | |||||||||
Total Assets | $ | 7,431 | $ | 7,864 | |||||||
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Reorganized NRG | |||||||||||
December 31, | December 31, | ||||||||||
2005 | 2004 | ||||||||||
(In millions, except shares | |||||||||||
and par value) | |||||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
Current Liabilities | |||||||||||
Current portion of long-term debt and capital leases | $ | 101 | $ | 511 | |||||||
Accounts payable — trade | 268 | 209 | |||||||||
Accounts payable — affiliates | — | 5 | |||||||||
Derivative instruments valuation | 692 | 17 | |||||||||
Other bankruptcy settlement | 3 | 6 | |||||||||
Accrued expenses | 82 | 57 | |||||||||
Other current liabilities | 95 | 109 | |||||||||
Current liabilities — discontinued operations | 115 | 173 | |||||||||
Total current liabilities | 1,356 | 1,087 | |||||||||
Other Liabilities | |||||||||||
Long-term debt and capital leases | 2,581 | 2,973 | |||||||||
Deferred income taxes | 135 | 169 | |||||||||
Postretirement and other benefit obligations | 125 | 116 | |||||||||
Derivative instruments valuation | 137 | 148 | |||||||||
Out of market contracts | 298 | 319 | |||||||||
Other long-term obligations | 81 | 71 | |||||||||
Non-current liabilities — discontinued operations | 240 | 288 | |||||||||
Total non-current liabilities | 3,597 | 4,084 | |||||||||
Total liabilities | 4,953 | 5,171 | |||||||||
Minority interest | 1 | 1 | |||||||||
3.625% Convertible Perpetual Preferred Stock; $.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs) | 246 | — | |||||||||
Commitments and Contingencies | |||||||||||
Stockholders’ Equity | |||||||||||
4% Convertible Perpetual Preferred Stock; $.01 par value; 420,000 shares issued and outstanding at December 31, 2005 and 2004 (at liquidation value of $420, net of issuance costs) | 406 | 406 | |||||||||
Common stock; $.01 par value; 100,048,676 and 100,041,935 shares issued and 80,701,888 and 87,041,935 outstanding at December 31, 2005 and 2004, respectively | 1 | 1 | |||||||||
Additional paid-in capital | 2,431 | 2,417 | |||||||||
Retained earnings | 261 | 197 | |||||||||
Less treasury stock, at cost; 19,346,788 and 13,000,000 shares as of December 31, 2005 and 2004, respectively | (663 | ) | (405 | ) | |||||||
Accumulated other comprehensive income/(loss) | (205 | ) | 76 | ||||||||
Total stockholders’ equity | 2,231 | 2,692 | |||||||||
Total Liabilities and Stockholders’ Equity | $ | 7,431 | $ | 7,864 | |||||||
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Accumulated | Total | ||||||||||||||||||||||||||||||||||||
Serial Preferred | Common | Additional | Retained | Other | Stockholders’ | ||||||||||||||||||||||||||||||||
Paid-In | Earnings/ | Treasury | Comprehensive | Equity/ | |||||||||||||||||||||||||||||||||
Stock | Shares | Stock | Shares | Capital | (Deficit) | Stock | Income/(Loss) | (Deficit) | |||||||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||||||||||||
Balances at December 31, 2002 (Predecessor Company) | $ | — | — | $ | — | — | $ | 2,228 | $ | (2,829 | ) | $ | — | $ | (95 | ) | $ | (696 | ) | ||||||||||||||||||
Net income | 2,766 | 2,766 | |||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments and other | 128 | 128 | |||||||||||||||||||||||||||||||||||
Deferred unrealized loss on derivatives, net | (32 | ) | (32 | ) | |||||||||||||||||||||||||||||||||
Comprehensive income for the period from January 1, 2003 through December 5, 2003 | 2,862 | ||||||||||||||||||||||||||||||||||||
Effects of reorganization | (2,228 | ) | 63 | (1 | ) | (2,166 | ) | ||||||||||||||||||||||||||||||
Issuance of common stock | 1 | 100 | 2,403 | 2,404 | |||||||||||||||||||||||||||||||||
Balances at December 5, 2003 (Predecessor Company) | $ | — | — | $ | 1 | 100 | $ | 2,403 | $ | — | $ | — | $ | — | $ | 2,404 | |||||||||||||||||||||
Net income | 11 | 11 | |||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments and other | 23 | 23 | |||||||||||||||||||||||||||||||||||
Deferred unrealized loss on derivatives, net | (1 | ) | (1 | ) | |||||||||||||||||||||||||||||||||
Comprehensive income for the period from December 6, 2003 through December 31, 2003 | 33 | ||||||||||||||||||||||||||||||||||||
Balances at December 31, 2003 (Reorganized NRG) | $ | — | — | $ | 1 | 100 | $ | 2,403 | $ | 11 | $ | — | $ | 22 | $ | 2,437 | |||||||||||||||||||||
Net income | 186 | 186 | |||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments and other | 46 | 46 | |||||||||||||||||||||||||||||||||||
Deferred unrealized gain on derivatives, net | 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 (Reorganized NRG) | $ | 406 | 0.4 | $ | 1 | 87 | $ | 2,417 | $ | 197 | $ | (405 | ) | $ | 76 | $ | 2,692 | ||||||||||||||||||||
Net income | 84 | 84 | |||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments and other | (72 | ) | (72 | ) | |||||||||||||||||||||||||||||||||
Deferred unrealized loss on derivatives, net | (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 (Reorganized NRG) | $ | 406 | 0.4 | $ | 1 | 81 | $ | 2,431 | $ | 261 | $ | (663 | ) | $ | (205 | ) | $ | 2,231 | |||||||||||||||||||
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Reorganized NRG | Predecessor Company | ||||||||||||||||||
Year Ended | Year Ended | December 6, 2003 | January 1, 2003 | ||||||||||||||||
December 31, | December 31, | Through | Through | ||||||||||||||||
2005 | 2004 | December 31, 2003 | December 5, 2003 | ||||||||||||||||
(In millions) | |||||||||||||||||||
Cash Flows from Operating Activities | |||||||||||||||||||
Net income | $ | 84 | $ | 186 | $ | 11 | $ | 2,766 | |||||||||||
Adjustments to reconcile net income to net cash provided by operating activities | |||||||||||||||||||
Distributions in excess of (less than) equity earnings of unconsolidated affiliates | (8 | ) | (1 | ) | 2 | (41 | ) | ||||||||||||
Depreciation and amortization | 195 | 215 | 13 | 257 | |||||||||||||||
Reserve for note and interest receivable | — | 12 | — | — | |||||||||||||||
Amortization of financing costs and debt discount/(premium) | 22 | 28 | 2 | 18 | |||||||||||||||
Write-off of deferred financing costs due to refinancings | (8 | ) | 42 | — | — | ||||||||||||||
Write downs and losses on sales of equity method investments | 31 | 16 | — | 147 | |||||||||||||||
Deferred income taxes and investment tax credits | 2 | 57 | (3 | ) | (2 | ) | |||||||||||||
Unrealized (gains)/losses on derivatives | 143 | (74 | ) | 4 | (35 | ) | |||||||||||||
Minority interest | 1 | 1 | — | 2 | |||||||||||||||
Amortization of intangible assets | 17 | 52 | (13 | ) | — | ||||||||||||||
Amortization of unearned equity compensations | 12 | 14 | — | — | |||||||||||||||
Restructuring and impairment charges | 6 | 45 | — | 408 | |||||||||||||||
Fresh start reporting adjustments | — | — | — | (3,895 | ) | ||||||||||||||
Loss on sale and disposal of assets | 4 | 1 | — | — | |||||||||||||||
Gain on sale of discontinued operations | (6 | ) | (23 | ) | — | (186 | ) | ||||||||||||
Gain on TermoRio settlement | (14 | ) | — | — | — | ||||||||||||||
Collateral deposit payments in support of energy risk management activities | (405 | ) | (7 | ) | (8 | ) | — | ||||||||||||
Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions | |||||||||||||||||||
Accounts receivable, net | (8 | ) | (52 | ) | 18 | 28 | |||||||||||||
Xcel Energy settlement receivable | — | 640 | — | — | |||||||||||||||
Inventory | (14 | ) | (56 | ) | 11 | 14 | |||||||||||||
Prepayments and other current assets | (35 | ) | 126 | (71 | ) | (37 | ) | ||||||||||||
Accounts payable | 57 | 50 | (40 | ) | 649 | ||||||||||||||
Accrued expenses | (8 | ) | (21 | ) | (67 | ) | 217 | ||||||||||||
Creditor pool obligation payments | — | (540 | ) | — | — | ||||||||||||||
Other current liabilities | (8 | ) | (106 | ) | (441 | ) | (23 | ) | |||||||||||
Other assets and liabilities | 8 | 40 | (7 | ) | (49 | ) | |||||||||||||
Net Cash Provided (Used) by Operating Activities | 68 | 645 | (589 | ) | 238 | ||||||||||||||
Cash Flows from Investing Activities | |||||||||||||||||||
Proceeds from sale of discontinued operations | 36 | 253 | — | 19 | |||||||||||||||
Proceeds from sale of investments | 70 | 51 | — | 107 | |||||||||||||||
Proceeds from sale of turbines and other property, plant and equipment | 9 | 4 | — | 71 | |||||||||||||||
Decrease/(increase) in restricted cash and trust funds | 45 | (27 | ) | 375 | (266 | ) | |||||||||||||
Decrease/(increase) in notes receivable | 107 | 25 | 1 | (2 | ) | ||||||||||||||
Deferred acquisition costs | (5 | ) | — | — | — | ||||||||||||||
Capital expenditures | (106 | ) | (119 | ) | (11 | ) | (114 | ) | |||||||||||
Return of capital/(Investments) in projects | 2 | (3 | ) | (2 | ) | (1 | ) | ||||||||||||
Net Cash Provided (Used) by Investing Activities | 158 | 184 | 363 | (186 | ) | ||||||||||||||
Cash Flows from Financing Activities | |||||||||||||||||||
Payment of dividends to preferred shareholders | (20 | ) | — | — | — | ||||||||||||||
Repayment of minority interest obligations | (4 | ) | — | — | — | ||||||||||||||
Accelerated share repurchase payment, net | (250 | ) | — | — | — | ||||||||||||||
Purchase of treasury stock | — | (405 | ) | — | — | ||||||||||||||
Issuance of 4% Preferred Stock, net | — | 406 | — | — | |||||||||||||||
Issuance of 3.625% Preferred Stock, net | 246 | — | — | — | |||||||||||||||
Proceeds from issuance of long-term debt, net | 249 | 1,333 | 2,450 | 40 | |||||||||||||||
Deferred debt issuance costs | (46 | ) | (26 | ) | (75 | ) | (19 | ) | |||||||||||
Funded letter of credit | — | (100 | ) | (250 | ) | — | |||||||||||||
Principal payments on short and long-term debt | (1,005 | ) | (1,492 | ) | (1,732 | ) | (51 | ) | |||||||||||
Net Cash Provided (Used) by Financing Activities | (830 | ) | (284 | ) | 393 | (30 | ) | ||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | (2 | ) | 3 | (14 | ) | (22 | ) | ||||||||||||
Change in Cash from Discontinued Operations | 8 | 6 | 1 | 35 | |||||||||||||||
Net Increase/(Decrease) in Cash and Cash Equivalents | (598 | ) | 554 | 154 | 35 | ||||||||||||||
Cash and Cash Equivalents at Beginning of Period | 1,104 | 550 | 396 | 361 | |||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 506 | $ | 1,104 | $ | 550 | $ | 396 | |||||||||||
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Note 1 — | Organization |
General |
Note 2 — | Summary of Significant Accounting Policies |
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Principles of Consolidation and Basis of Presentation |
“Predecessor Company” | The Company, pre-emergence from bankruptcy | |
The Company’s operations prior to December 6, 2003 | ||
“Reorganized NRG” | The Company, post-emergence from bankruptcy | |
The Company’s operations, December 6, 2003-December 31, 2005 |
Fresh Start Reporting |
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Cash and Cash Equivalents |
Restricted Cash |
143
Table of Contents
Inventory |
Property, Plant and Equipment |
Facilities and equipment | 1-42 years | |
Office furnishings and equipment | 2-10 years |
Asset Impairments |
Discontinued Operations |
Capitalized Interest |
144
Table of Contents
Capitalized Project Costs |
Debt Issuance Costs |
Intangible Assets |
Income Taxes |
Revenue Recognition |
145
Table of Contents
Derivative Financial Instruments |
146
Table of Contents
Foreign Currency Translation and Transaction Gains and Losses |
Concentrations of Credit Risk |
Fair Value of Financial Instruments |
Pensions |
147
Table of Contents
Stock Based Compensation |
Use of Estimates |
Reclassifications |
Recent Accounting Developments |
148
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149
Table of Contents
150
Table of Contents
Note 3 — | Emergence from Bankruptcy and Fresh Start Reporting |
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Company | NRG | |||||||||||||||||||
December 5, | Debt Discharge and | Fresh Start | December 6, | |||||||||||||||||
2003 | Exchange of Stock | Adjustments | Consolidation | 2003 | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Current Assets | $ | 1,718 | $ | 614 | $ | 4 | $ | 6 | $ | 2,342 | ||||||||||
Non-current Assets | 8,172 | (155 | ) | (1,233 | ) | 41 | 6,825 | |||||||||||||
Total Assets | $ | 9,890 | $ | 459 | $ | (1,229 | ) | $ | 47 | $ | 9,167 | |||||||||
Current Liabilities | 2,190 | 999 | 1,187 | 1 | 4,377 | |||||||||||||||
Non-current Liabilities | 9,458 | (6,270 | ) | (848 | ) | 46 | 2,386 | |||||||||||||
Total Liabilities | 11,648 | (5,271 | ) | 339 | 47 | 6,763 | ||||||||||||||
Stockholders Equity | (1,758 | ) | 2,404 | 1,758 | — | 2,404 | ||||||||||||||
Total Liabilities and Stockholders Equity | $ | 9,890 | $ | (2,867 | ) | $ | 2,097 | $ | 47 | $ | 9,167 | |||||||||
Note 4 — | Debtors’ Statements |
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For the Period | |||||
May 15, 2003 – | |||||
December 5, | |||||
2003 | |||||
(In millions) | |||||
Operating revenue | $ | 731 | |||
Operating costs and expenses | (620 | ) | |||
Fresh start reporting adjustments — asset write-downs, net | (1,244 | ) | |||
Reorganization items | (27 | ) | |||
Restructuring and impairment charges | (23 | ) | |||
Operating loss | (1,183 | ) | |||
Other expense | (161 | ) | |||
Net loss | $ | (1,344 | ) | ||
For the Period | ||||
May 15, 2003 | ||||
December 5, | ||||
2003 | ||||
(In millions) | ||||
Net cash provided by operating activities | $ | 66 | ||
Net cash used by investing activities | (73 | ) | ||
Net cash used by financing activities | — | |||
— | ||||
Net increase in cash and cash equivalents | (7 | ) | ||
Cash and cash equivalents at beginning of period | 23 | |||
Cash and cash equivalents at end of period | $ | 16 | ||
Note 5 — | Financial Instruments |
Reorganized NRG | ||||||||||||||||
December 31, 2005 | December 31, 2004 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Amount | Fair Value | Amount | Fair Value | |||||||||||||
(In millions) | ||||||||||||||||
Cash and cash equivalents | $ | 506 | $ | 506 | $ | 1,104 | $ | 1,104 | ||||||||
Restricted cash | 64 | 64 | 110 | 110 | ||||||||||||
Trust fund investments | 20 | 20 | 20 | 20 | ||||||||||||
Unfunded letters of credit and surety bonds | — | 13 | — | 21 | ||||||||||||
Notes receivable, including current portion | 483 | 494 | 649 | 662 | ||||||||||||
Long-term debt, including current portion | 2,682 | 2,809 | 3,484 | 3,624 |
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Note 6 — | Discontinued Operations |
154
Table of Contents
Reorganized NRG | ||||||||
December 31, | December 31, | |||||||
2005 | 2004 | |||||||
Wholesale | Wholesale | |||||||
Power | Power | |||||||
Generation | Generation | |||||||
Other | Other | |||||||
North | North | |||||||
America | America | |||||||
Consists of | ||||||||
McClain, | ||||||||
Northbrook | ||||||||
New York, | ||||||||
Northbrook | ||||||||
Consists of | Energy and | |||||||
Audrain | Audrain | |||||||
(In millions) | ||||||||
Cash and cash equivalents | $ | — | $ | 8 | ||||
Restricted cash | — | 5 | ||||||
Receivables, net | — | 2 | ||||||
Inventory | 1 | 1 | ||||||
Other current assets | — | 1 | ||||||
— | — | |||||||
Current assets — discontinued operations | 1 | 17 | ||||||
Property, plant and equipment, net | 114 | 217 | ||||||
Notes Receivable | 240 | 240 | ||||||
Non-current assets — discontinued operations | 354 | 457 | ||||||
Current portion of long-term debt | — | 1 | ||||||
Accounts payable — trade | — | 1 | ||||||
Other current liabilities | 115 | 171 | ||||||
Current liabilities — discontinued operations | 115 | 173 | ||||||
Long-term debt | 240 | 281 | ||||||
Minority interest | — | 6 | ||||||
Other non-current liabilities | — | 1 | ||||||
Non-current liabilities — discontinued operations | 240 | 288 |
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Initial Discontinued | ||||||
Operations | ||||||
Project | Segment | Treatment Date | Disposal Date | |||
Killingholme | Other International | Fourth Quarter 2002 | First Quarter 2003 | |||
NLGI | Alternative Energy | Second Quarter 2003 | Second Quarter 2003 | |||
TERI | Non-Generation | Third Quarter 2003 | Third Quarter 2003 | |||
McClain | Other North America | Third Quarter 2003 | Third Quarter 2004 | |||
NEO Corporation (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC) | Alternative Energy | Fourth Quarter 2003 | Fourth Quarter 2003 | |||
Cahua and Energia Pacasmayo | Other International | Fourth Quarter 2003 | Fourth Quarter 2003 | |||
PERC | Other North America | First Quarter 2004 | Second Quarter 2004 | |||
Cobee | Other International | First Quarter 2004 | Second Quarter 2004 | |||
Hsin Yu | Other International | Second Quarter 2004 | Second Quarter 2004 | |||
LSP Energy (Batesville) | Other North America | Second Quarter 2004 | Third Quarter 2004 | |||
NEO Corporation (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha LLC and NEO Tajiguas LLC) | Alternative Energy | Third Quarter 2004 | Third Quarter 2004 | |||
Northbrook New York and Northbrook Energy | Other North America | Third Quarter 2005 | Third Quarter 2005 | |||
Audrain | Other North America | Fourth Quarter 2005 | Second Quarter 2006 |
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Predecessor | |||||||||||||||||
Reorganized NRG | Company | ||||||||||||||||
For the Period | For the Period | ||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | ||||||||||||||
December 31, | December 31, | December 31, | December 5, | ||||||||||||||
Description | 2005 | 2004 | 2003 | 2003 | |||||||||||||
(In millions) | |||||||||||||||||
Operating revenues | $ | 15 | $ | 122 | $ | 20 | $ | 263 | |||||||||
Operating costs and other expenses | 13 | 119 | 20 | 753 | |||||||||||||
Pre-tax income/(loss) from operations of discontinued components | 2 | 3 | — | (490 | ) | ||||||||||||
Income tax expense/(benefit) | 1 | — | — | (22 | ) | ||||||||||||
Income/(loss) from operations of discontinued components | 1 | 3 | — | (468 | ) | ||||||||||||
Disposal of discontinued components — pre-tax gain (net) | 13 | 30 | — | 152 | |||||||||||||
Income tax expense/(benefit) | 7 | 8 | — | — | |||||||||||||
Disposal of discontinued components — gain (net) | 6 | 22 | — | 152 | |||||||||||||
Income/(loss) on discontinued operations, net of income taxes | $ | 7 | $ | 25 | $ | — | $ | (316 | ) | ||||||||
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Predecessor | |||||||||||||||||||
Reorganized NRG | Company | ||||||||||||||||||
For the Period | For the Period | ||||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | ||||||||||||||||
December 31, | December 31, | December 31, | December 5, | ||||||||||||||||
Project | Segment | 2005 | 2004 | 2003 | 2003 | ||||||||||||||
(In millions) | |||||||||||||||||||
Northbrook Energy, Northbrook New York | Other North America | $ | 12 | $ | — | $ | — | $ | — | ||||||||||
McClain | Other North America | — | (3 | ) | — | — | |||||||||||||
PERC | Other North America | — | 3 | — | — | ||||||||||||||
Cobee | Other International | — | 3 | — | — | ||||||||||||||
LSP Energy — Batesville | Other North America | — | 11 | — | — | ||||||||||||||
Hsin Yu | Other International | — | 10 | — | — | ||||||||||||||
NEO Nashville, Hackensack, Prima Deshecha, Tajiguas | Alternative Energy | — | 6 | — | — | ||||||||||||||
Killingholme | Other International | — | — | — | 191 | ||||||||||||||
TERI | Non-Generation | — | — | — | 1 | ||||||||||||||
Cahua and Energia Pacasmayo | Other International | — | — | — | (37 | ) | |||||||||||||
Others | — | — | — | (3 | ) | ||||||||||||||
Total gain on disposal of discontinued components — pre-tax | $ | 12 | $ | 30 | $ | — | $ | 152 | |||||||||||
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Note 7 — | Write Downs and (Gains)/ Losses on Sales of Equity Method Investments |
Predecessor | |||||||||||||||||||
Reorganized NRG | Company | ||||||||||||||||||
For the Period | For the Period | ||||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | ||||||||||||||||
December 31, | December 31, | December 31, | December 5, | ||||||||||||||||
Segment | 2005 | 2004 | 2003 | 2003 | |||||||||||||||
(In millions) | |||||||||||||||||||
Saguaro | Western | $ | 27 | $ | — | $ | — | $ | — | ||||||||||
Rocky Road | Other North America | 20 | — | — | — | ||||||||||||||
Kendall | Other North America | (4 | ) | — | — | — | |||||||||||||
Enfield | Other International | (12 | ) | — | — | — | |||||||||||||
Commonwealth Atlantic Limited Partnership | Other North America | — | 5 | — | — | ||||||||||||||
James River Power LLC | Other North America | — | 7 | — | — | ||||||||||||||
NEO Corporation | Alternative Energy | — | 4 | — | — | ||||||||||||||
Calpine Cogeneration | Other North America | — | (1 | ) | — | — | |||||||||||||
NLGI — Minnesota Methane | Alternative Energy | — | — | — | 12 | ||||||||||||||
NLGI — MM Biogas | Alternative Energy | — | — | — | 3 | ||||||||||||||
ECKG | Other International | — | — | — | (3 | ) | |||||||||||||
Loy Yang | Australia | — | 1 | — | 146 | ||||||||||||||
Mustang | Other North America | — | — | — | (12 | ) | |||||||||||||
Other | — | — | — | 1 | |||||||||||||||
Total write downs and losses on sales of equity method investments | $ | 31 | $ | 16 | $ | — | $ | 147 | |||||||||||
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Predecessor | ||||||||||||||||||
Reorganized NRG | Company | |||||||||||||||||
For the Period | For the Period | |||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | |||||||||||||||
December 31, | December 31, | December 31, | December 5, | |||||||||||||||
2005 | 2004 | 2003 | 2003 | |||||||||||||||
(In millions) | ||||||||||||||||||
Corporate relocation charges | $ | 6 | $ | 16 | $ | — | $ | — | ||||||||||
Reorganization items | — | (13 | ) | 2 | 198 | |||||||||||||
Impairment charges | 6 | 45 | — | 229 | ||||||||||||||
Restructuring charges | — | — | — | 8 | ||||||||||||||
Fresh Start adjustments | — | — | — | (4,220 | ) | |||||||||||||
Legal settlement | — | — | — | 463 | ||||||||||||||
Total | $ | 12 | $ | 48 | $ | 2 | $ | (3,322 | ) | |||||||||
Corporate Relocation Charges |
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Year Ended | Year Ended | ||||||||||||||||
December 31, | December 31, | Yet to be | Expected | ||||||||||||||
2004 | 2005 | Incurred | Total Charges | ||||||||||||||
(In millions) | |||||||||||||||||
Employee related transition costs | $ | 9 | $ | 2 | $ | — | $ | 11 | |||||||||
Severance and termination benefits | 6 | 1 | — | 7 | |||||||||||||
Lease termination costs | 1 | 3 | — | 4 | |||||||||||||
Total corporate relocation charges | $ | 16 | $ | 6 | $ | — | $ | 22 | |||||||||
Balance at | Relocation | Balance at | |||||||||||||||
December 31, | Related | Cash | December 31, | ||||||||||||||
2004 | Charges | Payments | 2005 | ||||||||||||||
(In millions) | |||||||||||||||||
Employee related transition costs | $ | (1 | ) | $ | 2 | $ | (1 | ) | $ | — | |||||||
Severance and termination benefits | 4 | 1 | (5 | ) | — | ||||||||||||
Lease termination costs | 1 | 3 | (2 | ) | 2 | ||||||||||||
Total | $ | 4 | $ | 6 | $ | (8 | ) | $ | 2 | ||||||||
Reorganization Items |
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Predecessor | ||||||||||||||||||
Reorganized NRG | Company | |||||||||||||||||
For the period | For the Period | |||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | |||||||||||||||
December 31, | December 31, | December 31, | December 5, | |||||||||||||||
2005 | 2004 | 2003 | 2003 | |||||||||||||||
(In millions) | ||||||||||||||||||
Reorganization items | ||||||||||||||||||
Professional fees | $ | — | $ | 7 | $ | 2 | $ | 82 | ||||||||||
Deferred financing costs | — | — | — | 55 | ||||||||||||||
Pre-payment settlement | — | — | — | 20 | ||||||||||||||
Interest earned on accumulated cash | — | — | — | (1 | ) | |||||||||||||
Contingent equity obligation | — | — | — | 42 | ||||||||||||||
Settlement of obligations and other gains | — | (20 | ) | — | — | |||||||||||||
Total reorganization items | $ | — | $ | (13 | ) | $ | 2 | $ | 198 | |||||||||
Impairment Charges |
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Predecessor | ||||||||||||||||||
Company | ||||||||||||||||||
Reorganized NRG | ||||||||||||||||||
For the Period | ||||||||||||||||||
Year Ended | Year Ended | January 1 — | ||||||||||||||||
December 31, | December 31, | December 5, | ||||||||||||||||
Project Name | Project Status | 2005 | 2004 | 2003 | Fair Value Basis | |||||||||||||
(In millions) | ||||||||||||||||||
Berrians I Gas Turbine Power LLC | Non-operating asset | $ | 6 | $ | — | $ | — | Sales price | ||||||||||
Meriden (turbine only) | Pending sale | — | 15 | — | Sales price | |||||||||||||
Kendall | Sold | — | 27 | — | Realized loss | |||||||||||||
Louisiana Generating LLC | Office building and land being marketed | — | 1 | — | Estimated market price | |||||||||||||
New Roads Holding LLC (turbine) | Non-operating asset — abandoned | — | 2 | — | Projected cash flows | |||||||||||||
Devon Power LLC | Operating at a loss in 2003 | — | — | 64 | Projected cash flows | |||||||||||||
Middletown Power LLC | Operating at a loss Terminated | — | — | 157 | Projected cash flows | |||||||||||||
Arthur Kill Power, LLC | construction project | — | — | 9 | Projected cash flows | |||||||||||||
Langage (UK) | Terminated | — | — | (3 | ) | Estimated market price/Realized gain | ||||||||||||
Turbines | Sold | — | — | (22 | ) | Realized gain | ||||||||||||
Berrians Project | Terminated | — | — | 14 | Realized loss | |||||||||||||
TermoRio | Terminated | — | — | 7 | Realized loss | |||||||||||||
Other | — | — | 3 | |||||||||||||||
Total impairment charges | $ | 6 | $ | 45 | $ | 229 | ||||||||||||
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Restructuring Charges |
Fresh Start Adjustments |
(In millions) | |||||
Discharge of corporate level debt | $ | 5,162 | |||
Discharge of other liabilities | 811 | ||||
Establishment of creditor pool | (1,040 | ) | |||
Receivable from Xcel | 640 | ||||
Revaluation of fixed assets | (1,392 | ) | |||
Revaluation of equity investments | (207 | ) | |||
Valuation of SO(2) emission credits | 374 | ||||
Valuation of out of market contracts, net | (400 | ) | |||
Fair market valuation of debt | 108 | ||||
Valuation of pension liabilities | (61 | ) | |||
Other valuation adjustments | (100 | ) | |||
Total Fresh Start adjustments | 3,895 | ||||
Less discontinued operations | (325 | ) | |||
Total Fresh Start adjustments — continuing operations | $ | 4,220 | |||
Legal Settlement Charges |
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Note 9 — | Asset Retirement Obligation |
168
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Reorganized NRG | ||||||||||||||||||||||||||||||||
Total | ||||||||||||||||||||||||||||||||
Asset | ||||||||||||||||||||||||||||||||
South | Other | Alternative | Non | Retirement | ||||||||||||||||||||||||||||
Northeast | Central | Australia | International | Energy | Generation | Other | Obligation | |||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Balance as of December 31, 2003 | $ | 12 | $ | 3 | $ | 9 | $ | 4 | $ | 1 | $ | 1 | $ | — | $ | 30 | ||||||||||||||||
Additions | 1 | — | 3 | — | — | — | — | 4 | ||||||||||||||||||||||||
Accretion | — | — | 2 | — | — | — | — | 2 | ||||||||||||||||||||||||
Balance as of December 31, 2004 | 13 | 3 | 14 | 4 | 1 | 1 | — | 36 | ||||||||||||||||||||||||
Additions | 1 | — | — | — | — | — | 4 | 5 | ||||||||||||||||||||||||
Accretion | 1 | — | 1 | — | — | — | — | 2 | ||||||||||||||||||||||||
Translation adjustments | — | — | (1 | ) | — | — | — | — | (1 | ) | ||||||||||||||||||||||
Balance as of December 31, 2005 | $ | 15 | $ | 3 | $ | 14 | $ | 4 | $ | 1 | $ | 1 | $ | 4 | $ | 42 | ||||||||||||||||
Note 10 — | Inventory |
Reorganized NRG | |||||||||
December 31, | December 31, | ||||||||
2005 | 2004 | ||||||||
(In millions) | |||||||||
Fuel oil | $ | 132 | $ | 114 | |||||
Coal | 66 | 75 | |||||||
Natural gas | 4 | — | |||||||
Spare parts | 54 | 53 | |||||||
Other | 4 | 5 | |||||||
Total inventory | $ | 260 | $ | 247 | |||||
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Note 11 — | Notes Receivable and Capital Lease |
Reorganized NRG | ||||||||||
December 31, | December 31, | |||||||||
2005 | 2004 | |||||||||
(In millions) | ||||||||||
Notes Receivable — non-affiliate | ||||||||||
Omega Energy, LLC, due 2004, 12.5% | $ | — | $ | 4 | ||||||
Omega Energy II, LLC, due 2009, 11% | — | 1 | ||||||||
Elk River — Great River Energy, due December 31, 2008, 4.69% | 1 | 1 | ||||||||
Northbrook Texas LLC, due February 2024, 9.25% | — | 9 | ||||||||
Termo Rio (via NRGenerating Luxembourg (No. 2) S.a.r.l), 8.0% | — | 57 | ||||||||
Capital Lease | ||||||||||
VEAG Vereinigte Energiewerke AG, due August 31, 2021, 13.88% (direct financing lease)(1) | 379 | 461 | ||||||||
Notes receivable and capital lease — non-affiliates | 380 | 533 | ||||||||
Reserve for uncollectible notes receivable | — | (8 | ) | |||||||
Notes receivable non-affiliates and capital lease, net | 380 | 525 | ||||||||
Less current maturities | 25 | 85 | ||||||||
Total | $ | 355 | $ | 440 | ||||||
Notes Receivable — affiliates | ||||||||||
NEO notes to various affiliates due primarily 2012, prime +2% | — | 4 | ||||||||
Kraftwerke Schkopau GBR, indefinite maturity date, 4.75%-7.79%(2) | 103 | 120 | ||||||||
Notes receivable — affiliates | $ | 103 | $ | 124 | ||||||
(1) | Saale Energie GmbH, or Saale, 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. The direct financing lease receivable amount was calculated based on the present value of the income to be received over the life of the contract. |
(2) | Saale entered into a note receivable with Kraftwerke Schkopau GBR, a partnership between Saale and E.On Kraftwerke GmbH. The note was used to fund Saale’s initial capital contribution to the partnership and to cover project liquidity shortfalls during construction of a power plant. The note is subject to repayment upon the disposition of the Schkopau plant. |
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Note 12 — | Property, Plant and Equipment |
Reorganized NRG | Average | ||||||||||||||
Remaining | |||||||||||||||
Depreciable | December 31, | December 31, | Useful | ||||||||||||
Lives | 2005 | 2004 | Life | ||||||||||||
(In millions) | |||||||||||||||
Facilities and equipment | 1-42 Years | $ | 3,223 | $ | 3,199 | 14 | |||||||||
Land and improvements | 128 | 127 | |||||||||||||
Office furnishings and equipment | 2-10 Years | 26 | 21 | 3 | |||||||||||
Construction in progress | 54 | 17 | |||||||||||||
Total property, plant and equipment | 3,431 | 3,364 | |||||||||||||
Accumulated depreciation | (392 | ) | (206 | ) | |||||||||||
Net property, plant and equipment | $ | 3,039 | $ | 3,158 | |||||||||||
Note 13 — | Investments Accounted for by the Equity Method |
Economic | ||||||
Name | Geographic Area | Interest | ||||
MIBRAG mbH, or MIBRAG | Germany | 50% | ||||
Saguaro Power Company, or Saguaro | USA | 50% | ||||
Rocky Road Power | USA | 50% | ||||
Enfield Energy Centre Limited, or Enfield — sold on April 1, 2005 | UK | 25% | ||||
West Coast Power, or WCP | USA | 50% | ||||
James River | USA | 50% | ||||
Gladstone Power Station, or Gladstone | Australia | 37.5% | ||||
Central and Eastern European Energy Power Fund | Various | 22.2% | ||||
Scudder LA Power Fund I | Latin America | 25% |
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Predecessor | ||||||||||||||||||
Reorganized NRG | Company | |||||||||||||||||
For the Period | For the Period | |||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | |||||||||||||||
December 31, | December 31, | December 31, | December 5, | |||||||||||||||
2005 | 2004 | 2003 | 2003 | |||||||||||||||
(In millions) | ||||||||||||||||||
Summarized Statements of Operations | ||||||||||||||||||
Operating revenues | $ | 1,300 | $ | 2,428 | $ | 268 | $ | 2,212 | ||||||||||
Costs and expenses | 1,101 | 1,966 | 203 | 2,036 | ||||||||||||||
Net income | $ | 199 | $ | 462 | $ | 65 | $ | 176 | ||||||||||
Summarized Balance Sheets | ||||||||||||||||||
Current assets | $ | 592 | $ | 845 | $ | 830 | $ | 784 | ||||||||||
Non-current assets | 2,561 | 2,903 | 6,541 | 6,452 | ||||||||||||||
Total assets | $ | 3,153 | $ | 3,748 | $ | 7,371 | $ | 7,236 | ||||||||||
Current liabilities | 133 | 206 | 1,276 | 1,216 | ||||||||||||||
Non-current liabilities | 1,143 | 1,740 | 3,592 | 3,529 | ||||||||||||||
Equity | 1,877 | 1,802 | 2,503 | 2,491 | ||||||||||||||
Total liabilities and equity | $ | 3,153 | $ | 3,748 | $ | 7,371 | $ | 7,236 | ||||||||||
NRG’s share of equity and net income | ||||||||||||||||||
NRG’s share of equity | $ | 810 | $ | 809 | $ | 1,052 | $ | 1,079 | ||||||||||
NRG’s share of net income | $ | 104 | $ | 160 | $ | 14 | $ | 171 |
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MIBRAG Summarized Financial Information |
For the Year Ended | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
(In millions) | ||||||||||||
Operating revenues | $ | 432 | $ | 427 | $ | 401 | ||||||
Operating income | 72 | 61 | 62 | |||||||||
Net income (pre-tax) | 51 | 43 | 46 |
December 31, | |||||||||
2005 | 2004 | ||||||||
(In millions) | |||||||||
Current assets | $ | 121 | $ | 179 | |||||
Other assets | 1,134 | 1,295 | |||||||
Total assets | $ | 1,255 | $ | 1,474 | |||||
Current liabilities | $ | 22 | $ | 21 | |||||
Other liabilities | 885 | 1,083 | |||||||
Equity | 348 | 370 | |||||||
Total liabilities and equity | $ | 1,255 | $ | 1,474 | |||||
West Coast Power LLC Summarized Financial Information |
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For the Period | For the Period | |||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | |||||||||||||
December 31, | December 31, | December 31, | December 5, | |||||||||||||
2005 | 2004 | 2003 | 2003 | |||||||||||||
(In millions) | ||||||||||||||||
Operating revenues | $ | 301 | $ | 726 | $ | 53 | $ | 643 | ||||||||
Operating income | 15 | 303 | 31 | 201 | ||||||||||||
Net income (pre-tax) | 21 | 306 | 31 | 202 |
December 31, | December 31, | ||||||||
2005 | 2004 | ||||||||
(In millions) | |||||||||
Current assets | $ | 312 | $ | 426 | |||||
Other assets | 376 | 394 | |||||||
Total assets | $ | 688 | $ | 823 | |||||
Current liabilities | 43 | 82 | |||||||
Other liabilities | 6 | 5 | |||||||
Equity | 639 | 736 | |||||||
Total liabilities and equity | $ | 688 | $ | 823 | |||||
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Acquisition of Remaining 50% in WCP from Dynegy, Inc. and sale of our 50% investment in Rocky Road Power LLC |
Saguaro Power Company |
Gladstone |
175
Table of Contents
Enfield Energy Centre Limited |
Reorganized NRG |
176
Table of Contents
Power Sale | Emission | |||||||||||
Agreements | Allowances | Total | ||||||||||
(In millions) | ||||||||||||
Original balance as of December 6, 2003 | $ | 64 | $ | 373 | $ | 437 | ||||||
Amortization | (5 | ) | — | (5 | ) | |||||||
Balance as of December 31, 2003 | 59 | 373 | 432 | |||||||||
Tax valuation adjustments | (5 | ) | (50 | ) | (55 | ) | ||||||
Other valuation adjustments | (2 | ) | (31 | ) | (33 | ) | ||||||
Amortization | (32 | ) | (18 | ) | (50 | ) | ||||||
Balance as of December 31, 2004 | 20 | 274 | 294 | |||||||||
Tax valuation adjustments | (1 | ) | (16 | ) | (17 | ) | ||||||
Other valuation adjustments | — | 9 | 9 | |||||||||
Sale of emission credits to 3rd parties | — | (5 | ) | (5 | ) | |||||||
Amortization | (12 | ) | (12 | ) | (24 | ) | ||||||
Balance as of December 31, 2005 | $ | 7 | $ | 250 | $ | 257 | ||||||
Predecessor Company |
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Table of Contents
Derivative Financial Instruments |
Energy Related Commodities |
• | Forward contracts, which commit us to purchase or sell energy commodities 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 (notional) quantity. | |
• | Option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price. |
• | Fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on our electric generation operations. | |
• | Fixing the price of a portion of anticipated fuel purchases for the operation of our power plants. | |
• | Fixing the price of a portion of anticipated energy purchases to supply our load-serving customers. |
• | Forward and financial contracts for the sale of electricity and related products economically hedging our generation assets forecasted output through 2008. | |
• | Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of our generation assets into 2006. |
• | Coal purchase contracts extending through 2009 designated as normal purchases and disclosed as part of our contractual cash obligations. (See Note 25 Commitments and Contingencies). | |
• | Natural gas transportation and storage agreements these contracts are not derivatives and are disclosed as part of our contractual cash obligations. (See Note 25 Commitments and Contingencies). | |
• | Load-following forward electric sales contracts extending through 2026 (these contracts are not considered derivatives). |
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Interest Rates |
179
Table of Contents
Foreign Currency Exchange Rates |
Accumulated Other Comprehensive Income |
Reorganized NRG | ||||||||||||||||||
Energy | Interest | Foreign | ||||||||||||||||
Commodities | Rate | Currency | Total | |||||||||||||||
(Gains/(losses) in millions) | ||||||||||||||||||
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 | |||||||||||||
Mark to market of hedge contracts | (341 | ) | 8 | — | (333 | ) | ||||||||||||
Accumulated OCI balance at December 31, 2005 | $ | (204 | ) | $ | 8 | $ | — | $ | (196 | ) | ||||||||
Gains/(Losses) expected to unwind from OCI during next 12 months | $ | (208 | ) | $ | 2 | $ | — | $ | (206 | ) |
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Reorganized NRG | ||||||||||||||||||
Energy | Interest | Foreign | ||||||||||||||||
Commodities | Rate | Currency | Total | |||||||||||||||
(Gains/(losses) 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 | ||||||||||||||
Mark to market of hedge contracts | 4 | (4 | ) | — | — | |||||||||||||
Accumulated OCI balance at December 31, 2004 | $ | 5 | $ | 2 | $ | — | $ | 7 | ||||||||||
Reorganized NRG | ||||||||||||||||||
Energy | Interest | Foreign | ||||||||||||||||
Commodities | Rate | Currency | Total | |||||||||||||||
(Gains/(losses) in millions) | ||||||||||||||||||
Accumulated OCI balance at December 6, 2003 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Unwound from OCI during period: | ||||||||||||||||||
— due to unwinding of previously deferred amounts | — | — | — | — | ||||||||||||||
Mark to market of hedge contracts | (2 | ) | 1 | — | (1 | ) | ||||||||||||
Accumulated OCI balance at December 31, 2003 | $ | (2 | ) | $ | 1 | $ | — | $ | (1 | ) | ||||||||
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Predecessor Company | ||||||||||||||||||
Energy | Interest | Foreign | ||||||||||||||||
Commodities | Rate | Currency | Total | |||||||||||||||
(Gains/(losses) in millions) | ||||||||||||||||||
Accumulated OCI balance at December 31, 2002 | $ | 130 | $ | (103 | ) | $ | — | $ | 27 | |||||||||
Unwound from OCI during period: | ||||||||||||||||||
— due to forecasted transactions probable of no longer occurring | — | 32 | — | 32 | ||||||||||||||
— due to unwinding of previously deferred amounts | (113 | ) | (2 | ) | — | (115 | ) | |||||||||||
Mark to market of hedge contracts | 44 | 7 | — | 51 | ||||||||||||||
Accumulated OCI balance at December 5, 2003 | 61 | (66 | ) | — | (5 | ) | ||||||||||||
— due to Fresh Start reporting write-off | (61 | ) | 66 | — | 5 | |||||||||||||
Accumulated OCI balance at December 6, 2003 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Statement of Operations |
Reorganized NRG | ||||||||||||||||
Energy | Interest | Foreign | ||||||||||||||
Commodities | Rate | Currency | Total | |||||||||||||
(Gains/(losses) in millions) | ||||||||||||||||
Revenue from majority-owned subsidiaries | $ | (145 | ) | $ | — | $ | — | $ | (145 | ) | ||||||
Cost of operations | 2 | — | — | 2 | ||||||||||||
Other income | — | — | — | — | ||||||||||||
Equity in earnings of unconsolidated subsidiaries | — | — | — | — | ||||||||||||
Interest expense | — | — | — | — | ||||||||||||
Total Statement of Operations impact before tax | $ | (143 | ) | $ | — | $ | — | $ | (143 | ) | ||||||
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Reorganized NRG | ||||||||||||||||
Energy | Interest | Foreign | ||||||||||||||
Commodities | Rate | Currency | Total | |||||||||||||
(Gains/(losses) in millions) | ||||||||||||||||
Revenue from majority-owned subsidiaries | $ | 57 | $ | — | $ | — | $ | 57 | ||||||||
Cost of operations | — | — | — | — | ||||||||||||
Other income | — | — | — | — | ||||||||||||
Equity in earnings of unconsolidated subsidiaries | 24 | — | — | 24 | ||||||||||||
Interest expense | — | — | — | — | ||||||||||||
Total Statement of Operations impact before tax | $ | 81 | $ | — | $ | — | $ | 81 | ||||||||
Reorganized NRG | |||||||||||||||||
Energy | Interest | Foreign | |||||||||||||||
Commodities | Rate | Currency | Total | ||||||||||||||
(Gains/(losses) in millions) | |||||||||||||||||
Revenue from majority-owned subsidiaries | $ | (1 | ) | $ | — | $ | — | $ | (1 | ) | |||||||
Cost of operations | 1 | — | — | 1 | |||||||||||||
Other income | — | — | — | — | |||||||||||||
Equity in earnings of unconsolidated subsidiaries | (1 | ) | — | — | (1 | ) | |||||||||||
Interest expense | — | 2 | — | 2 | |||||||||||||
Total Statement of Operations impact before tax | $ | (1 | ) | $ | 2 | $ | — | $ | 1 | ||||||||
Predecessor Company | |||||||||||||||||
Energy | Interest | Foreign | |||||||||||||||
Commodities | Rate | Currency | Total | ||||||||||||||
(Gains/(losses) in millions) | |||||||||||||||||
Revenue from majority-owned subsidiaries | $ | 30 | $ | — | $ | — | $ | 30 | |||||||||
Cost of operations | 5 | — | — | 5 | |||||||||||||
Other income | — | — | — | — | |||||||||||||
Equity in earnings of unconsolidated subsidiaries | 19 | — | — | 19 | |||||||||||||
Interest expense | — | (15 | ) | — | (15 | ) | |||||||||||
Total Statement of Operations impact before tax | $ | 54 | $ | (15 | ) | $ | — | $ | 39 | ||||||||
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Reorganized NRG | |||||||||||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||||||||||
Principal | Adjustment | Principal | Adjustment | ||||||||||||||||||||||
December 31, | December 31, | ||||||||||||||||||||||||
Stated | Effective | ||||||||||||||||||||||||
Rate | Rate | 2005 | 2005 | 2004 | 2004 | ||||||||||||||||||||
(Percent) | (In millions) | ||||||||||||||||||||||||
NRG Recourse Debt: | |||||||||||||||||||||||||
NRG Energy 2nd priority senior notes, due December 15, 2013(3)(4) | 8.00 | % | n/a | $ | 1,080 | $ | (6 | ) | $ | 1,725 | $ | 10 | |||||||||||||
NRG Amended Credit Facility, due December 24, 2011 | (1 | ) | — | 795 | — | 800 | — | ||||||||||||||||||
NRG Promissory Note, Xcel Energy, due June 5, 2006 | 3.00 | 9.00 | 10 | — | 10 | (1 | ) | ||||||||||||||||||
NRG Project-Level, Non-Recourse Debt: | |||||||||||||||||||||||||
NRG Peaker Finance Co. LLC, due June 2019 | (1 | ) | L+3.5 | (2) | 297 | (57 | ) | 301 | (64 | ) | |||||||||||||||
Flinders Power Finance Pty, due September 2012 | (1 | ) | — | 177 | — | 203 | 10 | ||||||||||||||||||
NRG Energy Center Minneapolis LLC, Senior secured notes, due 2013 and 2017, 7.12%-7.31% | (1 | ) | L+2 | (2) | 111 | 5 | 119 | 6 | |||||||||||||||||
Camas Power Boiler LP, unsecured term loan, due June 2007 | (1 | ) | L+2 | (2) | 4 | — | 6 | — | |||||||||||||||||
Camas Power Boiler LP, revenue bonds, due August 2007 | 3.38 | L+2 | (2) | 3 | — | 4 | — | ||||||||||||||||||
Itiquira Energetica S.A., due December 2013 | 12.00 | — | 30 | — | 31 | — | |||||||||||||||||||
Itiquira Energetica S.A., due January 2012 | (1 | ) | — | 19 | — | 20 | — | ||||||||||||||||||
Capital leases: | |||||||||||||||||||||||||
Saale Energie GmbH, Schkopau capital lease, due 2021 | (1 | ) | — | 214 | — | 304 | — | ||||||||||||||||||
Subtotal | 2,740 | (58 | ) | 3,523 | (39 | ) | |||||||||||||||||||
Less current maturities | 108 | (7 | ) | 508 | 3 | ||||||||||||||||||||
Total | $ | 2,632 | $ | (51 | ) | $ | 3,015 | $ | (42 | ) | |||||||||||||||
(1) | Distinguishes debt with various interest rates. |
(2) | L+ equals LIBOR plus x% |
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(3) | Fair value adjustment as of December 31, 2004 and December 31, 2005 reflects $16 million reduction and $20 million reduction, respectively, for an interest rate swap. In addition, the balances as of December 31, 2004 and December 31, 2005 reflect unamortized bond premium of $26 million and $14 million, respectively. |
(4) | $645 million in bonds have been redeemed or repurchased and retired in 2005. |
Senior Securities |
185
Table of Contents
186
Table of Contents
Peakers |
187
Table of Contents
Flinders |
NRG Thermal |
Camas |
188
Table of Contents
Itiquira Energetica S.A. |
Capital Leases |
Saale Energie GmbH |
Total | |||||
(In millions) | |||||
2006 | $ | 108 | |||
2007 | 82 | ||||
2008 | 66 | ||||
2009 | 65 | ||||
2010 | 71 | ||||
Thereafter | 2,348 | ||||
Total | $ | 2,740 | |||
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(In millions) | |||||
2006 | $ | 77 | |||
2007 | 48 | ||||
2008 | 42 | ||||
2009 | 33 | ||||
2010 | 19 | ||||
Thereafter | 187 | ||||
Total minimum obligations | 406 | ||||
Interest | 192 | ||||
Present value of minimum obligations | 214 | ||||
Current portion | 61 | ||||
Long-term obligations | $ | 153 | |||
Common Stock |
Treasury Stock |
190
Table of Contents
Preferred Stock |
4% Preferred Stock |
191
Table of Contents
Redeemable Preferred Stock |
192
Table of Contents
Incentive Compensation Plans |
2005 | 2004 | 2003 | |||||||||||
(In millions) | |||||||||||||
Non qualified stock options | $ | 4 | $ | 7 | $ | — | |||||||
Restricted stock units | 7 | 5 | — | ||||||||||
Deferred stock units | 1 | 2 | — | ||||||||||
Performance units | — | — | — | ||||||||||
Total | $ | 12 | $ | 14 | $ | — | |||||||
Long-Term Incentive Plan |
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• | in cash; | |
• | by delivery of shares of common stock with a fair market value equal to the exercise price; | |
• | by means of any cashless exercise procedure approved by the Compensation Committee; or | |
• | by any combination of the foregoing. |
Vesting, Withholding Taxes and Transferability of All Awards — |
• | Awards will vest over a period of not less than six months of the date of grant. | |
• | Participants may elect to deliver shares of common stock, or to have us withhold shares of common stock deliverable upon vesting or exercise, in order to satisfy our tax withholding obligations. | |
• | Awards are not transferable other than by will or the laws of descent and distribution. | |
• | Awards may be exercised only by the grantee or his or her executor, administrator, guardian or legal representative, or by a family member of the grantee if he or she has acquired the award by gift or qualified domestic relations order. |
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The following types of Awards are issued and outstanding as of December 31, 2005: |
Stock Options |
Weighted- | ||||||||||||
Average | ||||||||||||
Exercise Price Range | Exercise | |||||||||||
Shares | per Share | Price | ||||||||||
Outstanding at December 6 and December 31, 2003 | 632,751 | $ | 24.03 | $ | 24.03 | |||||||
Granted | 330,000 | $ | 19.90 - $31.48 | $ | 21.46 | |||||||
Outstanding at December 31, 2004 | 962,751 | $ | 19.90 - $31.48 | $ | 23.15 | |||||||
Granted | 134,000 | $ | 38.80 | $ | 38.80 | |||||||
Canceled or expired | (1,500 | ) | $ | 38.80 | $ | 38.80 | ||||||
Outstanding at December 31, 2005 | 1,095,251 | $ | 19.90-38.80 | $ | 25.04 | |||||||
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Options Outstanding | ||||||||||||||||||||
Options Exercisable | ||||||||||||||||||||
Weighted- | ||||||||||||||||||||
Average | Weighted- | Weighted- | ||||||||||||||||||
Remaining | Average | Average | ||||||||||||||||||
Total | Life (In | Exercise | Total | Exercise | ||||||||||||||||
Range of exercise prices | Outstanding | Years) | Price | Exercisable | Price | |||||||||||||||
$19.90 - $22.24 | 307,000 | 3.2 | $ | 20.92 | 102,333 | $ | 20.92 | |||||||||||||
$24.03 - $31.48 | 655,751 | 7.9 | $ | 24.20 | 429,501 | $ | 24.11 | |||||||||||||
$38.80 | 132,500 | 4.6 | $ | 38.80 | — | — |
2005 | 2004 | 2003 | ||||||||||
Dividends per year | — | — | — | |||||||||
Expected volatility | 29.75 | % | 51.05 | % | 35.70 | % | ||||||
Risk-free interest rate | 4.16 | % | 3.06 | % | 4.24 | % | ||||||
Expected life (years) | 5 | 5 | 10 | |||||||||
Fair value | $ | 13.22 | $ | 10.20 | $ | 13.17 |
Restricted Stock Units |
Deferred Stock Units |
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Performance Units |
Performance Units | ||||
Dividends per year | — | |||
Expected volatility | 29.75 | % | ||
Risk free interest rate | 4.09 | % | ||
Expected life of PU’s (in years) | 3 | |||
Fair value | $ | 29.87 |
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Reorganized NRG | ||||||||||||
For the Period | ||||||||||||
Year Ended | Year Ended | December 6 - | ||||||||||
December 31, 2005 | December 31, 2004 | December 31, 2003 | ||||||||||
(In millions, except per share data) | ||||||||||||
Basic earnings per share | ||||||||||||
Numerator: | ||||||||||||
Income from continuing operations | $ | 77 | $ | 161 | $ | 11 | ||||||
Deduct preferred stock dividends | (20 | ) | (1 | ) | — | |||||||
Net income available to common stockholders from continuing operations | 57 | 160 | 11 | |||||||||
Discontinued operations, net of tax | 7 | 25 | — | |||||||||
Net income available to common stockholders | $ | 64 | $ | 185 | $ | 11 | ||||||
Denominator: | ||||||||||||
Weighted average number of common shares outstanding | 84.6 | 99.6 | 100.0 | |||||||||
Basic earnings per share: | ||||||||||||
Income from continuing operations | $ | 0.67 | $ | 1.61 | $ | 0.11 | ||||||
Discontinued operations, net of tax | 0.09 | 0.25 | — | |||||||||
Net income | $ | 0.76 | $ | 1.86 | $ | 0.11 | ||||||
Diluted earnings per share | ||||||||||||
Numerator | ||||||||||||
Net income available to common stockholders from continuing operations | $ | 57 | $ | 160 | $ | 11 | ||||||
Add preferred stock dividends for dilutive preferred stock | — | 1 | — | |||||||||
Adjusted income from continuing operations | 57 | 161 | 11 | |||||||||
Discontinued operations, net of tax | 7 | 25 | — | |||||||||
Net income available to common stockholders | $ | 64 | $ | 186 | $ | 11 | ||||||
Denominator: | ||||||||||||
Weighted average number of common shares outstanding | 84.6 | 99.6 | 100.0 | |||||||||
Incremental shares attributable to the issuance of non-qualifying stock options (treasury stock method) | 0.2 | — | — | |||||||||
Incremental shares attributable to the issuance of non-vested restricted stock units (treasury stock method) | 0.4 | 0.4 | 0.1 | |||||||||
Incremental shares attributable to the assumed conversion of deferred stock units (if converted method) | 0.1 | 0.1 | — | |||||||||
Incremental shares attributable to the assumed conversion of the 4% preferred stock (if converted method) | — | 0.3 | — | |||||||||
Total dilutive shares | 85.3 | 100.4 | 100.1 | |||||||||
Diluted earnings per share: | ||||||||||||
Income from continuing operations | $ | 0.66 | $ | 1.60 | $ | 0.11 | ||||||
Discontinued operations, net of tax | 0.09 | 0.25 | — | |||||||||
Net income | $ | 0.75 | $ | 1.85 | $ | 0.11 | ||||||
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Anti-dilutive effect of certain equity instruments |
199
Table of Contents
200
Table of Contents
Reorganized NRG | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2005 | ||||||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||||||
All Other | ||||||||||||||||||||||||||||||||||||||||
Other | ||||||||||||||||||||||||||||||||||||||||
South | North | Other | Alternative | Non- | ||||||||||||||||||||||||||||||||||||
Northeast | Central | Western | America | Australia | International | Energy | Generation | Other | Total | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||||||
Operations | ||||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 1,554 | $ | 552 | $ | 1 | $ | 15 | $ | 212 | $ | 163 | $ | 70 | $ | 158 | $ | (17 | ) | $ | 2,708 | |||||||||||||||||||
Operating expenses | 1,262 | 471 | 6 | 30 | 192 | 122 | 60 | 124 | (3 | ) | 2,264 | |||||||||||||||||||||||||||||
Depreciation and amortization | 74 | 61 | 1 | 7 | 27 | 4 | 5 | 11 | 4 | 194 | ||||||||||||||||||||||||||||||
Corporate relocation charges | — | — | — | — | — | — | — | — | 6 | 6 | ||||||||||||||||||||||||||||||
Reorganization items | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Restructuring and impairment charges | — | — | — | 6 | — | — | — | — | — | 6 | ||||||||||||||||||||||||||||||
Operating income/(loss) | 218 | 20 | (6 | ) | (28 | ) | (7 | ) | 37 | 5 | 23 | (24 | ) | 238 | ||||||||||||||||||||||||||
Minority interest in earnings of consolidated subsidiaries | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | — | — | 22 | 13 | 24 | 45 | — | — | — | 104 | ||||||||||||||||||||||||||||||
Write downs and losses on sales of equity method investments | — | (27 | ) | (16 | ) | 12 | — | — | — | (31 | ) | |||||||||||||||||||||||||||||
Other income (expense), net | 4 | — | 1 | 13 | 3 | 21 | 2 | 6 | 12 | 62 | ||||||||||||||||||||||||||||||
Refinancing expenses | — | — | — | — | 10 | — | — | — | (66 | ) | (56 | ) | ||||||||||||||||||||||||||||
Interest expense | (9 | ) | (18 | ) | (13 | ) | (8 | ) | (9 | ) | (140 | ) | (197 | ) | ||||||||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 222 | 11 | (10 | ) | (36 | ) | 17 | 107 | 7 | 20 | (218 | ) | 120 | |||||||||||||||||||||||||||
Income tax expense/(benefit) | — | — | — | 4 | 2 | 18 | 4 | 4 | 11 | 43 | ||||||||||||||||||||||||||||||
Income/(loss) from continuing operations | 222 | 11 | (10 | ) | (40 | ) | 15 | 89 | 3 | 16 | (229 | ) | 77 | |||||||||||||||||||||||||||
Income/(loss) on discontinued operations, net of income taxes | — | — | — | 1 | — | 6 | — | — | 7 | |||||||||||||||||||||||||||||||
Net income/(loss) | $ | 222 | $ | 11 | $ | (10 | ) | $ | (39 | ) | $ | 15 | $ | 89 | $ | 9 | $ | 16 | $ | (229 | ) | $ | 84 | |||||||||||||||||
Balance Sheet | ||||||||||||||||||||||||||||||||||||||||
Equity investments in affiliates | 1 | — | 188 | 56 | 163 | 195 | — | — | 603 | |||||||||||||||||||||||||||||||
Capital expenditures | 51 | 26 | — | — | 17 | — | 1 | 6 | 5 | 106 | ||||||||||||||||||||||||||||||
Total assets | $ | 1,810 | $ | 1,075 | $ | 200 | $ | 599 | $ | 825 | $ | 679 | $ | 74 | $ | 1,446 | $ | 723 | $ | 7,431 |
Net income/(loss) as reported | $ | 222 | $ | 11 | $ | (10 | ) | $ | (39 | ) | $ | 15 | $ | 89 | $ | 9 | $ | 16 | $ | (229 | ) | $ | 84 | |||||||||||||||||
Increase/(decrease) in net income | 25 | 13 | — | (1 | ) | 6 | 4 | 1 | 5 | (53 | ) | — | ||||||||||||||||||||||||||||
Adjusted net income/(loss) | $ | 247 | $ | 24 | $ | (10 | ) | $ | (40 | ) | $ | 21 | $ | 93 | $ | 10 | $ | 21 | $ | (282 | ) | $ | 84 | |||||||||||||||||
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Reorganized NRG | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2004 | ||||||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||||||
All Other | ||||||||||||||||||||||||||||||||||||||||
Other | ||||||||||||||||||||||||||||||||||||||||
South | North | Other | Alternative | Non- | ||||||||||||||||||||||||||||||||||||
Northeast | Central | Western | America | Australia | International | Energy | Generation | Other | Total | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||||||
Operations | ||||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 1,251 | $ | 418 | $ | 3 | $ | 94 | $ | 181 | $ | 157 | $ | 65 | $ | 186 | $ | (7 | ) | $ | 2,348 | |||||||||||||||||||
Operating expenses | 860 | 294 | 11 | 51 | 162 | 122 | 61 | 101 | 37 | 1,699 | ||||||||||||||||||||||||||||||
Depreciation and amortization | 73 | 62 | 1 | 21 | 24 | 3 | 5 | 11 | 8 | 208 | ||||||||||||||||||||||||||||||
Corporate relocation charges | — | — | — | — | — | — | — | — | 16 | 16 | ||||||||||||||||||||||||||||||
Reorganization items | — | 1 | — | — | — | — | — | 1 | (15 | ) | (13 | ) | ||||||||||||||||||||||||||||
Restructuring and impairment charges | — | 3 | — | 27 | — | — | — | — | 15 | 45 | ||||||||||||||||||||||||||||||
Operating income/(loss) | 318 | 58 | (9 | ) | (5 | ) | (5 | ) | 32 | (1 | ) | 73 | (68 | ) | 393 | |||||||||||||||||||||||||
Minority interest in earnings of consolidated subsidiaries | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | — | — | 74 | 16 | 18 | 51 | 1 | — | — | 160 | ||||||||||||||||||||||||||||||
Write downs and losses on sales of equity method investments | — | — | — | (11 | ) | (1 | ) | — | (4 | ) | — | — | (16 | ) | ||||||||||||||||||||||||||
Other income (expense), net | 5 | — | — | 3 | 4 | 7 | 1 | 2 | 5 | 27 | ||||||||||||||||||||||||||||||
Refinancing expenses | — | — | — | — | — | — | — | — | (72 | ) | (72 | ) | ||||||||||||||||||||||||||||
Interest expense | (1 | ) | (9 | ) | — | (45 | ) | (11 | ) | (11 | ) | — | (8 | ) | (181 | ) | (266 | ) | ||||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 322 | 49 | 65 | (42 | ) | 5 | 79 | (3 | ) | 67 | (316 | ) | 226 | |||||||||||||||||||||||||||
Income tax expense/(benefit) | — | — | — | (10 | ) | (5 | ) | 13 | (1 | ) | 5 | 63 | 65 | |||||||||||||||||||||||||||
Income/(loss) from continuing operations | 322 | 49 | 65 | (32 | ) | 10 | 66 | (2 | ) | 62 | (379 | ) | 161 | |||||||||||||||||||||||||||
Income/(loss) on discontinued operations, net of income taxes | — | — | — | 14 | — | 12 | 2 | — | (3 | ) | 25 | |||||||||||||||||||||||||||||
Net income/(loss) | $ | 322 | $ | 49 | $ | 65 | $ | (18 | ) | $ | 10 | $ | 78 | $ | — | $ | 62 | $ | (382 | ) | $ | 186 | ||||||||||||||||||
Balance Sheet | ||||||||||||||||||||||||||||||||||||||||
Equity investments in affiliates | 1 | — | 256 | 76 | 156 | 246 | — | — | — | 735 | ||||||||||||||||||||||||||||||
Capital expenditures | 49 | 31 | — | 1 | 22 | 2 | 2 | 4 | 8 | 119 | ||||||||||||||||||||||||||||||
Total assets | $ | 1,932 | $ | 1,077 | $ | 279 | $ | 783 | $ | 1,008 | $ | 939 | $ | 51 | $ | 512 | $ | 1,283 | $ | 7,864 |
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Reorganized NRG | ||||||||||||||||||||||||||||||||||||||||
December 6, 2003 Through December 31, 2003 | ||||||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||||||
All Other | ||||||||||||||||||||||||||||||||||||||||
Other | ||||||||||||||||||||||||||||||||||||||||
South | North | Other | Alternative | Non- | ||||||||||||||||||||||||||||||||||||
Northeast | Central | Western | America | Australia | International | Energy | Generation | Other | Total | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||||||
Operations | ||||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 69 | $ | 27 | $ | — | $ | 4 | $ | 12 | $ | 13 | $ | 4 | $ | 10 | $ | (2 | ) | $ | 137 | |||||||||||||||||||
Operating expenses | 53 | 20 | — | 2 | 10 | 11 | 4 | 8 | — | 108 | ||||||||||||||||||||||||||||||
Depreciation and amortization | 5 | 3 | — | 2 | 2 | — | — | — | — | 12 | ||||||||||||||||||||||||||||||
Reorganization items | — | — | — | — | — | — | — | — | 2 | 2 | ||||||||||||||||||||||||||||||
Operating income/(loss) | 11 | 4 | — | — | — | 2 | — | 2 | (4 | ) | 15 | |||||||||||||||||||||||||||||
Minority interest in earnings of consolidated subsidiaries | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | 10 | 2 | 1 | 1 | — | — | — | 14 | ||||||||||||||||||||||||||||||
Other income (expense), net | — | — | — | — | 1 | — | — | — | (1 | ) | — | |||||||||||||||||||||||||||||
Interest expense | (3 | ) | (4 | ) | — | (3 | ) | (1 | ) | — | — | (1 | ) | (7 | ) | (19 | ) | |||||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 8 | — | 10 | (1 | ) | 1 | 3 | — | 1 | (12 | ) | 10 | ||||||||||||||||||||||||||||
Income tax expense/(benefit) | — | — | — | — | — | 1 | — | — | (2 | ) | (1 | ) | ||||||||||||||||||||||||||||
Income/(loss) from continuing operations | 8 | — | 10 | (1 | ) | 1 | 2 | — | 1 | (10 | ) | 11 | ||||||||||||||||||||||||||||
Income/(loss) on discontinued operations, net of income taxes | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
Net income/(loss) | $ | 8 | $ | — | $ | 10 | $ | (1 | ) | $ | 1 | $ | 2 | $ | — | $ | 1 | $ | (10 | ) | $ | 11 | ||||||||||||||||||
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Predecessor Company | ||||||||||||||||||||||||||||||||||||||||
January 1, 2003 Through December 5, 2003 | ||||||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||||||
All Other | ||||||||||||||||||||||||||||||||||||||||
Other | ||||||||||||||||||||||||||||||||||||||||
South | North | Other | Alternative | Non- | ||||||||||||||||||||||||||||||||||||
Northeast | Central | Western | America | Australia | International | Energy | Generation | Other | Total | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||||||
Operations | ||||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 861 | $ | 357 | $ | 24 | $ | 86 | $ | 151 | $ | 137 | $ | 61 | $ | 129 | $ | (8 | ) | $ | 1,798 | |||||||||||||||||||
Operating expenses | 800 | 247 | 7 | 45 | 124 | 111 | 52 | 87 | 51 | 1,524 | ||||||||||||||||||||||||||||||
Depreciation and amortization | 90 | 34 | 11 | 29 | 17 | 4 | 5 | 12 | 9 | 211 | ||||||||||||||||||||||||||||||
Reorganization items | 2 | 29 | — | 41 | — | — | — | — | 126 | 198 | ||||||||||||||||||||||||||||||
Restructuring and impairment charges | 232 | 2 | — | 17 | — | — | 1 | — | (15 | ) | 237 | |||||||||||||||||||||||||||||
Fresh start reporting adjustments | 1,068 | 429 | 107 | 415 | 78 | (11 | ) | 50 | 181 | (6,537 | ) | (4,220 | ) | |||||||||||||||||||||||||||
Legal settlement | — | — | — | 4 | — | — | (9 | ) | — | 468 | 463 | |||||||||||||||||||||||||||||
Operating income/(loss) | (1,331 | ) | (384 | ) | (101 | ) | (465 | ) | (68 | ) | 33 | (38 | ) | (151 | ) | 5,890 | 3,385 | |||||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | 103 | 7 | 30 | 32 | (1 | ) | — | — | 171 | |||||||||||||||||||||||||||||
Write downs and losses on sales of equity method investments | — | — | — | 12 | (146 | ) | 3 | (16 | ) | — | — | (147 | ) | |||||||||||||||||||||||||||
Other income (expense), net | 3 | 1 | — | 2 | (1 | ) | 13 | 2 | — | (1 | ) | 19 | ||||||||||||||||||||||||||||
Interest expense | (70 | ) | (74 | ) | — | (70 | ) | (4 | ) | (8 | ) | — | (10 | ) | (72 | ) | (308 | ) | ||||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | (1,398 | ) | (457 | ) | 2 | (514 | ) | (189 | ) | 73 | (53 | ) | (161 | ) | 5,817 | 3,120 | ||||||||||||||||||||||||
Income tax expense/(benefit) | — | — | 36 | 5 | 15 | 17 | 2 | — | (37 | ) | 38 | |||||||||||||||||||||||||||||
Income/(loss) from continuing operations | (1,398 | ) | (457 | ) | (34 | ) | (519 | ) | (204 | ) | 56 | (55 | ) | (161 | ) | 5,854 | 3,082 | |||||||||||||||||||||||
Income/(loss) on discontinued operations, net of income taxes | — | — | — | (414 | ) | — | 138 | (25 | ) | — | (15 | ) | (316 | ) | ||||||||||||||||||||||||||
Net income/(loss) | $ | (1,398 | ) | $ | (457 | ) | $ | (34 | ) | $ | (933 | ) | $ | (204 | ) | $ | 194 | $ | (80 | ) | $ | (161 | ) | $ | 5,839 | $ | 2,766 | |||||||||||||
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Predecessor | |||||||||||||||||||
Reorganized NRG | Company | ||||||||||||||||||
For the Period | For the Period | ||||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | ||||||||||||||||
December 31, | December 31, | December 31, | December 5, | ||||||||||||||||
2005 | 2004 | 2003 | 2003 | ||||||||||||||||
(In millions) | |||||||||||||||||||
Current | |||||||||||||||||||
U.S. | $ | 19 | $ | — | $ | (2 | ) | $ | 2 | ||||||||||
Foreign | 16 | 17 | 1 | 16 | |||||||||||||||
35 | 17 | (1 | ) | 18 | |||||||||||||||
Deferred | |||||||||||||||||||
U.S. | 2 | 57 | — | 3 | |||||||||||||||
Foreign | 6 | (9 | ) | — | 17 | ||||||||||||||
8 | 48 | — | 20 | ||||||||||||||||
Total income tax (benefit) | $ | 43 | $ | 65 | $ | (1 | ) | $ | 38 | ||||||||||
Effective tax rate | 35.8 | % | 28.7 | % | (6.2 | )% | 1.3 | % |
Predecessor | ||||||||||||||||
Reorganized NRG | Company | |||||||||||||||
For the Period | For the Period | |||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | |||||||||||||
December 31, | December 31, | December 31, | December 5, | |||||||||||||
2005 | 2004 | 2003 | 2003 | |||||||||||||
(In millions) | ||||||||||||||||
U.S. | $ | (4 | ) | $ | 138 | $ | 6 | $ | 3,236 | |||||||
Foreign | 124 | 88 | 4 | (116 | ) | |||||||||||
$ | 120 | $ | 226 | $ | 10 | $ | 3,120 | |||||||||
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Predecessor | |||||||||||||||||
Reorganized NRG | Company | ||||||||||||||||
For the Period | For the Period | ||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | ||||||||||||||
December 31, | December 31, | December 31, | December 5, | ||||||||||||||
2005 | 2004 | 2003 | 2003 | ||||||||||||||
(In millions) | |||||||||||||||||
Income/(Loss) From Continuing Operations Before Income Taxes | $ | 120 | $ | 226 | $ | 10 | $ | 3,120 | |||||||||
Tax at 35% | 42 | 80 | 4 | 1,092 | |||||||||||||
State taxes, (net of federal benefit) | (1 | ) | 6 | (2 | ) | 265 | |||||||||||
Foreign operations | (21 | ) | (22 | ) | (1 | ) | 15 | ||||||||||
Section 965 Taxable Dividend | 5 | — | — | — | |||||||||||||
Subpart F Taxable Income | 19 | — | — | — | |||||||||||||
Fresh Start accounting adjustments | — | — | — | (1,440 | ) | ||||||||||||
Valuation allowance | (22 | ) | — | (1 | ) | 71 | |||||||||||
Change in state effective tax rate | 22 | — | — | — | |||||||||||||
Change in tax rate | — | — | — | 36 | |||||||||||||
Permanent differences, reserves, other | (1 | ) | 1 | (1 | ) | (1 | ) | ||||||||||
Income Tax Expense/(Benefit) | $ | 43 | $ | 65 | $ | (1 | ) | $ | 38 | ||||||||
Effective income tax rate | 35.8 | % | 28.7 | % | (6.2 | )% | 1.3 | % |
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Reorganized NRG | ||||||||||
December 31, | December 31, | |||||||||
2005 | 2004 | |||||||||
(In millions) | ||||||||||
Deferred tax liabilities: | ||||||||||
Discount/premium on notes | $ | 23 | $ | 20 | ||||||
Emissions credits | 113 | 115 | ||||||||
Difference between book and tax basis of property | 247 | 246 | ||||||||
Total deferred tax liabilities | 383 | 381 | ||||||||
Deferred tax assets: | ||||||||||
Deferred compensation, accrued vacation and other reserves | 56 | 54 | ||||||||
Development costs | 2 | 3 | ||||||||
Net unrealized gains on mark to market transactions | 148 | 10 | ||||||||
Foreign net operating loss carryforwards | 46 | 64 | ||||||||
Differences between book and tax basis of contracts | 146 | 162 | ||||||||
Non-depreciable Property | 197 | 182 | ||||||||
Intangibles amortization (other than goodwill) | 12 | 13 | ||||||||
Restructuring costs | 80 | 60 | ||||||||
U.S. net operating loss carry forwards | 38 | 40 | ||||||||
U.S. capital loss carryforwards | 238 | 280 | ||||||||
Investments in projects | 63 | 83 | ||||||||
Other | 8 | 3 | ||||||||
Total deferred tax assets (before valuation allowance) | 1,034 | 954 | ||||||||
Valuation allowance | (756 | ) | (708 | ) | ||||||
Net deferred tax assets | 278 | 246 | ||||||||
Net deferred tax liability | $ | 105 | $ | 135 | ||||||
Reorganized NRG | ||||||||
December 31, | December 31, | |||||||
2005 | 2004 | |||||||
(In millions) | ||||||||
Current deferred tax asset | $ | (4 | ) | $ | — | |||
Non-current deferred tax asset | (26 | ) | (34 | ) | ||||
Non-current deferred tax liability | 135 | 169 | ||||||
Net deferred tax liability | $ | 105 | $ | 135 | ||||
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Taxes payable |
Deferred tax assets and valuation allowance |
Repatriation of foreign funds pursuant to the American Jobs Creation Act of 2004 |
208
Table of Contents
Tax Holidays |
Stock Purchase Agreement |
Operating Agreements |
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Predecessor | |||||||||||||||||
Reorganized NRG | Company | ||||||||||||||||
For the Period | For the Period | ||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | ||||||||||||||
December 31, | December 31, | December 31, | December 5, | ||||||||||||||
2005 | 2004 | 2003 | 2003 | ||||||||||||||
(In millions) | |||||||||||||||||
Revenues from Related Parties Included in Revenues from Majority-Owned Operations | |||||||||||||||||
WCP | |||||||||||||||||
O&M fees | $ | 6 | $ | 4 | $ | — | $ | 6 | |||||||||
AMA fees | 2 | 3 | — | 1 | |||||||||||||
Saguaro | |||||||||||||||||
O&M fees | — | — | — | — | |||||||||||||
Gladstone | |||||||||||||||||
O&M fees | 3 | 2 | — | 1 | |||||||||||||
MIBRAG | |||||||||||||||||
O&M fees | 4 | 3 | — | 3 | |||||||||||||
Total | $ | 15 | $ | 12 | $ | — | $ | 11 | |||||||||
Expenses from Related Parties Included in Cost of Majority-Owned Operations | |||||||||||||||||
MIBRAG | |||||||||||||||||
Cost of purchased coal | $ | 41 | $ | 39 | $ | 3 | $ | 36 |
Xcel Energy |
Operating Agreements |
210
Table of Contents
Administrative Services and Other Costs |
Natural Gas Marketing and Trading Agreement |
Reorganized NRG |
NRG Flinders Retirement Plan |
211
Table of Contents
NRG Pension and Postretirement Medical Plans |
Components of Net Periodic Benefit Cost |
Pension Benefits | |||||||||||||||||
Predecessor | |||||||||||||||||
Reorganized NRG | Company | ||||||||||||||||
For the Period | For the Period | ||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | ||||||||||||||
December 31, | December 31, | December 31, | December 5, | ||||||||||||||
2005 | 2004 | 2003 | 2003 | ||||||||||||||
(In millions) | |||||||||||||||||
Service cost benefits earned | $ | 11 | $ | 11 | $ | 1 | $ | — | |||||||||
Interest cost on benefit obligation | 4 | 3 | — | — | |||||||||||||
Expected return on plan assets | — | — | — | — | |||||||||||||
Curtailment gain | — | (1 | ) | — | — | ||||||||||||
Net periodic benefit cost | $ | 15 | $ | 13 | $ | 1 | $ | — | |||||||||
Other Benefits | |||||||||||||||||
Predecessor | |||||||||||||||||
Reorganized NRG | Company | ||||||||||||||||
For the Period | For the Period | ||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | ||||||||||||||
December 31, | December 31, | December 31, | December 5, | ||||||||||||||
2005 | 2004 | 2003 | 2003 | ||||||||||||||
(In millions) | |||||||||||||||||
Service cost benefits earned | $ | 2 | $ | 1 | $ | — | $ | 1 | |||||||||
Interest cost on benefit obligation | 3 | 3 | — | 2 | |||||||||||||
Amortization of prior service cost | — | — | — | — | |||||||||||||
Recognized actuarial (gain)/loss | — | — | — | — | |||||||||||||
Net periodic benefit cost | $ | 5 | $ | 4 | $ | — | $ | 3 | |||||||||
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Reconciliation of Funded Status |
Pension Benefits | Other Benefits | ||||||||||||||||
December 31, | December 31, | December 31, | December 31, | ||||||||||||||
Reorganized NRG | 2005 | 2004 | 2005 | 2004 | |||||||||||||
(In millions) | |||||||||||||||||
Benefit obligation at January 1 | $ | 64 | $ | 49 | $ | 51 | $ | 42 | |||||||||
Service cost | 11 | 11 | 2 | 1 | |||||||||||||
Interest cost | 4 | 3 | 3 | 3 | |||||||||||||
Plan initiation | — | — | — | — | |||||||||||||
Plan amendments | — | — | — | — | |||||||||||||
Plan curtailment | (1 | ) | — | — | |||||||||||||
Actuarial (gain)/loss | 5 | 2 | 2 | 6 | |||||||||||||
Benefit payments | (1 | ) | — | (1 | ) | (1 | ) | ||||||||||
Benefit obligation at December 31 | $ | 83 | $ | 64 | $ | 57 | $ | 51 | |||||||||
Fair value of plan assets at January 1 | 1 | — | — | — | |||||||||||||
Actual return on plan assets | — | — | — | — | |||||||||||||
Employer contributions | 13 | 1 | 1 | 1 | |||||||||||||
Benefit payments | (1 | ) | — | (1 | ) | (1 | ) | ||||||||||
Fair value of plan assets at December 31 | $ | 13 | $ | 1 | $ | — | $ | — | |||||||||
Funded status at December 31 — excess of obligation over assets | (70 | ) | (63 | ) | (57 | ) | (51 | ) | |||||||||
Unrecognized net (gain) loss | 8 | 2 | 8 | 6 | |||||||||||||
Accrued benefit liability recognized on the consolidated balance sheet at December 31 | $ | (62 | ) | $ | (61 | ) | $ | (49 | ) | $ | (45 | ) | |||||
Pension Benefits | Other Benefits | |||||||||||||||
December 31, | December 31, | December 31, | December 31, | |||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
(In millions) | ||||||||||||||||
Accrued benefit cost | $ | (62 | ) | $ | (61 | ) | $ | (49 | ) | $ | (45 | ) | ||||
Unfunded accrued benefit obligation | — | — | — | — | ||||||||||||
Intangible assets | — | — | — | — | ||||||||||||
Accumulated other comprehensive income | — | — | — | — | ||||||||||||
Net amount recognized | $ | (62 | ) | $ | (61 | ) | $ | (49 | ) | $ | (45 | ) | ||||
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Pension Benefits | ||||||||
December 31, | December 31, | |||||||
2005 | 2004 | |||||||
(In millions) | ||||||||
Projected benefit obligation | $ | 83 | $ | 64 | ||||
Accumulated benefit obligation | 35 | 16 | ||||||
Fair value of plan assets | 13 | 1 |
Pension Benefits | Other Benefits | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
Weighted-average assumptions used to determine benefit obligations at December 31 | ||||||||||||||||
Discount rate | 5.50 | % | 5.75 | % | 5.50% | 5.75% | ||||||||||
Rate of compensation increase | 4.00 - 4.50 | % | 4.00 - 4.50 | % | — | — | ||||||||||
11.5% grading to | 9% grading to | |||||||||||||||
Health care trend rate | — | — | 5.5% in 2012 | 5.5% in 2009 |
Pension Benefits | Other Benefits | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 | ||||||||||||||||
Discount rate | 5.75 | % | 6.00 | % | 5.75% | 6.00% | ||||||||||
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 | 9% grading to | 10% grading to | ||||||||||||||
— | — | 5.5% in 2009 | 5.5% in 2009 |
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December 31 | ||||||||
2005 | 2004 | |||||||
US Equity | 56 | % | N/A | |||||
International Equity | 15 | % | N/A | |||||
US Fixed Income | 29 | % | N/A | |||||
Cash | — | N/A |
Post Retirement Medical Plans | ||||||||||||
Pension Benefits | ||||||||||||
Medicare Prescription | ||||||||||||
Benefit Payments | Benefit Payments | Drug Reimbursements | ||||||||||
(In millions) | ||||||||||||
2006 | $ | 1 | $ | 1 | $ | — | ||||||
2007 | 1 | 2 | — | |||||||||
2008 | 3 | 2 | — | |||||||||
2009 | 4 | 3 | — | |||||||||
2010 | 6 | 3 | — | |||||||||
2011-2015 | 50 | 18 | 1 |
1-Percentage- | 1-Percentage- | |||||||
Point Increase | Point Decrease | |||||||
(In millions) | ||||||||
Effect on total service and interest cost components | $ | 1 | $ | — | ||||
Effect on postretirement benefit obligation | 6 | (5 | ) |
Defined Contribution Plans |
Predecessor Company |
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Table of Contents
Participation in Xcel Energy, Inc. Pension Plan and Postretirement Medical Plan |
2003 Medicare Legislation |
Note 25 — | Commitments and Contingencies |
Operating Lease Commitments |
Total | |||||
(In millions) | |||||
2006 | $ | 25 | |||
2007 | 21 | ||||
2008 | 16 | ||||
2009 | 14 | ||||
2010 | 13 | ||||
Thereafter | 61 | ||||
Total | $ | 150 | |||
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Table of Contents
Coal Purchase and Transportation Commitments |
Total | |||||
(In millions) | |||||
2006 | $ | 192 | |||
2007 | 106 | ||||
2008 | 48 | ||||
2009 | 49 | ||||
2010 | 3 | ||||
Thereafter | 18 | ||||
Total | $ | 416 | |||
International |
NRG FinCo Settlement |
217
Table of Contents
NYISO Claims |
Legal Issues |
218
Table of Contents
California Electricity and Related Litigation |
FERC Proceedings |
New York Operating Reserve Markets |
219
Table of Contents
Connecticut Congestion Charges |
New York Public Interest Research Group |
Station Service Disputes |
220
Table of Contents
Itiquira Energetica, S.A. |
CFTC Trading Litigation |
Disputed Claims Reserve |
221
Table of Contents
Note 26 — | Regulatory Matters |
Northeast Region |
RMR Agreements |
LICAP Market Developments |
222
Table of Contents
Connecticut |
New York |
223
Table of Contents
Mid Atlantic |
224
Table of Contents
South Central Region |
Western Region |
Note 27 — | Environmental Matters |
225
Table of Contents
226
Table of Contents
South Central Region |
Western Region |
Other North America |
227
Table of Contents
Note 28 — | Cash Flow Information |
Predecessor | ||||||||||||||||||
Reorganized NRG | Company | |||||||||||||||||
For the Period | For the Period | |||||||||||||||||
Year Ended | Year Ended | December 6 - | January 1 - | |||||||||||||||
December 31, | December 31, | December 31, | December 5, | |||||||||||||||
2005 | 2004 | 2003 | 2003 | |||||||||||||||
(In millions) | ||||||||||||||||||
Interest paid (net of amount capitalized) | $ | 257 | $ | 295 | $ | 87 | $ | 182 | ||||||||||
Income taxes paid | 21 | 34 | 2 | 27 | ||||||||||||||
Non-cash investing and financing activities: | ||||||||||||||||||
Investment in WCP by contributing fixed assets | — | 2 | — | — | ||||||||||||||
Reduction to fixed assets due to liquidated damages | — | 15 | — | — | ||||||||||||||
Addition to fixed assets due to conditional asset retirement obligations | 4 | — | — | — | ||||||||||||||
Conversion of accrued salaries to stockholders’ equity | 2 | — | — | — | ||||||||||||||
Addition to treasury stock for the maximum purchase price adjustment | 8 | — | — | — | ||||||||||||||
Accrued deferred acquisition costs | 2 | — | — | — |
Note 29 — | Guarantees and Other Contingent Liabilities |
• | Standby letters of credit and surety bonds — At December 31, 2005, we and our consolidated subsidiaries were contingently obligated for a total of approximately $321 million under standby letters of credit. Most of these letters of credit are issued in support of our obligations to perform under commodity agreements, financing or other arrangements. These letters of credit expire within one year of issuance, and it is typical for us to renew many of them on similar terms. |
As of December 31, 2005, standby letters of credit in amounts totaling approximately $312 million were issued under our $350.0 million corporate funded letter of credit facility, which is reflected in our financial statements. Of this amount, approximately $3 million was issued to support performance obligations of an unconsolidated affiliate of ours. Our Flinders subsidiary had issued approximately |
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Table of Contents
AUD 12 million (approximately US $9 million) in unfunded letters of credit under an AUD 20 million (approximately US $15 million) working capital and letter of credit facility, described in Note 17 — Debt and Capital Leases. | |
At December 31, 2005, we were also contingently obligated for approximately $4 million under surety bonds to support our prepayment, completion, license, tax or performance bonding requirements. Most of the bonds are supported by a letter of credit under our funded letter of credit facility, which is reflected in our financial statements. All of the bonds expire within one year; however, we expect to renew many of these bonds on a rolling twelve-month basis. |
• | Asset purchases and divestitures — In the normal course of business, we may be asked to provide certain assurances to the counter-parties of our asset sale and purchase agreements. Such assurances may take the form of a guarantee issued by us on behalf of a directly or indirectly held majority-owned subsidiary who included certain indemnifications to a third party (usually the buyer) as described below. Due to the inter-company nature of such arrangements (NRG Energy is essentially guaranteeing its own performance) and the nature of the guarantee being provided (usually the typical representations and warranties that are provided in any asset sales agreement), it is not our policy to recognize the value of such an obligation in our consolidated financial statements. Most of these guarantees provide an explicit cap on our maximum liability, as well as an expiration period, exclusive of breach of representations and warranties. |
On April 1, 2005, in conjunction with the sale of our interest in the Enfield Energy Center Ltd, a minority-owned, indirectly held affiliate of ours, we issued a guarantee of the obligations of a subsidiary of ours under the sale and purchase agreement, to the buyers of our interest. The maximum liability for this guarantee was approximately $56 million as of December 31, 2005. | |
At December 31, 2005, our maximum known exposure under asset purchase or sales guarantees was approximately $123 million. On January 1, 2006, we executed a guarantee to a prospective buyer of one of our unconsolidated affiliates. This guarantees the payment of claims related to tax obligations, late payments, and indemnifications, and the maximum liability we estimate under this guarantee is approximately $5 million. This guarantee expires on October 1, 2016. Upon the defeasance of $0.4 million of our Second Priority Notes on February 2, 2006, we retained guarantee obligations related to this indebtedness. For further information, see Note 17 — Debt and Capital Leases. |
• | Commercial sales arrangements — In connection with the purchase and sale of fuel, emission allowances and power generation products to and from third parties with respect to the operation of some of our generation facilities in the U.S., we may be required to guarantee a portion of the obligations of certain of our subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments. As of December 31, 2005, we estimate the maximum liability for this category of guarantee was approximately $91 million. We have subsequently issued additional guarantees or increased existing guarantees of the performance of NRG PMI, with increasing the maximum liability by approximately $19 million. These additional guarantees terminate between December 31, 2006 and December 31, 2008. | |
• | Other types of guarantees — We have issued guarantees of obligations our subsidiaries may incur in provision of environmental site remediation, payment of debt obligations, rail car leases and performance under operating and maintenance agreements. Maximum quantifiable liability under the environmental guarantees is approximately $64 million, most of which is a guarantee for plant removal and site remediation obligations at our Flinders facilities. The maximum quantifiable exposure under the operational guarantees is $25 million, primarily related to our role as operator at the Gladstone power plant. In addition, we have a maximum liability exposure of approximately $1 million under a tax indemnity guarantee to a third party and third-party debt guarantee exposure of approximately $1 million. |
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On February 18, 2005 we executed a guarantee to the benefit of our counter-party under a railcar lease. We guarantee the performance and payment obligations of NRG PMI under the railcar lease. Payment obligations include future rental and termination payments, which are estimated to total approximately $48 million over the next five years of the lease, and approximately $46 million over the remainder of the lease, should we elect not to exercise our termination rights. If we do elect to terminate the lease, we will be required to pay $8 million in termination fees, but we will have no obligation to make future lease payments. However, our obligations under this guarantee include additional requirements that would be difficult to quantify until such time as a claim were made. As a result, our maximum potential obligation under this guarantee is of indeterminate exposure, and therefore is not included in the table of maximum exposure maturities in this note. |
Amount of Guarantee Liabilities Expiration per Period as of | ||||||||||||||||||||
December 31, 2005 (in millions) | ||||||||||||||||||||
Total Amounts | After 5 Years or | |||||||||||||||||||
Guarantee Type | Committed | Short-term | 2-3 Years | 4-5 Years | Indeterminate | |||||||||||||||
Funded standby letters of credit | $ | 312 | $ | 312 | $ | — | $ | — | $ | — | ||||||||||
Unfunded standby letters of credit | 9 | 9 | — | — | — | |||||||||||||||
Surety bonds | 4 | 4 | — | — | — | |||||||||||||||
Asset sales guarantee obligations | 123 | — | 13 | — | 110 | |||||||||||||||
Commodity sales guarantee obligations | 91 | 62 | 12 | 14 | 3 | |||||||||||||||
Other guarantees | 91 | — | 1 | — | 90 | |||||||||||||||
Total guarantees | $ | 630 | $ | 387 | $ | 26 | $ | 14 | $ | 203 | ||||||||||
• | Asset purchases and divestitures —The purchase and sale agreements which govern our asset or share investments and divestitures customarily contain indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or quantify at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. For those indemnities in which liability is capped, the exposure ranges from $250 thousand up to $50 million. We have no reason to believe that we currently have any material liability relating to such routine indemnification obligations. | |
• | Other indemnities — Other indemnifications we have provided cover operational, tax, litigation and breaches of representations, warranties and covenants. We have also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to us. Our maximum potential exposure under these indemnifications can range from a specified dollar amount to an unlimited amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. We do not have any reason to believe that we will be required to make any material payments under these indemnity provisions. |
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Note 30 — | Sales to Significant Customers |
Reorganized NRG |
Predecessor Company |
Big Cajun II Unit 3 |
Reorganized NRG |
Keystone and Conemaugh |
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Reorganized NRG |
Reorganized NRG | ||||||||||||||||||||
Quarters Ended 2005 | ||||||||||||||||||||
March 31 | June 30 | September 30 | December 31 | Total Year | ||||||||||||||||
(In millions, except per share data) | ||||||||||||||||||||
Operating Revenues | $ | 597 | $ | 579 | $ | 762 | $ | 770 | $ | 2,708 | ||||||||||
Operating Income/(Loss) | 44 | 44 | (7 | ) | 157 | 238 | ||||||||||||||
Income From Continuing Operations | 22 | 22 | (37 | ) | 70 | 77 | ||||||||||||||
Income/(Loss) on Discontinued Operations net of Income Taxes | 1 | 2 | 10 | (6 | ) | 7 | ||||||||||||||
Net Income/(Loss) | $ | 23 | $ | 24 | $ | (27 | ) | $ | 64 | $ | 84 | |||||||||
Weighted Average Number of Common Shares Outstanding — Basic | 87 | 87 | 84 | 81 | 85 | |||||||||||||||
Income From Continuing Operations per Weighted Average Common Share — Basic | $ | 0.20 | $ | 0.21 | $ | (0.51 | ) | $ | 0.79 | $ | 0.67 | |||||||||
Income/(Loss) From Discontinued Operations per Weighted Average Common Share — Basic | 0.01 | 0.02 | 0.12 | (0.07 | ) | 0.09 | ||||||||||||||
Net Income per Weighted Average Common Share — Basic | $ | 0.21 | $ | 0.23 | $ | (0.39 | ) | $ | 0.72 | $ | 0.76 | |||||||||
Weighted Average Number of Common Shares Outstanding — Diluted | 88 | 88 | 84 | 92 | 85 | |||||||||||||||
Income From Continuing Operations per Weighted Average Common Share — Diluted | $ | 0.20 | $ | 0.20 | $ | (0.51 | ) | $ | 0.74 | $ | 0.66 | |||||||||
Income From Discontinued Operations per Weighted Average Common Share — Diluted | 0.01 | 0.02 | 0.12 | (0.06 | ) | 0.09 | ||||||||||||||
Net Income per Weighted Average Common Share — Diluted | $ | 0.21 | $ | 0.22 | $ | (0.39 | ) | $ | 0.68 | $ | 0.75 |
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Reorganized NRG | ||||||||||||||||||||
Quarters Ended 2004 | ||||||||||||||||||||
March 31 | June 30 | September 30 | December 31 | Total Year | ||||||||||||||||
(In millions, except per share data) | ||||||||||||||||||||
Operating Revenues | $ | 596 | $ | 570 | $ | 605 | $ | 577 | $ | 2,348 | ||||||||||
Operating Income | 118 | 115 | 79 | 81 | 393 | |||||||||||||||
Income From Continuing Operations | 31 | 69 | 44 | 17 | 161 | |||||||||||||||
Income/(Loss) on Discontinued Operations net of Income Taxes | (1 | ) | 14 | 10 | 2 | 25 | ||||||||||||||
Net Income | $ | 30 | $ | 83 | $ | 54 | $ | 19 | $ | 186 | ||||||||||
Weighted Average Number of Common Shares Outstanding — Basic | 100 | 100 | 100 | 99 | 100 | |||||||||||||||
Income From Continuing Operations per Weighted Average Common Share — Basic | $ | 0.31 | $ | 0.69 | $ | 0.44 | $ | 0.17 | $ | 1.61 | ||||||||||
Income/(Loss) From Discontinued Operations per Weighted Average Common Share — Basic | (0.01 | ) | 0.14 | 0.10 | 0.01 | 0.25 | ||||||||||||||
Net Income per Weighted Average Common Share — Basic | $ | 0.30 | $ | 0.83 | $ | 0.54 | $ | 0.18 | $ | 1.86 | ||||||||||
Weighted Average Number of Common Shares Outstanding — Diluted | 100 | 100 | 101 | 99 | 100 | |||||||||||||||
Income From Continuing Operations per Weighted Average Common Share — Diluted | $ | 0.31 | $ | 0.69 | $ | 0.44 | $ | 0.17 | $ | 1.60 | ||||||||||
Income From Discontinued Operations per Weighted Average Common Share — Diluted | (0.01 | ) | 0.14 | 0.10 | 0.01 | 0.25 | ||||||||||||||
Net Income per Weighted Average Common Share — Diluted | $ | 0.30 | $ | 0.83 | $ | 0.54 | $ | 0.18 | $ | 1.85 |
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Arthur Kill Power LLC | NRG Cabrillo Power Operations Inc. | |
Astoria Gas Turbine Power LLC | NRG Cadillac Operations Inc. | |
Berrians I Gas Turbine Power LLC | NRG California Peaker Operations LLC | |
Big Cajun II Unit 4 LLC | NRG Connecticut Affiliate Services Inc. | |
Capistrano Cogeneration Company | NRG Devon Operations Inc. | |
Chickahominy River Energy Corp. | NRG Dunkirk Operations Inc. | |
Commonwealth Atlantic Power LLC | NRG El Segundo Operations Inc. | |
Conemaugh Power LLC | NRG Huntley Operations Inc. | |
Connecticut Jet Power LLC | NRG International LLC | |
Devon Power LLC | NRG Kaufman LLC | |
Dunkirk Power LLC | NRG Mesquite LLC | |
Eastern Sierra Energy Company | NRG MidAtlantic Affiliate Services Inc. | |
El Segundo Power II LLC | NRG Middletown Operations Inc. | |
Hanover Energy Company | NRG Montville Operations Inc. | |
Huntley Power LLC | NRG New Jersey Energy Sales LLC | |
Indian River Operations Inc. | NRG New Roads Holdings LLC | |
Indian River Power LLC | NRG North Central Operations Inc. | |
James River Power LLC | NRG Northeast Affiliate Services Inc. | |
Kaufman Cogen LP | NRG Norwalk Harbor Operations Inc. | |
Keystone Power LLC | NRG Operating Services, Inc. | |
Louisiana Generating LLC | NRG Oswego Harbor Power Operations Inc. | |
Middletown Power LLC | NRG Power Marketing Inc. | |
Montville Power LLC | NRG Rocky Road LLC | |
NEO California Power LLC | NRG Saguaro Operations Inc. | |
NEO Chester-Gen LLC | NRG South Central Affiliate Services Inc. | |
NEO Corporation | NRG South Central Generating LLC | |
NEO Freehold-Gen LLC | NRG South Central Operations Inc. | |
NEO Landfill Gas Holdings Inc. | NRG West Coast LLC | |
NEO Power Services Inc. | NRG Western Affiliate Services Inc. | |
Norwalk Power LLC | Oswego Harbor Power LLC | |
NRG Affiliate Services Inc. | Saguaro Power LLC | |
NRG Arthur Kill Operations Inc. | Somerset Operations Inc. | |
NRG Asia-Pacific, Ltd. | Somerset Power LLC | |
NRG Astoria Gas Turbine Operations, Inc. | Vienna Operations Inc. | |
NRG Bayou Cove LLC | Vienna Power LLC |
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Guarantor | Non-Guarantor | NRG Energy, Inc. | Consolidated | |||||||||||||||||||
Subsidiaries | Subsidiaries | (Note Issuer) | Eliminations(1) | Balance | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||||
Revenues from majority-owned operations | $ | 2,095 | $ | 564 | $ | 54 | $ | (5 | ) | $ | 2,708 | |||||||||||
Operating Costs and Expenses | ||||||||||||||||||||||
Cost of majority-owned operations | 1,600 | 435 | 37 | (5 | ) | 2,067 | ||||||||||||||||
Depreciation and amortization | 133 | 51 | 10 | — | 194 | |||||||||||||||||
General, administrative and development | 39 | 31 | 127 | — | 197 | |||||||||||||||||
Other charges | ||||||||||||||||||||||
Corporate relocation charges | — | — | 6 | — | 6 | |||||||||||||||||
Reorganization items | — | — | — | — | — | |||||||||||||||||
Impairment charges | 6 | — | — | — | 6 | |||||||||||||||||
Total operating costs and expenses | 1,778 | 517 | 180 | (5 | ) | 2,470 | ||||||||||||||||
Operating Income/(Loss) | 317 | 47 | (126 | ) | — | 238 | ||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||
Minority interest in earnings of consolidated subsidiaries | — | — | — | — | — | |||||||||||||||||
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 | 54 | 13 | (21 | ) | 62 | ||||||||||||||||
Refinancing expenses | — | 10 | (66 | ) | — | (56 | ) | |||||||||||||||
Interest expense | (1 | ) | (76 | ) | (141 | ) | 21 | (197 | ) | |||||||||||||
Total other income/(expense) | 104 | 73 | 80 | (375 | ) | (118 | ) | |||||||||||||||
Income/(Loss) From Continuing Operations Before Income Taxes | 421 | 120 | (46 | ) | (375 | ) | 120 | |||||||||||||||
Income Tax Expense | 155 | 18 | (130 | ) | — | 43 | ||||||||||||||||
Income From Continuing Operations | 266 | 102 | 84 | (375 | ) | 77 | ||||||||||||||||
Income on Discontinued Operations, net of Income Taxes | 5 | 2 | — | — | 7 | |||||||||||||||||
Net Income | $ | 271 | $ | 104 | $ | 84 | $ | (375 | ) | $ | 84 | |||||||||||
(1) | 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(1) | Balance | |||||||||||||||||
(In millions) | |||||||||||||||||||||
ASSETS | |||||||||||||||||||||
Current Assets | |||||||||||||||||||||
Cash and cash equivalents | $ | (7 | ) | $ | 91 | $ | 422 | $ | — | $ | 506 | ||||||||||
Restricted cash | 3 | 61 | — | — | 64 | ||||||||||||||||
Accounts receivable-trade, net | 214 | 275 | (205 | ) | — | 284 | |||||||||||||||
Current portion of notes receivable | — | 25 | 468 | (468 | ) | 25 | |||||||||||||||
Taxes receivable | (2 | ) | — | 45 | — | 43 | |||||||||||||||
Inventory | 232 | 27 | 1 | — | 260 | ||||||||||||||||
Derivative instruments valuation | 385 | 16 | 3 | — | 404 | ||||||||||||||||
Collateral on deposit in support of energy risk management activities | 438 | — | — | — | 438 | ||||||||||||||||
Deferred income taxes | 6 | 3 | (5 | ) | — | 4 | |||||||||||||||
Prepayments and other current assets | 65 | 22 | 38 | — | 125 | ||||||||||||||||
Assets held for sale | 8 | — | 35 | — | 43 | ||||||||||||||||
Current assets — discontinued operations | — | 1 | — | — | 1 | ||||||||||||||||
Total current assets | 1,342 | 521 | 802 | (468 | ) | 2,197 | |||||||||||||||
Net property, plant and equipment | 2,176 | 832 | 31 | — | 3,039 | ||||||||||||||||
Other Assets | |||||||||||||||||||||
Investment in subsidiaries | 787 | — | 1,774 | (2,561 | ) | — | |||||||||||||||
Equity investments in affiliates | 243 | 360 | — | — | 603 | ||||||||||||||||
Notes receivable | 76 | 457 | 1,398 | (1,473 | ) | 458 | |||||||||||||||
Intangible assets, net | 238 | 19 | — | — | 257 | ||||||||||||||||
Derivative instruments valuation | 18 | 4 | — | — | 22 | ||||||||||||||||
Funded letter of credit | — | — | 350 | — | 350 | ||||||||||||||||
Deferred income taxes | — | 26 | — | — | 26 | ||||||||||||||||
Other assets | 22 | 20 | 83 | — | 125 | ||||||||||||||||
Non–current assets — discontinued operations | — | 354 | — | — | 354 | ||||||||||||||||
Total other assets | 1,384 | 1,240 | 3,605 | (4,034 | ) | 2,195 | |||||||||||||||
Total Assets | $ | 4,902 | $ | 2,593 | $ | 4,438 | $ | (4,502 | ) | $ | 7,431 | ||||||||||
LIABILITIES AND STOCK HOLDERS’ EQUITY | |||||||||||||||||||||
Current Liabilities | |||||||||||||||||||||
Current portion of long-term debt | $ | 459 | $ | 96 | $ | 14 | $ | (468 | ) | $ | 101 | ||||||||||
Accounts Payable | 158 | 89 | 21 | — | 268 | ||||||||||||||||
Derivative instruments valuation | 678 | 14 | — | — | 692 | ||||||||||||||||
Other bankruptcy settlement | — | 3 | — | — | 3 | ||||||||||||||||
Accrued expenses and other current liabilities | 60 | 48 | 69 | — | 177 | ||||||||||||||||
Current liabilities — discontinued operations | — | 115 | — | — | 115 | ||||||||||||||||
Total current liabilities | 1,355 | 365 | 104 | (468 | ) | 1,356 | |||||||||||||||
Other Liabilities | |||||||||||||||||||||
Long-term debt | 1,397 | 791 | 1,866 | (1,473 | ) | 2,581 | |||||||||||||||
Deferred income taxes | 37 | 149 | (51 | ) | — | 135 | |||||||||||||||
Derivative instruments valuation | 25 | 92 | 20 | — | 137 | ||||||||||||||||
Out-of-market contracts | 298 | — | — | — | 298 | ||||||||||||||||
Other long-term obligations | 126 | 58 | 22 | — | 206 | ||||||||||||||||
Non-current liabilities — discontinued operations | — | 240 | — | — | 240 | ||||||||||||||||
Total non-current liabilities | 1,883 | 1,330 | 1,857 | (1,473 | ) | 3,597 | |||||||||||||||
Total liabilities | 3,238 | 1,695 | 1,961 | (1,941 | ) | 4,953 | |||||||||||||||
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 | $ | 2,593 | $ | 4,438 | $ | (4,502 | ) | $ | 7,431 | ||||||||||
(1) | All significant intercompany transactions have been eliminated in consolidation. |
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Non- | NRG Energy, | |||||||||||||||||||||
Guarantor | Guarantor | Inc. | Consolidated | |||||||||||||||||||
Subsidiaries | Subsidiaries | (Note Issuer) | Eliminations(1) | Balance | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||||
Net income | $ | 271 | $ | 104 | $ | 84 | $ | (375 | ) | $ | 84 | |||||||||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||||||||||||||||
Distributions in excess of (less than) equity earnings of unconsolidated affiliates and consolidated subsidiaries | (64 | ) | (45 | ) | 453 | (352 | ) | (8 | ) | |||||||||||||
Depreciation and amortization | 133 | 52 | 10 | — | 195 | |||||||||||||||||
Amortization of deferred financing costs and debt discount/(premium) | — | 6 | 16 | — | 22 | |||||||||||||||||
Write-off of deferred financing costs due to refinancing | — | (10 | ) | 2 | — | (8 | ) | |||||||||||||||
Write downs and losses on sales of equity method investments | 47 | (16 | ) | — | — | 31 | ||||||||||||||||
Deferred income taxes and investment tax credits | 71 | 13 | (82 | ) | — | 2 | ||||||||||||||||
Unrealized (gains)/losses on derivatives | 150 | (10 | ) | 3 | — | 143 | ||||||||||||||||
Minority interest | — | 1 | — | — | 1 | |||||||||||||||||
Amortization of intangible assets | (2 | ) | 19 | — | — | 17 | ||||||||||||||||
Amortization of unearned equity compensation | 3 | 1 | 8 | — | 12 | |||||||||||||||||
Restructuring and impairment charges | 6 | — | — | — | 6 | |||||||||||||||||
Loss on sale and disposal of property, plant and equipment | 4 | — | — | — | 4 | |||||||||||||||||
Gain on sale of discontinued operations | (6 | ) | — | — | — | (6 | ) | |||||||||||||||
Gain on TermRio settlement | — | (14 | ) | — | — | (14 | ) | |||||||||||||||
Collateral deposit payments in support of energy risk management | (405 | ) | — | — | — | (405 | ) | |||||||||||||||
Cash provided by(used by) changes in other working capital, net of dispositions affects | (421 | ) | 9 | 404 | — | (8 | ) | |||||||||||||||
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 | ) | — | ||||||||||||||||
Inter-company Loans (I/ C) to Subsidiaries | — | — | (2,181 | ) | 2,181 | — | ||||||||||||||||
Proceeds from I/ C loans with parent and subsidiaries | 327 | — | 325 | (652 | ) | — | ||||||||||||||||
Proceeds from sale of discontinued operations | 36 | — | — | — | 36 | |||||||||||||||||
Proceeds from sale of investments | — | 70 | — | — | 70 | |||||||||||||||||
Proceeds from sale of property, plant and equipment | 9 | — | — | — | 9 | |||||||||||||||||
Return of capital/ (Investments) in projects | — | 2 | — | — | 2 | |||||||||||||||||
Decrease/(increase) in restricted cash | 1 | 44 | — | — | 45 | |||||||||||||||||
Deferred acquisition costs | — | — | (5 | ) | — | (5 | ) | |||||||||||||||
Decrease/(increase) in notes receivable | 5 | 102 | — | — | 107 | |||||||||||||||||
Capital expenditures | (78 | ) | (22 | ) | (6 | ) | — | (106 | ) | |||||||||||||
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 Inter-company Loans | 2,181 | — | — | (2,181 | ) | — | ||||||||||||||||
Payments for Parent Inter-company Loans | (325 | ) | (327 | ) | — | 652 | — | |||||||||||||||
Payments of dividends | (704 | ) | (23 | ) | (20 | ) | 727 | (20 | ) | |||||||||||||
Repayment of minority interest obligations | — | (4 | ) | — | — | (4 | ) | |||||||||||||||
Accelerated share repurchase payment, net | — | — | (250 | ) | — | (250 | ) | |||||||||||||||
Issuance of 3.625% Preferred Stock, net | — | — | 246 | — | 246 | |||||||||||||||||
Proceeds from issuance of long-term debt | — | 249 | — | — | 249 | |||||||||||||||||
Deferred debt issuance costs | — | — | (46 | ) | — | (46 | ) | |||||||||||||||
Principal payments on long-term debt | (4 | ) | (352 | ) | (649 | ) | — | (1,005 | ) | |||||||||||||
Net Cash Provided (Used) by Financing Activities | (250 | ) | (457 | ) | (719 | ) | 596 | (830 | ) | |||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | — | (2 | ) | — | — | (2 | ) | |||||||||||||||
Change in Cash from Discontinued Operations | — | 8 | — | — | 8 | |||||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (163 | ) | (145 | ) | (290 | ) | — | (598 | ) | |||||||||||||
Cash and Cash Equivalents at Beginning of Period | 156 | 236 | 712 | — | 1,104 | |||||||||||||||||
Cash and Cash Equivalents at End of Period | $ | (7 | ) | $ | 91 | $ | 422 | $ | — | $ | 506 | |||||||||||
(1) | 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(1) | Balance | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||||
Revenues from majority-owned operations | $ | 1,722 | $ | 582 | $ | 51 | $ | (7 | ) | $ | 2,348 | |||||||||||
Operating Costs and Expenses | ||||||||||||||||||||||
Cost of majority-owned operations | 1,060 | 405 | 31 | (7 | ) | 1,489 | ||||||||||||||||
Depreciation and amortization | 133 | 62 | 13 | �� | — | 208 | ||||||||||||||||
General, administrative and development | 118 | 30 | 62 | — | 210 | |||||||||||||||||
Other charges | ||||||||||||||||||||||
Corporate relocation charges | — | — | 16 | — | 16 | |||||||||||||||||
Reorganization items | 2 | — | (15 | ) | — | (13 | ) | |||||||||||||||
Impairment charges | 3 | 27 | 15 | — | 45 | |||||||||||||||||
Total operating costs and expenses | 1,316 | 524 | 122 | (7 | ) | 1,955 | ||||||||||||||||
Operating Income/(Loss) | 406 | 58 | (71 | ) | — | 393 | ||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||
Minority interest in earnings of consolidated subsidiaries | — | — | — | — | — | |||||||||||||||||
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 | 35 | 5 | (20 | ) | 27 | ||||||||||||||||
Refinancing expenses | — | — | (72 | ) | — | (72 | ) | |||||||||||||||
Interest expense | — | (104 | ) | (182 | ) | 20 | (266 | ) | ||||||||||||||
Total other income/(expense) | 172 | (1 | ) | 44 | (382 | ) | (167 | ) | ||||||||||||||
Income/(Loss) From Continuing Operations Before Income Taxes | 578 | 57 | (27 | ) | (382 | ) | 226 | |||||||||||||||
Income Tax Expense/(Benefit) | 238 | 44 | (217 | ) | — | 65 | ||||||||||||||||
Income/(Loss) From Continuing Operations | 340 | 13 | 190 | (382 | ) | 161 | ||||||||||||||||
Income/(Loss) on Discontinued Operations, net of Income Taxes | 3 | 26 | (4 | ) | — | 25 | ||||||||||||||||
Net Income | $ | 343 | $ | 39 | $ | 186 | $ | (382 | ) | $ | 186 | |||||||||||
(1) | 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(1) | Balance | |||||||||||||||||
(In millions) | |||||||||||||||||||||
ASSETS | |||||||||||||||||||||
Current Assets | |||||||||||||||||||||
Cash and cash equivalents | $ | 156 | $ | 236 | $ | 712 | $ | — | $ | 1,104 | |||||||||||
Restricted cash | 4 | 106 | — | — | 110 | ||||||||||||||||
Accounts receivable-trade, net | 183 | 80 | 7 | — | 270 | ||||||||||||||||
Current portion of notes receivable | — | 82 | 6 | (3 | ) | 85 | |||||||||||||||
Income taxes receivable | — | (5 | ) | 42 | — | 37 | |||||||||||||||
Inventory | 216 | 29 | 2 | — | 247 | ||||||||||||||||
Derivative instruments valuation | 80 | — | — | — | 80 | ||||||||||||||||
Prepayments and other current assets | 71 | 25 | 43 | (3 | ) | 136 | |||||||||||||||
Collateral on deposit in support of energy risk management activities | 33 | — | — | — | 33 | ||||||||||||||||
Current assets — discontinued operations | — | 17 | — | — | 17 | ||||||||||||||||
Total current assets | 743 | 570 | 812 | (6 | ) | 2,119 | |||||||||||||||
Net property, plant and equipment | 2,244 | 883 | 31 | — | 3,158 | ||||||||||||||||
Other Assets | |||||||||||||||||||||
Investment in subsidiaries | 777 | — | 3,916 | (4,693 | ) | — | |||||||||||||||
Equity investments in affiliates | 327 | 408 | — | — | 735 | ||||||||||||||||
Notes receivable, less current portion, less reserve | 408 | 797 | 1 | (642 | ) | 564 | |||||||||||||||
Intangible assets, net | 256 | 38 | — | — | 294 | ||||||||||||||||
Derivative instruments valuation | 2 | 35 | 5 | — | 42 | ||||||||||||||||
Funded letter of credit | — | — | 350 | — | 350 | ||||||||||||||||
Deferred income taxes | — | 34 | — | — | 34 | ||||||||||||||||
Other non- current assets | 36 | 21 | 54 | — | 111 | ||||||||||||||||
Non-current assets — discontinued operations | — | 457 | — | — | 457 | ||||||||||||||||
Total other assets | 1,806 | 1,790 | 4,326 | (5,335 | ) | 2,587 | |||||||||||||||
Total Assets | $ | 4,793 | $ | 3,243 | $ | 5,169 | $ | (5,341 | ) | $ | 7,864 | ||||||||||
LIABILITIES AND STOCK HOLDERS’ EQUITY | |||||||||||||||||||||
Current Liabilities | |||||||||||||||||||||
Current portion of long-term debt and capital leases | $ | — | $ | 98 | $ | 416 | $ | (3 | ) | $ | 511 | ||||||||||
Accounts payable | 427 | (33 | ) | (181 | ) | 1 | 214 | ||||||||||||||
Derivative instruments valuation | 17 | — | — | — | 17 | ||||||||||||||||
Other bankruptcy settlement | — | 6 | — | — | 6 | ||||||||||||||||
Accrued expenses and other current liabilities | 101 | 31 | 37 | (3 | ) | 166 | |||||||||||||||
Current liabilities — discontinued operations | — | 173 | — | — | 173 | ||||||||||||||||
Total current liabilities | 545 | 275 | 272 | (5 | ) | 1,087 | |||||||||||||||
Other Liabilities | |||||||||||||||||||||
Long-term debt | — | 1,487 | 2,128 | (642 | ) | 2,973 | |||||||||||||||
Deferred income taxes | (32 | ) | 165 | 36 | — | 169 | |||||||||||||||
Derivative instruments valuation | — | 132 | 16 | — | 148 | ||||||||||||||||
Out-of-market contracts | 319 | — | — | — | 319 | ||||||||||||||||
Other non-current liabilities | 122 | 40 | 25 | — | 187 | ||||||||||||||||
Non-current liabilities — discontinued operations | — | 288 | — | — | 288 | ||||||||||||||||
Total non-current liabilities | 409 | 2,112 | 2,205 | (642 | ) | 4,084 | |||||||||||||||
Total liabilities | 954 | 2,387 | 2,477 | (647 | ) | 5,171 | |||||||||||||||
Minority interest | — | 1 | — | — | 1 | ||||||||||||||||
Stockholders’ Equity | 3,839 | 855 | 2,692 | (4,694 | ) | 2,692 | |||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 4,793 | $ | 3,243 | $ | 5,169 | $ | (5,341 | ) | $ | 7,864 | ||||||||||
(1) | 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(1) | 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 of (less than) equity earnings of unconsolidated affiliates and consolidated subsidiaries | (53 | ) | (38 | ) | — | 90 | (1 | ) | ||||||||||||||
Depreciation and amortization | 133 | 69 | 13 | — | 215 | |||||||||||||||||
Reserve for note and interest receivable | 7 | 5 | — | — | 12 | |||||||||||||||||
Amortization of financing costs and debt discount/(premium) | — | 21 | 7 | — | 28 | |||||||||||||||||
Write-off of deferred financing costs and debt premium | — | — | 42 | — | 42 | |||||||||||||||||
Deferred income taxes and investment tax credits | 26 | (8 | ) | 118 | (79 | ) | 57 | |||||||||||||||
Minority interest | — | 1 | — | — | 1 | |||||||||||||||||
Unrealized (gains)/losses on derivatives | (71 | ) | (9 | ) | 6 | — | (74 | ) | ||||||||||||||
Write downs and losses on sales of equity method investments | 16 | 1 | (1 | ) | — | 16 | ||||||||||||||||
Amortization of intangibles | 14 | 38 | — | — | 52 | |||||||||||||||||
Amortization of unearned equity compensation | 2 | 1 | 11 | — | 14 | |||||||||||||||||
Collateral deposit payments in support of energy risk management | (7 | ) | — | — | — | (7 | ) | |||||||||||||||
Restructuring and impairment charges | �� | 3 | 27 | 15 | — | 45 | ||||||||||||||||
Loss from sale and disposal of property, plant and equipment | 1 | — | — | — | 1 | |||||||||||||||||
(Gain)/loss on sale of discontinued operations | (2 | ) | (26 | ) | 5 | — | (23 | ) | ||||||||||||||
Cash provided by provided (used) by changes in certain working capital items, net of effects from acquisitions and dispositions | (41 | ) | 1 | 126 | (5 | ) | 81 | |||||||||||||||
Net Cash Provided (Used) by Operating Activities | 371 | 122 | 528 | (376 | ) | 645 | ||||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||
Proceeds from sale of discontinued operations | 2 | 251 | — | — | 253 | |||||||||||||||||
Proceeds from sale of investments | 21 | 27 | 3 | — | 51 | |||||||||||||||||
Proceeds from sale of property, plant and equipment | 4 | — | — | — | 4 | |||||||||||||||||
Decrease/(increase) in restricted cash | 1 | (28 | ) | — | — | (27 | ) | |||||||||||||||
Decrease/(increase) in notes receivable | (23 | ) | 16 | 25 | 7 | 25 | ||||||||||||||||
Capital expenditures | (82 | ) | (28 | ) | (9 | ) | — | (119 | ) | |||||||||||||
Investments in projects | 4 | (16 | ) | 9 | — | (3 | ) | |||||||||||||||
Distributions/(investments) in subsidiaries | — | — | 82 | (82 | ) | — | ||||||||||||||||
Net Cash Provided (Used) by Investing Activities | (73 | ) | 222 | 110 | (75 | ) | 184 | |||||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||
Net borrowings under line of credit agreement | ||||||||||||||||||||||
Proceeds from issuance of preferred shares | — | — | 406 | — | 406 | |||||||||||||||||
Payment for treasury stock | — | — | (405 | ) | — | (405 | ) | |||||||||||||||
Capital contributions from parent | 10 | 33 | — | (43 | ) | — | ||||||||||||||||
Dividends and return of investment to NRG Energy, Inc. | (407 | ) | (10 | ) | — | 417 | — | |||||||||||||||
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 | ) | |||||||||||||||
Principal payments on long-term debt | (41 | ) | (292 | ) | (1,200 | ) | 41 | (1,492 | ) | |||||||||||||
Net Cash Provided (Used) by Financing Activities | (438 | ) | (276 | ) | (21 | ) | 451 | (284 | ) | |||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | — | 3 | — | — | 3 | |||||||||||||||||
Change in Cash from Discontinued Operations | — | 6 | — | — | 6 | |||||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (140 | ) | 77 | 617 | — | 554 | ||||||||||||||||
Cash and Cash Equivalents at Beginning of Period | 296 | 159 | 95 | — | 550 | |||||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 156 | $ | 236 | $ | 712 | $ | — | $ | 1,104 | ||||||||||||
�� |
(1) | 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(1) | Balance | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||||
Revenues from majority-owned operations | $ | 94 | $ | 40 | $ | 3 | $ | — | $ | 137 | ||||||||||||
Operating Costs and Expenses | ||||||||||||||||||||||
Cost of majority-owned operations | 64 | 29 | 2 | — | 95 | |||||||||||||||||
Depreciation and amortization | 7 | 4 | 1 | — | 12 | |||||||||||||||||
General, administrative and development | 7 | 3 | 3 | — | 13 | |||||||||||||||||
Other Charges: | ||||||||||||||||||||||
Reorganization items | — | — | 2 | — | 2 | |||||||||||||||||
Total operating costs and expenses | 78 | 36 | 8 | — | 122 | |||||||||||||||||
Operating Income/(Loss) | 16 | 4 | (5 | ) | — | 15 | ||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 3 | — | 17 | (20 | ) | — | ||||||||||||||||
Equity in earnings of unconsolidated affiliates | 11 | 2 | 1 | — | 14 | |||||||||||||||||
Interest expense | (6 | ) | (5 | ) | (8 | ) | — | (19 | ) | |||||||||||||
Total other income/(expense) | 8 | (3 | ) | 10 | (20 | ) | (5 | ) | ||||||||||||||
Income/(Loss) From Continuing Operations Before Income Taxes | 24 | 1 | 5 | (20 | ) | 10 | ||||||||||||||||
Income Tax Expense/(Benefit) | 4 | 1 | (6 | ) | — | (1 | ) | |||||||||||||||
Income/(Loss) From Continuing Operations | 20 | — | 11 | (20 | ) | 11 | ||||||||||||||||
Income/(Loss) on Discontinued Operations, net of Income Taxes | — | — | — | — | — | |||||||||||||||||
— | — | — | — | — | ||||||||||||||||||
Net Income | $ | 20 | $ | — | $ | 11 | $ | (20 | ) | $ | 11 | |||||||||||
(1) | 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(1) | Balance | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||||
Net income | $ | 20 | $ | — | $ | 11 | $ | (20 | ) | $ | 11 | |||||||||||
Adjustments to reconcile net income to net cash provided by operating activities Distributions in excess of (less than) equity earnings of unconsolidated affiliates | 2 | (2 | ) | (18 | ) | 20 | 2 | |||||||||||||||
Depreciation and amortization | 8 | 4 | 1 | — | 13 | |||||||||||||||||
Amortization of deferred financing costs | — | — | 1 | — | 1 | |||||||||||||||||
Amortization of debt discount/(premium) | — | 1 | — | — | 1 | |||||||||||||||||
Deferred income taxes and investment tax credits | — | — | (4 | ) | 1 | (3 | ) | |||||||||||||||
Current tax expense — non cash contribution from members | 4 | (3 | ) | — | (1 | ) | — | |||||||||||||||
Unrealized (gains)/losses on derivatives | — | 4 | — | — | 4 | |||||||||||||||||
Minority interest | — | — | — | — | — | |||||||||||||||||
Amortization of intangibles | (16 | ) | 3 | — | — | (13 | ) | |||||||||||||||
Collateral deposit payments in support of energy risk management | (8 | ) | — | — | — | (8 | ) | |||||||||||||||
Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions | (64 | ) | — | (533 | ) | (597 | ) | |||||||||||||||
Net Cash Provided (Used) by Operating Activities | (54 | ) | 7 | (542 | ) | — | (589 | ) | ||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||
Investments in subsidiaries | — | — | (1,531 | ) | 1,531 | — | ||||||||||||||||
Decrease/(increase) in restricted cash | 343 | 32 | — | — | 375 | |||||||||||||||||
Decrease/(increase) in notes receivable | 1 | (11 | ) | (1 | ) | 12 | 1 | |||||||||||||||
Capital expenditures | (3 | ) | (8 | ) | — | — | (11 | ) | ||||||||||||||
Investments in projects | (2 | ) | — | — | — | (2 | ) | |||||||||||||||
Net Cash Provided (Used) by Investing Activities | 339 | 13 | (1,532 | ) | 1,543 | 363 | ||||||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||
Capital contributions from parent | 1,531 | — | — | (1,531 | ) | — | ||||||||||||||||
Proceeds from issuance of long-term debt | — | — | 2,450 | — | 2,450 | |||||||||||||||||
Deferred debt issuance costs | — | — | (75 | ) | — | (75 | ) | |||||||||||||||
Funded letter of credit | — | — | (250 | ) | — | (250 | ) | |||||||||||||||
Principal payments on long-term debt | (1,714 | ) | (6 | ) | — | (12 | ) | (1,732 | ) | |||||||||||||
Net Cash Provided (Used) by Financing Activities | (183 | ) | (6 | ) | 2,125 | (1,543 | ) | 393 | ||||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | — | (14 | ) | — | — | (14 | ) | |||||||||||||||
Change in Cash from Discontinued Operations | — | 1 | — | — | 1 | |||||||||||||||||
Net Increase in Cash and Cash Equivalents | 102 | 1 | 51 | — | 154 | |||||||||||||||||
Cash and Cash Equivalents at Beginning of Period | 194 | 158 | 44 | — | 396 | |||||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 296 | $ | 159 | $ | 95 | $ | — | $ | 550 | ||||||||||||
(1) | 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(1) | Balance | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||||
Revenues from majority-owned operations | $ | 1,230 | $ | 522 | $ | 47 | $ | (1 | ) | $ | 1,798 | |||||||||||
Operating Costs and Expenses | ||||||||||||||||||||||
Cost of majority-owned operations | 991 | 331 | 33 | (1 | ) | 1,354 | ||||||||||||||||
Depreciation and amortization | 130 | 67 | 14 | — | 211 | |||||||||||||||||
General, administrative and development | 65 | 29 | 76 | — | 170 | |||||||||||||||||
Other Charges: | ||||||||||||||||||||||
Reorganization charges | 30 | 17 | 151 | — | 198 | |||||||||||||||||
Impairment charges | 248 | (123 | ) | 112 | — | 237 | ||||||||||||||||
Fresh start reporting adjustments | — | (101 | ) | (6,571 | ) | 2,452 | (4,220 | ) | ||||||||||||||
Fresh start reporting adjustments — subsidiaries | — | — | 2,452 | (2,452 | ) | — | ||||||||||||||||
Legal settlement | (9 | ) | 4 | 468 | — | 463 | ||||||||||||||||
Total operating costs and expenses | 1,455 | 224 | (3,265 | ) | (1 | ) | (1,587 | ) | ||||||||||||||
Operating Income/(Loss) | (225 | ) | 298 | 3,312 | — | 3,385 | ||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 105 | — | (18 | ) | (87 | ) | — | |||||||||||||||
Equity in earnings of unconsolidated affiliates | 107 | 65 | (1 | ) | — | 171 | ||||||||||||||||
Write downs and losses on sales of equity method investments | (16 | ) | (126 | ) | (5 | ) | — | (147 | ) | |||||||||||||
Other income, net | 5 | 30 | (15 | ) | (1 | ) | 19 | |||||||||||||||
Interest expense | (136 | ) | (61 | ) | (112 | ) | 1 | (308 | ) | |||||||||||||
Total other income/(expense) | 65 | (92 | ) | (151 | ) | (87 | ) | (265 | ) | |||||||||||||
Income/(Loss) From Continuing Operations Before Income Taxes | (160 | ) | 206 | 3,161 | (87 | ) | 3,120 | |||||||||||||||
Income Tax Expense/(Benefit) | (107 | ) | (11 | ) | 156 | — | 38 | |||||||||||||||
Income/(Loss) From Continuing Operations | (53 | ) | 217 | 3,005 | (87 | ) | 3,082 | |||||||||||||||
Income/(Loss) on Discontinued Operations, net of Income Taxes | (26 | ) | (51 | ) | (239 | ) | — | (316 | ) | |||||||||||||
Net Income/(Loss) | $ | (79 | ) | $ | 166 | $ | 2,766 | $ | (87 | ) | $ | 2,766 | ||||||||||
(1) | 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(1) | Balance | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||||
Net income/(loss) | $ | (79 | ) | $ | 166 | $ | 2,766 | $ | (87 | ) | $ | 2,766 | ||||||||||
Adjustments to reconcile net income/(loss) to net cash provided by operating activities | ||||||||||||||||||||||
Distributions in excess of (less than) equity earnings of unconsolidated affiliates | (95 | ) | (54 | ) | 21 | 87 | (41 | ) | ||||||||||||||
Depreciation and amortization | 131 | 112 | 14 | — | 257 | |||||||||||||||||
Amortization of deferred financing costs | 7 | 7 | 4 | — | 18 | |||||||||||||||||
Write downs and losses on sales of equity method investments | 16 | 131 | — | — | 147 | |||||||||||||||||
Deferred income taxes and investment tax credits | (123 | ) | (36 | ) | 181 | (24 | ) | (2 | ) | |||||||||||||
Current tax expense — non cash contribution from members | (17 | ) | (54 | ) | — | 71 | — | |||||||||||||||
Unrealized (gains)/losses on derivatives | (13 | ) | (75 | ) | 29 | 24 | (35 | ) | ||||||||||||||
Minority interest | — | 2 | — | — | 2 | |||||||||||||||||
Restructuring and impairment charges | 273 | 94 | 41 | — | 408 | |||||||||||||||||
Fresh start reporting adjustments | — | — | (3,895 | ) | — | (3,895 | ) | |||||||||||||||
Gain on sale of discontinued operations | 3 | (198 | ) | 9 | — | (186 | ) | |||||||||||||||
Cash provided by (used in) changes in certain working capital items, net of effects from acquisitions and dispositions | 348 | 2 | 658 | (209 | ) | 799 | ||||||||||||||||
Net Cash Provided (Used) by Operating Activities | 451 | 97 | (172 | ) | (138 | ) | 238 | |||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||
Investment in subsidiaries | — | — | 129 | (129 | ) | — | ||||||||||||||||
Proceeds from sale of discontinued operations | — | 19 | — | — | 19 | |||||||||||||||||
Proceeds from sale of investments | — | 107 | — | — | 107 | |||||||||||||||||
Proceeds from sale of turbines | — | — | 71 | — | 71 | |||||||||||||||||
(Increase) in trust funds | (14 | ) | — | — | — | (14 | ) | |||||||||||||||
Decrease/(increase) in restricted cash | (198 | ) | (54 | ) | — | — | (252 | ) | ||||||||||||||
Decrease/(increase) in notes receivable | 98 | 42 | — | (142 | ) | (2 | ) | |||||||||||||||
Capital expenditures | (56 | ) | (7 | ) | (51 | ) | — | (114 | ) | |||||||||||||
Investments in projects | (4 | ) | (5 | ) | 8 | — | (1 | ) | ||||||||||||||
Net Cash Provided (Used) by Investing Activities | (174 | ) | 102 | 157 | (271 | ) | (186 | ) | ||||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||
Capital contributions from parent | (135 | ) | (132 | ) | — | 267 | — | |||||||||||||||
Proceeds from issuance of long-term debt | — | 40 | — | — | 40 | |||||||||||||||||
Deferred debt issuance costs | (8 | ) | (1 | ) | (10 | ) | — | (19 | ) | |||||||||||||
Principal payments on long-term debt | (4 | ) | (189 | ) | — | 142 | (51 | ) | ||||||||||||||
Net Cash Provided (Used) by Financing Activities | (147 | ) | (282 | ) | (10 | ) | 409 | (30 | ) | |||||||||||||
Effect of Exchange Rate Changes on Cash and Cash Equivalents | — | (22 | ) | — | — | (22 | ) | |||||||||||||||
Change in Cash from Discontinued Operations | — | 35 | — | — | 35 | |||||||||||||||||
Net Increase in Cash and Cash Equivalents | 130 | (70 | ) | (25 | ) | — | 35 | |||||||||||||||
Cash and Cash Equivalents at Beginning of Period | 64 | 228 | 69 | — | 361 | |||||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 194 | $ | 158 | $ | 44 | $ | — | $ | 396 | ||||||||||||
(1) | All significant intercompany transactions have been eliminated in consolidation. |
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Texas Genco Acquisition |
246
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February 2, 2006 | |||||
(Unaudited) | |||||
(In millions) | |||||
Current and non-current assets | $ | 1,408 | |||
Property, Plant and equipment | 7,745 | ||||
Intangibles | 1,160 | ||||
Goodwill | 2,664 | ||||
Total assets acquired | 12,977 | ||||
Current and non-current liabilities | 1,004 | ||||
Out of market contracts | 3,048 | ||||
Long term debt | 2,735 | ||||
Total liabilities acquired | 6,787 | ||||
Net assets acquired | $ | 6,190 | |||
Cash Tender Offer and Consent Solicitation |
New Financings |
New Senior Credit Facility |
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• | incur indebtedness and liens and enter into sale and lease-back transactions; | |
• | make investments, | |
• | loans and advances; | |
• | engage in mergers, acquisitions consolidations and asset sales; | |
• | pay dividends and other restricted payments; | |
• | enter into transactions with affiliates; | |
• | engage in business activities and hedging transactions; | |
• | make capital expenditures; | |
• | make debt payments; | |
• | make certain changes to the terms of material indebtedness; | |
• | and other covenants customary for such facilities. |
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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 |
Senior Notes |
• | make restricted payments; | |
• | restrict dividends or other payments of subsidiaries; | |
• | incur additional debt; | |
• | engage in transactions with affiliates; | |
• | create liens on assets; | |
• | engage in sale and leaseback transactions; | |
• | and consolidate, merge or transfer all or substantially all of its assets and the assets of its subsidiaries. |
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5.75% Preferred Stock |
Common Stock |
Second Lien Structure |
Bourbonnais Settlement |
250
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/s/PricewaterhouseCoopers LLP | |
PricewaterhouseCoopers LLP |
251
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/s/PricewaterhouseCoopers LLP | |
PricewaterhouseCoopers LLP |
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Column A | Column B | Column C | Column D | Column E | ||||||||||||||||
Additions | ||||||||||||||||||||
Balance at | Charged to | Charged to | ||||||||||||||||||
Beginning of | Costs and | Other | Balance at | |||||||||||||||||
Description | Period | Expenses | Accounts | Deductions | End of Period | |||||||||||||||
(In millions) | ||||||||||||||||||||
Allowance for doubtful accounts, deducted from accounts receivable in the balance sheet: | ||||||||||||||||||||
Reorganized NRG | ||||||||||||||||||||
Year ended December 31, 2005 | $ | 1 | $ | 2 | $ | — | $ | (1 | ) | $ | 2 | |||||||||
Year ended December 31, 2004 | — | 1 | — | — | 1 | |||||||||||||||
December 6 - December 31, 2003 | — | — | — | — | — | |||||||||||||||
Predecessor Company | ||||||||||||||||||||
January 1 - December 5, 2003 | 18 | 16 | — | (34 | ) | — | * | |||||||||||||
Income tax valuation allowance, deducted from deferred tax assets in the balance sheet: | ||||||||||||||||||||
Reorganized NRG | ||||||||||||||||||||
Year ended December 31, 2005 | $ | 708 | $ | 22 | $ | 85 | $ | (59 | ) | $ | 756 | |||||||||
Year ended December 31, 2004 | 1,241 | — | (277 | ) | (256 | ) | 708 | |||||||||||||
December 6 - December 31, 2003 | 1,242 | (1 | ) | — | — | 1,241 | ||||||||||||||
Predecessor Company | ||||||||||||||||||||
January 1 - December 5, 2003 | 1,171 | 71 | — | — | 1,242 | * |
* | December 6, 2003 - Fresh Start Balance |
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NRG Energy, Inc. | |
(Registrant) | |
/s/David W. Crane | |
David W. Crane, | |
Chief Executive Officer | |
(Principal Executive Officer) | |
/s/Robert C. Flexon | |
Robert C. Flexon, | |
Chief Financial Officer | |
(Principal Financial Officer) | |
/s/James J. Ingoldsby | |
James J. Ingoldsby, | |
Controller | |
(Principal Accounting Officer) |
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Signature | Title | Date | ||||
/s/David W. Crane David W. Crane | President and Chief Executive Officer | March 7, 2006 | ||||
/s/Howard E. Cosgrove Howard E. Cosgrove | Chairman of the Board | March 7, 2006 | ||||
/s/John F. Chlebowski John F. Chlebowski | Director | March 7, 2006 | ||||
/s/Lawrence S. Coben Lawrence S. Coben | Director | March 7, 2006 | ||||
/s/Stephen L. Cropper Stephen L. Cropper | Director | March 7, 2006 | ||||
/s/Maureen Miskovic Maureen Miskovic | Director | March 7, 2006 | ||||
/s/Anne C. Schaumburg Anne C. Schaumburg | Director | March 7, 2006 | ||||
/s/Herbert H. Tate Herbert H. Tate | Director | March 7, 2006 | ||||
/s/Thomas H. Weidemeyer Thomas H. Weidemeyer | Director | March 7, 2006 | ||||
/s/Walter R. Young Walter R. Young | Director | March 7, 2006 |
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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.(7) | ||
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.(7) | ||
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.(16) | ||
3 | .1 | Amended and Restated Certificate of Incorporation.(21) | ||
3 | .2 | Amended and Restated By-Laws.(8) | ||
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.(10) | ||
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. (22) | ||
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. (24) | ||
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. (18) | ||
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.(4) | ||
4 | .6 | Registration Rights Agreement, dated December 21, 2004, by and among NRG Energy, Inc., Citigroup Global Markets Inc. and Deutsche Bank Securities Inc.(9) | ||
4 | .7 | Specimen of Certificate representing common stock of NRG Energy, Inc.(25) | ||
4 | .8 | Indenture, dated February 2, 2006, among NRG Energy, Inc. and Law Debenture Trust Company of New York.(26) | ||
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. (26) | ||
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. (26) | ||
4 | .11 | Form of 7.250% Senior Note due 2014.(26) | ||
4 | .12 | Form of 7.375% Senior Note due 2016.(26) | ||
10 | .1* | Employment Agreement, dated November 10, 2003, between NRG Energy, Inc. and David Crane.(2) | ||
10 | .2 | Note Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc. and each of the purchasers named therein.(5) |
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10 | .3 | 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.(5) | ||
10 | .4 | Asset Sales Agreement, dated December 23, 1998, between NRG Energy, Inc., and Niagara Mohawk Power Corporation.(6) | ||
10 | .5 | Amendment to the Asset Sales Agreement, dated June 11, 1999, between NRG Energy, Inc., and Niagara Mohawk Power Corporation.(6) | ||
10 | .6* | Severance Agreement between NRG Energy, Inc. and George Schaefer dated December 18, 2002.(4) | ||
10 | .7* | Severance Agreement between NRG Energy, Inc. and John P. Brewster dated July 23, 2003.(2) | ||
10 | .8 | Stock Purchase Agreement dated December 13, 2004, by and among NRG Energy, Inc. and MatlinPatterson Global Advisers LLC, MatlinPatterson Global Opportunities Partners, L.P. and MatlinPatterson Global Opportunities Partners (Bermuda) L.P.(11) | ||
10 | .9* | NEO 2004 AIP Payout and 2005 Base Salary Table.(8) | ||
10 | .10* | Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Officers and Key Management.(20) | ||
10 | .11* | Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Directors.(20) | ||
10 | .12* | NRG Energy, Inc. Long-Term Incentive Plan.(15) | ||
10 | .13* | Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified Stock Option Agreement.(12) | ||
10 | .14* | Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock Unit Agreement.(12) | ||
10 | .15* | Form of NRG Energy, Inc. Long Term Incentive Plan Performance Unit Agreement. (17) | ||
10 | .16* | Annual Incentive Plan for Designated Corporate Officers.(13) | ||
10 | .17* | Letter Agreement, dated March 5, 2004, between NRG Energy, Inc. and John P. Brewster.(14) | ||
10 | .18* | Letter Agreement, dated March 5, 2004, between NRG Energy, Inc. and Timothy W. O’Brien.(14) | ||
10 | .19* | Letter Agreement, dated February 19, 2004, between NRG Energy, Inc. and Robert C. Flexon.(14) | ||
10 | .20 | Railroad Car Full Service Master Leasing Agreement, dated as of February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(20) | ||
10 | .21 | Commitment Letter, dated February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(20) | ||
10 | .22* | Summary of Director Compensation.(20) | ||
10 | .23 | 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.(19) | ||
10 | .24 | 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.(19) | ||
10 | .25* | August 1, 2005 Executive Officer Grant Table.(23) | ||
10 | .26* | Letter Agreement, dated June 21, 2005, between NRG Energy, Inc. and Kevin T. Howell. (23) | ||
10 | .27 | Stock Purchase Agreement, dated as of August 10, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(22) | ||
10 | .28 | Accelerated Share Repurchase Agreement, dated as of August 11, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(22) | ||
10 | .29 | Credit Agreement, dated February 2, 2006, among NRG, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, Morgan Stanley Senior Funding, Inc. and Citigroup Global Markets Inc., as joint lead Book Runners, Joint Lead Arrangers and Co-Documentation Agents, Morgan Stanley & Co. Incorporated, as Collateral Agent, and Citigroup Global Markets Inc., as Syndication Agent.(26) |
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10 | .30 | 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.(27) | ||
10 | .31 | 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).(1) | ||
10 | .32 | Terms and Conditions of Sale, dated as of October 5, 2005, between Texas Genco II LP and FreightCar 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).(1) | ||
10 | .33* | Employment Agreement, dated March 3, 2006, between NRG Energy, Inc. and David Crane.(1) | ||
10 | .34* | NEO 2005 AIP Payout and 2006 Base Salary Table.(1) | ||
21 | Subsidiaries of NRG Energy. Inc.(1) | |||
23 | .1 | Consent of KPMG LLP.(1) | ||
23 | .2 | Consent of PricewaterhouseCoopers 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 James J. Ingoldsby.(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 on Form 10-K filed on March 16, 2004. | |
(3) | Incorporated herein by reference to NRG Energy Inc.’s Amendment No. 2 to its annual report on Form 10-K filed on November 3, 2004. | |
(4) | Incorporated herein by reference to NRG Energy, Inc.’s annual report on Form 10-K filed on March 31, 2003. | |
(5) | Incorporated herein by reference to NRG Energy Inc.’s Registration Statement on Form S-1, as amended, Registration No. 333-33397. | |
(6) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended June 30, 1999. | |
(7) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on November 19, 2003. | |
(8) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on March 3, 2005. | |
(9) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on December 27, 2004. |
(10) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on December 27, 2004. |
(11) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K/ A filed on December 14, 2004. |
(12) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended September 30, 2004. |
(13) | Incorporated herein by reference to NRG Energy, Inc.’s 2004 proxy statement on Schedule 14A filed on July 12, 2004. |
(14) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended March 31, 2004. |
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(15) | Incorporated herein by reference to NRG Energy Inc.’s Registration Statement on Form S-8, Registration No. 333-114007. |
(16) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on October 3, 2005. |
(17) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report on Form 10-Q for the quarter ended June 30, 2005. |
(18) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on January 4, 2006. |
(19) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on December 28, 2005. |
(20) | Incorporated herein by reference to NRG Energy, Inc.’s annual report on Form 10-K filed on March 30, 2005. |
(21) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on May 24, 2005. |
(22) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on August 11, 2005. |
(23) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on August 3, 2005. |
(24) | Incorporated herein by reference to NRG Energy, Inc.’s Form 8-A filed on January 27, 2006. |
(25) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on January 27, 2006. |
(26) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on February 6, 2006. |
(27) | Incorporated herein by reference to NRG Energy, Inc.’s current report on Form 8-K filed on February 8, 2006. |